Filed Pursuant to Rule 424(b)(4)
Registration Statement No. 333-232594

Prospectus

5,000,000 Shares

 

BORR DRILLING LIMITED

Common Shares

This is the initial public offering in the United States of 5,000,000 common shares, par value $0.05 per share (“Shares”), of Borr Drilling Limited, a Bermuda exempted company limited by shares (the “Offering”).

Prior to this Offering, there has been no public market in the United States for our Shares. Our Shares are listed on the Oslo Børs under the symbol “BDRILL” and have been approved for listing on the New York Stock Exchange (“NYSE”) under the symbol “BORR.” The initial public offering price of our Shares is $9.30. On July 30, 2019, the closing price of our Shares on the Oslo Børs was 82.36 Norwegian Kroner, or NOK, per share, which was equivalent to approximately $9.40 per share based upon the Bloomberg Composite Rate of NOK 8.76 to $1.00 in effect on that date.

We are an “emerging growth company” as that term is defined in the Jumpstart Our Business Startups Act of 2012 and as such, will be eligible for reduced public company reporting requirements.

INVESTING IN OUR SHARES INVOLVES RISKS. SEE “RISK FACTORS” BEGINNING ON PAGE 13.

Neither the United States Securities and Exchange Commission nor any state securities commission or other regulatory body has approved or disapproved of these securities, or determined if this Prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

No offer or invitation to subscribe for Shares may be made to the public in Bermuda.

PRICE $9.30 PER SHARE

	Per Share		Total
Initial public offering price	$	9.300	$	46,500,000
Underwriting discount(1)	$	0.515	$	2,575,000
Proceeds, before expenses, to Borr Drilling	$	8.785	$	43,925,000

(1) See the section entitled “Underwriting” for additional disclosure regarding underwriting compensation payable by us.

We have also granted the underwriters an option for a period of 30 days to purchase up to 750,000 additional Shares on the same terms as set forth above. See “Underwriting.”

The underwriters expect to deliver the Shares against payment in U.S. dollars in New York, New York on or about August 2, 2019.

Goldman Sachs & Co. LLC DNB Markets

BTIG Citigroup Danske Markets Evercore ISI Fearnley Securities

Prospectus dated July 31, 2019.

   
 

“Norve”

TABLE OF CONTENTS

	Page
NOTE ON THE PRESENTATION OF INFORMATION		iii
PROSPECTUS SUMMARY		1
RISK FACTORS		13
NOTE REGARDING FORWARD-LOOKING STATEMENTS		46
USE OF PROCEEDS		48
DIVIDEND POLICY		49
CAPITALIZATION		50
SELECTED CONSOLIDATED FINANCIAL AND OTHER DATA		51
UNAUDITED PRO FORMA FINANCIAL INFORMATION		54
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		57
INDUSTRY OVERVIEW		84
BUSINESS		100
REGULATION		116
MANAGEMENT		120
PRINCIPAL SHAREHOLDERS		126
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		128
DESCRIPTION OF SHARE CAPITAL		132
SHARES ELIGIBLE FOR FUTURE SALE		141
MATERIAL INCOME TAX CONSIDERATIONS		143
UNDERWRITING		147
EXPENSES RELATED TO THIS OFFERING		150
LEGAL MATTERS		151
EXPERTS		152
ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS		153
WHERE YOU CAN FIND ADDITIONAL INFORMATION		154
INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS		F-1

You should rely only on the information contained in this Prospectus (as defined below) and any related free writing prospectus that we authorize to be distributed to you. We and the underwriters have not authorized any person to provide you with information different from that contained in this Prospectus or any related free writing prospectus authorized to be distributed to you. This Prospectus is not an offer to sell, nor is it seeking an offer to buy, Shares in any state or other jurisdiction where such offer or sale is not permitted. The information in this Prospectus speaks only as of the date of this Prospectus unless the information specifically indicates that another date applies, regardless of the time of delivery of this Prospectus or of any sale of the securities offered hereby.

Neither we nor any of the underwriters has done anything that would permit this Offering or possession or distribution of this Prospectus, or any filed free writing prospectus, in any jurisdiction other than in the United States. Persons outside the United States who come into possession of this Prospectus or any filed free writing prospectus must inform themselves about, and observe any restrictions relating to, this Offering of the Shares and the distribution of this Prospectus or any filed free writing prospectus outside of the United States.

This Prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. See the sections entitled “Risk Factors” and “Note Regarding Forward-Looking Statements.”

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Until August 25, 2019 (the 25^th day after the date of this Prospectus), all dealers that buy, sell or trade Shares, whether or not participating in this Offering, may be required to deliver a prospectus. This is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Shares may be offered or sold in Bermuda only in compliance with the provisions of the Investment Business Act of 2003 and the Exchange Control Act 1972, and related regulations of Bermuda which regulate the sale of securities in Bermuda. In addition, specific permission is required from the Bermuda Monetary Authority, or the BMA, pursuant to the provisions of the Exchange Control Act 1972 and related regulations, for all issuances and transfers of securities of Bermuda companies, other than in cases where the BMA has granted a general permission. The BMA in its policy dated June 1, 2005 provides that where any equity securities of a Bermuda company, including our common shares, are listed on an appointed stock exchange, general permission is given for the issue and subsequent transfer of any securities of a company from and/or to a nonresident, for as long as any equities securities of such company remain so listed. The NYSE is deemed to be an appointed stock exchange under Bermuda law.

Approvals or permissions given by the Bermuda Monetary Authority do not constitute a guarantee by the Bermuda Monetary Authority as to our performance or our creditworthiness. In granting such permission, the BMA accepts no responsibility for our financial soundness or the correctness of any of the statements made or opinions expressed in this Prospectus. This Prospectus does not need to be filed with the Registrar of Companies in Bermuda in accordance with Part III of the Companies Act 1981 of Bermuda, as amended (the “Companies Act”) pursuant to provisions incorporated therein following the enactment of the Companies Amendment Act 2013. Such provisions state that a prospectus in respect of the offer of shares in a Bermuda company whose equities are listed on an appointed stock exchange under Bermuda law does not need to be filed in Bermuda, so long as the company in question complies with the requirements of such appointed stock exchange in relation thereto.

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NOTE ON THE PRESENTATION OF INFORMATION

Unless otherwise indicated, information presented in this Prospectus which forms part of this registration statement on Form F-1 (this “Prospectus”) assumes that the underwriters’ option to purchase additional Shares is not exercised.

Throughout this Prospectus, unless the context otherwise requires, (i) references to “Borr Drilling Limited,” “Borr Drilling,” the “Company,” the “Registrant,” “we,” “us,” “Group,” “our” and words of similar import refer to Borr Drilling Limited and its consolidated subsidiaries, (ii) references to our “Board” or “Board of Directors” refer to the board of directors of Borr Drilling Limited as constituted at any point in time and “Director” or “Directors” refers to a member or members of the Board, as applicable, (iii) references to “Borr Drilling Management Dubai” and “Borr Drilling Management UK” refer to our subsidiaries Borr Drilling Management DMCC and Borr Drilling Management (UK) Ltd, respectively, (iv) references to our “Memorandum,” each provision thereof a “Clause,” or the “Bye-Laws,” each provision thereof a “Bye-Law,” refer to the memorandum of association and the amended and restated bye-laws of Borr Drilling Limited, respectively, each as in effect from time to time, (v) references to “Magni” or “Magni Partners” refers to Magni Partners (Bermuda) Limited, (vi) references to “Taran” refer to Taran Holdings Limited, (vii) references to “Ubon” refer to Ubon Partners AS, (viii) references to “Drew” refer to Drew Holdings Limited, (ix) references to our “DNB Revolving Credit Facility” or “DNB RCF” refer to our historical revolving credit facility with DNB Bank ASA, (x) references to our “Guarantee Facility” refer to our historical guarantee facility with DNB Bank ASA, (xi) references to our “DC Revolving Credit Facility” or “DC RCF” refer to our historical revolving credit and guarantee facility with Danske Bank A/S and Citigroup Global Markets Limited, (xii) references to our “Bridge Facility” or “Bridge RCF” refer to our historical revolving credit facility with Danske Bank A/S and DNB Bank ASA, (xiii) references to our “Hayfin Facility” refer to our term loan facility with Hayfin Services LLP, among others, (xiv) references to our “Syndicated Facility” or “Syndicated RCF” refer to our senior secured credit facilities with DNB Bank ASA, Danske Bank, Citibank N.A., Jersey Branch and Goldman Sachs Bank USA, (xv) references to our “New Bridge Facility” or “New Bridge RCF” refer to our senior secured revolving credit facility with DNB Bank ASA and Danske Bank, (xvi) references to our “Convertible Bonds” refer to our $350.0 million convertible bonds due 2023, (xvii) references to our “jack-up rigs” shall be deemed to include our semi-submersible rig (as the context may require) and (xviii) references to our “Reverse Share Split” refer to the conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. Unless otherwise indicated, all Share and per Share data in this Prospectus is adjusted to give effect to our Reverse Share Split and is approximate due to rounding.

References in this Prospectus to our “Financing Arrangements” refer to our Hayfin Facility, Syndicated RCF, New Bridge RCF, Convertible Bonds and shipyard delivery financing arrangements described more fully herein, collectively, including the agreements and other terms governing our Hayfin Facility, Syndicated RCF, New Bridge RCF, Convertible Bonds and delivery financing arrangements, respectively.

References in this Prospectus (i) to the “SEC” refer to the United States Securities and Exchange Commission and (ii) to “U.S. GAAP” refer to the generally accepted accounting principles in the United States as in effect at any point in time.

References in this Prospectus to “Keppel” and “PPL” refer to the shipyards Keppel FELS Limited and PPL Shipyard Pte Ltd., respectively, including their respective subsidiaries and affiliates as the context may require.

References in this Prospectus to “NDC,” “Total,” “ExxonMobil,” “Perenco,” “TAQA,” “BW Energy,” “ONGC,” “Spirit Energy,” “Tulip,” “BP,” “Shell” and “Chevron” refer to our key customers the National Drilling Company, Total S.A., Exxon Mobil Corporation, Perenco S.A., Abu Dhabi National Energy Company PJSC, BW Offshore Limited, the Oil and Natural Gas Corporation, Spirit Energy Limited, Tulip Oil Holding B.V., BP plc, Royal Dutch Shell plc and Chevron Corporation, respectively, including their respective subsidiaries and affiliates as the context may require.

References in this Prospectus to “ABS” refer to the American Bureau of Shipping.

Unless otherwise indicated, all references to “U.S.$” and “$” in this Prospectus are to, and amounts are presented in, U.S. dollars. All references to “€,” “EUR,” or “Euros” are to the single currency of the European Monetary Union, all references to “£,” “Pounds” or “GBP” are to pounds sterling and all references to “NOK” are to Norwegian Kroner.

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In this Prospectus, we present certain market and industry data. When furnishing the information set out in this Prospectus, including the industry information and data presented in the section entitled “Industry Overview,” we have used certain statistical and graphical information obtained from Rystad Energy, an independent energy research and business intelligence company. See “Experts.” Rystad Energy has advised us that the statistical and graphical information presented in this Prospectus is drawn from its database and other sources. We do not have any knowledge that the information provided by Rystad Energy is inaccurate in any material respect. Rystad Energy has further advised us that: (a) certain of the information provided is based on estimates or subjective judgments, (b) the information in the databases of other offshore drilling data collection agencies may differ from the information in Rystad Energy’s database and (c) while Rystad Energy has taken reasonable care in the compilation of the statistical and graphical information and believes it to be accurate and correct, data collection is subject to limited audit and validation procedures. Other information contained in this Prospectus regarding our industry and the markets in which we operate is based on our own internal estimates and research. This information is based on third party services which we believe to be reliable. Unless otherwise indicated, the basis for any statements regarding our competitive position in this Prospectus is based on our own assessment and knowledge of the market in which we operate. Where information sourced from Rystad Energy is presented, the source of such information is identified. Forward-looking information obtained from third party sources, including Rystad Energy, is subject to the same qualifications and the uncertainties regarding the other forward-looking statements in this Prospectus.

Market data and statistics are inherently predictive and subject to uncertainty and do not necessarily reflect actual market conditions. Such statistics are based on market research, which, itself, is based on sampling and subjective judgments by both the researchers and the respondents, including judgments about what types of products and transactions should be included in the relevant market. As a result, investors should be aware that statistics, statements and other information relating to markets, market sizes, market shares, market positions and other industry data set forth in this Prospectus, including in the section entitled “Industry Overview” (and projections, assumptions and estimates based on such data) may not be reliable indicators of our future performance and the future performance of the offshore drilling industry. See the sections entitled “Risk Factors” and “Note Regarding Forward-Looking Statements.”

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PROSPECTUS SUMMARY

The following summary is qualified in its entirety by, and should be read in conjunction with, the more detailed information and financial statements appearing elsewhere in this Prospectus. In addition to this summary, we urge you to read the entire prospectus carefully before deciding whether to buy our Shares. You should carefully consider, among other things, our consolidated financial statements and the related notes and sections entitled “Risk Factors,” “Note Regarding Forward-Looking Statements,” “Selected Consolidated Financial and Other Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” as well as the audited consolidated financial statements of Borr Drilling Limited as of and for the years ended December 31, 2018 and 2017, the unaudited condensed consolidated interim financial statements of Borr Drilling Limited as of March 31, 2019 and for the three months ended March 31, 2019 and 2018, and the audited consolidated financial statements of Paragon Offshore Limited for its predecessor for the period from January 1, 2017, to July 18, 2017 and its successor for the periods from July 18, 2017, to December 31, 2017, and from January 1, 2018, to March 29, 2018, which are included elsewhere in this Prospectus, before making an investment decision.

OUR COMPANY

We are an offshore shallow-water drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership, contracting and operation of jack-up rigs for operations in shallow-water areas (i.e., in water depths up to approximately 400 feet), including the provision of related equipment and work crews to conduct oil and gas drilling and workover operations for exploration and production customers. We own 27 rigs, including 26 jack-up rigs and one semi-submersible rig, with an additional eight jack-up rigs scheduled to be delivered by the end of 2020. Upon delivery of these newbuild jack-up rigs, we will have a fleet of 30 premium jack-up rigs, which refers to rigs delivered from the yard in 2001 or later.

We aim to become a preferred operator of jack-up rigs within the jack-up drilling market. The shallow-water market is our operational focus as we expect demand will recover sooner than in the mid- and deepwater segments of the contract drilling market. We contract our jack-up rigs and offshore employees primarily on a dayrate basis to drill wells for our customers, including integrated oil companies, state-owned national oil companies and independent oil and gas companies. During 2018, our top five customers by revenue were subsidiaries of NDC, TAQA, BW Energy, Spirit Energy and Total. During the first quarter of 2019, our top five customers by revenue were subsidiaries of NDC, TAQA, Perenco, Total and Tulip. A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. Our Total Contract Backlog was $383.2 million as of June 30, 2019 and $377.5 million as of December 31, 2018. We currently operate in significant oil-producing geographies throughout the world, including the North Sea, the Middle East, Mexico, West Africa and Southeast Asia. We intend to operate our business with a competitive cost base, driven by a strong and experienced organizational culture and a carefully managed capital structure.

From our initial acquisition of rigs in early 2017, we have expanded rapidly into one of the world’s largest international offshore jack-up drilling contractors by number of jack-up rigs. The following chart illustrates the development in our fleet since our inception:

	As of and for the Six Months Ended June 30,		As of and for the Year Ended December 31,
	2019		2018		2017
Total Fleet as of January 1		27		13		0
Jack-up Rigs Acquired(1)		—		23		12
Newbuild Jack-up Rigs Delivered from Shipyards		2		9		1
Jack-up Rigs Disposed of		2		18		0
Total Fleet as of the end of Period		27		27		13
Newbuild Jack-up Rigs not yet Delivered as of the End of Period		8		9		13
Jack-up Rigs Committed to be Sold as of the End of Period		1		—		—
Total Fleet, including Newbuild Rigs not yet Delivered, as of the end of Period		35		36		26

(1) Includes acquisition of one semi-submersible rig in 2018.

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Our operating revenues, net (loss) and Adjusted EBITDA for the year ended December 31, 2018 were $164.9 million, $(190.9) million and $(65.8) million, respectively, and for the three months ended March 31, 2019 were $51.9 million, $(56.4) million and $(15.3) million, respectively. Adjusted EBITDA is a non-GAAP measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to the most directly comparable financial measure of net loss under U.S. GAAP, see “—Summary Consolidated Financial and Other Data.”

Our common shares have traded on the Oslo Børs since August 2017, under the symbol “BDRILL.”

OUR FLEET

We believe that we have one of the most modern jack-up fleets in the offshore drilling industry. Our drilling fleet consists of 27 rigs, of which four are standard jack-up rigs, 22 are premium jack-up rigs and one is a semi-submersible rig. In addition, we have agreed to purchase eight additional premium jack-up rigs to be delivered prior to the end of 2020. Premium jack-up rigs means rigs delivered from the yard in 2001 or later and which are suitable for operations in water depths up to 400 feet with an independent leg cantilever design. The majority of our rigs were built after 2013 and as of June 30, 2019, the average age of our premium fleet (excluding our four standard jack-up rigs and our semi-submersible rig) and of our entire fleet (excluding newbuilds not yet delivered) is 4.2 years and 9.7 years, respectively. As of the date of the last expected delivery of the newbuild jack-up rigs we have agreed to purchase, which is in 2020, the average age of our premium fleet (excluding our four standard jack-up rigs and our semi-submersible rig) and of our entire fleet will be 4.3 years and 8.8 years, respectively, which we believe to be among the lowest average fleet age in the industry (both currently and as of the date of our last expected delivery).

As of June 30, 2019, we had 26 total jack-up rigs, of which 11 rigs were “warm stacked,” which means the rigs, including our newbuild jack-up rigs which have been delivered but not yet been activated, are kept ready for redeployment and retain a maintenance crew, and three rigs were “cold stacked,” which means the rigs are stored in a harbor, shipyard or a designated offshore area and the crew is reassigned to an active rig or dismissed. We have entered into an agreement to sell one of our cold stacked jack-up rigs, the “Eir,” and we expect the sale to be completed by the end of the first quarter of 2020, subject to certain conditions. We believe that well-planned and well-managed stacking will significantly reduce reactivation cost and the cost of mobilization of a rig towards a contract. We are therefore focusing on securing cost efficiencies during stacking while limiting future risk from premature reactivation. This means concentrating stacked rigs in as few locations as possible to be able to share crew, running reduced but sufficient maintenance programs on equipment and preserving critical equipment.

We intend to prioritize the deployment of our currently contracted premium jack-up rigs. Reactivation of our premium jack-up rigs that are stacked will be undertaken for select contract opportunities. However, a stacked rig will only be reactivated if the achievable dayrate supports the reactivation and subsequent operating costs in a sensible way. Between April 1, 2018 and June 30, 2019, we signed 15 new contracts for drilling services, including nine with new customers. Our ability to keep our jack-up rigs operational when under contract, or Technical Utilization, for the year ended December 31, 2018 was 99.3% and for the six months ended June 30, 2019 was 99.0%, and the proportion of the potential full contractual dayrate that each contracted jack-up rig actually earns each day, or Economic Utilization, for the year ended December 31, 2018 was 97.9% and for the six months ended June 30, 2019 was 95.2%.

Each rig in our fleet is certified by ABS, enabling universal recognition of our equipment as qualified for international operations.

OUR COMPETITIVE STRENGTHS

We believe that our competitive strengths include:

One of the youngest and largest offshore drilling contractors

We have one of the youngest and largest fleets in the jack-up drilling market. The majority of our rigs were built after 2013 and, as of June 30, 2019, the average age of our premium fleet (excluding our four standard jack-up rigs, our semi-submersible rig and newbuilds not yet delivered) is 4.2 years and of our entire fleet (excluding newbuilds not yet delivered) is 9.7 years (implying an average building year of 2010),

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respectively, which we believe is among the lowest average fleet age in the industry. New and modern rigs that offer technically capable, operationally flexible, safe and reliable contracting are increasingly preferred by customers. We expect to compete for and secure new drilling contracts from new tenders as well as privately negotiated transactions, which we estimate represent approximately half of new contract opportunities. We believe, based on our young fleet and growing operational track record, that we will be better placed to secure new drilling contracts as offshore drilling demand rises than our competitors who operate older, less modern fleets.

Largely uniform and modern fleet with available capacity to expand customer base

Because our fleet is one of the youngest and largest and the drilling equipment on, and operating capability of, our jack-up rigs is largely uniform, we have the capacity to bid for multiple contracts simultaneously, including those requiring active employment of multiple rigs over the same period, as in the case of our operations for Pemex (as defined below) in Mexico. We have acquired (including newbuilds not yet delivered) a fleet of largely premium jack-up rigs from shipyards with a reputation for quality and reliability. Moreover, due to the uniformity of the jack-up rigs in our fleet, we have been able to achieve operational and administrative efficiencies.

We have activated a number of our jack-up rigs since late 2018 based on firm contract opportunities, which we believe confirms our expectation that industry conditions in the jack-up drilling market will continue to improve. We believe that we are well-placed to capitalize on these improving trends as we seek to establish ourselves as one of the preferred providers in the industry. As of June 30, 2019, we have 11 rigs warm stacked and available for contracting as well as an additional eight jack-up rigs under construction which are also available for contracting.

Commitment to safety and the environment

We are focused on developing a strong Quality, Health, Safety and Environment (“QHSE”) culture and performance history. We believe that the combination of quality jack-up rigs and experienced and skilled employees contributes to the safety and effectiveness of our operations. Since the 2010 Deepwater Horizon Incident (as defined below) (to which we were not a party), there has been an increased focus on offshore drilling QHSE issues by regulators as well as by the industry. As a result, companies exploring for or producing oil and/or natural gas (“E&P Companies”) have imposed increasingly stringent QHSE rules on their contractors, especially when working on challenging wells and operations where the QHSE risks are higher. Our commitment to strong QHSE culture and performance is reflected in our Technical Utilization rate of 99.3% in 2018 and 99.0% for the six months ended June 30, 2019, and our excellent safety record in the same period. We believe our focus on providing safe and efficient drilling services will enhance our growth prospects as we work toward becoming one of the preferred providers in the industry.

Strong and diverse customer relationships

We have strong relationships with our customers rooted in our employees’ expertise, reputation and history in the offshore drilling industry, as well as our growing operational track record and the quality of our fleet. Our customers are oil and gas exploration and production companies, including integrated oil companies, state-owned national oil companies and independent oil and gas companies. For the year ended December 31, 2018, our five largest customers in terms of revenue were NDC, TAQA, BW Energy, Spirit Energy and Total. We believe that we are responsive and flexible in addressing our customers’ specific needs and seek collaborative solutions to achieve customer objectives. We focus on strong operational performance and close alignment with our customers’ interests, which we believe provides us with a competitive advantage and will contribute to contracting success and rig utilization.

Management team and Board members with extensive experience in the drilling industry

Our executive management team and Board have extensive experience in the oil and gas industry in general and in the drilling industry in particular. In addition, the members of our executive management team are knowledgeable operating and financial executives with extensive experience with companies operating in the jack-up drilling market. The members of our executive management team and Board have held and

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currently hold leadership positions at prominent offshore drilling and oilfield services companies, including Schlumberger Limited, Marine Drilling Companies, Inc., Seadrill Limited, North Atlantic Drilling Ltd., TODCO and Archer Limited, and have relationships which complement one another and have assisted, and continue to assist, in our development.

Effective acquisition history

We acquired our jack-up rigs at what we believe are historically attractive prices, including through four major acquisitions since early 2017. The average purchase price of our rigs is significantly lower than the historical construction cost of comparable rigs. We acquired our jack-up rigs at a substantial discount to their cost when originally ordered. We have acquired the majority of our newbuild jack-up rigs by raising equity in the financial markets and by entering into delivery financing arrangements provided by the shipyards. In contrast to many of our competitors who built and owned their fleet prior to 2014, we entered the jack-up drilling market at what we believe to be an attractive price point. Although we have incurred net losses as we commence operations, we believe we are well placed, with a young and modern fleet, to capitalize on any upturn in the jack-up drilling market.

OUR BUSINESS STRATEGIES

Through our premium jack-up rigs, we intend to meet our primary business objective of becoming a preferred operator in the jack-up drilling market while also maximizing return to our shareholders. To achieve this, our strategies include the following:

Deploy high-quality rigs to service a growing industry

We have acquired one of the leading jack-up fleets in the industry with capacity to service existing and future client needs. Tender activity in the jack-up drilling market has been increasing sharply since the second quarter of 2018, which we believe indicates the industry is recovering from the challenges it has faced over the last five years. We believe that shallow-water drilling, such as that performed by our jack-up rigs, has a shorter lifecycle between exploration and first oil and lower capital expenditure than other forms of drilling performed by mobile offshore drilling units, such as drillships. We believe this makes shallow-water drilling more attractive than deep-water projects in the current economic and industry climates. Major E&P Companies have experienced falling production coupled with rising cash flows since late 2016 and as a result of these factors, we anticipate an increase in shallow-water drilling among E&P and other companies. In addition to tender activity in which we participate through bidding, we also compete for new contract opportunities through privately negotiated transactions, including private tenders and direct negotiations with customers, which we estimate represent approximately half of new contract opportunities. We believe our footprint in the industry is growing. Between April 1, 2018, and June 30, 2019, we signed 15 new contracts for drilling services with an aggregate value of approximately $439 million, including nine with new customers. During this period, we also signed two extensions and have had four options exercised. As of June 30, 2019, 16 of our 27 rigs are under contract (including our semi-submersible rig).

Become a preferred provider in the industry

We have established strong and long-term relationships with key participants and customers in the offshore drilling industry, including through our acquisition of Paragon Offshore Limited, the hiring of experienced personnel and contracts signed since our inception, and we will seek to deepen and strengthen these relationships as part of our strategy. This involves identifying value add services for our customers (such as integrated well contracts) and, as an example of this, we have signed a non-exclusive Collaboration Agreement (as defined below) with Schlumberger Oilfield Holdings Ltd., a wholly owned subsidiary of Schlumberger Limited, who is our principal shareholder (“Schlumberger”), to offer such services. For more information on our relationship with Schlumberger, please see the section entitled “Certain Relationships and Related Party Transactions.” We also plan to continue to hire employees with long track-records in the industry and extensive contacts with potential key customers to further improve customer relationships. Based on our largely premium and uniform fleet, our experienced team and a solid industry network, we believe that we are well-positioned to capitalize on improving trends as we seek to establish ourselves as a preferred provider to these customers.

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Establish high-quality, cost-efficient operations

We intend to be a leading offshore shallow-water drilling company by operating with a competitive cost base while continuing to grow our reputation as a high quality contractor. Our key objective is to deliver the best operations possible—both in terms of Technical Utilization and QHSE culture and performance—while also maximizing deployment of our rigs and maintaining a competitive cost structure.

To facilitate our strategy, we have acquired one of the most modern and uniform fleets in the industry, with experienced and skilled individuals across the organization and on our Board. We expect to have an advantage not only with regard to operating expenditures as a result of our largely standardized fleet, but also with regard to financing costs when compared to many of our industry peers.

Establish and offer integrated services

We are planning to offer integrated drilling/well services together with Schlumberger and have been tendering our services on this basis for some contract tenders. Integrated drilling services offer all services and equipment (and in some cases, material procurement) in a single contract. We believe this model is more economically feasible and thus attractive for smaller E&P Companies operating offshore, as the model could reduce the number of contracts required for a project from above ten to two or three. Significant cost saving potential is evident in the model. As a result, project management could become simpler, cheaper and more efficient for customers with integrated drilling services. Further, this could lead to improved well design, better selection and more efficient operators of rig equipment and technology.

We expect our collaboration agreement with Schlumberger, while not exclusive to either party, to enable us to offer integrated well services by providing a combination of services, technology, equipment and rigs that we expect to yield a significant value proposition. An example is the recent contract awarded to us in Mexico, where we, Schlumberger and local partners will work together to deliver integrated drilling services to Pemex.

Maintain financial discipline

We intend to manage our balance sheet by maintaining a suitable proportion of equity and debt, depending on our contract backlog and market outlook. In the future, we may consider adding leverage against our contract backlog or to finance growth or other accretive activities. We will also aim to distribute dividends to shareholders whenever we have excess cash flows and are permitted to do so under our Financing Arrangements.

RISK FACTORS

We face a number of risks associated with our business and industry and must overcome a variety of challenges to utilize our competitive strengths and implement our business strategies. These risks relate to, among others, changes in the jack-up drilling market, including supply and demand, utilization rates, dayrates, customer drilling programs and commodity prices; a downturn in the global economy; hazards inherent in our industry and operations resulting in liability for personal injury or loss of life, damage to or destruction of property and equipment, pollution or environmental damage; inability to comply with covenants in certain of our debt arrangements; and inability to successfully employ our jack-up rigs. Investing in our Shares involves substantial risk. You should carefully consider those risks described in the section entitled “Risk Factors” and the other information in this Prospectus before deciding whether to invest in our Shares.

RECENT DEVELOPMENTS

New Local Partner Relationship

In February 2019, we, along with a local partner in Mexico, Proyectos Globales de Energia y Servicos CME, S.A. DE C.V. (“CME”), successfully tendered for a contract to provide integrated well services to Petroleos Mexicanos (“Pemex”). On March 20, 2019, one of our subsidiaries and one of CME’s subsidiaries entered into a contract for the provision of integrated well services to Pemex (the “Pemex Contract”). In June 2019, we finalized the Mexican JV (as defined below) structure and expect to commence operations under the Pemex Contract in early August 2019. Please see the sections entitled “Business—Joint Venture, Partner and Agency Relationships—Mexico” and “—Our Fleet” for further information.

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Refinancing of Historical Financing Arrangements

During the first half of 2019, we refinanced our historical revolving credit facilities, including our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF. Following the signing of our Hayfin Facility, Syndicated Facility and New Bridge Facility agreements on June 25, 2019, which collectively provided $645 million in financing, we paid in full the outstanding balances due under our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF, respectively, which were subsequently cancelled. Please see the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Existing Indebtedness” for more information.

Reverse Share Split

We have effected a conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. Our post-Reverse Share Split Shares began to trade on the Oslo Børs on June 26, 2019. Unless otherwise indicated, all Share and per Share data in this Prospectus is adjusted to give effect to our Reverse Share Split and is approximate due to rounding.

As of March 31, 2019, there were 525,341,755 Shares issued and outstanding, representing a per share net tangible book value of $2.71. Immediately after our Reverse Share Split, the number of issued and outstanding Shares decreased to 105,068,351, not accounting for fractional shares, representing a per share net tangible book value of $13.55.

Acquisition of Keppel’s Hull B378

In March 2019, we entered into an assignment agreement with BOTL Lease Co. Ltd. (the “Original Owner”) for the assignment of the rights and obligations under a construction contract to take delivery of one KFELS Super B Bigfoot premium jack-up rig identified as Keppel’s Hull No. B378 from Keppel for a purchase price of $122.1 million. The construction contract was, at the same time, novated to our subsidiary, Borr Jack-Up XXXII Inc., and amended. We took delivery of the jack-up rig on May 9, 2019 and the rig was subsequently renamed “Thor.”

To finance the rig purchase we entered into a $120.0 million senior secured term loan facilities agreement, consisting of two facilities (Facility A and Facility B) of $60.0 million each, which we refer to as our Bridge Facility. The facilities had a maturity date of September 30, 2019. Following the signing of our Hayfin Facility, Syndicated Facility and New Bridge Facility agreements on June 25, 2019, which collectively provided $645 million in financing, we paid the outstanding balance due under our Bridge Facility, which was subsequently cancelled.

Sale of Jack-up Rigs

In May 2019, we entered into sale agreements for the sale of the “Eir,” “Baug” and “Paragon C20051,” none of which were operating or on contract, for cash consideration of $3.0 million each. The jack-up rigs have been sold with a contractual obligation not to be used for drilling purposes and so retired from the international jack-up fleet. The sales of “Baug” and “Paragon C20051” were completed in May 2019 for cash consideration of $6.0 million and the sale of “Eir” is expected to be completed by the end of the first quarter of 2020, subject to certain conditions. We have recorded an impairment of $11.4 million in the first quarter of 2019 in connection with our entry into an agreement for the sale of the “Eir.” These divestments bring the total number of jack-up rigs divested by us and retired from the international jack-up fleet to 20 since the beginning of 2018.

COMPANY INFORMATION

Borr Drilling Limited was incorporated by Taran Holdings Limited on August 8, 2016, pursuant to the Companies Act, as an exempted company limited by shares and registered in the Bermuda register of companies with the name “Magni Drilling Limited.” On December 16, 2016, we changed our name to Borr Drilling Limited. On December 19, 2016, our Shares were introduced to the Norwegian OTC market and on August 30, 2017, our Shares were listed on the Oslo Børs under the symbol “BDRILL.” Our principal executive offices are located at S. E. Pearman Building, 2^nd Floor, 9 Par-la-Ville Road, Hamilton HM11, Bermuda and our telephone number is +1 (441) 737-0152.

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OTHER INFORMATION

Because we are incorporated under the laws of Bermuda, you may encounter difficulty protecting your interests as shareholders, and your ability to protect your rights through the U.S. federal court system may be limited. Please refer to the sections entitled “Risk Factors” and “Enforceability of Civil Liabilities Against Foreign Persons” for more information.

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THE OFFERING

Shares offered by us

5,000,000 Shares (or 5,750,000 Shares if the underwriters exercise their option to purchase 750,000 additional Shares in full).

Shares outstanding immediately after this Offering

110,068,351 Shares (or 110,818,351 Shares if the underwriters exercise their option to purchase 750,000 additional Shares in full).

Underwriters’ option to purchase additional Shares

We have granted to the underwriters an option, exercisable within thirty days from the date of this Prospectus, to purchase up to an aggregate of 750,000 additional Shares.

Voting rights

Holders of our Shares are entitled to one vote per share on all matters submitted to a vote. See “Description of Share Capital” for a description of our Shares, our Memorandum and our Bye-Laws.

Use of proceeds

We intend to use the net proceeds from this Offering for general corporate purposes, which may include funding future mergers, acquisitions or investments in complementary businesses, products or technologies; maintaining liquidity; repayment of indebtedness; and funding our working capital needs. See “Use of Proceeds” for more information.

Dividend policy

Under our Bye-Laws, our Board may pay a fixed cash dividend or may declare cash dividends or distributions on such days as may be determined by our Board from time to time. Under Bermuda law, a company may not declare or pay a dividend, or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) it is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of its assets would thereby be less than its liabilities.

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 their earnings and cash flow to us. Furthermore, the covenants in our New Bridge Facility agreement require the approval of our lenders prior to the distribution of any dividends and the covenants in our Syndicated Facility agreement subject dividends to certain conditions which if not met would require the approval of our lenders prior to the distribution of any dividend.

We have not paid dividends to our shareholders since incorporation. We aim to distribute a portion of our future earnings from operations, if any, to our shareholders from time to time as determined by our Board. Any dividends declared in the future will be at

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the sole discretion of our Board and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities.

Lock-up

We, our directors, our executive officers and certain of our shareholders have agreed with the underwriters not to sell, transfer or dispose of any Shares or similar securities for a period of 180 days after the date of this Prospectus. See the sections entitled “Shares Eligible for Future Sale—Lock-Up Agreements” and “Underwriting” for more information.

Risk Factors

See “Risk Factors” and other information included in this Prospectus for a discussion of factors you should carefully consider before deciding to invest in our Shares.

Listing

Our Shares have been approved for listing on the New York Stock Exchange under the symbol “BORR.” Our Shares will remain listed on the Oslo Børs.

Transfer Agent

Broadridge Corporate Issuer Solutions, Inc.

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SUMMARY CONSOLIDATED FINANCIAL AND OTHER DATA

Our summary consolidated statement of operations and other financial data for the years ended December 31, 2018 and 2017 and our summary consolidated balance sheet data as of December 31, 2018 and 2017 have been derived from our audited consolidated financial statements as of and for the years ended December 31, 2018 and 2017, which are included elsewhere in this Prospectus (the “Consolidated Financial Statements”). Our summary consolidated statement of operations and other financial data for the three months ended March 31, 2019 and 2018 and our summary consolidated balance sheet data as of March 31, 2019 have been derived from our unaudited condensed consolidated financial statements as of March 31, 2019 and for the three months ended March 31, 2019 and 2018, which are included elsewhere in this Prospectus (the “Interim Financial Statements”).

Our Consolidated Financial Statements and Interim Financial Statements are prepared and presented in accordance with U.S. GAAP. Our historical results are not necessarily indicative of results expected for future periods.

The following table should be read in conjunction with the sections entitled “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and Interim Financial Statements and notes thereto, which are included herein. Our Consolidated Financial Statements and Interim Financial Statements are maintained in U.S. dollars. We refer you to the notes to our Consolidated Financial Statements and Interim Financial Statements for a discussion of the basis on which our Consolidated Financial Statements and Interim Financial Statements are prepared, respectively.

We have effected a conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. Our post-Reverse Share Split Shares began to trade on the Oslo Børs on June 26, 2019. The table below reflects our Reverse Share Split. Unless otherwise indicated, all Share and per Share data in this Prospectus is adjusted to give effect to our Reverse Share Split and is approximate due to rounding.

	For the Three Months Ended March 31						For the Year Ended December 31,
	2019			2018			2018			2017
	(in $ millions, except per share data)
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS DATA:
Operating revenues	$	51.9		$	10.6		$	164.9		$	0.1
Gain from bargain purchase		—			38.1			38.1			—
Gain on disposals		—			—			18.8			—
Operating expenses		(109.9	)		(62.8	)		(353.2	)		(109.8	)
Operating loss		(58.0	)		(14.1	)		(131.4	)		(109.7	)
Total other income (expenses), net		1.8			(19.7	)		(57.0	)		21.7
Income tax expense		(0.2	)		—			(2.5	)		—
Net loss		(56.4	)		(33.8	)		(190.9	)		(88.0	)
Other comprehensive gain (loss)		(7.3	)		—			0.6			(6.2	)
Total comprehensive loss	$	(63.7	)	$	(33.8	)	$	(190.3	)	$	(94.2	)
Net loss per common share:
Basic		(0.52	)		(0.35	)		(1.85	)		(1.70	)
Diluted		(0.52	)		(0.35	)		(1.85	)		(1.70	)
Common shares outstanding		105,068,351			105,068,351			105,068,351			95,264
Weighted average common shares outstanding		105,068,351			102,877,501			102,877,501			51,726,288

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	As of March 31		As of December 31,
	2019		2018		2017
	(in $ millions)
SUMMARY BALANCE SHEET DATA:
Cash and cash equivalents	$	29.4	$	27.9	$	164.0
Restricted cash		29.4		63.4		39.1
Other current assets		150.7		117.3		22.4
Jack-up drilling rigs		2,416.1		2,278.1		783.3
Newbuildings		432.5		361.8		642.7
Marketable securities		—		31.0		20.7
Other long-term assets		40.3		34.2		—
Total assets		3,098.4		2,913.7		1,672.3
Trade accounts payable		14.7		9.6		9.6
Accruals and other current liabilities		109.6		106.5		11.5
Long-term debt (including current portion)		1,415.4		1,174.6		87.0
Onerous contracts		71.3		81.5		71.3
Other liabilities		15.6		8.0		—
Total liabilities		1,626.6		1,380.2		179.4
Total equity	$	1,471.8	$	1,533.5	$	1,492.9

	For the Three Months Ended March 31,						For the Year Ended December 31,
	2019			2018			2018			2017
	(in $ millions)
CASH FLOW DATA:
Net Cash Provided by / (Used in) Operating Activities	$	(13.9	)	$	(45.4	)	$	(135.2	)	$	(184.8	)
Net Cash Provided by / (Used in) Investing Activities		(172.1	)		(198.8	)		(560.1	)		(1,256.5	)
Net Cash Provided by / (Used in) Financing Activities		153.5			147.6			583.5			1,506.3

	As of and for the Three Months Ended March 31,						As of and for the Year Ended December 31,
	2019			2018			2018			2017
OTHER FINANCIAL AND OPERATIONAL DATA:
Adjusted EBITDA(1) (in $ millions)	$	(15.3	)	$	(40.0	)	$	(65.8	)	$	(61.8	)
Total Contract Backlog(2) (in $ millions)		451.2			206.7			377.5			28.5
Technical Utilization(3) (in %)		98.8	%		91.9	%		99.3	%		—
Economic Utilization(4) (in %)		95.7	%		86.1	%		97.9	%		—
TRIF(5) (number of incidents)		1.20			1.66			1.54			—

(1) Adjusted EBITDA is a non-GAAP financial measure and as used herein represents net loss adjusted for: depreciation and impairment of non-current assets, amortization of contract backlog, interest income, interest capitalized to newbuildings, foreign exchange loss, net, other financial expenses, interest expense, gross, change in unrealized (loss)/gain on Call Spread Transactions (as defined below), (loss)/gain on forward contracts, gain from bargain purchase and income tax expense. We present Adjusted EBITDA because we believe that it and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance. We believe Adjusted EBITDA provides meaningful information about the performance of our business and therefore we use it to supplement our U.S. GAAP reporting. Moreover, our management uses Adjusted EBITDA in presentations to our Board to provide a consistent basis to measure operating performance of our business, as a measure for planning and forecasting overall expectations, for evaluation of actual results against such expectations and in communications with our shareholders, lenders, bondholders, rating agencies and others concerning our financial performance. We believe that Adjusted EBITDA improves the comparability of year-to-year results and is representative of our underlying performance, although Adjusted EBITDA has significant limitations, including not reflecting our cash requirements for capital or deferred costs, rig reactivation costs, newbuild rig activation costs contractual commitments, taxes, working

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capital or debt service. Non-GAAP financial measures may not be comparable to similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under U.S. GAAP. The following table sets forth a reconciliation of Adjusted EBITDA to net loss for the three months ended March 31, 2019 and 2018 and the years ended December 31, 2018 and 2017:

	For the Three Months Ended March 31,						For the Year Ended December 31,
	2019			2018			2018			2017
	(in $ millions)
Net loss	$	(56.4	)	$	(33.8	)	$	(190.9	)	$	(88.0	)
Depreciation and impairment of non-current assets		23.9			12.2			79.5			47.9
Amortization of contract backlog*		7.4			—			24.2			—
Interest income		(0.3	)		(0.5	)		(1.2	)		(3.2	)
Interest capitalized to newbuildings		(5.8	)		(2.7	)		(23.4	)		—
Foreign exchange loss, net		(0.2	)		0.2			1.1			0.3
Other financial expenses		0.8			—			3.5			—
Interest expense, gross		18.8			2.7			37.1			0.5
Change in unrealized (loss)/gain on Call Spread Transactions		(3.6	)		—			25.7			—
(Loss)/gain on forward contracts		(11.5	)		20.0			14.2			(19.3	)
Gain from bargain purchase		—			(38.1	)		(38.1	)		—
Income tax expense		0.2			—			2.5			—
Adjusted EBITDA	$	(15.3	)	$	(40.0	)	$	(65.8	)	$	(61.8	)

^* Amortization of the fair market value of existing contracts at the time of the initial acquisition.

See the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Business—Financial Measures—Adjusted EBITDA.”

(2) Our Total Contract Backlog includes only firm commitments for contract drilling services represented by definitive agreements. Total Contract Backlog (in $ millions) is calculated as the maximum contract drilling dayrate revenue that can be earned from a drilling contract based on the contracted operating dayrate. Total Contract Backlog excludes revenue resulting from mobilization and demobilization fees, contract preparation, capital or upgrade reimbursement, recharges, bonuses and other revenue sources and is not adjusted for planned out-of-service periods during the contract period. The contract period excludes additional periods that may result from the future exercise of extension options under our contracts, and such extension periods are included only when such options are exercised. The contract operating dayrate may temporarily change due to, among other factors, mobilization, weather or repairs. As used in this Prospectus, Total Contract Backlog (in $ millions) is not the same measure as the acquired contract backlog presented in our Consolidated Financial Statements and Interim Financial Statements. Please see Notes 2 and 14 to our Consolidated Financial Statements and Notes 3 and 11 to our Interim Financial Statements for further information. See the section entitled “Business—Customers and Contract Backlog.”

(3) Technical Utilization is the efficiency with which we perform well operations without stoppage due to mechanical, procedural or other operational events that result in down, or zero, revenue time. Technical Utilization is calculated as the technical utilization of each rig in operation for the period, divided by the number of rigs in operation for the period, with the technical utilization for each rig calculated as the total number of hours during which such rig generated dayrate revenue, divided by the maximum number of hours during which such rig could have generated dayrate revenue, expressed as a percentage measured for the period. We have not provided Technical Utilization data for the year ended December 31, 2017 because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017. See “Business—History and Development—Acquisition from Transocean” for more information. Technical Utilization is calculated only with respect to rigs in operation for the relevant period and is not calculated on a fleet-wide basis. Technical Utilization is a measure of efficiency of rigs in operation and is not a measurement of utilization of our fleet overall.

(4) Economic Utilization is the dayrate revenue efficiency of our operational rigs and reflects the proportion of the potential full contractual dayrate that each jack-up rig actually earns each day. Economic Utilization is affected by reduced rates for standby time, repair time or other planned out-of-service periods. Economic Utilization is calculated as the economic utilization of each rig in operation for the period, divided by the number of rigs in operation for the period, with the economic utilization of each rig calculated as the total revenue, excluding bonuses, as a proportion of the full operating dayrate multiplied by the number of days on contract in the period. We have not provided Economic Utilization data for the year ended December 31, 2017 because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017. See “Business—History and Development—Acquisition from Transocean” for more information. Economic Utilization is calculated only with respect to rigs in operation for the relevant period and is not calculated on a fleet-wide basis. Economic Utilization is a measure of efficiency of rigs in operation and is not a measurement of utilization of our fleet overall.

(5) Total recordable incident frequency (“TRIF”) is a measure of the rate of recordable workplace injuries. TRIF, as defined by the International Association of Drilling Contractors, is derived by multiplying the number of recordable injuries during the twelve-month period prior to the specified date by 1,000,000 and dividing this value by the total hours worked in that period by the total number of employees. An incident is considered “recordable” if it results in medical treatment over certain defined thresholds (such as receipt of prescription medication or stitches to close a wound) as well as incidents requiring the injured person to spend time away from work. We have not provided TRIF data for the year ended December 31, 2017 because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017. See “Business—History and Development—Acquisition from Transocean” for more information.

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RISK FACTORS

An investment in our Shares involves significant risks. You should carefully consider all of the information in this Prospectus, including the risks and uncertainties described below, before making an investment in our Shares. Any of the following risks could have a material adverse effect on our business, financial condition and results of operations. In any such case, the market price of our Shares could decline, and you may lose part or all of your investment.

RISK FACTORS RELATED TO OUR INDUSTRY

The jack-up drilling market historically has been highly cyclical, with periods of low demand and/or over-supply that could result in adverse effects on our business.

The jack-up drilling market historically has been highly cyclical and is primarily related to the demand for jack-up rigs and the available supply of jack-up rigs. Demand for jack-up rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. It is not unusual for jack-up rigs to be unutilized or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. During historical industry periods of high utilization and high dayrates, industry participants ordered the construction of new jack-up rigs, which has resulted in an over-supply of jack-up rigs worldwide. During periods of supply and demand imbalance, jack-up rigs are frequently contracted at or near cash breakeven operating rates for extended periods of time until dayrates increase when the supply/demand balance is restored. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.

The significant decline in oil and gas prices and resulting reduction in spending by customers, together with the increase in supply of jack-up rigs in recent years, has resulted in an oversupply of jack-up rigs and a decline in utilization and dayrates, a situation which may persist for many years.

A prolonged period of reduced demand and/or excess jack-up rig supply may require us to idle or dispose of additional jack-up rigs or to enter into low dayrate contracts or contracts with unfavorable terms. For more information on our jack-up rig disposal policy, see the section entitled “Business—Our Fleet.” There can be no assurance that the demand for jack-up rigs will increase in the future. Any further decline or if there is not an improvement in demand for jack-up rigs could have a material adverse effect on our business, financial condition and results of operations.

The offshore contract drilling industry is highly competitive, with periods of excess rig availability which reduce dayrates and could result in adverse effects on our business.

Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, rig age, safety records and competency are key factors in determining which qualified contractor is awarded a job. Competitive factors include: rig availability, rig location, rig operating features and technical capabilities, pricing, workforce experience, operating efficiency, condition of equipment, contractor experience in a specific area, reputation and customer relationships. If we are not able to compete successfully, our revenues and profitability may be impacted, which could have a material adverse effect on our business, financial condition and results of operations.

The supply of offshore drilling rigs, including jack-up rigs, has increased significantly in recent years. Delivery of newbuild drilling rigs will continue to increase rig supply in coming years and could curtail a strengthening, or trigger a further reduction, in utilization and dayrates. Approximately 13 newbuild jack-up rigs (of which nine were delivered to us) were delivered during 2018, representing an approximate 3% increase in the total worldwide fleet of competitive offshore drilling rigs since the end of 2017. As of June 12, 2019, there were approximately 62 newbuild jack-up rigs reported to be on order or under construction to be delivered no later than the end of 2020. Most of the newbuild jack-up rigs to be delivered no later than the end of 2020, including the eight newbuild jack-up rigs we have agreed to purchase, do not have drilling contracts in place. In addition, the supply of marketed offshore drilling rigs could further increase due to depressed market conditions resulting in an increase in uncontracted rigs as existing contracts expire. There is no assurance that the market in general or a geographic region in particular will be able to fully absorb the supply of new rigs in future periods. Any continued oversupply of drilling rigs could have a material adverse effect on our business, financial condition and results of operations.

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The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.

The success of our business largely depends on the level of activity in offshore oil and natural gas exploration, development and production, which may be affected by conditions in the worldwide economy. Oil and natural gas prices, and market expectations of potential changes in these prices, significantly affect the level of drilling activity. Historically, when drilling activity and operator capital spending decline, utilization and dayrates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. Oil and natural gas prices have historically been volatile, and oil prices have declined significantly since mid-2014 with prices in excess of $100 per barrel (as defined below), causing operators to reduce capital spending and cancel or defer existing programs, substantially reducing the opportunities for new drilling contracts. Oil prices have rebounded from the 12-year lows experienced during early 2016, and in 2017 experienced the first increase in average prices since 2014, with prices ranging from a low of $44 to a high of $67 per barrel. Oil prices experienced both increases and declines throughout 2018 and remained generally volatile, with prices ranging from a low of $50.47 to a high of $86.29 per barrel, according to Bloomberg. Oil prices have averaged approximately $66 per barrel during the first six months of 2019, around 23% higher than the cost of oil at the end of 2018, which was $54 per barrel. Oil prices increased gradually from January until April, reaching $75 per barrel, however, fell sharply toward the end of May and first half of June, dropping below $60 per barrel on June 12, 2019. In recent weeks, oil prices have increased. As of July 25, 2019, the price of oil was $63.13 per barrel. While oil prices have improved against historic lows, they have not improved to a level that supports increased rig demand which sufficiently absorbs existing rig supply and generates a meaningful increase in dayrates. We expect insufficient demand to continue as long as oil prices and rig supply remain at current levels. A lack of a meaningful and sustained recovery in oil and natural gas prices, continued volatility in prices or further price reductions, may cause our customers to maintain historically low levels or further reduce their overall level of activity, in which case demand for our services may decline and our results of operations may be adversely affected through lower rig utilization and/or low dayrates. Numerous factors may affect oil and natural gas prices and the level of demand for our services, including:

• regional and global economic conditions and changes therein;

• oil and natural gas supply and demand;

• expectations regarding future energy prices;

• the ability of the Organization of the Petroleum Exporting Countries (“OPEC”) to reach further agreements to set and maintain production levels and pricing and to implement existing and future agreements;

• the level of production by non-OPEC countries;

• capital allocation decisions by our customers, including the relative economics of offshore development versus onshore prospects;

• tax policy;

• advances in exploration and development technology;

• costs associated with exploring for, developing, producing and delivering oil and natural gas;

• the rate of discovery of new oil and gas reserves and the rate of decline of existing oil and gas reserves;

• trade policies and sanctions imposed on oil-producing countries or the lifting of such sanctions;

• laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions, or materially increase the cost of such exploration and development;

• the further development or success of shale technology to exploit oil and gas reserves;

• available pipeline and other oil and gas transportation capacity;

• the development and exploitation of alternative fuels;

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• laws and regulations relating to environmental matters, including those addressing alternative energy sources and the risks of global climate change;

• changes in tax laws, regulations and policies;

• merger, acquisition and divestiture activity among E&P Companies;

• the availability of, and access to, suitable locations from which our customers can explore and produce hydrocarbons;

• activities by non-governmental organizations to restrict the exploration, development and production of oil and gas in light of environmental considerations;

• disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof;

• natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills;

• the worldwide social and political environment, including uncertainty or instability resulting from changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and renewable energy and changes in investors’ expectations regarding environmental, social and governance (ESG) matters; and

• the worldwide military and political environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East or geographic areas in which we operate, or acts of terrorism.

Despite significant declines in capital spending and cancelled or deferred drilling programs by many operators since 2015, oil and gas production has not yet been reduced by amounts sufficient to result in a rebound in pricing to levels seen prior to the current downturn, and we may not see sufficient supply reductions or a resulting rebound in pricing for an extended period of time or at all. Further, any agreements of OPEC and certain non-OPEC countries to freeze and/or cut production may not be fully realized. The lack of actual production cuts or freezes, or the perceived risk that OPEC countries may not comply with such agreements, may result in depressed oil and gas prices for an extended period of time. In addition, higher oil and gas prices may not necessarily translate into increased activity, and even during periods of high oil and gas prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, including their lack of success in exploration efforts. Any increase or reduction in drilling activity by our customers may not be uniform across different geographic regions. Locations where costs of drilling and production are relatively higher may be subject to greater reductions in activity or may recover more slowly. Such variation between regions may lead to the relocation of drilling rigs, concentrating drilling rigs in regions with relatively fewer reductions in activity leading to greater competition.

Advances in onshore exploration and development technologies, particularly with respect to onshore shale, could also result in our customers allocating more of their capital expenditure budgets to onshore exploration and production activities and less to offshore activities.

Moreover, there has historically been a strong link between the development of the world economy and the demand for energy, including oil and gas. 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.

These factors could impact our revenues and profits and as a result limit our future growth prospects. Any significant decline in dayrates or utilization of our rigs could have a material adverse effect on our business, financial condition and results of operations. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and obtain insurance coverage that we consider adequate or are otherwise required by our contracts.

Down-cycles in the jack-up drilling industry and other factors may affect the market value of our jack-up rigs and the newbuild rigs we have agreed to purchase.

Consumer demand in the shallow-water offshore drilling market, or the jack-up drilling market, has been adversely impacted by trends in the price of oil since 2014 and has not yet recovered. As trends in the price of oil impact the spending plans of our customers, they may also affect the book or market values of our

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jack-up rigs. The price of Brent crude oil fell from a high of $115.19 per barrel on June 19, 2014, to a low of $26.01 on January 20, 2016, and was $50.57 on December 31, 2018, and $63.39 on July 25, 2019. Although oil prices have recovered from historic lows, they remain generally volatile. If oil prices do not stabilize at favorable levels or we experience further oil price down-cycles, we expect customer demand will continue to be negatively affected. If the offshore drilling industry suffers adverse developments due to the price of oil in the future, the fair market value of our existing and newbuild jack-up rigs may decline. In addition, the fair market value of the jack-up rigs that we currently own, have agreed to acquire, or may acquire in the future, may decrease depending on a number of factors, including:

• the general economic and market conditions affecting the offshore contract drilling industry, including competition from other offshore contract drilling companies;

• the types, sizes and ages of our jack-up rigs;

• the supply and demand for our jack-up rigs;

• the costs of newbuild jack-up rigs;

• prevailing drilling services contract dayrates;

• government or other regulations; and

• technological advances.

If jack-up rig values fall significantly, we may have to record an impairment in our financial statements, which could affect our results of operations. Certain of our competitors in the offshore drilling industry may have a larger or more diverse fleet and a more favorable capitalization than we do, which could allow them to better withstand any impairment recorded for their own fleets or the effects of a commodity price down-cycle. Additionally, if we sell one or more of our jack-up rigs at a time when drilling rig prices have fallen, we may incur a loss on disposal and a reduction in earnings, which may cause us to breach the covenants in certain of our finance agreements. Under certain of our Financing Arrangements, 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 jack-up rigs securing borrowings under each of such agreements decrease below required levels. If we are unable to comply with the covenants in certain of our financing agreements and we are unable to get a waiver, a default could occur under the terms of those agreements.

Our operations involve risks due their international nature.

We operate in various regions throughout the world. As a result of our international operations, we may be exposed to political and other uncertainties, including risks of:

• terrorist acts;

• armed hostilities, war and civil disturbances;

• acts of piracy, which have historically affected marine assets;

• significant governmental influence over many aspects of local economies;

• the seizure, nationalization or expropriation of property or equipment;

• uncertainty of outcome in court proceedings in any jurisdiction where we may be subject to claims;

• the repudiation, nullification, modification or renegotiation of contracts;

• limitations on insurance coverage, such as war risk coverage, in certain areas;

• political unrest;

• monetary policy and foreign currency fluctuations and devaluations;

• an 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;

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• imposition of, or changes in, local content laws and their enforcement, particularly in West Africa and Southeast Asia, where the legislatures are active in developing new legislation;

• sanctions or trade embargoes;

• compliance with various jurisdictional regulatory or financial requirements;

• compliance with and changes to tax laws and interpretations;

• other forms of government regulation and economic conditions that are beyond our control; and

• government corruption.

It is difficult to predict whether, and if so, when the risks referred to above may come to fruition and the impact thereof. Failure to comply with, or adapt to, applicable laws and regulations or other disturbances as they occur may subject us to criminal sanctions, civil remedies or other increases in costs, including fines, the denial of export privileges, injunctions, seizures of assets or the inability to otherwise remove our jack-up rig from the country in which it operates.

RISK FACTORS RELATED TO OUR BUSINESS

We may not be able to renew contracts which expire and our customers may seek to cancel or renegotiate their contracts, particularly in response to unfavorable industry conditions.

Many jack-up drilling contracts are short-term, and oil and natural gas companies tend to reduce activity levels quickly in response to declining oil and natural gas prices. Our jack-up drilling contracts typically range from three to twenty-four months, although this period may be longer in certain jurisdictions, including the Middle East. During oil price down-cycles, our customers may be unwilling to commit to long-term contracts. Short-term drilling contracts do not provide the stability or visibility of revenue that we would otherwise receive with long-term drilling contracts.

In addition, in difficult market conditions, some of our customers may seek to terminate their agreements with us or to renegotiate our contracts using various techniques, including threatening breaches of contract and applying commercial pressure. Some of our customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee or compensation for costs incurred up to termination. The general principle is that any such early termination payment, where applicable, shall compensate us for lost revenues less operating expenses for the remaining contract period; however, in some cases, any 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 any termination payment as a result of non-performance, periods of downtime or impaired performance caused by equipment or operational issues (typically after a specified remedial period), or sustained periods of downtime due to force majeure events beyond our control. In addition, state-owned 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 (i) customers choosing not to renew short-term contracts, (ii) customers seeking to repudiate their contracts, including through claims of non-performance, (iii) customers seeking to renegotiate their contracts to reduce the agreed day rates and (iv) cancellation of drilling contracts (with or without early termination payments). Such actions may have a material adverse effect on our business, financial condition and results of operations.

Prevailing market conditions, including the supply of jack-up rigs worldwide, may affect our ability to obtain favorable contracts for our newbuild jack-up rigs or our jack-up rigs that do not have contracts.

As of June 12, 2019, according to Rystad Energy, 199 jack-up rigs in the existing worldwide fleet were off-contract and a relatively large number of the drilling rigs under construction have not been contracted for future work, including the eight jack-up rigs we have agreed to purchase and which have not been delivered. In addition, as of June 30, 2019, we had 11 rigs warm stacked and three rigs cold stacked which are available for contracting (with the exception of the “Eir,” which is subject to a sale agreement).

The current over-supply of jack-up rigs may be exacerbated by the entry of newbuild rigs into the market, many of which are without drilling contracts. The supply of available uncontracted jack-up rigs has intensified

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price competition, reducing dayrates as the active fleet worldwide grows. Customers may also 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. For an overview of our fleet, see the section entitled “Business—Our Fleet.”

Our ability to obtain new contracts will depend on our customers and prevailing market conditions, which may vary among different geographic regions and types of drilling rigs sought. There is no assurance that we will secure drilling contracts for the newbuild rigs we have agreed to purchase or our jack-up rigs that are stacked, and the drilling contracts that we do secure may be at unattractive dayrates. If we are unable to secure contracts for our newbuild jack-up rigs, we may idle or stack these rigs, which means such rigs will not produce revenues but will continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. The key characteristics of our rigs owned but not under contract which may yield differences in their marketability or readiness for use include whether such rigs are warm stacked or cold stacked, age of the rig, geographic location and technical specifications; please see our fleet status report beginning on page 107 for further information concerning these features by rig. We may also seek to delay delivery of our newbuild jack-up rigs, which could adversely affect our revenues and profitability. We have no right to delay delivery of the newbuild rigs we have agreed to purchase if we are unable to secure contracts. If we request a delay to the contractual delivery dates, we are dependent upon the outcome of any negotiations with the shipyard, which may not result in any delay or may lead to an increase in cost to compensate the shipyard.

If new contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contract terms among our then-active fleet, our business could be adversely affected. We may also be required to accept more risk in areas other than price to secure a contract and we may be unable to push this risk down to other contractors or be unable or unwilling at competitive prices to insure against this risk, which will mean the risk will have to be managed by applying other controls. This could lead to significant losses or us being unable to meet our liabilities in the event of a catastrophic event on one of our rigs.

Our Total Contract Backlog may not be realized.

The Total Contract Backlog (in $ millions) presented in this Prospectus is only an estimate and is not the same measure as the acquired contract backlog presented in our Consolidated Financial Statements and Interim Financial Statements. Many of our contracts are short-term. As of June 30, 2019, our Total Contract Backlog was approximately $383.2 million, excluding unexercised options, and we had 9 contracts that expire during 2019, 2 contracts that expire during 2020 and 5 contracts that expire during 2021.

The actual amount of revenues earned and the actual periods during which revenues are earned will be different from our Total Contract Backlog projections due to various factors, including shipyard and maintenance projects, downtime and other events within or beyond our control. We do not adjust our Total Contract Backlog for expected or unexpected downtime. Our inability, or the inability of our customers, to perform under our or their contractual obligations could result in results that vary significantly than those contemplated by our Total Contract Backlog.

We have a limited operating history and have experienced net losses since inception.

We have a limited operating history upon which to base an evaluation of our current business and future prospects. Also, our lack of operating history may affect our ability to obtain customer contracts. We are establishing our history as an operator of jack-up rigs and as a result, the revenue and income potential of our business is unproven. We have experienced net losses since inception and this trend may continue. We may not be able to generate significant revenues in the future. We will be subject to the risks, uncertainties and difficulties frequently encountered by early-stage companies in evolving markets. We may not be able to successfully address any or all of these risks and uncertainties. Failure to adequately do so may have a material adverse effect on our business, financial condition and results of operations.

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In connection with the audits of our consolidated financial statements as of and for the years ended December 31, 2017 and 2018, we and our independent registered public accounting firm identified a material weakness in our internal control over financial reporting. If we fail to develop and maintain an effective system of internal control over financial reporting, we may be unable to accurately report our financial results or prevent fraud.

We were established in August 2016 and have since that time experienced significant expansion, especially during 2018 when we acquired Paragon Offshore Limited and shortly thereafter proceeded with a reorganization program. This growth, combined with the loss of historically significant individuals and relationships in the legacy Paragon business, resulted in too few accounting personnel to adequately follow and maintain our accounting processes, and constrained our ability to deploy resources with which to address compliance with internal controls over financial reporting. Subsequently, and although we are not yet subject to the certification or attestation requirements of Section 404 of the Sarbanes-Oxley Act, in the course of preparing and auditing our consolidated financial statements for the years ended December 31, 2017 and 2018, we and our independent registered public accounting firm respectively identified one material weakness in our internal control over financial reporting as of December 31, 2018. In accordance with reporting requirements set forth by the SEC, a “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our Company’s annual or interim consolidated financial statements will not be prevented or detected on a timely basis. The material weakness identified relates to lack of a sufficient number of competent financial reporting and accounting personnel to prepare and review our consolidated financial statements and related disclosures in accordance with U.S. GAAP and financial reporting requirements set forth by the SEC. Neither we nor our independent registered public accounting firm undertook a comprehensive assessment of our internal control under the Sarbanes-Oxley Act for purposes of identifying and reporting any material weakness in our internal control over financial reporting. Had we performed a formal assessment of our internal control over financial reporting or had our independent registered public accounting firm performed an audit of the effectiveness of our internal control over financial reporting, additional material weaknesses may have been identified.

To remedy our identified material weakness subsequent to December 31, 2018, we have undertaken steps to strengthen our internal control over financial reporting, including hiring more qualified personnel to strengthen the financial reporting function and to improve the financial and systems control framework and implementing regular and continuous U.S. GAAP accounting and financial reporting training programs for our accounting and financial reporting personnel. Further, we have engaged an external consulting firm to help us assess our compliance readiness under Rule 13a-15 of the Exchange Act of 1934, as amended (“the Exchange Act”) and improve overall internal controls.

We rely on a limited number of customers, and we are exposed to the risk of default or material non-performance by customers.

We have a limited number of customers and potential customers for our services. Mergers among oil and gas exploration and production companies have further reduced the number of available customers, which may increase the ability of potential customers to achieve pricing terms favorable to them as the jack-up drilling market recovers. Our five largest customers, subsidiaries of NDC, TAQA, BW Energy, Spirit Energy and Total, comprised 69% of our revenue for the year ended December 31, 2018.

We are subject to the risk of non-payment or non-performance by our customers. Certain of our customers may be highly leveraged and subject to their own operating and regulatory risks and liquidity risk, and such risks could lead them to seek to cancel, repudiate or seek to renegotiate our drilling contracts or fail to fulfill their commitments to us under those contracts. These risks are heightened in periods of depressed market conditions.

In addition, our drilling contracts provide for varying levels of indemnification and allocation of liabilities between our customers and us, including with respect to (i) well-control, reservoir liability and pollution, (ii) loss or damage to property, (iii) injury and death to persons arising from the drilling operations we perform and (iv) each respective parties’ consequential losses, if any. Apportionment of these liabilities is generally dictated by standard industry practice and the particular requirements of a customer. Under our drilling contracts, liability with respect to personnel and property customarily is generally allocated so that we and our customers each assume liability for our respective personnel and property, or a “knock-for-knock” basis.

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Customers have historically assumed most of the responsibility for, and indemnify contractors from, any loss, damage or other liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract when the source of the pollution originates from the well or reservoir, including damages resulting from blow-outs or cratering of the well, regaining control of, or re-drilling, the well and any 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 or otherwise limit indemnities or narrow the scope of their coverage, reducing our level of contractual protection. In addition, customers tend to request that we assume a limited amount of liability for pollution damage when such damage originates from our jack-up rigs and/or equipment above the surface of the water or is caused by our negligence, which liability generally has caps for ordinary negligence, with much higher caps or unlimited liability where the damage is caused by our gross negligence or willful misconduct, respectively. When we provide integrated well services, we may also be exposed to a risk of liability for reservoir or formation damage or loss of hydrocarbons.

Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to assume their responsibility, or otherwise honor their indemnity to us, for such losses. In addition, under the laws of certain jurisdictions, such indemnities under certain circumstances may not be enforceable if the cause of the damage was our gross negligence or willful misconduct. The foregoing could result in us having to assume liabilities in excess of those agreed in our contracts. Although we maintain certain insurance policies, such insurance may not fully compensate us in the event any key customers or potential customers default on their obligations to us. Our insurance policies do not cover damages arising from the willful misconduct or gross negligence of our personnel (which may include our subcontractors in some cases). In the event of a default or other material non-payment or non-performance by any customers, our business, financial condition and results of operations could be adversely affected.

Our drilling contracts contain fixed terms and dayrates, and consequently we may not fully recoup our costs in the event of a rise in expenses, including operating and maintenance costs.

Our operating costs are generally related to the number of rigs in operation and the cost level in each country or region where the rigs are located, which may increase depending on the circumstances. In contrast, the majority of our contracts have dayrates that are fixed over the contract term. 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. 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 result in us being unable to recoup incurred costs.

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, although 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 for reasons beyond our control, increasing our costs, without additional compensation from the customer.

We incur expenses, such as preparation costs, relocation costs, operating costs and maintenance costs, which we may not fully recoup from our customers, including where our jack-up rigs incur idle time between assignments.

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. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. In connection with new contracts or contract extensions, we incur expenses relating to preparation for operations, particularly when a jack-up rig moves to a new geographic location. These expenses may be significant. 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. In addition, equipment maintenance costs fluctuate depending upon the type of activity that the jack-up rig is performing and the age and condition of the equipment. In situations where our jack-up rigs incur idle time

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between assignments, the opportunity to reduce the size of our crews on those jack-up rigs is limited, as the crews will be engaged in preparing the rig for its next contract, which could affect our ability to make reductions in crew costs, provisions, equipment, insurance, maintenance and repairs or shipyard costs.

When a jack-up rig faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to prepare the jack-up rig for stacking and maintenance in the stacking period. As of June 30, 2019, we had 14 jack-up rigs either “warm stacked,” which means the rigs, including our newbuild jack-up rigs which have not yet been activated, are kept ready for redeployment and retain a maintenance 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, not including our jack-up rigs being activated to commence drilling operations as of such date. When idled or stacked, jack-up rigs do not earn revenues, but continue to require cash expenditures for crews, fuel, insurance, berthing and associated items. These expenses may be significant. Should units be idle for a longer period, we may be unable to reduce these expenses. This could have a material adverse effect on our business, financial condition and results of operations.

We incur activation costs, and may incur cost-overruns, on our newbuild jack-up rigs, which we may not fully recoup from our customers or the shipyard, as applicable.

We have an order book with Keppel for eight newbuild jack-up rigs. In connection with delivery of our newbuild jack-up rigs, we incur expenses relating to the activation of such newbuild rig. These expenses are significant and may be in excess of $13 million per newbuild jack-up rig activated. Expenses may vary based on the scope and length of such required preparations and may fluctuate depending upon the type of activity that the rig is intended to perform.

Construction of our newbuild jack-up rigs is subject to risks of delay or cost overruns inherent in any large construction project from numerous factors, including shortages of equipment, materials or skilled labor, unscheduled delays in the delivery of ordered materials and equipment or shipyard construction, the failure of equipment to meet quality and/or performance standards, financial or operating difficulties experienced by equipment vendors or the shipyard, unanticipated actual or purported change orders, the inability to obtain required permits or approvals, unanticipated cost increases between order and delivery, design or engineering changes, and work stoppages and other labor disputes. In addition, risks include adverse weather conditions or any other events of force majeure, terrorist acts, war, piracy or civil unrest. Significant cost overruns or delays could have a material adverse effect on our business, financial condition and results of operations. Additionally, failure to deliver a newbuild rig on time may result in the delay of revenue from that rig. Newbuild jack-up rigs may also experience start-up difficulties following delivery or other unexpected operational problems that could result in uncompensated downtime or the cancellation or termination of drilling contracts, which could have a material adverse effect on our business, financial condition and results of operations.

We may be unable to integrate or deploy newbuild jack-up rigs into our active fleet.

There is some inherent risk in accepting newbuilding deliveries and a newly delivered rig may require some rework or additional testing before it passes our stringent requirements for acceptance. This may delay the delivery date or, in limited circumstances, require us to increase our capital expenditure in order to accept the new rig. If we are unable to integrate newbuild jack-up rigs into our fleet according to our expected timeline, this would reduce our available capacity. In addition, any delay in delivery of a newbuild jack-up rig could delay, or result in us paying damages under, any customer contracts we enter into for those newbuilding rigs prior to delivery, which could have a material adverse effect on our business, financial condition and results of operations.

The limited availability of qualified personnel in the locations in which we operate may result in higher operating costs as the offshore drilling industry recovers.

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. In some regions, the limited availability of qualified personnel in combination with local regulations focusing on crew composition are expected to further impact the supply of qualified offshore drilling crews. In addition,

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during industry down-cycles, qualified personnel may elect to seek alternative employment and may not return to the offshore drilling industry immediately during periods of recovery, if at all, which may have the effect of further reducing the supply of qualified personnel.

Personnel salaries across the jack-up drilling market are affected by the cyclical nature of the offshore drilling industry, particularly during industry down-cycles. As the jack-up drilling market recovers, the tightness of labor supply within the industry could further create and intensify upward pressure on wages and make it more difficult or costly for us to staff and service our rigs. Furthermore, as a result of any increased competition for qualified personnel, we may experience a reduction in the experience level of our personnel, which could lead to higher downtime and more operating incidents. Such developments could have a material adverse effect on our business, financial condition and results of operations.

Furthermore, offshore drilling personnel (both employees and contractors) in certain regions, including those personnel who operate in the North Sea, are represented by collective bargaining agreements. Pursuant to 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, individuals covered by these collective bargaining agreements may be working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel or other increased costs or increased operating restrictions.

If we are unable to attract and retain highly skilled personnel who are qualified and able to work in the locations in which we operate 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. At a minimum, all offshore personnel are required to complete Basic Offshore Safety Induction and Emergency Training (“BOSIET”) or a similar offshore survival and training course. We may also require additional training certifications prior to employment with us, depending on the location of the drilling and related technical requirements. In addition to direct costs associated with BOSIET, other training courses and required training materials, there may be indirect costs to personnel (such as travel costs and opportunity costs) which have the effect of limiting the flow of new qualified personnel into the offshore drilling industry.

In addition to the technical certification requirements, our ability to operate worldwide depends on our ability to obtain the necessary visas and work permits for such 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. This includes local content laws which restrict or otherwise effect our crew composition. 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. These factors could increase competition for highly-skilled personnel throughout the offshore drilling industry, which may indirectly affect our business, financial condition and results of operations.

We may from time to time be a party to certain joint venture or other contractual arrangements with partners that introduce additional risks to our business.

We may establish relationships with partners, whether through the formation of joint ventures with local participation or through other contractual arrangements. For example, in Nigeria, in compliance with Nigerian law, our jack-up rig “Frigg” is currently operating for Shell in Nigeria in collaboration with our local partner, Valiant Energy Services West Africa, who has taken a 10% interest in Borr Jack-Up XVI Inc., the owner of our rig “Eir,” in order to comply with local content obligations. In addition, we finalized the Mexican JV structure through which we, along with our local partner in Mexico, CME, will provide integrated well services to Pemex. We expect to commence operations under the Pemex Contract in early August 2019. Please see the section entitled "Business—Joint Venture, Partner and Agency Relationships” for more information.

We believe that opportunities involving partners may arise from time to time and we may enter into such arrangements. We may not realize the expected benefits of any such arrangements and such arrangements may introduce additional risks to our business. In order to establish or preserve our relationship with our

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partners, we may agree to risks and contributions of resources that are proportionately greater than the returns we could receive, which could reduce our income and return on our investment in such arrangements. In certain joint ventures or other contractual relationships with our partners, we may transfer certain ownership stakes in one or more of our rig-owning subsidiaries and/or accept having less control over decisions made in the ordinary course business. In certain arrangements with our local partners we may also guarantee the performance of their obligations under the relevant contract and we may not be able to enforce any contractual indemnifications we obtain from such parties. Any reduction in our ownership of our rig-owning subsidiaries and/or control over decisions made in the ordinary course of business could significantly reduce our income and return on our investment in such arrangements.

Our operations involving partners are subject to risks, including (i) disagreement with our partner as to how to manage the drilling operations being conducted; (ii) the inability of our partner to meet their obligations to us, the joint venture or our customer, as applicable; (iii) litigation between our partner and us regarding joint-operational matters and (iv) failure of a partner to comply with applicable laws, including sanctions and anti-money laundering laws and regulations, and indemnity obligations. The happening of any of the foregoing events may have a material adverse effect on our business, financial condition and results of operations.

In addition, we rely on the internal controls and financial reporting controls of our subsidiaries and if any of our subsidiaries, including joint ventures which are subsidiaries, fail to maintain effective controls or to comply with applicable standards, this could make it difficult to comply with applicable reporting and audit standards. For example, the preparation of our consolidated financial statements requires the prompt receipt of financial statements from each of our subsidiaries and associated companies, some of whom rely on the prompt receipt of financial statements from each of their subsidiaries and associated companies. Additionally, in certain circumstances, we may be required to file with our annual report on Form 20-F, or a registration statement filed with the SEC, financial information of associated companies which has been audited in conformity with SEC rules and regulations and applicable audit standards. If we are unable for any reason to procure such financial statements or audited financial statements, as applicable, from our subsidiaries and associated companies, we may be unable to comply with applicable SEC reporting standards.

We are exposed to the risk of default or material non-performance by subcontractors.

In order to provide integrated drilling services to our customers, we rely on subcontractors to perform certain services. We may be liable to our customers in the event of non-performance by any such subcontractor. We cannot ensure that our back-to-back arrangements with our subcontractors, contractual indemnities or insurance arrangements will provide adequate protection for the risks we face. To the extent that there is any back-to-back arrangement, contractual indemnity and/or receipt of evidence of insurance from a subcontractor, there can be no assurance that our subcontractors will be in a position to honor such arrangements in the event a claim is made against us by a customer and we seek to pass the related damages on to the subcontractor. In addition, under the laws of certain jurisdictions, such indemnities under certain circumstances may not be enforceable. The foregoing could result in us having to assume liabilities in excess of those agreed in our contracts, which may have a material adverse effect on our business, financial condition and results of operations.

Public health threats could have an adverse effect on our operations and financial results.

Our crews generally work on a rotation basis, with a substantial portion relying on international air transport for rotation. 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. 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 business and financial results.

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We rely on a limited number of suppliers and may be unable to obtain needed supplies on a timely basis or at all.

We rely on certain third parties to provide supplies and services necessary for our offshore drilling operations, including drilling equipment suppliers, catering and machinery suppliers. There are a limited number of available suppliers throughout the offshore drilling industry and past consolidation among suppliers, combined with a high volume of drilling rigs 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.

With respect to certain items, such as blow-out preventers and drilling packages, we are dependent on the original equipment manufacturer for repair and replacement of the item or its spare parts. We maintain limited inventory of certain items, such as spare parts, and sourcing such items may involve long-lead times (six months or longer). Standardization across our fleet assists with our inventory management, however the inability to obtain certain items may be exacerbated if such items are required on multiple jack-up rigs simultaneously.

If we are unable to source certain items from the original equipment manufacturer for any reason, or if our inventory is rendered unusable by the original equipment manufacturer due to safety concerns, resulting 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 jack-up rigs. In addition, we may be unable to activate our jack-up rigs in response to market opportunities.

We may be unable to obtain, maintain and/or renew the permits necessary for our operations or experience delays in obtaining such permits, including the class certifications of rigs.

The operation of our jack-up rigs requires certain governmental approvals, the number and prerequisites of which vary, depending on the jurisdictions in which we operate our jack-up rigs. Depending on the jurisdiction, these governmental approvals may involve public hearings and costly undertakings on our part. We may not be able to obtain such approvals or such approvals may not be obtained in a timely manner. If we fail to secure the necessary approvals or permits in a timely manner, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment.

Offshore drilling rigs, although not self-propelled units, are nevertheless registered in international shipping or maritime registers and are subject to the rules of a classification society, which allows such rigs to be registered in an international shipping or maritime register. The classification society certifies that a drilling rig is “in-class,” signifying that such drilling rig has been built and maintained in accordance with the rules of the relevant classification society and complies with applicable rules and regulations of the drilling rig’s country of registry, or flag state, and the international conventions to which that country is a party. 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 jack-up rigs are built and maintained in accordance with the rules of a classification society, currently being ABS. The class status varies depending on a jack-up rig’s status (stacked or in operation). Operational rigs are certified by the relevant classification society as being in compliance with the mandatory requirements of the relevant national authorities in the countries in which our jack-up rigs are flagged and other applicable international rules and regulations. If any jack-up rig does not maintain the appropriate class certificates for its present status (stacked or in operation), fails any periodical survey or special survey and/or fails to comply with mandatory requirements of the relevant national authorities of its flag state, the jack-up rig may be unable to carry on operations and, depending on its status (stacked or in operation), may not be insured or insurable. Any such inability to carry on operations or be employed could have a material adverse effect on our business, financial condition and results of operations.

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We are a holding company and are dependent upon cash flows from subsidiaries to meet our obligations. If our operating subsidiaries experience sufficiently adverse changes in their financial condition or results of operations, or we otherwise become unable to arrange further financing to satisfy our debt or other obligations as they become due, we may become subject to insolvency proceedings.

Our only material assets are our interests in our subsidiaries. We conduct our operations through, and all of our assets are owned by, our subsidiaries and our operating revenues and cash flows are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of liquidity that we use to meet our obligations. Contractual provisions and/or local laws, as well as our subsidiaries’ financial condition, operating requirements and debt requirements, may limit our ability to the obtain cash from subsidiaries that we require to pay our expenses or otherwise meet our obligations when due. Applicable tax laws may also subject such payments to us by subsidiaries to further taxation.

The inability to transfer cash from our subsidiaries may mean that, although we may have sufficient resources on a consolidated basis to meet our obligations when due, we may not be permitted to make the necessary transfers from our subsidiaries to formerly meet our debt and other obligations when due. The terms of certain our Financing Arrangements, which are described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Existing Indebtedness,” may also place restrictions on our cash balance and require us to maintain reserves of cash that could inhibit our ability to meet our debt and other obligations when due.

If our operating subsidiaries experience sufficiently adverse changes in their financial condition or results of operations, or we otherwise become unable to arrange further financing to satisfy our debt or other obligations as they become due, we may become subject to insolvency proceedings. Any such proceedings would have a material adverse effect on our business, financial condition and results of operations and could have a significant negative impact on the market price of our Shares.

Our business and operations involve numerous operating hazards.

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 require the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers, subcontractors 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 jack-up rig personnel, third parties or customers and suspension of operations. Our 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 or due to severe weather, including hurricanes, and marine life infestations. For instance, during Hurricane Harvey in the Gulf of Mexico in 2017, the hurricane caused a drillship owned by a subsidiary of Paragon (as defined below) to break loose from its moorings and it was subsequently involved in a series of collisions. 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 contractual indemnities to our customers and subcontractors 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 fines and penalties and to property, environmental, natural resource and other damage claims, and we may not be able to limit our exposure through contractual indemnities, insurance or otherwise.

Consistent with standard industry practice, customers have historically assumed, and indemnify contractors against, any loss, damage or other liability resulting from pollution or contamination when the source of the pollution originates from the well or reservoir, including damages resulting from blow-outs or cratering of the well, regaining control of, or re-drilling, the well and any 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 a contractor’s

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level of contractual protection. In addition, customers tend to request that contractors assume (i) limited liability for pollution damage above the water when such damage has been caused by the contractor’s jack-up rigs and/or equipment and (ii) liability for pollution damage when pollution has been caused by the negligence or willful misconduct of the contractor or its personnel. Consistent with standard industry practice, we may therefore assume a limited amount of liability for pollution damage when such damage originates from our jack-up rigs and/or equipment above the surface of the water or is caused by our negligence, in which case such liability generally has caps for ordinary negligence, with much higher caps or unlimited liability where the damage is caused by our gross negligence. When we provide integrated well services, we may also be exposed to a risk of liability for reservoir or formation damage or loss of hydrocarbons.

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 rig in the Gulf of Mexico in April 2010 (the “2010 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.

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 us. Moreover, pollution and environmental risks generally are not totally insurable.

Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnification for all risks. In addition, where we do have such insurance coverage, the amount recoverable under insurance may be less than the related impact on enterprise value after a loss or not cover all potential consequences of an incident and include annual aggregate policy limits. As a result, we retain the risk through self-insurance for any losses in excess of these limits or that are not insurable. Any such lack of reimbursement may cause us to incur substantial costs or may otherwise result in losses. 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 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.

Our information technology systems are subject to cybersecurity risks and threats.

We depend on digital technologies to conduct our offshore and onshore operations, to collect payments from customers and to pay vendors and employees. Our data protection measures and measures taken by our customers and vendors may not prevent unauthorized access of information technology systems. Threats to our information technology systems and the systems of our customers and vendors, associated with cybersecurity risks or attacks continue to grow. Threats to our systems and our customers’ and vendors’ systems may derive from human error, fraud or malice or may be the result of accidental technological failure. Our drilling operations or other business operations could also be targeted by individuals or groups seeking to sabotage or disrupt our information technology systems and networks, or to steal data. A successful cyberattack 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. In addition, breaches to our systems and systems of our customers and vendors could go unnoticed for some period of time. Any such attack or other breach of our information technology systems, or failure to effectively comply with applicable laws and regulations concerning privacy, data protection and information security, could have a material adverse effect on our business and financial results.

We have been subject to cyberattacks. For example we have been targeted by parties using fraudulent “spoof” and “phishing” emails and other means to misappropriate information or to introduce viruses or other malware through “trojan horse” programs to our computers. In response to these attacks and to prevent future attacks, we have engaged, and may in the future engage, third party vendors to review and supplement our defensive measures and assist us in our effort to eliminate, detect, prevent, remediate, mitigate or alleviate cyber or other security problems, although such measures may not be effective. While we have not experienced any cybersecurity attacks or breaches to date that had a material impact on us, such attacks in the future could have a material impact on our business or operations. There is risk that these types of activities will recur and persist. There can be no assurance that our defensive measures will be

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adequate to prevent them in the future. The costs to us to eliminate, detect, prevent, remediate, mitigate or alleviate cyber or other security problems, viruses, worms, malicious software programs, phishing schemes and security vulnerabilities could be significant and our efforts to address these problems may not be successful and could adversely impact our business, financial condition and results of operations.

We may be subject to litigation, arbitration and other proceedings that could have an adverse effect on us.

We are from time to time 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 and employment-dispute litigation, environmental litigation, contractual litigation with customers, subcontractors and/or suppliers, intellectual property litigation, litigation regarding historical liabilities of acquired companies, tax or securities litigation and maritime lawsuits, including the possible arrest of our jack-up rigs. Risks associated with litigation include potential negative outcomes, the costs associated with asserting our claims or defending against such litigation, and the diversion of management’s attention to these matters. Accordingly, current and future litigation and the outcome of such litigation could adversely affect our business, financial condition and results of operations.

We may be subject to claims related to Paragon and the financial restructuring of its predecessor.

Paragon Offshore Limited (“Paragon”) was incorporated on July 18, 2017 as part of the financial restructuring of its predecessor, Paragon Offshore plc, who commenced proceedings under chapter 11 of the U.S. Bankruptcy Code on February 14, 2016. On March 29, 2018, we concluded the acquisition of 99.41% of the shares of Paragon for a total consideration of $240 million (the “Paragon Transaction”), subsequently acquiring the majority of the remaining shares in July 2018.

We were not able to contact certain minority shareholders of Paragon in connection with our acquisition of all remaining shares in July 2018. In order to complete our subsequent acquisition of minority shares, we performed a squeeze out of the shareholders of 7,188 shares as we were not able to contact them upon closing of the Paragon Transaction. Although these shares were canceled, we may be subject to future claims of approximately $0.3 million in connection with the squeeze-out.

We have been advised by the administrators of Paragon Offshore plc that they are preparing to move from administration to liquidation, which will be the final stage in the winding-up process. Funding has been provided by Paragon Offshore Limited to finance the costs of the administrators’ implementation of the reorganization and the liquidation. Any request for additional funding from the administrators is subject to approval by Paragon Offshore Limited and currently there is no indication or expectation that any such request will be made. We believe that substantially all of the material claims against Paragon Offshore plc that arose prior to the date of the bankruptcy filing were addressed during the Chapter 11 proceedings or will be resolved in connection with the plan of reorganization and the order of the Bankruptcy Court confirming such plan (the “Plan”). If we are subject to claims that are attributable to Paragon Offshore plc, or any of its subsidiary undertakings, including in connection with certain litigation arrangements in place prior the Paragon Transaction, but excluding any and all claims for debts which are unrelated to the litigation proceedings, and which were not discharged in the bankruptcy proceedings, or we are presented with a claim from the administrators of Paragon Offshore plc under the indemnities given by Paragon Offshore Limited pursuant to the Plan, our business, financial condition and results of operations could be adversely affected.

RISK FACTORS RELATED TO OUR FINANCING ARRANGEMENTS

Future cash flows may be insufficient to meet obligations under the terms of our Financing Arrangements.

As of March 31, 2019, we had $1,388.3 million in principal amount of debt outstanding (including current portion but excluding back-end fees), representing 44.8% of our total assets, of which $1,038.3 million, including $753.3 million of PPL Financing (as defined below), $165 million drawn on our DNB Revolving Credit Facility, $60 million drawn on our DC Revolving Credit Facility and $60 million drawn on our Bridge Facility, was secured by, among other things, mortgages on 20 of our jack-up rigs and shares of certain of our subsidiaries. Following the signing of our Hayfin Facility, Syndicated Facility and New Bridge Facility

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agreements on June 25, 2019, as of June 30, 2019, $195 million drawn on our Hayfin Facility, $300 million drawn on our Syndicated Facility (which includes utilization of the $70 million facility for guarantees) and $25 million drawn on our New Bridge Facility was secured by, among other things, mortgages on 11 of our jack-up rigs and shares of certain of our subsidiaries.

Beginning in the fourth quarter of 2022, the delivery financing arrangements related to 14 of our newbuild jack-up rigs will begin to mature and will continue to mature throughout 2025. We may exercise an option to accept delivery financing from Keppel with respect to two additional newbuild jack-up rigs. In addition, outstanding obligations under our Hayfin Facility, Syndicated Facility and New Bridge Facility will mature in 2022. These obligations will require significant amortization payments. Our future cash flows may be insufficient to meet all of these debt obligations and contractual commitments, and any insufficiency could negatively impact our business.

Our ability to fund planned expenditures and amortization payments related to our delivery financing arrangements, 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 outstanding and future indebtedness could affect our future operations, since a portion of our cash flow from operations will be dedicated to the payment of interest and principal on such debt, and consequently will not be available for other purposes. If 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—however, covenants in certain of our credit facilities may limit our ability to take these actions. If we are not able to borrow additional funds, raise other capital or utilize available cash on hand, a default could occur under certain or all of our Financing Arrangements. If we are able to refinance our debt or raise new debt or equity financing, such financing might not be on favorable terms.

If we fail to make a payment when due under our newbuilding contracts or otherwise fail to take delivery of our newbuild jack-up rigs, this may result in a default under our newbuilding contracts. In such case, we could also lose all or a portion of the payments made by us, which as of March 31, 2019, amounted to $432.5 million, and we could be liable for penalties and damages under such contracts. If a default occurs under any of our newbuilding contracts, we may lose all or a portion of the payments made by us under the relevant newbuilding contract and/or the shipyards may elect to foreclose their liens on our jack-up rigs, in which case our business, financial condition and results of operations could be adversely affected.

The covenants in certain of our Financing Arrangements impose operating and financial restrictions on us.

The covenants in certain of our Financing Arrangements impose operating and financial restrictions on us. These restrictions may affect our flexibility in planning for, and reacting to, changes in our business or economic conditions and may otherwise prohibit or limit our ability to undertake certain business activities without consent of the lending banks. In addition, the restrictions contained in certain of our Financing Arrangements and future financing arrangements could impact our ability to withstand current or future economic or industry downturns, compete with others in our industry for strategic opportunities or operationally (to the extent our competitors are subject to less onerous restrictions) and may also limit our ability to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate and other purposes. These restrictions include (i) paying dividends and repurchasing our Shares, (ii) changing the general nature of our business, (iii) making financial investments, (iv) entering into secured capital markets indebtedness and (v) removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim is required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions).

In addition, the terms of certain of our Financing Arrangements require us to maintain specified financial ratios and to satisfy financial covenants, including a minimum book equity ratio of 40%, a positive working capital balance, a debt service cover ratio in excess of 1.25 our interest and related expenses, from the end of 2020, and minimum free liquidity, including undrawn amounts under our facilities, equivalent to the higher of (i) $50 million and (ii) 4% of net interest-bearing debt. In addition, our Hayfin Facility agreement contains a requirement that we maintain minimum liquidity equal to three months interest on the facility when the

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jack-up rigs providing security thereunder are not actively operating under an approved drilling contract (as defined in the Hayfin Facility agreement). If there is a change of circumstances that the lenders under certain of our Financing Arrangements believe has had, or is reasonably likely to have, a material adverse effect on our business, our ability to comply with our obligations under our Financing Arrangements and/or the security we have provided for our obligations, the lenders may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. The lenders under certain of our Financing Arrangements may also require replacement or additional security if the fair market value of the jack-up rigs over which security is provided is insufficient to meet the market value-to-loan covenant in our various agreements. Any impairment charges to our jack-up rigs or other investments and assets could adversely impact our ability to comply with the financial ratios and tests in certain of our Financing Arrangements. Certain of our Financing Arrangements also contain events of default which include non-payment, cross default, breach of covenants, insolvency and changes that have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under any of such agreements or related security documents or jeopardize the security provided thereunder. If there is an event of default, the lenders under our Financing Arrangements may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. The lenders may also require replacement or additional security if the fair market value of the jack-up rigs over which security is provided is insufficient to meet our market value-to-loan covenant. Additionally, the Syndicated Facility and New Bridge Facility agreements contain a “Most Favored Nation” clause whereby the lenders thereunder have a right to amend the financial covenants to reflect any more lender-favorable covenants in any other agreement pursuant to which loan or guarantee facilities are provided to us, including amendments to our Financing Arrangements.

We may not be able to obtain our lenders’ consent to waive or amend covenants that are beneficial for our business, which may impact our performance. Moreover, in connection with any future waivers or amendments to our Financing Arrangements that we may obtain, our lenders may modify the terms of our Financing Arrangements or impose additional operating and financial restrictions on us. If we are unable to comply with any of the covenants in our current or future debt agreements, and we are unable to obtain a waiver or amendment from our lenders, a default could occur under the terms of those agreements.

If a default occurs under any of our Financing Arrangements, the lenders thereunder could terminate their commitments to lend or in some circumstances accelerate the loan and declare all amounts borrowed due and payable or require the unwinding of certain guarantees provided under our Syndicated Facility. Our Financing Arrangements contain cross-default provisions, meaning that if we are in default under any of our Financing Arrangements, amounts outstanding under our other Financing Arrangements may also be in default, and become due and payable or, in the case of our Convertible Bonds, require cancellation and repayment. Any of these events could have a material adverse effect on our business, financial condition and results of operations.

Our Financing Arrangements are not necessarily reflective of those that may be in place from time to time.

We expect to borrow from time to time under our Syndicated Facility and New Bridge Facility to fund working capital and capital expenditures, such as activation and mobilization costs and/or to fund the issuance of guarantees required for temporary import of rigs, customs bonds, performance guarantees or other needs, subject to compliance with the covenants in certain of our Financing Arrangements. However, 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 or through bank, shipyard or other financing arrangements to fund our capital expenditures, and in industry downcycles, our operating expenses. Any additional indebtedness may include additional revolving credit facilities, term loans, bonds, refinancing of our Financing Arrangements or other forms of indebtedness. We may also issue additional Shares or other securities and our subsidiaries may also issue securities in order to fund working capital, capital expenditures, such as activation and mobilization costs, or other needs.

Our ability to incur additional indebtedness or refinance our current Financing Arrangements will depend on the condition of the lending markets, capital markets and our financial position at such time. Any additional indebtedness or refinancing of our Financing Arrangements may result in higher interest rates or encumbrance of our jack-up rigs and may require us to comply with more onerous covenants, which could

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further restrict our business operations. Increases in interest rates will increase interest costs on our variable interest rate debt instruments, which would reduce our cash flows. If we are not able to maintain a level of cash flows sufficient to operate our business in the ordinary course according to our business plan and are unable to incur additional indebtedness or refinance our Financing Arrangements, our business, financial condition and results of operations may be adversely affected.

We have delivery financing arrangements in place with Keppel, which exposes us to risk related to the financial condition of this shipyard.

We have an order book with Keppel for eight newbuild jack-up rigs and have accepted corresponding delivery financing facilities for five of these rigs in the amount of $454.5 million. With respect to certain newbuild jack-up rigs that are to be delivered by Keppel no later than the end of 2020, we have been provided with refund guarantees and/or parent company guarantees as security for Keppel’s obligation to refund predelivery installment payments in the event of a default by Keppel. Such guarantees entitle us to a refund under the relevant construction contract.

As of March 31, 2019, we had $29.4 million in cash and cash equivalents. In addition, we currently have $125 million available to borrow under our Syndicated Facility and New Bridge Facility, collectively, provided certain conditions precedent are met. If Keppel is unable to honor its obligations to us, including the obligation to refund installment payments under certain circumstances or provide the underlying financing for our delivery financing arrangements, and we are not able to borrow additional funds, raise other capital or use available cash on hand, borrowings under our Syndicated Facility and New Bridge Facility and available current cash on hand are not sufficient to pay the remaining installments related to our contracted commitments for our newbuild jack-up rigs and we may not be able to acquire these jack-up rigs and/or may be subject to lengthy arbitral or court proceedings, either of which may have a material adverse effect on our business, financial condition and results of operations.

We have suffered, and may suffer in the future, losses through our investments in other companies in the offshore drilling and oilfield services industry, including debt and other securities issued by such companies.

From time to time, we make and hold investments in other companies in our industry that own/operate offshore drilling rigs with similar characteristics to our fleet of jack-up rigs, subject to compliance with the covenants contained in certain of our Financing Arrangements that restrict such investments. We also purchase and hold debt or other securities issued by other companies in the offshore drilling industry from time to time.

We hold forward contracts for marketable securities in EnscoRowan PLC with unrealized losses of $23.6 million as of March 31, 2019, recorded in the balance sheet under unrealized loss on forward contracts. We also hold marketable securities which are investments in Oro Negro debt securities. These investments had accumulated unrealized losses of $12.9 million as of March 31, 2019, as recognized in our Statement of Comprehensive Income in our Interim Financial Statements. The above described investments are not a core part of our business strategy.

The market value of our equity interest in, or debt or other securities issued by, these companies has been, and may continue to be, volatile and has fluctuated, and may continue to fluctuate, in response to changes in oil and gas prices and activity levels in the offshore oil and gas industry. If we sell our equity interest or debt or other securities in an investment at a time when the value of such investment has fallen, we may incur a loss on the sale or an impairment loss being recognized, ultimately leading to a reduction in earnings.

An economic downturn could have an adverse effect on our ability to access the capital markets.

Negative developments in worldwide financial and economic conditions could impact our ability to access the lending and capital markets, which could impact our ability to react to changing economic and business conditions. Worldwide economic conditions could in the future impact lenders willingness to provide credit facilities to us, or our customers, causing them to fail to meet their obligations to us.

A renewed period of adverse development in the outlook for the financial stability of European, Middle Eastern or other countries, or market perceptions concerning these and related issues, could reduce the

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overall demand for oil and natural gas and for our services and thereby could affect our business, financial condition and results of operations. Brexit, or similar events in other jurisdictions, can impact global markets, which may have an adverse impact on our ability to access the capital markets. In addition, turmoil and hostilities in the Ukraine, Korea, the Middle East, North Africa, South America and other geographic areas and countries are adding to the overall risk picture.

Our Hayfin Facility and New Bridge Facility are provided by European banking institutions and our Syndicated Facility is provided jointly by European and American banking institutions. In addition, a substantial portion of our long-term debt, our delivery financing arrangements, is provided by Keppel and PPL, Singaporean companies that may be highly leveraged, are not capitalized in the same manner as a financial institution and that are subject to their own operating, liquidity or regulatory risks. These risks could lead to Keppel and/or PPL to seek to cancel, repudiate or renegotiate our construction contracts or fail to fulfill or challenge their commitments to us under those contracts, including the obligation to refund installment payments. The risks of liquidity concerns are heightened in periods of depressed market conditions. If economic conditions in European or American markets preclude or limit financing from European and/or American banking institutions, or if financial conditions in the Republic of Singapore impair the ability of Keppel or PPL to honor their obligations to us, 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 or the United States remain favorable for lending. If our ability to access the debt or capital markets is affected by general economic conditions and contingencies and uncertainties that are beyond our control, there may be a material adverse effect on our business and financial condition.

Interest rate fluctuations could affect our earnings and cash flow.

In order to finance our growth we have incurred significant amounts of debt. A significant portion of our debt bears floating interest rates. As such, movements in interest rates could have an adverse effect on our earnings and cash flow. Interest rates under certain of our Financing Arrangements are determined with reference to LIBOR above a specified margin.

We currently have no hedging arrangements in place with respect to our floating-rate debt. We may enter into hedging arrangements from time to time in the future with respect to our interest rate exposure, but such hedging may not significantly reduce the risk we face. 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.

Moreover, the United Kingdom Financial Conduct Authority (“FCA”), which regulates LIBOR, has announced that it intends to stop persuading or compelling banks to submit rates for the calculation of LIBOR to the administrator of LIBOR after 2021 (“FCA Announcement”). The FCA Announcement indicates that the continuation of LIBOR on the current basis is not guaranteed after 2021. Significant increases in LIBOR or uncertainty surrounding its phase out after 2021 could adversely affect our business, financial condition and results of operation.

Fluctuations in exchange rates and the nonconvertibility of currencies could result in losses to us.

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. As a result of our international operations, we may be exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. dollars.

Notably, with respect to jack-up drilling contracts in the North Sea, revenues are commonly received, and salaries generally paid, in Euros or Pounds. In addition, we may receive revenue or incur expenses in other currencies, including the Nigerian naira. 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. Moreover, we may experience adverse tax consequences attributable to currency fluctuations. 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. As we earn revenues and incur expenses in currencies other than our reporting currency, there is a risk that currency fluctuations could have an adverse effect on our statements of operations and cash flows.

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RISK FACTORS RELATED TO APPLICABLE LAWS AND REGULATIONS

Compliance with, and breach of, the complex laws and regulations governing international drilling activity and 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, or impose restrictions, obligations or liabilities in connection with, exploration and development drilling for oil and gas. Offshore drilling in certain areas, including arctic areas, has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment. For example, on December 20, 2016, the then-United States President invoked a law that banned offshore oil and gas drilling in large areas of the Arctic and the Atlantic Seaboard. It is presently unclear for how long this ban may be effective. On April 28, 2017, a Presidential Executive Order was issued modifying the ban to apply only to federally protected marine sanctuaries. An appeal of a federal district court order dated March 29, 2019 vacating this modification of the 2016 U.S. ban is pending. A ban on new drilling in Canadian Arctic waters was announced simultaneously with the issuance of the 2016 U.S. ban. It is also possible that compliance with these laws and regulations may, in the future, add significantly to our operating costs or significantly limit drilling activity.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. 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. 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. Delays or denials of shipments of parts and equipment that we need could cause unscheduled operational downtime. Future earnings may be negatively affected by compliance with any such new legislation or regulations.

Any failure to comply with applicable legal and regulatory trading obligations, including as a result of changed or amended interpretations or enforcement policies, could also result in administrative, criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, the seizure of shipments, the loss of import and export privileges and the suspension or termination of operations. New laws, the amendment or modification of existing laws and regulations 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.

Local content requirements may increase the cost of, or restrict our ability to, obtain needed supplies or hire experienced personnel, or may otherwise affect our operations.

Local content requirements are policies imposed by governments that require companies who operate within their jurisdiction to use domestically supplied goods and services or work with a domestic partner in order to operate within the jurisdiction. Governments in some countries in which we operate, or may operate in the future, have become increasingly active in the requirements with respect to the ownership of drilling companies, local content requirements for equipment used in operations within the country and other aspects of the oil and gas industries in their countries. In addition, national oil companies may impose restrictions on the submission of tenders, including eligibility criteria, which effectively require the use of domestically supplied goods and services or a local partner.

For example, the Nigerian Oil and Gas Industry Content Development Act, 2010 (the “Local Content Act”) was enacted to provide for the development, implementation and monitoring of Nigerian content in the oil and gas industry and places emphasis on the promotion of Nigerian content among companies bidding for contracts in the oil and gas industry. The Local Content Act provides the parameters and minimum level/percentages to be used in determining and measuring Nigerian content in the composite human and material resources and services applied by operators and contractors in any industry project within Nigeria. In addition, we finalized the Mexican JV structure through which we, along with our local partner in Mexico, CME, will provide integrated well services to Pemex. In connection with our tender for the Pemex Contract

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and subsequent execution thereof, we were subject to eligibility criteria. We expect to commence operations under the Pemex Contract in early August 2019. Please see the section entitled "Business—Joint Venture, Partner and Agency Relationships” for more information.

Some foreign governments and/or national oil companies 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 and could result in increased costs and impact our ability to effectively control and operate our jack-up rigs, which could have a material impact on our earnings, operations and financial condition in the future.

As a limited liability company incorporated under Bermuda law with subsidiaries in certain offshore jurisdictions, our operations may be subject to economic substance requirements.

On December 5, 2017, following an assessment of the tax policies of various countries by the Code of Conduct Group for Business Taxation of the European Union (the “COCG”), the Council of the European Union (the “Council”) approved and published Council conclusions containing a list of “non-cooperative jurisdictions” for tax purposes (the “2017 Conclusions”). On March 12, 2019, the Council adopted a revised list of non-cooperative jurisdictions (the “2019 Conclusions”). Although not considered non-cooperative jurisdictions in the 2017 Conclusions, certain countries, including Bermuda, the Cayman Islands and the British Virgin Islands, were listed as having “tax regimes that facilitate offshore structures which attract profits without real economic activity.” Certain of our subsidiaries may also from time to time be organized in other jurisdictions identified by the COCG based on global standards set by the Organization for Economic Co-operation and Development with the objective of preventing low-tax jurisdictions from attracting profits from certain activities.

In connection with the 2017 Conclusions, and in an effort to avoid being placed on the list of non-cooperative jurisdictions, the government of Bermuda, among others, committed to addressing COCG proposals relating to economic substance for entities doing business in or through their respective jurisdictions and to pass legislation to implement any appropriate changes by the end of 2018. On December 17, 2018, the House of Assembly of Bermuda passed the Economic Substance Act 2018 of Bermuda (the “Economic Substance Act”), which became operative on December 31, 2018, along with the Economic Substance Regulations 2018 of Bermuda (the “Economic Substance Regulations”). The Economic Substance Act requires each registered entity to maintain a substantial economic presence in Bermuda and provides that a registered entity that carries on a relevant activity complies with economic substance requirements if (i) it is directed and managed in Bermuda, (ii) its core income-generating activities (as may be further prescribed) are undertaken in Bermuda with respect to the relevant activity, (iii) it maintains adequate physical presence in Bermuda, (iv) it has adequate full time employees in Bermuda with suitable qualifications and (v) it incurs adequate operating expenditure in Bermuda in relation to the relevant activity. A registered entity that carries on a relevant activity is obliged under the Economic Substance Act to file a declaration with the Bermuda Registrar of Companies on an annual basis containing certain information.

In the 2019 Conclusions, Bermuda and the Republic of the Marshall Islands, among others, were placed by the E.U. on the list of non-cooperative jurisdictions for tax purposes for failing to implement certain commitments previously made to the E.U. by the agreed deadline. At present, the impact of being included on the list of non-cooperative jurisdictions for tax purposes is unclear. It was announced by the European Council on May 17, 2019 that, following an amendment to the Economic Substance Regulations, Bermuda had been removed from the list of non-cooperative tax jurisdictions. We are now awaiting the publication of final guidance notes from the Bermuda Government on the application of the Economic Substance Act and the Economic Substance Regulations.

We are incorporated under Bermuda law and certain of our subsidiaries are organized in other jurisdictions identified by the COCG, both as non-cooperative jurisdictions or jurisdictions having tax regimes that facilitate offshore structures that attract profits without real economic activity, including the Cayman Islands, the Republic of the Marshall Islands and the British Virgin Islands.

Jurisdictions identified by the COCG, including the Crown Dependencies, the Cayman Islands and the British Virgin Islands, have enacted or may enact economic substance laws and regulations that we may be

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obligated to comply with. For example, new legislation adopted in the Cayman Islands requires certain entities that carry out particular activities to comply with an economic substance test whereby the entity must show that it (i) carries out activities that are of central importance to the entity from the Cayman Islands, (ii) has held an adequate number of its board meetings in the Cayman Islands when judged against the level of decision-making required and (iii) has an adequate (a) amount of operating expenditures in the Cayman Islands, (b) physical presence in the Cayman Islands and (c) number of full-time employees in the Cayman Islands. If we fail to comply with our obligations under the Economic Substance Act or any similar law applicable to us in any other jurisdictions, we could be subject to financial penalties and spontaneous disclosure of information to foreign tax officials in related jurisdictions and may be struck from the register of companies in Bermuda or such other jurisdiction. Any of these actions could have a material adverse effect on our business, financial condition and results of operations.

The obligations of being a public company, including compliance with the reporting requirements of the Exchange Act and NYSE Listed Company Manual, require certain resources and will cause us to incur additional costs.

We are subject to reporting and other requirements as a result of our listing on the Oslo Børs and the listing on the Cayman Stock Exchange of an intergroup bond issued by one of our subsidiaries. Upon our listing on the NYSE, complying with applicable statutes, regulations and requirements related to being a public company in the United States will occupy additional time of our Board and management and will increase our costs and expenses. We will need to:

• comply with applicable rules promulgated by the NYSE and U.S. regulations applicable to foreign private issuers registered under the Securities Exchange Act;

• prepare and distribute periodic annual and other reports in compliance with our obligations under the U.S. federal and Norwegian securities laws;

• maintain certain internal policies and procedures; and

• involve and retain to a greater degree outside counsel and accountants in the above activities.

If we fail to comply with requirements relating to being a public company in the United States when obligated to do so, our business could be harmed and our Share price could decline.

We qualify as an emerging growth company under the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), which exempts us from certain disclosure obligations, including the filing of an auditor’s attestation report regarding the effectiveness of our internal controls on financial reporting for a certain period of time. We intend to take advantage of the reduced reporting requirements and exemptions until we are no longer an emerging growth company or we become a large accelerated filer. We have taken advantage of certain reduced reporting and other requirements in this Prospectus. Notwithstanding our status as an emerging growth company, we have not elected to use the extended transition period for complying with any new or revised financial accounting standards and, in accordance with SEC standards applicable to emerging growth companies, such election is irrevocable. We cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common shares less attractive to investors.

Rules adopted by the SEC pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, as amended (the “Sarbanes-Oxley Act”), require that we assess our internal control over financial reporting annually, beginning with our second annual report. These rules are complex. They require significant documentation, testing and possible remediation of any significant deficiencies in or material weaknesses of internal controls in order to meet the detailed standards under these rules. See the section entitled “—Risk Factors Related to our Business—In connection with the audits of our consolidated financial statements as of and for the years ended December 31, 2017 and 2018, we and our independent registered public accounting firm identified a material weakness in our internal control over financial reporting. If we fail to develop and maintain an effective system of internal control over financial reporting, we may be unable to accurately report our financial results or prevent fraud.” for more information. Certain internal policies and procedures will be added prior to the time at which we are required to express our view as to the effectiveness of our internal controls over financial reporting. However, when such evaluation is required in future fiscal years, we

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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, when required to do so, 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. We cannot predict if investors will find our Shares less attractive because we will rely on the exemptions available to us as an emerging growth company. If some investors find our common shares less attractive as a result, there may be a less active trading market for our common shares and our common shares price may be more volatile.

We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

Our operations, including divestment of our jack-up rigs where appropriate, are subject to numerous international, national and local, environmental and safety laws and regulations, treaties and conventions in force in international waters and the jurisdictions in which our jack-up rigs operate or are registered, which can significantly affect the ownership and operation of our jack-up rigs. These requirements include:

• the United Nation’s International Maritime Organization, or the “IMO,” 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 IMO International Convention on Load Lines, 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;

• requirements of 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, “OCSLA”;

• the Code for the Construction and Equipment of Mobile Offshore Drilling Units, 2009, or the “MODU Code 2009”;

• the Basel Convention on the Control of Transboundary Movements of Hazardous Wastes and their Disposal, or the “Basel Convention”;

• the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships, 2009, or the “Hong Kong Convention”; and

• certain regulations of the European Union, including Regulation (EC) No 1013/2006 on Shipments of Waste and Regulation (E.U.) No 1257/2013 on Ship Recycling.

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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 life of our jack-up rigs. These costs could have a material adverse effect on our profitability. 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 that could limit our ability to do business or increase the cost of our doing business and that 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, major environmental incidents involving the offshore drilling industry, such as the 2010 Deepwater Horizon Incident (to which we were not a party), or other similar events in the future, may result in further regulation of the offshore 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 to 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.

Our jack-up rigs 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 jack-up rigs, clean up the releases, compensate for natural resource damages and comply with more stringent requirements in our discharge permits. Moreover, such 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.

Insurance coverage protecting us against damages incurred or fines imposed as a result of our violation of applicable environmental laws may not be available or we may choose not to obtain such insurance. If insurance is available and we have obtained the coverage, it may not be adequate to cover our liabilities and fully mitigate our risk 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.

The United Kingdom’s referendum to exit from the European Union will have uncertain effects and could adversely impact the offshore drilling industry.

In June 2016, the United Kingdom voted to exit from the European Union (commonly referred to as “Brexit”). The terms of Brexit and the resulting U.K./E.U. relationship are uncertain for companies doing business both in the United Kingdom and the broader global economy. 35% and 32.1% of our total revenues were generated in the United Kingdom for the year ended December 31, 2018 and the three months ended

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March 31, 2019, respectively. In addition, certain of our cold stacked jack-up rigs may from time to time be located in the United Kingdom and our remaining jack-up rigs may from time to time move into territorial waters of the United Kingdom. Furthermore, certain of our on-shore employees may from time to time be employed by Borr Drilling Management UK, which is based in the United Kingdom. Our business and operations may be impacted by any actions taken by the United Kingdom after Brexit, including with respect to employee and related persons permits and visas, and other authorizations required to live, work or operate within the United Kingdom. In particular, the impact of potential changes to the United Kingdom’s migration policy could adversely impact our employees of non-U.K. nationality that may from time to time be working in the United Kingdom, as well as have an uncertain impact on cross-border labor. The potential loss of the EU “passport,” or any other potential restrictions on free travel of U.K. citizens to Europe, and vice versa, could adversely impact the jobs market in general and our operations in Europe. Moreover, our business and operations may be impacted by any subsequent vote in Scotland to seek independence from the United Kingdom. Brexit, or similar events in other jurisdictions, can impact global markets, including foreign exchange and securities markets. 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.

Future government regulations may adversely affect the offshore drilling industry.

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 rigs;

• exchange rates or exchange controls;

• oil and gas exploration and development;

• the taxation of earnings;

• the taxation of the earnings of expatriate personnel; and

• the use and compensation of local employees and suppliers by foreign contractors.

It is difficult to predict what government regulations may be enacted in the future that could adversely affect the offshore drilling industry. 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 the seizures of assets.

Data protection and regulations related to privacy, data protection and information security could increase our costs, and our failure to comply could result in fines, sanctions or other penalties, as well as have an impact on our reputation.

We rely on information technology systems and networks in our operations and administration of our business. We are therefore subject to regulations related to privacy, data protection and information security in the jurisdictions in which we do business. As privacy, data protection and information security laws are interpreted and applied, compliance costs may increase, particularly in the context of ensuring that adequate data protection and data transfer mechanisms are in place.

In recent years, there has been increasing regulatory enforcement and litigation activity in the areas of privacy, data protection and information security in the U.S. and in various countries in which we operate, and legislators and/or regulators in the U.S., the European Union and other jurisdictions in which we operate are increasingly adopting or revising privacy, data protection and information security laws. For example, the General Data Protection Regulations of the European Union became enforceable in all 28 E.U. member states as of May 25, 2018, and require us to undertake enhanced data protection safeguards, with fines for noncompliance up to 4% of global total annual worldwide turnover or €20 million (whichever is higher), depending on the type and severity of the breach. Compliance with current or future privacy, data protection and information security laws could significantly impact our current and planned privacy, data protection and information security related practices, our collection, use, sharing, retention and safeguarding of customer and/or employee information, and some of our current or planned business activities. If we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur

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significant liabilities and penalties as a result. Our failure to comply with applicable privacy, data protection and information security laws could affect our results of operations and overall business, as well as have an impact on our reputation.

Our ability to operate our jack-up rigs in the U.S. Gulf of Mexico could be impaired by governmental regulation and new regulations adopted in response to the investigation into the 2010 Deepwater Horizon Incident.

The Bureau of Ocean Energy Management, Regulation and Enforcement, or the BOEMRE, (formerly the Minerals Management Service of the U.S. Department of the Interior), effective October 1, 2011, reorganized into two new organizations: the Bureau of Safety and Environmental Enforcement (“BSEE”) and Bureau of Ocean Energy Management (“BOEM”). In the aftermath of the 2010 Deepwater Horizon Incident (to which we were not a party), the BSEE and its predecessor put in place new and revised regulations governing safety and environmental management systems (“SEMS”), commonly referred to as SEMS II. The SEMS II regulations focus on operator obligations and require operators to flow SEMS obligations and commitments through their supply chain. Moreover, BOEM and BSEE have issued a number of new and revised regulations and guidelines since their reorganization, including, a new pilot inspection program for offshore facilities, a new well control rule issued in April 2016 and revised effective July 2019, additional guidelines requiring mobile offshore drilling units (“MODUs”) to be outfitted with global positioning systems, guidelines for tie-downs on drilling rigs and permanent equipment and facilities attached to outer continental shelf production platforms, and moored drilling rig fitness and guidelines that provide for enhanced information and data requirements from oil and natural gas companies that operate properties in the U.S. Gulf of Mexico region of the outer continental shelf. These guidelines effectively imposed new requirements on the offshore oil and natural gas industry. Implementation of new guidelines or regulations that may apply to jack-up rigs may subject us to increased costs and limit the operational capabilities of our jack-up rigs if, in the future, we have operations in the U.S. Gulf of Mexico region.

Other U.S. regulators also impose regulation on offshore drilling in the U.S. Gulf of Mexico. In addition, the oil and gas industry has adopted new equipment and operating standards, such as the American Petroleum Institute Standard 53, relating to the design, maintenance, installation and testing of well control equipment. In order to obtain drilling permits, operators must submit applications that demonstrate compliance with the enhanced regulations, which require independent third-party inspections, certification of well design and well control equipment, and emergency response plans in the event of a blowout, among other requirements. Operators have previously had, and may in the future have, difficulties obtaining drilling permits in the U.S. Gulf of Mexico.

We continue to evaluate these new measures to ensure that our rigs and equipment are in full compliance, when applicable. Additional requirements could be forthcoming. We are not able to predict the likelihood, nature or extent of additional rulemaking or when the interim rules, or any future rules, could become final. The current and future regulatory environment in the U.S. Gulf of Mexico could impact the demand for drilling rigs in the U.S. Gulf of Mexico in terms of overall number of rigs in operations and the technical specification required for offshore rigs to operate in the U.S. Gulf of Mexico. We cannot predict the potential impact of new regulations that may be forthcoming, nor can we predict if implementation of additional regulations might subject us to increased costs of operating and/or a reduction in the area of operation in the U.S. Gulf of Mexico.

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. 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. Moreover, our interpretation of the tax laws in effect may change from time to time. 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.

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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 positions we have taken in tax filings related to our operational structure, intercompany pricing policies, the taxable presence of our subsidiaries in certain countries or any other situation, or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure, or if we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings could increase substantially and our earnings and cash flows from operations could be materially adversely affected.

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 on Climate Change conference in Paris and entered into force on November 4, 2016. As at January 1, 2013, all ships (including jack-up rigs) 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. A roadmap for a “comprehensive IMO strategy on a reduction of GHG emissions from ships” was approved by MEPC at its 70^th session in October 2016, and in 2018 IMO adopted an initial strategy designed to reduce the emission of greenhouse gases from ships, including short-term, mid-term and long-term candidate measures, with a vision of reducing and phasing out greenhouse gas emissions from ships as soon as possible in the 21^st Century. These requirements could cause us to incur additional compliance costs. In May 2019, the MPEC approved a number of measures aimed at achieving the IMO initial strategy’s objectives.

In the United States, 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 rigs, such regulation of drilling rigs 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 has 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, require us to install new emission controls, require us to acquire emission allowances or pay taxes related to our greenhouse gas emissions, or require us to 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 that we cannot predict with certainty at this time.

Further, physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could have a material adverse effect on our operations, particularly given that our rigs may need to curtail damages or may suffer damages during significant weather events.

Additionally, adverse effects upon the oil and gas industry related to the worldwide social and political environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and

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renewable energy, concern about the environmental impact of climate change and investors’ expectations regarding environmental, social and governance (ESG) matters, 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 jack-up rigs, which we cannot predict with certainty at this time.

Failure to comply with international anti-corruption legislation, including the U.S. Foreign Corrupt Practices Act of 1977, the U.K. Bribery Act 2010 or the Bribery Act 2016 of Bermuda, could result in fines, criminal penalties, damage to our reputation and drilling contract terminations.

We currently operate, and historically have operated, our jack-up rigs 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 puts us in contact with persons who may be considered to be “foreign officials” under the U.S. Foreign Corrupt Practices Act of 1977 (the “FCPA”), and the Bribery Act 2010 of the United Kingdom (the “U.K. Bribery Act”).

In order to effectively compete in some foreign jurisdictions, we utilize local agents and/or establish entities with local operators or strategic partners. All of these activities may involve interaction by our agents with government officials. Even though some of our agents and partners may not themselves be subject to the FCPA, the U.K. Bribery Act or other anti-bribery laws to which we may be subject, if our agents or partners make improper payments to government officials or other persons in connection with engagements or partnerships with us, we could be investigated and potentially found liable for violations of such anti-bribery laws (including the books and records provisions of the FCPA) 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 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 and 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. Furthermore, detecting, investigating and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

If our jack-up rigs are located in countries that are subject to, or targeted by, economic sanctions, export restrictions or other operating restrictions imposed by the United States or other governments, our reputation and the market for our debt and common shares could be adversely affected.

The U.S. and other governments may impose economic sanctions against certain countries, persons and other entities that restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions in particular are targeted against countries (such as Russia, Venezuela, Iran and others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities. U.S. and other economic sanctions change frequently, and enforcement of economic sanctions worldwide is increasing. Subject to certain limited exceptions, U.S. law continues to restrict U.S.-owned or -controlled entities from doing business with Iran and Cuba, and various U.S. sanctions have certain other extraterritorial effects that need to be considered by non-U.S. companies. Moreover, any U.S. persons who serve as officers, directors or employees of our subsidiaries would be fully subject to U.S. sanctions. It should also be noted that other governments are more frequently implementing and enforcing sanctions regimes.

From time to time, we may be party to drilling contracts with countries or government-controlled entities that become subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism. Even in cases where the investment would not violate U.S. law, potential investors could view any such contracts negatively, which could adversely affect our reputation and the market for our shares. We do not currently have any drilling contracts or plans to initiate any drilling contracts involving operations in countries or with government-controlled entities that are subject to sanctions and embargoes imposed by the U.S. government and/or identified by the U.S. government as state sponsors of terrorism.

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There can be no assurance that we will be in compliance with all applicable economic sanctions and embargo laws and regulations, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Rapid changes in the scope of global sanctions may also make it more difficult for us to remain in compliance. Any violation of applicable economic sanctions could result in civil or criminal penalties, fines, enforcement actions, legal costs, reputational damage or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in our shares. Additionally, some investors may decide to divest their interest, or not to invest, in our shares simply because we may do business with companies that do business in sanctioned countries. Moreover, our drilling contracts may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us, or our jack-up 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.

RISK FACTORS RELATED TO THIS OFFERING AND OWNING OUR COMMON SHARES

The price of our common shares may fluctuate widely in the future, and you could lose all or part of your investment.

The market price of our Shares has fluctuated widely and may continue to do so as a result of many factors, such as actual or anticipated fluctuations in our operating results, changes in financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. The initial public offering price for the Shares offered hereby will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the Shares that will prevail in the trading market. Consequently, you may not be able to sell our Shares at prices equal to or greater than the price that you paid in this Offering. The following is a nonexhaustive list of factors that could affect our share price:

• our operating and financial performance;

• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

• the public reaction to our press releases, our other public announcements and our filings with the SEC;

• strategic actions by our competitors;

• our failure to meet revenue or earnings estimates by research analysts or other investors;

• changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

• speculation in the press or investment community;

• the failure of research analysts to cover our Shares;

• sales of our Shares by us or shareholders, or the perception that such sales may occur;

• changes in accounting principles, policies, guidance, interpretations or standards;

• additions or departures of key management personnel;

• actions by our shareholders;

• general market conditions, including fluctuations in oil and gas prices;

• domestic and international economic, legal and regulatory factors unrelated to our performance; and

• the realization of any risks described in this “Risk Factors” section.

In addition, the stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Shares. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s

41

securities. Such litigation, if instituted against us, could result in substantial costs and divert our management’s attention and resources, which could have a material adverse effect on our business, financial condition and results of operations.

There is no existing U.S. market for our Shares, and one that will provide you with adequate liquidity may not develop.

Prior to this Offering, there has been no public U.S. market for our Shares, which have traded only on the Oslo Børs. Our Shares have been approved for listing on the NYSE. An active or liquid public market for our Shares in the United States may not develop and, if it does, may not persist. We do not know the extent to which investor interest will lead to the development of an active trading market or how liquid that market might become. If an active trading market does not develop, you may have difficulty reselling any of our Shares at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our Shares and limit the number of investors who are able to buy our Shares. If an active trading market for our Shares does not develop in the United States, the price of our Shares may be more volatile and it may be more difficult and time consuming to complete a transaction in our common shares, which could have an adverse effect on the realized price of our Shares. You may have difficulty reselling any of the Shares above the public offering price. We cannot predict the price at which our Shares will trade. In addition, an adverse development in the market price for our common shares could negatively affect our ability to issue new equity to fund our activities.

The relative volatility and limited liquidity of the Norwegian securities markets may adversely affect the liquidity and market price of our Shares.

The market price of the Shares on the Oslo Børs has historically fluctuated over a wide range and may continue to fluctuate significantly in response to many factors such as actual or anticipated fluctuations in our operating results, changes in financial estimates by securities analysts, economic and regulatory trends, general market conditions, rumors and other factors, many of which are beyond our control. The Norwegian equity market is smaller and less liquid than the major U.S., and some other E.U., securities markets. The Oslo Børs is significantly less liquid than the NYSE, or other major exchanges in the world. As of June 30, 2019, the aggregate market capitalization of the Oslo Børs was equivalent to approximately NOK 2.7 trillion ($0.3 trillion). In contrast, as of June 30, 2019, the aggregate market capitalization of the NYSE was approximately $26.1 trillion. If the volatility in the market continues or worsens, it could have an adverse effect on the market price of our Shares and impact potential sale prices.

We maintain commercial relationships with a significant shareholder in our business who may sell or reduce its holding in our business.

Schlumberger is our principal shareholder. As of July 24, 2019, Schlumberger held 14.2% of our Shares. Furthermore, an executive officer of Schlumberger Limited sits on our Board. Other than the lock-up arrangements described in this Prospectus, to which Schlumberger is subject, there is no restriction on Schlumberger’s ability to sell, reduce or increase its holding in us, and any reduction or increase in its holding may lead to different outcomes than we currently envision. If Schlumberger sells substantial amounts of our common shares to the public market or is perceived by the public market as intending to sell, the trading price of our Shares could be adversely affected. In addition, sales of our Shares could impair our ability to raise capital, should we wish to do so. We cannot predict the timing or amount of future sales of our common shares by Schlumberger or any other shareholder, but such sales, or the perception that such sales could occur, may adversely affect prevailing market prices for our Shares.

Additionally, on March 26, 2017, we signed an agreement with Schlumberger establishing the commercial principles upon which we agreed to work closely with Schlumberger, on a non-exclusive basis, on certain aspects of our business which were subsequently identified in an enhanced collaboration agreement entered into on October 6, 2017 (both agreements collectively, the “Collaboration Agreement”) and which include the provision of streamlined, integrated drilling services and the sharing of infrastructure and technology. We also obtain certain supplies from an affiliate of Schlumberger. Although our Collaboration Agreement is not related to Schlumberger’s status as our principal shareholder, in the event Schlumberger does not maintain its shareholding in our business, the economic incentive or rationale for the Collaboration Agreement may be affected. Whether or not Schlumberger maintains such shareholding in our business, we

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may not necessarily achieve any anticipated synergies or opportunities envisioned by the Collaboration Agreement. Any reduction in Schlumberger’s shareholding may reduce our ability to realize operational or financial benefits from our relationship with Schlumberger, which could have a material adverse effect on our ability to obtain financing from equity raises or issuance of debt securities, the prevailing market prices of our Shares and our business, financial condition and results of operations.

We are permitted to adopt certain home country practices in relation to our corporate governance, which may afford you less protection.

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

As an issuer whose shares will be listed on the NYSE, we will be subject to corporate governance listing standards of the NYSE. However, NYSE rules permit a foreign private issuer like us to follow the corporate governance practices of its home country. Certain corporate governance practices in Bermuda, which is our home country, may differ significantly from NYSE corporate governance listing standards. Currently, we intend to comply with certain NYSE corporate governance listing standards by following certain home country practices. See the section entitled “Management—Board of Directors & Board Practices.” Therefore, our shareholders may be afforded less protection than they otherwise would have under NYSE corporate governance listing standards applicable to U.S. domestic issuers.

Certain transactions we have entered into may affect the value of our Shares

In connection with the pricing of our Convertible Bonds, we (i) purchased from Goldman Sachs International call options over 10,453,612 Shares with a strike price of $33.4815 and (ii) sold to Goldman Sachs International call options over the same number of shares with a strike price of $42.6125 (together, the “Call Spread Transactions”). The Call Spread Transactions mitigate the economic exposure from a potential exercise of the conversion rights embedded in our Convertible Bonds by improving the effective conversion premium for the Company in relation to our Convertible Bonds from 37.5% to 75% over the reference price of $24.35 per share. The Call Spread Transactions may separately have a dilutive effect on our earnings per share to the extent that the market price per share of our Shares exceeds the applicable strike price of the options at the time of exercise.

We or Goldman Sachs International may modify our initial hedge position by entering into or unwinding various derivatives with respect to our Shares and/or purchasing or selling Shares in secondary market transactions. This activity could also affect the number of shares and value of the consideration that holders of our Convertible Bonds will receive upon conversion of the Convertible Bonds, which could impact the market price of our Shares.

Future sales of our equity securities in the public market, or the perception that such sales may occur, could reduce our share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional equity securities, including additional Shares or convertible securities, in subsequent public offerings. After the completion of this Offering, we will have outstanding 110,068,351 Shares, and assuming no exercise of the underwriters’ option to purchase additional shares, the Related Parties (as defined below) will collectively own 26,340,927 of our common shares or approximately 23.9% of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in the section entitled “Underwriting,” but may be sold into the market in the future. See the section entitled “Shares Eligible for Future Sale.” Additionally, shares held by our employees and others will be eligible for sale in the United States at various times after the date of this Prospectus under the provisions of Rule 144 under the Securities Act (“Rule 144”) and will generally be freely tradable on the Oslo Børs.

Future issuances and sales of Shares or other equity securities may have a negative impact on the market price of our Shares. In particular, sales of substantial amounts of our Shares (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Shares.

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We depend on directors who are associated with affiliated companies, which may create conflicts of interest.

Our principal shareholder is Schlumberger and, in addition, significant shareholders include Drew Holdings Limited and Ubon Partners AS and, in each case, affiliates thereof, including, in the case of Drew Holdings Limited, Magni Partners (Bermuda) Limited (collectively, the “Related Parties”). We maintain commercial relationships with our Related Parties, including advisory arrangements that are currently in place and under which services continue to be provided to us. Certain of our Related Parties have, in the past, provided foundational loans to us, including our initial payment under the Hercules Acquisition (as defined below). Furthermore, certain Related Parties are required to serve on our Board pursuant to covenants contained in certain of our financing arrangements.

A majority of our directors, including the chairman of our Board, also serve as directors of the Related Parties. These dual positions may conflict with such individuals’ duties as one of our directors or officers regarding business dealings and other matters between each of the Related Parties and us. Our directors owe fiduciary duties to both us and each respective Related Party and may have conflicts of interest in matters involving or affecting us and our customers. The resolution of these conflicts may not always be in our or your best interest.

Please see the section entitled “Certain Relationships and Related Party Transactions” for more information, including information on the commercial arrangements between us and the Related Parties.

If securities or industry analysts do not publish research reports or publish unfavorable research about our business, the price and trading volume of our common shares could decline.

The trading market for our common shares will depend in part on the research reports that securities or industry analysts publish about us or our business. We may never obtain significant research coverage by securities and industry analysts. If limited securities or industry analysts continue coverage of us, the trading price for our common shares and other securities would be negatively affected. In the event we obtain significant securities or industry analyst coverage, and one or more of the analysts who covers us downgrades our securities, the price of our securities would likely decline. If one or more of these analysts ceases to cover us or fails to publish regular reports on us, interest in the purchase of our securities could decrease, which could cause the price of our common shares and other securities and their trading volume to decline.

We may not pay dividends in the future.

Under our Bye-Laws, any dividends declared will be in the sole discretion of our Board and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities, although the payment of dividends is restricted by the covenants in certain of our Financing Arrangements. 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 cannot predict when, or if, dividends will be paid in the future.

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 nonresidents of the United States, and all or a substantial portion of the assets of these nonresidents 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.

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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.

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 non-U.S. corporation will be treated as a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes for a taxable year if either (1) at least 75% of its gross income for such taxable year consists of certain types of “passive income” or (2) at least 50% of the average value of the corporation’s assets during such year produce or are held for the production of those types of “passive income.” For purposes of these tests, a non-U.S. corporation is treated as holding directly and receiving directly its proportionate share of the assets and income of any other corporation in which it directly or indirectly owns at least 25% (by value) of such corporation’s stock. Also, for purposes of these tests, “passive income” includes dividends, interest, 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 but does not include income derived from the performance of services.

Based on the current and anticipated valuation of our assets, including goodwill, and composition of our income and assets, we do not believe that we will be treated as a PFIC for U.S. federal income tax purposes for our current taxable year or in the foreseeable future. We believe that we will not be treated as a PFIC for any relevant period because we believe that any income we receive from offshore drilling service contracts should be treated as “services income” rather than as passive income under the PFIC rules. In addition, the assets we own and utilize to generate this “services income” should not be considered to be passive assets. Given the lack of authority and highly factual nature of the analysis, no assurance can be given in this regard. Moreover, we have not sought, and we do not expect to seek, a ruling from the Internal Revenue Service (“IRS”) on this matter. As a result, 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 in a manner that causes us to become a PFIC.

If we were treated as a PFIC for any taxable year during which a U.S. Holder (as defined in “Material Income Tax Considerations—U.S. Federal Income Tax Considerations”) held a common share, certain adverse U.S. federal income tax consequences could apply to such U.S. Holder. See “Material Income Tax Considerations—U.S. Federal Income Tax Considerations—Passive Foreign Investment Company Considerations” for a more comprehensive discussion.

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NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Prospectus and any other written or oral statements made by us or on our behalf may include forward-looking statements that reflect our current views with respect to future events and financial performance. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, underlying assumptions, expected industry trends, including statements in the sections entitled “Industry Overview” and “Management's Discussion and Analysis of Financial Condition and Results of Operations—General Trends and Outlook,” and other statements, which are other than statements of historical or present facts or conditions. 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 are reasonable, 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.

Actual results could differ materially from our forward-looking statements due to a number of factors, including the following:

• 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 jack-up rigs;

• supply and demand for drilling rigs and competitive pressure on utilization rates and dayrates;

• future energy prices;

• customer contracts, including total contract backlog, contract commencements, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilization and demobilizations;

• the repudiation, nullification, modification or renegotiation of drilling contracts;

• delays in payments by, or disputes with, our customers or subcontractors under our drilling contracts;

• the global number of contracted rigs and our ability to benefit from any increased activity;

• fluctuations in the market value of our drilling rigs and the amount of debt we can incur under certain covenants in certain of our Financing Arrangements;

• our liquidity and the adequacy of our cash flow for our operations and to satisfy our obligations;

• our ability to successfully employ our drilling rigs;

• our ability to procure or have access to financing and refinancing;

• our expected debt levels;

• our ability to comply with certain covenants in certain of our Financing Arrangements;

• our ability to pay dividends in the future;

• credit risks of our customers, partners and suppliers;

• credit risks of counterparties who provide us with delivery financing;

• 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;

• any inability to repatriate income or capital;

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• the operation and maintenance of our drilling rigs, 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;

• the ability to take delivery of our newbuild jack-up rigs and deploy them without certain rework or upgrades;

• the delivery financing arrangements in respect of the newbuild rigs we have agreed to purchase;

• local content regulations;

• wage and price controls and the imposition of trade barriers;

• the recruitment and retention of qualified personnel;

• regulatory or financial requirements to comply with foreign bureaucratic actions, including potential limitations on drilling activity, changing taxation policies, local content laws and regulations 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;

• tax matters, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated the various jurisdictions of incorporation of our subsidiaries as well as our activities in Bermuda, the United Kingdom, the Netherlands and the United States and any jurisdiction which may become relevant for us in the future;

• economic substance laws and regulations adopted or considered by various jurisdictions of incorporation of us and certain of our subsidiaries;

• 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;

• effects of accounting changes and adoption of accounting policies;

• any material weakness in our internal controls;

• the costs associated with being a public company, including compliance with the various U.S. securities laws;

• loss of our status as a foreign private issuer or an emerging growth company;

• our incorporation under the laws of Bermuda and the limited rights to relief that may be available compared to U.S. laws; and

• other factors described under “Risk Factors” and elsewhere in this Prospectus.

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

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USE OF PROCEEDS

The net proceeds from our issuance and sale of the Shares in this Offering will be approximately $41.0 million (or approximately $47.6 million if the underwriters exercise in full their option to purchase additional Shares), and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

We intend to use the net proceeds from this Offering for general corporate purposes, which may include funding future mergers, acquisitions or investments in complementary businesses, products or technologies; maintaining liquidity; repayment of indebtedness; and funding our working capital needs. We have no current specific plans to use the net proceeds from this Offering to fund future mergers, acquisitions or investments, or repay indebtedness. For more information on our indebtedness, see the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Existing Indebtedness.” We will have broad discretion in allocating the net proceeds from this Offering. The timing and amount of our actual expenditures will be based on many factors, including cash flows from operations and the anticipated growth of our business and customer base. Pending their use, we intend to invest the net proceeds of this Offering in short-term, investment grade, interest-bearing instruments or hold them as cash.

Although we currently anticipate that we will use the net proceeds from this Offering as described above, there may be circumstances where a reallocation of funds is necessary. The amounts and timing of our actual expenditures will depend upon numerous factors, including the factors described in the section entitled “Risk Factors” in this Prospectus. Accordingly, our management will have flexibility in applying the net proceeds from this Offering. An investor will not have the opportunity to evaluate the economic, financial or other information on which we base our decisions on how to use the proceeds.

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DIVIDEND POLICY

Under our Bye-Laws, our Board may pay a fixed cash dividend or may declare cash dividends or distributions on such days as may be determined by our Board from time to time. Under Bermuda law, a company may not declare or pay a dividend, or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (a) it is, or would after the payment be, unable to pay its liabilities as they become due; or (b) the realizable value of its assets would thereby be less than its liabilities.

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 their earnings and cash flow to us. Furthermore, the covenants in our New Bridge Facility agreement require the approval of our lenders prior to the distribution of any dividends and the covenants in our Syndicated Facility agreement subject dividends to certain conditions which if not met would require the approval of our lenders prior to the distribution of any dividend.

We have not paid dividends to our shareholders since incorporation. We aim to distribute a portion of our future earnings from operations, if any, to our shareholders from time to time as determined by our Board. Any dividends declared in the future will be at the sole discretion of our Board and will depend upon earnings, market prospects, current capital expenditure programs and investment opportunities.

Although we are incorporated in Bermuda, we are classified as a nonresident of Bermuda for exchange control purposes by the Bermuda Monetary Authority. Other than transferring Bermuda Dollars out of Bermuda, there are no restrictions on our ability to transfer funds into or out of Bermuda to pay dividends to U.S. residents who are holders of our common shares or other non-resident holders of our common shares in currency other than Bermuda Dollars.

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CAPITALIZATION

The following table sets forth our capitalization as of March 31, 2019:

• on an actual basis; and

• on an as-adjusted basis to give effect to (i) the incurrence of debt under our Bridge RCF and DC RCF subsequent to March 31, 2019, (ii) the repayment of the outstanding balances due under our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF and the finalization and subsequent drawdown of our Hayfin Facility, Syndicated Facility and New Bridge Facility, in each case occurring on June 28, 2019 ((i) and (ii) together, the “Refinancing”), and (iii) the sale of the Shares in this Offering and the application of the net proceeds from this Offering.

	As of March 31, 2019
	Actual			As Adjusted for the Refinancing			As Adjusted for the Refinancing and this Offering
	(in $ millions)
Cash and cash equivalents and short term investments
Cash and cash equivalents	$	29.4		$	177.0		$	218.0
Restricted cash		29.4			33.3			33.3
Marketable securities		26.8			26.8			26.8
Non-current liabilities
Long-term debt(1)		1,388.3			1,553.3			1,553.3
DNB Revolving Credit Facility		165.0			—			—
Bridge Facility		60.0			—			—
DC Revolving Credit Facility		60.0			—			—
Syndicated Facility		—			230.0			230.0
New Bridge Facility		—			25.0			25.0
Hayfin Facility		—			195.0			195.0
Shipyard Financing(2)		753.3			753.3			753.3
Convertible Bond		350.0			350.0			350.0
Shareholders’ equity
Common shares of par value $0.05 per share(3)		5.3			5.3			5.6
Additional paid-in capital		1,839.5			1,839.5			1,880.2
Treasury shares		(26.2	)		(26.2	)		(26.2	)
Other comprehensive loss		(12.9	)		(12.9	)		(12.9	)
Accumulated deficit		(334.1	)		(338.4	)		(338.4	)
Non-controlling interest		0.2			0.2			0.2
Total equity		1,471.8			1,467.5			1,508.5
Total capitalization	$	2,860.1		$	3,020.8		$	3,061.8

(1) Reflects the principal amount of debt outstanding (including current portion but excluding back-end fees). All of our long-term debt is secured by, among other things, mortgages on 20 of our jack-up rigs and shares of certain of our subsidiaries.

(2) Shipyard Financing includes PPL Newbuild Financing and Keppel Newbuild Financing, as described in the section “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Our Existing Indebtedness—Our Delivery Financing Arrangements.”

(3) Common shares of par value $0.05 per share were, prior to the Offering, authorized 125,000,000 shares, issued 106,528,065 shares and outstanding 105,068,351 shares as of March 31, 2019. The foregoing reflects our Reverse Share Split. Common shares of par value $0.05 per share were, following the Offering, authorized 125,000,000 shares, issued 111,528,065 shares and outstanding 110,068,351 shares (and authorized 125,000,000 shares, issued 112,278,065 shares and outstanding 110,818,351 shares assuming the underwriters exercise their option to purchase 750,000 additional shares in full).

The above table is derived from and should be read together with the sections of this Prospectus entitled “Use of Proceeds,” “Selected Consolidated Financial and Other Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and Interim Financial Statements and the accompanying notes thereto included elsewhere in this Prospectus.

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SELECTED CONSOLIDATED FINANCIAL AND OTHER DATA

Our selected consolidated statement of operations and other financial data for the years ended December 31, 2018 and 2017 and our selected consolidated balance sheet data as of December 31, 2018 and 2017 have been derived from our Consolidated Financial Statements, which are included elsewhere in this Prospectus. Our summary consolidated statement of operations and other financial data for the three months ended March 31, 2019 and 2018 and our consolidated balance sheet data as of March 31, 2019 have been derived from our Interim Financial Statements, which are included elsewhere in this Prospectus.

Our Consolidated Financial Statements and Interim Financial Statements are prepared and presented in accordance with U.S. GAAP. Our historical results are not necessarily indicative of results expected for future periods.

The following table should be read in conjunction with the sections entitled “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and Interim Financial Statements and notes thereto, which are included herein. Our Consolidated Financial Statements and Interim Financial Statements are maintained in U.S. dollars. We refer you to the notes to our Consolidated Financial Statements and Interim Financial Statements for a discussion of the basis on which our Consolidated Financial Statements and Interim Financial Statements are prepared, respectively.

We have effected a conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. Our post-Reverse Share Split Shares began to trade on the Oslo Børs on June 26, 2019. The table below reflects our Reverse Share Split. Unless otherwise indicated, all Share and per Share data in this Prospectus is adjusted to give effect to our Reverse Share Split and is approximate due to rounding.

	For the Three Months Ended March 31,						For the Year Ended December 31,
	2019			2018			2018			2017
	(in $ millions, except per share data)
SELECTED CONSOLIDATED STATEMENTS OF OPERATIONS DATA:
Operating revenues	$	51.9		$	10.6		$	164.9		$	0.1
Gain from bargain purchase		—			38.1			38.1			—
Gain on disposals		—			—			18.8			—
Operating expenses		(109.9	)		(62.8	)		(353.2	)		(109.8	)
Operating loss		(58.0	)		(14.1	)		(131.4	)		(109.7	)
Total other income (expenses), net		1.8			(19.7	)		(57.0	)		21.7
Income tax expense		(0.2	)		—			(2.5	)		—
Net loss		(56.4	)		(33.8	)		(190.9	)		(88.0	)
Other comprehensive gain (loss)		(7.3	)		—			0.6			(6.2	)
Total comprehensive loss	$	(63.7	)	$	(33.8	)	$	(190.3	)	$	(94.2	)
Net loss per common share:
Basic		(0.52	)		(0.35	)		(1.85	)		(1.70	)
Diluted		(0.52	)		(0.35	)		(1.85	)		(1.70	)
Common shares outstanding		105,068,351			105,068,351			105,068,351			95,264
Weighted average common shares outstanding		105,068,351			102,877,501			102,877,501			51,726,288

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	As of March 31,		As of December 31,
	2019		2018		2017
	(in $ millions)
SELECTED BALANCE SHEET DATA:
Cash and cash equivalents	$	29.4	$	27.9	$	164.0
Restricted cash		29.4		63.4		39.1
Other current assets		150.7		117.3		22.4
Jack-up drilling rigs		2,416.1		2,278.1		783.3
Newbuildings		432.5		361.8		642.7
Marketable securities		—		31.0		20.7
Other long-term assets		40.3		34.2		—
Total assets		3,098.4		2,913.7		1,672.3
Trade accounts payables		14.7		9.6		9.6
Accruals and other current liabilities		109.6		106.5		11.5
Long-term debt (including current portion)		1,415.4		1,174.6		87.0
Onerous contracts		71.3		81.5		71.3
Other liabilities		15.6		8.0		—
Total liabilities		1,626.6		1,380.2		179.4
Total equity	$	1,471.8	$	1,533.5	$	1,492.9

	For the Three Months Ended March 31,						For the Year Ended December 31,
	2019			2018			2018			2017
	(in $ millions)
CASH FLOW DATA:
Net Cash Provided by / (Used in) Operating Activities	$	(13.9	)	$	(45.4	)	$	(135.2	)	$	(184.8	)
Net Cash Provided by / (Used in) Investing Activities		(172.1	)		(198.8	)		(560.1	)		(1,256.5	)
Net Cash Provided by / (Used in) Financing Activities		153.5			147.6			583.5			1,506.3

	As of and for the Three Months Ended March 31,						As of and for the Year Ended December 31,
	2019			2018			2018			2017
OTHER FINANCIAL AND OPERATIONAL DATA:
Adjusted EBITDA(1) (in $ millions)	$	(15.3	)	$	(40.0	)	$	(65.8	)	$	(61.8	)
Total Contract Backlog(2) (in $ millions)		451.2			206.7			377.5			28.5
Technical Utilization(3) (in %)		98.8	%		91.9	%		99.3	%		—
Economic Utilization(4) (in %)		95.7	%		86.1	%		97.9	%		—
TRIF(5)(number of incidents)		1.20			1.66			1.54			—

(1) Adjusted EBITDA is a non-GAAP financial measure and as used herein represents net loss adjusted for: depreciation and impairment of non-current assets, amortization of contract backlog, interest income, interest capitalized to newbuildings, foreign exchange loss, net, other financial expenses, interest expense, gross, change in unrealized (loss)/gain on Call Spread Transactions (as defined below), (loss)/gain on forward contracts, gain from bargain purchase and income tax expense. We present Adjusted EBITDA because we believe that it and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance. We believe Adjusted EBITDA provides meaningful information about the performance of our business and therefore we use it to supplement our U.S. GAAP reporting. Moreover, our management uses Adjusted EBITDA in presentations to our Board to provide a consistent basis to measure operating performance of our business, as a measure for planning and forecasting overall expectations, for evaluation of actual results against such expectations and in communications with our shareholders, lenders, bondholders, rating agencies and others concerning our financial performance. We believe that Adjusted EBITDA improves the comparability of year-to-year results and is representative of our underlying performance, although Adjusted EBITDA has significant limitations, including not reflecting our cash requirements for capital or deferred costs, rig reactivation costs, newbuild rig activation costs contractual commitments, taxes, working capital or debt service. Non-GAAP financial measures may not be comparable to similarly titled measures of other

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companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under U.S. GAAP. The following table sets forth a reconciliation of Adjusted EBITDA to net loss for the three months ended March 31, 2019 and 2018 and the years ended December 31, 2018 and 2017:

	For the Three Months Ended March 31,						For the Year Ended December 31,
	2019			2018			2018			2017
	(in $ millions)
Net loss	$	(56.4	)	$	(33.8	)	$	(190.9	)	$	(88.0	)
Depreciation and impairment of non-current assets		23.9			12.2			79.5			47.9
Amortization of contract backlog*		7.4			—			24.2			—
Interest income		(0.3	)		(0.5	)		(1.2	)		(3.2	)
Interest capitalized to newbuildings		(5.8	)		(2.7	)		(23.4	)		—
Foreign exchange loss, net		(0.2	)		0.2			1.1			0.3
Other financial expenses		0.8			—			3.5			—
Interest expense, gross		18.8			2.7			37.1			0.5
Change in unrealized (loss)/gain on Call Spread Transactions		(3.6	)		—			25.7			—
(Loss)/gain on forward contracts		(11.5	)		20.0			14.2			(19.3	)
Gain from bargain purchase		—			(38.1	)		(38.1	)		—
Income tax expense		0.2			—			2.5			—
Adjusted EBITDA	$	(15.3	)	$	(40.0	)	$	(65.8	)	$	(61.8	)

* Amortization of the fair market value of existing contracts at the time of the initial acquisition.

See the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Business—Financial Measures—Adjusted EBITDA.”

(2) Our Total Contract Backlog includes only firm commitments for contract drilling services represented by definitive agreements. Total Contract Backlog (in $ millions) is calculated as the maximum contract drilling dayrate revenue that can be earned from a drilling contract based on the contracted operating dayrate. Total Contract Backlog excludes revenue resulting from mobilization and demobilization fees, contract preparation, capital or upgrade reimbursement, recharges, bonuses and other revenue sources and is not adjusted for planned out-of-service periods during the contract period. The contract period excludes additional periods that may result from the future exercise of extension options under our contracts, and such extension periods are included only when such options are exercised. The contract operating dayrate may temporarily change due to, among other factors, mobilization, weather or repairs. As used in this Prospectus, Total Contract Backlog (in $ millions) is not the same measure as the acquired contract backlog presented in our Consolidated Financial Statements and Interim Financial Statements. Please see Notes 2 and 14 to our Consolidated Financial Statements and Notes 3 and 11 to our Interim Financial Statements for further information. See the section entitled “Business—Customers and Contract Backlog.”

(3) Technical Utilization is the efficiency with which we perform well operations without stoppage due to mechanical, procedural or other operational events that result in down, or zero, revenue time. Technical Utilization is calculated as the technical utilization of each rig in operation for the period, divided by the number of rigs in operation for the period, with the technical utilization for each rig calculated as the total number of hours during which such rig generated dayrate revenue, divided by the maximum number of hours during which such rig could have generated dayrate revenue, expressed as a percentage measured for the period. We have not provided Technical Utilization data for the year ended December 31, 2017 because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017. See “Business—History and Development—Acquisition from Transocean” for more information. Technical Utilization is calculated only with respect to rigs in operation for the relevant period and is not calculated on a fleet-wide basis. Technical Utilization is a measure of efficiency of rigs in operation and is not a measurement of utilization of our fleet overall.

(4) Economic Utilization is the dayrate revenue efficiency of our operational rigs and reflects the proportion of the potential full contractual dayrate that each jack-up rig actually earns each day. Economic Utilization is affected by reduced rates for standby time, repair time or other planned out-of-service periods. Economic Utilization is calculated as the economic utilization of each rig in operation for the period, divided by the number of rigs in operation for the period, with the economic utilization of each rig calculated as the total revenue, excluding bonuses, as a proportion of the full operating dayrate multiplied by the number of days on contract in the period. We have not provided Economic Utilization data for the year ended December 31, 2017 because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017. See “Business—History and Development—Acquisition from Transocean” for more information. Economic Utilization is calculated only with respect to rigs in operation for the relevant period and is not calculated on a fleet-wide basis. Economic Utilization is a measure of efficiency of rigs in operation and is not a measurement of utilization of our fleet overall.

(5) Total recordable incident frequency (“TRIF”) is a measure of the rate of recordable workplace injuries. TRIF, as defined by the International Association of Drilling Contractors, is derived by multiplying the number of recordable injuries during the twelve- month period prior to the specified date by 1,000,000 and dividing this value by the total hours worked in that period by the total number of employees. An incident is considered “recordable” if it results in medical treatment over certain defined thresholds (such as receipt of prescription medication or stitches to close a wound) as well as incidents requiring the injured person to spend time away from work. We have not provided TRIF data for the year ended December 31, 2017 because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017. See “Business—History and Development—Acquisition from Transocean” for more information.

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UNAUDITED PRO FORMA FINANCIAL INFORMATION

On March 29, 2018, we concluded the acquisition of 99.41% of the shares of Paragon Offshore Limited for a total consideration of $240 million, subsequently acquiring all remaining shares in July 2018 for $1.3 million. Paragon was incorporated on July 18, 2017, as part of the financial restructuring of its predecessor, Paragon Offshore plc, who commenced proceedings under chapter 11 of the U.S. Bankruptcy Code on February 14, 2016.

The following unaudited pro forma combined statements of operations for the year ended December 31, 2018, and related notes (the “Pro Forma Financial Information”) has been prepared to illustrate the effect of the Paragon Transaction as if it had occurred on January 1, 2018. The Pro Forma Financial Information has been derived from the historical consolidated financial statements of Borr Drilling Limited and the historical consolidated financial statements of Paragon Offshore Limited included herein, each of which were prepared in accordance with U.S. GAAP. The Pro Forma Financial Information gives effect to the acquisition of Paragon and the issuance of 10,869,565 Shares necessary to finance the acquisition, as if both occurred on January 1, 2018. Unless otherwise indicated, all Share and per Share data in this Prospectus is adjusted to give effect to our Reverse Share Split and is approximate due to rounding.

The Pro Forma Financial Information has been prepared to aid you in your analysis of our financial prospects. You should not rely on the Pro Forma Financial Information as being indicative of the historical results that would have been achieved had the Paragon Transaction been completed on January 1, 2018, or what may be realized in the future.

The following table should be read in conjunction with the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements of Borr Drilling Limited and Paragon Offshore Limited and notes thereto, which are included herein.

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	For the Year Ended December 31, 2018			For the period from January 1, 2018 to March 28, 2018
	Borr Drilling Ltd Historical			Paragon Historical			Adjustments			Pro Forma Combined
(in $ millions except share and per share data)
COMBINED STATEMENTS OF OPERATIONS DATA:
Operating revenues	$	164.9		$	26.6		$	—		$	191.5
Reimbursable revenues		—			0.6			—			0.6
Gain on disposals		18.8			7.9			—			26.7
Gain from bargain purchase(1(c))		38.1			—			(38.1	)		—
Remeasurement gain from equity affiliate		—			8.6			—			8.6
Rig operating and maintenance expenses.		(180.1	)		(29.2	)		—			(209.3	)
Depreciation(1(a))		(79.5	)		(10.7	)		2.9			(87.3	)
Impairment of non-current assets(1(d))		—			(187.6	)		187.6			—
Amortization of contract backlog(1(b))		(24.2	)		—			(7.2	)		(31.4	)
General and administrative expenses(1(e), (f))		(38.7	)		(34.5	)		19.0			(54.2	)
Restructuring costs		(30.7	)		—			—			(30.7	)
Legal settlement		—			15.4			—			15.4
Operating expenses		(353.2	)		(246.6	)		202.3			(397.5	)
Operating Loss		(131.4	)		(202.9	)		164.2			(170.1	)
Interest income		1.2			—			—			1.2
Interest expenses, net of amounts capitalized		(13.7	)		(1.9	)		—			(15.6	)
Other, net.		(44.5	)		0.4			—			(44.1	)
Earnings from equity affiliate		—			(46.5	)		—			(46.5	)
Total Financial Items		(57.0	)		(48.0	)		—			(105.0	)
Loss before income taxes		(188.4	)		(250.9	)		164.2			(275.1	)
Income tax expense		(2.5	)		(2.7	)		—			(5.2	)
Net loss		(190.9	)		(253.6	)		164.2			(280.3	)
Net loss per common share:
Basic		(1.85	)		—			—			(2.65	)
Diluted		(1.85	)		—			—			(2.65	)
Weighted average number of outstanding shares(1(g))		102,877,501			—			3,041,088			105,918,589

(1) Pro Forma Adjustments: The following adjustments have been reflected in the Pro Forma Financial Information:

(a) Reflects the estimated depreciation relating to the depreciation related to the acquired fleet of rigs. There was no change in depreciation policy. Furthermore the value of the Paragon fleet was reduced in total by $182 million, from $427.6 million to $246.0 million, based on management’s estimate of fair value, thereby reducing depreciation by $2.9 million.

(b) Reflects the amortization of the fair value of acquired contract backlog. As part of the purchase price allocation exercise, our management determined that the firm contractual backlog on rigs in operation at the time of acquisition met the definition of an intangible asset. The amount was capitalized and is amortized to the income statement over the period of the firm contract. The adjustment of $7.2 million reflects the additional amortization of the contract backlog.

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(c) Reflects the adjustment of the bargain purchase gain of $38.1 million. For the purposes of preparing the Pro Forma Information, the bargain gain is considered to be a non-recurring transaction and therefore not appropriate to be reflected in these pro forma combined statement of operations.

(d) Reflects the adjustment of the impairment charge recognized in the Paragon historical column. Paragon recognized an impairment charge of $187.6 million in the period ended March 28, 2018. For the purposes of preparing the Pro Forma Information, this impairment is considered to be a non-recurring transaction and therefore not appropriate to be reflected in these pro forma combined statement of operations.

(e) Reflects the adjustment of the severance payment of $18 million recognized within general and administrative expenses in the Paragon historical column. This payment was triggered by the tender offer for the Paragon shares and for the purposes of preparing the Pro Forma Information is considered to be a non-recurring transaction directly attributable to the transaction.

(f) Reflects the transaction costs of $1 million Borr incurred associated with the acquisition. These costs include legal expenses, consultancy fees and certain internal costs directly associated with the transaction. For the purposes of preparing the Pro Forma Information these are considered to be non-recurring transaction and therefore not appropriate to be reflected in these pro forma combined statement of operations.

(g) Reflects the weighted average number of outstanding Shares for Borr Drilling for the year ended December 31, 2018 and the pro forma weighted average number of outstanding Shares for Borr Drilling for the year ended December 31, 2018, adjusted for the issuance of 10,869,565 Shares in the March 2018 Private Placement (as defined below) as if such issuance occurred on January 1, 2018, respectively.

The tax effect of adjustments (a), (b), (c), (d), (e), (f) and (g) have had our statutory tax rate of 0% applied to them. We are an exempted company for tax purposes in Bermuda.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and Interim Financial Statements and the related notes thereto included elsewhere in this Prospectus. The discussion and analysis below contains certain forward-looking statements about our business and operations that are subject to the risks, uncertainties and other factors described in the section entitled “Risk Factors,” beginning on page 13, and elsewhere in this Prospectus. These risks, uncertainties and other factors could cause our actual results to differ materially from those expressed in, or implied by, the forward-looking statements. See the section entitled “Note Regarding Forward-Looking Statements.”

OVERVIEW

We are an offshore shallow-water drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership, contracting and operation of jack-up rigs for operations in shallow-water areas (i.e., in water depths up to approximately 400 feet), including the provision of related equipment and work crews to conduct oil and gas drilling and workover operations for exploration and production customers. We own 27 rigs, including 26 jack-up rigs and one semi-submersible rig, with an additional eight jack-up rigs scheduled to be delivered by the end of 2020. Upon delivery of these newbuild jack-up rigs, we will have a fleet of 30 premium jack-up rigs, which refers to rigs delivered from the yard in 2001 or later.

We aim to become a preferred operator of jack-up rigs within the jack-up drilling market. The shallow-water market is our operational focus as we expect demand will recover sooner than in the mid- and deepwater segments of the contract drilling market. We contract our jack-up rigs and offshore employees primarily on a dayrate basis to drill wells for our customers, including integrated oil companies, state-owned national oil companies and independent oil and gas companies. During 2018, our top five customers by revenue were subsidiaries of NDC, TAQA, BW Energy, Spirit Energy and Total. During the first quarter of 2019, our top five customers by revenue were subsidiaries of NDC, TAQA, Perenco, Total and Tulip. A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. Our Total Contract Backlog was $383.2 million as of June 30, 2019 and $377.5 million as of December 31, 2018. We currently operate in significant oil-producing geographies throughout the world, including the North Sea, the Middle East, Mexico, West Africa and Southeast Asia. We intend to operate our business with a competitive cost base, driven by a strong and experienced organizational culture and a carefully managed capital structure.

From our initial acquisition of rigs in early 2017, we have expanded rapidly into one of the world’s largest international offshore jack-up drilling contractors by number of jack-up rigs. The following chart illustrates the development in our fleet since our inception:

	As of and for the Six Months Ended June 30,		As of and for the Year Ended December 31,
	2019		2018		2017
Total Fleet as of January 1		27		13		0
Jack-up Rigs Acquired(1)		—		23		12
Newbuild Jack-up Rigs Delivered from Shipyards		2		9		1
Jack-up Rigs Disposed of		2		18		0
Total Fleet as of the end of Period		27		27		13
Newbuild Jack-up Rigs not yet Delivered as of the end of Period		8		9		13
Jack-up Rigs Committed to be Sold as of the end of Period		1		—		—
Total Fleet, including Newbuild Rigs not yet Delivered, as of the end of Period		35		36		26

(1) Includes acquisition of one semi-submersible rig in 2018.

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HOW WE EVALUATE OUR BUSINESS

We manage our operations through a single global segment. We evaluate our business based on a number of operational and financial measures that we believe are useful in assessing our historical and future performance throughout the commodity-price cycles that have characterized the offshore drilling industry since our inception. These operational and financial measures include:

Operational Measures

Total Contract Backlog

Our Total Contract Backlog includes only firm commitments for contract drilling services represented by definitive agreements.

Total Contract Backlog (in $ millions) is calculated as the maximum contract drilling dayrate revenue that can be earned from a drilling contract based on the contracted operating dayrate. Total Contract Backlog excludes revenue resulting from mobilization and demobilization fees, contract preparation, capital or upgrade reimbursement, recharges, bonuses and other revenue sources and is not adjusted for planned out-of-service periods during the contract period.

Total Contract Backlog (in contracted rig years) is calculated as our total number of contracted rig years based on firm commitments, which illustrates the time it would take one jack-up rig to perform the obligations under all agreements for all rigs consecutively.

The contract period excludes additional periods that may result from the future exercise of extension options under our contracts, and such extension periods are included only when such options are exercised. The contract operating dayrate may temporarily change due to, among other factors, mobilization, weather or repairs. As used in this Prospectus, Total Contract Backlog (in $ millions) is not the same measure as the acquired contract backlog presented in our Consolidated Financial Statements and Interim Financial Statements. Please see Notes 2 and 14 to our Consolidated Financial Statements, Notes 3 and 11 to our Interim Financial Statements and the section entitled “Business—Customers and Contract Backlog.”

Our Total Contract Backlog, expressed in U.S. dollars and in number of years, as of June 30, 2019 and 2018 and December 31, 2018 and 2017, was as follows:

	As of June 30,				As of December 31,
	2019		2018		2018		2017
Total Contract Backlog (in $ millions)(1)	$	383.2	$	184.7	$	377.5	$	28.5
Total Contract Backlog (in contracted rig years)(1)		13.4		7.5		14.3		1.5

(1) The table assumes no exercise of extension options or renegotiations under our current contracts.

Technical Utilization

Technical Utilization is the efficiency with which we perform well operations without stoppage due to mechanical, procedural or other operational events that result in down, or zero, revenue time. Technical Utilization is calculated as the technical utilization of each rig in operation for the period, divided by the number of rigs in operation for the period, with the technical utilization for each rig calculated as the total number of hours during which such rig generated dayrate revenue, divided by the maximum number of hours during which such rig could have generated dayrate revenue, expressed as a percentage measured for the period. Technical Utilization is calculated only with respect to rigs in operation for the relevant period and is not calculated on a fleet-wide basis. Technical Utilization is a measure of efficiency of rigs in operation and is not a measurement of utilization of our fleet overall.

Economic Utilization

Economic Utilization is the dayrate revenue efficiency of our operational rigs and reflects the proportion of the potential full contractual dayrate that each jack-up rig actually earns each day. Economic Utilization is affected by reduced rates for standby time, repair time or other planned out-of-service periods. Economic Utilization is calculated as the economic utilization of each rig in operation for the period, divided by the

58

number of rigs in operation for the period, with the economic utilization of each rig calculated as the total revenue, excluding bonuses, as a proportion of the full operating dayrate multiplied by the number of days on contract in the period. Economic Utilization is calculated only with respect to rigs in operation for the relevant period and is not calculated on a fleet-wide basis. Economic Utilization is a measure of efficiency of rigs in operation and is not a measurement of utilization of our fleet overall.

Rig Utilization

Rig Utilization is calculated as the weighted average number of operating rigs divided by the weighted average number of rigs owned for each period.

Total Recordable-Incident Frequency

TRIF is a measure of the rate of recordable workplace injuries. TRIF, as defined by the International Association of Drilling Contractors, is derived by multiplying the number of recordable injuries during the twelve-month period prior to the specified date by 1,000,000 and dividing this value by the total hours worked in that period by the total number of employees. An incident is considered “recordable” if it results in medical treatment over certain defined thresholds (such as receipt of prescription medication or stitches to close a wound) as well as incidents requiring the injured person to spend time away from work.

Our Technical Utilization, Economic Utilization, Rig Utilization, TRIF and Weighted Average Number of Operating Rigs for the six months ended June 30, 2019 and 2018 and years ended December 31, 2018 and 2017 were:

	For the Six Months Ended June 30,						For the Year Ended December 31,
	2019			2018			2018			2017(1)
Technical Utilization (in %)		99.0	%		98.9	%		99.3	%		—
Economic Utilization (in %)		95.2	%		98.9	%		97.9	%		—
Rig Utilization (in %)		35.6	%		21.7	%		27.3	%		—
TRIF (number of incidents)		1.91			0.66			1.55			—
Weighted Average Number of Operating Rigs(2)		10.6			8.7			7.0			—

(1) We have provided no data for Technical Utilization, Economic Utilization, Rig Utilization, TRIF or Average Number of Operating Rigs for the year ended December 31, 2017, because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017, with the exception of those jack-up rigs under contract upon closing of the Transocean Transaction for which Transocean, as the seller, retained the associated revenue, expenses and cash flows. See “Business—History and Development—Acquisition from Transocean” for more information.

(2) Weighted Average Number of Operating Rigs describes the number of jack-up rigs operating, which may be compared to our total available jack-up fleet. We define operating rigs as all of our jack-up rigs that are currently operating on firm commitments for contract drilling services, represented by definitive agreements. This excludes our jack-up rigs which are stacked, undergoing reactivation products and newbuild rigs under construction. The Weighted Average Number of Operating Rigs is the aggregate number of expected revenue days to be realized during the period from firm commitments for contract drilling services, divided by the number of days in the applicable period.

Financial Measures

Operating Revenues

Operating revenues includes the gross revenue generated from jack-up rigs operated by us under our drilling contracts, including amortization of mobilization revenue received from customers.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure and as used herein represents net loss adjusted for: depreciation and impairment of non-current assets, amortization of contract backlog, interest income, interest capitalized to newbuildings, foreign exchange loss, net, other financial expenses, interest expense, gross, change in unrealized (loss)/gain on Call Spread Transactions, (loss)/gain on forward contracts, gain from bargain purchase and income tax expense. We present Adjusted EBITDA because we believe that it and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance. We believe Adjusted EBITDA provides meaningful

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information about the performance of our business and therefore we use it to supplement our U.S. GAAP reporting. Moreover, our management uses Adjusted EBITDA in presentations to our Board to provide a consistent basis to measure operating performance of our business, as a measure for planning and forecasting overall expectations, for evaluation of actual results against such expectations and in communications with our shareholders, lenders, bondholders, rating agencies and others concerning our financial performance. We believe that Adjusted EBITDA improves the comparability of year-to-year results and is representative of our underlying performance, although Adjusted EBITDA has significant limitations, including not reflecting our cash requirements for capital or deferred costs, rig reactivation costs, newbuild rig activation costs contractual commitments, taxes, working capital or debt service. Non-GAAP financial measures may not be comparable to similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under U.S. GAAP.

The following table sets forth a reconciliation of Adjusted EBITDA to net loss for the three months ended March 31, 2019 and 2018 and the years ended December 31, 2018 and 2017:

	For the Three Months Ended March 31,						For the Year Ended December 31,
	2019			2018			2018			2017
	(in $ millions)
Net loss	$	(56.4	)	$	(33.8	)	$	(190.9	)	$	(88.0	)
Depreciation and impairment of non-current assets		23.9			12.2			79.5			47.9
Amortization of contract backlog(1)		7.4			—			24.2			—
Interest income		(0.3	)		(0.5	)		(1.2	)		(3.2	)
Interest capitalized to newbuildings		(5.8	)		(2.7	)		(23.4	)		—
Foreign exchange loss, net		(0.2	)		0.2			1.1			0.3
Other financial expenses		0.8			—			3.5			—
Interest expense, gross		18.8			2.7			37.1			0.5
Change in unrealized (loss)/gain on Call Spread Transactions		(3.6	)		—			25.7			—
(Loss)/gain on forward contracts		(11.5	)		20.0			14.2			(19.3	)
Gain from bargain purchase		—			(38.1	)		(38.1	)		—
Income tax expense		0.2			—			2.5			—
Adjusted EBITDA	$	(15.3	)	$	(40.0	)	$	(65.8	)	$	(61.8	)

(1) Amortization of the fair market value of existing contracts at the time of the initial acquisition.

KEY COMPONENTS OF OUR RESULTS OF OPERATIONS

Operating revenues

We earn revenues primarily by performing the following activities: (i) providing our jack-up rigs, work crews, related equipment and services necessary to operate our jack-up rigs; (ii) delivering our jack-up rigs by mobilizing to and demobilizing from the drill location; and (iii) performing certain pre-operating activities, including rig preparation activities or equipment modifications required for our contracts.

We recognize revenues earned under our drilling contracts based on variable dayrates, which range from a full operating dayrate to lower rates or zero rates for periods when drilling operations are interrupted or restricted, based on the specific activities we perform during the contract. Such dayrate consideration is attributed to the distinct time period to which it relates within the contract term, and therefore, is recognized as we perform the services. We recognize reimbursement revenues and the corresponding costs as we provide the customer-requested goods and services, when such reimbursable costs are incurred while performing drilling operations. Prior to performing drilling operations, we may receive pre-operating revenues, on either a fixed lump sum or variable dayrate basis, for mobilization, contract preparation, customer-requested goods and services or capital upgrades, which we recognize on a straight-line basis over the estimated firm contract period. We recognize losses related to contracts as such losses are incurred.

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Gains on disposals

From time to time we may sell, or otherwise dispose of, our jack-up rigs and/or other fixed assets to external parties or related parties. In addition, assets, including certain jack-up rigs, may be classified as “held for sale” on our balance sheet when, among other things, we are committed to a plan to sell such assets and consider a sale probable within twelve months. We may recognize a gain or loss on any such disposal depending on whether the fair value of the consideration received is higher or lower than the carrying value of the asset.

Operating expenses

Our operating primarily expenses include jack-up rig operating and maintenance expenses, depreciation and impairment, amortization of contract backlog, general and administrative expenses and restructuring costs.

Rig operating and maintenance expenses are the costs associated with owning a jack-up rig that may from time to time be either in operation or stacked, including:

• Rig personnel expenses: compensation, transportation, training, as well as catering costs while the crews are on the jack-up rig. Such expenses vary from country to country and reflect the combination of expatriates and nationals, local market rates, unionized trade arrangements, local law requirements regarding social security, payroll charges and end of service benefit payments.

• Rig maintenance expenses: expenses related to maintaining our jack-up rigs in operation, including the associated freight and customs duties, which are not capitalized nor deferred. Such expenses do not directly extend the rig life or increase the functionality of the rig.

• Other rig-related expenses: all remaining operating expenses such as supplies, insurance costs, professional services, equipment rental and other miscellaneous costs.

Depreciation costs are based on the historical cost of our jack-up rigs. Rigs are recorded at historical cost less accumulated depreciation. Jack-up rigs acquired as part of asset acquisitions are stated at fair market value as of the date of the acquisition. 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 jack-up 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 costs related to employees directly involved in the work. Amortization costs for periodic surveys and other major maintenance projects are included in depreciation and amortization expense.

Amortization of contract backlog is the 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.

Our general and administrative expenses primarily include all office personnel costs and other miscellaneous expenses incurred by the operational headquarters of Borr Drilling Management Dubai in Dubai, as well as share-based compensation expenses, fixed annual fees payable to certain Related Parties under a management agreement for providing business, organizational, strategic, financial and other advisory services and doubtful debt provisions or releases.

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Our restructuring costs related to the Paragon Transaction are as further described below.

FACTORS AFFECTING OUR RESULTS OF OPERATIONS

Our results of operations have a number of key components and are primarily affected by the number of jack-up rigs under contract, the contractual dayrates we earn and the associated operating expenses. Our future results may not be comparable to our historical results of operations for the periods presented. In addition, when evaluating our historical results of operations and assessing our prospects in the periods under review, you should consider the following factors:

Acquisitions and Dispositions

Since our inception in 2016, we have acquired more than 50 jack-up rigs through both the purchase of existing jack-up rigs, companies owning jack-up rigs and contracts for newbuild jack-up rigs. This increase in jack-up rigs and related expansion of operations resulting from an increased number of jack-up rigs under contract has had a significant impact on our results of operations and our balance sheet during the periods presented in our Consolidated Financial Statements. The key characteristics of our rigs owned but not under contract which may yield differences in their marketability or readiness for use include whether such rigs are warm stacked or cold stacked, age of the rig, geographic location and technical specifications; please see our fleet status report beginning on page 107 for further information concerning these features by rig.

For more information on our acquisitions and dispositions, please see the section entitled “Business—History and Development.”

• Acquisitions and Dispositions: The table below sets forth information relating to our acquisitions and dispositions since our formation:

Transaction (Closing Date)	Transaction Value (in $ millions)	Purchase Price Allocation (in $ millions)	Rigs Purchased	Rig Status at Acquisition	Rig Status as of June 30, 2019(1)
Hercules Acquisition (January 23, 2017)	$130 (Asset Acquisition)	N/A	•   2 premium      jack-up rigs	•   Warm      Stacked: 2	•   Under New      Contract: 2
Transocean Transaction (May 31, 2017)	$1,240.5 (Business Combination)	•   Jack-up Rigs: $547.7 •   Onerous Contract:      $(223.7) •   Current Assets: $0.5      Total: $324.5(2) •   Future Newbuild      Contracts: $916.0      Total: $1,240.5	•   6 premium      jack-up rigs •   4 standard      jack-up rigs •   5 contracts for      newbuild      jack-up rigs	•   Warm      Stacked: 7 •   Under Legacy      Contract: 3 •   Under      Construction: 5	•   Warm      Stacked: 3 •   Cold      Stacked: 3 •   Under New      Contract: 3 •   Disposed of: 3 •   Under      Construction: 3
PPL Acquisition (October 6, 2017)	$1,300 (Asset Acquisition)	•   N/A	•   9 contracts for      newbuild      jack-up rigs	•   Under      Construction: 9	•   Warm      Stacked: 4 •   Under New      Contract: 5
Paragon Transaction (March 29, 2018)	$241.3 (Business Combination)	•   Jack-up Rigs: $261.0 •   Other Net Assets:      $18.4 •   Bargain Gain: $(38.1) •   Total: $241.3	•   2 premium      jack-up rigs •   20 standard      jack-up rigs •   1 semi-      submersible	•   Warm      Stacked:16 •   Under Legacy      Contract: 7	•   Under Legacy      Contract: 4 •   Under New      Contract: 2 •   Disposed of: 17
Keppel Acquisition (May 16, 2018)	$742.5 (Asset Acquisition)	N/A	•   5 contracts for      newbuild      jack-up rigs	•   Under      Construction: 5	•   Under      Construction: 5
Keppel Hull B378 Acquisition (March 29, 2019)	$122.1 (Asset Acquisition)	N/A	•   1 contract for      a newbuild      jack-up rig	•   Under      Construction: 1	•   Warm      Stacked: 1

(1) Jack-up rigs “Under New Contract” include those rigs which are being mobilized to, or are otherwise awaiting the commencement of, drilling operations under the relevant contract.

(2) This is the amount reflected in the balance sheet as a result of purchase accounting.

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• Recent and Future Acquisitions and Dispositions: We expect to take delivery of the remaining eight newbuild jack-up rigs not yet delivered no later than the end of 2020. We have explored and may continue to explore further acquisition opportunities and we have made and may consider in the future dispositions of jack-up rigs. Acquisitions or dispositions of, our jack-up rigs are likely to impact our revenue as well as our operating and maintenance expenses. For example, in 2018 we recognized gain on disposals of $18.8 million in connection with the disposition of 18 jack-up rigs, 16 of which were acquired during the Paragon Transaction. In May 2019, we entered into sale agreements for the sale of the “Eir,” “Baug” and “Paragon C20051,” none of which were operating or on contract, for consideration of $3.0 million each for a total consideration of $9.0 million. The jack-up rigs have been sold with a contractual obligation not to be used for drilling purposes and so retired from the international jack-up fleet. The sales of “Baug” and “Paragon C20051” were completed in May 2019 for cash consideration of $6.0 million and the sale of “Eir” is expected to be completed by the end of the first quarter of 2020, subject to certain conditions. These divestments bring the total number of jack-up rigs divested by us and retired from the international jack-up fleet to 20 since the beginning of 2018.

• Restructuring Costs: Following the Paragon Transaction in March 2018, we undertook a rigorous review of the acquired business and have undertaken steps to reduce headcount, office locations and administrative costs. In 2018, we recognized $30.7 million of restructuring costs in connection with such cost reduction measures, which also impacted on our operating and general and administrative costs. We continue to implement our restructuring and integration of the acquired business during 2019, which may affect our operating and general and administrative costs as well as restructuring costs during this year and future years.

• Purchase Price Allocations: In connection with any past or future acquisition accounted for as a business combination, including the Transocean Transaction and the Paragon Transaction, we use a purchase price allocation so that the value of the assets acquired reflects the estimates, assumptions and judgments of our management relative to the carrying values, remaining useful lives and residual values. The estimates, assumptions and judgements involved in accounting for acquisitions, including the recognition of goodwill, may result in the impairment of certain assets in the future and have the effect of creating assets and liabilities which directly affect our financial statements and may indirectly affect our results of operations.

Other Factors Affecting our Financial Statements

In addition to the factors identified above, you should consider the following facts when evaluating our financial statements and assessing our prospects:

• Revenues: Our revenues are primarily affected by the number of jack-up rigs under contract from time to time and the dayrates we are able to charge our customers, which vary from time to time. To a significant extent, the dayrates we charge our customers depend on the market cycle of the jack-up drilling market at a given point in time. Historically, when oil prices decrease, capital spending and drilling activity decline, which leads to an oversupply of drilling rigs and reduced dayrates. Conversely, higher oil prices, increased capital spending and drilling activity and limited supply of drilling rigs have historically led to higher dayrates. In addition, the number of jack-up rigs under contract from time to time is affected by, among other factors, our relationships with new and existing customers and suppliers, which have grown substantially since our inception in 2016. Going forward, our ability to leverage those relationships into new contracts and advantageous rates will be critical to our success and prospects for growth. Our revenues may also be affected by other situations, including when our jack-up rigs cease operations due to technical failures and other situations where we do not collect revenue from our customers. Our ability to keep our jack-up rigs operational when under contract is monitored by our Board and management as Technical Utilization. As we transition our focus from the acquisition of jack-up rigs to the operation of our jack-up rigs, our results of operations will be more affected by Technical Utilization than was historically the case during our acquisition phase.

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• Nature of Our Operating and General and Administrative Expenses: During 2017, the majority of our operating expenses consisted of stacking costs related to our jack-up rigs that were not in operation. Between April 1, 2018 and June 30, 2019, we signed 15 new contracts to provide drilling services. To the extent that the offshore drilling market recovers, we expect the nature of our operating expenses will shift to include primarily expenses related to the ongoing operation of our jack-up rigs. In such case, our operating expenses will depend on various factors, including expenses related to operating our jack-up rigs, maintenance projects, downtime, weather and other operating factors. In addition, upon completion of this Offering, we expect to incur direct, incremental general and administrative expenses as a result of our being a publicly traded company in the United States, including costs associated with hiring personnel for positions created as a result of our U.S. public company status, publishing annual and interim reports to shareholders consistent with SEC and NYSE requirements, expenses relating to compliance with the rules and regulations of the SEC, listing standards of the NYSE and the costs of independent director compensation. These incremental general and administrative expenses related to being a publicly traded company in the United States are not included in our historical consolidated results of operations.

• Financing Arrangements and Investments in Securities: The financial income and expenses reflected in our Consolidated Financial Statements may not be indicative of our future financial income and expenses and may, along with other line items related to our Financing Arrangements and historicial financing arrangements detailed in the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Existing Indebtedness,” change as the number of our jack-up rigs under contract increases. As we take delivery of the newbuild rigs we have agreed to purchase, we finance a portion of the purchase price and thus our finance expense will increase. The financing arrangements we have had in place historically may not be representative of the agreements that will be in place in the future or that we had in place during our first two years of operations. For example, we may amend our existing Financing Arrangements or enter into new financing arrangements after the closing of this Offering and such new agreements may not be on the same terms as our current Financing Arrangements. In addition, from time to time, we make and hold investments in other companies in our industry that own/operate offshore drilling rigs with similar characteristics to our fleet of jack-up rigs, subject to compliance with the covenants contained in certain of our Financing Arrangements which restrict such investments. We also purchase and hold debt or other securities issued by other companies in the offshore drilling industry from time to time. The impact of these financial investments will impact our results of operations.

• Interest Rates and Derivative Values: A significant portion of our debt bears floating interest rates. For example, the interest rates under certain of our Financing Arrangements are determined with reference to LIBOR plus a specified margin. As such, movements in interest rates, and LIBOR specifically, could have an adverse effect on our results of operations and cash flows. In addition, in connection with the issuance of our Convertible Bonds we entered into the Call Spread Transactions, which may have a dilutive effect on our earnings per share to the extent that the market price per share of our Shares exceeds the applicable strike price of the options. In future periods, interest expense will depend on, among other things, our overall level of indebtedness, interest rates and the value of our Shares and related-derivative values.

• Income Taxes: Income tax expense reflects current tax and deferred taxes related to the operation of our jack-up rigs and may vary significantly depending on the jurisdiction(s) of operation of our subsidiaries, the underlying contractual arrangements and ownership structure and other factors. In most cases, the calculation of tax is based on net income or deemed income in the jurisdiction(s) where our subsidiaries operate. As we transition our focus to the operation of our jack-up rigs, our income tax expense will be primarily affected by the number of jack-up rigs under contract from time to time and the dayrates we are able to charge our customers as well as the expenses we incur which can vary from time to time. Because taxes are impacted by taxable income of our subsidiaries, our tax expense may not be correlated with our income on a consolidated basis.

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GENERAL TRENDS AND OUTLOOK

During 2019, global jack-up drilling rig fleet utilization in our target markets, including Saudi Arabia, the UAE, Qatar and Mexico, continued its upward trend. Global competitive jack-up rig utilization stood at 58% as of June 12, 2019, according to Rystad Energy. The number of jack-up rigs delivered from shipyards was four in the fourth quarter of 2018 and is on par with the number delivered from shipyards in the fourth quarter of 2017, according to Rystad Energy. In the first quarter of 2019, the number of jack-up rigs delivered from shipyards was five according to Rystad Energy.

Based on the budgets reported by independent oil companies in the fourth quarter of 2018, according to Rystad Energy, offshore focused E&P Companies are projecting an increase in capital expenditures for 2019, as compared to 2018. In addition, we expect that the spending plans of national oil companies will continue to increase in 2019. We believe that offshore spending by E&P Companies, including national oil companies, will increase in 2019 for the first time in recent years.

According to data from Rystad Energy, the number of New Unique Contract jack-up rig years contracted in the first quarter of 2019 was approximately 76, which represents an increase of over 150% compared to the same period in the previous year. The average duration of the contracts awarded in the first quarter of 2019 was approximately 1.4 years, compared to approximately 0.8 years for contracts awarded during the first quarter of 2018. We believe this reflects an increasing level of confidence of industry customers in their shallow water portfolio and a higher sense of urgency in securing rig time as available supply reduces, particularly for modern units. References to New Unique Contract means an original contract between an operator and a drilling contractor. The duration of the contract can be for a fixed period of time (e.g., days, months or years) or for a fixed number of wells (which is not necessarily dependent on a fixed period of time). The dayrate for the contract is mutually agreed based on market conditions at the time of the fixture (or contract signing). A New Unique Contract may also have option periods which are considered separate and not included as part of the original firm term. Certain parameters of the option period(s) may be agreed upon when the original contract is signed or may be agreed upon when the option is exercised.

The number of jack-up rigs operating in China has increased by six rigs since mid-2018, reflecting an effort by the Chinese government to boost Chinese production. We believe that the increased demand in China may help to alleviate newbuild supply pressure in other regions. The Chinese government has stated that it intends to create a new state-owned asset company, Beijing Guohai Offshore Ltd, for the purpose of owning distressed shipyard assets (including jack-up rigs) with the intention of deploying and operating these units locally in China.

According to Rystad Energy as of June 12, 2019, there are approximately 65 uncontracted jack-up rigs built in or after 2010, including 8 of our jack-up rigs. We estimate that approximately 61 of the uncontracted jack-up rigs are being actively marketed. In the standard jack-up segment, competitive utilization has remained flat in the first quarter of 2019 when compared to the first quarter of 2018, despite additional reductions to the competitive fleet due to retirements and cold stacking. In some regions, such as the North Sea, Middle East and West Africa, competitive utilization for premium jack-up rigs is well above 90%, which continues to drive dayrates higher, as we have experienced in recent tenders.

During the fourth quarter of 2018, three jack-up rigs were retired from the worldwide jack-up rig fleet, according to Rystad Energy. In total, 35 jack-up rigs were retired in 2018, which was on par with the number of retirements in 2016 and 2017 combined, according to Rystad Energy. During the first quarter of 2019, five units were retired from the worldwide jack-up rig fleet. We believe that a significant number of the jack-up rigs that are more than thirty years old and uncontracted will remain uncompetitive and unlikely to return to the active fleet in the near future, if at all. According to Rystad Energy, the total number of jack-up rigs under contract as of June 12, 2019 was 304 (including 138 rigs built after 2010), up from 280 at the lowest point in January 2018, compared to a peak of 422 in 2014. Please see the section entitled “Industry Overview” for more information.

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RESULTS OF OPERATIONS

Three Months ended March 31, 2019 compared to the Three Months ended March 31, 2018

The following table summarizes our results of operations for the three months ended March 31, 2019 and 2018:

	For the Three Months Ended March 31,
	2019			2018
	(in $ millions)
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS DATA:
Operating revenues	$	51.9		$	10.6
Gain from bargain purchase		—			38.1
Operating expenses		(109.9	)		(62.8	)
Operating loss	$	(58.0	)	$	(14.1	)
Total other income (expenses), net		1.8			(19.7	)
Income tax expense		(0.2	)		—
Net loss		(56.4	)		(33.8	)
Other comprehensive gain (loss)		(7.3	)		—
Total comprehensive loss	$	(63.7	)	$	(33.8	)

Operating Revenues

Our operating revenues were $51.9 million for the three months ended March 31, 2019, compared to $10.6 million for the three months ended March 31, 2018. The increase is primarily due to having an increased number of jack-up rigs in operation and the dayrates thereunder.

Gain from Bargain Purchase

Our gain from bargain purchase was $nil for the three months ended March 31, 2019, compared to $38.1 million for the three months ended March 31, 2018, which relates to the Paragon Transaction.

Operating Expenses   

Operating expenses include the following items:

	For the Three Months Ended March 31,
	2019		2018
	(in $ millions)
Rig operating and maintenance expenses	$	57.1	$	22.5
Depreciation of non-current assets		23.9		12.2
Impairment of non-current assets		11.4		—
Amortization of contract backlog		7.4		—
General and administrative expenses		10.1		10.2
Restructuring costs		—		17.9
Operating expenses	$	109.9	$	62.8

Our operating expenses were $109.9 million for the three months ended March 31, 2019, compared to $62.8 million for the three months ended March 31, 2018. The increase of $47.1 million was primarily due to having an increased number of jack-up rigs in operation as well as the $11.4 million impairment of non-current assets during the first quarter of 2019.

Our rig operating and maintenance expenses, including stacking costs, were $57.1 million for the three months ended March 31, 2019, compared to $22.5 million for the three months ended March 31, 2018.

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These expenses for the first quarter of 2019 consisted of $16.2 million in rig maintenance expenses, which includes stacking costs, and $40.9 million in rig operating expenses. During the same period in 2018, rig operating and maintenance expenses consisted of $7.7 million in rig maintenance expenses and $14.8 million in rig operating expenses. Compared to the first quarter of 2018, the increase in rig maintenance expenses of $8.5 million was due to an increased number of non-contracted jack-up rigs having been delivered from PPL or otherwise acquired in the Paragon Transaction as compared to the same period in 2018. The increase in rig operating expenses of $26.1 million for the first quarter of 2019 compared to the same period in 2018 reflects the significantly higher number of jack-up rigs in operation throughout the period.

Depreciation of non-current assets was $23.9 million for the three months ended March 31, 2019, compared to $12.2 million for the three months ended March 31, 2018. Impairment of non-current assets was $11.4 million for the three months ended March 31, 2019, compared to $nil for the three months ended March 31, 2018. The impairment relates to the anticipated sale of “Eir” for $3.0 million, which is expected to close in early 2020, subject to certain conditions.

Amortization of contract backlog was $7.4 million for the three months ended March 31, 2019, compared to $nil for the three months ended March 31, 2018, as the underlying contracts were acquired in the Paragon Transaction.

General and administrative expenses were $10.1 million for the three months ended March 31, 2019, compared to $10.2 million for the three months ended March 31, 2018. General and administrative expenses for the three months ended March 31, 2019 included $1.7 million of non-cash charges linked to the Company’s long term share option program.

Our restructuring costs were $nil for the three months ended March 31, 2019, compared to $17.9 million for the three months ended March 31, 2018. The 2018 restructuring costs related to costs incurred in connection with closure of certain offices following the Paragon Transaction, including termination payments to certain Paragon employees and lease agreement counterparties following the Paragon Transaction.

Total Other Income (Expenses), net

Our total other income (expenses), net was income of $1.8 million for the three months ended March 31, 2019, compared to an expense of $19.7 million for the three months ended March 31, 2018. Total other income (expenses), net in the three months ended March 31, 2019 included interest expense of $13.0 million (additionally, interest of $5.8 million was capitalized in the quarter), mark-to-market gains on forward contracts relating to marketable securities of $11.5 million and a mark-to-market gain of $3.6 million on the Call Spread Transactions, in each case during the first quarter of 2019. For the first quarter of 2018, the primary driver of our total other income (expenses), net was an unrealized loss on forward contracts of $20 million.

Income Tax Expense

Our income tax expense for the three months ended March 31, 2019 was $0.2 million as a result of having 16 jack-up rigs under contract, compared to $nil for the corresponding period in 2018.

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Year ended December 31, 2018 compared to the Year ended December 31, 2017

The following table summarizes our results of operations for the years ended December 31, 2018 and 2017:

	For the Year Ended December 31,
	2018			2017
	(in $ millions)
SUMMARY CONSOLIDATED STATEMENTS OF OPERATIONS DATA:
Operating revenues	$	164.9		$	0.1
Gain from bargain purchase		38.1			—
Gain on disposals		18.8			—
Operating expenses		(353.2	)		(109.8	)
Operating loss	$	(131.4	)	$	(109.7	)
Total other income (expenses), net		(57.0	)		21.7
Income tax expense		(2.5	)		—
Net loss		(190.9	)		(88.0	)
Other comprehensive loss		0.6			(6.2	)
Total comprehensive loss	$	(190.3	)	$	(94.2	)

Operating Revenues

Our operating revenues were $164.9 million for the year ended December 31, 2018, compared to $0.1 million for 2017. The increase of $164.8 million is primarily due to a significantly higher number of jack-up rigs in operation throughout 2018, as compared to 2017, when one jack-up rig was on contract for approximately one day late in the year. The increase in jack-up rigs in operation was primarily due to the Paragon Transaction, where we acquired six rigs operating under contract and contracted for a further two of the acquired rigs throughout 2018.

Gain from Bargain Purchase

Our gain from bargain purchase was $38.1 million for the year ended December 31, 2018, which relates to the Paragon Transaction, compared to $nil for 2017.

Gain on Disposals

Our gain on disposals was $18.8 million for the year ended December 31, 2018, compared to $nil for 2017. We sold 18 jack-up rigs during 2018, 16 of which we acquired in the Paragon Transaction, for total proceeds of $37.6 million. No jack-up rigs were sold in 2017.

Operating Expenses   

Operating expenses include the following items:

	For the Year Ended December 31,
	2018		2017
	(in $ millions)
Rig operating and maintenance expenses	$	180.1	$	36.2
Depreciation of non-current assets		79.5		21.1
Impairment of non-current assets		—		26.7
Amortization of contract backlog		24.2		—
General and administrative expenses		38.7		21.0
Restructuring costs		30.7		—
Cost for issuance of warrants		—		4.7
Operating expenses	$	353.2	$	109.8

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Our operating expenses were $353.2 million for the year ended December 31, 2018, compared to $109.8 million for 2017. The increase of $243.4 million is primarily due to an increase in the number of rigs in operation in 2018.

Our rig operating and maintenance expenses, including stacking costs, were $180.1 million for the year ended December 31, 2018, compared to rig maintenance expenses of $36.2 million for 2017.

Our rig operating and maintenance expenses for the year ended December 31, 2018 consisted of $59.0 million in rig maintenance expenses, which includes stacking costs, and $121.1 million in rig operating expenses. The increase of $143.9 million from 2018 compared to 2017 was primarily driven by rig operating expenses of $121.1 million for our operating rigs during 2018, which reflects the significantly higher number of jack-up rigs in operation throughout 2018, as compared to 2017 when one rig was on contract for approximately one day at the end of December 2017. Our rig maintenance expenses for the year ended December 31, 2018 also include $12.0 million related to amortization of mobilization costs compared with $nil for 2017.

Our depreciation charge was $79.5 million for the year ended December 31, 2018, compared to $21.2 million for 2017, which was a result of a larger fleet of jack-up rigs in 2018. Impairment of non-current assets was $26.7 million for the year ended December 31, 2017, whereas we did not take an impairment charge during 2018.

Amortization of contract backlog was $24.2 million for the year ended December 31, 2018, compared to $nil for 2017. The increase of $24.2 million was the result of our capitalization of contract backlog acquired in connection with the Paragon Transaction, which is amortized over the firm contract periods.

Our general and administrative expenses were $38.7 million for the year ended December 31, 2018, compared to $21.0 million for 2017. The increase was a result of a larger organization and additional offices due to both having more jack-up rigs in operation in 2018 and the Paragon Transaction. Office lease costs in 2018 were $11.6 million compared to $0.4 million in 2017, which includes acquired offices in Aberdeen, United Kingdom, Beverwijk, The Netherlands and Houston, United States.

Our restructuring costs were $30.7 million for the year ended December 31, 2018, compared to $nil for 2017. This relates to costs incurred in connection with closure of certain offices following the Paragon Transaction, including termination payments to certain Paragon employees and lease agreement counterparties following the Paragon Transaction.

Total Other Income (Expenses), net

Our total other income (expenses), net was a loss of $57.0 million for the year ended December 31, 2018 compared to a gain of $21.7 million for 2017. The main explanations for the negative movement of $78.7 million in 2018 are net losses on forward contracts of $14.2 million in 2018 compared with gains of $19.3 million in 2017, unrealized loss on the Call Spread Transactions entered into in 2018 of $25.7 million and interest expense net of capitalized interest of $13.7 million compared with $nil in 2017.

Income Tax Expense

Our income tax expense for the year ended December 31, 2018 was $2.5 million, compared to $nil for 2017, when one jack-up rig was on contract for approximately one day late in the year.

LIQUIDITY AND CAPITAL RESOURCES

Historically, we have met our liquidity needs principally from equity offerings, cash generated from operations, availability under our historical financing arrangements and the delivery financing arrangements related to our newbuild rigs. We have historically raised capital through private issuances of our Shares and our Convertible Bonds. During the first half of 2019, we refinanced our historical revolving credit facilities, including our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF. Following the signing of our Hayfin Facility, Syndicated Facility and New Bridge Facility agreements on June 25, 2019, which collectively provided $645 million in financing, we paid in full the outstanding balances due under our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF, respectively, which were subsequently cancelled.

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Our primary uses of cash were, and following this Offering we expect will be, operating expenses, repayment of long term debt, capital expenditures and deferred payments for newbuild rigs (including our delivery financing arrangements related to our newbuild rigs), interest expense and income tax payments.

We currently estimate our 2019 capital expenditures, based on current contractual commitments associated with our newbuild rigs and costs associated with the acquisition of “Thor”, of approximately $297.7 million, of which the entire amount has been or will be debt financed. During 2018 and 2017, our capital expenditures based on contractual commitments associated with our newbuild rigs, including deferred compensation costs, were $971.4 million and $860.4 million, respectively. During the first quarter of 2019, our capital expenditures based on contractual commitments associated with our newbuild rigs, including deferred compensation costs, were $211.3 million.

Capital expenditures related to contract preparation, purchase and refurbishment of rig equipment, and other investments are highly dependent on how many jack-up rigs we activate, which is dependent on the number of contracts we are able to secure. We expect to fund our remaining 2019 capital expenditures and deferred costs using available cash and cash flows from operations, and, if necessary, borrowings under new secured financing arrangements or our Syndicated Facility and New Bridge Facility.

Total available free liquidity (cash and cash equivalents excluding restricted cash, plus available amounts under our historical financing arrangements) as of March 31, 2019 was $164.4 million. We had $29.4 million in cash and cash equivalents as of March 31, 2019, compared to $27.9 million as of December 31, 2018 and $164.0 million as of December 31, 2017. In addition, under our DNB RCF, we had $nil and $70 million available as of March 31, 2019 and December 31, 2018, respectively, which was not available as of December 31, 2017. As of June 30, 2019, we had borrowed $300 million under our Syndicated Facility (which includes utilization of the $70 million facility for guarantees) and $25 million under New Bridge Facility and had $50 million and $75 million available to borrow under our Syndicated Facility and New Bridge Facility, respectively.

We may consider entering into additional financing arrangements with banks or other capital providers. Subject, in each case, to then-existing market conditions and to our then-expected liquidity needs, among other factors, we may use a portion of our internally generated cash flows from operations to reduce debt prior to scheduled maturities, whether through early repayment, debt repurchases (either in the open market or in privately negotiated transactions or through debt redemptions or tender offers) or to issue a dividend to our shareholders. At any given time, we may require a significant portion of cash on hand and amounts available under our Syndicated Facility and New Bridge Facility for working capital and other needs related to the operation of our business.

Three Months ended March 31, 2019 compared to the Three Months ended March 31, 2018

Our cash flows for the three months ended March 31, 2019 and 2018 are presented below:

	For the Three Months Ended March 31,
	2019			2018
	(in $ millions)
Net Cash Provided by / (Used in) Operating Activities	$	(13.9	)	$	(45.4	)
Net Cash Provided by / (Used in) Investing Activities		(172.1	)		(198.8	)
Net Cash Provided by / (Used in) Financing Activities		153.5			147.6
Net Change in Cash and Cash Equivalents	$	(32.5	)	$	(96.6	)

    Cash Flows Used in Operating Activities

Net cash used in operating activities was $13.9 million for the three months ended March 31, 2019, compared to $45.4 million for the three months ended March 31, 2018. The $31.5 million decrease was partly due to restructuring costs of $17.9 million during the first quarter of 2018 compared to $nil during the first quarter of 2019, a loss on total other income (expenses), net of $19.7 million during the first quarter of 2018 compared to a gain on total other income (expenses), net of $1.8 million during the first quarter of 2019, partially offset by interest expense of $13.0 million in the first quarter of 2019 compared to $nil during the first quarter of 2018.

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   Cash Flows Used in Investing Activities

Net cash used in investing activities was $172.1 million for the three months ended March 31, 2019, compared to $198.8 million for the three months ended March 31, 2018. The $26.7 million decrease was partly due to payments in respect of the Paragon Transaction of $194.1 million in the first quarter of 2018 compared to $nil in the first quarter of 2019, partially offset by payments in respect of newbuilding jack-up rigs of $129.0 million in the first quarter of 2019 compared to $0.6 million during the same period in 2018, payments in respect of jack up rigs of $43.9 million in the first quarter of 2019, compared to $4.1 million in the first quarter of 2018 and the purchase of marketable securities of $4.0 million in the first quarter of 2019, compared to $nil during the first quarter of 2018.

   Cash Flows Provided by Financing Activities

Net cash provided by financing activities was $153.5 million for the three months ended March 31, 2019, compared to $147.6 million for the three months ended March 31, 2018. Our financing activities in the three months ended March 31, 2019 related to proceeds from long-term debt, net of deferred loan costs, of $95 million, compared to $nil in the three months ended March 31, 2018, and proceeds, net of deferred loan costs, from issuance of short-term debt related to the acquisition of “Thor” of $58.5 million compared to $nil during the first quarter of 2018. Our financing activities in the three months ended March 31, 2018 related to the March 2018 Private Placement (as defined below) and the repayment of an outstanding term loan of Paragon in connection with the Paragon Transaction.

Year ended December 31, 2018 compared to the Year ended December 31, 2017

Our cash flows for the years ended December 31, 2018 and 2017 are presented below:

	Year ended December 31,
	2018			2017
	(in $ millions)
Net Cash Provided by / (Used in) Operating Activities	$	(135.2	)	$	(184.8	)
Net Cash Provided by / (Used in) Investing Activities		(560.1	)		(1,256.5	)
Net Cash Provided by / (Used in) Financing Activities		583.5			1,506.3
Net Change in Cash and Cash Equivalents	$	(111.8	)	$	65.0

Cash Flows Used in Operating Activities

Net cash used in operating activities was $135.2 million during the year ended December 31, 2018, compared to $184.8 million during the year ended December 31, 2017. The decrease of $49.6 million was primarily due to operating cash loss in the period, interest paid and change in working capital.

Cash Flows Used in Investing Activities

Net cash used in investing activities was $560.1 million for the year ended December 31, 2018, compared to $1,256.5 million for 2017. Our investment activities in the year ended December 31, 2018 relate to payments and costs in respect of newbuildings of $362.4 million, ($785.2 million in 2017), payments to acquire Paragon Offshore, net of cash acquired of $195.1 million ($324.5 million in 2017 for the Transocean Transaction), purchase of marketable securities of $13.0 million ($26.9 million in 2017), payments and costs in respect of jack-up drilling rigs of $23.4 million ($119.8 million in 2017) and purchase of plant and equipment of $7.8 million ($0.1 million in 2017), offset by proceeds from the sale of rigs of $41.6 million in 2018 compared to $nil in 2017.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities was $583.5 million for the year ended December 31, 2018, compared to $1,506.3 million for the year ended December 31, 2017. Our financing activities in the year ended December 31, 2018 relate to proceeds from long-term debt, net of deferred loan costs, of $474.4 million, proceeds from share issuance net of issuance costs of $218.9 million, proceeds from a shareholder loan of $27.7 million, offset by repayment of long-term debt of $89.3 million and purchase of

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financial instruments and purchase of treasury shares of $19.7 million. In the period ended December 31, 2017, we generated proceeds from share issuance, net of issuance costs and conversion of shareholders loans of $1,415 million, proceeds from issuance of long-term debt, net of deferred loan costs of $87.0 million and proceeds from a related party shareholder loan of $12.7 million, offset by purchase of treasury shares of $8.4 million.

OUR EXISTING INDEBTEDNESS

Our 3.875% Convertible Bonds due 2023

In May 2018 we raised $350.0 million through the issuance of our Convertible Bonds, which mature in 2023. The initial conversion price (which is subject to adjustment) is $33.4815 per Share, for a total of 10,453,534 Shares. The Convertible Bonds have a coupon of 3.875% per annum payable semi-annually in arrears in equal installments. The terms and conditions governing our Convertible Bonds contain customary events of default, including failure to pay any amount due on the bonds when due, and certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to incur secured capital markets indebtedness.

As of March 31, 2019, we were in compliance with the covenants and our obligations under our Convertible Bonds. We expect to remain in compliance with our obligations under our Convertible Bonds in 2019.

Call Spread Transactions

In connection with the pricing of our Convertible Bonds, we (i) purchased from Goldman Sachs International call options over 10,453,612 Shares with a strike price of $33.4815 and (ii) sold to Goldman Sachs International call options over the same number of shares with a strike price of $42.6125. The average maturity of the call options purchased and sold is May 14, 2023 with maturities starting on May 16, 2022 and ending on May 16, 2024. The call options bought and sold are European options exercisable only at maturity, are cash settled and are subject to customary anti-dilution provisions.

The Call Spread Transactions mitigate the economic exposure from a potential exercise of the conversion rights embedded in our Convertible Bonds by improving the effective conversion premium for the Company in relation to our Convertible Bonds from 37.5% to 75% over the reference price of $24.35 per share. The Call Spread Transactions may separately have a dilutive effect on our earnings per share to the extent that the market price per share of our Shares exceeds the applicable strike price of the options at the time of exercise.

Fair value adjustments related to the Call Spread Transactions resulted in an unrealized loss recognized in Total other income (expenses), net, of $25.7 million for the year ended December 31, 2018 and an unrealized gain of $3.6 million for the three months ended March 31, 2019. See Note 5—“Total other (expenses), net” to our Consolidated Financial Statements and Notes 4 and 14 to our Interim Financial Statements for more information.

We may modify our position by entering into further derivative transactions with respect to our Shares and/or purchasing our Shares in secondary market transactions following this Offering. This activity could also cause or avoid an increase or a decrease in the market price of our Shares, which could affect any potential exercise of the conversion rights embedded in our Convertible Bonds.

Our Revolving and Term Loan Credit Facilities

During the first half of 2019, we refinanced our historical revolving credit facilities, including our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF. Following the signing of our Hayfin Facility, Syndicated Facility and New Bridge Facility agreements on June 25, 2019, which collectively provided $645 million in financing, we paid the outstanding balance due under our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF, respectively, which were subsequently cancelled.

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Hayfin Term Loan Facility

On June 25, 2019, we entered into a $195 million senior secured term loan facility agreement with funds managed by Hayfin Capital Management LLP, as lenders, among others. Our wholly-owned subsidiary, Borr Midgard Assets Ltd., is the borrower under the Hayfin Facility, which is guaranteed by Borr Drilling Limited and secured by mortgages over three of our jack-up rigs, pledges over shares of and related guarantees from certain of our rig-owning subsidiaries who provide this security as owners of the mortgaged rigs and general assignments of rig insurances, certain rig earnings, charters, intragroup loans and management agreements from our related rig-owning subsidiaries. Our Hayfin Facility matures in June 2022 and bears interest at a rate of LIBOR plus a specified margin. The Hayfin Facility agreement includes a make-whole obligation if repaid during the first twelve months and, thereafter, a fee for early prepayment and final repayment. As of June 30, 2019, our Hayfin Facility was fully drawn.

Our Hayfin Facility agreement contains various financial covenants, including requirements that we maintain minimum liquidity equal to three months interest on the facility when the jack-up rigs providing security are not actively operating under an approved drilling contract (as defined in the Hayfin Facility agreement). Our Hayfin Facility agreement also contains a loan to value clause requiring that the fair market value of our rigs shall at all times cover at least 175% of the aggregate outstanding facility amount. The facility also contains various covenants which restrict distributions of cash from Borr Midgard Holding Ltd., Borr Midgard Assets Ltd. and our related rig-owning subsidiaries to us or our other subsidiaries and the management fees payable to Borr Midgard Assets Ltd.’s directly-owned subsidiaries. Our Hayfin Facility agreement also contains customary events of default which include any change of control, non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the Hayfin Facility agreement or security documents or jeopardize the security provided thereunder. If there is an event of default, the lenders under our Hayfin Facility may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. The lenders under our Hayfin Facility may also require replacement or additional security if the fair market value of the jack-up rigs over which security is provided is insufficient to meet our market value-to-loan covenant.

As of June 30, 2019, we were in compliance with the covenants and our obligations under the Hayfin Facility agreement and we expect to remain in compliance with the covenants and our obligations under our Hayfin Facility in 2019.

Syndicated Senior Secured Credit Facilities

On June 25, 2019, we entered into a $450 million senior secured credit facilities agreement with DNB Bank ASA, Danske Bank, Citibank N.A., Jersey Branch and Goldman Sachs Bank USA, as lenders, among others (consisting of a $230 million credit facility, $50 million newbuild facility, $70 million for the issuance of guarantees and other trade finance instruments as required in the ordinary course of business and, assuming certain conditions are met, a $100 million incremental facility), secured by mortgages over six of our jack-up rigs and, when delivered, one of our newbuild jack-up rigs under construction, pledges over shares of and related guarantees from certain of our rig-owning subsidiaries who provide this security as owners of the mortgaged rigs and general assignments of rig insurances, certain rig earnings, charters, intragroup loans and management agreements from our related rig-owning subsidiaries. In connection with the drawdown of the $100 million incremental facility, two additional jack-up rigs will be mortgaged as security, in addition to assignments, pledges and guarantees from the related rig-owning subsidiaries that are identical to those described in the preceding sentence, and we are obligated to repay any amounts outstanding under our New Bridge Facility. Our Syndicated Facility matures in June 2022 and bears interest at a rate of LIBOR plus a specified margin. As of June 30, 2019, the $50 million newbuild facility and $100 million incremental facility remained undrawn and unavailable to draw, respectively, under our Syndicated Facility.

Our Syndicated Facility agreement contains various financial covenants, including requirements that we maintain a minimum book equity ratio of 40%, positive working capital, a debt service cover ratio in excess of 1.25x our interest and related expenses, from the end of 2020, and minimum liquidity equal to the greater of $50 million and 4% of net interest-bearing debt. Our Syndicated Facility agreement also contains a loan to value clause requiring that the fair market value of our rigs shall at all times cover at least 175% of the aggregate outstanding facility amount and any undrawn and uncancelled part of the facility. The Syndicated

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Facility agreement also contains various covenants, including, among others, restrictions on incurring additional indebtedness and entering into joint ventures; covenants subjecting dividends to certain conditions which, if not met, would require the approval of our lenders prior to the distribution of any dividend; restrictions on the repurchase of our Shares; restrictions on changing the general nature of our business; and restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim is required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions). Our Syndicated Facility agreement also contains customary events of default which include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the Syndicated Facility agreement or security documents or jeopardize the security provided thereunder. If there is an event of default, the lenders may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. The lenders may also require replacement or additional security if the fair market value of the jack-up rigs over which security is provided is insufficient to meet our market value-to-loan covenant. In addition, our Syndicated Facility contains a “Most Favored Nation” clause giving the lenders a right to amend the financial covenants to reflect any more lender-favorable covenants in any other agreement pursuant to which loan or guarantee facilities are provided to us, including amendments to our Financing Arrangements.

As of June 30, 2019, we were in compliance with the covenants and our obligations under the Syndicated Facility agreement and we expect to remain in compliance with the covenants and our obligations under our Syndicated Facility in 2019.

New Bridge Revolving Credit Facility

On June 25, 2019, we entered into a $100 million senior secured revolving loan facility agreement with DNB Bank ASA and Danske Bank, as lenders, secured by mortgages over two of our jack-up rigs, assignments of intra-group loans, rig insurances and certain rig earnings and pledges over shares of and related guarantees from certain of our rig-owning subsidiaries who provide this security as owners of the mortgaged rigs. Our New Bridge Facility matures in June 2022 and bears interest at a rate of LIBOR plus a variable margin. As of June 30, 2019, $75 million remained undrawn under our New Bridge Facility.

Our New Bridge Facility agreement contains various financial covenants, including requirements that we maintain a minimum book equity ratio of 40%, positive working capital, a debt service cover ratio in excess of 1.25x our interest and related expenses, from the end of 2020, and minimum liquidity equal to the greater of $50 million and 4% of net interest-bearing debt. Our New Bridge Facility agreement also contains a loan to value clause requiring that the fair market value of our rigs shall at all times cover at least 175% of the aggregate outstanding facility amount and any undrawn and uncancelled part of the facility. The agreement also contains various covenants, including, among others, restrictions on incurring additional indebtedness and entering into joint ventures; covenants requiring the approval of our lenders prior to the distribution of any dividends; and restrictions on the repurchase of our Shares; restrictions on changing the general nature of our business; restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim is required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions). Our New Bridge Facility agreement also contains customary events of default which include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the New Bridge Facility agreement or security documents or jeopardize the security provided thereunder. If there is an event of default, the lenders may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. The lenders may also require replacement or additional security if the fair market value of the jack-up rigs over which security is provided is insufficient to meet our market value-to-loan covenant. In addition, our New Bridge Facility contains a “Most Favored Nation” clause giving the lenders a right to amend the financial covenants to reflect any more lender-favorable covenants in any other agreement pursuant to which loan or guarantee facilities are provided to us, including amendments to our Financing Arrangements.

As of June 30, 2019, we were in compliance with the covenants and our obligations under the New Bridge Facility agreement and we expect to remain in compliance with the covenants and our obligations under our New Bridge Facility in 2019.

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DNB Revolving Credit Facility and Guarantee Facility

In May 2018, we entered into a $200 million senior secured revolving loan facility agreement with DNB Bank ASA secured by mortgages over five of our jack-up rigs, assignments of rig insurances and certain rig earnings, pledges over shares and related guarantees from certain of our rig-owning subsidiaries who provide this security as owners of the mortgaged rigs. Our DNB Revolving Credit Facility had a maturity date in May 2020 and bore interest at a rate of LIBOR plus a specified margin. As of December 31, 2018, $70 million remained undrawn under our DNB Revolving Credit Facility, which was fully drawn as of March 31, 2019. Our DNB Revolving Credit Facility agreement contained various financial covenants, including requirements that we maintain a minimum book equity ratio of 40%, positive working capital and minimum liquidity equal to the greater of $50 million and 5% of net interest-bearing debt. Our DNB Revolving Credit Facility agreement also contained a loan to value clause requiring that the fair market value of our rigs shall at all times cover at least 175% of the aggregate outstanding facility amount and any undrawn and uncancelled part of the facility. The facility also contained various covenants, including, among others, restrictions on incurring additional indebtedness and entering into joint ventures; restrictions on paying dividends; and restrictions on the repurchase of our Shares; restrictions on changing the general nature of our business; restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim was required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions).

In January 2019, we executed an amendment to the DNB Revolving Credit Facility agreement which allowed us to procure the issuance of guarantees as required in the ordinary course of business, typically for bid bonds, import bonds and performance bonds, up to an aggregate amount of $30 million. Our obligations to reimburse the bank for any payment made under such guarantees was secured by the guarantees, security over the rigs, insurances and shares provided under the DNB Revolving Credit Facility agreement. This amendment replaced the cash collateral required by the common terms agreement with DNB Bank ASA, which we refer to as the Guarantee Facility, and resulted in the release of $25.0 million of cash that was categorized as restricted as of December 31, 2018.

As of March 31, 2019, we were in compliance with the covenants and our obligations under the DNB Revolving Credit Facility and Guarantee Facility agreements, which were subsequently repaid and cancelled in June 2019.

DC Revolving Credit Facility and Guarantee Facility

In March 2019, we entered into a $160 million revolving credit facility and guarantee facility agreement with Danske Bank A/S and Citigroup Global Markets Limited (consisting of a $100.0 million credit facility and $60.0 million for the issuance of guarantees as required in the ordinary course of business), secured by mortgages over four of our jack-up rigs, assignments, pledges or charges of rig insurances, earnings, earnings accounts, shares and intra-group loans, as applicable, as well as guarantees from certain of our rig-owning subsidiaries providing the security as owners of the mortgaged rigs.

Our DC Revolving Credit Facility had a maturity date in May 2020 and bore interest at a rate of LIBOR plus a specified margin. As of March 31, 2019, $40 million remained undrawn under our DC Revolving Credit Facility. Our DC Revolving Credit Facility agreement contained various financial covenants, including requirements that we maintain a minimum book equity ratio of 40%, positive working capital and minimum liquidity equal to the greater of $50 million and 5% of net interest-bearing debt (including a contractual right to reduce this requirement to 4% in the event the liquidity covenant in the DNB RCF agreement is amended to this effect). Our DC Revolving Credit Facility agreement also contained a loan to value clause requiring that the fair market value of our rigs shall at all times cover at least 175% of the aggregate outstanding facility amount and any undrawn and uncancelled part of the facility. Our DC RCF agreement also contained various restrictive covenants, including, among others, restrictions on incurring additional indebtedness; restrictions on paying dividends; restrictions on us repurchasing our Shares; restrictions on changing the general nature of our business; and restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim was required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions).

As of March 31, 2019, we were in compliance with the covenants and our obligations under the DC Revolving Credit Facility agreement, which was subsequently repaid and cancelled in June 2019.

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Bridge Facility

In March 2019, we entered into a $120.0 million senior secured term loan facilities agreement, consisting of two facilities (Facility A and Facility B) of $60.0 million each, with Danske Bank A/S and DNB Bank ASA, secured by a mortgage over one of our currently owned jack-up rigs, with another mortgage to be taken out over the rig “Thor” upon delivery, an assignment of rig insurances and a pledge over the shares of certain of our rig-owning subsidiaries providing the security as owners of the mortgaged rigs.

Our Bridge Facility had a maturity date on September 30, 2019 and bore interest at a rate of LIBOR plus a specified margin. As of March 31, 2019, Facility A had been utilized in the amount of $60.0 million, and $60.0 million in Facility B remained undrawn. Facility B was subsequently fully drawn. Our Bridge Facility contained various financial covenants, including requirements that we maintain a minimum book equity ratio of 40% and minimum liquidity equal to the greater of $50 million and 5% of net interest-bearing debt. Our Bridge Facility also contained various covenants, including, among others, restrictions on incurring additional indebtedness; restrictions on paying dividends; restrictions on us repurchasing our Shares; restrictions on changing the general nature of our business; restrictions on making certain investments; and restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim was required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions).

As of March 31, 2019, we were in compliance with the covenants and our obligations under the Bridge Facility agreement, which was subsequently repaid and cancelled in June 2019.

Our Delivery Financing Arrangements

In addition to three jack-up rigs which we have taken delivery of against full payment from Keppel, we have contracts with Keppel to purchase eight jack-up rigs under construction. We have the option to accept delivery financing for two of the jack-up rigs to be delivered from Keppel. For five of our newbuild jack-up rigs under construction and nine additional jack-up rigs which have been delivered from PPL, we have agreed to accept and accepted, respectively, delivery financing from PPL and Keppel subject to the terms described below:

PPL Newbuild Financing

In October 2017, we agreed to acquire nine premium “Pacific Class 400” jack-up rigs from PPL (the “PPL Rigs”). All nine PPL Rigs have been delivered as of the date of this Prospectus. In connection with delivery of the PPL Rigs, our rig-owning subsidiaries as buyers of the PPL Rigs agreed to accept delivery financing for a portion of the purchase price equal to $87.0 million per jack-up rig (the “PPL Financing”), which does not include an estimate of certain fees payable in connection with the increase in the market value of the relevant PPL Rig from October 31, 2017 until the repayment date. Please see Notes 13 and 21 to our Consolidated Financial Statements and Note 18 to our Interim Financial Statements for more information.

The PPL Financing for each PPL Rig is an interest-bearing secured seller’s credit, guaranteed by Borr Drilling Limited which matures on the date falling 60 months from the delivery date of the respective PPL Rig. The PPL Financing bears interest at 3-month USD LIBOR plus a variable marginal rate. Interest accrues and is payable quarterly in arrears.

The PPL Financing for each respective PPL Rig is secured by a mortgage on such PPL Rig and an assignment of the insurances in respect of such PPL Rig. The PPL Financing also contains various covenants and the events of default include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the PPL Financing agreements or security documents, or jeopardize the security. In addition, each rig-owning subsidiary is subject to covenants which management consider to be customary in a transaction of this nature.

As of March 31, 2019, we had $753.3 million of PPL Financing outstanding and were in compliance with the covenants and our obligations under the PPL Financing agreements. We expect to remain in compliance with the covenants and our obligations under the PPL Financing agreements in 2019. We expect to satisfy our obligations under the PPL Financing for each respective PPL Rig with cash flow from operations when due.

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Keppel Newbuild Financing

In May 2018, we agreed to acquire five premium KFELS B class jack-up rigs, three completed and two under construction from Keppel (the “Keppel Rigs”). As of March 31, 2019, all five Keppel Rigs remain to be delivered. In connection with delivery of the Keppel Rigs, Keppel has agreed to extend delivery financing for a portion of the purchase price equal to $90.9 million per jack-up rig (the “Keppel Financing”). Separately from the Keppel Financing described below, we may exercise an option to accept delivery financing from Keppel with respect to two additional newbuild jack-up rigs, “Vale” and “Var,” acquired in connection with the Transocean Transaction. We will, prior to delivery of each jack-up rig from Keppel, consider available alternatives to such financing.

The Keppel Financing for each Keppel Rig is an interest-bearing secured facility from the lender thereunder (an affiliate of Keppel), guaranteed by Borr Drilling Limited, which will be made available on delivery of each Keppel Rig and matures on the date falling 60 months from the delivery date of each respective Keppel Rig. The Keppel Financing bears interest at 3-month USD LIBOR plus a variable marginal rate, payable beginning on the third anniversary of each Keppel Rigs’ delivery.

The Keppel Financing for each respective Keppel Rig will be secured by a mortgage on such Keppel Rig, assignments of earnings and insurances and a charge over the shares of the rig-owning subsidiary which holds each such Keppel Rig. The Keppel Financing agreements also contain a loan to value clause requiring that the fair market value of each Keppel Rig shall at all times cover at least 130% of the loan and also contains various covenants, including, among others, restrictions on incurring additional indebtedness. Each Keppel Financing agreement also contains events of default which include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the Keppel Financing agreements or security documents, or jeopardize the security.

As of March 31, 2019, we had no Keppel Financing outstanding and were in compliance with our pre-drawdown covenants and obligations under the Keppel Financing agreements. We expect to remain in compliance with our Keppel Financing obligations in 2019. We expect to satisfy our obligations under the Keppel Financing for each respective Keppel Rig with cash flow from operations when due.

Average Interest Rate

The average interest rate for our interest-bearing historical financing arrangements, which consist of LIBOR plus a margin specified in each such historical financing arrangement (excluding our Convertible Bonds), was 5.84% for the year ended December 31, 2018 and 6.09% for the three months ended March 31, 2019. The forecasted average margin for our interest-bearing Financing Arrangements is 3.84% and 4.04% for the years ending December 31, 2019 and 2020, respectively. The average margin of our interest-bearing Financing Arrangements is calculated as the weighted average of the forecasted outstanding loan balance and margin, and excludes our Convertible Bonds.

CONTRACTUAL OBLIGATIONS

In the ordinary course of business, we enter into various contractual obligations that impact or could impact our liquidity. The table below reflects our estimated contractual obligations stated at face value as of December 31, 2018 for referenced years:

	PAYMENTS DUE BY PERIOD
	Less than 1 year		1–3 years		3–5 years		More than 5 years		Total
	(in $ millions)
Long-term debt obligations	$	0.0	$	130.0	$	1,045.7	$	0.0	$	1,175.7
Interest obligations(1)		63.5		112.0		92.6		0.0		268.1
Operating lease obligations		4.6		7.2		0.6		0.0		12.3
Purchase obligations		170.1		793.8		0.0		0.0		963.9
Other long-term liabilities		1.0		0.0		7.0		0.0		8.0
Total	$	239.1	$	1,042.9	$	1,145.9	$	0.0	$	2,428.0

(1) The estimated interest obligations take into account both contractual interest rates and expected margins, but do not reflect our entry into the Hayfin Facility, Syndicated Facility and New Bridge Facility agreements.

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During the first half of 2019, we refinanced our historical revolving credit facilities, including our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF. Following the signing of our Hayfin Facility, Syndicated Facility and New Bridge Facility agreements on June 25, 2019, which collectively provided $645 million in financing, we paid the outstanding balance due under our DNB RCF, Guarantee Facility, DC RCF and Bridge RCF, respectively, which were subsequently cancelled.

Other Commercial Commitments as of December 31, 2018

We have other commercial commitments that contractually obligate us to settle with cash under certain circumstances. Parent company guarantees issued by Borr Drilling Limited in favor of certain customers and governmental bodies guarantee our performance in connection with certain drilling contracts, customs import duties and other obligations in various jurisdictions.

As of December 31, 2018, we had outstanding surety bonds, bank guarantees and performance bonds amounting to $23.0 million (2017: $15.9 million). The bank guarantees and bonds outstanding were backed by cash deposits of $25.0 million and are reflected in our balance sheet under restricted cash. In January 2019, we executed an amendment to the DNB RCF agreement which allowed us to finance the issuance of guarantees secured by the collateral rigs under the loan agreement instead of cash collateral, which resulted in the release of the $25.0 million of cash that was categorized as restricted as of December 31, 2018.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The discussion and analysis of our financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our financial statements.

We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe that most of these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. For a more complete discussion of our accounting policies, see Note 2—“Accounting policies” to our Consolidated Financial Statements.

Our Jack-up Rigs

The carrying amount of our jack-up rigs is subject to various estimates, assumptions, and judgments related to capitalized costs, useful lives and residual values and impairments. As of March 31, 2019, December 31, 2018 and 2017, the carrying amount of our jack-up rigs was $2,416.1 million, $2,278.1 million and $783.3 million, representing 78.0%, 78.2% and 46.8% of our total assets, respectively.

Jack-up rigs 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 jack-up rigs, when new, is 30 years.

We determine the carrying values of our jack-up rigs and related equipment based on policies that incorporate estimates, assumptions and judgments relative to the carrying values, 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 jack-up rigs, which could materially affect our results of operations.

The useful lives of our jack-up 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

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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 jack-up rigs as of and when events occur that 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 jack-up rigs and related equipment are reviewed for impairment when certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be recoverable. We assess recoverability of the carrying value of an 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 loss is recorded equal to the difference between the asset’s carrying value and fair value. 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.

Our management has identified certain indicators, among others, that the carrying value of our jack-up rigs and related equipment may not be recoverable and our market capitalization was lower than the book value of our equity. These market indicators include the reduction in new contract opportunities, fall in market dayrate and contract terminations. We assessed recoverability of our jack-up rigs by first evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilizations of the rigs. The estimated undiscounted future net cash flows were found to be greater than the carrying value of our jack-up rigs, with sufficient headroom. As a result, we did not need to proceed to assess the discounted cash flows of our rigs, and no impairment charges were recorded.

With regard to older jack-up rigs 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 rig obtaining a contract upon the expiration of any current contract, and our intention for the rig should no contract be obtained, including warm/cold stacking or disposal. The use of different assumptions in the future could potentially result in an impairment of our jack-up rigs, which could materially affect our results of operations. If market supply and demand conditions in the jack-up drilling market do not improve, it is likely that we will be required to impair certain jack-up rigs.

Financial Instruments

Marketable debt securities held by us which do not give us the ability to exercise significant influence are considered to be available-for-sale. These are re-measured at fair value each reporting period with resulting unrealized gains and losses recorded as a separate component of accumulated other comprehensive income in stockholders’ equity. Gains and losses are not realized until the securities are sold or subject to temporary impairment. Gains and losses on forward contracts to purchase marketable equity securities that do not meet the definition of a derivative are accounted for as available-for-sale securities. We analyze our available-for-sale securities for impairment at each reporting period to evaluate whether an event or change in circumstances has occurred in that period that may have a significant adverse effect on the value of the securities. We record an impairment charge for other-than-temporary declines in value when the value is not anticipated to recover above the cost within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in value are not reflected in earnings until sale of the securities held as available for sale occurs.

Where there are indicators that fair value is below the carrying value of our investments, we will evaluate these investments for other-than-temporary impairment. Consideration will be given to (i) the length of time and the extent to which fair value of the investments is below carrying value, (ii) the financial condition and near-term prospects of the investee, and (iii) our intent and ability to hold the investment until any anticipated recovery. Where we determine that there is other-than-temporary impairment, we will recognize an impairment loss in the period.

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Marketable equity securities with readily determinable fair value are re-measured at fair value each reporting period with unrealized gains and losses recognized under other total income (expenses), net.

Income Tax Positions

Income taxes, as presented, are calculated on an “as if” separate tax return basis. Our global tax model has been developed based on our entire business. Accordingly, the tax results are not necessarily reflective of the results that we would have generated on a stand-alone basis. Income tax expense is based on reported income or loss before income taxes.

As tax law is based on interpretations and applications of the law, which are only ultimately decided by the courts of the particular jurisdictions, significant judgment is involved in determining our provision for income taxes in the ordinary course of our business. 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, based on the technical merits of each position and having regard to the relevant taxing authority’s widely understood administrative practices and precedence.

Deferred tax assets and liabilities are based on temporary differences that arise between carrying values used for financial reporting purposes and amounts used for taxation purposes of assets and liabilities and the future tax benefits of tax loss carry forwards. A deferred tax asset is recognized only to the extent that it is probable that future taxable profits will be available against which the asset can be utilized. The impact of tax law changes is recognized in periods when the change is enacted.

Deferred tax assets and deferred tax liabilities are offset, if a legally enforceable right exists to set off current tax assets against current tax liabilities and the deferred taxes relate to the same taxable entity and the same taxation authority.

Business Combinations

The Company applies the acquisition method of accounting for business combinations in accordance with ASC 805. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred. The Company allocates the purchase price of acquired businesses to the identifiable tangible and intangible assets and liabilities acquired, with any remaining amount being recorded as goodwill.

The estimated fair value of the jack-up rigs in a business combination is derived by using a market and income-based approach with market participant-based assumptions. When we acquire jack-up rigs there may exist unfavorable contracts which are recorded at fair value at the date of acquisition. An unfavorable contract is a contract that has a carrying value which is higher than prevailing market rates at the time of acquisition. The net present value of such contracts when lower than prevailing market rates, is recorded as an onerous contract at the purchase date.

In a business combination, contract backlog is recognized when it meets the contractual-legal criterion for identification as an intangible asset when an entity has a practice of establishing contracts with its customers. We record an intangible asset equal to its fair value on the date of acquisition. Fair value is determined by using multi-period excess earnings method. The multi-period excess earnings method is a specific application of the discounted cash flow method. The principle behind the method is that the value of an intangible asset is equal to the present value of the incremental after-tax cash flows attributable only to the subject intangible asset after deducting contributory asset charges. The asset is then amortized over its estimated remaining contract term.

Lease Liabilities

We apply ASU No. 2016-02 (Topic 842), as amended, which generally requires lessees to recognize operating and financing lease liabilities and corresponding right-of-use (ROU) assets on the balance sheet and to provide enhanced disclosures surrounding the amount, time and uncertainty of cash flows arising from lease agreements. As lessee, we have made the accounting policy election to not recognize a right-of-use asset lease and lease liability for leases with a term of 12 months or less.

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Many of our leases contain variable non-lease components such as maintenance, taxes, insurance, and similar costs for the spaces we occupy. For new and amended leases beginning in 2019 and after, the Company has elected the practical expedient not to separate these non-lease components of leases for classes of all underlying assets and instead account for them as a single lease component for all leases. We straight-line the net fixed payments of operating leases over the lease term and expense the variable lease payments in the period in which we incur the obligation to pay such variable amounts. These variable lease payments are not included in our calculation of our ROU assets or lease liabilities.

As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Certain of our lease agreements include options to extend or terminate the lease, which we do not include in our minimum lease terms unless management is reasonably certain to exercise.

Our drilling contracts contain a lease component related to the underlying drilling equipment, in addition to the service component provided by our crews and our expertise to operate such drilling equipment. We have concluded the non-lease service of operating our equipment and providing expertise in the drilling of the client’s well is predominant in our drilling contracts. We have applied the practical expedient to account for the lease and associated non-lease components as a single component. With the election of the practical expedient, we will continue to present a single performance obligation under the new revenue guidance in Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers.”

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 2 to our Consolidated Financial Statements and our Interim Financial Statements for a discussion of recently adopted and issued accounting pronouncements. Please also see the section entitled “—Critical Accounting Policies and Estimates” above.

OFF BALANCE SHEET ARRANGEMENTS

We had no off-balance sheet arrangements during the years ended December 31, 2018 and 2017 or the three months ended March 31, 2019.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including liquidity risks, interest rate risks, inflation risks, foreign currency risks and credit risks.

Liquidity Risk

We manage our liquidity risk by maintaining adequate cash reserves and undrawn facilities at banking facilities, by continuously monitoring our cash forecasts and our actual cash flows and by matching the maturity profiles of financial assets and liabilities.

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Interest Rate Risk

We are exposed to interest rate risk related to floating-rate debt under our Financing Arrangements. Our variable rate debt, where the interest rate may be adjusted frequently over the life of the debt, exposes us to short-term changes in market interest rates. We are exposed to changes in long-term market interest rates if and when maturing debt is refinanced with new debt.

Further, we may utilize derivative instruments to manage interest rate risk in the future. We are not engaged in derivative transactions for speculative or trading purposes.

A change of 100 basis points in interest rates for the year ended December 31, 2018 would have increased/(decreased) our total other income (expenses), net and loss before income taxes by the amounts shown below. This analysis assumes that all other variables remain constant. The analysis is performed on the same basis for the year ended December 31, 2017 and for the three months ended March 31, 2019.

	For the Three Months ended March 31,			For the Year ended December 31,
	2019			2018			2017
	(in $ millions)
Sensitivity Analysis – Financial income (expense), net
Increase by 100 basis points	$	(2.1	)	$	(3.8	)	$	2.9
Decrease by 100 basis points		2.1			3.8			(2.9	)
Sensitivity Analysis – Loss before income taxes
Increase by 100 basis points		(2.1	)		(3.8	)		2.9
Decrease by 100 basis points		2.1			3.8			(2.9	)

Inflation Risk

Inflation has not had significant impact on operating or other expenses, however our contracts do not generally contain inflation-adjustment mechanisms and we are subject to risks related to inflation.

We do not consider inflation to be a significant risk to costs in the current and foreseeable future economic environment. However, should the world economy be affected by inflationary pressures this could result in increased operating and financing costs.

Foreign Currency Risk

Our international operations expose us to currency exchange rate risk, although we believe this risk is low. This risk is primarily associated with compensation costs of employees, drilling contracts in the North Sea and purchasing costs from non-U.S. suppliers, which are denominated in currencies other than the U.S. dollar, including Euros, Pounds and Nigerian Naira. We do not have any non-U.S. dollar debt and thus are not exposed to currency risk related to debt.

Our primary currency exchange rate risk management strategy involves structuring certain customer contracts to provide for payment from the customer in both U.S. dollars and local currency. The payment portion denominated in local currency is based on anticipated local currency requirements over the contract term. Due to various factors, including customer acceptance, local banking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual local currency needs may vary from those anticipated in the customer contracts, resulting in partial exposure to currency exchange rate risk. The currency exchange effect resulting from our international operations has not historically had a material impact on our operating results.

Further, we may utilize foreign currency forward exchange contracts to manage foreign exchange risk. We are not engaged in derivative transactions for speculative or trading purposes.

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Credit Risk

Our financial instruments that potentially subject us to concentrations of credit risk are cash and cash equivalents and accounts receivables. We generally maintain cash and cash equivalents at commercial banks with high credit ratings.

Our trade receivables are with a variety of integrated oil companies, state-owned national oil companies and independent oil and gas companies. We perform ongoing credit evaluations of our customers, and generally do not require material collateral. We may from time to time require customers to issue bank guarantees in our favor to cover non-payment under drilling contracts.

An allowance for doubtful accounts is established on a case-by-case basis, considering changes in the financial position of a customer, when it is believed that the required payment of specific amounts owed is unlikely to occur. We have not currently made any allowance for doubtful accounts in our Consolidated Financial Statements.

Market Risk

From time to time, we make and hold investments in other companies in our industry that own/operate offshore drilling rigs with similar characteristics to our fleet of jack-up rigs, subject to compliance with the covenants contained in certain of our Financing Arrangements which restrict such investments. We also purchase and hold debt securities issued by other companies in the offshore drilling industry from time to time. Through these investments, we seek to optimize our free-cash flow through strategic investments where cash may otherwise remain idle. In addition, the Call Spread Transactions expose us to the risk of fluctuations in the market value of our Shares.

As a result of these investments and transactions, we are exposed to the risk of fluctuations in the market values of the available-for-sale financial assets we hold from time to time (other than changes in interest rates and foreign currencies) and our Shares. We generally do not use any derivative instruments to manage this risk.

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INDUSTRY OVERVIEW

When furnishing the information set out in this Prospectus, including the industry information and data presented in this section entitled “Industry Overview,” we have used certain statistical and graphical information obtained from Rystad Energy, an independent energy research and business intelligence company. Rystad Energy has advised us that the statistical and graphical information presented in this Prospectus is drawn from its database and other sources. Rystad Energy has further advised us that: (a) certain of the information provided is based on estimates or subjective judgments, (b) the information in the databases of other offshore drilling data collection agencies may differ from the information in Rystad Energy’s database and (c) while Rystad Energy has taken reasonable care in the compilation of the statistical and graphical information and believes it to be accurate and correct, data collection is subject to limited audit and validation procedures. Market data and statistics are inherently predictive and subject to uncertainty and do not, necessarily, reflect actual market conditions. Such statistics are based on market research, which, itself, is based on sampling and subjective judgments by both the researchers and the respondents, including judgments about what types of products and transactions should be included in the relevant market. Furthermore, all references to barrels of oil refer to barrels of Brent crude oil.

We have compiled, extracted and reproduced data from Rystad Energy and, confirm that such information has been accurately reproduced and, as far as we are aware and are able to ascertain, no facts have been omitted that would render the reproduced information inaccurate or misleading. Forward-looking information obtained from third-party sources, including Rystad Energy, is subject to the same qualifications and the uncertainties regarding the other forward-looking statements in this Prospectus. See the sections entitled “Risk Factors” and “Note Regarding Forward-Looking Statements.”

INTRODUCTION

We operate in the global offshore contract drilling industry, which is a part of the international oil industry, and within the global offshore contract drilling industry we predominately operate jack-up rigs in shallow-water. The activity and pricing within the global offshore contract drilling industry is driven by a multitude of demand and supply factors, including expectations regarding oil and gas prices, anticipated oil and gas production levels, worldwide demand for oil and gas products, the availability of quality reservoirs, exploration success, availability of qualified drilling rigs and operating personnel, relative production costs, the availability of or lead time required for drilling and production equipment, the stage of reservoir development and the political and regulatory environments. One fundamental demand driver is the level of investment by E&P Companies and their associated capital expenditures. Historically, the level of upstream capital expenditures has primarily been driven by future expectations regarding the price of oil and natural gas. This correlation has recently been observed following the decline in crude oil prices in 2014, which had a negative impact on the demand for services across the oil service industry in general. As oil prices fell from an average of $109/unit of Brent oil (“barrel” or “Bbl”) in the first half of 2014 to an average of $44/Bbl in 2016, declining prices along with uncertainty of future price development caused a material reduction in global E&P Companies’ offshore spending in each of 2015, 2016 and 2017. However, as the price of oil has risen from the 2016 trough, E&P Companies’ offshore spending has stabilized. The figure below shows the relationship between global E&P Companies’ offshore spending on exploration and production and associated capital expenditure and the yearly average oil price from 2000 to 2018.

Figure 1.1: Global E&P Companies’ offshore spending from 2000 to 2018

 

Note: E&P expenditures excludes estimated internal operating expenses, including internal salaries, internal engineering, project management, SG&A, transport fees and special taxes, which typically do not affect expenditures on offshore drilling.

Source: Rystad Energy ServiceDemandCube (as of June 12, 2019 (E&P spending)); Bloomberg (Yearly average oil price)

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OVERVIEW OF THE GLOBAL OFFSHORE CONTRACT DRILLING MARKET

The offshore contract drilling industry provides drilling, workover and well construction services to E&P Companies through the use of MODUs. Historically, the offshore drilling industry has been highly cyclical. As seen in Figure 1.1 above, offshore spending by E&P Companies has fluctuated substantially on an annual basis depending on a variety of factors. See “Risk Factors—Risk Factors Related to Our Industry.”

The profitability of the offshore contract drilling industry is largely determined by the balance between supply and demand for MODUs. Offshore drilling contractors can mobilize MODUs from one region of the world to another, or reactivate stacked/laid up rigs in order to meet demand in various markets.

Offshore drilling contractors typically operate their MODUs under contracts received either by submitting proposals in competition with other contractors or following direct negotiations. The rate of compensation specified in each contract depends on, among other factors, the number of available rigs capable of performing the work, the nature of the operations to be performed, the duration of work, the amount and type of equipment and services provided, the geographic areas involved and other variables. Generally, contracts for drilling services specify a daily rate of compensation and can vary significantly in duration, from weeks to several years. Competitive factors include, amongst others: price, rig availability, rig operating features, workforce experience, operating efficiency, condition of equipment, safety record, contractor experience in a specific area, reputation and customer relationships.

Periods of high demand are typically followed by a shortage of rigs and consequently higher dayrates which, in turn, makes it advantageous for industry participants to place orders for new rigs. This was the case prior to the oil price decline in 2014, where several industry participants ordered new rigs in response to the high demand in the market. However, despite the deteriorating market conditions in the recent downturn, the number of rigs available in the market continued to increase due to both rigs coming off contract with no follow on work and continued inflow of new rigs (albeit at a slower rate than originally planned). This increase in spare capacity, when met with reduced demand for services, shifted excess rig demand into an excess supply of rigs and, consequently reduced dayrates. The figure below illustrates the development in supply and demand for MODUs, split by the three MODU sub-segments: drillships, semi-submersibles and jack-ups (demand reflects the number of contracted MODUs in the global market at each given period).

Figure 1.2: Supply and demand for MODUs from 2000 to 2018

 

Source: Rystad Energy RigCube (as of June 12, 2019)

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MODU Segments

All MODUs provide varying levels of storage capacity, workspace, drilling and water depth capabilities as well as living quarters necessary to support well construction and maintenance services to its customer 24 hours a day. MODUs are generally divided into three main segments as described below.

Jack-ups

Jack-up rigs are mobile drilling platforms standing on the seabed, typically equipped with three steel legs and a self-elevating system that adjusts the platform height to water depth (this Prospectus focuses on independent leg units only, as opposed to mat-supported and other types of jack-up rigs, which are rarely used anymore). When the jack-up rig arrives at its drilling location, it will jack its steel legs down on the seabed until its platform is above the waterline. Upon completion of drilling operations, the jack-up rig is towed by tugboats to its next location or, if being moved over a greater distance, lifted by a heavy-transportation vessel. Jack-up rigs typically operate in shallow-water depths, generally ranging from 30 to 400 feet.

The jack-up rig’s deck provides space for drilling equipment, supplies and living quarters. Modern jack-up rigs typically have a drilling package mounted on a cantilever (a platform projecting outward from the jack-up rig), which allows it to drill away from the hull. A cantilevered rig enables drilling at distances from the hull ranging from approximately 45 to 110 feet. The cantilever allows for flexibility when the jack-up rig is required to perform drilling or workover operations over pre-existing platforms or structures, such as metal towers (jackets) that are put in place to support production facilities. A cantilevered rig is very useful for drilling a series of wells, as it allows the client to perform operations on multiple wells on the platform without re-positioning the jack-up rig.

There are several sub-categories within the jack-up drilling segment based on different attributes of the respective jack-up rigs, typically water depth capability, hook load capacity and cantilever reach. Jack-up rigs can also be designed and equipped to operate in harsh environment (lower temperature and/or harsher weather conditions compared to more benign environments). The offshore drilling market has, over the last years, experienced a shift in demand towards modern and more advanced rigs. In line with this trend, several drilling contractors have, over the last five years, renewed their fleets through both newbuildings and acquisitions.

Jack-up rigs are used globally, with the top three regions by number of contracted jack-ups being the Middle East, South-East Asia and the Indian Ocean.

Semi-submersibles

Semi-submersible rigs, or semi-submersibles, are floating platforms equipped with a ballasting system that can vary the draft (the distance between the surface of the water and the lowest point of the rig) of the partially submerged hull from a shallow draft for transit to a predetermined operational draft while drilling operations are ongoing at a well location. Submerging the rig further in the water reduces the rig’s exposure to ocean conditions (waves, winds and currents) and increases its stability.

Semi-submersible rigs typically have the capability to operate in water depths generally ranging from 450 to 12,000 feet, but are primarily used in water depths between the operational capabilities of jack-up rigs and drillships, or around 7,500 feet.

Semi-submersibles drill in open water, do not have cantilevers and cannot drill over fixed structures. Drilling operations are conducted through an opening in the hull. Semi-submersibles maintain their position above the wellhead either by means of a conventional mooring system, consisting of anchors and chains and/or cables, or by a computerized dynamic positioning system. Generally, in shallower waters, semi-submersibles are moored to the seafloor with anywhere from six to twelve anchors. Once the water depth becomes too deep, the rigs depend on dynamic positioning systems to keep the vessel in place while drilling. The dynamic positioning system relies on several thrusters located on the hulls of the rig, which are activated by an on-board computer that constantly monitors winds and waves to adjust the thrusters to compensate for these changes.

Semi-submersibles are most prevalent in North West Europe, South East Asia and South America.

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Drillships

Drillships are ships with an on-board propulsion system, often based on a conventional ship hull design, but carrying full drilling equipment similar to that on semi-submersible rigs. Drilling operations are conducted through moon pools, and like modern semi-submersible rigs, drillships are in general equipped with dynamic positioning systems. Drillships generally have the capability to operate in water depths ranging from 450 to 12,000 feet, but are primarily used in water depths between deepwater and ultra-deepwater territory, ranging from 7,500 to 12,000 feet.

Drillships normally have better mobility and higher load capacity than the other MODUs, which make them more suitable for exploration drilling in ultra-deepwater areas far from shore bases and other infrastructure. Drillships are, however, less stable than semi-submersibles, which makes them less suitable for harsh environment areas and therefore are usually operated in benign water regions such as offshore South America, West Africa and the U.S. Gulf of Mexico.

THE JACK-UP RIG SEGMENT

The market

Jack-up rigs can, in principle, be used to drill (a) exploration wells, i.e. explore for new sources of oil and gas or (b) new production wells in an area where oil and gas is already produced; the latter activity is referred to as development drilling. As seen in Figure 1.3 below, shallow-water oil and gas production is generally a low-cost production, with shallow-water oil and gas production the cheapest method of drilling second only to Middle East onshore production in terms of cost per barrel of oil. As a result, and due to the shorter period from investment decision to cash flow, E&P Companies generally invest in shallow-water developments over other offshore production categories. The figure below shows Rystad Energy’s global liquids cost curve.

Figure 1.3: Global liquids cost curve

 

Note: The chart above illustrates the estimated breakeven prices in Brent crude oil equivalent for all projects from different sectors of potential global liquids production and the cumulative liquids production in 2020 deliverable from these sectors. The breakeven prices in Brent crude oil equivalent are calculated by Rystad on a project-by-project basis within each sector and represent the Brent crude oil price required to generate a 10% rate of return for the project on a forward-looking basis (i.e., any activity before 2017 is disregarded). Data comprises fields that will produce by 2020, i.e. also include fields that are not currently producing but are expected to by 2020. The projects are then aggregated by sector, and plotted to illustrate the range of breakeven and weighted average breakeven price by sector. The 20% highest and 20% lowest breakeven prices for the different supply sources are not shown in the figure. Onshore Middle East and North American Shale are regional categories, while the other categories are global.

Source: Rystad Energy Ucube (as of June 12, 2019)

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According to Rystad Energy, and as shown in Figure 1.4 below, oil production in shallow-waters, where jack-up rigs are used, accounted for 64% of the global offshore production during the last five years (a fraction of shallow production also comes from fixed installations). Shallow-water production therefore represents a key element in the global oil supply chain. The figure below shows the offshore oil production by water depth.

Figure 1.4: Offshore oil production by water depth from 2000 to 2018

 

Note: The above figure reflects crude oil and condensate.

Source: Rystad Energy Ucube (as of June 12, 2019)

77% out of the estimated average 285 contracted rig years (i.e., the total aggregate number of days under contract is 285 years) on jack-up rigs globally were used for production drilling in 2018. The remaining 23% were used for exploration drilling. The tendency to rely on shallow-water production during periods of recovery makes the jack-up drilling market more resilient and less volatile when compared against other MODU segments, especially those more exposed to exploration drilling. The graph below shows the development in usage for jack-up rigs between 2000 and 2018.

Figure 1.5: Development in type of rig employment for jack-ups from 2000 to 2018

 

Note: The above figure reflects the number of contracted rig years on jack-up rigs globally.

Source: Rystad Energy RigCube (as of June 12, 2019)

Competition and margins

The jack-up drilling market is characterized by a highly competitive and fragmented supplier landscape, with market participants ranging from large international companies to small, locally owned companies and rigs owned by national oil companies (the latter are referred to as owner-operated rigs). The operations of the largest players are generally dispersed around the globe due to the high mobility of most MODUs. Although the cost of moving MODUs from one region to another and/or the availability of rig-moving vessels may cause a short term imbalance between supply and demand in one region, significant variations between

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regions do not exist in the long-term due to MODU mobility. According to Rystad Energy as of June 12, 2019, excluding rigs under construction, 93 contract drilling companies own a total of 493 jack-up rigs, equivalent to approximately 5.3 rigs per company on average. Figure 1.6 below illustrates the fragmented supply situation, showing that very few drilling companies own a material fraction of the total jack-up fleet worldwide.

Figure 1.6: Number of jack-ups owned by different drilling companies

 

Note: The above figure excludes newbuild jack-up rigs under construction.

Source: Rystad Energy RigCube (as of June 12, 2019)

Offshore drilling contracts are generally awarded on a competitive bid basis. In determining which qualified drilling contractor is awarded a contract, key factors are pricing, rig availability and sustainability, rig location, condition of equipment, operating integrity, safety performance record, crew experience, reputation, industry standing and client relationships.

Furthermore, competition for offshore drilling rigs is generally on a global basis, as MODUs are highly mobile. However, the cost associated with mobilizing rigs between regions can be substantial, as entering a new region could necessitate upgrades of the unit and its equipment due to specific regional requirements. We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future. Please see “Risk Factors—Risk Factors Related to Our Industry—The jack-up drilling market historically has been highly cyclical, with periods of low demand and/or over-supply that could result in adverse effects on our business.”

Jack-up rig sub-segments

There are several sub-segments within the jack-up drilling segment based on different attributes of the rigs, typically water depth capability, age, hook load capacity, cantilever reach and environmental conditions a rig can operate in. The sub-segment classification varies across market participants, third parties (researchers, consultants etc.), classification societies and others. In this Prospectus, we have used the following classification of the jack-up sub-segments, which are as follows:

• “modern” – rigs delivered in 2000 or later; and

• “standard” – rigs delivered prior to 2000.

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Recently, the jack-up drilling market has experienced a shift in demand towards modern jack-up rigs. In line with this trend, several drilling contractors are renewing their fleets through both newbuildings and rig acquisitions. The figure below shows the largest owners of modern jack-up rigs by number of rigs.

Figure 1.7: Largest modern jack-up rig owners by number of rigs

 

Note: Figure only includes publicly listed owners; Seadrill Limited excludes non-consolidated entities (Seamex Limited); EnscoRowan plc excludes ARO Drilling Joint Venture.

Source: Rystad Energy RigCube (as of June 12, 2019)

One of the main reasons for the increased focus on modern jack-up rigs is an expected increase in the activity which requires equipment of higher standards due to more demanding wells. The 2010 Deepwater Horizon Incident (to which we were not a party) on the BP-operated Macondo prospect has led to an increased focus on safe operations and QHSE performance from the E&P Companies, leading to E&P Companies in part shifting their preference to more advanced equipment. This trend can be observed in Figure 1.8 below.

Figure 1.8: Development in number of contracted jack-ups split by sub-segment from 2003 to May 2019

 

Source: Rystad Energy RigCube (as of June 12, 2019)

In addition to the sub-segments described above, which are based on the attributes of the rig, there is another sub-segment for jack-ups, namely owner-operated jack-up rigs. These rigs are wholly or partially owned by oil companies, often being national or state-owned oil companies (“NOCs”) or international oil companies (“IOCs”). Generically speaking, owner-operators occasionally ordered drilling rigs to cover recurring work, which may span several years, or to meet basic demand within certain geographical areas. Owner-operated rig employment shares some similarities with outsourced drilling activity—when an NOC or IOC has chartered a drilling rig long-term, but with no specific work for it, such company may offer the rig to other oil companies. According to Rystad Energy, as of June 12, 2019, the owner-operated jack-up fleet is relatively fragmented, with 23 companies owning 86 jack-up rigs. The largest owner is the Abu Dhabi National Oil Company (“ADNOC”), owning 20 jack-up

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rigs, followed by China Petroleum Offshore Engineering Company Ltd., owning 10 jack-ups. Among other well-known oil companies owning jack-ups are Equinor ASA (formerly Statoil ASA), which owns two jack-up rigs. Geographically, the owner-operated fleet is rather concentrated in Asia, with approximately 34% of the fleet operating throughout China, Vietnam and India.

The demand for owner-operated jack-up rigs is, to an extent, unrelated to conventional demand for contract drilling services, primarily as the drilling demand covered by owner-operated rigs has not historically been considered as part of conventional demand for contract drilling services by the industry. Furthermore, owner-operated jack-up rigs are often built with unique specifications fit for a specific purpose or field, hence they can be less versatile than conventional jack-ups. In recent years, NOCs and IOCs have trended toward a preference for contracted jack-up rigs as opposed to owner-operated rigs, evinced through the relative low number of newbuild orders and an older fleet, on average. Figure 1.9 below outlines the geographical distribution of the current fleet of owner-operated jack-up rigs.

Figure 1.9: Geographical split of owner-operated jack-ups

 

Source: Rystad Energy RigCube (as of June 12, 2019)

The global jack-up rig fleet

According to Rystad Energy, as of June 12, 2019, the global jack-up drilling fleet was approximately 501 units. Of the global fleet as of June 12, 2019, 285 jack-up rigs are currently drilling, 120 rigs are ready and warm-stacked, 65 rigs are cold-stacked and the remaining 31 are being used for other non-drilling purposes, stacked and/or retired. As illustrated in Figure 1.10 below, the fraction of the active fleet which is actively contracted has increased from approximately 54% in 2017 to 57% in 2018, reflecting an increase in offshore drilling activity.

Figure 1.10: Jack-up fleet status from 2000 to 2018

 

Note: The above figure excludes newbuild jack-up rigs under construction.

Source: Rystad Energy RigCube (as of June 12, 2019)

Periods of high jack-up utilization, high dayrates, availability of capital and positive market expectations generally lead to increased ordering activity. After a period of high building activity in the early 1980s, jack-up ordering activity was muted through the 1990s, until 2005. In the recent upcycle from 2005 until 2014, a large

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number of jack-up rigs were ordered. Although there are large variations in the condition of older rigs, the expected increase in the complexity of wells to be drilled, and the general focus on safe operations and QHSE performance, is shifting E&P Company demand toward newer rigs. Figure 1.11 below shows the historical newbuild development of the global jack-up rig fleet since 1970. Please see Figure 1.12 and the related discussion below for information on rigs currently on order or under construction.

Figure 1.11: Development in jack-up newbuild deliveries from 1970 to 2018

 

Source: Rystad Energy RigCube (as of June 12, 2019)

As of June 12, 2019, there were 72 jack-ups on order for delivery through to 2020, representing 27% of the rigs delivered and expected to be delivered in the period from 2010 to 2020. Furthermore, a significant number of jack-up orders placed at Chinese shipyards, which have different experience in building jack-up rigs, were made on speculation by non-established offshore drilling contractors and without employment secured post-delivery. With respect to a number of these jack-up rigs, construction supervision has been poor and such rigs remain unfinished and may never be delivered or otherwise enter the global jack-up fleet. As illustrated in Figure 1.12 below, Chinese shipyards represent 72% of the current global order book, but have in general less experience building jack-up rigs historically. The figure below shows the historical jack-up rig deliveries from 2010 to 2018 and the estimated delivery schedule of current order book by shipyard country.

Figure 1.12: Historical jack-up deliveries from 2010 to 2019 and estimated delivery schedule of current order book

 

Note: According to Rystad Energy, 11 jack-up rigs have been delivered in 2019 as of June 12, 2019 (seven jack-up rigs from Chinese yards and four rigs from other yards).

Source: Rystad Energy RigCube (as of June 12, 2019)

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Currently, over 40% of the jack-up drilling fleet is more than 30 years old. A large portion of the older rigs have been without work for several years and will require significant capital expenditure in order to become competitive. The figure below shows the development in the number of jack-up rigs older than 30 and 40 years as a percent of the total jack-up drilling fleet.

Figure 1.13: Rigs older than 30 and 40 years old in percentage of the total jack-up drilling fleet from 2000 to 2020e

 

Source: Rystad Energy RigCube (as of June 12, 2019)

As older rigs struggle to find work, contractors are less likely to invest in ongoing maintenance and upgrades. Consequently, these rigs will require significant capital expenditure to become operational. Although the scrap value of a jack-up rig is generally lower than floaters (less steel and associated equipment and inventories), high reactivation costs and less attractive re-contracting prospects are likely to force many of the older jack-up rigs to the scrapping yard. Since the peak in the summer of 2014, as of June 12, 2019 111 jack-up rigs with an average age of 39 years have been scrapped (or recycled for non-drilling purposes). The youngest rig scrapped was built in 1999. As the scrap value of an older jack-up rig, depending on rig location, can be similar or less than the cost of relocating the rig, the actual number of rigs scrapped (or recycled for non-drilling purposes) could be significantly higher than the number of rigs brought to the scrapping yards.

Demand

Historically, demand for jack-up rigs has been primarily driven by NOCs. Since 2000, NOCs have increased their demand for jack-up rigs at a higher rate than other E&P Companies, both in absolute and relative terms. IOCs and small independent E&P Companies have generally become increasingly focused on deepwater drilling. NOCs and integrated national oil companies (“INOCs”) represented an average of 40% of the total jack-up rig demand from 2010 to 2018. By comparison, the major E&P Companies were responsible for, on average, 12% of total jack-up rig demand from 2010 to 2018, which is the second largest source of demand in the jack-up drilling market. The figure below shows the development in jack-up rig demand by type of operator.

Figure 1.14: Jack-up rig demand by operator from 2000 to 2018

 

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Note: The category “NOC & INOC” includes national oil companies and integrated national oil companies; the category “Majors” includes the seven largest E&P Companies: ExxonMobil, BP, Shell, Chevron, Total, ConocoPhillips and ENI; the category “Independent” includes upstream oriented companies with exploration and production assets with average daily production greater than 50 kboe/d; the category “E&P Companies” includes upstream oriented companies with average daily production lower than 50 kboe/d owning both fields and licenses; and the category “Other” includes industrial companies, suppliers and other investors.

Source: Rystad Energy RigCube (as of June 12, 2019)

As seen in Figure 1.15 below, and as of June 12, 2019, the NOCs who have contracted the largest number of jack-up rigs are Saudi Aramco, China National Offshore Oil Corporation, Oil and Natural Gas Corporation (India), ADNOC, Pemex and Qatar Petroleum. According to Rystad Energy, these companies are expected to continue with high levels of shallow-water drilling activity.

Figure 1.15: Number of contracted jack-up rigs by top 10 operators

 

Note: The above figure excludes owner-operated jack-up rigs.

Source: Rystad Energy RigCube (as of June 12, 2019)

NOCs typically reflect a long-term view of the offshore drilling industry. This has resulted in an increase in jack-up contract days in recent years. In contrast, independent E&P Companies generally take a shorter-term view of the offshore drilling industry. These different approaches have resulted in a divergence of activity levels with independent E&P Companies being more prone to cancelling or delaying projects where viability is threatened by persistent cost increases. On the other hand, NOCs’ longer-term view tends to result in fewer project cancellations, longer contract lengths and ultimately, higher levels of sustained drilling activity. The figure below illustrates the average jack-up rig contract lengths by operator type.

Figure 1.16: Average jack-up drilling contract lengths by operator type from 2010 to 2018

 

Note: The above figure excludes owner-operated jack-up rigs and shows new unique contracts only.

Source: Rystad Energy RigCube (as of June 12, 2019)

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Dayrates

As observed in Figure 1.17, the global jack-up drilling market experienced a steady increase in dayrates in the period from 2010 to 2014. The significant increase was due primarily to increased demand for drilling services caused by rapidly increasing oil and gas prices and investments in exploration during the period. The dayrates have since fallen more than 45% on average from the peak level observed in 2013. Figure 1.17 below shows the development in dayrates.

Figure 1.17: Dayrates per jack-up segment from 2008 to May 2019

 

Note: The above figure shows new unique contracts only.

Source: Rystad Energy RigCube (as of June 12, 2019)

Utilization

In line with the rest of the offshore drilling industry, the global jack-up drilling market was adversely affected by the abrupt downturn in the price of oil in 2014, which resulted in customers cancelling and/or postponing their drilling projects. The 2014 downturn broke the upward trend in utilization which occurred from 2011 to 2014, resulting in the decline of the average utilization rate for jack-up rigs from approximately 81% in 2013 to 57% in 2018. As observed in Figure 1.18 below, the jack-up drilling market is generally short-cycled in nature compared to the floater drilling market (consisting of the two drilling rig segments: drillships and semi-submersibles), meaning that recovery is generally faster. According to Rystad Energy, E&P Companies prefer shallow-water developments over deepwater as the market recovers due to shorter periods from the initial investment decision to the generation of cash flow. The figure below illustrates the development in utilization for the global jack-up drilling fleet compared to the global floater fleet.

Figure 1.18: Total utilization for jack-up rigs vs floaters from 2003 to May 2019

 

Note: The above figure excludes newbuild jack-up rigs under construction.

Source: Rystad Energy RigCube (as of June 12, 2019)

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As reflected above, the jack-up drilling market is traditionally characterized by a short-cycled nature and the tendency to employ jack-up rigs on brownfield projects (drilling on reservoirs which have matured to a production plateau or even progressed to a stage of declining production), which have relatively low breakeven points, further exacerbates the short-cycled nature of the jack-up drilling market. The jack-up drilling market has historically been less volatile and the areas with jack-up exposure have recovered faster following price down-cycles than those areas with greenfield projects (drilling on newly discovered oil reservoirs), with the latter historically having utilized floaters to a larger extent. The short-cycle nature and attractive economics of shallow-water development has resulted in the jack-up drilling market recovering on average nine months faster than the floater market in previous commodity price down-cycles. This is evident in Figure 1.19 below, which sets out the marketed utilization for jack-up rigs and floaters for the five most prominent commodity price down-cycles as a percentage change from the peak utilization (which is set as 100% at the start of the periods presented).

Figure 1.19: Marketed utilization for five different commodity price down-cycles

 

Source: Rystad Energy RigCube (as of June 12, 2019) and Rystad Energy research and analysis.

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Jack-up drilling regions

Since 2010, the geographical location of the working jack-up drilling fleet, has been the most stable and the highest in the Middle East, the North Sea, the Indian Ocean and South East Asia (collectively representing more than 50% of the contracted fleet). With the exception of the Indian Ocean, these markets are still the most active and promising markets for high-specification jack-up rigs, with visible requirements increasing throughout 2019 and beyond. The demand for jack-up rigs in the Indian Ocean is covered predominately by local operators and standard jack-up rigs. The Middle East and South East Asia regional markets are characterized by higher activity from E&P Companies that are owned wholly or with a majority share by NOCs, and low breakeven costs relative to other regions. Although the development in activity in West Africa has declined since 2010, the region is currently regaining some of its potential. Development in Mexico has also declined, but is trending upward while the U.S. Gulf of Mexico has collapsed and is no longer considered a relevant market for jack-up rigs. The figure below shows the jack-up drilling market by region per 2018 compared to 2010, measured by number of contracted jack-up rigs.

Figure 1.20: Jack-up market activity by region, comparing 2018 to 2010

Colors represent jack-up activity level

 

Note: The shaded area on the above figure is intended only to show the general area and is not a precise depiction of the relevant jack-up region/market.

Source: Rystad Energy RigCube (as of June 12, 2019)

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Recent trends and outlook

According to Rystad Energy, activity in shallow-waters is increasing based on growing demand due to, among other factors, competitive break-even costs. Over the last couple of years, it has become evident that operators prefer modern jack-up rigs to standard jack-up rigs. Figure 1.21 below shows that the number of awarded contracts has increased by 28% from 2017 to the end of 2018 for modern jack-up rigs, while the number of awarded contracts has decreased by 8% for standard jack-up rigs. On an aggregated basis, the number of awarded contracts has increased by 15% from 2017 to 2018, showing that the overall demand for jack-up rigs is increasing.

Figure 1.21: Number of contracts awarded by jack-up segment

 

Note: The above figure reflects only new arms-length contracts and excludes non-competitive rigs (as defined by Rystad Energy) and certain Chinese contracts which were not awarded through competitive bidding processes and are therefore not considered by Rystad Energy as within global demand.

Source: Rystad Energy RigCube (as of June 12, 2019)

In addition to the increasing market share for modern jack-up rigs in terms of their share of contract awards, these jack-up rig sub-segments generally earn higher dayrates compared to other standard rigs due to their specialized features and greater capacity. This trend is particularly visible for modern jack-up rigs which, due to higher building costs, are eligible for a premium dayrate compared to standard jack-up rigs.

Figure 1.22 below shows the development in fixtures split by jack-up rig sub-segment and distinctively illustrates the difference in dayrate levels between the various rig classes. During the previous commodity price down-turn, the spread between modern and standard jack-up rigs narrowed significantly. This spread is, however, expected to widen again as activity in the industry picks up.

Figure 1.22: Jack-up fixtures from 2008 to 2018 per jack-up rig sub-segment

 

Note: The above figure excludes contract fixtures above $250,000 per day, non-competitive rigs (as defined by Rystad Energy) and certain Chinese contracts which were not awarded through competitive bidding processes and are therefore not considered by Rystad Energy as within global demand.

Source: Rystad Energy RigCube (as of June 12, 2019)

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Figure 1.23 below shows utilization over the period from 2006 to May 2019 for different jack-up sub-segments. It is visible that modern jack-up rigs have consistently experienced significantly higher utilization over the period from 2006 to May 2019. What is particularly evident is the bifurcation trend observed in the jack-up market from the trough in 2017 and onwards, as E&P Companies prefer more capable modern jack-up rigs over standard jack-up rigs. Utilization for modern jack-up rigs increased by 8% from May 2018 to May 31, 2019, while utilization for standard jack-up rigs decreased by 8% over the same period.

Figure 1.23: Jack-up rig utilization per jack-up rig sub-segment from 2006 to May 2019

 

Note: The above figure excludes newbuild jack-up rigs under construction.

Source: Rystad Energy RigCube (as of June 12, 2019)

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BUSINESS

OUR COMPANY

We are an offshore shallow-water drilling contractor providing worldwide offshore drilling services to the oil and gas industry. Our primary business is the ownership, contracting and operation of jack-up rigs for operations in shallow-water areas (i.e., in water depths up to approximately 400 feet), including the provision of related equipment and work crews to conduct oil and gas drilling and workover operations for exploration and production customers. We own 27 rigs, including 26 jack-up rigs and one semi-submersible rig, with an additional eight jack-up rigs scheduled to be delivered by the end of 2020. Upon delivery of these newbuild jack-up rigs, we will have a fleet of 30 premium jack-up rigs, which refers to rigs delivered from the yard in 2001 or later.

We aim to become a preferred operator of jack-up rigs within the jack-up drilling market. The shallow-water market is our operational focus as we expect demand will recover sooner than in the mid- and deepwater segments of the contract drilling market. We contract our jack-up rigs and offshore employees primarily on a dayrate basis to drill wells for our customers, including integrated oil companies, state-owned national oil companies and independent oil and gas companies. During 2018, our top five customers by revenue were subsidiaries of NDC, TAQA, BW Energy, Spirit Energy and Total. During the first quarter of 2019, our top five customers by revenue were subsidiaries of NDC, TAQA, Perenco, Total and Tulip. A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. Our Total Contract Backlog was $383.2 million as of June 30, 2019 and $377.5 million as of December 31, 2018. We currently operate in significant oil-producing geographies throughout the world, including the North Sea, the Middle East, Mexico, West Africa and Southeast Asia. We intend to operate our business with a competitive cost base, driven by a strong and experienced organizational culture and a carefully managed capital structure.

From our initial acquisition of rigs in early 2017, we have expanded rapidly into one of the world’s largest international offshore jack-up drilling contractors by number of jack-up rigs. The following chart illustrates the development in our fleet since our inception:

	As of and for the Six Months Ended June 30,		As of and for the Year Ended December 31,
	2019		2018		2017
Total Fleet as of January 1		27		13		0
Jack-up Rigs Acquired(1)		—		23		12
Newbuild Jack-up Rigs Delivered from Shipyards		2		9		1
Jack-up Rigs Disposed of		2		18		0
Total Fleet as of the end of Period		27		27		13
Newbuild Jack-up Rigs not yet Delivered as of the end of Period		8		9		13
Jack-up Rigs Committed to be Sold as of the end of Period		1		—		—
Total Fleet, including Newbuild Rigs not yet Delivered, as of the end of Period		35		36		26

(1) Includes acquisition of one semi-submersible rig in 2018.

Our operating revenues, net (loss) and Adjusted EBITDA for the year ended December 31, 2018 were $164.9 million, $(190.9) million and $(65.8) million, respectively, and for the three months ended March 31, 2019 were $51.9 million, $(56.4) million and $(15.3) million, respectively. Adjusted EBITDA is a non-GAAP measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to the most directly comparable financial measure of net loss under U.S. GAAP, see “Selected Financial and Other Data.”

Our common shares have traded on the Oslo Børs since August 2017, under the symbol “BDRILL.”

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HISTORY AND DEVELOPMENT

Borr Drilling Limited was incorporated by Taran Holdings Limited on August 8, 2016, pursuant to the Companies Act, as an exempted company limited by shares and registered in the Bermuda register of companies with the name “Magni Drilling Limited.” On December 16, 2016, we changed our name to Borr Drilling Limited. On December 19, 2016, our Shares were introduced to the Norwegian OTC market and on August 30, 2017, our Shares were listed on the Oslo Børs under the symbol “BDRILL.” Our principal executive offices are located at S. E. Pearman Building, 2^nd Floor, 9 Par-la-Ville Road, Hamilton HM11, Bermuda and our telephone number is +1 (441) 737-0152.

We have appointed Puglisi & Associates, whose address is 850 Liberty Avenue, Suite 204, Newark, Delaware 19711, as our agent upon whom process may be served in any action brought against us under the laws of the United States. Please see the section entitled “Enforceability of Civil Liabilities Against Foreign Persons” for more information.

The SEC maintains an internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, which can be found at http://www.sec.gov. Our internet address is http://borrdrilling.com/. The information contained on our website is not incorporated by reference and does not form part of this Prospectus.

Acquisition of Hercules Rigs

On December 2, 2016, we agreed to purchase two premium jack-up rigs (the “Hercules Rigs”) from Hercules British Offshore Limited (“Hercules”). The transaction was completed on January 23, 2017 (the “Hercules Acquisition”). The Hercules Rigs, named “Frigg” and “Ran,” were acquired at a total price of $130 million. Each rig is a premium jack-up rig.

Acquisition from Transocean

On March 15, 2017, we signed a letter of intent with Transocean Inc. (“Transocean”) for the purchase of all of certain Transocean subsidiaries owning 10 jack-up rigs and the rights under five newbuilding contracts (the “Transocean Transaction”). On May 31, 2017, we completed the Transocean Transaction for a total price of $1,240.5 million. Three of the jack-up rigs we acquired, “Idun,” “Mist” and “Odin,” were, at the time, employed with Chevron for operations in Thailand. Transocean, as the seller, retained the revenue, expenses and cash flow associated with the three rigs under contract upon closing of the Transocean Transaction. Two of the jack-up rigs we acquired are currently employed with drilling contracts. Since the acquisition closed, two of the rigs under the newbuilding contracts have been delivered, “Saga” and “Skald,” and an additional three are scheduled to be delivered in 2020. Of the rigs initially delivered at closing, four were standard jack-up rigs and six were premium jack-up rigs. Since the closing of the Transocean Transaction, we have divested three of the standard jack-up rigs and entered into a sale agreement to sell the fourth standard jack-up rig as there was no economic incentive to reactivate these rigs.

Acquisition from PPL

On October 6, 2017, we entered into a master agreement with PPL for the acquisition of the PPL Rigs. The consideration in the transaction with PPL (the “PPL Acquisition”) was $1.3 billion. All of the PPL Rigs have been delivered to us as of the date hereof.

Acquisition of Paragon

Paragon Offshore Limited (“Paragon”) was incorporated on July 18, 2017 as part of the financial restructuring of its predecessor, Paragon Offshore plc, who commenced proceedings under chapter 11 of the U.S. Bankruptcy Code on February 14, 2016. On March 29, 2018, we concluded the Paragon Transaction, subsequently acquiring the majority of the remaining shares in July 2018. At the closing of the Paragon Transaction, Paragon owned two premium jack-up rigs, 20 standard jack-up rigs (built before 2001) and one semi-submersible rig (built in 1979) (the “Paragon Rigs”). The Paragon Transaction provided us with a solid operational platform which matches the quality of our jack-up fleet. Paragon’s five-year track record has helped position us to win tenders from key E&P Companies. As part of the acquisition, Paragon became a subsidiary of Borr Drilling. Subsequent to the acquisition, we divested 17 standard jack-up rigs acquired in the Paragon Transaction as there was no economic incentive to reactivate these rigs.

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Acquisition from Keppel

On May 16, 2018, we entered into an agreement to acquire five premium jack-up rigs, three completed and two under construction from Keppel (the “Keppel Acquisition”). The purchase price for the Keppel Rigs was $742.5 million. As part of the transaction, we agreed with Keppel to delay the delivery of one of the newbuild jack-up rigs acquired in the Transocean Transaction, “Tivar,” by 15 months to July 2020.

Acquisition of Keppel’s Hull B378

In March 2019, we entered into an assignment agreement with BOTL Lease Co. Ltd. (the “Original Owner”) for the assignment of the rights and obligations under a construction contract to take delivery of one KFELS Super B Bigfoot premium jack-up rig identified as Keppel’s Hull No. B378 from Keppel for a purchase price of $122.1 million. The construction contract was, at the same time, novated to our subsidiary, Borr Jack-Up XXXII Inc., and amended. We took delivery of the jack-up rig on May 9, 2019 and the rig was subsequently renamed “Thor.”

To finance the rig purchase we entered into a $120.0 million senior secured term loan facilities agreement, consisting of two facilities (Facility A and Facility B) of $60.0 million each, which we refer to as our Bridge Facility. The facilities had a maturity date of September 30, 2019. Following the signing of our Hayfin Facility, Syndicated Facility and New Bridge Facility agreements on June 25, 2019, which collectively provided $645 million in financing, we paid the outstanding balance due under our Bridge Facility, which was subsequently cancelled.

Divestments

Although we do not actively market our jack-up rigs, from time to time we may consider opportunities to sell our standard jack-up rigs if it can be achieved in a manner in which such jack-up rigs are contractually obligated to leave the jack-up drilling market, thereby decreasing the worldwide supply of jack-up rigs available for contract. In 2018, we divested 18 jack-up rigs for total proceeds of $37.6 million and recorded a gain of $18.8 million. In May 2019, we entered into sale agreements for the sale of the “Eir,” “Baug” and “Paragon C20051,” none of which were operating or on contract, for cash consideration of $3.0 million each. The jack-up rigs have been sold with a contractual obligation not to be used for drilling purposes and so retired from the international jack-up fleet. The sales of “Baug” and “Paragon C20051” were completed in May 2019 for cash consideration of $6.0 million and the sale of “Eir” is expected to be completed by the end of the first quarter of 2020, subject to certain conditions precedent. These divestments bring the total number of jack-up rigs divested by us and retired from the international jack-up fleet to 20 since the beginning of 2018.

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The following chart sets forth an overview of the acquisitions and dispositions we have made since our formation:

ACQUISITIONS AND DISPOSITIONS SINCE OUR FORMATION
Acquisition / Disposition	Closing Date	Description of Transaction	Transaction Value (in $ millions)		Rigs Subsequently Divested
Hercules Acquisition	January 23, 2017	Acquisition of two premium jack-up rigs	$	130.0	—
Transocean Transaction	May 31, 2017	Acquisition of 10 jack-up rigs and novation of contracts in respect of five newbuild premium jack-up rigs(1)	$	1,240.5	3 standard jack-up rigs
PPL Acquisition	October 6, 2017	Acquisition of nine newbuild premium jack-up rigs(2)	$	1,300.0	—
Paragon Transaction	March 29, 2018	Acquisition of 22 jack-up rigs and one semi-submersible(3)	$	241.3	17 standard jack-up rigs
Keppel Acquisition	May 16, 2018	Acquisition of five newbuild premium jack-up rigs(4)	$	742.5	—
Keppel Hull B378 (“Thor”) Acquisition	March 29, 2019	Acquisition of one newbuild premium jack-up rig	$	122.1	—

(1) Two jack-up rigs were delivered in January and June 2018, respectively. Three jack-up rigs are due to be delivered in 2020. Six premium jack-up rigs and two standard jack-up rigs remain from the Transocean Transaction.

(2) All jack-up rigs acquired in the PPL Acquisition have been delivered.

(3) Two premium jack-up rigs, four standard jack-up rigs and our semi-submersible rig remain from the Paragon Transaction.

(4) All five jack-up rigs are due to be delivered no later than the end of 2020.

OUR COMPETITIVE STRENGTHS

We believe that our competitive strengths include:

One of the youngest and largest offshore drilling contractors

We have one of the youngest and largest fleets in the jack-up drilling market. The majority of our rigs were built after 2013 and, as of June 30, 2019, the average age of our premium fleet (excluding our four standard jack-up rigs, our semi-submersible rig and newbuilds not yet delivered) is 4.2 years and of our entire fleet (excluding newbuilds not yet delivered) is 9.7 years (implying an average building year of 2010), respectively, which we believe is among the lowest average fleet age in the industry. New and modern rigs that offer technically capable, operationally flexible, safe and reliable contracting are increasingly preferred by customers. We expect to compete for and secure new drilling contracts from new tenders as well as privately negotiated transactions, which we estimate represent approximately half of new contract opportunities. We believe, based on our young fleet and growing operational track record, that we will be better placed to secure new drilling contracts as offshore drilling demand rises than our competitors who operate older, less modern fleets.

Largely uniform and modern fleet with available capacity to expand customer base

Because our fleet is one of the youngest and largest and the drilling equipment on, and operating capability of, our jack-up rigs is largely uniform, we have the capacity to bid for multiple contracts simultaneously, including those requiring active employment of multiple rigs over the same period, as in the case of our operations for Pemex in Mexico. We have acquired (including newbuilds not yet delivered) a fleet of largely premium jack-up rigs from shipyards with a reputation for quality and reliability. Moreover, due to the uniformity of the jack-up rigs in our fleet, we have been able to achieve operational and administrative efficiencies.

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We have activated a number of our jack-up rigs since late 2018 based on firm contract opportunities, which we believe confirms our expectation that industry conditions in the jack-up drilling market will continue to improve. We believe that we are well-placed to capitalize on these improving trends as we seek to establish ourselves as one of the preferred providers in the industry. As of June 30, 2019, we have 11 rigs warm stacked and available for contracting as well as an additional eight jack-up rigs under construction which are also available for contracting.

Commitment to safety and the environment

We are focused on developing a strong QHSE culture and performance history. We believe that the combination of quality jack-up rigs and experienced and skilled employees contributes to the safety and effectiveness of our operations. Since the 2010 Deepwater Horizon Incident (as defined below) (to which we were not a party), there has been an increased focus on offshore drilling QHSE issues by regulators as well as by the industry. As a result, E&P Companies have imposed increasingly stringent QHSE rules on their contractors, especially when working on challenging wells and operations where the QHSE risks are higher. Our commitment to strong QHSE culture and performance is reflected in our Technical Utilization rate in 2018, of 99.3% in 2018 and 99.0% for the six months ended June 30, 2019, and our excellent safety record in the same period. We believe our focus on providing safe and efficient drilling services will enhance our growth prospects as we work toward becoming one of the preferred providers in the industry.

Strong and diverse customer relationships

We have strong relationships with our customers rooted in our employees’ expertise, reputation and history in the offshore drilling industry, as well as our growing operational track record and the quality of our fleet. Our customers are oil and gas exploration and production companies, including integrated oil companies, state-owned national oil companies and independent oil and gas companies. For the year ended December 31, 2018, our five largest customers in terms of revenue were NDC, TAQA, BW Energy, Spirit Energy and Total. We believe that we are responsive and flexible in addressing our customers’ specific needs and seek collaborative solutions to achieve customer objectives. We focus on strong operational performance and close alignment with our customers’ interests, which we believe provides us with a competitive advantage and will contribute to contracting success and rig utilization.

Management team and Board members with extensive experience in the drilling industry

Our executive management team and Board have extensive experience in the oil and gas industry in general and in the drilling industry in particular. In addition, the members of our executive management team are knowledgeable operating and financial executives with extensive experience with companies operating in the jack-up drilling market. The members of our executive management team and Board have held and currently hold leadership positions at prominent offshore drilling and oilfield services companies, including Schlumberger Limited, Marine Drilling Companies, Inc., Seadrill Limited, North Atlantic Drilling Ltd., TODCO and Archer Limited, and have relationships which complement one another and have assisted, and continue to assist, in our development.

Effective acquisition history

We acquired our jack-up rigs at what we believe are historically attractive prices, including through four major acquisitions since early 2017. The average purchase price of our rigs is significantly lower than the historical construction cost of comparable rigs. We acquired our jack-up rigs at a substantial discount to their cost when originally ordered. We have acquired the majority of our newbuild jack-up rigs by raising equity in the financial markets and by entering into delivery financing arrangements provided by the shipyards. In contrast to many of our competitors who built and owned their fleet prior to 2014, we entered the jack-up drilling market at what we believe to be an attractive price point. Although we have incurred net losses as we commence operations, we believe we are well placed, with a young and modern fleet, to capitalize on any upturn in the jack-up drilling market.

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OUR BUSINESS STRATEGIES

Through our premium jack-up rigs, we intend to meet our primary business objective of becoming a preferred operator in the jack-up drilling market while also maximizing return to our shareholders. To achieve this, our strategies include the following:

Deploy high-quality rigs to service a growing industry

We have acquired one of the leading jack-up fleets in the industry with capacity to service existing and future client needs. Tender activity in the jack-up drilling market has been increasing sharply since the second quarter of 2018, which we believe indicates the industry is recovering from the challenges it has faced over the last five years. We believe that shallow-water drilling, such as that performed by our jack-up rigs, has a shorter lifecycle between exploration and first oil and lower capital expenditure than other forms of drilling performed by mobile offshore drilling units, such as drillships. We believe this makes shallow-water drilling more attractive than deep-water projects in the current economic and industry climates. Major E&P Companies have experienced falling production coupled with rising cash flows since late 2016 and as a result of these factors, we anticipate an increase in shallow-water drilling among E&P and other companies. In addition to tender activity in which we participate through bidding, we also compete for new contract opportunities through privately negotiated transactions, including private tenders and direct negotiations with customers, which we estimate represent approximately half of new contract opportunities. We believe our footprint in the industry is growing. Between April 1, 2018, and June 30, 2019, we signed 15 new contracts for drilling services with an aggregate value of approximately $439 million, including nine with new customers. During this period, we also signed two extensions and have had four options exercised. As of June 30, 2019, 16 of our 26 rigs are under contract (including our semi-submersible rig).

Become a preferred provider in the industry

We have established strong and long-term relationships with key participants and customers in the offshore drilling industry, including through our acquisition of Paragon Offshore Limited, the hiring of experienced personnel and contracts signed since our inception, and we will seek to deepen and strengthen these relationships as part of our strategy. This involves identifying value add services for our customers (such as integrated well contracts) and, to this end, we have signed a non-exclusive Collaboration Agreement with Schlumberger to offer such services. For more information on our relationship with Schlumberger, please see the section entitled “Certain Relationships and Related Party Transactions.” We also plan to continue to hire employees with long track-records in the industry and extensive contacts with potential key customers to further improve customer relationships. Based on our largely premium and uniform fleet, our experienced team and a solid industry network, we believe that we are well-positioned to capitalize on improving trends as we seek to establish ourselves as a preferred provider to these customers.

Establish high-quality, cost-efficient operations

We intend to be a leading offshore shallow-water drilling company by operating with a competitive cost base while continuing to grow our reputation as a high quality contractor. Our key objective is to deliver the best operations possible—both in terms of Technical Utilization and QHSE culture and performance—while also maximizing deployment of our rigs and maintaining a competitive cost structure.

To facilitate our strategy, we have acquired one of the most modern and uniform fleets in the industry, with experienced and skilled individuals across the organization and on our Board. We expect to have an advantage not only with regard to operating expenditures as a result of our largely standardized fleet, but also with regard to financing costs when compared to many of our industry peers.

Establish and offer integrated services

We are planning to offer integrated drilling/well services together with Schlumberger and have been tendering our services on this basis for some contract tenders. Integrated drilling services offer all services and equipment (and in some cases, material procurement) in a single contract. We believe this model is more economically feasible and thus attractive for smaller E&P Companies operating offshore, as the model could reduce the number of contracts required for a project from above ten to two or three. Significant cost saving

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potential is evident in the model. As a result, project management could become simpler, cheaper and more efficient for customers with integrated drilling services. Further, this could lead to improved well design, better selection and more efficient operators of rig equipment and technology.

We expect our collaboration with Schlumberger, while not exclusive, will enable us to offer integrated well services by providing a combination of services, technology, equipment and rigs that we expect to yield a significant value proposition. An example is the recent contract awarded to us in Mexico, where we, Schlumberger and local partners will work together to deliver integrated drilling services to Pemex.

Maintain financial discipline

We intend to manage our balance sheet by maintaining a suitable proportion of equity and debt, depending on our contract backlog and market outlook. In the future, we may consider adding leverage against our contract backlog or to finance growth or other accretive activities. We will also aim to distribute dividends to shareholders whenever we have excess cash flows and are permitted to do so under our Financing Arrangements.

OUR FLEET

We believe that we have one of the most modern jack-up fleets in the offshore drilling industry. Our drilling fleet consists of 27 rigs, of which four are standard jack-up rigs, 22 are premium jack-up rigs and one is a semi-submersible rig. In addition, we have agreed to purchase eight additional premium jack-up rigs to be delivered prior to the end of 2020. Premium jack-up rigs means rigs delivered from the yard in 2001 or later and which are suitable for operations in water depths up to 400 feet with an independent leg cantilever design. The majority of our rigs were built after 2013 and as of June 30, 2019, the average age of our premium fleet (excluding our four standard jack-up rigs and our semi-submersible rig) and of our entire fleet (excluding newbuilds not yet delivered) is 4.2 years and 9.7 years, respectively. As of the date of the last expected delivery of the newbuild jack-up rigs we have agreed to purchase, which is in 2020, the average age of our premium fleet (excluding our four standard jack-up rigs and our semi-submersible rig) and of our entire fleet will be 4.3 years and 8.8 years, respectively, which we believe to be among the lowest average fleet age in the industry (both currently and as of the date of our last expected delivery).

Jack-up rigs are mobile, self-elevating drilling platforms equipped with legs that are lowered to the seabed. A jack-up rig is towed to the drill site with its hull riding in the water and its legs raised. At the drill site, the jack-up rig’s legs are lowered until they penetrate the sea bed. Its hull is then elevated (jacked-up) until it is above the surface of the water. After the completion of drilling operations at a drill site, the hull is lowered until it rests on the water and the legs are raised. The rig can then be relocated to another drill site. Jack-up rigs typically operate in shallow water, generally in water depths of less than 400 feet and with crews of 90 to 120 people. We believe a modern fleet allows us to enjoy better utilization and higher daily rates for our jack-up rigs than competitors with older rigs.

As of June 30, 2019, we had 26 total jack-up rigs, of which 11 rigs were “warm stacked,” which means the rigs, including our newbuild jack-up rigs which have been delivered but not yet been activated, are kept ready for redeployment and retain a maintenance crew, and three rigs were “cold stacked,” which means the rigs are stored in a harbor, shipyard or a designated offshore area and the crew is reassigned to an active rig or dismissed. We have entered into an agreement to sell one of our cold stacked jack-up rigs, the “Eir,” and we expect the sale to be completed by the end of the first quarter of 2020, subject to certain conditions. We believe that well-planned and well-managed stacking will significantly reduce reactivation cost and the cost of mobilization of a rig towards a contract. We are therefore focusing on securing cost efficiencies during stacking while limiting future risk from premature reactivation. This means concentrating stacked rigs in as few locations as possible to be able to share crew, running reduced but sufficient maintenance programs on equipment and preserving critical equipment.

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We intend to prioritize the deployment of our currently contracted premium jack-up rigs. Reactivation of our premium jack-up rigs that are stacked will be undertaken for select contract opportunities. However, a stacked rig will only be reactivated if the achievable dayrate supports the reactivation and subsequent operating costs in a sensible way. Between April 1, 2018 and June 30, 2019, we signed 15 new contracts for drilling services, including nine with new customers. Our ability to keep our jack-up rigs operational when under contract, or Technical Utilization, for the year ended December 31, 2018 was 99.3% and for the six months ended June 30, 2019 was 99.0%, and the proportion of the potential full contractual dayrate that each contracted jack-up rig actually earns each day, or Economic Utilization, for the year ended December 31, 2018 was 97.9% and for the six months ended June 30, 2019 was 95.2%.

Each rig in our fleet is certified by ABS, enabling universal recognition of our equipment as qualified for international operations. The key characteristics of our rigs owned but not under contract which may yield differences in their marketability or readiness for use include whether such rigs are warm stacked or cold stacked, age of the rig, geographic location and technical specifications.

The following table sets forth additional information concerning our fleet:

Fleet Status Report
As of May 29, 2019

Rig Name	Rig Design	Rig Water Depth (ft)	Year Built	Customer/ Status	Contract Start	Contract End	Location	Comments
PREMIUM JACK-UP RIGS
Idun	KFELS Super B Bigfoot Class	350 ft	2013	Available			Singapore	Warm Stacked
Galar	PPL Pacific Class 400	400 ft	2017	Available			Singapore	Warm Stacked
Gunnlod	PPL Pacific Class 400	400 ft	2018	Available			Singapore	Warm Stacked
Gyme	PPL Pacific Class 400	400 ft	2018	Available			Singapore	Warm Stacked
Njord	PPL Pacific Class 400	400 ft	2019	Available			Singapore	Warm Stacked
Saga	KFELS Super B Bigfoot Class	400 ft	2018	Available			Singapore	Warm Stacked
Skald	KFELS Super B Bigfoot Class	400 ft	2018	Available			Singapore	Warm Stacked
Thor	KFELS Super B Bigfoot Class	400 ft	2019	Available			Singapore	Warm Stacked
Mist	KFELS Super B Bigfoot Class	350 ft	2013	Available Vestigo Petroleum	March 2019 May 2019	May 2019 November 2019	Singapore Malaysia	Warm Stacked Committed
Gersemi	PPL Pacific Class 400	400 ft	2018	Available Pemex	March 2019 July 2019	June 2019 December 2019	Singapore Mexico	Activation and Mobilization Committed
Grid	PPL Pacific Class 400	400 ft	2018	Available Pemex	March 2019 July 2019	June 2019 December 2019	Singapore Mexico	Activation and Mobilization Committed
Odin	KFELS Super B Bigfoot Class	350 ft	2013	PanAmerican	April 2019	December 2019	Mexico	Operating
Frigg	KFELS Super A	400 ft	2013	Total Shell (via Assignment)	January 2019 June 2019	June 2019 October 2019	Nigeria Nigeria	Operating Committed with option to extend
Prospector 1	F&G, JU2000E	400 ft	2013	Tulip	December 2018	July 2019	Netherlands	Operating with option to extend
Prospector 5	F&G, JU2000E	400 ft	2014	Available Neptune	February 2019 May 2019	May 2019 October 2019	United Kingdom Netherlands	Warm Stacked Operating
Gerd	PPL Pacific Class 400	400 ft	2018	Exxon	April 2019	April 2021	Nigeria	Operating with option to extend
Groa	PPL Pacific Class 400	400 ft	2018	Exxon	May 2019	May 2021	Nigeria	Operating with option to extend
Ran	KFELS Super A	400 ft	2013	Spirit Energy	April 2019	March 2020	United Kingdom	Operating
Norve	PPL Pacific Class 400	400 ft	2011	Available BW Energy Dussafu	April 2019 July 2019	June 2019 April 2020	Gabon/Cameroon Gabon	Warm Stacked Committed
Natt	PPL Pacific Class 400	400 ft	2018	First E&P	April 2019	April 2021	Nigeria	Operating with option to extend

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Rig Name	Rig Design	Rig Water Depth (ft)	Year Built	Customer/ Status	Contract Start	Contract End	Location	Comments
STANDARD JACK-UP RIGS
Dhabi II	Baker Marine BMC-150 ILC	150 ft	1981	NDC (ADOC)	April 2017	July 2019	United Arab Emirates	Operating
B152	Baker Marine BMC-150 ILC	150 ft	1982	NDC (ADOC)	April 2017	November 2019	United Arab Emirates	Operating
B391	Baker Marine Europe Class	250 ft	1981	Spirit Energy	March 2018	December 2019	United Kingdom	Operating with option to extend
SEMI-SUBMERSIBLE
MSS1	Offshore Company (IDC) SCP III M2	1500 ft	1979	TAQA	March 2018	November 2019	United Kingdom	Operating with option to extend
JACK-UP RIGS UNDER CONSTRUCTION/NOT DELIVERED
Hild	KFELS Super B Bigfoot Class	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in October 2019
Heimdal	KFELS Mod V	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in January 2020
Hermod	KFELS Mod V	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in April 2020
Huldra	KFELS Mod V	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in July 2020
Tivar	KFELS Super B Bigfoot Class	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in July 2020
Heidrun	KFELS Mod V	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in October 2020
Vale	KFELS Super B Bigfoot Class	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in October 2020
Var	KFELS Super B Bigfoot Class	400 ft		Under Construction			KFELS shipyard, Singapore	Expected Rig Delivery in December 2020
COLD STACKED JACK-UP RIGS
Atla	F&G, JU 2000	400 ft	2003				United Arab Emirates
Balder	F&G, JU 2000	400 ft	2003				Cameroon
Eir	F&G, Mod VI Universe Class	394 ft	1999				United Kingdom	Not Marketed

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CUSTOMERS AND CONTRACT BACKLOG

Our customers are oil and gas exploration and production companies, including integrated oil companies, state-owned national oil companies and independent oil and gas companies. As of December 31, 2018, our largest customers in terms of revenue were subsidiaries of NDC, TAQA, BW Energy, Spirit Energy and Total. During the first quarter of 2019, our top five customers by revenue were subsidiaries of NDC, TAQA, Perenco, Total and Tulip. We obtain the majority of our contracts through tenders, market surveys and direct approaches to customers.

Several of our jack-up rigs are contracted to customers for periods between a couple to several months and our contracts generally range from three to 24 months. Our Total Contract Backlog (in $ millions) was $383.2 million as of June 30, 2019 and $377.5 million as of December 31, 2018. As included in this Prospectus, Total Contract Backlog is not the same measure as the acquired contract backlog presented in our Consolidated Financial Statements and Interim Financial Statements. Please see Notes 2 and 14 to our Consolidated Financial Statements and Notes 3 and 11 to our Interim Financial Statements for further information.

The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the Total Contract Backlog projections due to various factors. For example, shipyard and maintenance projects, downtime and other factors may result in lower revenues than our average Total Contract Backlog per day. Downtime, caused by unscheduled repairs, maintenance, weather and other operating factors, may result in lower applicable daily rates than the full contractual operating daily rate.

As of June 30, 2019 we had 16 committed jack-up rigs in total, including 13 jack-up rigs in operation (five in the North Sea, two in the Middle East, four in West Africa, one in Southeast Asia and one in North America) and another three premium jack-up rigs contracted. The Technical Utilization and Economic Utilization for our drilling fleet was 99.3% and 97.9% during 2018, respectively and was 99.0%, and 95.2% during the six months ended June 30, 2019, respectively.

Contractual Terms

Our drilling contracts are individually negotiated and vary in their terms and provisions. We obtain most of our drilling contracts through competitive bidding against other contractors and direct negotiations with operators.

Our drilling contracts provide for payment on a dayrate basis, with higher rates for periods while the jack-up rig is operating. A dayrate drilling contract generally extends over a period of time covering either the drilling of a single well or group of wells or covering a stated term. We have historically not provided “turnkey” or other risk-based drilling services to customers. The customer bears substantially all of the ancillary costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well. In addition, dayrate contracts may provide for a lump sum amount or dayrate for mobilizing the rig to the initial operating location, which is usually lower than the contractual dayrate for uptime services, and a reduced dayrate when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control.

Certain of our drilling contracts may be terminated for the convenience of the customer, in some cases upon payment of an early termination fee or compensation for costs incurred up to termination. Any such payments, however, may not fully compensate us for the loss of the contract. Contracts also customarily provide for either automatic termination or termination at the option of the customer, typically without any termination payment, under various circumstances such as non-performance, in the event of extended downtime or impaired performance caused by equipment or operational issues or periods of extended downtime due to other conditions beyond our control. Many of these events are beyond our control.

The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional term. Our contracts also typically include a provision that allows the customer to extend the contract to finish drilling a well-in-progress. During periods of depressed market conditions, our customers may seek to renegotiate firm drilling contracts to reduce the term of their obligations or the average dayrate through term extensions, or may seek to repudiate their contracts. Suspension of drilling contracts will result in the reduction in or loss of dayrate for the period of the

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suspension. If our customers cancel some of our contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our business, financial condition and results of operations.

Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate drilling contracts. Under all of our current drilling contracts, our customers, as the operators, indemnify us for pollution damages in connection with reservoir fluids stemming from operations under the contract and we indemnify the operator for pollution from substances in our control that originate from the rig, such as diesel used onboard the rig or other fluids stored onboard the rig and above the water surface. Also, under all of our current drilling contracts, the operator indemnifies us against damage to the well or reservoir and loss of subsurface oil and gas and the cost of bringing the well under control. However, our drilling contracts are individually negotiated, and the degree of indemnification we receive from the operator against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated. In some instances, we have contractually agreed upon certain limits to our indemnification rights and can be responsible for damages up to a specified maximum dollar amount. The nature of our liability and the prevailing market conditions, among other factors, can influence such contractual terms. In most instances in which we are indemnified for damages to the well, we have the responsibility to redrill the well at a reduced dayrate as the customer’s sole and exclusive remedy if such well damages are due to our negligence. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations.

Although our drilling contracts are the result of negotiations with our customers, our drilling contracts may also contain, among other things, the following commercial terms: (i) payment by us of the operating expenses of the drilling rig, including crew labor and incidental rig supply costs; (ii) provisions entitling us to adjustments of dayrates (or revenue escalation payments) in accordance with published indices, changes in law or otherwise; (iii) provisions requiring us to provide a performance guarantee; and (iv) provisions permitting the assignment to a third party with our prior consent, such consent not to be unreasonably withheld.

JOINT VENTURE, PARTNER AND AGENCY RELATIONSHIPS

In some areas of the world, local content requirements, customs and practice necessitate the formation of joint ventures with local participation. Local laws or customs or customer requirements in some jurisdictions also effectively mandate establishment of a relationship with a local agent or partner. For more information regarding certain local content requirements that may be applicable to our operations from time to time, please see the section entitled “Regulation—Environmental And Other Regulations In The Offshore Drilling Industry—Local Content Requirements.” When appropriate in these jurisdictions, we will enter into agency or other contractual arrangements. We may or may not control these joint ventures. We participate in joint venture drilling operations in Nigeria and Mexico and may participate in additional joint venture drilling operations.

Nigeria

As of December 31, 2018, we participated in one arrangement involving a local partner and our jack-up rig “Frigg,” which is currently operating for Shell in Nigeria in collaboration with our local partner. Our local partner, Valiant Energy Services West Africa (“Valiant”), a Nigerian company, owns a 10% interest in Borr Jack-Up XVI Inc., the owner of our rig “Eir.” In order to comply with applicable local content regulations and pursuant to the approval of the Nigerian Content Development and Monitoring Board it was agreed that Valiant would acquire an equity interest in one of our subsidiaries, Borr Jack-Up XVI Inc., in lieu of acquiring an equity interest in “Frigg” or its rig-owning subsidiary. The non-controlling interest reflected in our Consolidated Financial Statements relates to Valiant’s interest in Borr Jack-Up XVI Inc.

Valiant has the right to acquire additional shares in Borr Jack-Up XVI Inc. up to a maximum shareholding of 50%, however this right expires upon termination of the drilling contract under which our jack-up rig “Frigg” is currently operating and is subject to certain other commercial conditions. In May 2019, we entered into a sale agreement for the sale of the “Eir,” which is expected to be completed by the end of the first quarter of 2020. The sale of “Eir” is subject to certain conditions precedent.

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Mexico

In February 2019, we, along with our local partner in Mexico, CME, successfully tendered for a contract to provide integrated well services to Pemex. On March 20, 2019, our subsidiary, Borr Drilling Mexico S. de R.L. de C.V. (“BDM”), and a CME subsidiary, Opex Perforadora S.A. de C.V. (“Opex” and together with BDM, the “Contractor”), entered into a contract for the provision of integrated well services to Pemex. Borr Drilling Limited guarantees the performance of the Contractor’s obligations under the Pemex Contract and we have nominated our subsidiary, Borr Mexico Ventures Limited (“BMV”), to enter into the joint venture arrangements in connection with the Pemex Contract (the “Mexican JV”). In June 2019, we finalized the Mexican JV structure and with effect from June 28, 2019, BMV owns a 49% interest in both Opex and a second CME subsidiary, Perforaciones Estrategicas e Integrales Mexicana S.A. de C.V. (“Perfomex”). We expect to commence operations under the Pemex Contract in early August 2019.

Opex will act as integrated well services contractor under the Pemex Contract and within the structure of the Mexican JV. Opex will enter into a contract with an affiliate of Schlumberger for the provision of integrated well services. Perfomex is the entity subcontracted by Opex to provide drilling services under the Pemex Contract. In connection with the provision of drilling services by Perfomex, our rigs “Grid” and “Gersemi” will be chartered to Perfomex through bareboat charter agreements. In addition to the rigs, we will provide technical and operational management for all jack-up rigs being operated through the Mexican JV. The Mexican JV may be used to provide integrated well and/or drilling services utilizing other rigs owned by our subsidiaries and/or subsidiaries of CME and, if we enter into further contracts with Pemex to provide integrated well and/or drilling services, we may enter into other joint venture structures with CME in order to provide such services.

GEOGRAPHICAL FOCUS

We bid for contracts globally, however our current geographical focus is on the Middle East, North Sea, West Africa, South East Asia and Gulf of Mexico regions. This is based on our current assessment of potential contracting opportunities, including, pre-tender and tender activity. Several countries within these regions, such as Nigeria, have laws that regulate operations and/or ownership of rigs operating within their jurisdiction, including local content and/or local partner requirements. In order to comply with these regulations, and successfully secure contracts to operate in these regions, we have employed personnel with long experience from securing contracts and operation rigs in countries within these regions. Adapting to the above-mentioned factors is, and will be, part of our business. The percentage of operating revenues earned by each geographical region for the years ended December 31, 2018 and 2017 and the three months ended March 31, 2019 and 2018 was as follows:

	For the Three Months Ended March 31,						For the Year Ended December 31,
	2019			2018			2018			2017(1)
	(in % of Operating revenues)
Middle East		20.2	%		4.7	%		25.0	%		—
North Sea Region		48.9	%		6.6	%		45.3	%		—
West Africa		22.2	%		88.7	%		27.1	%		—
South East Asia		6.7	%		—			2.6	%		—
Other		2.0	%		—			—			—

(1) We have provided no data for the percentage of operating revenues earned by each geographical region identified above for the year ended December 31, 2017 because only one of our jack-up rigs was in operation for approximately one day at the end of December 2017 (in West Africa), with the exception of those jack-up rigs under contract upon closing of the Transocean Transaction for which Transocean, as the seller, retained the associated revenue, expenses and cash flows. See “Business—History and Development—Acquisition from Transocean” for more information.

SUPPLIERS

Our material supply needs include labor agencies, insurance brokers, maintenance providers, shipyard access and drilling equipment.

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Our senior management team has extensive experience in the oil and gas industry in general, and in the offshore drilling industry in particular and has built an extensive industry network. We believe that our relationships with our key suppliers and service providers is critical as it allows us to benefit from economies of scale in the procurement of goods and services and sub-contracting work.

We maintain commercial relationships with certain affiliates of Schlumberger, our principal shareholder and any reduction in such shareholding may reduce our ability to realize certain benefits from our relationship with them. To date, we have been able to obtain the services, equipment, materials and supplies necessary to support our operations on a timely basis. We believe that we will be able to make satisfactory alternative arrangements in the event of any interruption in the supply of these services, equipment and/or materials by any of our suppliers, as we have established alternative vendors for all critical products for our business. In addition, in several of the countries in which we operate, we assisted suppliers in developing manufacturing capability and obtaining original equipment manufacturer certification.

COMPETITION   

The shallow-water offshore contract drilling industry is highly competitive. We compete on a worldwide basis and competition varies by region at any particular time. Our competition ranges from large international companies offering a wide range of drilling and other oilfield services to smaller, locally owned companies. Some of our competitors’ fleets comprise a combination of offshore, onshore, shallow, midwater and deepwater rigs. We seek to differentiate our company from most of our competitors, which have mixed fleets, by exclusively focusing on shallow-water drilling which we believe allows us to optimize our size and scale and achieve operational efficiency.

Drilling contracts are traditionally awarded on a competitive basis, whether through tender or private negotiations. We believe that the principal competitive factors in the markets we serve are pricing, technical capability of service and equipment, condition and age of equipment, rig availability, rig location, safety record, crew quality, operating integrity, reputation, industry standing and customer relations. We have significant equity investment in our jack-up rigs and have built a fleet consisting of premium jack-up rigs with proven design and quality equipment, acquired at what we believe are attractive prices. We believe we have a fleet of high-quality jack-up rigs, which allow us to competitively bid on industry tenders on the basis of the modern technical capability, condition and age of our jack-up rigs. In addition, we believe our focus on QHSE performance will complement our modern fleet, further allowing us to competitively bid for drilling contracts.

SEASONALITY

In general, seasonal factors do not have a significant direct effect on our business. However, we have operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operational utilization of the rigs and our ability to relocate rigs between drilling locations, and as such, limit contract opportunities in the short term. Such adverse weather could occur during, among other times, the winter season in the North Sea and the monsoon season in Southeast Asia.

EMPLOYEES

As of June 30, 2019, we had 664 employees with 528 working offshore and 136 working onshore. In addition, we engaged 944 contractors, of which 884 worked offshore and 60 worked onshore in the first quarter of 2019.

As at December 31, 2018, we had approximately 593 employees with 463 working offshore and 130 working onshore; compared to December 31, 2017 when we had approximately 98 employees with 54 working offshore and 44 working onshore. In addition, we engaged 664 contractors, of which 606 worked offshore and 58 worked onshore in 2018 and 190 contractors, of which 158 worked offshore and 32 worked onshore in 2017. These employees and contractors have extensive technical, operational and management experience in the jack-up segment of the shallow-water offshore drilling industry.

As of June 30, 2019, Borr Drilling Management Dubai has 52 full-time employees. In addition, Paragon Offshore (Land Support) Limited and Paragon Offshore (Nederlands) B.V., in Aberdeen and Beverwijk, have 28 and 10 full-time employees, respectively. In addition, Borr Drilling Eastern Peninsula has five full-time employees. Through our acquisition of Paragon we also obtained a number of employees who have extensive technical, operational and management experience in the jack-up segment of the shallow-water offshore drilling industry.

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Some of our employees and our contracted labor are represented by collective bargaining agreements. As part of the legal obligations in some of these agreements, we are required to contribute certain amounts to retirement funds and pension plans and have restricted ability to dismiss employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance. We consider our relationships with the various unions as stable, productive and professional.

The table below presents our employees and contractors by function as of June 30, 2019:

	Company Employees		Contractors		Total
Rig-based		528		884		1,412
Shore-based		136		60		196
Total		664		944		1,608

We seek to employ national employees and contractors wherever possible in the markets in which our rigs operate. This enables us to strengthen customer and governmental relationships, particularly with NOCs, and results in a more competitive cost base as well as relatively lower employee turnover.

RISK OF LOSS AND INSURANCE

Our operations are subject to hazards inherent in the drilling of oil and gas wells, including blowouts, punch through, loss of control of the well, abnormal drilling conditions, mechanical or technological failures, seabed cratering, fires and pollution, which could cause personal injury, suspend drilling operations, or seriously damage or destroy the equipment involved. 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. Litigation arising from such an event may result in us being named a defendant in lawsuits asserting large claims.

As is customary in the drilling industry, we attempt to mitigate our exposure to some of these risks through indemnification arrangements and insurance policies. We carry insurance coverage for our operations in line with industry practice and our insurance policies provide insurance cover for physical damage to the rigs, loss of income for certain rigs and third-party liability, including:

Physical Damage Insurance: Hull and Machinery Insurance

We purchase hull and machinery insurance for all of our fleet and fleet equipment to cover the risk of physical damage to a rig. The level of coverage for each rig reflects its agreed value when the insurance is placed. We effectively self-insure part of the risk as any claim we make under our insurance will be subject to a deductible. The deductible for each rig reflects the market value of the rig and is currently a weighted average maximum of approximately $1.1 million per claim (with the actual deductible reflecting the rig value).

War Risk Insurance

We maintain war risk insurance for our rigs up to a maximum amount of $500 million per rig depending on the value of the protection and indemnity and hull and machinery insurance policies for each rig and subject to certain coverage limits, deductibles and exclusions. The terms of our war risk policies include a provision whereby underwriters can, upon service of seven days’ prior written notice to the insured, cancel the policies in the event that the insured has or may have breached sanctions. Further, the policies will automatically terminate 30 days after the outbreak of war, or war-like conditions, between two or more of China, the United States of America, the United Kingdom, Russia and France, with the insurers’ liability during the 30-day period being capped at an aggregate value of $1 billion.

Loss of Hire Insurance

We maintain loss of hire insurance for a limited number of our jack-up rigs (currently four jack-up rigs) to cover loss of revenue in the event of extensive downtime caused by physical damage covered by our hull and machinery insurance policies. Provided such downtime continues for more than 45 days, the policies will

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cover an agreed daily rate of hire for such downtime up to a maximum of 180 days, not to exceed 100% of the daily loss of hire for such period. The decision to obtain loss of hire insurance is taken on a case-by-case basis whenever a rig is contracted for drilling operations and the amount covered under a loss of hire policy will depend on, among other things, the duration of the contract, the contract rates and other terms of the relevant drilling contract.

Protection and Indemnity Insurance

We purchase protection and indemnity insurance and excess liability insurance. Our protection and indemnity insurance covers third-party liabilities arising from the operation of our rigs, including personal injury or death (for crew and other third-parties), collisions, damage to fixed and floating objects and statutory liability for oil spills and the release of other forms of pollution, such as bunkers, and wreck removal. The protection and indemnity insurance policies, together with our excess umbrella policy, cover claims up to the maximum of the agreed total claim amount, but not exceeding the maximum of $500 million (for our operational rigs) or $200 million (for our stacked rigs), as applicable, depending on the type of jack-up rig, related contractual obligations and area of operation. The excess umbrella insurance policy referred to above covers an additional $100 million to $300 million per event, in addition to our protection and indemnity insurance policies, as part of our overall combined maximum insurance coverage. If the aggregate value of a claim against one of our rig-owning subsidiaries under a protection and indemnity insurance policy exceeds the maximum of $200 million, the excess umbrella insurance policy will cover an additional agreed amount, including (i) between $200 million for stacked jack-up rigs or (ii) such amount as provides aggregate coverage between $300 million and $500 million for our operational jack-up rigs, as agreed for each individual operating rig. We are self-insured for costs in excess of the overall combined maximum limit of coverage, or $200 million for a stacked rig and the agreed aggregate limit between $300 million and 500 million for an operational rig, as agreed for each individual rig. In addition, the excess insurance policies cover an additional $100 million per claim. If the aggregate value of a claim against one of our subsidiaries under a protection and indemnity insurance policy exceeds $200 million, the excess policy will cover an additional $100 million, meaning that we are self-insured for costs in excess of $300 million. We retain the risk for the deductible of up to $25,000 per claim relating to protection and indemnity insurance or up to $250,000 for claims made in the United States.

We also maintain insurance policies and excess insurance policies against general liability and public liability for onshore statutory and contractual risks, mainly related to employment but also in respect of onshore third-party liabilities. The insured value under each policy is $5 million. We also have a global, aggregate excess policy of $50 million per annum.

Management considers our level of insurance coverage to be appropriate for the risks inherent to our business. The determination of the appropriate level of insurance coverage is made on an individual asset basis taking into account several factors, including the age, market value, cash flow value and replacement value of our jack-up rigs, their location and operational status.

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ORGANIZATIONAL STRUCTURE

A full list of our significant management, operating and rig-owning subsidiaries is shown in Exhibit 22.1 to the registration statement to which this Prospectus forms a part and the following diagram depicts our simplified organizational and ownership structure:

 

* As more fully described herein, our subsidiary Borr Mexico Ventures Limited also holds a 49% interest in two Mexican entities and our local operating partner in Mexico holds the remaining 51% interest.

** 1% of the interest in our Mexican JV subsidiaries is held by Borr Brage Limited, which is wholly owned by Borr Drilling Limited.

*** As more fully described herein, 10% of our subsidiary Borr Jack-up XVI Inc. is held by our local operating partner in Nigeria.

PROPERTY, PLANT AND EQUIPMENT

Our principal executive offices are located at S. E. Pearman Building, 2nd Floor, 9 Par-la-Ville Road, Hamilton HM11, Bermuda. The operational headquarters of Borr Drilling Management DMCC in Dubai in the United Arab Emirates and our other offices, including in Singapore, Aberdeen and London in the United Kingdom, Beverwijk in the Netherlands, Abu Dhabi in the United Arab Emirates, Port Gentile in Gabon, Port Harcourt in Nigeria and Bangkok in Thailand, are leased.

We own a substantially modern fleet of jack-up rigs. See “—Our Fleet” for a table setting forth the jack-up rigs that we own or are under construction as of May 29, 2019. Available jack-up rigs include rigs that may be cold or warm stacked or held for sale.

LEGAL PROCEEDINGS

We are from time to time 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 jack-up rigs. Risks associated with litigation include potential negative outcomes, the costs associated with asserting our claims or defending such lawsuits, and the diversion of management’s attention to these matters. We may also be subject to significant legal costs in defending these actions, which we may or may not be able to recoup depending on the results of such claim.

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REGULATION

We are an international company that is registered under the laws of Bermuda. Our principal executive offices are located in Bermuda and the operational headquarters of Borr Drilling Management Dubai are located in the United Arab Emirates, while we have business operations in various countries and regions around the world where our rigs and services are available for contract. As a result of this organizational structure and the scope of our operations, we are subject to a variety of laws in different countries, including those related to the environment, health and safety, personal privacy and data protection, content restrictions, telecommunications, intellectual property, advertising and marketing, labor, foreign exchange, competition and taxation. These laws and regulations are constantly evolving and may be interpreted, implemented or amended in a manner that could harm our business. It also is likely that if our business grows and evolves and our rigs and services are used more globally, we will become subject to laws and regulations in additional jurisdictions. This section sets forth the summary of material laws and regulations relevant to our business operations.

ENVIRONMENTAL AND OTHER REGULATIONS IN THE OFFSHORE DRILLING INDUSTRY

Our operations are subject to numerous QHSE laws and regulations in the form of international treaties and maritime regimes, flag state requirements, national environmental laws and regulations, navigation and operating permits requirements, local content requirements, and other national, state and local laws and regulations in force in the jurisdictions in which our jack-up rigs operate or are registered, which can significantly affect the ownership and operation of our jack-up rigs. See the section entitled “Risk Factors—Risk Factors Related to Applicable Laws and Regulations—We are subject to complex environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.”

Class and Flag State Requirements

All of our jack-up rigs are subject to regulatory requirements of the flag state where the rig is registered.

Flag state requirements reflect international maritime requirements and are in some cases further interpolated by the flag state itself. These include engineering, safety and other requirements related to offshore industries, generally. In addition, in order to operate, each of our jack-up rigs must be certified by a classification society as being “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 to which that country is a party. Maintenance of class certification requires expenditure of substantial sums and can require taking a jack-up rig out of service from time to time for repairs or modifications to meet class requirements. Our jack-up rigs are certified as being “in-class” by the ABS and comply with the mandatory requirements of the national authorities in the countries in which our jack-up rigs operate. In addition, for some of the internationally required class certifications, such as the Code for the Construction and Equipment of Mobile Offshore Drilling Units certificate, the classification society will act on a flag state’s behalf.

International Maritime Regimes

Applicable international maritime regime requirements include, but are not limited to, the International Convention for the Prevention of Pollution from Ships, the International Convention on Civil Liability for Oil Pollution Damage of 1969, the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008), the International Convention for the Safety of Life at Sea of 1974, the Code for the Construction and Equipment of Mobile Offshore Drilling Units, 2009 and the BWM Convention. These conventions have been widely adopted by U.N. member countries, and in some jurisdictions in which we operate, these regulations have been expanded upon. These various conventions regulate air emissions and other discharges to the environment from our jack-up rigs 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.

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

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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, Annex VI regulations impose progressively stricter limitations on sulfur emissions from ships. Since January 1, 2015, these limitations have required that fuels of vessels in covered ECAs, including the Baltic Sea, North Sea, North America and United States Caribbean Sea ECAs, contain no more than 0.1% sulfur. For non-ECA areas, the capped sulfur limitations decrease progressively until they reach the global limit of 0.5% that applies on and after January 1, 2020. Annex VI also establishes 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 jack-up rigs with a ballast water capacity of 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 of our jack-up rigs considered in operational status are in full compliance with the staged implementation of the BWM Convention by IMO guidelines.

Environmental Laws and Regulations

Applicable environmental laws and regulations include the U.S. Oil Pollution Act of 1990, the Comprehensive Environmental Response, Compensation and Liability Act, the U.S. Clean Water Act, the U.S. Clean Air Act, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, the Basel Convention, the Hong Kong International Convention for the Safe and Environmentally Sound Recycling of Ships, 2009, European Union regulations, including the E.U. Directive 2013/30 on the Safety of Offshore Oil and Gas Operations, Regulation (EC) No 1013/2006 on Shipments of Waste and Regulation (E.U.) No 1257/2013 on Ship Recycling 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 jack-up rigs may subject us to increased costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations and financial condition.

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 Macondo well blowout situation that led to the 2010 Deepwater Horizon Incident (to which we were not a party). 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, 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 blowout 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 May 2019, BSEE revised the 2016 rule to correct errors and reduce regulatory burdens determined to be unnecessary. The requirements of these regulations 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, 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 the launch of a pilot risk-based inspection

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program for offshore facilities. New requirements resulting from the program may cause us to incur costs and may result in additional downtime for our jack-up rigs in the U.S. Gulf of Mexico. Also, if material spill events similar to the 2010 Deepwater Horizon Incident (to which we were not a party) 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 E.U. has also undertaken a significant revision of its safety requirements for offshore oil and gas activity through the issuance of the E.U. 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 operations within the country 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, including in Nigeria. 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. In addition, national oil companies may impose restrictions on the submission of tenders, including eligibility criteria, which effectively require the use of domestically supplied goods and services or a local partner. In connection with our tender for the Pemex Contract and subsequent execution thereof, we were subject to eligibility criteria. These practices may adversely affect our ability to compete in those regions. Although these requirements have not had a material impact on our operations in the past, they could have a material impact on our earnings, operations and financial condition in the future.

Data Protection Laws and Regulations

We are subject to rules and regulations governing data protection including the General Data Protection Regulation (EU) 2016/679, repealing the 1995 European Data Protection Directive (Directive 95/46/EC) (the “GDPR”). Data protection legislation, including the GDPR, regulates the manner in which we may hold and communicate personal data of our employees and third parties.

The companies within our Group which are employers are “data controllers” for the purposes of the GDPR, meaning that they are required to ensure that personal data collected from our employees is safely stored, that its accuracy is maintained (meaning that inaccurate data is corrected) and that personal data is only stored for as long as necessary further to the purpose for which it was collected. With respect to transfers of our employees’ personal data that is subject to the GDPR, whether externally to third parties or internally within our Group, the GDPR requires that we establish safeguards to ensure that personal date is safely transferred and that the rights of the data subject are respected and upheld.

The companies within our Group which communicate with third parties, in connection with contracts or otherwise, may be “data controllers” or “data processors” for the purposes of the GDPR and are required to handle any personal data received from third parties in accordance with the provisions of the GDPR.

The GDPR applies primarily to our companies in Europe but may also apply to other companies in the Group to the extent that their business involves personal data of persons within the E.U. Noncompliance with the GDPR can lead to the imposition of fines, currently up to a maximum of the greater of €20 million and 4% of our global turnover, as well as an obligation to compensate the relevant individual for financial or non-financial damages claimed under Article 82 of the GDPR. A breach of the GDPR (or other applicable data protection legislation) could have a material adverse effect on our business, financial condition and results of operations.

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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, jack-up rigs and equipment, currency conversions and repatriation, oil and gas exploration and development, taxation of offshore earnings, taxation of the earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of our rigs 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.

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MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth information regarding our directors and executive officers.

Directors and Executive Officers	Age	Position/Title
Tor Olav Trøim	56	Director and Chairman of the Board
Fredrik Halvorsen	45	Director
Jan A. Rask	64	Director
Patrick Schorn	51	Director
Kate Blankenship	54	Director
Georgina Sousa	69	Director and Company Secretary
Svend Anton Maier	55	Chief Executive Officer, Borr Drilling Management DMCC
Rune Magnus Lundetræ	42	Chief Financial Officer and Deputy CEO, Borr Drilling Management DMCC

The business address of the directors and officers is S. E. Pearman Building, 2^nd Floor, 9 Par-la-Ville Road, Hamilton HM11, Bermuda.

Biographies

Certain biographical information about each of our directors, executive officers and key officers is set forth below:

Tor Olav Trøim has served as a Director on our Board since our incorporation and was our founder. He became the Chairman of the Board on August 30, 2017. Mr. Trøim is the founder and sole shareholder of Magni Partners. He is the senior partner (and an employee) of Magni Partners’ subsidiary, Magni Partners Limited, in the U.K. Mr. Trøim is a beneficiary of the Drew Trust, the sole shareholder of Drew. Mr. Trøim has 30 years of experience in energy related industries in various positions. Before founding Magni Partners in 2014, Mr. Trøim was a director of Seatankers Management Co. Ltd. from 1995 until September 2014. He was the Chief Executive Officer of DNO AS from 1992 to 1995 and an Equity Portfolio Manager with Storebrand ASA from 1987 to 1990. Mr. Trøim graduated with an MSc degree in naval architecture from the University of Trondheim, Norway in 1985. Mr. Trøim is a Norwegian citizen and a resident of the U.K.

Current directorship and senior management positions include:	•	Magni Partners (Bermuda) Limited (Founding Partner);
	•	Golar LNG Limited (Chairman);
	•	Golar LNG Partners LP (Chairman);
	•	Golar LNG Energy Limited (Chairman);
	•	Stolt-Nielsen SA. (Director);
	•	Vålerenga Football AS (Director); and
	•	Magni Sports AS

Fredrik Halvorsen has served as a Director on our Board since December 12, 2016. Mr. Halvorsen founded Ubon Partners AS, a private investment company focused on technology and growth companies. He was the founder and Chairman of Acano until its sale to Cisco Systems Inc. in 2016 and earlier in his career the CEO of Tandberg until it was acquired by Cisco Systems Inc. in 2010. He worked for Frontline Corporate Services Ltd from October 2010 until July 2013 and in this capacity acted as transitional CEO and President of Seadrill Management UK Limited from January to July 2013. In addition, Mr. Halvorsen has held senior positions at Cisco Systems Inc. as well as McKinsey & Company and served as a director of Golar LNG Limited until September 2018. Mr. Halvorsen graduated from the Norwegian School of Business Economics in 1997. Mr. Halvorsen is a Norwegian citizen and a resident of Oslo, Norway.

Current directorship and senior management positions include:	•	Jazz Networks Ltd. (Chairman); and
	•	Ubon Partner AS (Founder and Partner).

Jan A. Rask has served as a Director on our Board since August 30, 2017. Mr. Rask has worked in the shipping and oil service industries for approximately 30 years and has held a number of positions of

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responsibility in finance, chartering and operations. Mr. Rask possesses particular knowledge of and experience in the offshore drilling industry. Mr. Rask also has extensive knowledge of international operations, leadership of complex organizations and other aspects of operating a major corporation. He has held a number of executive positions including president, CEO and Director of TODCO, Managing Director, Acquisitions and Special Projects, of Pride International, President, CEO and director of Marine Drilling Companies, Inc. and President and CEO of Arethusa (Off-Shore) Limited. Mr. Rask holds a Bachelor degree from Stockholm School of Economics and Business Administration. Mr. Rask is a U.S. citizen and resident.

Current directorship and senior management positions include: • Helix Energy Solutions Inc. (Director).

Patrick Schorn has served as a Director on our Board since January 10, 2018. Mr. Schorn is the Executive Vice President of Wells for Schlumberger Limited. Prior to his current role, he held various global management positions including President of Operations for Schlumberger Limited, President Production Group, President of Well Services, President of Completions and GeoMarket Manager Russia. He began his career with Schlumberger Limited in 1991 as a Stimulation Engineer in Europe and held various management and engineering positions in France, United States, Russia, U.S. Gulf of Mexico and Latin America. Mr. Schorn holds a Bachelor of Science degree in Oil and Gas Technology from the University “Noorder Haaks” in Den Helder, the Netherlands. Mr. Schorn is a Dutch citizen and a resident of the U.K.

Current directorship and senior management positions include:	•	Schlumberger Limited (Executive Vice President, Wells); and
	•	OneLNG (Director).

Kate Blankenship has served as a Director on our Board and our sole Audit Committee member since February 26, 2019. Mrs. Blankenship is a member of the Institute of Chartered Accountants in England and Wales and graduated from the University of Birmingham with a Bachelor of Commerce in 1986. Mrs. Blankenship joined Frontline Ltd in 1994 and served as its Chief Accounting Officer and Company Secretary until October 2005. Among other positions, she has served on the board of numerous companies, including as director and audit committee Chairperson of North Atlantic Drilling Ltd. from 2011 to 2018, Archer Limited from 2007 to 2018, Golden Ocean Group Limited from 2004 to 2018, Frontline Ltd. from August 2003 to 2018, Avance Gas Holding Limited from 2013 to 2018, Ship Finance International Limited from October 2003 to 2018, Golar LNG Limited from 2003 to 2015, Golar LNG Partners LP from 2007 to 2015, Seadrill Limited from 2005 to 2018 and Seadrill Partners LLC from 2012 to 2018. Mrs. Blankenship is a U.K. citizen and resident.

Current directorship and senior management positions include:	•	2020 Bulkers Ltd. (Director and audit committee Chairperson);
	•	Cool Company Ltd (Director); and
	•	Diamond S Shipping Inc (Director and audit committee Chairperson).

Georgina Sousa has served as a Director on our Board and our Company Secretary since February 27, 2019. Ms. Sousa was employed by Frontline Ltd. as Head of Corporate Administration from February 2007 until December 2018. She previously served as a director of Frontline from April 2013 until December 2018, Ship Finance International Limited from May 2015 until September 2016, North Atlantic Drilling Ltd. from September 2013 until June 2018, Sevan Drilling Limited from August 2016 until June 2018, Northern Drilling Ltd. from March 2017 until December 2018 and FLEX LNG LTD. from June 2017 until December 2018. Ms. Sousa also served as a Director of Seadrill Limited from November 2015 until July 2018, Knightsbridge Shipping Limited (the predecessor of Golden Ocean Group Limited) from 2005 until 2015 and Golar LNG Limited from 2013 until 2015. Ms. Sousa served as Secretary for all of the abovementioned companies at various times during the period between 2005 and 2018. She served as secretary of Archer Limited from 2011 until December 2018 and Seadrill Partners LLC from 2012 until 2017. Until January 2007, she was Vice-President 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 Ms. Sousa was employed by the Bermuda law firm of Appleby, Spurling & Kempe as company secretary and from 1982 to 1993 she was employed by the Bermuda law firm of Cox & Wilkinson as senior company secretary. Ms. Sousa is a U.K. citizen and a resident of Bermuda.

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Current directorship and senior management positions include: • 2020 Bulkers Ltd. (Director and Secretary).

Svend Anton Maier joined Borr Drilling Management AS (Oslo) on December 19, 2016. He transferred to the employment of Borr Drilling Management Dubai on August 1, 2017. He served as our chief operating officer until March 22, 2018 when he was appointed as our chief executive officer from the same date. Mr. Maier has more than three decades of experience within the oil and gas industry. He worked for Seadrill Limited serving as its Senior Vice President for Africa and the Middle East between 2007 and 2016. Prior to this, Mr. Maier worked for leading drilling companies such as Transocean and Ross Offshore. He holds a degree in Marine Engineering from Tønsberg Maritime Academy. Mr. Maier is a Norwegian citizen and a resident of the United Arab Emirates.

Current directorship and senior management positions include: • Prosafe SE (Director).

Rune Magnus Lundetræ joined Borr Drilling Management AS (Oslo) on December 19, 2016. He served as our chief executive officer until July 31, 2017. With effect from August 1, 2017 he was appointed as our deputy chief executive officer and chief financial officer. Before joining Borr Drilling Management AS (Oslo), Mr. Lundetræ worked as a Managing Director of DNB Markets, Inc from 2015 until 2016. He previously worked at Seadrill Limited for eight years, serving as its chief financial officer from 2012 to 2015. Mr. Lundetræ holds an MSc of Accounting and Finance from the Norwegian School of Business and Economics (NHH) and London School of Economics. Mr. Lundetræ is a Norwegian citizen and a resident of the United Arab Emirates.

Current directorship and senior management positions include:	•	Primato AS (Chairman);
	•	Primato Eiendom AS (Chairman);
	•	Steinkargt 24 AS (Chairman);
	•	Terrebrune AS (Chairman);
	•	Øvre Holmegate 34 AS (Chairman); and
	•	Montaag AS (Chairman).

BOARD OF DIRECTORS & BOARD PRACTICES

Our Board consists of six directors. A director is not required to hold any shares in our company by way of qualification. A director who is in any way, whether directly or indirectly, interested in a contract or proposed contract with our company is required to declare the nature of his interest at a meeting of our directors. A director may vote in respect of any contract, proposed contract, or arrangement notwithstanding that he or she may be interested therein, and if he or she does so, their vote shall be counted and may be counted in the quorum at any meeting of our directors at which any such contract or proposed contract or arrangement is considered. The directors may exercise all of our powers to borrow money, mortgage our undertaking, property and uncalled capital, and issue debentures or other securities whenever money is borrowed or as security for any of our obligations or of any third party.

Our Board is elected annually by a vote of a majority of the common shares represented at the meeting at which at least two shareholders, present in person or by proxy, and entitled to vote (whatever the number of shares held by them) constitutes a quorum. In addition, the maximum and minimum number of directors is determined by a resolution of our shareholders, but no less than two directors shall serve at any given time. Each director shall hold office until the next annual general meeting following his or her election or until his or her successor is elected.

There are no service contracts between us and any member of our Board providing for the accrual of benefits, compensation or otherwise, upon termination of their employment or service.

Our Board has determined that a majority of our directors are considered independent under the NYSE independence standards.

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Board Committees & Corporate Governance

Under an exception to the NYSE listing standards available to foreign private issuers, we are not required to comply with all of the corporate governance practices followed by U.S. companies under the NYSE listing standards. Under Section 303A.11 of the NYSE Listed Company Manual, we are required to list the significant differences between our corporate governance practices and the NYSE standards applicable to listed U.S. companies. Set forth below is a list of those differences.

Independence of directors

The NYSE requires that a U.S. listed company maintain a majority of independent directors. As permitted under Bermuda law and our articles, upon the completion of this Offering, a majority of the members of our Board will be independent according to the NYSE’s standards for independence.

Audit committee

The NYSE requires, among other things, that a listed U.S. company have an audit committee with a minimum of three members all of whom must be independent. As a foreign private issuer, we are exempt from certain rules of the NYSE and are permitted to follow home country practice in lieu of the relevant provisions of the NYSE Listed Company Manual. Consistent with our status as a foreign private issuer and the jurisdiction of our incorporation (Bermuda), our audit committee currently consists of one member, Mrs. Blankenship, who will be independent under the NYSE listing standards and U.S. securities laws relating to audit committees. Under our audit committee charter, the audit committee is responsible for overseeing the quality and integrity of our Consolidated Financial Statements and our accounting, auditing and financial reporting practices; reviewing, evaluating and advising the Board concerning the adequacy of our accounting systems and maintenance of our books and records and our internal controls; our compliance with legal and regulatory requirements; the independent auditor’s qualifications, independence and performance; and our internal audit function.

Compensation committee

The NYSE requires that a listed U.S. company have a compensation committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. Consistent with our status as a foreign private issuer and the jurisdiction of our incorporation (Bermuda), we have established a compensation committee and the members are currently Mrs. Blankenship and Mr. Shorn, both of whom are independent directors. The compensation committee is responsible for establishing general compensation guidelines and policies for executive employees. The compensation committee determines the compensation and other terms of employment for executive employees (including salary, bonus, equity participation, benefits and severance terms) and reviews, from time to time, our compensation strategy and compensation levels in order to ensure we are able to attract, retain and motivate executives and other employees. The compensation committee is also responsible for approving any equity incentive plans or arrangements and any guidelines or policies for the grant of equity incentives thereunder to our employees. It oversees and periodically reviews all annual bonuses, long-term incentive plans, stock options, employee pension and welfare benefit plans and also reviews and makes recommendations to the Board regarding the compensation of directors for their services to the Board.

Nominating and governance committee

The NYSE requires that a listed U.S. company have a nominating/corporate governance committee of independent directors and a committee charter specifying the purpose, duties and evaluation procedures of the committee. We have established a nominating and corporate governance committee comprised of Mr. Rask and Mr. Halvorsen, both of whom are independent directors according to the NYSE’s standards for independence. The nominating and governance committee is appointed by the Board to assist the Board in (i) identifying individuals qualified to become members of the Board, consistent with criteria approved by the Board, (ii) recommending to the Board the director nominees to stand for election at the next general meeting of shareholders, (iii) developing and recommending to the Board a set of corporate governance principles applicable to our directors and employees, (iv) recommending committee structure, operations and reporting obligations to the Board, (v) recommending committee assignments for directors to the Board and (vi) overseeing an annual review of Board performance.

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Executive sessions

The NYSE requires that non-management directors meet regularly in executive sessions without management. The NYSE also requires that, if such executive sessions include any non-management directors who are not independent, all independent directors also meet in an executive session at least once a year. As permitted under Bermuda law and our Bye-Laws, neither our non-management directors nor our independent directors regularly hold executive sessions without management and we do not expect them to do so in the future.

Corporate governance guidelines

The NYSE requires U.S. companies to adopt and disclose corporate governance guidelines. The guidelines must address, among other things: director qualification standards, director responsibilities, director access to management and independent advisers, director compensation, director orientation and continuing education, management succession and an annual performance evaluation. We are not required to adopt such guidelines under Bermuda law and we have not adopted such guidelines.

MANAGEMENT OF THE COMPANY

Our Board is responsible for determining the strategic vision and ultimate direction of our business, determining the principles of our business strategy and policies and promoting our long-term interests. Our Board possesses and exercises oversight authority over our business and, subject to our governing documents and applicable law, generally delegates day-to-day management of the Company to our senior management team. Viewed from this perspective, our Board generally oversees risk management and our senior management team generally manage the material risks that we face. The Board must, however, 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 our senior management to act on its behalf.

The senior management team responsible for our day-to-day management has extensive experience in the oil and gas industry in general and in the offshore drilling area in particular. The Board has defined the scope and terms of the services to be provided by our senior management. Management services are provided to the Group by Borr Drilling Management DMCC and Borr Drilling Management (UK) Limited, subsidiaries of Borr Drilling incorporated in the United Arab Emirates and England and Wales, respectively. For more information on management practice and related parties, please see the sections entitled “Management—Board of Directors & Board Practices” and “Certain Relationships and Related Party Transactions.”

CODE OF BUSINESS CONDUCT AND ETHICS

Our Board has established a code of business conduct and ethics applicable to our employees, directors and officers. Any waiver of this code may be made only by our Board and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

COMPENSATION

During the year ended December 31, 2018, we paid our directors and executive officers aggregate compensation of $8.3 million, including compensation in the form of 14,285 Shares valued at $250,000 issued to Jan A. Rask and any in-kind benefits provided to such persons.

In addition to cash compensation, during 2018 we also recognized an expense of $1.3 million relating to stock options for Shares and restricted stock units granted to certain of our directors and executive officers.

We did not incur any costs related to the provision of pension, retirement or similar benefits to our directors and executive officers.

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Long-term Incentive Program

We have adopted a long-term incentive plan and have authorized the issuance of up to 3,494,000 options pursuant to awards under our long-term incentive program, of which 419,000 options remain unallocated for further awards and recruitments. Any person who is contracted to work at least 20 hours per week in our service, the members of our Board and any person who is a member of the board of any of our subsidiaries are eligible to participate in our long-term incentive plan. The purpose of our long-term incentive program is to align the long-term financial interests of our employees and directors with those of our shareholders, to attract and retain those individuals by providing compensation opportunities that are competitive with other companies, and to provide incentives to those individuals who contribute significantly to our long-term performance and growth. To accomplish this, our long-term incentive plan permits the issuance of our Shares.

We also held 1,459,714 treasury shares as of December 31, 2018 and 1,459,714 treasury shares as of March 31, 2019, which we may use for issuances under our long-term incentive program and for other purposes.

AUDITORS

PricewaterhouseCoopers AS served as our independent registered public accounting firm for the years ended December 31, 2018, 2017 and 2016. The offices of PricewaterhouseCoopers AS are located at Dronning Eufemias, Gate 71, 0194 Oslo, Norway.

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PRINCIPAL SHAREHOLDERS

Except as specifically noted, the following table sets forth information as of July 24, 2019 with respect to the beneficial ownership of our common shares by:

• each of our directors and executive officers;

• all of our directors and executive officers as a group; and

• each person known to us to own beneficially more than 5% of our total common shares.

The calculations in the table below are based on 105,068,351 common shares outstanding and 110,068,351 common shares outstanding immediately after the completion of this Offering (110,818,351 common shares assuming the underwriters exercise their option to purchase additional shares in full). All of our shareholders, including the shareholders listed in the table below, are entitled to one vote for each Share held.

Beneficial ownership is determined in accordance with the rules and regulations of the SEC. In computing the number of shares beneficially owned by a person and the percentage ownership of that person, we have included shares that the person has the right to acquire within 60 days, including through the exercise of any option, warrant or other right or the conversion of any other security. These shares, however, are not included in the computation of the percentage ownership of any other person.

	Common Shares Beneficially Owned Prior to This Offering(1)					Common Shares Beneficially Owned After This Offering (assuming underwriters' option to purchase additional common shares is not exercised)(1)					Common Shares Beneficially Owned After This Offering (assuming underwriters' option to purchase additional common shares is exercised in full)(1)
	Number		%			Number		%			Number		%
Directors and Executive Officers:
Tor Olav Trøim(2)		8,882,117		8.4	%		8,882,117		8.1	%		8,882,117		8.0	%
Fredrik Halvorsen(3)		2,327,110		2.2	%		2,327,110		2.1	%		2,327,110		2.1	%
Patrick Schorn		—		—			—		—			—		—
Jan A. Rask		14,285			*		14,285			*		14,285			*
Kate Blankenship		—		—			—		—			—		—
Georgina Sousa		—		—			—		—			—		—
Svend Anton Maier(4)		215,500			*		215,500			*		215,500			*
Rune Magnus Lundetræ(5)		181,500			*		181,500			*		181,500			*
All Directors and Executive Officers as a Group		11,618,512		11.1	%		11,618,512		10.6	%		11,618,512		10.5	%
Principal Shareholders:
Schlumberger Oilfield Holdings Limited		15,131,700		14.4	%		15,131,700		13.7	%		15,131,700		13.7	%
Tor Olav Trøim(2)		8,882,117		8.4	%		8,882,117		8.1	%		8,882,117		8.0	%
Folketrygdfondet(6)		7,862,711		7.5	%		7,862,711		7.1	%		7,862,711		7.1	%
Allan & Gill Gray Foundation(7)		5,352,268		5.1	%		5,352,268		4.9	%		5,352,268		4.8	%

(1) Our post-Reverse Share Split Shares began to trade on the Oslo Børs on June 26, 2019. The table above reflects our Reverse Share Split.

(2) Represents shares beneficially owned by Tor Olav Trøim, including those held by Drew Holdings Ltd., Magni Partners (Bermuda) Ltd and their respective subsidiaries and affiliates, as the context may require.

(3) Represents shares beneficially owned by Fredrik Halvorsen, including those held by Ubon Partners AS and its respective subsidiaries and affiliates, as the context may require.

(4) Includes options to purchase 86,000 shares exercisable at a price of $17.50 per share and which expire on June 12, 2022 and options to purchase 60,500 shares exercisable at a price of $24.35 per share and which expire on July 6, 2023.

(5) Includes options to purchase 86,000 shares exercisable at a price of $17.50 per share and which expire on June 12, 2022 and options to purchase 35,500 shares exercisable at a price of $24.35 per share and which expire on July 6, 2023.

(6) To the best of the our knowledge, voting and decision making authority over shares held by Folketrygdfondet is held by the board of directors and management, under the direction of the Norwegian Ministry of Finance.

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(7) To the best of our knowledge, the above represents shares beneficially owned by the Allan & Gill Gray Foundation, including (i) 4,342,755 shares held by funds managed by Orbis Investment Management Limited and/or Allan Gray Australia Pty Limited (together, the “Managers”) and (ii) 1,009,513 shares issuable upon the conversion of the principal amount outstanding of our Convertible Bonds which is held by the Allan & Gill Gray Foundation and related entities. To the best of our knowledge, the Managers are ultimately controlled by the Allan & Gill Gray Foundation, through its ownership or control, as applicable, of Orbis Allan Gray Limited, Allan Gray (Holdings) Pty Limited and Orbis Holdings Limited.

* Represents ownership of less than 1% of our outstanding Shares.

As of July 24, 2019, a total of 11,530,823 shares are held by 68 record holders in the United States, representing 10.8% of our total outstanding shares on an as-converted basis.

We are not aware of any arrangement that may, at a subsequent date, result in a change of control of our company. See the section entitled “Description of Share Capital—History of Securities Issuances” for historical changes in our shareholding structure.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Borr Drilling and its affiliates are party to a number of significant contractual arrangements with related parties. In addition to the information contained in this section, you should carefully review the notes to our financial statements included in this Prospectus.

In addition to the director and executive officer compensation arrangements discussed in the section entitled “Management—Compensation,” the following is a description of transactions since January 1, 2017 to which we have been a party and in which any of our directors, executive officers, beneficial owners of more than 5% of our common shares, or their immediate family members or entities affiliated with them, had or will have a direct or indirect material interest. We have effected a conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. The share and per share data discussed in the section below is adjusted to reflect our Reverse Share Split and is approximate due to rounding.

AGREEMENTS AND OTHER ARRANGEMENTS WITH DREW HOLDINGS LIMITED (“DREW”) AND TARAN HOLDINGS LIMITED (“TARAN”)

Drew is a trust established for the benefit of Tor Olav Trøim, chairman of our Board. Drew is, following its merger with Taran in 2017, one of our largest shareholders.

Loans & Related Facilities

A short-term loan of $13.0 million was provided by Taran to us on December 2, 2016 to finance the deposit payable for the Hercules Rigs (Hercules Triumph and Hercules Resilience), which was completed in January 2017. The loan was repaid with no interest accruing by way of set-off against Taran’s subscription of shares in our first private placement in December 2016.

Taran also provided us with a revolving credit facility of $20.0 million on December 12, 2016. The facility was never utilized and expired in May 2017.

A short-term loan of $12.75 million was provided to us by Taran on March 15, 2017, to finance a deposit payable pursuant to the terms of the acquisition agreement for the Transocean jack-up fleet which was completed in May 2017. The loan was repaid with no interest accrued by way of set-off against Taran’s payment obligations for its subscription of shares in our private placement in March 2017.

Other

On March 22, 2018, it was announced that we would raise up to $250 million in an equity offering divided in two tranches. In order to complete settlement of tranche 1 of the March 2018 Private Placement (as defined below), we accepted a loan of 332,065 shares from Magni, which were to be settled by the issuance of the same number of new shares to Drew in connection with the settlement of tranche 2 of the March 2018 Private Placement. In connection with the settlement of tranche 2, $27.7 million was registered as liability to shareholders, including $20.0 million to Drew as of March 31, 2018 as our authorized share capital was insufficient to issue the shares required pursuant to Drew’s subscription. Tranche 2 of the March 2018 Private Placement was subject to approval by the special general meeting held on April 5, 2018 and subsequent share issue. On May 30, 2018, the 1,528,065 new shares allocated in tranche 2 of the equity offering were validly issued and fully paid and the related liabilities settled. 870,000 new shares were purchased by Drew in the March 2018 Private Placement at a price of $23.00 per share.

AGREEMENTS AND OTHER ARRANGEMENTS WITH MAGNI PARTNERS LIMITED

Mr. Tor Olav Trøim is the chairman of our Board and is the sole owner of Magni.

Corporate Support Agreement

Magni is party to a Corporate Support Agreement with Borr Drilling Limited pursuant to which it is providing strategic advice and assistance in sourcing investment opportunities, financing etc. This agreement was formalized on March 15, 2017.

Magni received cash compensation of $1.4 million for various commercial services provided in connection with the acquisition of the Hercules Rigs (“Hercules Triumph” and “Hercules Resilience”) which

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was completed in the first quarter of 2017. Of this amount $1.0 million has been capitalized within drilling rigs, $0.3 million has been offset against additional paid in capital as equity issuance cost and $0.07 million has been recognized within general and administrative expenses in the statement of operations for the period ended December 31, 2016. In the third quarter of 2017, $2.0 million was paid to Magni for its assistance in the March 2017 Private Placement (as defined below) ($1.75 million) and Transocean Transaction ($0.25 million). The total cost for the March 2017 Private Placement (including the payment to the investment banks and Magni) was $8.75 million, or 1.1% of the gross proceeds. In the fourth quarter of 2017, $1.5 million was paid to Magni for its assistance in the October Private Placement (as defined below) ($1.25 million) and PPL Acquisition ($0.25 million). The total cost for the October Private Placement (including the payment to the investment banks and Magni) was $8.75 million, or 1.3% of the gross proceeds.

Warrants

On December 9, 2016, our Board issued 1,550,000 warrants to Magni to subscribe for our common shares at a price of $0.05 per share. The issue of the warrants to Magni was made in recognition of its role in relation to the identification, negotiation and conclusion of the purchase agreement for the two Hercules jack-up rigs, its commitment to subscribe in the March 2017 Private Placement and the provision of general and administrative services to us.

On the date of issuance, the warrants issued to Magni were valued at $8.6 million and were deemed to have vested on the basis that Magni had fulfilled all of its performance criteria. The amount recognized as additional paid in capital with respect to the warrants issued to Magni was $8.6 million, while $6.0 million has been capitalized within drilling rigs, $2.1 million has been allocated against equity as issuance costs and $0.4 million has been allocated to general and administrative expenses in the statement of operations for the year ended December 31, 2016.

AGREEMENTS AND OTHER ARRANGEMENTS WITH UBON PARTNERS AS (“UBON”)

Mr. Fredrik Halvorsen owns 50% of the shares in Ubon and is a director on our Board.

Warrants

On December 9, 2016, our Board issued 387,500 warrants to Ubon to subscribe for our common shares at a price of $0.05 per share. The issue of the warrants to Ubon was made in recognition of its commitment to subscribe in the March 2017 Private Placement and the provision of general and administrative services to us. On the date of issuance, the warrants issued to Ubon were valued at $2.1 million and were deemed to have fully vested on the basis that Ubon had fulfilled all its performance criteria.

Other

228,860 new shares were purchased by Ubon and 97,140 were purchased directly by Mr. Halvorsen in the March 2018 Private Placement, in each case at a price of $23.00 per share.

AGREEMENTS AND OTHER ARRANGEMENTS WITH SCHLUMBERGER

Schlumberger is our principal shareholder and Patrick Schorn, Executive Vice President of Wells in Schlumberger Limited, is a director on our Board.

Collaboration Agreement

On March 26, 2017, we signed a preliminary collaboration agreement with Schlumberger in which we agreed to discuss a collaborative initiative whereby we would work together on a “joint service model” to facilitate the provision of a combined offering portfolio of integrated drilling services to customers and established a framework for entering into a definitive agreement defining each party’s key contributions to the collaboration. The commercial principle that we would work with Schlumberger, on a non-exclusive basis, and the aspects of our respective businesses which we agreed to approach on a collaborative basis were subsequently established in an enhanced collaboration agreement entered into on October 6, 2017. The Collaboration Agreement provides for the provision of streamlined, integrated drilling services to customers and the sharing of infrastructure and improving technology.

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Under the Collaboration Agreement, we have agreed to meet with Schlumberger annually to define a strategic plan for the upcoming year, including key milestones, which is then presented to our respective management teams for approval. In addition, we have agreed to work together, on a non-exclusive basis, in the following areas:

• Schlumberger will be the preferred provider to us for training our employees, where available within a specific geographic region, and the development of a “next generation” curriculum for the training of our employees;

• The sharing of office space, warehouses, employee accommodations and other similar resources with a view toward reducing costs for and increasing the competitiveness of each party;

• Improving drilling performance and wellsite outcomes, which may include joint technology projects and field trials of new equipment, software and techniques (although no such projects have taken place to date);

• Schlumberger will be the preferred provider of certain equipment and services required by us, including Cement Units, Solids Control Equipment, Tubular Management, Managed Pressure Drilling, Well Control and Drilling Systems and Testing Services; and

• The submission of tenders to provide drilling services on an integrated basis.

The Collaboration Agreement shall remain in force until terminated by either party upon 45-days’ notice. The key contributions of each party were to be defined subsequent to execution of the Collaboration Agreement, but have not yet been agreed. We were recently awarded a contract to deliver integrated drilling services to Pemex in Mexico and are working to finalize definitive documentation related thereto.

Warrants

On March 21, 2017, we issued 947,377 warrants to subscribe for our common shares at a price of $17.50 plus 4% per annum per share to Schlumberger for its role, support and participation in the March 2017 Private Placement. At the grant date, the warrants issued to Schlumberger were valued at $3.01 million and were deemed to have vested on the basis that Schlumberger had fulfilled all of its performance criteria.

In October 2017, we issued a further 947,377 warrants to subscribe for our common shares at a price of $17.50 plus 4% per annum per share to Schlumberger as a consequence of the Collaboration Agreement between Schlumberger and us being signed. The warrants were valued at $4.7 million which was charged to the statement of operations in the fourth quarter of 2017. Immediately thereafter, we agreed to repurchase all of 1,894,754 warrants held by Schlumberger at a price of $2.50 per warrant, $4.7 million in total. Consequently, all related warrants were then cancelled.

Commercial Arrangements

We have obtained certain rig and other operating supplies from Schlumberger and/or its affiliates and may continue to obtain such supplies in the future. Purchases from Schlumberger were $8.5 million during 2018 and $0.1 million during 2017. As of December 31, 2018 and 2017, we had outstanding liabilities to Schlumberger of $0.4 million and $nil, respectively. Purchases from Schlumberger were $6.1 million during the first quarter of 2019, compared to $0.6 million during the first quarter of 2018, and we had outstanding liabilities to Schlumberger of $0.8 million and $0.4 million as of March 31, 2019 and December 31, 2018, respectively.

OTHER RELATIONSHIPS

Indemnification Agreements

In connection with this Offering, we have entered into indemnification agreements with each of our executive officers and directors to contain customary terms for public companies.

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Option Agreements

On December 18, 2016 Rune Magnus Lundetræ (then-CEO) and Svend Anton Maier (then-COO) entered into option agreements to buy 192,000 shares each from Magni and Ubon (“Grantors”) through their individual companies, Primato AS (Rune Magnus Lundetræ) and SAM International Offshore Consulting (Svend Anton Maier). The strike price per share was $10.00 and the options expired on April 1, 2019. The employees’ companies paid an option premium to the Grantors an amount of $192,414 as consideration for the option to buy shares in us. This has been calculated by an independent third party and reflects market terms or the fair value of the instrument.

STATEMENT OF POLICY REGARDING TRANSACTIONS WITH RELATED PERSONS

Prior to the consummation of this Offering, our Board will adopt a written policy for the review by the audit committee of any transaction, arrangement or relationship in which we are a participant, the amount involved exceeds $120,000 and one of our executive officers, directors, director nominees or beneficial owners of more than 5% of our common shares (or their immediate family members), each of whom we refer to as a “related person,” has a direct or indirect material interest. If a related person proposes to enter into such a transaction, arrangement or relationship, which we refer to as a “related person transaction,” the related person must report the proposed related person transaction to the chairperson of our audit committee. The policy calls for the proposed related person transaction to be reviewed and, if deemed appropriate, approved by the audit committee. In approving or rejecting such proposed transactions, the audit committee will be required to consider the relevant facts and circumstances available and deemed relevant to the audit committee, including the material terms of the transaction, risks, benefits, costs, availability of other comparable services or products and, if applicable, the impact on a director’s independence. Our audit committee will approve only those transactions that, in light of known circumstances, are in, or are not inconsistent with, our best interests, as our audit committee determines in good faith. In the event that any member of our audit committee is not a disinterested person with respect to the related person transaction under review, that member will be excluded from the review and approval or rejection of such related person transaction and another director may be designated to join the committee for purposes of such review. Whenever practicable, the reporting, review and approval will occur prior to entering into the transaction. If advance review and approval is not practicable, the audit committee will review and may, in its discretion, ratify the related person transaction retroactively.

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DESCRIPTION OF SHARE CAPITAL

We are an exempted company limited by shares incorporated in Bermuda and our corporate affairs are governed by our Memorandum and Bye-Laws, the Companies Act and the common law of Bermuda.

Our authorized share capital is $6,250,000 divided into 125,000,000 common shares of par value of $0.05 each, of which all are designated as common shares. All of our issued and outstanding Shares are fully paid. We have effected a conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. Our post-Reverse Share Split Shares began to trade on the Oslo Børs on June 26, 2019. Immediately upon the completion of this Offering, there will be 110,068,351 Shares outstanding, assuming the underwriters do not exercise the option to purchase additional Shares.

OUR MEMORANDUM OF ASSOCIATION AND BYE-LAWS

Our Memorandum is filed as Exhibit 3.1 to this registration statement. Our Bye-Laws, which were adopted on August 25, 2017 are filed as Exhibit 3.2 to this registration statement. The following are summaries of material provisions of our Memorandum and Bye-Laws, insofar as they relate to the material terms of our Shares.

Objects of Our Company

We were incorporated by registration under the Companies Act. Our business objects are unrestricted and we have all the powers of a natural person.

Common Shares Ownership

Our Memorandum and Bye-Laws do not impose any limitations on the ownership rights of our shareholders. The Bermuda Monetary Authority has given a general permission for us to issue shares to nonresidents of Bermuda and for the free transferability of our Shares among nonresidents of Bermuda, for so long as our Shares are listed on an appointed stock exchange. There are no limitations on the right of non-Bermudians or non-residents of Bermuda to hold or vote our common shares.

Dividends

As a Bermuda exempted company limited by shares, we are subject to Bermuda law relating to the payment of dividends. We may not pay any dividends if, at the time the dividend is declared or at the time the dividend is paid, there are reasonable grounds for believing that, after giving effect to that payment:

• we will not be able to pay our liabilities as they fall due; or

• the realizable value of our assets is less than our liabilities.

In addition, since we are a holding company with no material assets, and conduct our operations through subsidiaries, our ability to pay any dividends to shareholders will depend on our subsidiaries’ distributing to us their earnings and cash flow. Some of our loan agreements currently limit or prohibit our subsidiaries’ ability to make distributions to us and our ability to make distributions to our shareholders.

Voting Rights

Holders of common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Unless a different majority is required by law or by our Bye-Laws, resolutions to be approved by holders of common shares require approval by a simple majority of votes cast at a meeting at which a quorum is present.

Majority shareholders do not generally owe any duties to other shareholders to refrain from exercising all of the votes attached to their shares. There are no deadlines in the Companies Act relating to the time when votes must be exercised. However, our Bye-Laws provide that where a shareholder or a person representing a shareholder as a proxy wishes to attend and vote at a meeting of our shareholders, such shareholder or person must give us not less than 48 hours’ notice in writing of their intention to attend and vote.

The key powers of our shareholders include the power to alter the terms of our Memorandum and to approve and thereby make effective any alterations to our Bye-Laws made by the directors. Dissenting shareholders holding 20% of our Shares may apply to the court to annul or vary an alteration to our

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Memorandum. A majority vote against an alteration to our Bye-Laws made by the directors will prevent the alteration from becoming effective. Other key powers are to approve the alteration of our capital, including a reduction in share capital, to approve the removal of a director, to resolve that we will be wound up or discontinued from Bermuda to another jurisdiction or to enter into an amalgamation, merger or winding up. Under the Companies Act, all of the foregoing corporate actions require approval by an ordinary resolution (a simple majority of votes cast), except in the case of an amalgamation or merger transaction, which requires approval by 75% of the votes cast, unless our Bye-Laws provide otherwise, which our Bye-Laws do. Our Bye-Laws provide that the Board may, with the sanction of a resolution passed by a simple majority of votes cast at a general meeting with the necessary quorum for such meeting of two persons at least holding or representing 33.33% of our issued Shares (or the class of securities, where applicable), amalgamate or merge us with another company. In addition, our Bye-Laws confer express power on the Board to reduce its issued share capital selectively with the authority of an ordinary resolution of the shareholders.

The Companies Act provides that a company shall not be bound to take notice of any trust or other interest in its shares. There is a presumption that all the rights attaching to shares are held by, and are exercisable by, the registered holder, by virtue of being registered as a member of the company. Our relationship is with the registered holder of its shares. If the registered holder of the shares holds the shares for someone else (the beneficial owner), then the beneficial owner is entitled to the shares and may give instructions to the registered holder on how to vote the shares. The Companies Act provides that the registered holder may appoint more than one proxy to attend a shareholder meeting, and consequently where rights to shares are held in a chain the registered holder may appoint the beneficial owner as the registered holder’s proxy.

Meetings of Shareholders

The Companies Act provides that a company must have a general meeting of its shareholders in each calendar year unless that requirement is waived by resolution of the shareholders. Under our Bye-Laws, annual shareholder meetings will be held in accordance with the Companies Act at a time and place selected by the Board. Special general meetings may be called at any time at the discretion of the Board.

Annual shareholder meetings and special meetings must be called by not less than seven days’ prior written notice specifying the place, day and time of the meeting. The Board may fix any date as the record date for determining those shareholders eligible to receive notice of and to vote at the meeting.

The quorum at any annual or general meeting is equal to at least two shareholders, present in person or by proxy, and entitled to vote (whatever the number of shares held by them). The Companies Act specifically imposes special quorum requirements where the shareholders are being asked to approve the modification of rights attaching to a particular class of shares (33.33%) or an amalgamation or merger transaction (33.33%) unless in either case the bye-laws provide otherwise.

The Companies Act provides shareholders holding 10% of a Company’s voting shares the ability to request that the Board shall convene a meeting of shareholders to consider any business which the shareholders wish to be discussed by the shareholders including (as noted below) the removal of any director. However, the shareholders are not permitted to pass any resolutions relating to the management of our business affairs unless there is a pre-existing provision in the company’s bye-laws which confers such rights on the shareholders. Subject to compliance with the time limits prescribed by the Companies Act, shareholders holding 5% of the voting shares (or alternatively, 100 shareholders) may also require the directors to circulate a written statement not exceeding 1,000 words relating to any resolution or other matter proposed to be put before, or otherwise considered during, the annual general meeting of the company.

Election, Removal and Remuneration of Directors

The Companies Act provides that the directors shall be elected or appointed by the shareholders. A director may be elected by a simple majority vote of shareholders. A person holding more than 50% of the voting shares of the company will be able to elect all of the directors, and to prevent the election of any person whom such shareholder does not wish to be elected. There are no provisions for cumulative voting in the Companies Act or the Bye-Laws. Further, our Bye-Laws do not contain any super-majority voting requirements relating to the appointment or election of directors. The appointment and removal of directors is covered by Bye-Laws 97, 98 and 99.

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There are procedures for the removal of one or more of the directors by the shareholders before the expiration of his term of office. Shareholders holding 10% or more of our voting shares may require the Board to convene a shareholder meeting to consider a resolution for the removal of a director. At least 14 days’ written notice of a resolution to remove a director must be given to the director affected, and that director must be permitted to speak at the shareholder meeting at which the resolution for his removal is considered by the shareholders. Any vacancy created by such a removal may be filled at the meeting by the election of another person by the shareholders or in the absence of such election, by the Board.

The Companies Act stipulates that an undischarged bankruptcy of a director (in any country) shall prohibit that director from acting as a director, directly or indirectly, and taking part in or being concerned with the management of a company, except with leave of the court. Bye-Law 101 is more restrictive in that it stipulates that the office of a Director shall be vacated upon the happening of any of the following events:

• If he resigns his office by notice in writing delivered to the registered office or tendered at a meeting of the Board;

• If he becomes of unsound mind or a patient for any purpose of any statute or applicable law relating to mental health and the Board resolves that his office is vacated;

• If he becomes bankrupt or compounds with his creditors;

• If he is prohibited by law from being a Director; or

• If he ceases to be a Director by virtue of the Companies Act or is removed from office pursuant to the company’s bye-laws.

Under our Bye-Laws, the minimum number of directors comprising the Board at any time shall be two. The Board currently consists of six directors. The minimum and maximum number of directors comprising the Board from time to time shall be determined by way of an ordinary resolution of our shareholders. The shareholders may, at the annual general meeting by ordinary resolution, determine that one or more vacancies in the Board be deemed casual vacancies. Our directors are not required to retire because of their age, and the directors are not required to be holders of our Shares. Directors serve for one year terms, and shall serve until re-elected or until their successors are appointed at the next annual general meeting. The Board, so long as a quorum remains in office, shall have the power to fill such casual vacancies. Each director will hold office until the next annual general meeting or until his successor is appointed or elected. There is no requirement for our Directors to hold our shares to qualify for appointment.

Director Transactions

Our Bye-Laws do not prohibit a director from being a party to, or otherwise having an interest in, any transaction or arrangement with our Company or in which our Company is otherwise interested. Our Bye-Laws provide that a director who has an interest in any transaction or arrangement with us and who has complied with the provisions of the Companies Act and with our Bye-Laws with regard to disclosure of such interest shall be taken into account in ascertaining whether a quorum is present, and will be entitled to vote in respect of any transaction or arrangement in which he is so interested.

Bye-Law 112 provides our Board the authority to exercise all of our powers to borrow money and to mortgage or charge all or any part of our property and assets as collateral security for any debt, liability or obligation. However, under the Companies Act, companies may not lend money to a director or to a person connected to a director who is deemed by the Companies Act to be a director (a “Connected Person”), or enter into any guarantee or provide any security in relation to any loan made to a director or a Connected Person without the prior approval of the shareholders of the company holding in aggregate 90% of the total voting rights in the company.

Our Bye-Laws provide that no director, alternate director, officer, person or member of a committee, if any, resident representative, or his heirs, executors or administrators, which we refer to collectively as an indemnitee, is liable for the acts, receipts, neglects or defaults of any other such person or any person involved in our formation, or for any loss or expense incurred by us through the insufficiency or deficiency of title to any property acquired by us, or for the insufficiency of deficiency of any security in or upon which any of our monies shall be invested, or for any loss or damage arising from the bankruptcy, insolvency or tortious act of any person with whom any monies, securities or effects shall be deposited, or for any loss occasioned by any error of judgment,

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omission, default or oversight on his part, or for any other loss, damage or other misfortune whatever which shall happen in relation to the execution of his duties, or supposed duties, to us or otherwise in relation thereto. Each indemnitee will be indemnified and held harmless out of our funds to the fullest extent permitted by Bermuda law against all liabilities, loss, damage or expense (including but not limited to liabilities under contract, tort and statute or any applicable foreign law or regulation and all reasonable legal and other costs and expenses properly payable) incurred or suffered by him as such director, alternate director, officer, person or committee member or resident representative (or in his reasonable belief that he is acting as any of the above). In addition, each indemnitee shall be indemnified against all liabilities incurred in defending any proceedings, whether civil or criminal, in which judgment is given in such indemnitee’s favor, or in which he is acquitted. We are authorized to purchase insurance to cover any liability it may incur under the indemnification provisions of our Bye-Laws. Each shareholder has agreed in Bye-Law 167 to waive to the fullest extent permitted by Bermuda law any claim or right of action he might have whether individually or derivatively in the name of the company against each indemnitee in respect of any action taken by such indemnitee or the failure by such indemnitee to take any action in the performance of his duties to us.

Liquidation

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

Redemption, Repurchase and Surrender of Shares

Subject to certain balance sheet restrictions, the Companies Act permits a company to purchase its own shares if it is able to do so without becoming cash flow insolvent as a result. The restrictions are that the par value of the share must be charged against the company’s issued share capital account or a company fund which is available for dividend or distribution or be paid for out of the proceeds of a fresh issue of shares. Any premium paid on the repurchase of shares must be charged to the company’s current share premium account or charged to a company fund which is available for dividend or distribution. The Companies Act does not impose any requirement that the directors shall make a general offer to all shareholders to purchase their shares pro rata to their respective shareholdings. Our Bye-Laws do not contain any specific rules regarding the procedures to be followed by us when purchasing our Shares, and consequently the primary source of our obligations to shareholders when we tender for our Shares will be the rules of the listing exchanges on which our Shares are listed. Our power to purchase our shares is covered by Bye-Law 8, 9 and 10.

Issuance of Additional Shares

Bye-Law 4 confers on the directors the right to dispose of any number of unissued shares forming part of our authorized share capital without any requirement for shareholder approval.

The Companies Act and our Bye-Laws do not confer any pre-emptive, redemption, conversion or sinking fund rights attached to our common shares. Bye-Law 15 specifically provides that the issuance of more shares ranking pari passu with the shares in issue shall not constitute a variation of class rights, unless the rights attached to shares in issue state that the issuance of further shares shall constitute a variation of class rights.

Inspection of Books and Records

The Companies Act provides that a shareholder is entitled to inspect the register of shareholders and the register of directors and officers of the company. A shareholder is also entitled to inspect the minutes of the meetings of the shareholders of the company, and the annual financial statements of the company. Our Bye-Laws do not provide shareholders with any additional rights to information, and our Bye-Laws do not confer any general or specific rights on shareholders to inspect our books and records.

Anti-Takeover Provisions

Our Bye-Laws provide that the Board may, with the sanction of a resolution passed by a simple majority of votes cast at a general meeting with the necessary quorum for such meeting of two persons at least holding or representing 33.33% of our issued Shares (or the class of securities, where applicable), amalgamate or merge us with another company. In addition, our Bye-Laws confer express power on the board to reduce its issued share capital selectively with the authority of a resolution of the shareholders.

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IMPLICATIONS OF BEING A FOREIGN PRIVATE ISSUER

We are considered a “foreign private issuer.” As a foreign private issuer, we are exempt from certain rules under the Exchange Act that impose certain disclosure obligations and procedural requirements for proxy solicitations under section 14 of the Exchange Act. In addition, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of section 16 of the Exchange Act and the rules under the Exchange Act with respect to their purchases and sales of our common shares. Moreover, we are not required to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act. In addition, we are not required to comply with Regulation FD, which restricts the selective disclosure of material information.

We may take advantage of these exemptions until the first day after we cease to qualify as a foreign private issuer. We would cease to be a foreign private issuer if, on the last business day of our second fiscal quarter, more than 50.0% of our outstanding voting securities are held by U.S. residents and any of the following three circumstances applies: (i) the majority of our executive officers or directors are U.S. citizens or residents, (ii) more than 50.0% of our assets are located in the United States or (iii) our business is administered principally in the United States. We have taken advantage of certain reduced reporting and other requirements in this Prospectus. Accordingly, the information contained herein may be different than the information you receive from other public companies in which you hold equity securities.

IMPLICATIONS OF BEING AN EMERGING GROWTH COMPANY

We are also an “emerging growth company” as defined in the JOBS Act enacted in April 2012. An emerging growth company may take advantage of reduced reporting requirements that are otherwise applicable to public companies. These provisions include, but are not limited to:

• being permitted to present only two years of audited financial statements and only two years of related disclosure in our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Prospectus; and

• not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act.

To the extent that we cease to qualify as a foreign private issuer but remain an emerging growth company, we may also take advantage of (i) reduced disclosure obligations regarding executive compensation in our periodic reports, proxy statements (if any) and registration statements and (ii) exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved.

We intend to take advantage of the reduced reporting requirements and exemptions to the extent we cease to qualify as a foreign private issuer but remain an emerging growth company. Notwithstanding our status as an emerging growth company, we have not elected to use the extended transition period for complying with any new or revised financial accounting standards and, in accordance with SEC standards applicable to emerging growth companies, such election is irrevocable. For more information, please see the section entitled “Risk Factors—Risk Factors Related to Applicable Laws and Regulations—If we fail to comply with requirements relating to being a public company in the United States when obligated to do so, our business could be harmed and our Share price could decline.”

We may take advantage of these provisions until the last day of our fiscal year following the fifth anniversary of the date of the first sale of our common equity securities under an effective registration statement under the Securities Act. However, if certain events occur prior to the end of such five-year period, including if we become a “large accelerated filer,” our gross revenues for any fiscal year equal or exceed $1.07 billion (as adjusted for inflation under SEC rules from time to time) or we issue more than $1.0 billion of nonconvertible debt in any three-year period, we will cease to be an emerging growth company prior to the end of such five-year period.

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CERTAIN BERMUDA COMPANY CONSIDERATIONS

Our corporate affairs are governed by our Memorandum and Bye-Laws as described above, the Companies Act 1981 and the common law of Bermuda. You should be aware that the Companies Act differs in certain material respects from the laws generally applicable to U.S. companies incorporated in the State of Delaware. Accordingly, you may have more difficulty protecting your interests under Bermuda law in the face of actions by management, directors or controlling shareholders than would shareholders of a corporation incorporated in a United States jurisdiction, such as the State of Delaware. The following table provides a comparison between the statutory provisions of the Companies Act and the Delaware General Corporation Law relating to shareholders’ rights.

BERMUDA	DELAWARE
Shareholder Meetings and Voting Rights
Shareholder meetings may be held at such times and places as designated in the bye-laws.	Shareholder meetings may be held at such times and places as designated in the certificate of incorporation or the bye-laws, or if not so designated, as determined by the board of directors.
Special meetings of the shareholders may be called by the board of directors at any time. A special shareholder meeting may be called at the request of shareholders holding at least 10% of paid-up share capital carrying the right to vote at general meetings.	Special meetings of the shareholders may be called by the board of directors or by such person or persons as may be authorized by the certificate of incorporation or by the bye-laws.
A minimum of five days’ notice of an annual meeting or special meeting must be given to each shareholder. Accidental failure to give notice will not invalidate proceedings at a meeting.	Written notice shall be given not less than 10 nor more than 60 days before the meeting. Whenever shareholders are required to take any action at a meeting, a written notice of the meeting shall be given which shall state the place, if any, date and hour of the meeting, and the means of remote communication, if any.
Shareholder meetings may be held in or outside of Bermuda.	Shareholder meetings may be held within or without the State of Delaware.
Shareholders may take action by written consent if such consent is signed by (a) the shareholders who represent such majority of votes as would be required if the resolution had been voted on at a meeting of the shareholders or (b) by 100% of the shareholders or such other majority of the shareholders as may be provided by the bye-laws.	Any action required to be taken by a meeting of shareholders may be taken without a meeting if a consent for such action is in writing and is signed by shareholders having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted.
Transactions with Significant Shareholders
A company may enter into certain business transactions with its significant shareholders, including asset sales, in which a significant shareholder receives, or could receive, a financial benefit that is greater than that received, or to be received, by other shareholders with prior approval from our board of directors but without obtaining prior approval from our shareholders.	Subject to certain exceptions and conditions, a corporation may not enter into a business combination with an interested shareholder for a period of three years from the time the person became an interested shareholder without prior approval from shareholders holding at least 66 2/3% of the corporation’s outstanding voting stock which is not owned by such interested shareholder.

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BERMUDA	DELAWARE
Dissenters’ Rights of Appraisal
In the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who did not vote in favor of the amalgamation or merger and is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares.	Appraisal rights shall be available for the shares of any class or series of stock of a corporation in a merger or consolidation, subject to limited exceptions, such as a merger or consolidation of corporations listed on a national securities exchange in which listed stock is the offered consideration.
Shareholders’ Suits
Class actions and derivative actions are generally not available to shareholders under the laws of Bermuda. However, the Bermuda courts ordinarily would be expected to follow English case law precedent, which would permit a shareholder to commence an action in our name to remedy a wrong done to us where the act complained of is alleged to be beyond our corporate power or is illegal or would result in the violation of a company’s memorandum of association or bye-laws. Furthermore, consideration would be given by the court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of shareholders than actually approved it.	Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In any derivative suit instituted by a shareholder or a corporation, it shall be averred in the complaint that the plaintiff was a shareholder of the corporation at the time of the transaction of which he complains or that such shareholder’s stock thereafter developed upon such shareholder by operation of law.
Indemnification of Directors and Officers
A company’s bye-laws may contain provisions excluding personal liability of a director, alternate director, officer, member of a committee authorized under the company’s bye-laws, resident representative or their respective heirs, executors or administrators to the company for any loss arising or liability attaching to him by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which the officer or person may be guilty. Companies also have the power, generally, to indemnify directors, alternate directors and officers of a company and any member of a committee authorized under the company’s bye-laws, resident representatives or their respective heirs, executors or administrators if any such person was or is a party or threatened to be made a party to a threatened, pending or completed action, suit or proceeding by reason of the fact that he or she is or was a director, alternate director or officer of the company or member of a	A corporation may indemnify a director or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if (i) such director or officer acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and (ii) with respect to any criminal action or proceeding, such director or officer had no reasonable cause to believe his conduct was unlawful.

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BERMUDA	DELAWARE
committee authorized under the company’s bye-laws, resident representative or their respective heirs, executors or administrators or was serving in a similar capacity for another entity at the company’s request.
Directors
The board of directors must consist of at least one member, although the minimum number of directors may be set higher.	The board of directors must consist of at least one member.
The maximum number of directors may be set by the shareholders at a general meeting or in accordance with the Bye-Laws. The maximum number of directors is usually fixed by the shareholders at the annual general meeting and may be fixed at a special general meeting. Only the shareholders may increase or decrease the number of directors’ seats last approved by the shareholders. If the maximum number of directors fixed by the shareholders has not been elected by the shareholders, the shareholders may authorize the board of directors to fill any vacancies.	Number of board members shall be fixed by, or in a manner provided by, the bye-laws, unless the certificate of incorporation fixes the number of directors, in which case a change in the number shall be made only by amendment of the certificate of incorporation.
Duties of Directors
Members of a board of directors owe a fiduciary duty to the company to act in good faith in their dealings with or on behalf of the company, and to exercise their powers and fulfill the duties of their office honestly.	The business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a fiduciary duty of care to protect the interests of the corporation and a fiduciary duty of loyalty to act in the best interests of its shareholders.

HISTORY OF SECURITIES ISSUANCES

The following is a summary of our securities issuances from our inception through June 30, 2019:

• On December 9, 2016, (i) we completed the private placement of 15,500,000 Shares at a subscription price of $10.00 per share raising gross proceeds of $155 million to finance the Hercules Acquisition and (ii) our Board issued a total of 1,937,500 share warrants. 1,550,000 warrants were issued to Magni and 387,500 warrants were issued to Ubon. The issue of the warrants to Magni and Ubon was done in recognition of their respective role in relation to the identification, negotiation and conclusion of the purchase agreement for the two Hercules jack-up rigs, their commitment to subscribe in the March 2017 Private Placement and the provision of general and administrative services to us. At the issuance date, the warrants issued to Magni were valued at $8.6 million and were deemed to have vested on the basis that Magni had fulfilled all of its performance criteria. At the issuance date, the warrants issued to Ubon were valued at $2.1 million and were deemed to have fully vested on the basis that Ubon had fulfilled all of its performance criteria.

• On March 21, 2017, we completed the private placement of 45,720,000 shares at a subscription price of $17.50 per share raising gross proceeds of $800 million (the “March 2017 Private Placement”) to finance, in part, the Transocean Transaction.

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• On March 21, 2017, we issued 947,377 warrants to subscribe for new shares at a subscription price of $17.50 plus 4% per annum per share to Schlumberger for its role, support and participation in the March 2017 Private Placement. At the grant date, the warrants issued to Schlumberger were valued at $3.01 million and were deemed to have vested on the basis that Schlumberger had fulfilled all of its performance criteria.

• On October 8, 2017, we completed the offering of 32,500,000 new shares at a subscription price of $20.00 per share raising gross proceeds of $650 million (the “October Private Placement”) to finance, in part, the PPL Acquisition.

• In October 2017, we issued a further 947,377 warrants to Schlumberger as a consequence of the Collaboration Agreement signed by Schlumberger and us. The warrants were valued at $4.7 million which was charged to the statement of operations in the fourth quarter of 2017.

• On March 23, 2018, we completed the private placement of 10,869,565 shares at a subscription price of $23.00 per share raising gross proceeds of $250 million to finance the acquisition of shares in Paragon Offshore Limited and for general corporate purposes (the “March 2018 Private Placement”).

• On May 23, 2018, we issued our 3.875% Convertible Bonds due 2023 with a principal amount of $350 million in a private placement, raising gross proceeds of $350 million. The bonds have a conversion premium of 37.5%, above a reference price of $24.35 per share. In connection with the placement, we entered into the Call Spread Transactions, which increases the effective conversion premium 75% above the reference price.

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SHARES ELIGIBLE FOR FUTURE SALE

Upon completion of this Offering, we will have 110,068,351 Shares outstanding, assuming the underwriters do not exercise their option to purchase additional Shares. All of the Shares sold in this Offering will be freely transferable by persons other than by our “affiliates” without restriction or further registration under the Securities Act. Sales of substantial amounts of our Shares in the public market could adversely affect prevailing market prices of our Shares. Prior to this Offering, there has been no public market in the United States for our Shares. We intend to apply to list the Shares on the New York Stock Exchange, but we cannot assure you that a regular trading market will develop in the Shares.

Certain of our Shares that will be outstanding upon the completion of this Offering, other than those Shares sold in this Offering, may be “restricted securities” as that term is defined in Rule 144 under the Securities Act and therefore may be sold publicly in the United States only if they are subject to an effective registration statement under the Securities Act or pursuant to an exemption from registration, such as those provided by Rule 144 and Rule 701 promulgated under the Securities Act. Moreover, other Shares that have been acquired by a person who is not an affiliate of ours on the Oslo Børs or otherwise in the public market prior to this Offering and that will be outstanding upon completion of this Offering are not “restricted securities” as that term is defined in Rule 144 under the Securities Act and will be eligible for resale immediately upon consummation of this Offering without restriction.

LOCK-UP AGREEMENTS

We, members of our Board and executive management team and certain of our shareholders have or will have signed lock-up agreements under which we or they have agreed not to offer, sell, contract to sell, pledge or otherwise dispose of, or to enter into any hedging transactions with respect to, or effect certain other transactions in, our Shares or any securities convertible into or exercisable or exchangeable for our Shares for a period of 180 days after the date of this Prospectus, without the prior written consent of Goldman Sachs & Co. LLC. For more information, see the section entitled “Underwriting.”

RULE 144

Pursuant to Rule 144 under the Securities Act as in effect on the date of this Prospectus, beginning 90 days after the date of this Prospectus, a person who is not an affiliate of ours at the time of a sale or at any time during the 90 days preceding a sale, and who has held their Shares for at least six months, as measured by SEC rules, including the holding period of any prior owner other than one of our affiliates, may sell Shares without restriction, provided current public information about us is available. In addition, under Rule 144, any person who is not an affiliate of ours at the time of a sale or at any time during the three months preceding a sale, and who has held their Shares for at least one year, as measured by SEC rules, including the holding period of any prior owner other than one of our affiliates, would be entitled to sell an unlimited number of Shares immediately upon consummation of this Offering without restriction, including whether or not current public information about us is available.

Beginning 90 days after the date of this Prospectus, persons who are our affiliates and have beneficially owned our restricted securities for at least six months may sell a number of restricted securities within any three-month period that does not exceed the greater of the following:

• 1% of the-then outstanding common shares of the same class, in the form of Shares or otherwise, that immediately after this Offering will equal 1,100,683 common shares, assuming the underwriters do not exercise their option to purchase additional Shares; or

• the average weekly trading volume of our common shares of the same class during the four calendar weeks preceding the date on which notice of the sale is filed with the SEC.

Sales by our affiliates under Rule 144 are also subject to certain requirements relating to manner of sale, notice and the availability of current public information about us.

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RULE 701

In general, under Rule 701 of the Securities Act as currently in effect, each of our employees, consultants or advisors who purchases our common shares from us in connection with a compensatory stock plan or other written agreement executed prior to the completion of this Offering is eligible to resell those common shares in reliance on Rule 144, but without compliance with some of the restrictions, including the holding period, contained in Rule 144. However, the Rule 701 shares would remain subject to lock-up arrangements and would only become eligible for sale when the lock-up period expires.

REGULATION S

Regulation S under the Securities Act (“Regulation S”) provides an exemption from registration requirements in the United States for offers and sales of securities that occur outside the United States. Rule 903 of Regulation S provides the conditions to the exemption for a sale by an issuer, a distributor, their respective affiliates or anyone acting on their behalf, while Rule 904 of Regulation S provides the conditions to the exemption for a resale by persons other than those covered by Rule 903. In each case, any sale must be completed in an offshore transaction, as that term is defined in Regulation S, and no directed selling efforts, as that term is defined in Regulation S, may be made in the United States.

We are a foreign issuer as defined in Regulation S. As a foreign issuer, securities that we sell outside the United States pursuant to Regulation S are not considered to be restricted securities under the Securities Act, and, subject to any applicable distribution compliance period under Regulation S, are freely tradable without registration or restrictions under the Securities Act, unless the securities are held by our affiliates.

In addition, subject to certain limitations, holders of our restricted securities who are not our affiliates, or who are our affiliates solely by virtue of their status as an officer or director of Borr Drilling, may, under Regulation S, resell their restricted shares in an “offshore transaction” if none of the seller, its affiliate or any person acting on their behalf engages in directed selling efforts in the United States and, in the case of a sale of our restricted securities by an officer or director who is our affiliate solely by virtue of holding such position, no selling concession, fee or other remuneration is paid in connection with the offer or sale other than the usual and customary broker’s commission that would be received by a person executing such transaction as agent. Additional restrictions are applicable to a holder of our restricted securities who is our affiliate other than by virtue of his or her status as an officer or director of Borr Drilling.

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MATERIAL INCOME TAX CONSIDERATIONS

The following discussion of the Bermuda and U.S. federal income tax consequences of an investment in our common shares is based upon laws and relevant interpretations thereof in effect as of the date of this registration statement, all of which are subject to change. This summary does not deal with all possible tax consequences relating to an investment in our common shares, such as the tax consequences under U.S. state and local tax laws or under the tax laws of jurisdictions other than Bermuda and the United States.

BERMUDA TAXATION

While we are incorporated in Bermuda, we are not subject to taxation under the laws of Bermuda. Distributions we receive from our subsidiaries also are not subject to any Bermuda tax. There is no Bermuda income, corporation or profits tax, withholding tax, capital gains tax, capital transfer tax or estate duty or inheritance tax payable by nonresidents of Bermuda in respect of capital gains realized on a disposition of our Shares or in respect of distributions they receive from us with respect to our Shares. This discussion does not, however, apply to the taxation of persons ordinarily resident in Bermuda. Bermuda shareholders should consult their own tax advisors regarding possible Bermuda taxes with respect to dispositions of, and distributions on, our Shares. We have received from the Minister of Finance under The Exempted Undertaking Tax Protection Act 1966, as amended, an assurance that, in the event that Bermuda enacts legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, the imposition of any such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035. This assurance is subject to the proviso that it is not to be construed to prevent the application of any tax or duty to such persons as are ordinarily resident in Bermuda or to prevent the application of any tax payable in accordance with the provisions of the Land Tax Act 1967. The assurance does not exempt us from paying import duty on goods imported into Bermuda. In addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government. We and our subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda government. Bermuda currently has no tax treaties in place with other countries in relation to double-taxation or for the withholding of tax for foreign tax authorities.

U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following discussion is a summary of U.S. federal income tax considerations relating to the ownership and disposition of our common shares by a U.S. Holder (as defined below) that acquires our Shares in this Offering and holds our Shares as “capital assets” (generally, property held for investment) under the Code. This discussion is based on the U.S. Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations promulgated thereunder (“Regulations”), published positions of the IRS, court decisions and other applicable authorities, all as currently in effect as of the date hereof and all of which are subject to change or differing interpretations (possibly with retroactive effect). No ruling has been sought from the IRS with respect to any U.S. federal income tax consequences described below, and there can be no assurance that the IRS or a court will not take a contrary position. This discussion does not discuss all aspects of U.S. federal income taxation that may be important to particular investors in light of their individual investment circumstances, including investors subject to special tax rules (including, for example, banks or other financial institutions, insurance companies, regulated investment companies, real estate investment trusts, broker-dealers, dealers in securities or foreign currency, traders in securities that elect mark-to-market treatment, tax-exempt organizations (including private foundations), entities that are treated as partnerships for U.S. federal income tax purposes (or partners therein), holders who are not U.S. Holders, U.S. expatriates, holders who own (directly, indirectly or constructively) 10% or more of our stock (by vote or value), holders who acquire their common shares pursuant to any employee share option or otherwise as compensation, investors that will hold their common shares as part of a straddle, conversion, constructive sale or other integrated transaction for U.S. federal income tax purposes or investors who have a functional currency other than the U.S. dollar, all of whom may be subject to tax rules that differ significantly from those discussed below). This discussion, moreover, does not address the U.S. federal estate and gift tax or alternative minimum tax consequences of the acquisition or ownership of our common shares or the Medicare tax on net investment income. Each U.S. Holder is urged to consult its tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax considerations of an investment in our common shares.

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General

For purposes of this discussion, a “U.S. Holder” is a beneficial owner of our common shares that is, for U.S. federal income tax purposes, (i) an individual who is a citizen or resident of the United States, (ii) a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created in, or organized under the laws of, the United States or any state thereof or the District of Columbia, (iii) an estate the income of which is includible in gross income for U.S. federal income tax purposes regardless of its source or (iv) a trust (A) the administration of which is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust or (B) that has otherwise validly elected to be treated as a U.S. person under the Code for U.S. federal income tax purposes.

If a partnership (or other entity treated as a partnership for U.S. federal income tax purposes) is a beneficial owner of our common shares, the tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. Partnerships holding our common shares and their partners are urged to consult their tax advisors regarding an investment in our common shares.

Dividends

Subject to the discussion below under “Passive Foreign Investment Company Considerations,” any cash distributions (including the amount of any tax withheld) paid on our common shares out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles, will generally be includible in the gross income of a U.S. Holder as dividend income on the day actually or constructively received by the U.S. Holder. Because we do not intend to determine our earnings and profits on the basis of U.S. federal income tax principles, any distribution we pay will generally be treated as a “dividend” for U.S. federal income tax purposes. A non-corporate U.S. Holder will be subject to tax on dividend income from a “qualified foreign corporation” at a lower applicable capital gains rate rather than the marginal tax rates generally applicable to ordinary income; provided that certain holding period and other requirements are met. A non-U.S. corporation (other than a corporation that is classified as a PFIC for the taxable year in which the dividend is paid or the preceding taxable year) will generally be considered to be a qualified foreign corporation (i) if it is eligible for the benefits of a comprehensive tax treaty with the United States which the Secretary of Treasury of the United States determines is satisfactory for purposes of this provision and which includes an exchange of information program, or (ii) with respect to any dividend it pays on stock which is readily tradable on an established securities market in the United States. We intend to apply to list the Shares on the New York Stock Exchange. Provided the listing is approved on the New York Stock Exchange, which is an established securities market in the United States, the Shares are expected to be readily tradable. There can be no assurance that our Shares will continue to be considered readily tradable on an established securities market in later years.

Dividends will generally be treated as income from foreign sources for U.S. foreign tax credit purposes and will generally constitute passive category income. Depending on the U.S. Holder’s individual facts and circumstances, a U.S. Holder may be eligible, subject to a number of complex limitations, to claim a foreign tax credit not in excess of any applicable treaty rate in respect of any foreign withholding taxes imposed on dividends received on our common shares. A U.S. Holder who does not elect to claim a foreign tax credit for foreign tax withheld may instead claim a deduction, for U.S. federal income tax purposes, in respect of such withholding, but only for a year in which such holder elects to do so for all creditable foreign income taxes. The rules governing the foreign tax credit are complex and their outcome depends in large part on the U.S. Holder’s individual facts and circumstances. Accordingly, U.S. Holders are urged to consult their tax advisors regarding the availability of the foreign tax credit under their particular circumstances.

Sale or Other Disposition of our Shares

Subject to the discussion below under “Passive Foreign Investment Company Considerations,” a U.S. Holder will generally recognize capital gain or loss upon the sale or other disposition of common shares in an amount equal to the difference between the amount realized upon the disposition and the holder’s adjusted tax basis in such common shares. Any capital gain or loss will be long-term if the common shares have been held for more than one year and will generally be U.S. source gain or loss for U.S. foreign tax credit purposes.

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Long-term capital gains of non-corporate U.S. Holders are currently eligible for reduced rates of taxation. The deductibility of a capital loss may be subject to limitations. U.S. Holders are urged to consult their tax advisors regarding the tax consequences if a foreign tax is imposed on a disposition of our common shares, including the availability of the foreign tax credit under their particular circumstances.

Passive Foreign Investment Company Considerations

A non-U.S. corporation, such as the Company, will be classified as a passive foreign investment company, or PFIC, for U.S. federal income tax purposes, if, in the case of any particular taxable year, either (i) 75% or more of its gross income for such year consists of certain types of “passive” income or (ii) 50% or more of the value of its assets (determined on the basis of a quarterly average) during such year is attributable to assets that produce or are held for the production of passive income. For this purpose, cash and assets readily convertible into cash are categorized as a passive asset and the company’s goodwill and other unbooked intangibles associated with active business activities may generally be classified as active assets. Passive income generally includes, among other things, dividends, interest, rents, royalties and gains from the disposition of passive assets. However, passive income does not include income derived from the performance of services. We will be treated as owning a proportionate share of the assets and earning a proportionate share of the income of any other corporation in which we own, directly or indirectly, at least 25% (by value) of the stock.

Based upon our current and projected income and assets, including the proceeds from this Offering, and projections as to the value of our assets, we do not believe we were a PFIC for the taxable year ended December 31, 2018, and we do not expect to be a PFIC for the current taxable year or in the foreseeable future. In making this determination, we believe that any income we receive from offshore drilling service contracts should be treated as “services income” as opposed to passive income under the PFIC rules. In addition, the assets we own and utilize to generate this “services income” should not be considered passive assets for purposes of the PFIC rules. However, because these determinations are based on the nature of our income and assets from time to time, as well as involving the application of complex tax rules, and because our view is not binding on the courts or the IRS, no assurances can be provided that we will not be considered a PFIC for the current, or any past or future tax year. While we do not expect to be or become a PFIC in the current or future taxable years, the determination of whether we are or will become a PFIC will depend on our income, assets and activities in each year. No assurance can be given that the composition of our income or assets will not change in a manner that could make us a PFIC in the future. Under circumstances where we determine not to deploy significant amounts of cash for capital expenditures and other general corporate purposes, our risk of becoming classified as a PFIC may substantially increase.

Because determination of PFIC status is a fact-intensive inquiry made on an annual basis and will depend upon the composition of our assets and income, and the continued existence of our goodwill at that time, no assurance can be given that we are not or will not become classified as a PFIC. If we are classified as a PFIC for any year during which a U.S. Holder holds our common shares, we generally will continue to be treated as a PFIC with respect to such U.S. Holder for all succeeding years during which such U.S. Holder holds our common shares, regardless of whether we meet the PFIC tests described above.

If we are classified as a PFIC for any taxable year during which a U.S. Holder holds our common shares, and unless the U.S. Holder makes a mark-to-market election (as described below), the U.S. Holder will generally be subject to special tax rules that have a penalizing effect, regardless of whether we remain a PFIC, on (i) any excess distribution that we make to the U.S. Holder (which generally means any distribution paid during a taxable year to a U.S. Holder that is greater than 125% of the average annual distributions paid in the three preceding taxable years or, if shorter, the U.S. Holder’s holding period for the common shares) and (ii) any gain realized on the sale or other disposition, including an indirect disposition such as a pledge, of common shares. Under the PFIC rules:

• the excess distribution or gain will be allocated ratably over the U.S. Holder’s holding period for the common shares;

• the amount allocated to the current taxable year and any taxable years in the U.S. Holder’s holding period prior to the first taxable year in which we are classified as a PFIC (each, a “pre-PFIC year”), will be taxable as ordinary income;

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• the amount allocated to each prior taxable year, other than a pre-PFIC year, will be subject to tax at the highest marginal tax rate in effect for individuals or corporations, as appropriate, for that year; and

• the interest charge generally applicable to underpayments of tax will be imposed on the tax attributable to each prior taxable year, other than a pre-PFIC year.

If we are a PFIC for any taxable year during which a U.S. Holder holds our common shares and any of our subsidiaries is also a PFIC, such U.S. Holder would be treated as owning a proportionate amount (by value) of the shares of the lower-tier PFIC for purposes of the application of these rules. U.S. Holders are urged to consult their tax advisors regarding the application of the PFIC rules to any of our subsidiaries.

As an alternative to the foregoing rules, a U.S. Holder of “marketable stock” in a PFIC may make a mark-to-market election with respect to such stock, provided that such stock is regularly traded. For those purposes, our Shares will be treated as marketable stock upon their listing on the New York Stock Exchange. We anticipate that our Shares should qualify as being regularly traded, but no assurances may be given in this regard. If a U.S. Holder makes this election, the holder will generally (i) include as ordinary income for each taxable year that we are a PFIC the excess, if any, of the fair market value of Shares held at the end of the taxable year over the adjusted tax basis of such Shares and (ii) deduct as an ordinary loss the excess, if any, of the adjusted tax basis of the Shares over the fair market value of such Shares held at the end of the taxable year, but such deduction will only be allowed to the extent of the amount previously included in income as a result of the mark-to-market election. The U.S. Holder’s adjusted tax basis in the Shares would be adjusted to reflect any income or loss resulting from the mark-to-market election. If a U.S. Holder makes a mark-to-market election in respect of our Shares and we cease to be classified as a PFIC, such U.S. Holder will not be required to take into account the gain or loss described above during any period that we are not classified as a PFIC. If a U.S. Holder makes a mark-to-market election, any gain such U.S. Holder recognizes upon the sale or other disposition of our Shares in a year when we are a PFIC will be treated as ordinary income and any loss will be treated as ordinary loss, but such loss will only be treated as ordinary loss to the extent of the net amount previously included in income as a result of the mark-to-market election.

Because a mark-to-market election can be made only with respect to marketable stock, such election generally will not be available for any lower-tier PFICs that we may own. Therefore, if we are treated as a PFIC, a U.S. Holder may continue to be subject to the PFIC rules with respect to such U.S. Holder’s indirect interest in any investments held by us that are treated as an equity interest in a PFIC for U.S. federal income tax purposes.

We do not intend to provide information necessary for U.S. Holders to make qualified electing fund elections which, if available, would result in tax treatment different from the general tax treatment for PFICs described above.

If a U.S. Holder owns our common shares during any taxable year that we are a PFIC, the holder must generally file an annual IRS Form 8621 or such other form as is required by the U.S. Treasury Department. Each U.S. Holder is advised to consult its tax advisor regarding the potential tax consequences to such holder if we are or become a PFIC, including the possibility of making a mark-to-market election.

Foreign Financial Asset Reporting

Certain U.S. Holders are required to report information to the IRS relating to an interest in “specified foreign financial assets,” including shares issued by a non-U.S. corporation, for any year in which the aggregate value of all specified foreign financial assets held by such U.S. Holder exceeds $50,000 (or a higher dollar amount prescribed by the IRS), subject to certain exceptions (including an exception for shares held in custodial accounts maintained with a U.S. financial institution). These rules also impose penalties if a U.S. Holder is required to submit such information to the IRS and fails to do so.

In addition, U.S. Holders may be subject to information reporting to the IRS with respect to dividends on and proceeds from the sale or other disposition of our common shares. Each U.S. Holder is advised to consult with its tax advisor regarding the application of the United States information reporting rules to their particular circumstances.

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UNDERWRITING

The Company and the underwriters named below have entered into an underwriting agreement with respect to the common shares being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of common shares indicated in the following table. Goldman Sachs & Co. LLC and DNB Markets, Inc. are the representatives of the underwriters.

Underwriters	Number of Common Shares
Goldman Sachs & Co. LLC		2,184,466
DNB Markets, Inc.		1,067,961
BTIG, LLC		582,524
Citigroup Global Markets Inc.		194,175
Danske Markets Inc.		194,175
Evercore Group L.L.C.		194,175
Fearnley Securities, Inc.		582,524
Total		5,000,000

The underwriters are committed to take and pay for all of the common shares being offered, if any are taken, other than the common shares covered by the option described below unless and until this option is exercised.

The underwriters have an option to buy up to an additional 750,000 common shares from the Company to cover sales by the underwriters of a greater number of common shares than the total number set forth in the table above. They may exercise that option for 30 days. If any common shares are purchased pursuant to this option, the underwriters will severally purchase common shares in approximately the same proportion as set forth in the table above.

The following table shows the per common share and total underwriting discounts and commissions to be paid to the underwriters by the Company. Such amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase an additional 750,000 common shares.

Paid by the Company

	No Exercise		Full Exercise
Per Share	$	0.515	$	0.515
Total	$	2,575,000	$	2,961,250

We have agreed to reimburse the underwriters for certain of their expenses in an amount up to $425,000. We estimate that our portion of the total expenses of the Offering, excluding underwriting discounts and commissions, will be approximately $2.9 million.

Common shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common shares sold by the underwriters to securities dealers may be sold at a discount of up to $0.309 per common share from the initial public offering price. After the initial offering of the common shares, the representatives may change the offering price and the other selling terms. The offering of the common shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The Company and its executive officers, directors, and certain of its shareholders have agreed with the underwriters, subject to certain exceptions, not to dispose of or hedge any of their common shares or securities convertible into or exchangeable for common shares during the period from the date of this prospectus continuing through the date 180 days after the date of this prospectus, except with the prior written consent of Goldman Sachs & Co. LLC. This agreement does not apply to any existing employee benefit plans. See “Shares Eligible for Future Sale” for a discussion of certain transfer restrictions.

Prior to this Offering, there has been no public market in the United States for our common shares. Neither we nor the underwriters can assure investors that an active trading market will develop for our common shares, or that our common shares will trade in the public market at or above the initial public offering price.

Our common shares have been approved for listing on the NYSE under the symbol “BORR.”

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In connection with the Offering, the underwriters may purchase and sell common shares in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of common shares than they are required to purchase in the Offering, and a short position represents the amount of such sales that have not been covered by subsequent purchases. A “covered short position” is a short position that is not greater than the amount of additional common shares for which the underwriters’ option described above may be exercised. The underwriters may cover any covered short position by either exercising their option to purchase additional common shares or purchasing common shares in the open market. In determining the source of common shares to cover the covered short position, the underwriters will consider, among other things, the price of common shares available for purchase in the open market as compared to the price at which they may purchase additional common shares pursuant to the option described above. “Naked” short sales are any short sales that create a short position greater than the amount of additional common shares for which the option described above may be exercised. The underwriters must cover any such naked short position by purchasing common shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common shares in the open market after pricing that could adversely affect investors who purchase in the Offering. Stabilizing transactions consist of various bids for or purchases of common shares made by the underwriters in the open market prior to the completion of the Offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common shares sold by or for the account of such underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the Company’s common shares, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common shares. As a result, the price of the common shares may be higher than the price that otherwise might exist in the open market. The underwriters are not required to engage in these activities and may end any of these activities at any time. These transactions may be effected on the NYSE, in the over-the-counter market or otherwise.

The Company has agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act of 1933.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to the issuer and to persons and entities with relationships with the issuer, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of the issuer (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships with the issuer. The underwriters and their respective affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such assets, securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

In addition, Goldman Sachs & Co. LLC and DNB Markets, Inc. are acting as the representatives for the underwriters in connection with this Offering. Goldman Sachs Bank USA, an affiliate of Goldman Sachs & Co. LLC, is party to, and has acted as lender under, our Syndicated RCF. DNB Bank ASA, an affiliate of DNB Markets, Inc, is party to, and has acted as lender under, our Syndicated RCF and our New Bridge RCF.

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Citibank N.A., Jersey Branch, an affiliate of Citigroup Global Markets Inc., is party to, and has acted as lender under, our Syndicated RCF. Danske Bank, an affiliate of Danske Markets Inc., is party to, and has acted as lender under, our Syndicated RCF and our New Bridge RCF.

European Economic Area

In relation to each member state of the European Economic Area (each, a “Member State”) an offer to the public of our common shares may not be made in that Member State, except that an offer to the public in that Member State of our common shares may be made at any time under the following exemptions under the Prospectus Regulation:

(a) to any legal entity which is a qualified investor as defined in the Prospectus Regulation;

(b) to fewer than 150 natural or legal persons (other than qualified investors as defined in the Prospectus Regulation), subject to obtaining the prior consent of the Representatives for any such offer; or

(c) in any other circumstances falling within Article 1(4) of the Prospectus Regulation,

provided that no such offer of our common shares shall result in a requirement for the publication by us or any underwriter of a prospectus pursuant to Article 3 of the Prospectus Regulation.

For the purposes of this provision, the expression an “offer to the public” in relation to our common shares in any Member State means the communication in any form and by any means of sufficient information on the terms of the offer and our common shares to be offered so as to enable an investor to decide to purchase our common shares, and the expression “Prospectus Regulation” means Regulation (EU) 2017/1129.

This European Economic Area selling restriction is in addition to any other selling restrictions set out below.

United Kingdom

In the United Kingdom, this prospectus is only addressed to and directed at qualified investors who are (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”); or (ii) high net worth entities and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (e) of the Order (all such persons together being referred to as “relevant persons”). Any investment or investment activity to which this prospectus relates is available only to relevant persons and will only be engaged with relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

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EXPENSES RELATED TO THIS OFFERING

Set forth below is an itemization of the total expenses, excluding underwriting discounts and commissions, that we expect to incur in connection with this Offering. With the exception of the SEC registration fee, the FINRA filing fee, and the stock exchange application and listing fee, all amounts are estimates.

SEC Registration Fee	$	6,885
FINRA Fee		15,500
Stock Exchange Application and Listing Fee		150,000
Printing and Engraving Expenses		135,000
Legal Fees and Expenses		1,535,000
Accounting Fees and Expenses		1,016,156
Miscellaneous		41,459
Total	$	2,900,000

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LEGAL MATTERS

We are being represented by Skadden, Arps, Slate, Meagher & Flom (UK) LLP with respect to certain legal matters as to United States federal securities and New York State law. The underwriters are being represented by Baker Botts L.L.P., Washington D.C., with respect to certain legal matters as to United States federal securities and New York State law. The validity of the common shares offered in this Offering, and certain legal matters as to Bermuda law, will be passed upon by MJM Limited. Skadden, Arps, Slate, Meagher & Flom (UK) LLP and Baker Botts L.L.P., Washington D.C., may rely upon MJM Limited with respect to matters governed by Bermuda law.

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EXPERTS

The financial statements of Borr Drilling Limited and subsidiaries, as of December 31, 2018 and December 31, 2017 and for each of the two years in the period ended December 2018 included in this Prospectus have been so included in reliance on the report (which contains an explanatory paragraph relating to the matters that alleviate previous substantial doubt about the Company’s ability to continue as a going concern as described in Note 1 to the financial statements and an explanatory paragraph relating to the restatement of previously issued financial statements) of PricewaterhouseCoopers AS, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Paragon Offshore Limited as of March 28, 2018 and for the period from January 1, 2018 to March 28, 2018 included in this Prospectus have been so included in reliance on the report (which contains an explanatory paragraph relating to the Company's ability to continue as a going concern as described in Note 1 to the financial statements) of PricewaterhouseCoopers AS, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The financial statements of Paragon Offshore Limited as of December 31, 2017 and for the period July 18, 2017 to December 31, 2017 (Successor) and the financial statements for the period January 1, 2017 to July 18, 2017 (Predecessor) included in this Prospectus have been so included in reliance on the reports (which contain explanatory paragraphs relating to the Predecessor’s ability to continue as a going concern as described in note 1 to the Predecessor financial statements and the Successor’s transfer of certain direct and indirect subsidiaries and certain other assets on July 18, 2017 as described in note 1 to the financial statements) of PricewaterhouseCoopers LLP, an independent accountant, given on the authority of said firm as experts in auditing and accounting.

The section in this Prospectus entitled “Industry Overview,” the other information appearing in this Prospectus as attributed to Rystad Energy and the additional information based on such section and on such other information has been reviewed by Rystad Energy, which has confirmed to us that such section, such other information and such additional information accurately describes the offshore exploration, development and production industry and the contract drilling services industry, subject to the availability and reliability of the data supporting the statistical and graphical information presented in this Prospectus, including ours and other companies’ relative performance and position in the contract drilling services industry, as indicated in the consent of Rystad Energy filed as an exhibit to this registration statement on Form F-1 under the Securities Act of which this Prospectus is a part. The address of Rystad Energy is Fjordalléen 16, 0250 Oslo, Norway.

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ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS

We are a Bermuda exempted company limited by shares. As a result, the rights of holders of our common shares will be governed by Bermuda law and our Memorandum and Bye-Laws. The rights of shareholders under Bermuda law may differ from the rights of shareholders of companies incorporated in other jurisdictions. We were incorporated in Bermuda in order to run the business and enjoy certain benefits, such as political and economic stability, an effective judicial system, a favorable tax system, the absence of exchange control or currency restrictions and the availability of professional and support services. However, certain disadvantages accompany incorporation in Bermuda. These disadvantages include a less developed body of Bermuda securities laws that provide significantly less protection to investors as compared to the laws of other jurisdictions, such as the United States or any state, and the potential lack of standing by Bermuda companies to sue before the federal courts of the United States.

Many of our directors and some of the named experts referred to in this Prospectus are not residents of the United States, and a substantial portion of our assets are located outside the United States. As a result, it may be difficult for investors to effect service of process on those persons in the United States or to enforce in the United States judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws or of any state of the United States.

We have appointed Puglisi & Associates as our agent upon whom process may be served in any action brought against us under the laws of the United States. It is doubtful whether courts in Bermuda will enforce judgments obtained in other jurisdictions, including the United States, against us or our directors or officers under the securities laws of those jurisdictions or entertain actions in Bermuda against us or our directors or officers under the securities laws of other jurisdictions.

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WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed a registration statement, including relevant exhibits, with the SEC on Form F-1 under the Securities Act with respect to the Shares to be sold as contemplated by this Prospectus. This Prospectus, which constitutes a part of the registration statement on Form F-1, does not contain all of the information contained in the registration statement. You should read our registration statement and the exhibits and schedules thereto for further information with respect to us and our Shares.

Immediately upon the effectiveness of the registration statement on Form F-1 of which this Prospectus forms a part, we will become subject to periodic reporting and other informational requirements of the Exchange Act as applicable to foreign private issuers. Accordingly, we will be required to file reports, including annual reports on Form 20-F, and other information with the SEC. All information filed with the SEC can be obtained over the internet at the SEC’s website at www.sec.gov.

In addition, following the closing of this Offering, we will make the information filed with or furnished to the SEC available free of charge through our website (www.borrdrilling.com) or by calling us at +1 (441) 737-0152 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on our website is not a part of this Prospectus.

As a foreign private issuer, we are exempt under the Exchange Act from, among other things, the rules prescribing the furnishing and content of proxy statements. While we furnish proxy statements to shareholders in accordance with the rules of any stock exchange on which our common shares may be listed in the future, those proxy statements will not conform to Schedule 14A of the proxy rules promulgated under the Exchange Act. Our executive officers, directors and principal shareholders are also exempt from the reporting and short-swing profit recovery provisions contained in section 16 of the Exchange Act. Although we will not be required under the Exchange Act to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act, we will furnish holders of our Shares with annual reports containing audited financial statements and a report by our independent registered public accounting firm and intend to make available quarterly reports containing selected unaudited financial data for the first three quarters of each fiscal year. The audited financial statements will be prepared in accordance with U.S. GAAP and those reports will include a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section for the relevant periods.

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INDEX TO THE CONSOLIDATED FINANCIAL STATEMENTS

	Page
Borr Drilling Limited Unaudited Condensed Consolidated Interim Financial Statements for the Three Months ended March 31, 2019 and 2018
Unaudited Condensed Consolidated Statements of Operations for the three months ended March 31, 2019 and 2018		F-2
Unaudited Condensed Consolidated Statement of Comprehensive Income (Loss) for the three months ended March 31, 2019 and 2018		F-3
Unaudited Condensed Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018		F-4
Unaudited Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018		F-6
Unaudited Condensed Consolidated Statement of Changes in Shareholders’ Equity for the three months ended March 31, 2019 and 2018		F-7
Notes to the Unaudited Condensed Consolidated Financial Statements		F-8
Borr Drilling Limited Consolidated Financial Statements as of and for the Years ended December 31, 2018 and 2017
Report of Independent Registered Public Accounting Firm		F-25
Consolidated Statements of Operations for the years ended December 31, 2018 and 2017		F-26
Consolidated Statements of Comprehensive Income / (Loss) for the years ended December 31, 2018 and 2017		F-27
Consolidated Balance Sheets as of December 31, 2018 and 2017		F-28
Consolidated Statements of Cash Flows for the years ended December 31, 2018 and 2017		F-30
Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2018 and 2017		F-31
Notes to the Consolidated Financial Statements		F-32
Paragon Offshore Limited Consolidated Financial Statements for the Predecessor as of and for the period from January 1, 2017 to July 18, 2017 and the Successor for the period from July 18, 2017 to December 31, 2017
Reports of the Independent Auditors, for the Predecessor and the Successor, respectively		F-67
Consolidated Statements of Operations for the period from January 1, 2017 to July 18, 2017 and the Successor for the periods from July 18, 2017 to December 31, 2017		F-69
Consolidated Statements of Comprehensive Income / (Loss) for the period from January 1, 2017 to July 18, 2017 and the Successor for the periods from July 18, 2017 to December 31, 2017		F-70
Consolidated Balance Sheet as of December 31, 2017		F-71
Consolidated Statements of Changes in Equity for the period from January 1, 2017 to July 18, 2017 and the Successor for the periods from July 18, 2017 to December 31, 2017		F-72
Consolidated Statements of Cash Flows for the period from January 1, 2017 to July 18, 2017 and the Successor for the periods from July 18, 2017 to December 31, 2017		F-73
Notes to the Consolidated Financial Statements		F-74
Paragon Offshore Limited Consolidated Financial Statements as of and for the period from January 1, 2018 to March 28, 2018
Report of Independent Auditor		F-109
Consolidated Statements of Operations for the period from January 1, 2018 to March 28, 2018		F-110
Consolidated Statements of Comprehensive Income / (Loss) for the period from January 1, 2018 to March 28, 2018		F-111
Consolidated Balance Sheet as of March 28, 2018		F-112
Consolidated Statements of Cash Flows for the period from January 1, 2018 to March 28, 2018		F-113
Consolidated Statements of Changes in Equity for the period from January 1, 2018 to March 28, 2018		F-114
Notes to the Consolidated Financial Statements		F-115

F-1

BORR DRILLING LIMITED
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In $ millions except per share data)

	Notes	Three months ended March 31, 2019			Three months ended March 31, 2018
Operating revenues	3		51.9			10.6
Gain from bargain purchase	11		—			38.1
Operating expenses
Rig operating and maintenance expenses			(57.1	)		(22.5	)
Depreciation of non-current assets	7		(23.9	)		(12.2	)
Impairment of non-current assets	7		(11.4	)		—
Amortisation of contract backlog	11		(7.4	)		—
General and administrative expenses	19		(10.1	)		(10.2	)
Restructuring costs	11		—			(17.9	)
Total operating expenses			(109.9	)		(62.8	)
Operating loss			(58.0	)		(14.1	)
Other income (expenses), net
Interest income			0.3			0.5
Interest expense	18		(13.0	)		—
Other, net	4, 14		14.5			(20.2	)
Total other income (expenses), net			1.8			(19.7	)
Loss before income taxes			(56.2	)		(33.8	)
Income tax expense	5		(0.2	)		—
Net loss			(56.4	)		(33.8	)
Net loss attributable to non-controlling interests			(1.5	)		(0.1	)
Net loss attributable to shareholders of Borr Drilling Limited			(54.9	)		(33.7	)
Basic loss per share	6		(0.52	)		(0.35	)
Diluted loss per share	6		(0.52	)		(0.35	)
Weighted-average shares outstanding			105,068,351			96,498,185

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

F-2

BORR DRILLING LIMITED
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (LOSS)
(In $ millions)

	Notes	Three months ended March 31, 2019			Three months ended March 31, 2018
Condensed Consolidated Statement of Comprehensive Income (Loss)
Loss after income taxes			(56.4	)		(33.8	)
Unrealised gain (loss) from marketable securities	13		(7.3	)		—
Other comprehensive loss			(7.3	)		—
Total comprehensive loss			(63.7	)		(33.8	)
Comprehensive loss for the period attributable to
Shareholders of Borr Drilling Limited			(62.2	)		(33.7	)
Non-controlling interests			(1.5	)		(0.1	)
Total comprehensive loss			(63.7	)		(33.8	)

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

F-3

BORR DRILLING LIMITED
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET
(In $ millions)

	Notes	March 31, 2019		December 31, 2018
ASSETS
Current assets
Cash and cash equivalents			29.4		27.9
Restricted cash	12		29.4		63.4
Trade accounts receivables			25.7		25.1
Jack-up drilling rigs held for sale	7		—		—
Marketable securities	13		26.8		4.2
Prepaid expenses			10.0		10.8
Acquired contract backlog			12.8		20.2
Deferred mobilization costs			18.2		6.0
Accrued revenue			18.5		18.9
Tax retentions receivable			11.6		11.6
Other current assets	15		27.1		20.5
Total current assets			209.5		208.6
Non-current assets
Property, plant and equipment			7.1		9.5
Jack-up drilling rigs	7		2,416.1		2,278.1
Newbuildings	8		432.5		361.8
Deferred mobilization costs			7.5		5.1
Marketable securities	13		—		31.0
Other long-term assets	16		25.7		19.6
Total non-current assets			2,888.9		2,705.1
Total assets			3,098.4		2,913.7
LIABILITIES AND EQUITY
Current liabilities
Trade accounts payables			14.7		9.6
Amounts due to related parties	22		0.8		0.4
Unrealized loss on forward contracts			23.6		35.1
Accrued expenses			66.8		63.7
Onerous contracts			—		3.2
Current portion of long-term debt	18		58.5		—
Other current liabilities	21		18.4		7.3
Total current liabilities			182.8		119.3
Non-current liabilities
Long-term debt	18		1,356.9		1,174.6
Other liabilities			15.6		8.0
Onerous contracts	17		71.3		78.3
Total non-current liabilities			1,443.8		1,260.9
Total liabilities			1,626.6		1,380.2
Commitments and contingencies	23

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

F-4

BORR DRILLING LIMITED
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET
(In $ millions)

	Notes	March 31, 2019			December 31, 2018
Stockholders’ Equity
Common shares of par value $0.05 per share: authorized 125,000,000 (2018: 125,000,000) shares, issued 106,528,065 (2018:106,528,065) shares and outstanding 105,068,351 (2018: 105,068,351) shares at March 31, 2019			5.3			5.3
Additional paid in capital			1,839.5			1,837.5
Treasury shares			(26.2	)		(26.2	)
Other comprehensive loss			(12.9	)		(5.6	)
Accumulated deficit			(334.1	)		(279.2	)
Equity attributable to the Company			1,471.6			1,531.8
Non-controlling interest			0.2			1.7
Total equity			1,471.8			1,533.5
Total liabilities and equity			3,098.4			2,913.7

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

F-5

BORR DRILLING LIMITED
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(In $ millions)

	Notes	Three months ended March 31, 2019			Three months ended March 31, 2018
Cash Flows from Operating Activities
Net (loss)/income			(56.4	)		(33.8	)
Adjustments to reconcile net (loss)/income to net cash (used in)/ provided by operating activities:
Non-cash compensation expense related to stock options and warrants	19		2.0			0.4
Depreciation of non-current assets	7		23.9			12.2
Impairment of non-current assets	7		11.4			—
Amortisation of acquired contract backlog	11		7.4			—
Unrealized (gain) loss on financial instruments	4		(15.1	)		20.0
Bargain purchase gain	11		—			(38.1	)
Deferred income tax	5		(0.3	)		—
Change in other current and non-current assets			(2.0	)		(10.6	)
Change in current and non-current liabilities			15.2			4.5
Net cash (used in)/provided by operating activities			(13.9	)		(45.4	)
Cash Flows from Investing Activities
Purchase of plant and equipment			—			—
Proceeds from sale of fixed assets			0.6			—
Purchase business combination (acquisition), net of cash acquired	9		—			(194.1	)
Purchase of marketable securities	13		(4.0	)		—
Proceeds from sale of marketable securities	13		4.2			—
Additions to newbuildings	8		(129.0	)		(0.6	)
Additions to jack-up rigs	7		(43.9	)		(4.1	)
Net cash (used in)/provided by investing activities			(172.1	)		(198.8	)
Cash Flows from Financing Activities
Proceeds from share issuance, net of issuance costs and conversion of shareholders loans			—			211.5
Proceeds from related party shareholder loan	22		—			27.7
Purchase of treasury shares			—			(2.3	)
Repayment of long-term debt	9		—			(89.3	)
Purchase of financial instruments	13		—			—
Proceeds, net of deferred loan costs, from issuance of long-term debt	18		95.0			—
Proceeds, net of deferred loan costs, from issuance of short-term debt	18		58.5			—
Net cash (used in)/provided by financing activities			153.5			147.6
Net increase (decrease) in cash and cash equivalents			(32.5	)		(96.6	)
Cash and cash equivalents and restricted cash at beginning of the period			91.3			203.1
Cash, cash equivalents and restricted cash at the end of period			58.8			106.5
Supplementary disclosure of cash flow information
Interest paid, net of capitalized interest			(8.7	)		—
Income taxes paid			(1.7	)		—
Issuance of long-term debt as non-cash settlement for newbuild delivery instalment	18		87.0
Non-cash payments and cost in respect of jack-up rigs	7		17.0			—

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

F-6

BORR DRILLING LIMITED
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(In $ millions except share data)

	Number of shares			Common shares		Treasury shares			Additional paid in capital			Other Comprehensive Loss			Accumulated Deficit			Non- controlling interest			Total equity
Consolidated balance at December 31, 2017		95,264,500			4.8		(6.7	)		1,587.8			(6.2	)		(88.8	)		2.0			1,492.9
Issue of common shares		9,341,500			0.4		—			214.3			—			—			—			214.7
Equity issuance costs		—			—		—			(3.3	)											(3.3	)
Other transactions:
Share-based compensation		—			—		—			0.4			—			—			—			0.4
Purchase of treasury shares		(100,000	)		—		(2.3	)		—			—			—			—			(2.3	)
Total comprehensive loss		—			—		—			—			—			(33.7	)		(0.1	)		(33.8	)
Non-controlling interest		—			—		—			—			—			—			1.3			1.3
Other, net										0.1						—			—			0.1
Consolidated balance at March 31, 2018		104,506,000			5.2		(9.0	)		1,799.3			(6.2	)		(122.5	)		3.2			1,670.0
Issue of common shares		1,528,065			0.1		—			35.1			—			—			—			35.2
Equity issuance costs		—			—		—			(0.1	)											(0.1	)
Other transactions:
Stock-based compensation		—			—		—			3.4			—			—			—			3.4
Settlement of directors’ fees		—			—		0.2			(0.2	)		—			—			—			—
Purchase of treasury shares		(1,359,714	)		—		(17.4	)		—			—			—			—			(17.4	)
Total comprehensive loss		—			—		—			—			0.6			(156.8	)		(0.4	)		(156.6	)
Non-controlling interest		—			—		—			—			—			0.1			(1.1	)		(1.0	)
Other, net										—						—			—			—
Consolidated balance at December 31, 2018		105,068,351			5.3		(26.2	)		1,837.5			(5.6	)		(279.2	)		1.7			1,533.5
Stock-based compensation		—			—		—			2.0			—			—			—			2.0
Total comprehensive loss		—			—		—			—			(7.3	)		(54.9	)		(1.5	)		(63.7	)
Other, net		—			—		—
Consolidated balance at March 31, 2019		105,068,351			5.3		(26.2	)		1,839.5			(12.9	)		(334.1	)		0.2			1,471.8

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

F-7

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - General information

Borr Drilling Limited was incorporated in Bermuda on August 8, 2016. The Company is listed on the Oslo Stock Exchange, under the ticker BDRILL. Borr Drilling Limited is an international offshore drilling contractor providing services to the oil and gas industry, with the ambition of acquiring and operating modern jack-up drilling rigs. As of March 31, 2019, the total fleet consisted of 27 jack-up rigs and one semi-submersible drilling rig, and an additional 8 jack-up rigs that are scheduled for delivery between 2019 and 2020.

As used herein, and unless otherwise required by the context, the term “Borr Drilling” refers to Borr Drilling Limited and the terms “Company,”, “Borr”, “we,” “Group,” “our” and words of similar import refer to Borr Drilling and its consolidated companies. The use herein of such terms as “group”, “organisation”, “we”, “us”, “our” and “its”, or references to specific entities, is not intended to be a precise description of corporate relationships.

Basis of presentation

We have prepared our accompanying unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the United States (“U.S.”) for interim financial information. Pursuant to such rules and regulations, these financial statements do not include all disclosures required by accounting principles generally accepted in the U.S. for complete financial statements. The condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair statement of financial position, results of operations and cash flows for the interim periods. Operating results for the three months ended March 31, 2019, are not necessarily indicative of the results that may be expected for the year ending December 31, 2019, or for any future period. The accompanying condensed consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto including the Company’s annual report for the year ended December 31, 2018. The amounts are presented in millions of United States dollars (U.S. dollar), unless otherwise stated. The financial statements have been prepared on a going concern basis.

Certain amounts in prior periods have been reclassified to conform to current presentation, including the bargain purchase gain reported in the first quarter of 2018 that has been reclassified as part of operating items. Such reclassifications did not have a material effect on our consolidated statement of financial position, results of operations or cash flows.

The Condensed Consolidated Financial Statements present the financial position of Borr Drilling Limited and its subsidiaries. Investments in companies in which the Company controls, or directly or indirectly holds more than 50% of the voting control are consolidated in the financial statements.

Subsequent events have been reviewed from the period end to June 7, 2019.

Basis of consolidation

The consolidated financial statements include the assets and liabilities of the Company. All intercompany balances, transactions and internal sales have been eliminated on consolidation. Unrealized gains and losses arising from transactions with affiliates are eliminated to the extent of the Company’s interest in the entity. The non-controlling interests of subsidiaries were included in the Consolidated Balance Sheets and Statements of Operations as “Non-controlling interests”. Profit or loss and each component of other comprehensive income are attributed to the equity holders of the parent of the Group and to the non-controlling interests, even if this results in the non-controlling interests having a deficit balance.

Going concern

The consolidated financial statements have been prepared on a going concern basis. The Company has, as of June 28, 2019 finalized and partly drawn on secured financing arrangements in the total amount of $645 million, which were used to refinance all of its credit facilities of $510 million. The Company’s new financing arrangements include a $195 million senior secured term loan facility agreement with funds

F-8

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

managed by Hayfin Capital Management LLP, as lenders, among others, a $450 million senior secured credit facilities agreement with DNB Bank ASA, Danske Bank, Citibank N.A., Jersey Branch and Goldman Sachs Bank USA, as lenders, among others (consisting of a $230 million credit facility, $50 million newbuild facility, $70 million for the issuance of guarantees and other trade finance instruments as required in the ordinary course of business and a $100 million incremental facility) and a $100 million senior secured revolving facility agreement with Danske Bank and DNB Bank ASA, as lenders, among others. The financing arrangements contain certain financial and non-financial covenants, including restrictions that require the approval of our lenders prior to the distribution of any dividend. The outstanding obligations under the new financing arrangements will mature in 2022. Based on the execution of the financing arrangements, we believe the prior conclusion on April 29, 2019 of substantial doubt over going concern has been alleviated.

Reverse Share Split

We have effected a conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. Our post-Reverse Share Split Shares began to trade on the Oslo Børs on June 26, 2019.

Use of estimates

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

Note 2 - Accounting policies

The accounting policies used in the preparation of the condensed interim consolidated financial statements are consistent with those followed in the preparation of the Company’s consolidated financial statements for the year ended December 31, 2018. None of the new accounting standards or amendments that were adopted as of the first quarter of 2019 had a significant effect on the condensed interim consolidated financial statements, except as described below.

Recently Issued Accounting Standards

Adoption of new accounting standards

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02 (Topic 842, “Leases”), as amended, which generally requires lessees to recognize operating and financing lease liabilities and corresponding right-of-use (ROU) assets on the balance sheet and to provide enhanced disclosures surrounding the amount, time and uncertainty of cash flows arising from lease agreements. We adopted this standard, on a modified retrospective basis, effective January 1, 2019 and will not restate comparative periods. With respect to leases in which we are the lessee, we recognized a lease liability of $12.1 million and a corresponding right-of-use asset of approximately $2.0 million as of January 1, 2019. Adoption of this standard did not materially impact our Consolidated Statement of Operations and had no impact on our Consolidated Statement of Cash Flows.

We have elected the package of practical expedients that permits us to not reassess (1) whether previously expired or existing contracts are or contain leases, (2) the lease classification for any expired or existing leases, and (3) any initial direct costs for any existing leases as of the effective date. In addition, we have elected the hindsight practical expedient in connection with our adoption of the new lease standard. As lessee, we have made the accounting policy election to not recognize a right-of-use asset lease and lease liability for leases with a term of 12 months or less. We will recognize lease payments in the Consolidated Statements of Operations on a straight-line basis over the lease term. We have also elected the practical expedient to not separate lease and non-lease components.

Many of our leases contain variable non-lease components such as maintenance, taxes, insurance, and similar costs for the spaces we occupy. For new and amended leases beginning in 2019 and after, the

F-9

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Company has elected the practical expedient not to separate these non-lease components of leases for classes of all underlying assets and instead account for them as a single lease component for all leases. We straight-line the net fixed payments of operating leases over the lease term and expense the variable lease payments in the period in which we incur the obligation to pay such variable amounts. These variable lease payments are not included in our calculation of our ROU assets or lease liabilities.

As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Certain of our lease agreements include options to extend or terminate the lease, which we do not include in our minimum lease terms unless management is reasonably certain to exercise.

Our drilling contracts contain a lease component related to the underlying drilling equipment, in addition to the service component provided by our crews and our expertise to operate such drilling equipment. We have concluded the non-lease service of operating our equipment and providing expertise in the drilling of the client’s well is predominant in our drilling contracts. We have applied the practical expedient to account for the lease and associated non-lease components as a single component. With the election of the practical expedient, we will continue to present a single performance obligation under the new revenue guidance in Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers.”

In June 2018, the FASB issued ASU No. 2018-07, Compensation – Stock Compensation (Topic 718): Improvements to Nonemployee Share Based-Payment Accounting. This ASU intends to improve the usefulness of information provided and reducing the cost and complexity of financial reporting. A main objective of this ASU is to substantially align the accounting for share-based payments to employees and non-employees. The guidance is effective for annual reporting periods beginning after December 15, 2018 for public entities, including interim periods within that period. Our adoption did not have a material effect on our Condensed Consolidated Financial Statements.

Issued not effective accounting standards

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which revises guidance for the accounting for credit losses on financial instruments within its scope. The new standard introduces an approach, based on expected losses, to estimate credit losses on certain types of financial instruments and modifies the impairment model for available-for-sale debt securities. The guidance will be effective January 1, 2020, with early adoption permitted. Entities are required to apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. We continue to evaluate the requirements and do not expect our adoption to have a material effect on our condensed consolidated statements of financial position, operations or cash flows or on the disclosures contained in our notes to condensed consolidated financial statements.

Note 3 - Revenues

In the three months ended March 31, 2019 and March 31, 2018, the Company recognised revenues of $51.9 million and $10.6 million, respectively, primarily relating to dayrates.

To obtain contracts with our customers, the Company incurs costs to prepare a rig for contract and deliver or mobilise a rig to the drilling location. The Company defers pre-operating costs, such as contract preparation and mobilisation costs, and recognise such costs on a straight-line basis, consistent with the general pace of activity, in rig operating and maintenance costs over the estimated firm period of drilling. In the three months ended March 31, 2019 and March 31, 2018, the Company recognised $0.5 million and $4.2 million, respectively, of pre-operating expenses included in rig operating and maintenance expenses in the Unaudited Condensed Consolidated Statements of Operations.

The Company has one operating segment, and this is reviewed by the Chief Operating Decision Maker, which is the Board, as an aggregated sum of assets, liabilities and activities that exists to generate cash flows.

F-10

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Geographic data

Revenues are attributed to geographical location based on the country of operations for drilling activities, i.e. the country where the revenues are generated.

The following presents our revenues by geographic area:

(In $ millions)	Three months ended March 31, 2019		Three months ended March 31, 2018
North Sea		25.4		0.7
West Africa		11.5		9.4
Middle East		10.5		0.5
South East Asia		3.5		—
Mexico		1.0		—
Total		51.9		10.6

Major customers

The following customers accounted for more than 10% of our contract revenues:

(In % of operating revenues)	Three months ended March 31, 2019			Three months ended March 31, 2018
National Drilling Company (ADOC)		20	%		3	%
TAQA Bratani Limited		17	%		2	%
Perenco Oil Company		14	%		—
Total S.A.		13	%		32	%
Tulip Oil		11	%		—
Centrica North Sea Limited (Spirit Energy)		10	%		1	%
Total		85	%		38	%

Fixed Assets — Jack-up rigs⁽¹⁾

The following presents the net book value of our jack-up rigs by geographic area

(In $ millions)	As of March 31, 2019		As of December 31, 2018
Middle East		42.2		42.0
North Sea		308.4		320.0
West Africa		663.2		203.0
South East Asia		1,284.8		1,713.1
Mexico		117.5		—
Total		2,416.1		2,278.1

(1) The fixed assets referred to in the table above exclude assets under construction. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

Contract balances

Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules.

F-11

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Payment terms on invoiced amounts are typically 30 days. Current contract asset balances are included in “Deferred mobilization costs, Acquired contract backlog and Accrued revenue” and non-current contract assets are included in “Other assets” on our Consolidated Balance Sheets.

The following table provides information about contract assets from contracts with customers:

(In $ millions)	As of March 31, 2019		As of December 31, 2018
Current contract assets		49.5		45.1
Non-current contract assets		7.5		5.1
Total contract assets		57.0		50.2

Significant changes in the remaining performance obligation contract assets balances for the period ended March 31, 2019 are as follows:

(In $ millions)	Contract assets
Net balance at January 1, 2019		50.2
Additions to deferred costs, acquired contract backlog and accrued revenue		33.2
Amortization of deferred costs		(26.4	)
Total contract assets		57.0

Contract Costs

Certain direct and incremental costs incurred for upfront preparation, initial rig mobilization and modifications are costs of fulfilling a contract and are recoverable. These recoverable costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process.

Note 4 - Other income (expenses), net

Other income (expenses), net is comprised of the following:

(In $ millions)	Three months ended March 31, 2019			Three months ended March 31, 2018
Foreign exchange loss, net		0.2			(0.2	)
Other financial expenses		(0.8	)		—
Change in unrealised (loss)/gain on call spread (note 14)		3.6			—
(Loss)/gain on forward contracts (note 14)		11.5			(20.0	)
Total		14.5			(20.2	)

(Loss)/gain on forward contracts is presented net for the three months ended March 31, 2019 and 2018. The Company did not realize any gains or losses in the first quarter of 2019.

Note 5 - Taxation

Borr Drilling Limited is a Bermuda company not required to pay taxes in Bermuda on ordinary income or capital gains as it qualifies as an Exempted Company. We operate through various subsidiaries in numerous countries throughout the world and are subject to tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in jurisdictions in which we or any of our subsidiaries operate, were incorporated, or otherwise considered to have a tax presence. 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.

F-12

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The change in the effective tax rate from period to period is primarily attributable to changes in the profitability or loss mix of our operations in various jurisdictions. As our operations continually change among numerous jurisdictions, and methods of taxation in these jurisdictions vary greatly, there is little direct correlation between the income tax provision or benefit and income or loss before taxes. We used a discrete effective tax rate method to calculate income taxes.

Income tax expense is comprised of the following:

(In $ millions)	Three months ended March 31, 2019			Three months ended March 31, 2018
Current tax		0.5			—
Change in deferred tax		(0.3	)		—
Total		0.2			—

Note 6 - Earnings/(Loss) per share

The computation of basic earnings/(loss) per share (“EPS”) is based on the weighted average number of shares outstanding during the period. Diluted EPS does not include the effect of the assumed conversion of potentially dilutive instruments which are 3,075,000 share options outstanding issued to employees and directors and convertible bonds with a conversion price of $33.4815 for a total of 10,453,534 shares. Due to the Company’s current loss-making position these are deemed to have an anti-dilutive effect on the EPS of the Company.

	Three months ended March 31, 2019			Three months ended March 31, 2018
Basic loss per share	$	(0.52	)	$	(0.35	)
Diluted loss per share		(0.52	)		(0.35	)
Issued ordinary shares at the end of the period		106,528,065			105,000,000
Weighted average numbers of shares in issue for the period		105,068,351			96,498,185

The number of share options that would be considered dilutive under the “if converted method” for the three months ended March 31, 2019 is 107,426 (three months ended March 31, 2018: 138,915.

Note 7 - Jack-up rigs

(In $ millions)	Cost			Accumulated depreciation			Net carrying value
Balance at December 31, 2018		2,366.6			(88.5	)		2,278.1
Additions		26.9			—			26.9
Asset transfers (note 8)		146.0			—			146.0
Depreciation and amortisation		—			(23.5	)		(23.5	)
Impairment		(11.4	)		—			(11.4	)
Balance at March 31, 2019		2,528.1			(112.0	)		2,416.1

The Company took delivery of the “Njord” in the first quarter of 2019. The final delivery instalment was funded by delivery financing from PPL Shipyard of $87.0 million.

The Company entered into a sale agreement for the “Baug”, “Paragon C20051” and “Eir” subsequent to March 31, 2019. See note 24. An impairment loss of $11.4 million was recognized for the “Eir” in the first quarter of 2019 as a result of entering into the sale agreement. As of March 31, 2019, management does not consider conditions of held for sale presentation to be achieved and the rigs are recognized under jack-up rigs.

In addition, the Company recorded a depreciation charge of $0.4 million in the first quarter of 2019, and $ nil in the first quarter of 2018 related to property, plant and equipment.

F-13

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 8 - Newbuildings

(In $ millions)	March 31, 2019			March 31, 2018
Opening balance		361.8			642.7
Additions		210.9			174.4
Capitalized interest		5.8			2.7
Asset transfers (note 7)		(146.0	)		(420.7	)
Total		432.5			399.1

The Company took delivery of the “Njord” in the first quarter of 2019. The delivery instalment was funded by delivery financing from PPL Shipyard Ltd of $87.0 million. Also in the first quarter of 2019, the Company entered into a novation agreement to acquire Hull No. B378 from Keppel Shipyard Ltd (see note 10) for a purchase price of $122.1 million. The acquisition was partly funded by a new bridge financing facility from Danske Bank A/S and partly by drawing down on the $160 million Senior secured revolving loan facility entered into in the first quarter of 2019 (see note 18).

Note 9 - Leases

We have operating leases expiring at various dates, principally for real estate, office space, storage facilities and operating equipment. For our Houston office space, we have previously deemed the lease as an onerous lease as a result of change in our operating strategy, it is expected that the lease will expire on March 1, 2022. For this operating lease, upon adoption of the new standard, we offset the right-of-use asset of the lease by the existing carrying amount of the liability previously recorded on the date of adoption. We have subleased a section of our Houston office space as an operating lease for an amount of approximately $50,000 per month.

Supplemental balance sheet information related to leases was as follows:

(In $ millions)	January 1, 2019		March 31, 2019
Operating leases
Operating leases right-of-use assets		2.0		1.7
Current operating lease liabilities		4.1		3.7
Long-term operating lease liabilities		8.0		7.4

The current portion of the ROU asset is recognized within other current assets (see note 15) and the non-current portion is recognized within other long-term assets (see note 16). The current lease liabilities are recognized within other current liabilities (see note 21) and the non-current lease liabilities are recognized within other liabilities.

Components of lease cost is comprised of the following:

(In $ millions)	March 31, 2019
Operating lease cost		0.5
Short-term lease cost		2.3
Variable lease cost		—
Total lease cost		2.8
Sublease income		0.2

F-14

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Supplemental cash flow information related to leases was as follows:

(In $ millions)	March 31, 2019
Cash payments for onerous lease contracts		0.9
Operating cash flows from operating leases		0.3
Total lease payments		1.2
Weighted average remaining lease term for operating leases (years)		9.45
Weighted average discount rate for operating leases		6.38	%

Maturities of lease liabilities were as follows:

(In $ millions)	March 31, 2019
2019		4.6
2020		4.0
2021		3.5
2022		—
2023		—
Thereafter		—
Total lease payments		12.1
Less interest		1.0
Present value of lease liability		11.1

As at December 31, 2018, our nominal lease payment maturities under the previous operating lease standard were as follows:

(In $ millions)	December 31, 2018
2019		4.6
2020		3.6
2021		3.6
2022		0.5
2023		—
Thereafter		—
Total lease payments		12.3

Note 10 - Asset acquisition

Acquisition of Keppel’s Hull B378

In March 2019, the Company entered into an assignment agreement with the original owner for the assignment of the rights and obligations under a construction contract to take delivery of one KFELS Super B Bigfoot premium jack-up rig identified as Keppel’s Hull No. B378 from Keppel for a purchase price of $122.1 million. The construction contract was, at the same time, novated to our subsidiary, Borr Jack-Up XXXII Inc., and amended. Borr Jack-Up XXXII Inc. took delivery of the rig on May 9, 2019 (see note 24). The rig has been named “Thor.”

Note 11 - Business acquisition

Paragon Offshore Limited

The Company announced a binding tender offer agreement (the “Tender Offer Agreement”) on February 21, 2018 to offer to purchase all outstanding shares in Paragon Offshore Limited (“Paragon”) (“the Offer”). The total acquisition price to purchase all outstanding shares was $241.3 million. The transaction was subject to the satisfaction of the offer conditions, customary closing conditions, including, among other

F-15

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

customary conditions, that (a) at least 67% of the outstanding Paragon shares were validly tendered and not withdrawn before the expiration date, (b) no material adverse change shall have occurred prior to closing, and (c) Paragon shall have completed all actions necessary to acquire ownership of certain Prospector drilling rigs and legal entities currently subject to Chapter 11 proceedings in the United States Bankruptcy Court in the District of Delaware. On March 29, 2018, all of the conditions to the Offer were satisfied and the transaction closed. Shareholders holding 99.41% of the shares accepted the offer for a total payment of approximately $240.0 million.

Note 12 - Restricted cash

(In $ millions)	March 31, 2019			December 31, 2018
Opening balance		63.4			39.1
Transfer to (from) restricted cash		(34.0	)		24.3
Total		29.4			63.4

All restricted cash is classified as current assets and consist of deposits in margin accounts and bank deposits in relation to forward contracts and deposits made for issued guarantees.

Note 13 - Marketable Securities

Our marketable securities consist of debt securities and equity securities. Debt securities are marked to market, with changes in fair value recognised in “Other comprehensive income” (“OCI”). Equity securities are re-measured at fair value with unrealized gains and losses recognized under other income (expenses), net. In the first quarter 2019, the Company purchased debt securities for approximately $3.1 million.

As of December 31, 2018, an accumulated unrealised loss of $5.6 million was recognised in OCI for the non-current marketable securities. In the first quarter of 2019, we recorded an unrealised loss of $7.3 million through OCI.

The following table sets forth Marketable securities, non-current

(In $ millions)	Three months ended March 31, 2019
Opening balance		31.0
Purchase of marketable securities		3.1
Unrealized gain/(loss) on marketable securities		(7.3	)
Reclassification to marketable securities, current		(26.8	)
Total marketable securities, non-current		—

The following table sets forth Marketable securities, current

(In $ millions)	Three months ended March 31, 2019
Opening balance		4.2
Purchase of marketable securities		—
Sale of marketable securities		(4.2	)
Reclassification from marketable securities, non-current		26.8
Total marketable securities, current		26.8

We have reclassified $26.8 million of our debt securities from non-current to current in the first quarter of 2019 due to recent developments in the issuer of the debt securities. Realization of the investment is estimated to take place within the next 12 months.

F-16

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

During the first quarter of 2019, the Company sold its shares acquired in the fourth quarter of 2018 and generated a gain of $0.0 million.

Note 14 - Financial Instruments

Forward contracts

As of March 31, 2019, the Company has forward contracts to purchase shares in listed drilling companies for an aggregate amount of approximately $90.4 million. The forward contracts consist of forward assets of $66.8 million and forward liabilities of $90.4 million and are presented as net unrealized loss of $23.6 million under accrued expenses and other current liabilities (see note 20) in the Consolidated Balance Sheets as of March 31, 2019. During the first quarter of 2019, the Company sold shares resulting in net cash proceeds of $4.2 million (see note 13) and simultaneously purchased forward contracts with exposure to the same amount.

Call Spread

Fair value adjustments during the first quarter of 2019 resulted in an unrealised gain recognised in the Condensed Consolidated Statements of Operations in other income (expense), net, of $3.6 million. As of March 31, 2019, aggregated fair value adjustments were unrealised loss of $22.2 million related to one-off costs for entering the position and subsequent fair value adjustments. The Call Spread is presented under other long-term assets, see note 16.

Note 15 - Other current assets

Other current assets are comprised of the following:

(In $ millions)	March 31, 2019		December 31, 2018
Client rechargeable		9.6		5.1
Other receivables		7.5		7.9
Current taxes receivable		6.3		4.3
Deferred financing fee		2.8		3.2
Right-of-use lease asset, current		0.9		—
Total		27.1		20.5

Note 16 - Other long-term assets

Other long-term assets are comprised of the following:

(In $ millions)	March 31, 2019		December 31, 2018
Other receivables		1.4		0.5
Deferred tax asset		2.9		2.6
Call Spread (note 14)		6.4		2.8
Tax refunds		4.2		4.2
Prepaid fees		10.0		9.5
Right-of-use lease asset, non-current		0.8		—
Total		25.7		19.6

F-17

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 17 - Onerous contracts

(In $ millions)	March 31, 2019		December 31, 2018
Onerous lease commitments		—		10.2
Onerous rig contracts		71.3		71.3
Total		71.3		81.5

Onerous contracts for Hull B366 (TBN “Tivar”) of $16.8 million, Hull B367 (TBN “Vale”) of $26.9 million and Hull B368 (TBN “Var”) of $27.6 million, in total $71.3 million, relate to the estimated excess of remaining shipyard instalments to be made to Keppel FELS over the value in use estimate for the jack-up drillings rigs to be delivered. Remaining shipyard instalments and onerous contract are expected to be settled when the newbuildings are delivered and paid in 2020. As a result of the adoption of the new lease standard from January 1, 2019, the onerous lease commitments for our office space in Houston and Beverwijk are now included in our lease liabilities (see note 9 and 21).

Note 18 - Long-term debt

Long-term debt is comprised of the following:

	Carrying amount				Principal amount				Back end fee
(In $ millions)	March 31, 2019		December 31, 2018		March 31, 2019		December 31, 2018		March 31, 2019		December 31, 2018
$120 Bridge Facility		58.5		—		60.0		—		—		—
$160 DC Revolving Credit Facility		60.0		—		60.0		—		—		—
$200 DNB Revolving Credit Facility		165.0		130.0		165.0		130.0		—		—
$350 Convertible bonds		345.6		346.5		350.0		350.0		—		—
PPL Delivery Financing		786.3		698.1		753.3		669.6		29.6		26.1
Total		1,415.4		1,174.6		1,388.3		1,149.6		29.6		26.1

At March 31, 2019 the scheduled maturities of our debt were as follows:

(In $ millions)	Maturities
2019		60.0
2020		225.0
2021		—
2022		83.7
2023		935.9
2024		83.7
Thereafter		—
Total principal amount of debt		1,388.3
Total debt-related balances, net		27.1
Total carrying amount of debt		1,415.4

$200 million DNB Revolving Credit Facility and Guarantee Facility

The DNB Revolving Credit Facility matures in May 2020 and bears interest at a rate of LIBOR plus a specified margin.

In January 2019, we executed an amendment to the DNB Revolving Credit Facility agreement which allows us to procure the issuance of guarantees as required in the ordinary course of business, typically for bid bonds, import bonds and performance bonds, up to an aggregate amount of $30 million. Our obligations to reimburse the bank for any payment made under such guarantees is secured by the guarantees, security

F-18

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

over the rigs, insurances and shares provided under the DNB Revolving Credit Facility agreement. This amendment replaced the cash collateral required by the common terms agreement with DNB Bank ASA, which we refer to as the Guarantee Facility, and resulted in the release of $25.0 million of cash that was categorized as restricted as of December 31, 2018.

As of March 31, 2019, and December 31, 2018 we had $165.0 million and $130 million outstanding, respectively under the facility. As of March 31, 2019, we were in compliance with the covenants and our obligations under the DNB Revolving Credit Facility agreement. We expect to remain in compliance with the covenants and our obligations under the DNB Revolving Credit Facility agreement in 2019.

As of March 31, 2019, “Frigg”, “Idun”, “Norve”, “Prospector 1” and “Prospector 5” were pledged as collateral for the DNB Revolving Credit Facility. Total book value of the encumbered rigs was $476.8 million as of March 31, 2019.

$ 160 million DC Revolving Credit Facility and Guarantee Facility

In March 2019, we entered into a $160 million revolving credit facility and guarantee facility agreement with Danske Bank A/S and Citigroup Global Markets Limited (“DC Revolving Credit Facility”) (consisting of a $100.0 million credit facility and $60.0 million for the issuance of guarantees as required in the ordinary course of business), secured by mortgages over four of our jack-up rigs, assignments, pledges or charges of rig insurances, earnings, earnings accounts, shares and intra-group loans, as applicable, as well as guarantees from certain of our rig-owning subsidiaries providing the security as owners of the mortgaged rigs.

Our DC Revolving Credit Facility matures in May 2020 and bears interest at a rate of LIBOR plus a specified margin. Our DC Revolving Credit Facility agreement contains various financial covenants, including requirements that we maintain a minimum book equity ratio of 40%, positive working capital and minimum liquidity equal to the greater of $50 million and 5% of net interest-bearing debt (including a contractual right to reduce this requirement to 4% in the event the liquidity covenant in the DNB Revolving Credit Facility agreement is amended to this effect). Our DC Revolving Credit Facility agreement also contains a loan to value clause requiring that the fair market value of our rigs shall at all times cover at least 175% of the aggregate outstanding facility amount and any undrawn and uncancelled part of the facility. Our DC Revolving Credit Facility agreement also contains various restrictive covenants, including, among others, restrictions on incurring additional indebtedness; restrictions on paying dividends; restrictions on us repurchasing our Shares; restrictions on changing the general nature of our business; and restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim is required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions). The DC Revolving Credit Facility agreement also contains events of default which include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the DC Revolving Credit Facility agreement or security documents, or jeopardize the security. If there is an event of default, the lenders under our DC Revolving Credit Facility may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. The lenders under our DC Revolving Credit Facility may also require replacement or additional security if the fair market value of the jack-up rigs over which security is provided is insufficient to meet our market value-to-loan covenant. In addition, the DC Revolving Credit Facility agreement contains a “Most Favored Nation” clause giving the lenders a right to amend the financial covenants to reflect any more lender-favorable covenants in any other agreement pursuant to which loan or guarantee facilities are provided to us, including amendments to our Financing Arrangements. As of March 31, 2019, we were in compliance with the covenants and our obligations under the DC Revolving Credit Facility Agreement. We expect to remain in compliance with the covenants and our obligations under the DC Revolving Credit Facility agreement in 2019.

As of March 31, 2019, “Odin”, “Mist”, “Ran” and “Saga” were pledged as collateral for the $160 million senior secured revolving loan facility. Total book value of the encumbered rigs was $392.8 million as of March 31, 2019.

F-19

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

$ 120 million Bridge Facility

In March 2019, we entered into a $120.0 million senior secured term loan facilities agreement, consisting of two facilities (Facility A and Facility B) of $60.0 million each, with Danske Bank A/S and DNB Bank ASA (“Bridge Facility”), secured by a mortgage over one of our currently owned jack-up rigs, with another mortgage to be taken out over the rig “Thor” upon delivery, an assignment of rig insurances and a pledge over the shares of certain of our rig-owning subsidiaries providing the security as owners of the mortgaged rigs. Our Bridge Facility matures on September 30, 2019 and bears interest at a rate of LIBOR plus a specified margin. As of March 31, 2019, Facility A had been utilized in the amount of $60.0 million, and $60.0 million in Facility B remained undrawn. The availability period of Facility B expires June 30, 2019. Our Bridge Facility contains various financial covenants, including requirements that we maintain a minimum book equity ratio of 40% and minimum liquidity equal to the greater of $50 million and 5% of net interest-bearing debt.

Our Bridge Facility also contains various covenants, including, among others, restrictions on incurring additional indebtedness; restrictions on paying dividends; restrictions on us repurchasing our Shares; restrictions on changing the general nature of our business; restrictions on making certain investments; and restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim is required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions). The Bridge Facility agreement also contains events of default which include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the Bridge Facility or security documents, or jeopardize the security. If there is an event of default, the lenders under our Bridge Facility may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. In addition, the Bridge Facility contains a “Most Favored Nation” clause giving the lenders a right to amend the financial covenants to reflect any more lender-favorable covenants in any other agreement pursuant to which loan or guarantee facilities are provided to us, including amendments to our Financing Arrangements. As of March 31, 2019, we were in compliance with the covenants and our obligations under the Bridge Facility. We expect to remain in compliance with the covenants and our obligations under the Bridge Facility in 2019.

As of March 31, 2019, “Skald” and “Thor” were pledged as collateral for the $120 million bridge loan facility. Total book value of the encumbered rigs was $252.5 million as of March 31, 2019.

$350 million Convertible Bonds

In May 2018 we raised $350.0 million through the issuance of our Convertible Bonds, which mature in 2023. The initial conversion price (which is subject to adjustment) is $33.4815 per Share, for a total of 10,453,534 Shares. The Convertible Bonds have a coupon of 3.875% per annum payable semi-annually in arrears in equal instalments. The terms and conditions governing our Convertible Bonds contain customary events of default, including failure to pay any amount due on the bonds when due, and certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to incur secured capital markets indebtedness. The Company has entered into Call Spreads to mitigate the effect of conversion – see note 14 for details.

As of March 31, 2019, we were compliant with the covenants and our obligations under our Convertible Bonds. We expect to remain compliant with our obligations under our Convertible Bonds in 2019.

Our Delivery Financing Arrangements

In addition to two jack-up rigs which we have taken delivery from Keppel against full payment, we have contracts with Keppel to purchase nine jack-up rigs under construction. We have the option to accept delivery financing for two of the jack-up rigs to be delivered from Keppel. For five of our newbuild jack-up rigs under construction and nine additional jack-up rigs which have been delivered from PPL, we have agreed to accept and accepted, respectively, delivery financing from PPL and Keppel subject to the terms described below:

F-20

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PPL Newbuild Financing

In October 2017, we agreed to acquire nine premium “Pacific Class 400” jack-up rigs from PPL (the “PPL Rigs”). We accepted delivery of eight of the PPL Rigs as of December 31, 2018 and all nine PPL Rigs had been delivered as of January 31, 2019. In connection with delivery of the PPL Rigs, our rig-owning subsidiaries as buyers of the PPL Rigs agreed to accept delivery financing for a portion of the purchase price equal to $87.0 million per jack-up rig (the “PPL Financing”). The PPL Financing for each PPL Rig is an interest-bearing secured seller’s credit, guaranteed by the Company which matures on the date falling 60 months from the delivery date of the respective PPL Rig.

The PPL Financing for each respective PPL Rig is secured by a mortgage on such PPL Rig and an assignment of the insurances in respect of such PPL Rig. The PPL Financing also contains various covenants and the events of default include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the PPL Financing agreements or security documents, or jeopardize the security. In addition, each rig-owning subsidiary is subject to covenants which management considered to be customary in a transaction of this nature.

As of March 31, 2019, and December 31, 2018, we had $782.6 and $695.6 million, respectively, of PPL Financing outstanding and were in compliance with the covenants and our obligations under the PPL Financing agreements. We expect to remain in compliance with the covenants and our obligations under the PPL Financing agreements in 2019. We expect to satisfy our obligations under the PPL Financing for each respective PPL Rig with cash flow from operations when due.

As of March 31, 2019, “Galar”, “Gerd”, “Gersemi”, “Grid”, “Gunnlod”, “Groa”, “Gyme”, “Natt” and “Njord” were pledged as collateral for the PPL financing. Total book value for the encumbered rigs was $1,306.7 million as of March 31, 2019.

Interest

Average interest rate for all our interest-bearing debt, excluding the Convertible Bonds, was 6.09% for the period ended March 31, 2019.

Note 19 - Share-based compensation

Share-based payment charges for the period ending:

(In $ millions)	Three Months Ended March 31, 2019		Three Months Ended March 31, 2018
Total		2.0		0.4

At March 11, 2019, the Company issued 460,000 share options to certain employees and directors of the Company. The awards were granted under the existing approved share option scheme. The options have a strike price of $17.50 per share, which compares to the Company’s share’s closing price of $14.20 on March 8, 2019. The options will expire after five years and have a four-year vesting period. Expected life after vesting is estimated at two years. Risk free interest rate is set to 2% and expected future volatility is estimated at 32%. Total number of options authorised by the Board is 3,494,000 and 3,075,000 have been awarded as of March 31, 2019.

F-21

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 20 - Fair values of financial instruments

The carrying value and estimated fair value of the Company’s cash and financial instruments were as follows:

		As at March 31, 2019
(In $ millions)	Hierarchy	Fair value		Carrying value
Assets
Cash and cash equivalents	1		29.4		29.4
Restricted cash	1		29.4		29.4
Marketable securities – non-current	1		—		—
Marketable securities – current	1		26.8		26.8
Trade receivables	1		25.7		25.7
Accrued revenue	1		18.5		18.5
Tax retentions receivable	1		11.6		11.6
Other current assets (excluding prepayments and deferred costs)	1		23.4		23.4
Forward contracts (note 14)	2		66.8		66.8
Liabilities
Long-term liabilities	2		1,320.1		1,356.9
Current portion of long-term debt			58.5		58.5
Trade payables	1		14.7		14.7
Accruals and other current liabilities	1		85.2		85.2
Forward contracts (note 14)	2		90.4		90.4

Financial instruments included in the consolidated accounts within ‘Level 1 and 2’ of the fair value hierarchy are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency.

Included in “Level 1” are cash and cash equivalents, restricted cash, trade receivables, marketable securities, other current assets (excluding prepayments and deferred costs), trade payables, accruals and other current liabilities. The carrying value of any accounts receivable and payables approximates fair value due to the short time to expected payment or receipt of cash.

Included in “Level 2” are forward contracts and Call Spread (note 14). No assets or liabilities have been transferred from one level to another during the three month ended March 31, 2019.

Note 21 - Other current liabilities

Accruals and other current liabilities are comprised of the following:

(In $ millions)	March 31, 2019		December 31, 2018
Accrued payroll and severance		11.1		3.1
Taxes payable		3.6		4.2
Operating lease liability, current		3.7		—
Total accruals and other current liabilities		18.4		7.3

F-22

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 22 - Related party transactions

Transactions with those holding significant influence over the Company

Equity offering

At March 22, 2018, the Company announced that it would raise up to $250 million in an equity offering divided in two tranches. Tranche 2 of (the “Equity Offering”) was subject to approval by the extraordinary general meeting to be held on 5 April 2018 and subsequent share issue. In connection with the settlement of Tranche 2, $27.7 million was registered as liability to shareholders including $20.0 million to Drew Holdings Ltd (“Drew”) as of March 31, 2018. Drew is a trust established for the benefit of Tor Olav Trøim, the Chairman of the Company. As of May 30, 2018, the 1,528,065 new shares allocated in Tranche 2 of the Equity Offering were validly issued and fully paid.

Director fee

On November 20, 2018, the Company transferred 14,285 of its treasury shares to Mr. Jan A. Rask. Following this transaction, Mr. Rask owns a total of 14,285 shares in the Company. Mr Jan A. Rask received treasury shares during fourth quarter of 2018 as settlement of his director fee for the period from the Company’s Annual General Meeting in 2017 until the Annual General Meeting in 2018. In accordance with the agreement, settlement of treasury shares was valued at $17.50 per share, being the share price at the time Mr Rask was elected as an independent director of the Board on August 31, 2017.

Commercial Arrangements

We have obtained certain rig and other operating supplies from Schlumberger and may continue to obtain such supplies in the future. Purchases from Schlumberger were $6.1 million during the first quarter of 2019 and $0.6 million during the first quarter of 2018. $0.8 million and $0.4 million were outstanding at March 31, 2019 and December 31, 2018, respectively.

Note 23 - Commitments and contingencies

The Company has the following commitments as of March 31, 2019:

(in $ millions)	Delivery installment		Back-end fee
Delivery installments for jack-up drilling rigs		880.2		22.5

In addition, under the PPL Financing, PPL Shipyard is entitled to certain fees payable in connection with the increase in market value of the relevant PPL Shipyard Rig from October 31, 2017 until the repayment date, less the relevant rig owner’s equity cost of ownership of each jack-up rig and any interest paid on the delivery financing. No provision has been made for such fees as of March 31, 2019.

The following table sets forth when our commitments fall due as of March 31, 2019

(In $ millions)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Delivery installments for jack-up rigs		172.8		707.4		0.0		0.0		880.2

Other commercial commitments

We have other commercial commitments which contractually obligate us to settle with cash under certain circumstances. Surety bonds and parent company guarantees entered into between certain customers and governmental bodies guarantee our performance regarding certain drilling contracts, customs import duties and other obligations in various jurisdictions.

The principal amounts of the outstanding surety bonds were $82.5 million and $13.2 million as of March 31, 2019 and December 31, 2018, respectively. In addition, we had outstanding bank guarantees and performance bonds amounting to $11.5 million as of March 31, 2019 and $9.8 million as of December 31, 2018.

F-23

BORR DRILLING LIMITED
NOTES TO THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 2019, these obligations and their expiration dates are as follows:

(In $ millions)	1 year		1-3 years		3-5 years		Thereafter		Total
Surety bonds and other guarantees		69.4		24.0		—		0.6		94.0

Note 24 - Subsequent events

Delivery of Thor

The Company took delivery of “Thor” on May 9, 2019 from Keppel Shipyard. The rig was acquired from BOTL Lease Co. Ltd. in March 2019. In connection with the delivery, the Company drew down $60 million on the $120 million bridge loan facility (see notes 8, 10 and 18).

Sale of rigs

In May 2019, the Company entered into binding sale and purchase agreements for the sale of the “Eir”, “Baug” and “Paragon C20051”, none of which were on contract at the end of the first quarter 2019. The rigs will be sold to an undisclosed, private buyer for non-drilling purposes for a consideration of $3.0 million each, therefore a total consideration of $9.0 million. The sale of “Baug” and “Paragon C20051” closed in May 2019, and we expect the sale of “Eir” to close in early 2020. The Company recorded an impairment of $11.4 million in the first quarter of 2019 in connection with its entry into an agreement for the sale of the “Eir” (see also note 7).

F-24

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the board of directors and shareholders of Borr Drilling Limited

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Borr Drilling Limited and its subsidiaries (the “Company”) as of December 31, 2018 and 2017, and the related consolidated statements of operations, consolidated statements of comprehensive loss, consolidated statements of cash flows and consolidated statements of changes in shareholders’ equity for each of the two years in the period ended December 31, 2018, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America.

Restatement of Previously Issued Financial Statements

As discussed in Note 1 to the consolidated financial statements, the Company has restated its 2017 financial statements to correct a misstatement.

Basis for Opinion

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

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

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

Substantial Doubt About the Company’s Ability to Continue as a Going Concern Has Been Removed

Management and we previously concluded there was substantial doubt about the Company’s ability to continue as a going concern. As discussed in Note 1, management has subsequently taken certain actions, which management and we have concluded remove that substantial doubt.

/s/ PricewaterhouseCoopers AS
Stavanger, Norway
April 29, 2019, except with respect to the matters that alleviate previous substantial doubt about the Company’s ability to continue as a going concern discussed in Note 1 and the effects of the reverse stock split discussed in Note 1 to the consolidated financial statements, as to which the date is July 10, 2019

We have served as the Company's auditor since 2016.

F-25

BORR DRILLING LIMITED
CONSOLIDATED STATEMENTS OF OPERATIONS

for the Years ended December 31, 2018 and 2017
(In $ millions, except per share data)

	Notes	2018			2017
Operating revenues	3		164.9			0.1
Gain from bargain purchase	14		38.1			—
Gain on disposals	4		18.8			—
Operating expenses
Rig operating and maintenance expenses			(180.1	)		(36.2	)
Depreciation of non-current assets	11		(79.5	)		(21.2	)
Impairment of non-current assets	11		—			(26.7	)
Amortization of acquired contract backlog			(24.2	)		—
General and administrative expenses	14, 23		(38.7	)		(21.0	)
Restructuring costs	14		(30.7	)		—
Cost for issuance of warrants	25		—			(4.7	)
Total operating expenses			(353.2	)		(109.8	)
Operating loss			(131.4	)		(109.7	)
Other income (expenses), net
Interest income			1.2			3.2
Interest expenses, net of amounts capitalized			(13.7	)		(0.5	)
Other, net	5		(44.5	)		19.0
Total other income (expenses), net			(57.0	)		21.7
Loss before income taxes			(188.4	)		(88.0	)
Income tax expense	6		(2.5	)		—
Net loss			(190.9	)		(88.0	)
Net (loss) attributable to non-controlling interests	22		(0.4	)		—
Net (loss) attributable to shareholders of Borr Drilling Limited			(190.5	)		(88.0	)
Earnings (loss) per share
Basic loss per share	7		(1.85	)		(1.70	)
Diluted loss per share	7		(1.85	)		(1.70	)
Weighted-average shares outstanding	7		102,877,501			51,726,288

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

F-26

BORR DRILLING LIMITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

for the Years ended December 31, 2018 and 2017
(In $ millions)

	Notes	2018			2017
Loss after income taxes			(190.9	)		(88.0	)
Unrealized gain (loss) from marketable securities	15		0.6			(6.2	)
Other comprehensive income (loss)			0.6			(6.2	)
Total comprehensive loss			(190.3	)		(94.2	)
Comprehensive loss attributable to
Shareholders of Borr Drilling Limited			(189.9	)		(94.2	)
Non-controlling interests			(0.4	)		—
Total comprehensive loss			(190.3	)		(94.2	)

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

F-27

BORR DRILLING LIMITED
CONSOLIDATED BALANCE SHEET

as of December 31, 2018 and 2017
(In $ millions, except number of shares)

	Notes	2018		2017
ASSETS
Current assets
Cash and cash equivalents			27.9		164.0
Restricted cash	8		63.4		39.1
Trade accounts receivables	9		25.1		—
Marketable securities	15		4.2		—
Prepaid expenses			10.8		2.6
Acquired contract backlog	14		20.2		—
Deferred mobilization costs			6.0		10.3
Accrued revenue			18.9		—
Tax retentions receivable			11.6		—
Other current assets	10		20.5		9.5
Total current assets			208.6		225.5
Non-current assets
Property, plant and equipment			9.5		0.1
Jack-up drilling rigs	11		2,278.1		783.3
Newbuildings	12		361.8		642.7
Marketable securities	15		31.0		20.7
Other long-term assets	17		24.7		—
Total non-current assets			2,705.1		1,446.8
Total assets			2,913.7		1,672.3
LIABILITIES AND EQUITY
Current liabilities
Trade accounts payables			9.6		9.6
Amounts due to related parties			0.4		—
Unrealized loss on forward contracts	16		35.1		—
Accrued expenses			63.7		11.5
Onerous contracts	20		3.2		—
Other current liabilities	18		7.3		—
Total current liabilities			119.3		21.1
Non-current liabilities
Long-term debt	19		1,174.6		87.0
Other liabilities			8.0		—
Onerous contracts	20		78.3		71.3
Total non-current liabilities			1,260.9		158.3
Total liabilities			1,380.2		179.4
Commitments and contingencies	21

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

F-28

BORR DRILLING LIMITED
CONSOLIDATED BALANCE SHEET

	Notes	2018			2017
Stockholders’ Equity
Common shares of par value $0.05 per share: authorized 125,000,000 (2017: 105,000,000) shares, issued 106,528,065 (2017: 95,658,500) shares and outstanding 105,068,351 (2017: 95,264,500) shares at December 31, 2018			5.3			4.8
Treasury shares			(26.2	)		(6.7	)
Additional paid in capital			1,837.5			1,587.8
Other comprehensive loss			(5.6	)		(6.2	)
Accumulated deficit			(279.2	)		(88.8	)
Equity attributable to the Company			1,531.8			1,490.9
Non-controlling interest			1.7			2.0
Total equity			1,533.5			1,492.9
Total liabilities and equity			2,913.7			1,672.3

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

F-29

BORR DRILLING LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS

for the Years ended December 31, 2018 and 2017
(In $ millions)

	Notes	2018			2017
Cash Flows from Operating Activities						(Restated	)
Net (loss)			(190.9	)		(88.0	)
Adjustments to reconcile net (loss to net cash used in operating activities:
Non-cash compensation expense related to stock options and warrants	23		3.7			8.2
Depreciation of non-current assets	11		79.5			21.2
Impairment of non-current assets	11		—			26.7
Amortization of acquired contract backlog			24.2			—
Payments related to onerous contracts			—			(152.2	)
Gain on sale of rigs	4		(18.8	)		—
Unrealized (gain) loss on financial instruments	16		65.2			(4.4	)
Bargain purchase gain	14		(38.1	)		—
Deferred income tax	6		(0.5	)		—
Change in other current and non-current assets			(24.8	)		(16.5	)
Change in current and non-current liabilities			(34.7	)		20.1
Net cash used in operating activities			(135.2	)		(184.8	)
Cash Flows from Investing Activities
Purchase of plant and equipment			(7.8	)		(0.1	)
Proceeds from sale of fixed assets	4		41.6			—
Purchase business combination (acquisition), net of cash acquired	14		(195.1	)		(324.5	)
Purchase of marketable securities	15		(13.0	)		(26.9	)
Additions to newbuildings	12		(362.4	)		(785.2	)
Additions to jack-up drilling rigs	11		(23.4	)		(119.8	)
Net cash used in investing activities			(560.1	)		(1,256.5	)
Cash Flows from Financing Activities
Proceeds from share issuance, net of issuance costs and conversion of shareholders loans			218.9			1,415.0
Proceeds from related party shareholder loan	26		27.7			12.7
Purchase of treasury shares	28		(19.7	)		(8.4	)
Repayment of long-term debt	14		(89.3	)		—
Purchase of financial instruments			(28.5	)		—
Proceeds, net of deferred loan costs, from issuance of long-term debt	19, 12, 13		474.4			87.0
Net cash provided by financing activities			583.5			1,506.3
Net (decrease) increase in cash, restricted cash and cash equivalents			(111.8	)		65.0
Foreign exchange translation difference			—			—
Cash and cash equivalents and restricted cash at beginning of the period			203.1			138.1
Cash and cash equivalents and restricted cash at the end of period			91.3			203.1
Supplementary disclosure of cash flow information
Interest paid, net of capitalized interest			(8.6	)		—
Income taxes paid			(3.2	)		—
Issuance of long-term debt as non-cash settlement for newbuild delivery instalment			609.0			—
Non-cash settlement of shareholder loan with issuance of shares			27.7			—

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

F-30

BORR DRILLING LIMITED
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

for the Years ended December 31, 2018 and 2017
(In $ millions, except share and per share data)

	Number of outstanding shares			Common shares		Treasury shares			Additional paid in capital			Other Comprehensive (Loss)/Income			Accumulated Deficit			Non- controlling interest			Total equity
Consolidated balance at December 31, 2016		15,501,000			0.8		—			157.8			—			(0.8	)		—			157.8
Issue of common shares		78,220,000			3.9		—			1,446.2			—			—			—			1,450.1
Equity issuance costs		—			—		—			(17.8	)		—			—			—			(17.8	)
Other transactions:							—
Exercise of warrants		1,937,500			0.1		—			—			—			—			—			0.1
Fair value of warrants issued		—			—		—			7.7			—			—			—			7.7
Equity issuance costs, warrants		—			—		—			(3.0	)		—			—			—			(3.0	)
Purchase of warrants		—			—		—			(4.7	)		—			—			—			(4.7	)
Stock based compensation		—			—		1.7			1.8			—			—			—			3.5
Purchase of treasury shares		(394,000	)				(8.4	)		—			—			—						(8.4	)
Total comprehensive loss		—			—		—			—			(6.2	)		(88.0	)		—			(94.2	)
Sale of shares to non-controlling interest		—			—		—			—			—			—			2.0			2.0
Other, net		—			—		—			(0.2	)		—			—			—			(0.2	)
Consolidated balance at December 31, 2017		92,264,500			4.8		(6.7	)		1,587.8			(6.2	)		(88.8	)		2.0			1,492.9
Issue of common shares (03.23.18)		9,341,500			0.4		—			214.3			—			—			—			214.7
Equity issuance costs		—			—		—			(3.2	)		—			—			—			(3.2	)
Issue of common shares (05.30.18)		1,528,065			0.1		—			35.1			—			—			—			35.2
Other transactions:							—
Stock based compensation		—			—					3.7			—			—			—			3.7
Settlement of directors’ fees		—			—		0.2			(0.2	)											—
Purchase of treasury shares		(1,459,714	)		—		(19.7	)		—			—			—			—			(19.7	)
Total comprehensive loss		—			—		—			—			0.6			(190.5	)		(0.4	)		(190.3	)
Non-controlling interest		—			—		—			—			—			0.1			0.1			0.2
Other, net		—			—		—			—			—			—			—			—
Consolidated balance at December 31, 2018		105,068,351			5.3		(26.2	)		1,837.5			(5.6	)		(279.2	)		1.7			1,533.5

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

F-31

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – General information

Borr Drilling Limited was incorporated in Bermuda on August 8, 2016. The company is listed on the Oslo Stock Exchange, under the ticker symbol “BDRILL.” Borr Drilling Limited is an international offshore drilling contractor providing services to the oil and gas industry, with the objective of acquiring and operating modern jack-up drilling rigs. As of December 31, 2018, we had 27 total jack-up rigs, including 10 rigs “warm stacked” and 4 rigs “cold stacked,” and had agreed to purchase 9 additional premium jack-up rigs under construction.

As used herein, and unless otherwise required by the context, the term “Borr Drilling” refers to Borr Drilling Limited and the terms “Company,” “we,” “Group,” “our” and words of similar import refer to Borr Drilling and its consolidated companies. The use herein of such terms as “group”, “organization”, “we”, “us”, “our” and “its”, or references to specific entities, is not intended to be a precise description of corporate relationships.

Basis of presentation

The consolidated financial statements are presented in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). The amounts are presented in United States Dollars (“U.S. dollar or $”) rounded to the nearest million, unless otherwise stated.

Operating results for the years ending December 31, 2018 and 2017 are not necessarily indicative of the results that may be expected for any future period.

The consolidated financial statements present the financial position of Borr Drilling Limited and its subsidiaries. Investments in companies in which the Company controls, or directly or indirectly holds more than 50% of the voting control are consolidated in the financial statements.

Subsequent events have been reviewed from the period end to the date at which the financial statements were made available for issue, which is April 29, 2019.

Restatement of Comparative Consolidated Statements of Cash Flows

We have restated our Consolidated Financial Statements to correct an error within our Consolidated Statements of Cash Flows. In the course of preparing our consolidated financial statements for 2018, we identified an error for the year ended December 31, 2017, of approximately $152.2 million between Net cash used in operating activities and Net cash used in investing activities sections of our statement of cash flows related to the extinguishment of the onerous contract related to the Keppel Rigs (as defined below). The following table presents the effect of the correction on the selected line items previously reported in the Consolidated Statements of Cash Flows for the year ended December 31, 2017:

(In $ millions)	2017			Adjustments			2017
							(Restated)
Cash Flows from Operating Activities
Net (loss)		(88.0	)		—			(88.0	)
Adjustments to reconcile net (loss to net cash used in operating activities:
Amortization of onerous contracts		—			(152.2	)		(152.2	)
Net cash used in operating activities		(32.6	)		(152.2	)		(184.8	)
Cash Flows from Investing Activities
Additions to newbuildings		(937.4	)		152.2			(785.2	)
Net cash used in investing activities		(1,408.7	)		152.2			(1,256.5	)

F-32

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

There was no impact to net cash provided by financing activities within our consolidated statements of cash flows and there was no impact to the net increase (decrease) in cash and cash equivalents resulting from the restatement. In addition, there was no impact to our consolidated statement of operations or financial position.

Basis of consolidation

The consolidated financial statements include the assets and liabilities of the Company. All intercompany balances, transactions and internal sales have been eliminated on consolidation. Unrealized gains and losses arising from transactions with associates are eliminated to the extent of the Company’s interest in the entity. The non-controlling interests of subsidiaries were included in the consolidated balance sheet and Statements of Operations as “Non-controlling interests”. Profit or loss and each component of other comprehensive income are attributed to the shareholders of the Company and to the non-controlling interests, even if this results in the non-controlling interests having a deficit balance.

Going concern

The consolidated financial statements have been prepared on a going concern basis. The Company has, as of June 28, 2019 finalized and partly drawn on secured financing arrangements in the total amount of $645 million, which were used to refinance all of its credit facilities of $510 million. The Company’s new financing arrangements include a $195 million senior secured term loan facility agreement with funds managed by Hayfin Capital Management LLP, as lenders, among others, a $450 million senior secured credit facilities agreement with DNB Bank ASA, Danske Bank, Citibank N.A., Jersey Branch and Goldman Sachs Bank USA, as lenders, among others (consisting of a $230 million credit facility, $50 million newbuild facility, $70 million for the issuance of guarantees and other trade finance instruments as required in the ordinary course of business and a $100 million incremental facility) and a $100 million senior secured revolving facility agreement with Danske Bank and DNB Bank ASA, as lenders, among others. The financing arrangements contain certain financial and non-financial covenants, including restrictions that require the approval of our lenders prior to the distribution of any dividend. The outstanding obligations under the new financing arrangements will mature in 2022. Based on the execution of the financing arrangements, we believe the prior conclusion on April 29, 2019 of substantial doubt over going concern has been alleviated.

Reverse Share Split

We have effected a conversion of each of our Shares into 0.20 Shares, resulting in a reverse share split at a ratio of 5-for-1. Our post-Reverse Share Split Shares began to trade on the Oslo Børs on June 26, 2019.

Use of estimates

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

Note 2 – Accounting policies

Revenue

The Company performs services that represent a single performance obligation under its drilling contracts. This performance obligation is satisfied over time. The Company earns revenues primarily by performing the following activities: (i) providing the drilling rig, work crews, related equipment and services necessary to operate the rig (ii) delivering the drilling rig by mobilizing to and demobilizing from the drill location, and (iii) performing certain pre-operating activities, including rig preparation activities or equipment modifications required for the contract.

The Company recognizes revenues earned under drilling contracts based on variable dayrates, which range from a full operating dayrate to lower rates or zero rates for periods when drilling operations are

F-33

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

interrupted or restricted, based on the specific activities performed during the contract. Such dayrate consideration is attributed to the distinct time period to which it relates within the contract term, and therefore recognized as the Company performs the services. The Company recognizes reimbursement revenues and the corresponding costs as the Company provides the customer-requested goods and services, when such reimbursable costs are incurred while performing drilling operations. Prior to performing drilling operations, the Company may receive pre-operating revenues, on either a fixed lump-sum or variable dayrate basis, for mobilization, contract preparation, customer-requested goods and services or capital upgrades, which the Company recognizes over time in line with the satisfaction of the performance obligation.

The Company incurs costs to prepare a rig for contract and deliver or mobilize a rig to the drilling location. The Company defers pre-operating costs, such as contract preparation and mobilization costs, and recognizes such costs on a straight-line basis, consistent with the general level of activity, in operating and maintenance costs over the estimated firm period of drilling.

Jack-up rigs

The carrying amount of our jack-up rigs is subject to various estimates, assumptions, and judgments related to capitalized costs, useful lives and residual values and impairments. Jack-up rigs and related equipment are recorded at historical cost less accumulated depreciation. Jack-up rigs acquired as part of asset acquisitions are stated at fair market value as of the date of the acquisition. 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 jack-up rigs and our semi-submersible drilling rig when new, is 30 years.

We determine the carrying values of our jack-up rigs and semi-submersible and related equipment based on policies that incorporate estimates, assumptions and judgments relative to the carrying values, 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 jack-up rigs and semi-submersible, which could materially affect our balance sheet and results of operations.

The useful lives of our jack-up rigs and semi-submersible 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 jack-up rigs and semi-submersible as of and when events occur that 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 jack-up rigs and semi-submersible and related equipment are reviewed for impairment when certain triggering events or changes in circumstances indicate that the carrying amount of an asset may no longer be recoverable. We assess recoverability of the carrying value of an 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 loss is recorded equal to the difference between the asset’s carrying value and fair value. 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 balance sheet and results of operations.

As of December 2018, management identified certain indicators, among others, that the carrying value of our jack-up rigs and semi-submersible and related equipment may not be recoverable and our market

F-34

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

capitalization was lower than the book value of our equity. These market indicators include the reduction in new contract opportunities, decrease in market dayrates and contract terminations. We assessed recoverability of the carrying value of our jack-up rigs and semi-submersible by first evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilizations of the rigs. The estimated undiscounted future net cash flows were found to be greater than the carrying value of our jack-up rigs and semi-submersible, with sufficient headroom. As a result, we did not need to proceed to assess the discounted cash flows of our rigs, and no impairment charges were recorded.

With regard to older jack-up rigs which have relatively short remaining estimated useful lives, the results of impairment tests are particularly sensitive to management’s assumptions. These assumptions include the likelihood of the rig obtaining a contract upon the expiration of any current contract, and our intention for the rig should no contract be obtained, including warm/cold stacking or disposal. The use of different assumptions in the future could potentially result in an impairment of our jack-up rigs, which could materially affect our balance sheet and results of operations. If market supply and demand conditions in the jack-up drilling market do not improve, it is likely that we will be required to impair certain jack-up rigs.

Newbuildings

Jack-up rigs under construction are capitalized, classified as newbuildings and presented as non-current assets. The capitalized costs are reclassified from newbuildings to jack-up rigs when the asset is available for its intended use.

Interest cost capitalized

Interest costs are capitalized on all qualifying assets that require a period of time to get them ready for their intended use. Qualifying assets consist of newbuilding rigs under construction. The interest costs capitalized are calculated using the weighted average cost of borrowings, from commencement of the asset development until substantially all the activities necessary to prepare the assets for its intended use are complete. We do not capitalize amounts beyond the actual interest expense incurred in the period.

Rig operating and maintenance expenses

Rig operating and maintenance expenses are costs associated with operating a rig that is either in operation or stacked, and include the remuneration of offshore crews and related costs, rig supplies, inventory, insurance costs, expenses for repairs and maintenance as well as costs related to onshore personnel in various locations where we operate the jack-up rigs and are expensed as incurred. Stacking costs for rigs are expensed as incurred.

Business combinations

The Company applies the acquisition method of accounting for business combinations in accordance with ASC 805. The acquisition method requires the total of the purchase price of acquired businesses and any non-controlling interest recognized to be allocated to the identifiable tangible and intangible assets and liabilities acquired at fair value, with any residual amount being recorded as goodwill as of the acquisition date. Costs associated with the acquisition are expensed as incurred. The Company allocates the purchase price of acquired businesses to the identifiable tangible and intangible assets and liabilities acquired, with any remaining amount being recorded as goodwill.

The estimated fair value of the jack-up rigs in a business combination is derived by using a market and income-based approach with market participant-based assumptions. When we acquire jack-up rigs there may exist unfavorable contracts which are recorded at fair value at the date of acquisition. An unfavorable contract is a contract that has a carrying value which is higher than prevailing market rates at the time of acquisition. The net present value of such contracts when lower than prevailing market rates, is recorded as an onerous contract at the purchase date.

In a business combination, contract backlog is recognized when it meets the contractual-legal criterion for identification as an intangible asset when an entity has a practice of establishing contracts with its

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

customers. We record an intangible asset equal to its fair value on the date of acquisition. Fair value is determined by using Multi-Period Excess Earnings Method. The multi-period Excess Earnings Method is a specific application of the discounted cash flow method. The principle behind the method is that the value of an intangible asset is equal to the present value of the incremental after-tax cash flows attributable only to the subject intangible asset after deducting contributory asset charges. The asset is then amortized over its estimated remaining contract term.

Onerous contracts

Newbuildings: When we acquire rigs there may exist unfavorable contracts which are recorded at fair value at the date of acquisition. An unfavorable contract is a contract that has a carrying value which is higher than prevailing market rates at the time of acquisition. The net present value of such contracts when lower than prevailing market rates, is recorded as a liability at the purchase date.

Office leases: Onerous contracts are recognized for costs that will continue to be incurred under a contract for its remaining term without economic benefit to the Company. The net present value of such contracts is recorded as a liability at the cease-use date.

Share-based compensation

We have an employee share ownership plan under which our employees, directors and officers may be allocated options to subscribe for new shares in the Company as a form of remuneration. The cost of equity settled transactions is measured by reference to the fair value at the date on which the share options are granted. The fair value of the share options issued under the Company’s employee share option plans are determined at the grant date taking into account the terms and conditions upon which the options are granted, and using a valuation technique that is consistent with generally accepted valuation methodologies for pricing financial instruments, and that incorporates all factors and assumptions that knowledgeable, willing market participants would consider in determining fair value. The fair value of the share options is recognized as a general and administrative expense with a corresponding increase in equity over the period during which the employees become unconditionally entitled to the options. Compensation cost is initially recognized based upon options expected to vest, excluding forfeitures, with appropriate adjustments to reflect actual forfeitures.

Marketable securities

Marketable debt securities held by us which do not give us the ability to exercise significant influence are considered to be available-for-sale. These are re-measured at fair value each reporting period with resulting unrealized gains and losses recorded as a separate component of accumulated other comprehensive income in shareholders’ equity. Gains and losses are not realized until the securities are sold or subject to temporary impairment. Gains and losses on forward contracts to purchase marketable equity securities that do not meet the definition of a derivative are accounted for as available-for-sale securities. We analyze our available-for-sale securities for impairment at each reporting period to evaluate whether an event or change in circumstances has occurred in that period that may have a significant adverse effect on the value of the securities. We record an impairment charge for other-than-temporary declines in value when the value is not anticipated to recover above the cost within a reasonable period after the measurement date, unless there are mitigating factors that indicate impairment may not be required. If an impairment charge is recorded, subsequent recoveries in value are not reflected in earnings until sale of the securities held as available for sale occurs.

Where there are indicators that fair value is below the carrying value of our investments, we will evaluate these for other-than-temporary impairment. Consideration will be given to (i) the length of time and the extent to which fair value of the investments is below carrying value, (ii) the financial condition and near-term prospects of the investee, and (iii) our intent and ability to hold the investment until any anticipated recovery. Where we determine that there is other-than-temporary impairment, we will recognize an impairment loss in the period.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Marketable equity securities with readily determinable fair value are re-measured at fair value each reporting period with unrealized gains and losses recognized under total other income (expenses), net.

Legal proceedings

We may, from time to time, be involved in legal proceedings and claims that arise in the ordinary course of business. A provision will be recognized in the financial statements only where we believe that a liability will be probable and for which the amounts are reasonably estimable, based upon the facts known prior to the issuance of the financial statements.

Foreign currencies

The Company and the majority of its subsidiaries use the U.S. dollar as their functional currency because the majority of their revenues and expenses are denominated in U.S. dollars. Accordingly, the Company’s reporting currency is also U.S. dollars. For subsidiaries that maintain their accounts in currencies other than U.S. dollars, the Company uses the current method of translation whereby the statements of operations are translated using the average exchange rate for the period and the assets and liabilities are translated using the period end exchange rate. Foreign currency translation gains or losses on consolidation are recorded as a separate component of other comprehensive income in shareholders’ equity.

Transactions in foreign currencies are translated into U.S. dollars at the rates of exchange in effect at the date of the transaction. Gains and losses on foreign currency transactions are included in the consolidated statement of operations.

Current and non-current classification

Assets and liabilities (excluding deferred taxes) are classified as current assets and liabilities respectively, if their maturity is within 1 year of the balance sheet date. Otherwise, they are classified as non-current assets and liabilities.

Other intangible assets and liabilities

Other intangible assets and liabilities are recorded at fair value on the date of acquisition less accumulated amortization. The amounts of these assets and liabilities less the estimated residual value, if any, is generally amortized on a straight-line basis over the estimated remaining economic useful life or contractual period.

Cash and cash equivalents

Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.

Restricted cash

Restricted cash consists of margin accounts which have been pledged as collateral in relation to forward contracts and bank deposits which have been pledged as collateral for guarantees issued by a bank or minimum deposits which must be maintained in accordance with contractual arrangements. Restricted cash amounts with maturities longer than one year are classified as non-current assets.

Trade receivables

Trade receivables are presented net of allowances for doubtful balances. At each balance sheet date, all potentially uncollectible accounts are assessed individually for purposes of determining the appropriate provision for doubtful accounts.

Fair Value

The Company accounts for fair value in accordance with ASC 820, Fair Value Measurements and Disclosures (“ASC 820”). Fair value is defined under ASC 820 as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

asset or liability in an orderly transaction between market participants on the measurement date. Valuation techniques used to measure fair value under ASC 820 must maximize the use of observable inputs and minimize the use of unobservable inputs. The Company uses a three-tier hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1. Quoted prices in active markets for identical assets or liabilities.

Level 2. Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.

Level 3. Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.

The first two levels in the hierarchy are considered observable inputs and the last is considered unobservable. The Company’s cash and cash equivalents and restricted cash, which are held in operating bank accounts, are classified within Level 1 of the fair value hierarchy because they are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. The carrying value of accounts receivable and payables approximates fair value due to the short time to expected payment or receipt of cash.

Income taxes

Borr Drilling Limited is a Bermuda company that has a number of subsidiaries in various jurisdictions. Whilst the Company is resident in Bermuda, it is not subject to taxation under the laws of Bermuda, so currently, the Company is not required to pay taxes in Bermuda on ordinary income or capital gains. The Company and each of its subsidiaries and affiliates that are Bermuda companies have received written assurance from the Minister of Finance in Bermuda that in the event that Bermuda enacts legislation imposing taxes on ordinary income or capital gains, any such tax shall not be applicable to the Company or such subsidiaries and affiliates 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 and statutory tax rates in the various jurisdictions in which we operate. We provide for income taxes based on the tax laws and rates in effect in the countries in which operations are conducted and income is earned.

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

Income tax expense consists of taxes currently payable and changes in deferred tax assets and liabilities calculated according to local tax rules.

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

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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 assumptions regarding where our jack-up rigs are expected to be deployed, as well as other assumptions related to our future tax position. A change in such estimates and assumptions, along with any changes in tax laws, could require us to adjust the deferred tax assets, liabilities, or valuation allowances. The amount of deferred tax provided is based upon the expected manner of settlement of the carrying amount of assets and liabilities, using tax rates enacted at the balance sheet date. The impact of tax law changes is recognized in periods when the change is enacted.

Provisions

A provision is recognized in the balance sheet when the Company has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.

Contingencies

We recognize contingencies in the consolidated balance sheet where we have a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation and a reliable estimate of the amount can be made. If, and only when the timing of related cash flows is fixed or reliably determinable, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence.

Warrants (Equity-based payments to non-employees)

All non-employee stock-based transactions, in which goods or services are the consideration received in exchange for equity instruments are required to be accounted for based on the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable.

Earnings/(loss) per share

Basic earnings per share (“EPS”) is calculated based on the loss for the period available to common shareholders divided by the weighted average number of shares outstanding for basic EPS for the period. Diluted EPS includes the effect of the assumed conversion of potentially dilutive instruments which for the Company includes share options and warrants. The determination of dilutive earnings per share requires the Company to potentially make certain adjustments to net income and for the weighted average shares outstanding used to compute basic earnings per share unless anti-dilutive.

Interest-bearing debt

Interest-bearing debt is recognized initially at fair value less directly attributable transaction costs. Subsequent to initial recognition, interest-bearing borrowings are stated at amortized cost. Transaction costs are amortized over the term of the loan.

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BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Derivatives

We have a Call Spread (as defined below) derivative to mitigate the economic exposure from a potential exercise of conversion rights embedded in the convertible bonds. Call options bought and sold are cash settled European options exercisable only at maturity. The Call Spread derivative is fair value adjusted at each reporting period using a valuation technique that is consistent with generally accepted valuation methodologies for pricing financial instruments, and that incorporates all factors and assumptions that knowledgeable, willing market participants would consider in determining fair value. The fair value adjustments are recognized under total other income (expenses), net with a corresponding increase or decrease in other long-term assets over the duration of the bonds.

Forward contracts that meet the definition of derivative instruments are recognized at fair value. Changes in the fair value of these derivatives are recorded in total other income (expenses), net in our Consolidated Statements of Operations. Cash outflows and inflows resulting from economic derivative contracts are presented as cash flows from operations in the consolidated statement of cash flows.

Debt and equity issuance costs

Issuance costs are allocated to the debt and equity components in proportion to the allocation of proceeds to those components. Allocated costs are accounted for as debt issuance costs (capitalized and amortized to interest expense using the interest method) and equity issuance costs (charged to shareholders’ equity) recorded as a reduction of the share balance/additional paid-in capital, respectively.

Treasury shares

Treasury shares are recognized at cost as a component of shareholders’ equity.

Adoption of new accounting standards

In January 2017, the Financial Accounting Standards Board (“FASB”) issued guidance to Accounting Standards Update (“ASU”) 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business”. The amendments provide guidance on evaluating whether transactions should be accounted for as an asset acquisition or a business combination (or disposal). The guidance requires that in order to be considered a business, a transaction must include, at a minimum, an input and a substantial process that together significantly contribute to the ability to create output. The guidance removes the evaluation of whether a market participant could replace the missing elements. The revised guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within those annual reporting periods. The adoption did not have a material impact on the Consolidated Financial Statements and related disclosures.

In March 2017 the FASB issued ASU No. 2017-07, “Compensation − Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” The amendments in this update require that an employer disaggregate the service cost component from the other components of net benefit cost and provide guidance on how to present the service cost component and the other components of net benefit cost in the income statement. The guidance is effective for public company financial statements issued for annual reporting periods beginning after December 15, 2017, and interim periods within annual periods beginning after December 15, 2018. The amendment for the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost should be applied retrospectively. The adoption did not have a material impact on the Consolidated Financial Statements and related disclosures.

In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, which amends the scope of modification accounting for share-based payment arrangements, provides guidance on the types of changes to the terms or conditions of share-based payment awards to which an entity would be required to apply modification accounting under ASC 718. For all entities, the ASU is effective for annual reporting periods, including interim periods within those annual reporting periods, beginning after December 15, 2017. The adoption did not have a material impact on the Consolidated Financial Statements and related disclosures.

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BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Issued not effective accounting standards

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update requires an entity to recognize right-of-use assets and lease liabilities on its balance sheet and disclose key information about leasing arrangements. It also offers specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and early adoption is permitted. We expect to elect the new optional transition method of adoption. With respect to our drilling contracts, which could contain a lease component, we expect to apply the practical expedient. Our drilling contracts contain a lease component related to the underlying drilling equipment, in addition to the service component provided by our crews and our expertise to operate such drilling equipment. We have concluded that the non-lease service of operating our equipment and providing expertise in the drilling of the customer’s well is predominant in our drilling contracts. We expect to apply the practical expedient to account for the lease and associated non-lease operations as a single component. With the election of the practical expedient, we will continue to present a single performance obligation under the new revenue guidance in ASC 606 and recognize revenues based on the service component, which we have determined is the predominant component of our contracts. The Company believes that the adoption of this standard will not have a material effect on the Consolidated Financial Statements and related disclosures.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which revises guidance for the accounting for credit losses on financial instruments within its scope. The new standard introduces an approach, based on expected losses, to estimate credit losses on certain types of financial instruments and modifies the impairment model for available-for-sale debt securities. The guidance will be effective January 1, 2020, with early adoption permitted. Entities are required to apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company is in the process of evaluating the impact of this standard update on its Consolidated Financial Statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-13 – Fair Value Measurement (Topic 820): Disclosure Framework –Changes to the Disclosure Requirements for Fair Value Measurement. This ASU modifies the disclosure requirements in Topic 820 by identifying a narrower set of disclosures about that topic to be required on the basis of, amongst other considerations, an evaluation of whether the expected benefits of entities providing the information justify the expected costs. The amendments are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. The Company does not intend to early adopt this standard. The Company believes that the adoption of this standard will not have a material effect on the Consolidated Financial Statements and related disclosures.

In June 2018, the FASB issued ASU No. 2018-07, Compensation – Stock Compensation (Topic 718): Improvements to Nonemployee Share Based-Payment Accounting. This ASU intends to improve the usefulness of information provided and reducing the cost and complexity of financial reporting. A main objective of this ASU is to substantially align the accounting for share-based payments to employees and non-employees. The guidance is effective for annual reporting periods beginning after December 15, 2018 for public entities, including interim periods within that period, with early adoption permitted. The Company believes that the adoption of this standard will not have a material effect on the Consolidated Financial Statements and related disclosures.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This ASU refines and expands hedge accounting for both financial (e.g. interest rate) and commodity risks and creates more transparency around how economic results are presented, both on the face of the financial statements and in the footnotes, for investors and

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BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

analysts. The amendments are effective for annual periods beginning after December 15, 2018 for public entities, including interim periods within that period, with early adoption permitted. The Company believes that the adoption will not have a material effect on the Consolidated Financial Statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-14 – Compensation – Retirement Benefits – Defined Benefit Plans –General (Subtopic 715-20): Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans. This amendment modifies disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The main objective of this ASU is to remove disclosures that are no longer considered cost beneficial, clarify specific requirements of disclosures and to add disclosure requirements that are identified as relevant. The amendments are effective for fiscal years ending after December 15, 2020, with early adoption permitted. The Company does not intend to early adopt this standard. The Company believes that the adoption of this standard will not have a material effect on the Consolidated Financial Statements and related disclosures.

In November 2018, the FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808), to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the ASU specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. The accounting update also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. We are currently evaluating the impact of the adoption of the accounting standard on our Consolidated Financial Statements and related disclosures.

In July 2017, the FASB issued ASU No. 2017-11, Earnings Per Share, Distinguishing Liabilities from Equity, and Derivatives and Hedging, which changes the classification of certain equity-linked financial instruments with down round features. As a result, a free standing equity-linked financial instrument or an embedded conversion option would not be accounted for as a derivative liability at fair value as a result of existence of a down round feature. For freestanding equity classified financial instruments, the amendment requires the entities to recognize the effect of the down round feature when triggered in its earnings per share calculations. The standard is effective for fiscal years and interim periods within those fiscal years, beginning after December 15, 2018. We are currently not expecting any material impact as a result of the adoption of this accounting standard on our Consolidated Financial Statements and related disclosures.

Note 3 – Segment information

The Company has one operating segment, and this is reviewed by the Chief Operating Decision Maker, which is the Company’s board of directors (the “Board”), as an aggregated sum of assets, liabilities and activities that exists to generate cash flows.

Geographic data

Revenues are attributed to geographical location based on the country of operations for drilling activities, i.e. the country where the revenues are generated. The following presents our revenues by geographic area:

	For the Year Ended December 31,
(in $ millions)	2018		2017
Middle East		41.1		—
North Sea		75.1		—
West Africa		44.4		0.1
South East Asia		4.3
Total		164.9		0.1

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BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Major customers

In the years ended December 31, 2018 and 2017, the following customers accounted for more than 10% of our contract revenues:

	For the Year Ended December 31,
(In % of operating revenues)	2018			2017
National Drilling Company (ADOC)		21	%		—	%
TAQA Bratani Limited		17	%		—	%
BW Energy Energy Gabon S.A.		13	%		—	%
Total S.A.		13	%		100	%
Centrica North Sea Limited (Spirit Energy)		10	%		—	%
Total		73	%		100	%

Fixed Assets — Jack-up rigs⁽¹⁾

The following presents the net book value of our jack-up rigs by geographic area as of December 31, 2018 and 2017:

	As of December 31,
(In $ millions)	2018		2017
Middle East		42.0		42.5
North Sea		320.0		122.9
West Africa		203.0		169.8
South East Asia		1,713.1		448.1
Total		2,278.1		783.3

(1) The fixed assets referred to in the table above exclude assets under construction. Asset locations at the end of a period are not necessarily indicative of the geographic distribution of the revenues or operating profits generated by such assets during such period.

Contract balances

Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Current contract asset balances are included in “Deferred mobilization costs, Acquired contract backlog and Accrued revenue” and noncurrent contract assets are included in “Other assets” on our Consolidated Balance Sheets.

The following table provides information about contract assets from contracts with customers:

	As of December 31,
(In $ millions)	2018		2017
Current contract assets		45.1		10.4
Non-current contract assets		5.1		—
Total contract assets		50.2		10.4

Significant changes in the remaining performance obligation contract assets balances for the year ended December 31, 2018 are as follows:

(In $ millions)	Contract assets
Net balance at January 1, 2018		10.4
Additions to deferred costs, acquired contract backlog and accrued revenue		76.1
Amortization of deferred costs		(36.3	)
Total contract assets		50.2

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BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Contract Costs

Certain direct and incremental costs incurred for upfront preparation, initial rig mobilization and modifications are costs of fulfilling a contract and are recoverable. These recoverable costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process.

Practical expedient

We have applied the disclosure practical expedient in ASC 606-10-50-14A(b) and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue. The duration of our performance obligations varies by contract.

Impact of Topic 606 on Financial Statement Line Items

Our revenue recognition pattern under ASC 606 is materially equivalent to revenue recognition under the previous guidance. For the year ended December 31, 2018, there were no material differences, upon adoption of the new standard, to our Consolidated Balance Sheets, Consolidated Statements of Operations, or Consolidated Statements of Cash Flows.

Note 4 – Gain on disposals

We have recognized the following gains on disposal of 18 rigs for the year ended December 31, 2018:

(In $ millions)	Net proceeds / recoverable amount		Book value on disposals		Gain
April 2018		4.2		2.1		2.1
May 2018		29.0		14.3		14.7
June 2018		2.0		1.3		0.7
October 2018		2.4		1.1		1.3
Total		37.6		18.8		18.8

Gain on disposals in 2017

We did not dispose of any jack-up rigs during 2017.

Note 5 – Total other income (expenses), net

Total other income (expenses), net is comprised of the following:

	For the Year Ended December 31,
(In $ millions)	2018			2017
Foreign exchange loss		(1.1	)		(0.3	)
Other financial expenses		(3.5	)		—
(Loss)/gain on forward contracts (note 16)		(14.2	)		19.3
Change in unrealized (loss)/gain on Call Spread (note 16)		(25.7	)		—
Total		(44.5	)		19.0

(Loss)/gain on forward contracts is presented net. For the year ended December 31, 2018, the Company recorded an unrealized losses of $35.1 million and reversal of unrealized gains of $4.4 million and partly offset by realized gains of $25.3 million. For the year ended December 31, 2017 the Company recorded an unrealized gain of $4.4 million and realized accounting gain of $14.9 million.

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BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 6 – Taxation

Borr Drilling Limited is a Bermuda company not required to pay taxes in Bermuda on ordinary income or capital gains under a tax exemption granted by the Minister of Finance in Bermuda until March 31, 2035. We operate through various subsidiaries in numerous countries throughout the world and are subject to tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in jurisdictions in which we or any of our subsidiaries operate, were incorporated, or otherwise considered to have a tax presence. 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. For the year ended December 31, 2018, our pre-tax loss in 2018 is all attributable to foreign jurisdictions except for $4 million loss associated with Bermuda.

Income tax expense is comprised of the following:

	For the Year Ended December 31,
(In $ millions)	2018		2017
Current tax		2.0		—
Change in deferred tax		0.5		—
Total		2.5		—

Our annual effective tax rate for the year ended December 31, 2018 was approximately (1.3%), on a pre-tax loss of $188.4 million. Changes in our effective tax rate from period to period are primarily attributable to changes in the profitability or loss mix of our operations in various jurisdictions. As our operations continually change among numerous jurisdictions, and methods of taxation in these jurisdictions vary greatly, there is little direct correlation between the income tax provision/benefit and income/loss before taxes. A reconciliation of the Bermuda statutory tax rate to our effective rate is shown below:

Reconciliation of the Bermuda statutory tax rate to our effective rate:

	For the Year Ended December 31,
	2018			2017
Bermuda statutory income tax rate		0	%		0	%
Tax rates which are different from the statutory rate		(1.95	%)		—
Adjustment attributable to prior years		1.17	%		—
Change in valuation allowance		(0.26	%)		—
Adjustments to uncertain tax positions		(0.28	%)		—
Total		(1.32	%)		0	%

The components of the net deferred taxes are as follows:

(In $ millions)	2018			2017
Deferred tax assets
Net operating losses		12.6			—
Excess of tax basis over book basis of Property, Plant and Equipment		75.8			—
Other		2.0			—
Deferred tax assets		90.4			—
Less: Valuation allowance		(87.8	)		—
Net deferred tax assets		2.6			—
Deferred tax liabilities
Deferred tax liabilities		—			—
Net deferred tax asset (liabilities)		2.6			—

F-45

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The deferred tax assets related to our net operating losses were generated in the United Kingdom and will not expire. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if estimates of future taxable income change.

We conduct business globally and, as a result, we file income tax returns, or are subject to withholding taxes, in various jurisdictions. In the normal course of business we are generally subject to examination by taxing authorities throughout the world, including major jurisdictions we operate or used to operate, such as Denmark, Egypt, Gabon, India, Israel, the Netherlands, Nigeria, Norway, Oman, Saudi Arabia, the United Kingdom, the United States, and Tanzania. We are no longer subject to examinations of tax matters for Paragon Offshore Limited (“Paragon”) legacy companies prior to 1999.

The following is a reconciliation of the liabilities related to our unrecognized tax benefits:

(In $ millions)	2018		2017
Unrecognized tax benefits, excluding interest and penalties, at January 1,	$	—		—
Additions as a result of Paragon acquisition		4.8		—
Unrecognized tax benefits, excluding interest and penalties, at December 31,		4.8		—
Interest and penalties		3.4		—
Unrecognized tax benefits, including interest and penalties, at December 31,	$	8.1		—

We include, as a component of our income tax provision, potential interest and penalties related to liabilities for our unrecognized tax benefits within our global operations. Interest and penalties resulted in an income tax expense of $0.5 million, and $nil million for the years ended December 31, 2018 and 2017, respectively.

At December 31, 2018, the liabilities related to our unrecognized tax benefits, including estimated accrued interest and penalties, totaled $8.1 million, and if recognized, would reduce our income tax provision by $8.1 million. At December 31, 2017, the liabilities related to our unrecognized tax benefits totaled $0 million. It is reasonably possible that our existing liabilities related to our unrecognized tax benefits may increase or decrease in the next twelve months primarily due to the progression of open audits or the expiration of statutes of limitation. However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties, such as the unresolved nature of various audits.

Note 7 – Earnings/(loss) per share

The computation of basic EPS is based on the weighted average number of shares outstanding during the period. Diluted EPS exclude the effect of the assumed conversion of potentially dilutive instruments which are 2,615,000 of share options (2017: 1,711,000) outstanding issued to employees and directors and convertible bonds with a conversion price of $33.4815 for a total of 10,453,534 shares (2017: nil). Due to the current loss-making position these are deemed to have an anti-dilutive effect on the EPS of the Company.

	For the Year Ended December 31,
	2018			2017
Basic loss per share		(1.85	)		(1.70	)
Diluted loss per share		(1.85	)		(1.70	)
Issued ordinary shares at the end of the year		106,528,065			95,658,500
Weighted average number of shares outstanding during the year		102,877,501			51,726,288

The number of share options that would be considered dilutive under the if converted method in 2018 is 153,457 (2017: 87,352).

F-46

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 8 – Restricted cash

Restricted cash is comprised of the following:

	For the Year Ended December 31,
(In $ millions)	2018		2017
Opening balance		39.1		—
Transfer to (from) restricted cash		24.3		39.1
Total restricted cash		63.4		39.1

All restricted cash is classified as current assets and consist of margin accounts which have been pledged as collateral in relation to forward contracts (see Note 16) and bank deposits which have been pledged as collateral for issued guarantees.

Note 9 – Trade accounts receivable

Trade accounts receivable are presented net of allowances for doubtful accounts. The allowance for doubtful accounts receivables at December 31, 2018 was $0.1 million (2017: $nil million).

Included within trade receivables as of December 31, 2018 are amounts due from Related Parties of $nil (2017: $nil), see Note 26 for details).

Note 10 – Other current assets

Other current assets are comprised of the following:

	For the Year Ended December 31,
(In $ millions)	2018		2017
Financial instruments		—		4.4
Client rechargeable		5.1		—
Current taxes receivable		4.3		1.0
Deferred financing fee		3.2		—
Other receivables		7.9		4.1
Total other current assets		20.5		9.5

Note 11 – Jack-up rigs

Set forth below is the carrying value of our jack-up rigs

	For the Year Ended December 31,
(In $ millions)	2018			2017
Opening balance		783.3			—
Additions		307.5			688.4
Transfers from newbuildings (note 12)		1,275.7			142.8
Depreciation and amortization		(69.6	)		(21.2	)
Disposals		(18.8	)		—
Impairment		—			(26.7	)
Total		2,278.1			783.3

In addition, the Company recorded a depreciation charge of $9.9 million for the full year 2018 related to property, plant and equipment ($ nil in 2017).

F-47

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Impairment assessment of jack-up rigs

Jack-up drilling rigs are reviewed for impairment, whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Management identified indications of impairment for the years ended December 31, 2018 and 2017 and tested recoverable amounts of jack-up drilling rigs.

Future cash flows expected to be generated from the use or eventual disposal of the assets are estimated to determine the amount of impairment, if any. Estimating future cash flows requires management to make judgments regarding long-term forecasts of future revenues and costs. Significant changes to these assumptions could materially alter our calculations and may lead to impairment.

In estimating future cash flows of the jack-up rigs, management has assumed that revenue levels and utilization will be at lower levels in 2019 and thereafter start to increase, ultimately reaching revenue levels and utilization in the lower quartile observed in the jack-up market in the last 10 years.

The Company recognized an impairment of $ nil and $26.7 million for the years ended December 31, 2018 and 2017, respectively, relating to “Brage” and “Fonn” which were disposed in 2018. We estimated the fair value of the two impaired rigs using estimated scrap values less cost of disposal.

A scenario with a 10% decrease in day rates used when estimating undiscounted cash flows would result in $5.7 million shortfall between the undiscounted cash flow and carrying value for the cold stacked rig “Eir” for the year ended December 31, 2018. No other rigs will have a shortfall with a 10% decrease in day rates.

Note 12 – Newbuildings

The table below set forth our carrying value of our newbuildings:

	For the Year Ended December 31,
(In $ millions)	2018			2017
Opening balance		642.7			—
Additions		971.4			785.5
Capitalized interest		23.4			—
Transfers to jack-up rigs (note 11)		(1,275.7	)		(142.8	)
Total		361.8			642.7

The table below sets forth information regarding our rigs that were delivered during 2018, together with their final instalment and related financing where applicable

Rig	Delivery date	Final instalment ($ million)		Delivery financing ($ million)		Shipyard
Saga*	January – 18		72.5		—	Keppel
Gerd	January – 18		87.0		87.0	PPL
Gersemi	February – 18		87.0		87.0	PPL
Grid	April – 18		87.0		87.0	PPL
Gunnlod	June – 18		87.0		87.0	PPL
Skald	June – 18		72.4		—	Keppel
Groa	July – 18		87.0		87.0	PPL
Gyme	September – 18		87.0		87.0	PPL
Natt	October – 18		87.0		87.0	PPL

The table above does not include first instalment and capitalized interest and will not cast to the transfers to Jack-up Rigs. *The final instalment of $72.5 million for “Saga” was paid in December 2017, before taking delivery of the rig in January 2018.

F-48

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 13 – Asset acquisitions

Acquisition of Keppel Rigs

In May 2018, the Company signed a master agreement to acquire five premium newbuild jack-up drilling rigs from Keppel FELS Limited. Total consideration for the transaction will be approximately $742.5 million. In the second quarter of 2018, the Company paid a pre-delivery instalment of $288.0 million. The pre-delivery instalment is secured by a parent guarantee from Keppel Offshore & Marine Ltd. The Company has secured financing of the delivery payment for each Keppel Rig from Offshore Partners Pte. Ltd (formerly Caspian Rigbuilders Pte. Ltd). Each loan is non-amortizing and matures five years after the respective delivery dates. The delivery financing will be secured by a first priority mortgage, an assignment of earnings, an assignment of insurance and a charge over shares and parent guarantee from the Company. The Company expects to take delivery of the first rig in the fourth quarter of 2019, with the remaining rigs scheduled to be delivered quarterly thereafter until the last rig is delivered in the fourth quarter of 2020. The remaining contracted instalments, payable on delivery, for the Keppel newbuilds acquired in 2018 are approximately $454.5 million as of December 31, 2018.

Acquisition of PPL Rigs

In October 2017, the Company signed a master agreement with PPL Shipyard Pte Ltd. (“PPL”) setting forth the terms pursuant to which PPL agreed to sell six premium jack-up drilling rigs and three premium jack-up drilling rigs under construction at its yard in Singapore (together, the “PPL Rigs”) to designated subsidiaries of the Company for a total consideration of approximately $1,300 million, $55.8 million of this was paid per rig on October 31, 2017, and we agreed to accept delivery financing for a portion of the purchase price equal to $87.0 million per rig. The Company entered into loans for the financing of the delivery payment for each PPL Rig from PPL Shipyard Pte. Ltd. Each loan is non-amortizing and matures five years after the delivery date. These loans are secured by a first priority mortgage over the relevant PPL Rig and a guarantee from the Company. In addition, the seller is entitled to certain fees payable in connection with the increase in the market value of the relevant PPL Rig from October 31, 2017 until the repayment date, less the relevant rig owner’s equity cost of ownership of each rig and any interest paid on the delivery financing. The back-end fee, which is included within the portion of the purchase price for which we have agreed to accept delivery financing as described above, will be recognized as part of the cost price for each rig while the fees payable in connection with the increase in value of the relevant PPL Rig, as more fully described above, have not been recognized as of the date of the financial statements. The remaining contracted instalments, payable on delivery, for the PPL newbuilds are approximately $87 million as of December 31, 2018 ($696.0 million as of December 31, 2017).

Acquisition of Hercules Triumph (“Ran”) and Hercules Resilience (“Frigg”)

On December 2, 2016, the Company entered into a purchase and sale agreement with Hercules British Offshore Limited (“Hercules”) to purchase the jack-up drilling rigs “Hercules Triumph” and “Hercules Resilience” (named “Ran” and “Frigg” respectively) for a total consideration of $130.0 million. On the same date, the Company paid $13.0 million which represented 10% of the agreed contractual price for the rigs. On January 23, 2017, the Company took delivery of the rigs, which was considered to be the acquisition date.

The Company considered the guidance in ASC 805 “Business Combinations” and concluded that none of the Keppel, PPL and Hercules transactions listed above constituted a business under ASC 805 and the purchases were therefore accounted for as asset acquisitions.

Note 14 – Business combinations

Paragon Transaction

The Company announced a binding tender offer agreement (the “Tender Offer Agreement”) on February 21, 2018 to offer (“the Offer”) to purchase all outstanding shares in Paragon Offshore Limited (“Paragon”). The total acquisition price to purchase all outstanding shares was $241.3 million. The transaction was subject to the satisfaction of the offer conditions, customary closing conditions, including,

F-49

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

among other customary conditions, that (a) at least 67% of the outstanding Paragon shares were validly tendered and not withdrawn before the expiration date, (b) no material adverse change shall have occurred prior to closing, and (c) Paragon shall have completed all actions necessary to acquire ownership of certain Prospector drilling rigs and legal entities currently subject to chapter 11 proceedings in the United States Bankruptcy Court in the District of Delaware. On March 29, 2018, all of the conditions to the Offer were satisfied and the transaction closed. Shareholders holding 99.41% of the shares accepted the offer for a total payment of approximately $240.0 million.

Recognized amounts of identifiable assets acquired, and liabilities assumed at fair value:

(In $ millions)	March 29, 2018
Cash and cash equivalents		41.7
Restricted cash		4.2
Trade receivables		31.0
Other current assets (including acquired contract backlog of $31.6 million)		53.4
Jack-up drilling rigs		246.0
Assets held for sale		15.0
Property, plant and equipment		16.1
Other long-term assets (including acquired contract backlog of $12.8 million)		24.8
Trade payables		(10.5	)
Accruals and other current liabilities		(40.9	)
Long term debt		(87.7	)
Other non-current liabilities		(13.7	)
Total		279.4
Fair value of consideration satisfied by cash:
Payment upon completion by the Company (March 29, 2018)		240.0
Payment to non-controlling interest		1.3
Total		241.3
Total fair value of purchase consideration		241.3
Fair value of net assets acquired		279.4
Bargain gain		(38.1	)

At the time of the acquisition, Paragon was an international driller with a fleet of 23 drilling units. This fleet included two modern units, the Prospector 1 and Prospector 5 built in 2013 and 2014, respectively. The fleet also included a semi-submersible drilling rig, MSS1, with a long-term contract for TAQA in the North Sea which commenced on March 6, 2018. We disposed of 16 jack-up rigs acquired in the Paragon transaction during 2018.

The Paragon transaction is accounted for as a business combination. The estimated fair value of the individual rigs was derived by using a market and income-based approach with market participant-based assumptions. A bargain purchase gain of $38.1 million was recognized in the Consolidated Statement of Operations. A bargain purchase gain arises when fair value of the net assets acquired is higher than total fair value of purchase consideration.

Immediately following the closing of the Paragon transaction, the Company settled the long-term debt of $87.7 million plus $1.6 million of accrued interest and brokerage fees.

During 2018, the Company purchased the remaining outstanding shares in Paragon Offshore limited for $1.0 million.

F-50

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Restructuring

The table below sets forth the movements in restructuring provisions as a result of Paragon transaction:

(In $ millions)	2018			2017
Non-current
Opening balance		—			—
Onerous office lease (ii)		7.0			—
Non-current restructuring provision (a)		7.0			—
Current
Opening balance		—			—
Severance (i)		22.8			—
Severance payments (i)		(21.1	)		—
Onerous office lease (ii)		5.2			—
Lease payments		(2.0	)		—
Current restructuring provision (b)		4.9			—
Total (a+b)		11.9			—

(i) Severance payment

As part of the Tender Offer Agreement signed February 21, 2018, the Company initiated a workforce reduction program at closing of the transaction to align the size and composition of the Paragon workforce to Company’s expected future operations and strategy. An agreement was reached with relevant employees of Paragon that specifies the amounts payable to those made redundant. The Company recognized $22.8 million in restructuring expense for the year ended December 31, 2018 related to those employees. As of December 31, 2018, $1.7 million is recognized within other current liabilities as final settlement for Paragon employees still employed by the Company. It is expected that the liability will be settled in 2019 when the employees are no longer employed by the Company.

(ii) Office lease

The Company recognized $7.8 million as restructuring cost for vacating excess Paragon offices as part of the workforce reduction program. The restructuring expense of $7.8 million relates to future lease obligations still present after the cease of use date. The Company’s future lease obligation of $10.2 is recognized under onerous contracts, whereof $4.4 million where recognized by Paragon before the acquisition as part of Paragon’s own restructuring plan. All future payments will be recognized against onerous contracts until February 2022 when the lease obligation is settled. The Company expects no additional cost to be recognized related to the Paragon restructuring after the year ended December 31, 2018.

Paragon pro forma information (unaudited)

Basis of preparation

The unaudited pro forma financial information is based on Borr Drilling’s and Paragon’s historical consolidated financial statements as adjusted to give effect to the acquisition of Paragon. The unaudited revenue and net income (loss) for the twelve months ended December 31, 2018 and 2017 give effect to the Paragon acquisition as if it had occurred on January 1, 2017.

	Pro forma for the Year Ended December 31,
(In $ millions)	2018 (unaudited)			2017 (unaudited)
Revenue		192.1			185.5
Net income (loss)		(297.5	)		738.0

Certain one-time adjustments were included in the pro forma financial information.

For the period from March 29, 2018 until December 31, 2018, Paragon contributed $116.3 million in revenue resulting in loss before income taxes of $42.7 million, excluding bargain purchase gain of $38.1 million.

F-51

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Transocean Transaction

On March 15, 2017, the Company entered into an agreement to acquire fifteen high specification jack-up drilling rigs from Transocean Inc. (“Transocean”). The transaction consisted of Transocean’s entire jack-up fleet, comprising eight rig owning companies (which together owned 10 rigs) and five newbuildings under construction at Keppel FELS Limited’s shipyard in Singapore. Total consideration for the transaction was $1,240.5 million and included jack-up rigs of $547.7 million, onerous contract of $223.7 million, current assets of $0.5 million and future newbuild contracts of $916.0 million.

On March 15, 2017 a deposit of $32.0 million was paid to Transocean. The Company financed the transaction through a private placement of 45,720,000 shares, issued at $17.50 per share.

On May 31, 2017, the acquisition date, the Company completed the transaction with Transocean upon paying further consideration of $288.7 million, in addition to the $32.0 million deposit already paid. As a result of the transaction, the Company acquired 100% ownership of the following established rig owning entities and branches, which have been accounted for as a business combination under ASC 805:

Name of Acquired Entities	New Name of Acquired Entities
Constellation II Limited	—
GlobalSantaFe West Africa Drilling Limited	Borr Baug Limited
Transocean Andaman Limited	Borr Idun Limited
Transocean Ao Thai Limited	Borr Mist Limited
Constellation Rig Owner I Limited	Borr Atla Limited
Transocean Drilling Resources Limited	Borr Brage Limited
Transocean Drilling Services Offshore Inc.	Borr Jack-Up XIV Inc.
Transocean Siam Driller Limited	Borr Odin Limited

Three of the Transocean rigs were on contract with an external customer at the time of closing. The rigs ended their contracts in July 2017, March 2018 and October 2018, respectively. While the Company took title and ownership to the rigs at the time of closing, Transocean retained the associated revenue, expenses and cash flow associated with the customer contracts including risks and rewards. The Company agreed that the existing bareboat charters to Transocean for these rigs would continue for the remaining contract periods (the “Transocean Bareboat Charters”). As part of the agreement, the Company agreed to pay Transocean an amount equal to the amounts received by the owners of the three rigs under the Transocean Bareboat Charters to Transocean. As a result of the agreement with Transocean, the bareboat proceeds and payments for these rigs are presented net in the consolidated statement of operations.

Recognized amounts of identifiable assets acquired and liabilities assumed at fair value:

	May 31, 2017
(In $ millions)
Jack-up drilling rigs		547.7
Current assets		0.5
Onerous contract (Note 20)		(223.7	)
Total		324.5
Fair value of consideration satisfied by cash:
Deposit on March 15, 2017		32.0
Payment upon completion (May 31, 2017)		288.7
Balancing payment		3.8
Total		324.5
Total fair value of purchase consideration		324.5
Fair value of net assets acquired		324.5
Goodwill		—

F-52

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The estimated fair value of the jack-up drilling rigs was derived by using a market and income based approach with market participant-based assumptions. An onerous contract liability was recognized with regards to the newbuilding contracts acquired as the carrying value (future commitments) differed from prevailing market rates at the time of acquisition. The net present value of the newbuilding contracts has been recorded as a liability at the purchase date. No goodwill was recognized from the business combination.

Acquisition related transaction costs consisted of various legal, accounting, commissions, valuations and other professional fees which amounted to $3.3 million, which were expensed as incurred and are presented in the statement of operations within general and administrative expenses.

No quantitative pro forma profit and loss information has been prepared for the Transocean transaction, as it is impractical. Post-acquisition, the acquired business contributed $4.2 million and $nil million in operating revenue in the Consolidated Financial Statements for the year ended December 31, 2018 and the period from May 31, 2017 through December 31, 2017, resulting in a loss before income taxes of $52.1 million and $51.8 million, respectively.

In June 2017, the Company paid $275.0 million to Keppel as a second instalment of the contract value for the construction of five new-build jack-up drilling rigs. The payment of $275.0 million made by the Company was allocated first against the relevant part of the onerous contract directly attributable to each hull (newbuild). An adjustment of $38.0 million and $39.2 million was made towards the onerous contract for Hull B364 (TBN “Saga”) and Hull B365 (TBN “Skald”), respectively. A further adjustment of $62.0 million and $60.8 million was capitalized as newbuildings milestone payments for Hull B364 (TBN “Saga”) and Hull B365 (TBN “Skald”), respectively. Of the remaining $75.0 million, $25.0 million was adjusted each towards the onerous contracts for Hull B366 (TBN “Tivar”), Hull B367 (TBN “Vale”) and Hull B368 (TBN “Var”). The remaining contracted instalments as of December 31, 2018, payable on delivery, for the Keppel newbuilds acquired in 2017 are approximately $448.2 million (approximately $515 million as of December 31, 2017).

Note 15 – Marketable securities

Marketable securities are marked to market, with changes in fair value recognized in “Other comprehensive income” (“OCI”).

(In $ millions)	2018		2017
Opening balance		20.7		—
Purchase of marketable securities		13.9		26.9
Unrealized gain / (loss) on marketable securities		0.6		(6.2	)
Total		35.2		20.7

In 2017, the Company purchased debt securities for approximately $26.9 million. In 2018, the Company purchased additional debt securities for approximately $9.7 million and shares for approximately $4.2 million. An accumulated unrealized gain of $0.6 million was recognized in other comprehensive income in the year ended December 31, 2018 (loss of $6.2 million in 2017).

Note 16 – Financial instruments

Forward contracts

As of December 31, 2018, the Company has forward contracts to purchase shares in listed drilling companies for an aggregate amount of approximately $85.4 million. The unrealized loss related to these forward contracts is $35.1 million as of December 31, 2018. The forward contracts are presented net in the consolidated balance sheet as of December 31, 2018 and consist of forward assets of $50.3 million and forward liabilities of $85.4 million. As of December 31, 2018, there is $37.9 million of restricted cash recorded in the balance sheet as collateral for these forward contracts (December 31, 2017: $20.0 million).

F-53

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Call Spread

On May 16, 2018 the Company issued $350.0 million in convertible bonds due in 2023 (the “Convertible Bonds”) (see note 19). The Company has purchased from Goldman Sachs International call options over 10,453,612 shares with an exercise price of $33.4815 per share to mitigate the economic exposure from a potential exercise of the conversion rights embedded in the Convertible Bonds. In addition, the Company sold to Goldman Sachs International call options for the same number of shares with an exercise price of $42.6125 per share. The transactions are referred to as the “Call Spread”. The purpose of the Call Spread is to improve the effective conversion premium for the Company in relation to the Convertible Bonds to 75% over $24.35. The average maturity of the call options purchased and sold is May 14, 2023 with maturities starting on May 16, 2022 and ending on May 16, 2024. The call options bought and sold are European options exercisable only at maturity and are cash settled. Fair value adjustments in 2018 resulted in an unrealized loss of $25.7 million related to one-off costs for entering into the Call Spread and subsequent fair value adjustments recognized in the Consolidated Statements of Operations under total other income (expenses), net.

Note 17 – Other long-term assets

Other long-term assets are comprised of the following:

(In $ millions)	2018		2017
Other receivables		0.5		—
Deferred tax asset		2.6		—
Call Spread (Note 16)		2.8		—
Tax refunds		4.2		—
Deferred mobilisation costs — long term		5.1		—
Prepaid fees		9.5		—
Total		24.7		—

Note 18 – Accruals and other current liabilities

Accruals and other current liabilities are comprised of the following:

(In $ millions)	2018		2017
Accrued payroll and severance		3.1		—
Taxes payable		4.2		—
Total accruals and other current liabilities		7.3		—

Note 19 – Long-term debt

Long-term debt is comprised of the following:

									Maturities
As of December 31, 2018 (In $ millions)	Carrying value		Fair value		Principal		Back end fee		Less than 6 months		6 months to 1 year		1-5 years
$200 million senior secured revolving loan facility		130.0		130.0		130.0		—		—		—		130.0
Convertible bonds		346.5		287.9		350.0		—		—		—		350.0
Delivery financing from PPL		698.1		695.7		669.6		26.1		—		—		695.7
Total		1,174.6		1,113.6		1,149.6		26.1		—		—		1,175.7

									Maturities
As of December 31, 2017 (In $ millions)	Carrying value		Fair value		Principal		Back end fee		Less than 6 months		6 months to 1 year		1-5 years
Delivery financing from PPL		87.0		87.0		83.7		3.3		—		—		87.0
Total		87.0		87.0		83.7		3.3		—		—		87.0

F-54

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

$200 million senior secured revolving loan facility

In May 2018, we entered into a $200 million senior secured revolving loan facility agreement with DNB Bank ASA (the “DNB Revolving Credit Facility”) secured by mortgages over five of our jack-up rigs, assignments of rig insurances, pledges over shares and related guarantees from certain of our rig-owning subsidiaries who provide this security as owners of the mortgaged rigs. As of December 31, 2018, $70 million remained undrawn under our DNB Revolving Credit Facility. Our DNB Revolving Credit Facility agreement contains various financial covenants, including requirements that we maintain a minimum book equity ratio of 40%, positive working capital and minimum liquidity equal to the greater of $50 million and 5% of net interest-bearing debt. Our DNB Revolving Credit Facility Agreement also contains a loan to value clause requiring that the fair market value of our rigs shall at all times cover at least 175% of the aggregate outstanding facility amount and any undrawn and uncancelled part of the facility. The facility also contains various covenants, including, among others, restrictions on incurring additional indebtedness and entering into joint ventures; restrictions on paying dividends; and restrictions on the repurchase of our Shares; restrictions on changing the general nature of our business; and restrictions on removing Tor Olav Trøim from our Board. Furthermore, Tor Olav Trøim is required to maintain ownership of at least six million Shares (subject to adjustment for certain transactions). Our DNB Revolving Credit Facility agreement also contains events of default which include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the DNB Revolving Credit Facility agreement or security documents or jeopardize the security provided thereunder. If there is an event of default, DNB Bank ASA may have the right to declare a default or may seek to negotiate changes to the covenants and/or require additional security as a condition of not doing so. DNB Bank ASA may also require replacement or additional security if the fair market value of the jack-up rigs over which security is provided is insufficient to meet our market value-to-loan covenant.

The DNB Revolving Credit Facility matures in May 2020 and bears interest at a rate of LIBOR plus a specified margin.

In January 2019, we executed an amendment to the DNB Revolving Credit Facility agreement which allows us to procure the issuance of guarantees as required in the ordinary course of business, typically for bid bonds, import bonds and performance bonds, up to an aggregate amount of $30 million. Our obligations to reimburse the bank for any payment made under such guarantees is secured by the guarantees, security over the rigs, insurances and shares provided under the DNB Revolving Credit Facility agreement. This amendment replaced the cash collateral required by the common terms agreement with DNB Bank ASA, which we refer to as the Guarantee Facility, and resulted in the release of $25.0 million of cash that was categorized as restricted as of December 31, 2018.

As of December 31, 2018, we were in compliance with the covenants and our obligations under the DNB Revolving Credit Facility agreement. We expect to remain in compliance with the covenants and our obligations under the DNB Revolving Credit Facility agreement in 2019.

As of December 31, 2018, Frigg, Idun, Norve, Prospector 1 and Prospector 5 were pledged as collateral for the Senior Secured Revolving Loan Facility. Total book value of the encumbered rigs was $482.0 million as of December 31, 2018.

Convertible Bonds

In May 2018 we raised $350.0 million through the issuance of our Convertible Bonds, which mature in 2023. The initial conversion price (which is subject to adjustment) is $33.4815 per Share, for a total of 10,453,534 Shares. The Convertible Bonds have a coupon of 3.875% per annum payable semi-annually in arrears in equal installments. The terms and conditions governing our Convertible Bonds contain customary events of default, including failure to pay any amount due on the bonds when due, and certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to incur secured capital markets indebtedness. The Company has entered into Call Spreads to mitigate the effect of conversion – see Note 16 for details.

As of December 31, 2018, we were in compliance with the covenants and our obligations under our Convertible Bonds. We expect to remain in compliance with our obligations under our Convertible Bonds in 2019.

F-55

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Our Delivery Financing Arrangements

In addition to two jack-up rigs which we have taken delivery of against full payment from Keppel, we have contracts with Keppel to purchase nine jack-up rigs under construction. We have the option to accept delivery financing for two of the jack-up rigs to be delivered from Keppel. For five of our newbuild jack-up rigs under construction and nine additional jack-up rigs which have been delivered from PPL, we have agreed to accept and accepted, respectively, delivery financing from PPL and Keppel subject to the terms described below:

PPL Newbuild Financing

In October 2017, we agreed to acquire nine premium “Pacific Class 400” jack-up rigs from PPL (the “PPL Rigs”). We accepted delivery of eight of the PPL Rigs as of December 31, 2018 and all nine PPL Rigs had been delivered as of January 31, 2019. In connection with delivery of the PPL Rigs, our rig-owning subsidiaries as buyers of the PPL Rigs agreed to accept delivery financing for a portion of the purchase price equal to $87.0 million per jack-up rig (the “PPL Financing”).

The PPL Financing for each PPL Rig is an interest-bearing secured seller’s credit, guaranteed by the Company which matures on the date falling 60 months from the delivery date of the respective PPL Rig.

The PPL Financing for each respective PPL Rig is secured by a mortgage on such PPL Rig and an assignment of the insurances in respect of such PPL Rig. The PPL Financing also contains various covenants and the events of default include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the PPL Financing agreements or security documents, or jeopardize the security. In addition, each rig-owning subsidiary is subject to covenants which management considered to be customary in a transaction of this nature.

As of December 31, 2018, we had $695.6 million of PPL Financing outstanding and were in compliance with the covenants and our obligations under the PPL Financing agreements. We expect to remain in compliance with the covenants and our obligations under the PPL Financing agreements in 2019. We expect to satisfy our obligations under the PPL Financing for each respective PPL Rig with cash flow from operations when due.

As of December 31, 2018, Galar, Gerd, Gersemi, Grid, Gunnlod, Groa, Gyme and Natt were pledged as collateral for the PPL financing. Total book value for the encumbered rigs was $1,151.3 million as of December 31, 2018.

Keppel Newbuild Financing

In May 2018, we agreed to acquire five premium KFELS B class jack-up rigs, three completed and two under construction from Keppel (the “Keppel Rigs”). As of December 31, 2018, all five Keppel Rigs remain to be delivered. In connection with delivery of the Keppel Rigs, Keppel has agreed to extend delivery financing for a portion of the purchase price equal to $90.9 million per jack-up rig (the “Keppel Financing”). Separately from the Keppel Financing described below, we may exercise an option to accept delivery financing from Keppel with respect to two additional newbuild jack-up rigs, “Vale” and “Var,” acquired in connection with the Transocean Transaction. We will, prior to delivery of each jack-up rig from Keppel, consider available alternatives to such financing.

The Keppel Financing for each Keppel Rig is an interest-bearing secured facility from the lender thereunder (an affiliate of Keppel), guaranteed by the Company which will be made available on delivery of each Keppel Rig and matures on the date falling 60 months from the delivery date of each respective Keppel Rig.

The Keppel Financing for each respective Keppel Rig will be secured by a mortgage on such Keppel Rig, assignments of earnings and insurances and a charge over the shares of the rig-owning subsidiary which holds each such Keppel Rig. The Keppel Financing agreements also contain a loan to value clause requiring that the fair market value of our rigs shall at all times be at least 130% of the loan and also contains various covenants, including, among others, restrictions on incurring additional indebtedness. Each Keppel Financing agreement also contains events of default which include non-payment, cross default, breach of covenants, insolvency and changes which have or are likely to have a material adverse effect on the relevant obligor’s business, ability to perform its obligations under the Keppel Financing agreements or security documents, or jeopardize the security.

F-56

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2018, we had no Keppel Financing outstanding and were in compliance with our pre-drawdown covenants and obligations under the Keppel Financing agreements. We expect to remain in compliance with our Keppel Financing obligations in 2019. We expect to satisfy our obligations under the Keppel Financing for each respective Keppel Rig with cash flow from operations when due.

Interest

Average interest rate for all our interest-bearing debt was 5.84% for the year ended December 31, 2018.

Note 20 – Onerous contracts

Onerous contracts are comprised of the following:

(In $ millions)	2018		2017
Onerous lease commitments		10.2		—
Onerous rig construction contracts acquired		71.3		71.3
Total onerous contracts		81.5		71.3

Onerous contracts for Hull B366 (TBN “Tivar”) of $16.8 million, Hull B367 (TBN “Vale”) of $26.9 million and Hull B368 (TBN “Var”) of $27.6 million, in total $71.3 million, relate to the estimated excess of remaining shipyard instalments to be made to Keppel FELS over the value in use estimate for the jack-up drillings rigs to be delivered. Remaining shipyard instalments and onerous contract are expected to be amortized when the newbuildings are delivered and paid in 2020.

Note 21 – Commitments and contingencies

The Company has the following commitments:

	As at December 31, 2018				As at December 31, 2017
(In $ millions)	Delivery instalment		Back-end fee		Delivery instalment		Back-end fee
Delivery instalments for jack-up drilling rigs		963.9		25.8		1,190.2		26.0

In addition, under the PPL Financing, PPL is entitled to certain fees payable in connection with the increase in the market value of the relevant PPL Rig from October 31, 2017 until the repayment date, less the relevant rig owner’s equity cost of ownership of each rig and any interest paid on the delivery financing. See note 13.

The following table sets for maturity of our commitments as of December 31, 2018

(In $ millions)	Less than 1 year		1–3 years		3–5 years		More than 5 years		Total
Delivery instalments for jack-up rigs		170.1		793.8		0.0		0.0		963.9

Operating leases

Future minimum lease payments for operating leases for years ending December 31, 2018 are as follows:

(In $ millions)	2019		2020		2021		2022		Thereafter		Total
Minimum lease payments		4.6		3.6		3.6		0.5		—		12.3

Our leases consist of office leases, warehouses, vehicles and office equipment. The majority of our lease commitments relate to office leases, of which $10.2 million is recognized as onerous lease liability, (see note 20). At the end of the various initial lease terms the Company can renew its leases, usually for a period of one year. As of December 31, 2018, all our leases were classified as operational leases.

F-57

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Other commercial commitments

We have other commercial commitments which contractually obligate us to settle with cash under certain circumstances. Surety bonds and parent company guarantees entered into between certain customers and governmental bodies guarantee our performance regarding certain drilling contracts, customs import duties and other obligations in various jurisdictions.

The principal amount of the outstanding surety bonds were $13.2 million and $12.9 million as of December 31, 2018 and 2017, respectively. In addition, we had outstanding bank guarantees and performance bonds amounting to $9.8 million (2017: $3.0 million).

As of December 31, 2018, these obligations stated in $ equivalent and their expiry dates are as follows:

(In $ millions)	2019		2020		2021		2022		Thereafter		Total
Surety bonds and other guarantees		22.6		—		—		—		0.5		23.1

Rigs pledged as collateral

As of December 31, 2018, Frigg, Idun, Norve, Prospector 1 and Prospector 5 were pledged as collateral for the DNB Revolving Credit Facility. The Total book value of the encumbered rigs was $482.0 million as of December 31, 2018.

As of December 31, 2018, Galar, Gerd, Gersemi, Grid, Gunnlod, Groa, Gyme and Natt were pledged as collateral for the PPL financing. The total book value for the encumbered rigs was $1,151.3 million as of December 31, 2018.

Note 22 – Non-controlling interest

Non-controlling interests consists of a 10% ownership interest in Borr Jack-Up XVI Inc. acquired in late 2017 by Valiant Offshore Contractors Limited.

Note 23 – Share based compensation

Share-based payment charges for the year ending

(In $ millions)	2018		2017
Share-based payment charge		3.7		1.8
Total		3.7		1.8

In January, April, July, September and October 2018 the Company issued 10,000, 30,000, 1,564,000, 20,000 and 40,000 share options, respectively, to employees of the Company. The options have an exercise price per share $20.00, $21.00, $24.35, $22.95 and $22.75, respectively. Share price at grant date for the 2018 grants was $21.75, $22.85, $22.95, $22.80 and $22.85, respectively. The options will expire after five years and have a four-year vesting period. The total estimated cost of the share option granted in 2018 will be approximately $9.9 million which will be expensed over the requisite service period. The total aggregated number of share options authorized by the Board is 3,494,000. As of December 31, 2018, 2,615,000 share options are outstanding.

In June, July and October 2017, the Company issued 896,000, 560,000 and 375,000 share options, respecively, to employees of the Company. The options expire in five years and vest over a period of three years. Vesting is contingent upon employment on the vesting date. The exercise price is $17.50 per share for the options issued in June and July 2017 and $20.00 per share for the options issued in October 2017. The share price at the grant date for the options issued in October 2017 was $21.80. The Company was not listed when granting options in June and July 2017. The options are non-transferable. The fair values of the share options were calculated at $2.9 million, $1.7 and $2.2 million, respectively, and will be charged to the statement of operations as general and administrative expenses over the vesting period.

F-58

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

During 2017 the Company transferred 100,000 of its treasury shares to the then-CEO as part of his remuneration package and $1.7 million was charged to the statement of operations in 2017. As part of the CEO’s termination, the Company repurchased 100,000 of its own shares at a price of $23.25 per share for a total consideration of $2.3 million. The Company transferred 14,285 treasury shares to a director as settlement of director’s fees in the fourth quarter of 2018.

The table below sets forth the number of share options granted and weighted average exercise price during the years ended December 31, 2018 and 2017.

	2017				2018
Number and weighted average exercise price stock options:	Number		Weighted Average Exercise Price (in $)		Number		Weighted Average Exercise Price (in $)
Outstanding at January 1		—		—		1,711,000		18.0
Granted during the year		1,711,000		18.0		1,664,000		24.0
Exercised during the year		—		—		—		—
Forfeited during the year		—		—		760,000		18.0
Outstanding at December 31		1,711,000		18.0		2,615,000		22.0
Exercisable at December 31		—		—		333,666		18.0

The fair value of equity settled options are measured at grant date using the Black Scholes option pricing model.

Following input is used when calculating fair value:	2017	2018
Expected future volatility	25%	30%
Expected dividend rate	—	—
Risk-free rate	1.5% - 2.0%	2.1% - 2.9%
Expected life after vesting	2 years	2 years

In 2017 the expected future volatility was based on peer group volatility due to the short lifetime of the Company. In 2018 volatility was derived by using an average of (i) Historic volatility of the Company’s shares since listing on the Oslo Stock Exchange (ii) Deleveraged peer group volatility (iii) Oslo Energy sector index volatility.

Note 24 – Fair values of financial instruments

The carrying value and estimated fair value of the Company’s cash and financial instruments were as follows:

			As at December 31, 2018				As at December 31, 2017
(In $ millions)	Hierarchy		Fair value		Carrying value		Fair value		Carrying value
Assets
Cash and cash equivalents		1		27.9		27.9		164.0		164.0
Restricted cash		1		63.4		63.4		39.1		39.1
Marketable securities – non-current		1		31.0		31.0		20.7		20.7
Marketable securities – current		1		4.2		4.2		—		—
Other current assets (excluding prepayments and financial instruments)		1		20.5		20.5		9.5		9.5
Forward contracts (note 16)		2		50.3		50.3		60.6		60.6
Liabilities
Long term liabilities		2		1,113.6		1,174.6		87.0		87.0
Other non-current liabilities				8.0		8.0		—		—
Trade payables		1		10.0		10.0		9.6		9.6
Accruals and other current liabilities		1		71.0		71.0		11.5		11.5
Forward contracts (note 16)		2		85.4		85.4		56.2		56.2

F-59

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Financial instruments included in the table above are included within ‘Level 1 and 2’ of the fair value hierarchy because they are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. The forward contracts are presented net in the consolidated balance sheet as of December 31, 2018 and December 31, 2017. The carrying value of any accounts receivable and payables approximates fair value due to the short time to expected payment or receipt of cash.

Note 25 – Warrants

Schlumberger Oilfield Holdings Limited

On March 21, 2017, the Company issued 947,377 warrants to subscribe for ordinary shares at a subscription price of $17.50 plus 4% per annum. per share to Schlumberger Oilfield Holdings Limited (“Schlumberger”) for its role, support and participation in the March 2017 Private Placement. At the grant date, the warrants issued to Schlumberger were valued at $3.01 million and were deemed to have vested on the basis that Schlumberger had fulfilled all of its performance criteria. The amount recognized as additional paid in capital with respect to the warrants issued to Schlumberger was $3.01 million in which the entire amount has been allocated against equity as issuance costs within the Statement of Changes in Shareholders’ Equity for the year ended December 31, 2017. The average contractual term of the warrants was 4 years.

In October 2017, the Company issued 947,377 additional warrants to Schlumberger as a consequence of a final collaboration agreement between the Company and Schlumberger being signed. The warrants were valued at $4.7 million which was charged to the statement of operations in 2017. Immediately thereafter, the Company agreed to repurchase all of 1,894,754 Warrants held by Schlumberger at a price of $2.50 per Warrant, $4.7 million in total. Consequently, all warrants originally issued to Schlumberger were then cancelled.

The warrants outstanding as of December 31, 2018 were as follows:

	Number of Shares Outstanding under Warrants		Weighted Average Exercise Price per Share		Average Contractual Term
Warrants outstanding, December 31, 2016		1,937,500	$	0.05	5 years
Granted		—		—
Exercised		1,937,500	$	0.05
Warrants outstanding, December 31, 2017		—		—	—
Granted		—		—	—
Exercised		—		—	—
Warrants outstanding, December 31, 2018		—		—	—

Note 26 – Related party transactions

Agreements and other Arrangements with Drew Holdings Limited (“Drew”)

Drew is a trust established for the benefit of Tor Olav Trøim, chairman of our Board. Drew is, following its merger with Taran Holdings Limited (“Taran”) in 2017, a large shareholder in us.

Loans & Related Facilities

A short-term loan of $13.0 million was provided by Taran to us on December 2, 2016 to finance the deposit payable for the Hercules acquisition, which was completed in January 2017. The loan was repaid with no interest accruing by way of set-off against Taran’s subscription of shares in our first private placement in December 2016.

Taran also provided us with a revolving credit facility of $20.0 million on December 12, 2016. The facility was never utilized and expired at the completion of the Transocean transaction.

F-60

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Taran provided us with a short-term loan of $12.75 million on March 15, 2017, to finance a deposit payable pursuant to the terms of the acquisition agreement for the Transocean Transaction. The loan was repaid with no interest accrued by way of set-off against Taran’s payment obligations for its subscription of shares in our private placement in March 2017.

Other

On March 22, 2018, it was announced that we would raise up to $250 million in an equity offering divided in two tranches. Tranche 2 of the equity offering was subject to approval by the extraordinary general meeting to be held on April 5, 2018 and subsequent share issue. In connection with the settlement of tranche 2, $27.7 million was recorded as a liability to shareholders, including $20.0 million to Drew as of March 31, 2018. On May 30, 2018, the 1,528,065 new shares allocated in tranche 2 of the equity offering were validly issued and fully paid and the related liabilities settled.

Agreements and other Arrangements with Magni Partners Limited (“Magni”)

Mr. Tor Olav Trøim is the chairman of our Board and is the sole owner of Magni.

Corporate Support Agreement

Magni is party to a Corporate Support Agreement with the Company pursuant to which it is providing strategic advice and assistance in sourcing investment opportunities, financing etc. This agreement was formalized on March 15, 2017.

Magni received cash compensation of $1.4 million for various commercial services provided in connection with the acquisition of the Hercules rigs (Hercules Triumph and Hercules Resilience) which completed in the first quarter of 2017. Of this amount $1.0 million has been capitalized within drilling rigs, $0.3 million has been offset against additional paid in capital as equity issuance cost and $0.07 million has been recognized within opening retained earnings.

In the third quarter of 2017, $2.0 million was paid to Magni for its assistance in the March 2017 Private Placement ($1.75 million) and Transocean Transaction ($0.25 million). The total cost for the March 2017 Private Placement (including the payment to the investment banks and Magni) was $8.75 million, or 1.1% of the gross proceeds. In the fourth quarter of 2017, $1.5 million was paid to Magni for its assistance in the October 2017 Private Placement ($1.25 million) and PPL Transaction ($0.25 million). The total cost for the October 2017 Private Placement (including the payment to the investment banks and Magni) was $8.75 million, or 1.3% of the gross proceeds.

Agreements and other Arrangements with Schlumberger Limited (“Schlumberger”)

Schlumberger is our largest shareholder, holding 14,2% at December 31, 2018 and Patrick Schorn, Executive Vice President of Wells at Schlumberger Limited, is a Director on our Board.

Collaboration Agreement

On October 6, 2017, we signed an enhanced collaboration agreement with Schlumberger with the intention of offering performance-based drilling contracts to our clients whereby the required drilling services along with the rig equipment were integrated under a single contract. We believe that this provide us with a competitive advantage while tendering for such work.

Warrants

On March 28, 2017 our Board issued warrants to Schlumberger – see Note 25.

Commercial Arrangements

We have obtained certain rig and other operating supplies from Schlumberger and may continue to obtain such supplies in the future. Purchases from Schlumberger were $8.5 million during 2018 and $0.1 million during 2017. $0.4 million and $ nil were outstanding at December 31, 2018 and 2017, respectively.

F-61

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 27 – Risk management and financial instruments

Financial instruments that potentially subject the Company to concentration of credit risk consist principally of cash deposits. Accounts held at Norwegian finance institutions are insured by Norges Bank (Bank of Norway) up to NOK 2.0 million. As of December 31, 2018, the Company had $91.1 million (December 31, 2017: $202.9 million) in excess of the Norges Bank insured limit. Of the uninsured amount at December 31, 2018, $nil (December 31, 2017: $140.0 million) was held on a short-term time deposit account.

Foreign exchange risk management

The majority of the Company’s transactions, assets and liabilities are denominated in U.S. dollars, the functional currency of the Company. However, the Company has operations and assets in other countries and incurs expenditures in other currencies, causing its results from operations to be affected by fluctuations in currency exchange rates, primarily relative to the U.S. dollar. There is thus a risk that currency fluctuations will have a positive or negative effect on the value of the Company’s cash flows. The Company has not entered into derivative agreements to mitigate the risk of fluctuations.

Market risk for forward contracts and marketable securities

The Company’s listed equity securities are susceptible to market price risk arising from uncertainties about future values of the investment securities.

Supplier risk

A supplier risk exists in relation to our vessels undergoing construction with Keppel and PPL. However, we believe this risk is remote as Keppel and PPL are global leaders in the rig and shipbuilding sectors. Failure to complete the construction of any newbuilding on time may result in the delay, renegotiation or cancellation of employment contracts secured for the newbuildings. Further, significant delays in the delivery of the newbuildings could have a negative impact on the Company’s reputation and customer relationships. The Company could also be exposed to contractual penalties for failure to commence operations in a timely manner or experience a loss due to non-payment under refund guarantees issued by Keppel’s and PPL’s respective parent, all of which would adversely affect the Company’s business, financial condition and results of operations.

Concentration of financing risk

There is a concentration of financing risk with respect to our long-term debt to the extent that a substantial amount of our long-term debt is carried or will be carried by Keppel and PPL in the form of shipyard financing. We believe the counterparties to be sound financial institutions. Therefore, we believe this risk is remote.

Note 28 – Common shares

	December 31, 2018					December 31, 2017
All shares are common shares of $0.01 par value each	Shares		$ million			Shares		$ million
Authorized share capital		125,000,000		6.3			105,000,000		5.3
Issued and fully paid share capital		106,528,065		5.3			95,658,500		4.8
Treasury shares held by the company		1,459,714		(0.1	)		394,000		—
Outstanding shares in issue		105,068,351		5.3			95,264,500		4.8

As at December 31, 2018, our shares were listed on the Oslo Stock Exchange.

On March 23, 2018, 9,341,500 new shares were issued at a subscription price of 23.00 per share. On May 30, 2018, 1,528,065 new shares were issued at a subscription price of 23.00 per share. As of December 31, 2018, the Company has a share capital of $5,326,403.27 divided into 106,528,065 shares.

F-62

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

On August 8, 2017, the Company’s Board of Directors approved share repurchase program for the Company’s shares to purchase 494,000 shares in the open market. In the third quarter of 2017, the Company purchased 494,000 shares for $8.4 million, and transferred 100,000 treasury shares to the former CEO of the Company (see note 23). On August 28, 2018, the Company’s Board of Directors approved a share repurchase program for the Company’s shares, to be purchased in the open market by December 30, 2018 and limited to a total amount of $20.0 million. In the first quarter of 2018, the Company purchased 100,000 treasury shares at a cost of $2.3 million. In the third quarter of 2018, the Company purchased 340,000 treasury shares at a cost of $7.4 million. In the fourth quarter of 2018 the Company purchased 640,000 shares at a cost of $10.0 million. No treasury shares are canceled as of December 31, 2018.

The Company transferred 14,285 treasury shares as settlement of director’s fees in the fourth quarter of 2018. At December 31, 2018 the Company owned 1,459,714 treasury shares. All treasury shares were pledged as collateral for forward contracts at December 31, 2018.

Note 29 – Pension

Defined Benefit Plans

As part of the Paragon acquisition on March 29, 2018, the Company acquired two defined benefit pension plans.

As of December 31, 2018, the Company sponsored two non-U.S. noncontributory defined benefit pension plans, the Paragon Offshore Enterprise Ltd and the Paragon Offshore Nederland B.V. pension plans, which cover certain Europe-based salaried employees. As of January 1, 2017, all active employees under the defined benefit pension plans were transferred to a defined contribution pension plan as related to their future service. The accrued benefits under the defined benefit plans were frozen and all employees became deferred members. The transfer to a defined contribution pension plan was accounted for as a curtailment during the year ended December 31, 2016.

At December 31, 2018 our pension obligations represented an aggregate liability of $140.7 million and an aggregate asset of $141.0 million, representing the funded status of the plans. In the year ended December 31, 2018, aggregate periodic benefit costs showed interest cost of $1.6 million and expected return on plan assets of $1.6 million. Our defined benefit pension plans are recorded at fair value. See Note 2 – Accounting Policies – Adoption of new accounting standards.

A reconciliation of the changes in projected benefit obligations (“PBO”) for our pension plans is as follows:

(In $ millions)	December 31, 2018
Benefit obligation at beginning of period		—
Benefit obligation acquired through business combination		147.2
Service cost		—
Interest cost		1.6
Actuarial loss (gain)		4.2
Benefits and expenses paid		(1.0	)
Foreign exchange rate changes		(11.3	)
Benefit obligation at end of period		140.7

F-63

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the changes in fair value of plan assets is as follows:

(In $ millions)	December 31, 2018
Fair value of plan assets at beginning of period		—
Plan assets acquired through business combination		146.5
Actual return on plan assets		5.8
Employer contribution		1.0
Benefits paid		(1.0	)
Plan participants’ contributions		0.1
Expenses paid		—
Foreign exchange rate changes		(11.2	)
Fair value of plan assets at end of period		141.0

The funded status of the plans is as follows:

(In $ millions)	As of December 31, 2018
Funded status		0.3

Amounts recognized in the Consolidated Balance Sheets consist of:

(In $ millions)	December 31, 2018
Other assets - noncurrent		0.3
Other liabilities - noncurrent		—
Net pension asset (liability)		0.3
Accumulated other comprehensive loss recognized in financial statements		—
Net amount recognized		0.3

Amounts recognized in OCI consist of:

(In $ millions)	December 31, 2018
Net loss		—
Accumulated other comprehensive income (loss)		—

Pension cost includes the following components:

(In $ millions)	2018
Interest cost		1.6
Expected return on plan assets		(1.6	)
Net pension expense		—

Defined Benefit Plans - Disaggregated Plan Information

Disaggregated information regarding our pension plans is summarized below:

(In $ millions)	December 31, 2018
Projected benefit obligation		140.7
Accumulated benefit obligation		140.7
Fair value of plan assets		141.0

F-64

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Defined Benefit Plans – Key Assumptions

The key assumptions for the plans are summarized below:

Weighted Average Assumptions Used to Determine Benefit Obligations	As of December 31, 2018
Discount rate	1.16% to 1.50%
Rate of compensation increase	Not applicable

Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	March 29, 2018 to December 31, 2018
Discount rate	1.16% to 1.50%
Expected long-term return on plan assets	1.16% to 1.50%
Rate of compensation increase	Not applicable

The discount rates used to calculate the net present value of future benefit obligations are determined by using a yield curve of high-quality bond portfolios with an average maturity approximating that of the liabilities.

We use a portfolio return model to assess the initial reasonableness of the expected long-term rate of return on plan assets. To develop the expected long-term rate of return on assets, we considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets for the portfolio.

Defined Benefit Plans – Plan Assets

At December 31, 2018, assets of Paragon Offshore Enterprise Ltd and Paragon Offshore Nederland B.V. pension plans were invested in instruments that are similar in form to a guaranteed insurance contract. The plan assets are based on surrender values. Surrender values are calculated based on the Dutch Central Bank interest curve. This yield curve is based on inter-bank swap rates. There are no observable market values for the assets (Level 3); however, the amounts listed as plan assets were materially similar to the anticipated benefit obligations under the plans.

The actual fair value of our pension assets as of December 31, 2018 is as follows:

			Estimated Fair Value Measurements
(In $ millions)	Carrying Amount		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2018
Guaranteed insurance contracts		140.7		—		—		140.7
Other		0.3		—		—		0.3
Total		141.0		—		—		141.0

The following table details the activity related to the guaranteed insurance contract during the years.

	Fair value
Balance as of January 1, 2018	$	—
Acquisition of plan assets		146.5
Balance as of March 29, 2018		146.5
Assets sold/benefits paid		0.1
Return on plan assets		5.8
Foreign exchange rate changes		(11.3	)
Balance as of December 31, 2018		141.0

F-65

BORR DRILLING LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Defined Benefit Plans – Cash Flows

In 2018 we made $1.0 million in contributions to our defined benefit pension plans.

The following table summarizes the benefit payments at December 31, 2018 estimated to be paid within the next ten years by the issuer of the guaranteed insurance contract:

			Payments by Period
	Total		2019		2020		2021		2022		2023		Five Years Thereafter
Estimated benefit payments		28.2		1.5		1.7		1.9		2.2		2.6		18.3

Note 30 – Subsequent events

Delivery of Njord

In January 2019, we took delivery of the “Njord”. The final delivery installment was $87.0 million, which was financed through shipyard financing for the same amount.

Secured $160 million financing

In March 2019, we executed a $160 million financing agreement consisting of a $100 million revolving credit facility and a $60 million guarantee credit line for issuance of guarantees.

Appointment of Directors

The Board of Directors appointed Alexandra Kate Blankenship as director of the Company and Georgina Sousa as director and company secretary on February 27, 2019.

Share option awards

In March 2019, we granted 460,000 options to certain employees and directors of the Company. The awards were granted under the existing approved share option scheme. The options have a strike price of $17.50 per share.

Novation of “Thor”

In March 2019, we entered into an assignment agreement with BOTL Lease Co. Ltd. (the “Original Owner”) for an assignment, and subsequently a novation and amendment agreement of the rights and obligations to purchase a KFELS Super B Bigfoot premium jack-up drilling rig with hull number B378 being built by Keppel FELS Limited for a purchase price of $122.1 million. We expect to take delivery of the rig from the yard prior to May 31, 2019 and the rig will be named “Thor”.

To finance the rig purchase we entered into a $120 million senior secured term loan facilities agreement, consisting of two facilities (Facility A and Facility B) of $60 million each. The facilities mature on September 30, 2019. As of April 29, 2019, Facility A had been utilized in the amount of $60 million, and $60 million in Facility B remained undrawn. The availability period of Facility B expires June 30, 2019.

F-66

REPORT OF INDEPENDENT AUDITORS

To the Management of Paragon Offshore Limited

We have audited the accompanying consolidated financial statements of Paragon Offshore plc and its subsidiaries (the “Predecessor” or “Company”), which comprise the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for the period from January 1, 2017 to July 18, 2017.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Paragon Offshore plc and its subsidiaries for the period from January 1, 2017 to July 18, 2017 in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company filed a petition on February 14, 2016 with the United States Bankruptcy Court for the district of Delaware for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Fifth Joint Chapter 11 filing was substantially consummated on July 18, 2017 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting. Also as discussed in Note 1, the Company is in the process of winding down its operations, which raises substantial doubt about the Company’s ability to continue as a going concern. Management’s plans are discussed in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to these matters.

/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 8, 2018

F-67

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Management of Paragon Offshore Limited

We have audited the accompanying consolidated financial statements of Paragon Offshore Limited and its subsidiaries (the “Successor” or “Company”), which comprise the consolidated balance sheet as of December 31, 2017 and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for the period from July 18, 2017 to December 31, 2017.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Paragon Offshore Limited and its subsidiaries as of December 31, 2017 and the results of their operations and their cash flows for the period from July 18, 2017 to December 31, 2017 in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

As discussed in Note 1 to the consolidated financial statements, on July 18, 2017, Paragon Offshore plc (the “Predecessor”) transferred certain direct and indirect subsidiaries and certain other assets to the Company pursuant to the fifth amended plan of reorganization for debtors filed with the Bankruptcy Court. Also as discussed in Note 1 to the consolidated financial statements, the Company signed a tender agreement on February 22, 2018 to sell all of its outstanding shares to a third party. Our opinion is not modified with respect to these matters.

/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 8, 2018

F-68

PARAGON OFFSHORE LIMITED
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)

	Successor			Predecessor
	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Operating revenues
Contract drilling services	$	54,651		$	124,663
Labor contract drilling services		—			—
Reimbursables and other		1,380			4,760
		56,031			129,423
Operating costs and expenses
Contract drilling services		78,702			96,853
Labor contract drilling services		—			(566	)
Reimbursables		936			3,296
Depreciation and amortization		24,636			66,860
General and administrative		13,778			17,312
Loss on impairments		18,745			391
Gain on sale of assets, net		(833	)		(1,383	)
		135,964			182,763
Operating loss before interest, reorganization items and income taxes		(79,933	)		(53,340	)
Interest expense, net		(2,952	)		(39,610	)
Other, net		986			3,452
Reorganization items, net		—			895,931
Other non-operating items		1,069			—
Earnings from equity method affiliate		1,519			—
Income (loss) before income taxes		(79,311	)		806,433
Income tax benefit (provision)		1,371			2,078
Net income (loss)	$	(77,940	)	$	808,511

See accompanying notes to the consolidated financial statements.

F-69

PARAGON OFFSHORE LIMITED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)

	Successor			Predecessor
	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Net income (loss)	$	(77,940	)	$	808,511
Other comprehensive income (loss), net of tax
Foreign currency translation adjustments		—			2,977
Adjustments to pension plans		—			(82	)
Total other comprehensive income (loss), net		—			2,895
Total comprehensive income (loss)	$	(77,940	)	$	811,406

See accompanying notes to the consolidated financial statements.

F-70

PARAGON OFFSHORE LIMITED
CONSOLIDATED BALANCE SHEETS
(In thousands)

	Successor
	December 31, 2017
ASSETS
Current assets
Cash and cash equivalents	$	149,096
Restricted cash		5,776
Accounts receivable, net of allowance for doubtful accounts (Note 3)		34,037
Prepaid and other current assets		27,129
Total current assets		216,038
Property and equipment, at cost		270,819
Accumulated depreciation		(22,138	)
Property and equipment, net		248,681
Investment in equity method affiliate		157,908
Other long-term assets		9,914
Total assets	$	632,541
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	—
Accounts payable and accrued expenses		27,150
Accrued payroll and related costs		27,347
Taxes payable		6,733
Interest payable		1,379
Other current liabilities		3,167
Total current liabilities		65,776
Long-term debt		86,370
Deferred income taxes		—
Other liabilities		10,766
Total liabilities		162,912
Commitments and contingencies (Note 16)
Equity
Successor Ordinary Shares, $0.001 par value, 15,000,000 share authorized; with 5,017,556 issued and outstanding as of December 31, 2017		5
Successor additional paid-in capital		547,564
Accumulated deficit		(77,940	)
Accumulated other comprehensive loss		—
Total shareholders’ equity (deficit)		469,629
Total liabilities and equity	$	632,541

See accompanying notes to the consolidated financial statements.

F-71

PARAGON OFFSHORE LIMITED
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(In thousands)

		Ordinary Shares						Additional Paid-in Capital			Accumulated Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity (Deficit)			Total Equity (Deficit)
		Shares			Amount
Predecessor	Balance as of January 1, 2017		88,439		$	884		$	1,438,265		$	(2,233,248	)	$	(38,658	)	$	(832,757	)	$	(832,757	)
	Net income		—			—			—			808,511			—			808,511			808,511
	Employee related equity activity:
	Amortization of share-based compensation		—			—			2,981			—			—			2,981			2,981
	Vesting of restricted stock unit awards		572			6			(31	)		—			—			(25	)		(25	)
	Other comprehensive income, net		—			—			—			—			2,895			2,895			2,895
	Elimination of Predecessor equity		(89,011	)		(890	)		(1,441,215	)		1,424,737			35,763			18,395			18,395
	Issuance of Successor equity		5,000			5			546,122			—			—			546,127			546,127
Predecessor	Balance as of July 18, 2017		5,000		$	5		$	546,122		$	—		$	—		$	546,127		$	546,127
Successor	Balance as of July 18, 2017		5,000		$	5		$	546,122		$	—		$	—		$	546,127		$	546,127
	Net loss		—			—			—			(77,940	)		—			(77,940	)		(77,940	)
	Employee related equity activity:
	Amortization of share-based compensation		—			—			1,994			—			—			1,994			1,994
	Vesting of restricted stock unit awards		18			—			(552	)		—			—			(552	)		(552	)
Successor	Balance as of December 31, 2017		5,018		$	5		$	547,564		$	(77,940	)	$	—		$	469,629		$	469,629

See accompanying notes to the consolidated financial statements.

F-72

PARAGON OFFSHORE LIMITED
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Successor			Predecessor
(In thousands)	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Cash flows from operating activities
Net income (loss)	$	(77,940	)	$	(808,511	)
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation and amortization		24,636			66,860
Earnings from equity method affiliate		(1,519	)		—
Loss on impairments		18,745			391
Gain on sale of assets, net		(833	)		(1,383	)
Deferred income taxes		(3,174	)		(6,385	)
Share-based compensation		1,994			1,348
Reorganization items and fresh start related adjustments, net		—			(895,931	)
Other, net		—			1,231
Net change in other assets and liabilities (Note 17)		(21,650	)		(65,713	)
Net cash provided by (used in) operating activities		(59,741	)		(91,071	)
Cash flows from investing activities
Capital expenditures		(10,500	)		(5,413	)
Change in accrued capital expenditures		2,802			(313	)
Proceeds from sale of assets		8,363			2,800
Cash outflow related to deconsolidation of equity method affiliate		(20,173	)		—
Cash outflow related to legal separation of Former Parent Company and its Liquidating Subsidiaries		—			(6,876	)
Change in restricted cash		34,507			(41,595	)
Net cash provided by (used in) investing activities		14,999			(51,397	)
Cash flows from financing activities
Repayments on Sale-Leaseback Financing		—			(32,463	)
Payment of Secured Lender claims		—			(410,000	)
Payment of Bondholders’ claims		—			(105,000	)
Tax withholding on restricted stock units		—			(25	)
Net cash provided by (used in) financing activities		—			(547,488	)
Net change in cash and cash equivalents		(44,742	)		(689,956	)
Cash and cash equivalents, beginning of period		193,838			883,794
Cash and cash equivalents, end of period	$	149,096		$	193,838
Supplemental information for non-cash activities (Note 17)

See accompanying notes to the consolidated financial statements.

F-73

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION, CURRENT EVENTS, AND BASIS OF PRESENTATION

Paragon Offshore plc (in administration), (the “Former Parent Company”), (together with its subsidiaries) is the “Predecessor” of Paragon Offshore Limited (together with its subsidiaries, the “Successor”), a leading provider of standard specification offshore drilling services. Reference to “we,” “us,” “our” or the “Company” throughout these financial statements is intended to mean the contract drilling operations and business conducted by both the Predecessor and Successor.

The Predecessor is a public limited company registered under the Companies Act 2006 of England. In July 2014, Noble Corporation plc (“Noble”) transferred to the Predecessor the assets and liabilities (the “Separation”) constituting most of Noble’s standard specification drilling units and related assets, liabilities and business. On August 1, 2014, Noble made a pro rata distribution to its shareholders of all of the Predecessor’s issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”).

The Successor is an exempted company limited by shares incorporated under the laws of the Cayman Islands.

On July 18, 2017 (the “Effective Date”), the Successor acquired substantially all of the Predecessor’s assets pursuant to the Consensual Plan which became effective and had been confirmed by the Bankruptcy Court on June 7, 2017 (as defined and described below). In connection with the Paragon Bankruptcy cases (as defined below) and the Consensual Plan, on and prior to the Effective Date, the Predecessor and certain of its subsidiaries effectuated certain restructuring transactions, pursuant to which the Predecessor formed Paragon Offshore Limited, as a wholly-owned subsidiary of the Predecessor. On the Effective Date, in order to separate the results and financial position of the Former Parent Company and its Liquidating Subsidiaries from the ongoing operational business, the Predecessor transferred to Paragon Offshore Limited certain direct and indirect subsidiaries and certain other assets of the Predecessor (excluding Prospector Offshore Drilling S.à r.l. (“Prospector Offshore”) and its direct and indirect subsidiaries (collectively, the “Prospector Group”)). In accordance with the Consensual Plan, the Former Parent Company and certain remaining subsidiaries (excluding the Prospector Group) (the “Liquidating Subsidiaries”) will, in due course, be wound down and dissolved by the Joint Administrators (as defined below) in accordance with applicable law. The Successor will constitute the ongoing operational business after the Effective Date.

Our primary business is contracting our rigs, related equipment and work crews to conduct oil and gas drilling and workover operations for exploration and production customers on a dayrate basis around the world. We currently operate in significant hydrocarbon-producing geographies throughout the world, including the North Sea, the Middle East and India. Our fleet includes 22 jackups and one semisubmersible. This includes the Prospector Group’s two high specification heavy duty/harsh environment jackups.

Paragon Offshore plc (in administration) Emergence from Bankruptcy

On February 14, 2016 (the “Petition date”), Paragon Offshore plc (in administration) and its Debtors (the “Debtors”) commenced their chapter 11 cases (the “Paragon Bankruptcy cases”) by filing voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. During the bankruptcy proceedings, the Debtors operated their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court.

On May 2, 2017, as a result of a successful court-ordered mediation process with representatives of the lenders under the Revolving Credit Facility and the Term Loan Facility (collectively, the “Secured Lenders”) and the holders of the Senior Notes (the “Bondholders”), the Predecessor filed its fifth amended plan of reorganization for the Debtors (the “Consensual Plan”) with the Bankruptcy Court.

On May 17, 2017, the board of directors of the Predecessor filed an administration application with the High Court of Justice, Chancery Division, Companies Court of England and Wales (the “English Court”) for the appointment of two partners of Deloitte LLP, as joint administrators of the Former Parent Company, and on May 23, 2017, the English Court granted an order, pursuant to paragraph 13 of Schedule B1 to the Insolvency Act 1986 appointing these partners as joint administrators (the “Joint Administrators”) of the

F-74

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Former Parent Company. The power to manage the affairs, business and property of the Former Parent Company and the Liquidating Subsidiaries is vested in the Joint Administrators. The appointment of the Joint Administrators was a necessary component of the Consensual Plan.

On June 7, 2017, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Consensual Plan.

On July 18, 2017, the Effective Date, the Consensual Plan became effective pursuant to its terms and the Debtors emerged from the Paragon Bankruptcy cases.

On the Effective Date, the following events occurred in connection with the effectiveness of the Consensual Plan:

• All outstanding obligations under the Senior Notes and the indenture governing such obligations were cancelled and discharged, and the Predecessor and certain of its subsidiaries were released from their respective obligations under the Revolving Credit Facility and the Term Loan Facility.

• The Predecessor, Successor, certain of the reorganized Debtors and the Joint Administrators entered into a Litigation Trust Agreement (the “Litigation Trust Agreement”) with Drivetrain, LLC, as Litigation Trust management, and certain members of a litigation trust committee, pursuant to which a trust (the “Litigation Trust”) was established for the benefit of certain holders of allowed claims under the Consensual Plan. Pursuant to the Consensual Plan and the Confirmation Order, the Predecessor and the reorganized Debtors transferred to the Litigation Trust certain claims against Noble relating to the Predecessor’s separation from Noble (the “Noble Claims”). In addition, Noble may assert damages against the Predecessor for indemnification amounts that would have been owed to Noble pursuant to the Noble Separation Agreements (as defined in Note 16, “Commitments and Contingencies”). Pursuant to the terms of the Litigation Trust Agreement, a subsidiary of the Successor agreed to provide the Litigation Trust with an interest-free delayed draw term loan of up to $10 million in cash to fund the reasonable costs and expenses associated with the administration of the Litigation Trust (the “Litigation Trust Term Loan”). The Litigation Trust may prosecute the Noble Claims and conduct such other action as described in and authorized by the Consensual Plan, make timely and appropriate distributions to the beneficiaries of the Litigation Trust and otherwise carry out the provisions of the Litigation Trust Agreement. None of the Predecessor, Successor or any of the reorganized Debtors is a beneficiary to, or investor in, the Litigation Trust.

• The Predecessor issued a distribution, pro rata, to each of the Secured Lenders (the “Secured Lender Distribution”) and to each of the Bondholders (the “Bondholder Distribution”). The Secured Lender Distribution consisted of: (i) approximately $410 million in cash, (ii) allocation of new senior first lien debt in the original aggregate principal amount of $85 million maturing in 2022, (iii) 50% of the equity of the Successor, (iv) 50% of certain Class A interests in the Litigation Trust, which are entitled to a preferential right of recovery from the first $10 million of assets of the Litigation Trust (after giving effect to the repayment of the Litigation Trust Term Loan) (the “Class A Litigation Trust Interests”) and (v) 25% of certain Class B interests in the Litigation Trust, which are entitled to distribution of the remaining assets of the Litigation Trust (the “Class B Litigation Trust Interests”). The Bondholder Distribution consisted of: (i) approximately $105 million in cash, (ii) 50% of the equity of the Successor, (iii) 50% of the Class A Litigation Trust Interests, (iv) 75% of the Class B Litigation Trust Interests, (v) payment of certain Bondholder professionals’ fees and expenses and (vi) payment of up to $850,000 of reasonable and documented fees and expenses of the indentured trustee for the Bondholders.

• The Prospector Group was not transferred from the Predecessor to the Successor on the Effective Date; however, it will not be wound down and dissolved by the Joint Administrators. As such, the Prospector Group is intended to constitute part of our ongoing operational business after the Effective Date. Therefore, on the Effective Date, the Successor, Predecessor, and the Joint Administrators entered into a management agreement (the “Management Agreement”), pursuant to which the Successor has the economic benefit of and operational control over the Prospector

F-75

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Group subject to certain restrictions on the existing share pledges over Prospector Offshore. In addition, the Successor agreed to continue to procure the provision of management services to the Prospector Group while the Prospector Group remains held by the Predecessor. Further, pursuant to the Management Agreement, the Predecessor undertook to transfer the Prospector Group to the Successor at such time as the Successor obtains the consents required by the Sale-Leaseback Transaction to such transfer or such consent is no longer required (as described below). Because the Management Agreement grants the Successor control over the Prospector Group, under the variable interest entity (“VIE”) accounting guidance, the Successor continued to consolidate the Prospector Group in its consolidated financial statements on the Effective Date.

• The Predecessor deregistered under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and suspended its SEC reporting obligations. The Predecessor’s shares were not cancelled on the Effective Date. These shares do not represent the equity of the Successor nor any right to receive any equity or other interest in (or property of) the Successor as the Predecessor and Successor are two separate and distinct entities. As of the date of this report, the shares of the Successor are not traded on any market and are worthless.

Following the Effective Date, the Predecessor held approximately $11 million of cash on trust to discharge the fees, expenses and disbursements of the administration of the Predecessor, including the fees and expenses of the Joint Administrators, and the wind down of the Former Parent Company and its Liquidating Subsidiaries, excluding the Prospector Group.

Prospector Chapter 11 Filing and Execution of the Settlement Agreement

The Prospector Group has an interest in two high specification jackup units, Prospector 1 and Prospector 5 (collectively, the “Prospector Rigs”) pursuant to two sale-leaseback agreements (the “Lease Agreements”) executed with subsidiaries of SinoEnergy Capital Management Ltd. (the “Lessors”). In connection with the Lease Agreements, the Predecessor’s shares in Prospector Offshore (the “Prospector Shares”) are pledged in favor of the Lessors. In order to transfer the Prospector Group to the Successor as contemplated by the Consensual Plan, the Successor must obtain a consent to the transfer from the Lessors.

On July 20, 2017, the Former Parent Company, Prospector Offshore, Prospector Rig 1 Contracting Company S.à r.l., and Prospector Rig 5 Contracting Company S.à r.l. (collectively, the “Prospector Debtors”) commenced their chapter 11 cases (the “Prospector Bankruptcy cases”) by filing voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court in order to implement a restructuring plan to effectuate the transfer of the Prospector Group to the Successor.

During these proceedings, the Prospector Rigs have continued to be operated by the Successor under the Management Agreement without any impact to customers, suppliers, or employees. The Prospector Debtors have continued to operate their business as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code.

On February 15, 2018, the Former Parent Company entered into a consensual settlement agreement (the “Settlement Agreement”) with the Lessors. Under the terms of the Settlement Agreement, the Lessors will be paid certain agreed amounts totaling approximately $135 million, representing the outstanding principal balance on the Lease Agreements with the Lessors, lease termination fees, expenses, and a consent fee, in exchange for which the Lessors will cause ownership of the Prospector Rigs to be transferred to the Successor. On March 5, 2018, the Bankruptcy Court approved the Settlement Agreement. We intend to complete our obligations under the Settlement Agreement, including the pay off of the sale-leaseback and acquisition of the Prospector rigs, and dismiss the related bankruptcy cases, as soon as possible.

Acquisition by Borr Drilling

On February 22, 2018, we signed a tender offer agreement (the “Tender Offer Agreement”) with Borr Drilling Limited (“Borr”), a public limited liability company incorporated under the laws of Bermuda and listed on the Oslo Stock Exchange, pursuant to which, on the terms and subject to the conditions thereof, Borr agreed to commence a tender offer to acquire all of our outstanding shares (the “Shares”) at a purchase price

F-76

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

of $42.28 per share (the “Offer”). The Offer commenced on February 26, 2018 and will remain open for 20 business days (the “Offer Period”). The Offer Period is expected to expire at 12:01 A.M. Eastern Time on March 24, 2018, unless extended (such date, including any extension, being referred to as the “Expiration Date”). The transaction is expected to close on March 27, 2018, subject to the satisfaction of the Offer conditions. The conditions, among other customary conditions include, that (a) at least 3,361,763 Shares, representing at least 67% of the outstanding Shares have been validly tendered and not withdrawn before the Expiration Date, (b) no material adverse change shall have occurred prior to closing, and (c) we shall have completed all actions necessary to acquire ownership of the Prospector Rigs and the Prospector Group. The Offer is not subject to financing conditions.

In connection with, and as a condition to Borr’s willingness to enter into and perform its obligations under the Tender Offer Agreement, Borr entered into individual tender support agreements (each, a “Tender Support Agreement”), with certain of our shareholders (the “Tendering Shareholders”). Subject to the terms and conditions of each Tender Support Agreement, the Tendering Shareholders have agreed, among other things, to irrevocably tender all of their Shares pursuant to the Offer. The Tendering Shareholders beneficially own, in the aggregate, 3,407,072 Shares, representing approximately 67.9% of the total outstanding Shares as of February 21, 2018.

Basis of Presentation and Fresh-Start Accounting

Upon emergence from bankruptcy on the Effective Date, we adopted fresh-start accounting in accordance with ASC 852 (as defined below), which resulted in the Predecessor becoming a new Successor entity for financial reporting purposes. As such, fresh-start accounting is reflected in the accompanying consolidated balance sheet as of December 31, 2017 and fresh-start adjustments are included in the accompanying statement of operations for the period from January 1, 2017 through July 18, 2017.

All financial information presented prior to the Effective Date represents the consolidated results of operations, financial position and cash flows of the Predecessor. All financial information presented after the Effective Date represents the consolidated results of operations, financial position and cash flows of the Successor. As a result of the application of fresh-start accounting and the effects of the implementation of the Consensual Plan, the Successor’s financial statements subsequent to July 18, 2017 are not comparable to the Predecessor’s financial statements prior to that date.

The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.

NOTE 2—NEW ACCOUNTING PRONOUNCEMENTS

In May 2014, the FASB issued ASU No. 2014-09 (“ASU 2014-09”), which creates ASC Topic 606, Revenue from Contracts with Customers and supersedes the revenue recognition requirements in Topic 605 and industry-specific standards that currently exist under U.S. GAAP. The amendments in this ASU are intended to provide a more robust framework for addressing revenue issues, improve comparability of revenue recognition practices and improve disclosure requirements. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. In March, April, May and November 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients, and ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, respectively. These updates clarify important aspects of the guidance and improve its operability and implementation. ASC Topic 606 is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual reporting periods beginning after December 15, 2019. We are evaluating the provisions of ASU 2014-09, concurrently with the provisions of ASU 2016-02 (defined below) since we have determined that our drilling contracts contain a lease component, and our adoption of ASU 2016-02, therefore, will require that we

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separately recognize revenues associated with lease and nonlease components. Nonlease components or the provision of contract drilling services will be accounted for under ASU 2014-09. We are in the process of reviewing our revenue streams under these ASUs and have identified a subset of contracts that we believe are representative of our operations and have initiated an analysis of the related performance obligations and pricing arrangements in such contracts. We are still evaluating methods of adoption and what impact the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures which will be based on contract-specific facts and circumstances that could introduce variability to the timing of our revenue recognition relative to current accounting standards.

In February 2016, the FASB issued ASU No. 2016-02, which creates ASC Topic 842, Leases (“ASU 2016-02”). This ASU requires an entity to separate lease components from nonlease components in a contract. The lease components would be accounted for under ASU 2016-02, which requires lessees to recognize a right-of-use asset and a lease liability for capital and operating leases with lease terms greater than twelve months. Lessors must align certain requirements with the updates to lessee accounting standards and potentially derecognize a leased asset and recognize a net investment in the lease. This ASU also requires key qualitative and quantitative disclosures by lessees and lessors to help users of financial statements better understand the amount, timing and uncertainty of cash flows arising from leases. This update is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2019, and interim reporting periods within fiscal years beginning after December 15, 2020. A modified retrospective approach is required. Under this ASU, we have determined that our drilling contracts contain a lease component, and our adoption, therefore, will require that we separately recognize revenues associated with the lease and service components. We are evaluating the provisions of ASU 2016-02, concurrently with the provisions of ASU 2014-09 and expect to adopt both updates concurrently in 2019. We are still evaluating what impact the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.

In June 2016, the FASB issued ASU No. 2016-13, which creates ASC Topic 326, Financial Instruments - Credit Losses. The new guidance introduces new accounting models for expected credit losses on financial instruments and applies to: (1) loans, accounts receivable, trade receivables and other financial assets measured at amortized cost, (2) loan commitments and certain other off-balance sheet credit exposures, (3) debt securities and other financial assets measured at fair value through other comprehensive income, and (4) beneficial interests in securitized financial assets. The scope of the new guidance is broad and is designed to improve the current accounting models for the impairment of financial assets. The guidance is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2020, and interim periods within that reporting period. Early adoption is permitted for annual reporting periods beginning after December 15, 2018, and interim periods within that reporting period. A modified retrospective approach is required. We are evaluating what impact the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.

In August 2016 the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, a consensus of the FASB’s Emerging Issues Task Force. The new guidance is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The ASU addresses how the following cash transactions are presented: (1) debt prepayment or debt extinguishment costs; (2) settlement of zero-coupon debt instruments; (3) contingent consideration payments made after a business combination; (4) proceeds from the settlement of insurance claims; (5) proceeds from the settlement of corporate-owned life insurance policies; (6) distributions received from equity method investments; and (7) beneficial interests in securitization transactions. The ASU also addresses how to present cash receipts and cash payments that have aspects of multiple cash flow classifications. The guidance is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. Early adoption is permitted provided that all of the amendments are adopted in the same period. The guidance requires application using a retrospective transition method. We do not expect that our adoption will have a material impact on our cash flows or financial disclosures.

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In October 2016 the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory. This ASU requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. Consequently, the amendments in this ASU eliminate the exception for an intra-entity transfer of an asset other than inventory. The guidance is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. Early adoption is permitted for all entities as of the beginning of an annual reporting period for which financial statements (interim or annual) have not been made available for issuance. This ASU should be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption. The Predecessor early adopted this guidance on a modified retrospective basis for the quarter ended March 31, 2017, and it had no impact on prior periods as reported in our financial statements.

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and restricted cash. The new guidance is intended to reduce diversity in practice on the presentation of restricted cash in the statement of cash flows. The guidance is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. Early adoption is permitted, including adoption in an interim period. This ASU should be applied using a retrospective transition method to each period presented. We are evaluating what impact the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.

In January 2017 the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this update provide a more robust framework to use in determining when a set of assets and activities is a business. The objective of this ASU is to add guidance that will assist entities in evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses and may affect many areas of accounting including acquisitions, disposals, goodwill and consolidations. The guidance is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. The amendments in this update should be applied prospectively on or after the effective date. No disclosures are required at transition. We do not expect that our adoption will have a material impact on our financial condition, results of operations, cash flows or financial disclosures and the impact will be based on whether it is necessary for us to determine if we have acquired or sold a business in any period after the effective date.

In February 2017, the FASB issued ASU No. 2017-05, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets which will be effective at the same time as ASC Topic 606. ASU No. 2017-05 clarifies the scope, definition and accounting of a financial asset that meets the definition of an “in-substance nonfinancial asset” and adds guidance for partial sales of nonfinancial assets. We are evaluating what impact the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.

In March 2017 the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments in this update require that an employer disaggregate the service cost component from the other components of net benefit cost and provide guidance on how to present the service cost component and the other components of net benefit cost in the income statement. The guidance is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. The amendment for the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost should be applied retrospectively. We do not expect that our adoption will have a material impact on our financial condition, results of operations, cash flows or financial disclosures.

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NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Consolidation

We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes, except for certain subsidiaries that were deconsolidated on July 20, 2017 as a result of their voluntary filing for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Accordingly, we apply the equity method of accounting for an investment if we have the ability to exercise significant influence over an entity that meets the variable interest entity (“VIE”) criteria, but for which we are not deemed to be the primary beneficiary. A primary beneficiary requires both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses and the right to receive benefits from the VIE that potentially could be significant to the VIE. In accordance with U.S. GAAP, when a subsidiary whose financial statements were previously consolidated becomes subject to the control of a government, court, administrator or regulator (including filing for protection under the Bankruptcy Code), whether solvent or insolvent, deconsolidation of that subsidiary is generally required.

We eliminate intercompany transactions and accounts in consolidation, including certain subsidiaries that were deconsolidated on July 20, 2017 and are reported as “Investment in equity method affiliate” and “Earnings from equity method affiliate” on the Successor’s consolidated financial statements.

Reorganization and Fresh-Start Accounting

In connection with filing chapter 11 of the Bankruptcy Code on February 14, 2016, we are subject to the requirements of FASB ASC 852, Reorganizations (“ASC 852”). ASC 852 is applicable to companies under bankruptcy protection and requires amendments to the presentation of key financial statement line items. ASC 852 generally does not change the manner in which financial statements are prepared. However, it does require that the financial statements for periods subsequent to the filing of the Paragon Bankruptcy cases distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business.

Revenues, expenses, realized gains and losses, and provisions for losses that can be directly associated with the reorganization of the business and bankruptcy proceedings must be reported separately as reorganization items in the consolidated statements of operations. The balance sheets as of the Petition date and just prior to emergence from bankruptcy, must distinguish pre-petition liabilities subject to compromise from both those pre-petition liabilities that are not subject to compromise and from post-petition liabilities. Liabilities subject to compromise are pre-petition obligations that are not fully secured and that have at least a possibility of not being repaid at the full claim amount by the plan of reorganization. Liabilities subject to compromise must be reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts as a result of the plan of reorganization.

Upon emergence from bankruptcy on the Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which resulted in the Predecessor becoming a new Successor entity for financial reporting purposes. We qualified for fresh-start accounting because (1) the reorganization value of our assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of existing voting shares of the Predecessor received less than 50% of the voting shares of the post-emergence Successor entity.

Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical consolidated balance sheets. The effects of the Consensual Plan and the application of fresh-start accounting were reflected in our consolidated balance sheet as of the Effective Date and the related adjustments thereto were recorded in the Predecessor’s consolidated statement of operations as reorganization items for the period from January 1, 2017 through July 18, 2017.

The Successor’s consolidated balance sheets and consolidated statement of operations subsequent to July 18, 2017 are not comparable to the Predecessor’s consolidated balance sheets and statement of

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operations prior to the Effective Date. As a result, our consolidated financial statements and related notes are presented with a black line division which delineates the lack of comparability between the amounts presented on or after July 18, 2017 and dates prior. Our financial results for future periods following the application of fresh-start accounting are different from historical trends and differences may be material.

Operating Revenues and Expenses

Our typical dayrate drilling contracts require our performance of a variety of services for a specified period of time. We determine progress towards completion of the contract by measuring efforts expended and the cost of services required to perform under a drilling contract, as the basis for our revenue recognition. Revenues generated from our dayrate basis drilling contracts and labor contracts are recognized on a per day basis as services are performed and begin upon the contract commencement, as defined under the specified drilling or labor contract. Dayrate revenues are typically earned, and contract drilling expenses are typically incurred ratably over the term of our drilling contracts. We review and monitor our performance under our drilling contracts to confirm the basis for our revenue recognition. Revenues from bonuses are recognized when earned.

It is typical in our dayrate drilling contracts to receive compensation and incur costs for mobilization, equipment modification, or other activities prior to the commencement of the contract. Any such compensation may be paid through a lump-sum payment or other daily compensation. Pre-contract compensation and costs are deferred until the contract commences. The deferred pre-contract compensation and costs are amortized, using the straight-line method, into income over the term of the initial contract period, regardless of the activity taking place. This approach is consistent with the economics for which the parties have contracted. Once a contract commences, we may conduct various activities, including drilling and well bore related activities, rig maintenance and equipment installation, movement between well locations or other activities.

We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.

Cash and Cash Equivalents and Restricted Cash

We consider all highly liquid investments with maturities of three months or less to be cash equivalents. The following table reflects the short-term and long-term restricted cash balances included in our Consolidated Balance Sheets as of December 31, 2017.

	Successor
(In thousands)	December 31, 2017
Capital expenditure reserve for Sale-Leaseback Transaction(1)	$	—
Operating reserve for Sale-Leaseback Transaction(1)		—
Escrow restricted for the future payment of bankruptcy professional fee claims and general unsecured creditor claims		5,108
Other		668
Total short-term restricted cash	$	5,776
Rental reserve for Sale-Leaseback Transaction(2)		—
Outstanding performance bond		—
Total long-term restricted cash	$	—

(1) Our short-term restricted cash balance as of December 31, 2017 does not include $8 million related to the restricted cash balance of the deconsolidated Prospector Group held to satisfy the capital expenditure and operating reserve requirements of our Sale-Leaseback Transaction. See Note 6, “Investment in Equity Method Affiliate.”

(2) Our long-term restricted cash balance as of December 31, 2017 does not include $33 million related to the restricted cash balance of the deconsolidated Prospector Group held to satisfy the rental reserve requirements of our Sale-Leaseback Transaction. See Note 6, “Investment in Equity Method Affiliate.”

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Allowance for Doubtful Accounts

We utilize the specific identification method for establishing and maintaining allowances for doubtful accounts. We review accounts receivable on a quarterly basis to determine the reasonableness of the allowance. We monitor the accounts receivable from our customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors.

In connection with our adoption of fresh-start accounting upon emergence from bankruptcy, the carrying value of our trade receivables was adjusted to fair value, eliminating the Successor’s allowance for doubtful accounts as of July 18, 2017. We had no allowance for doubtful accounts as of December 31, 2017. Our Predecessor and Successor had an immaterial amount of bad debt expense and no recoveries for the year ended December 31, 2017. Bad debt expense and recoveries are reported as a component of “Contract drilling services operating costs and expenses” in our Consolidated Statements of Operations.

Long-lived Assets and Impairments

The carrying amount of our property and equipment, consisting primarily of offshore drilling rigs and related equipment, are based on our estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our rigs. These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations.

Successor property and equipment were recorded at fair value upon adoption of fresh-start accounting. Accumulated depreciation and impairment were therefore reset to zero as of that date. Subsequent purchases of major replacements and improvements have been recorded at cost.

When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and a gain or loss is recognized. Property and equipment are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment.

Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred.

The amount of depreciation expense we record is dependent upon certain assumptions, including an asset’s estimated useful life, rate of consumption and corresponding salvage value. We periodically review these assumptions and may change one or more of these assumptions. Changes in our assumptions may require us to recognize, on a prospective basis, increased or decreased depreciation expense. In connection with the adoption of fresh-start accounting, the useful lives for drilling rigs and equipment were reset based on fair value assumptions and standardization of rig components. The new useful lives of the drilling rig components range between 3 and 30 years.

In accordance with our policy, the estimated useful lives of our property and equipment are as follows:

	Years
Drilling rigs	7 – 30
Drilling machinery and equipment	3 – 5
Other	3 – 10

We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For assets classified as held and used, we determine recoverability by evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilization. An impairment loss on our long-lived assets exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition is less than its carrying amount. For property and equipment whose carrying values are determined not to be recoverable, we calculate an impairment loss as a difference between the fair value and carrying amount. We estimate the fair values by applying either an income approach, using projected discounted cash flows, or a market approach.

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Estimates of discounted future cash flows typically include (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses, (ii) long-term growth rates, and (iii) estimates of useful lives of the assets. Such estimates of future discounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. In a market approach, the fair value would be based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants.

Fair Value Measurements

We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability, respectively. Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows:

(1) Level 1 - Unadjusted quoted prices for identical assets or liabilities in active markets,

(2) Level 2 - Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets, and

(3) Level 3 - Unobservable inputs that require significant judgment for which there is little or no market data.

When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Our cash and cash equivalents, accounts receivable and accounts payable are by their nature short-term. As a result, the carrying values included in the accompanying Consolidated Balance Sheets approximate fair value. The carrying amount of the Successor’s variable-rate debt, the New Term Loan Facility, approximates fair value as such debt bears short-term, market-based interest rates. The Successor has classified these instruments as Level 2 valuation inputs used for purposes of determining the fair value disclosure are readily available published LIBOR rates.

Foreign Currency

Our reporting currency is the U.S. dollar. All subsidiaries of the Predecessor and Successor maintain their books and records in their functional currency. The functional currency of the Predecessor was primarily the U.S. dollar. The functional currency is the U.S. dollar for all our Successor’s operations. We therefore define foreign currency transactions as any transaction denominated in a currency other than the U.S. dollar. Monetary assets and liabilities denominated in a foreign currency are measured to U.S. dollars at the rate of exchange in effect as of each respective period end; items of income and expense are measured at average monthly rates; and property and equipment and other non-monetary assets are measured at historical rates. Realized and unrealized gains and losses on foreign currency transactions are recorded in “Other, net” on our Consolidated Statement of Operations.

Certain Significant Estimates and Contingent Liabilities

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. On an ongoing basis, the Company evaluates its estimates, including those related to allowance for doubtful accounts, long-lived asset impairment, useful lives for depreciation, income taxes, insurance claims, employment benefits and contingent liabilities. We base our estimates on historical experience and various other assumptions that are

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believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions.

Income Taxes

We operate through various subsidiaries in numerous countries throughout the world. Due to our global presence, we are subject to tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in the U.K., the U.S., and any other jurisdictions in which we or any of our subsidiaries operate, were incorporated, or otherwise considered to have a tax presence. 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. If the taxing authorities do not agree with our assessment of the effects of such laws, policies, treaties and regulations, or the interpretation or enforcement thereof, this could have a material adverse effect on us including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

In certain jurisdictions, we have recognized deferred tax assets and liabilities. Judgment and assumptions are required in determining whether deferred tax assets will be fully or partially utilized. When we estimate that all or some portion of certain deferred tax assets such as net operating loss carryforwards will not be utilized, we establish a valuation allowance for the amount ascertained to be unrealizable. We continually evaluate strategies that could allow for future utilization of our deferred tax assets. Any change in the ability to utilize such deferred tax assets will be accounted for in the period of the event affecting the valuation allowance. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting adjustments could have a material effect on our financial results or cash flow.

In certain circumstances, we expect that, due to changing demands of the offshore drilling markets and the ability to redeploy our offshore drilling units, certain units will not reside in a location long enough to give rise to future tax consequences. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should our expectations change regarding the length of time an offshore drilling unit will be used in a given location, we will adjust deferred taxes accordingly.

Subsequent Events

The Company’s consolidated financial statements were evaluated for subsequent events through March 8, 2018, the date the consolidated financial statements were available to be issued.

NOTE 4 — FRESH-START ACCOUNTING

Upon emergence from bankruptcy on the Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which requires the Successor to allocate its reorganization value to the fair value of assets in conformity with the guidance for the acquisition method of accounting for business combinations.

Reorganization Value

Reorganization value represents the fair value of the Successor’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately before restructuring.

Enterprise value represents the estimated fair value of an entity’s interest-bearing debt and shareholders’ equity after adjustment for certain cash items. As part of the Consensual Plan and prior to the Effective Date, an independent financial advisor estimated a range of enterprise values of approximately $550 million and $675 million, with a midpoint of $612.5 million. As discussed below, on the Effective Date, using numerous projections and assumptions, we estimated an enterprise value of $557 million which was within the range provided by the independent financial advisor and approved by the Bankruptcy Court.

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The following table reconciles the enterprise value to the estimated fair value of the Successor’s ordinary shares issued as of the Effective Date.

(In thousands)
Enterprise value	$	556,760
Plus: Cash and cash equivalents		193,838
Plus: Prospector Group long-term restricted cash		32,286
Less: Fair value of new senior first lien debt issued to the Secured Lenders		(85,000	)
Less: Fair value of Sale-Leaseback Transaction		(151,757	)
Fair value of Successor ordinary shares issued upon emergence	$	546,127

A reconciliation of the reorganization value is provided in the table below. The estimated enterprise value, after adding cash (including long-term restricted cash) plus the estimated fair values of all the Successor’s non-debt liabilities, is intended to approximate the reorganization value.

(In thousands)
Enterprise value	$	556,760
Plus: Cash and cash equivalents		193,838
Plus: Prospector Group long-term restricted cash		32,286
Plus: Current liabilities		108,918
Plus: Other liabilities		11,622
Reorganization value of Successor assets	$	903,424

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

In order to estimate the enterprise value of the Successor, we relied on the net asset value method (the “NAV Method”), a form of cost approach. The NAV Method is a valuation technique commonly used in the valuation of asset intensive businesses and consists of adjusting the book value of the assets and liabilities to fair value. The results of adjusting certain items to fair value is reflected in the column “Fresh-Start Adjustments” in the balance sheets below.

The discounted cash flow method (the “DCF Method”) was used to corroborate our concluded enterprise value under the NAV Method. The DCF Method estimates the value of a business by calculating the present value of expected future unlevered after-tax free cash flows to be generated by such business. This analysis is supported through a comparison of indicated values resulting from the use of other valuation techniques including a comparison of financial multiples implied by the estimated enterprise value to a range of multiples of publicly held companies with similar characteristics.

The financial projections used to estimate the expected future unlevered after-tax free cash flows were based on our 5-year forecast. The projections were prepared by management based on a number of estimates including various assumptions regarding the anticipated future performance of the Successor, industry performance, general business and economic conditions and other matters, many of which are beyond our control. The DCF Method also includes assumptions of the weighted average cost of capital (the “Discount Rate”), an estimate of residual growth for both revenues and expenses to reflect the period beyond the 5-year plan, and a terminal value based on a terminal EBITDA multiple. The Discount Rate is calculated by weighting the after-tax required returns on debt and equity by their respective percentages of total capital and resulted in a Discount Rate of 12.0%. Because we are expected to operate into perpetuity, we calculated a terminal value using an EBITDA multiple that we believe represents the enterprise value at the end of a discrete projection period.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Consolidated Effective Date Balance Sheet

The adjustments set forth in the following consolidated balance sheets:

(i) reflect the effect of the consummation of the transactions contemplated by the Consensual Plan (reflected in the column “Reorganization Adjustments”) which includes the restructuring transactions to wind down and dissolve the Former Parent Company and its Liquidating Subsidiaries by the Joint Administrators in accordance with the applicable law;

(ii) reflect the effect to legally separate the results and financial position of the Former Parent Company and its Liquidating Subsidiaries from the ongoing operational business after the Effective Date. The Former Parent Company and its Liquidating Subsidiaries will, in due course, be wound down and dissolved by the Joint Administrators in accordance with applicable law (reflected in the column “In Administration Restructuring”); and

(iii) reflect the fair value adjustments as a result of the adoption of fresh-start accounting (reflected in the column “Fresh-Start Adjustments”).

The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions or inputs.

(In thousands)	Predecessor July 18, 2017			Reorganization Adjustments			In Administration Restructuring			Fresh-Start Adjustments			Successor July 18, 2017
ASSETS
Current assets
Cash and cash equivalents	$	778,640		$	(577,925	)(a)	$	(6,877	)(i)	$	—		$	193,838
Restricted cash		6,819			39,783	(a)		—			—			46,602
Accounts receivable, net		52,253			—			(607	)(i)		9,408	(j)		61,054
Due from Former Parent Company and Liquidating Subsidiaries		—			11,439	(b)		—			—			11,439
Prepaid and other current assets		50,084			—			(12,638	)(i)		8,647	(k)		46,093
Total current assets		887,796			(526,703	)		(20,122	)		18,055			359,026
Property and equipment, at cost		2,330,383			—			(54,985	)(i)		(1,763,953	)(l)		511,445
Accumulated depreciation		(1,578,329	)		—			47,880	(i)		1,530,449	(l)		—
Property and equipment, net		752,054			—			(7,105	)		(233,504	)(l)		511,445
Restricted cash		41,560			(9,274	)(b)		—			—			32,286
Other long-term assets		22,964			—			(7,826	)(i)		(14,471	)(m)		667
Total assets	$	1,704,374		$	(535,977	)	$	(35,053	)	$	(229,920	)	$	903,424
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	28,344		$	—		$	—		$	—		$	28,344
Accounts payable and accrued expenses		75,962			(4,527	)(c)		(4,725	)(i)		—			66,710
Accrued payroll and related costs		35,207			—			(3,001	)(i)		—			32,206
Taxes payable		11,251			—			(5,764	)(i)		578	(j)		6,065
Interest payable		3,272			(3,261	)(d)		—			—			11
Other current liabilities		11,160			—			(6,032	)(i)		(1,202	)(n)		3,926
Total current liabilities		165,196			(7,788	)		(19,522	)		(624	)		137,262
Long-term debt		135,261			85,000	(e)		—			(11,848	)(o)		208,413
Other liabilities		26,528			—			(14,480	)(i)		(426	)(n)		11,622
Liabilities subject to compromise		2,379,355			(2,379,355	)(f)		—			—			—
Total liabilities		2,706,340			(2,302,143	)		(34,002	)		(12,898	)		357,297

F-86

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(In thousands)	Predecessor July 18, 2017			Reorganization Adjustments			In Administration Restructuring			Fresh-Start Adjustments			Successor July 18, 2017
Predecessor ordinary shares		890			—			(890	)(i)		—			—
Successor ordinary shares		—			5	(g)		—			—			5
Predecessor additional paid-in capital		1,441,215			—			(1,441,215	)(i)		—			—
Successor additional paid-in capital		—			546,122	(g)		—			—			546,122
Accumulated deficit		(2,408,308	)		1,220,039	(h)		1,424,737	(i)		(236,468	)(q)		—
Accumulated other comprehensive loss		(35,763	)		—			16,317	(i)		19,446	(p)		—
Total shareholders’ equity (deficit)		(1,001,966	)		1,766,166			(1,051	)		(217,022	)		546,127
Total liabilities and equity	$	1,704,374		$	(535,977	)	$	(35,053	)	$	(229,920	)	$	903,424

(a) Reflects payments and the funding of escrow accounts on the Effective Date from implementation of the Consensual Plan:

(In thousands)
Payment of Secured Lender claims	$	(410,000	)
Payment of Bondholders’ claims		(105,000	)
Payment of final interest to Secured Lenders		(3,261	)
Payment of professional fee claims		(8,984	)
Payment to operating and contingency escrow accounts of the Joint Administrators		(10,702	)
Payment of lending related fees		(195	)
Total payments	$	(538,142	)
Funding of professional fee claims escrow (Restricted cash)		(34,783	)
Funding of general unsecured claims escrow (Restricted cash)		(5,000	)
Total funding of escrow accounts (Restricted cash)	$	(39,783	)
Total payment and reclassification of Cash and cash equivalents	$	(577,925	)

(b) Pursuant to the Consensual Plan, following the Effective Date, the Successor maintains claims that are receivable in cash from the Former Parent Company and its Liquidating Subsidiaries, in the amount of $11.4 million. Of this amount, $9.3 million was held as restricted cash by the Former Parent Company.

(c) Reflects adjustment to and reclassification of claims accruals associated with liabilities subject to compromise balance on the Effective Date. Unpaid claims accrual amounts relate to general unsecured creditor, administrative expense and rejected contract claims. Also, reflects payment of professional fees incurred during the pendency of the bankruptcy proceedings as indicated in (a).

(d) Reflects payment of final interest to Secured Lenders as indicated in (a).

(e) Reflects the fair value issuance of new senior first lien debt to the Secured Lenders in the original aggregate principal amount of $85 million maturing in 2022 in connection with the Consensual Plan.

(f) Reflects the settlement of Liabilities subject to compromise in accordance with the Consensual Plan as follows:

(In thousands)
Revolving Credit Facility	$	709,100
Predecessor Term Loan Facility		641,875
Senior Notes due 2022, bearing fixed interest at 6.75% per annum		456,572
Senior Notes due 2024, bearing fixed interest at 7.25% per annum		527,010
Interest payable on Senior Notes		37,168
General unsecured creditor claim		7,630
Liabilities subject to compromise of the Predecessor	$	2,379,355
Cash payment of Secured Lender claims		(410,000	)
Cash payment of Bondholders’ claims		(105,000	)
Fair value of new senior first lien debt issued to the Secured Lenders		(85,000	)
Fair value of new equity issued to the Secured Lenders and Bondholders		(546,127	)
Adjustment of general unsecured creditor claim and rejected contract claim accruals		(4,457	)
Gain on settlement of Liabilities subject to compromise (debt forgiveness)	$	1,228,771

(g) Represents the issuance of new equity, 50% of 5,000,000, $0.001 par value shares, to each of the Secured Lenders and the Bondholders, respectively, in connection with the Consensual Plan.

F-87

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(h) Reflects the cumulative impact of reorganization adjustments discussed above:

(In thousands)	Earnings/(deficit)
Gain on settlement of liabilities subject to compromise(f)	$	1,228,771
Reorganization expense for the payment of lending related fees(a)		(195	)
Reorganization expense for the payment to operating and contingency escrow accounts of the Joint Administrators(a)		(10,702	)
Reorganization gain for receivable from Former Parent Company and Liquidating Subsidiaries(b)		2,165
Net impact to retained earnings	$	1,220,039

(i) Reflects the legal separation of the Former Parent Company and its Liquidating Subsidiaries and their related balances as of July 18, 2017. Such balances are removed from the ongoing operational business of the Successor after the Effective Date. The Former Parent Company and its Liquidating Subsidiaries will, in due course, be wound down and dissolved by the Joint Administrators in accordance with applicable law.

(j) Represents adjustment of third party receivable balance and withholding taxes payable to estimated fair value as a result of a signed settlement agreement on outstanding litigation for which collection is considered to be highly probable. Estimated fair value is based on the face amount of the receivable per the settlement agreement due to the short-term nature of the receivable which will be collected in January 2018.

(k) Represents the adjustments of deferred mobilization costs to an estimated zero fair value as well as a fair value adjustment for a favorable contract. A market analysis of all contracts was performed at the Effective Date to determine if we had any off-market contracts. The purchase price adjustment that was recorded on the Prospector 5 contract as of the date of the Predecessor’s acquisition of the Prospector Group was re-evaluated and it was determined that the actual contract dayrate continued to be significantly greater than the current market dayrate as of the Effective Date. The fair value adjustment was determined using the income approach and the estimated Discount Rate. The resulting fair value adjustment will be amortized through Contract Drilling Services Revenue of the Prospector Group on a straight-line basis over the term of the contract through November 2017.

(l) An adjustment of $234 million (after consideration for the separation of the Former Parent Company and Liquidating Subsidiaries’ property and equipment, net balance of approximately $7 million) was recorded to decrease the net book value of property and equipment to estimated fair value. In conjunction with the adjustment to fair value, accumulated depreciation was eliminated and depreciable lives were revised downward to reflect the remaining lives of the assets at fair value. The fair value of our fleet was determined utilizing the income approach and market approach depending on the circumstances of each rig. The DCF Method under the income approach estimates the future cash flows that an asset is expected to generate and was used for those rigs forecasted to operate into the future. Future cash flows are converted to a present value equivalent using the estimated Discount Rate. The key assumptions used for the DCF Method were consistent with those used to determine the reorganization value disclosed above. For rigs in the process of being sold for scrap, management’s estimated salvage values were used as an indication of fair value. For rigs that are currently stacked, and for which management intends to hold for the indefinite future in the hope of future contracts, but without a specific operating forecast, or rigs with a letter of intent from potential buyers, we relied on the market approach using either broker estimates or purchase prices, respectively, to approximate fair value. Drilling machinery and equipment and other includes our capital spares, leasehold improvements, office and technology equipment. The fair value of drilling machinery and equipment and other was based on management’s estimates. The components of property and equipment, net for the Predecessor carrying value as of July 18, 2017 and the Successor fair value at July 18, 2017 are summarized in the following table:

	Successor		Predecessor
(In thousands)	July 18, 2017		July 18, 2017
Drilling rigs	$	481,530	$	685,134
Drilling machinery and equipment and other		29,915		66,920
Property and equipment, net	$	511,445	$	752,054

(m) Represents the adjustments of deferred equipment survey and inspection costs, deferred mobilization costs, and the indicated loss recorded on our Sale-Leaseback Transaction to an estimated zero fair value. In addition, amount includes the fair value adjustment for our defined benefit pension plan balance. See (n) below.

(n) Represents the adjustments of deferred mobilization revenue to an estimated zero fair value. In addition, amount includes the fair value adjustment of the liability related to our defined benefit pension plans. See (m) above.

(o) Represents the adjustment of the outstanding capital lease obligation on the Sale-Leaseback Transaction to estimated fair value. The long-term lease agreements were valued by discounting the remaining rental payments based on the rate of return associated with the level of risk of future financing options of the Successor.

(p) Represents the adjustment to Accumulated Other Comprehensive Loss (“AOCL”), including deferred pension actuarial losses and cumulative translation adjustment, to reflect as zero upon emergence.

F-88

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(q) Reflects the cumulative impact of fresh-start adjustments, in order of the items discussed above:

(In thousands)	Earnings/(deficit)
Third party receivable balance, net of withholding taxes payable fair value adjustment(j)	$	8,830
Deferred mobilization expense write-off(k)(m)		(1,534	)
Favorable contract fair value adjustment(k)		10,047
Property and equipment fair value adjustment(l)		(233,504	)
Deferred equipment survey and inspection cost write-off(l)		(4,443	)
Indicated loss on Sale-Leaseback Transaction write-off(m)		(4,385	)
Deferred mobilization revenue write-off(n)		1,329
Defined benefit pension plan adjustment(m)(n)		(5,210	)
Obligation on Sale-Leaseback Transaction fair value adjustment(o)		11,848
Adjustment to AOCL - pension actuarial loss(p)		(14,410	)
Adjustment to AOCL - cumulative translation adjustment(p)		(5,036	)
Net impact to retained earnings (deficit)	$	(236,468	)

NOTE 5—PROPERTY AND EQUIPMENT AND OTHER ASSETS

Property and equipment consists of drilling rigs, drilling machinery and equipment and other property and equipment.

	Successor
(In thousands)	December 31, 2017
Drilling rigs	$	234,494
Drilling machinery and equipment		23,933
Other		12,392
Property and equipment, at cost		270,819
Less: Accumulated depreciation		(22,138	)
Property and equipment, net	$	248,681

Successor depreciation expense was $25 million for the period from July 18, 2017 to December 31, 2017. Predecessor depreciation expense was $67 million for the period from January 1, 2017 to July 18, 2017.

As a result of the deconsolidation of the Prospector Group on July 20, 2017, the Prospector Rigs, our leased drilling rigs under the Sale-Leaseback Transaction, are not consolidated in the Successor’s “Property and equipment, net.” The net book value for the Prospector Rigs, included in “Investment in equity method affiliate” on our Consolidated Balance Sheet as of December 31, 2017 was $215 million. Also excluded from the Successor’s “Property and equipment, net” is approximately $2 million of assets held for sale. This amount is included in “Other current assets” on the Consolidated Balance Sheet and comprises the net book value of the Paragon L1115 and Paragon M842. The Paragon C20052, Paragon M821, Paragon L1116, Paragon L1113, Paragon B301, Paragon L781, Paragon L1114, and the Paragon L785 were also classified as assets held for sale with no net book value. The Paragon L1115 was sold in January 2018 to a third party for approximately $2 million. The Paragon M821, Paragon L1116, Paragon L1113, Paragon B301, Paragon L781, Paragon L1114 were sold together in February 2018 to a third party for a total of approximately $4 million. The Paragon M842 and Paragon C20052 was also sold in February 2018 to a third party for approximately $5 million.

Amortization of our leased drilling rigs under the Sale-Leaseback Transaction was recorded in depreciation expense during the Predecessor period. Predecessor amortization of the Prospector Rigs was $11 million for January 1, 2017 to July 18, 2017. Successor depreciation expense for the Prospector rigs, included in “Earnings from equity method affiliate” on our Consolidated Statement of Operations for the period from July 20, 2017 to December 31, 2017 was $2 million.

F-89

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Our capital expenditures totaled $11 million for the Successor period from July 18, 2017 to December 31, 2017 and $5 million for the Predecessor period from January 1, 2017 to July 18, 2017. Included in accounts payable were $5 million of capital accruals as of December 31, 2017.

Loss on Impairment

In connection with the application of fresh-start accounting on July 18, 2017, we recorded fair value adjustments disclosed in Note 4, “Fresh-Start Accounting”.

In addition, during the fourth quarter ended December 31, 2017, we identified indicators of impairment, including the failure to secure contract tenders on two jackups and viable options, including letters of intent from potential buyers, to sell other rigs. These indicators required us to perform an impairment assessment of our fleet of drilling rigs. Based on this analysis, we recognized an impairment loss of $19 million on three jackups for the Successor period from July 18, 2017 to December 31, 2017. We recorded an impairment loss of $0.4 million on one jackup for the Predecessor period from January 1, 2017 to July 18, 2017.

Sales of Assets, net

For the period from July 18, 2017 to December 31, 2017, the Successor recorded a pre-tax net gain on the sale of assets of $1 million related to our sales of the Paragon DPDS1, Paragon DPDS2, Paragon DPDS3 and the Paragon L1111 subsequent to the Effective Date. The Paragon MDS1 and Paragon MSS3 were also sold subsequent to the Effective Date with no net gain on sale. These rigs were sold to unrelated third parties for total net proceeds of approximately $8 million. For the period from January 1, 2017 to July 18, 2017, the Predecessor recorded a pre-tax net gain on the sale of assets of $1 million related to our sales of the Paragon L782 and Paragon L783 prior to the Effective Date. The Paragon B153 and Paragon MSS2 were also sold prior to the Effective Date with no net gain on sale. These rigs were sold to unrelated third parties for total net proceeds of approximately $3 million.

NOTE 6 — INVESTMENT IN EQUITY METHOD AFFILIATE

The Prospector Group was not transferred from the Predecessor to the Successor on the Effective Date; however, it will not be wound down and dissolved by the Joint Administrators. As such, the Prospector Group is intended to constitute part of our ongoing operational business. On the Effective Date, the Prospector Group remained held by the Predecessor; however, pursuant to the Management Agreement, the Successor has the power to direct the activities that most significantly impact the Prospector Group’s economic performance, and the obligation to absorb losses and the right to receive benefits that could potentially be significant to the Prospector Group. As a result, the Prospector Group is a VIE for accounting purposes for which the Successor is the primary beneficiary, and as of the Effective Date, the Successor continued to consolidate the Prospector Group in our consolidated financial statements.

On July 20, 2017, the Prospector Debtors commenced the Prospector Bankruptcy cases by filing voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court in order to implement a restructuring plan to effectuate the transfer of the Prospector Group to the Successor. In accordance with U.S. GAAP, when a subsidiary whose financial statements were previously consolidated (as the Prospector Group’s were with ours) becomes subject to the control of a government, court, administrator or regulator (including filing for protection under the Bankruptcy Code), whether solvent or insolvent, deconsolidation of that subsidiary is generally required. Accordingly, the Prospector Group is no longer fully consolidated with the Successor subsequent to the Prospector Debtors’ voluntarily filing for reorganization on July 20, 2017. Our investment in the Prospector Group is recorded under the equity method of accounting effective July 20, 2017. The equity method requires us to present the net assets of the Prospector Group at July 20, 2017 as an investment and recognize the income or loss from the Prospector Group in our results of operations during the reorganization period. As a result of fresh-start accounting on the Effective Date, we did not record a gain or loss on the deconsolidation of the Prospector Group since the Prospector Group’s net assets approximated fair value on July 20, 2017. When the Prospector Group emerges from the jurisdiction of the Bankruptcy Court, the subsequent accounting will be determined based upon the applicable circumstances and facts at such time.

F-90

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The financial statements below represent the condensed consolidated financial statements of the Prospector Group. The financial statements below have been prepared assuming that the Prospector Group will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. The Prospector Group’s ability to continue as a going concern is contingent upon the Bankruptcy Court’s approval of it’s financial restructuring as described above. This represents a material uncertainty related to events and conditions that raises substantial doubt on the Prospector Group’s ability to continue as a going concern and, therefore, the Prospector Group may be unable to utilize its assets and discharge its liabilities in the normal course of business.

During the period that the Prospector Group is operating as debtors-in-possession under chapter 11 of the Bankruptcy Code, it may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions in the Lease Agreements), for amounts other than those reflected in the financial statements below. Further, the results of the financial restructuring could materially change the amounts and classifications of assets and liabilities reported in these financial statements. These financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Prospector Group be unable to continue as a going concern.

Intercompany transactions among the Prospector Group have been eliminated in the financial statements presented below. Intercompany transactions between the Prospector Group and the Successor are included in the Prospector Group’s financial statements presented below. However, “Investment in equity method affiliate” as reported on the Successor’s Consolidated Balance Sheet as of December 31, 2017 and “Earnings from equity method affiliate” as reported on the Successor’s Consolidated Statement of Operations for the Successor period from July 20, 2017 to December 31, 2017 do not include intercompany transactions between the Prospector Group and the Successor, which eliminate upon consolidation of the two, respectively.

F-91

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

PROSPECTOR GROUP’S CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(DEBTOR-IN-POSSESSION)
(Unaudited)
(In thousands)

	July 20, 2017 to December 31, 2017
Operating revenues
Contract drilling services	$	28,902
Reimbursables and other		1,818
		30,720
Operating costs and expenses
Contract drilling services		11,082
Contract drilling services - affiliate		6,750
Reimbursables		1,227
Depreciation and amortization (Note 5)		6,529
General and administrative		485
		26,073
Operating income before interest, reorganization items and income taxes		4,647
Interest expense, net		(5,973	)
Other, net		(185	)
Reorganization items, net		(3,480	)
Loss before income taxes		(4,991	)
Income tax provision		(240	)
Net Loss	$	(5,231	)

F-92

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

PROSPECTOR GROUP’S CONDENSED CONSOLIDATED BALANCE SHEET
(DEBTOR-IN-POSSESSION)
(Unaudited)
(In thousands)

	December 31, 2017
ASSETS
Current assets
Cash and cash equivalents	$	23,408
Restricted cash		7,867
Accounts receivable, net of allowance for doubtful accounts		6,858
Prepaid and other current assets		912
Total current assets		39,045
Property and equipment, at cost		221,768
Accumulated depreciation		(7,168	)
Property and equipment, net (Note 5)		214,600
Restricted cash		33,053
Other assets		120
Total assets	$	286,818
LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt (Note 8)	$	25,391
Accounts payable and accrued expenses		6,793
Accounts payable - affiliate		11,446
Accrued payroll and related costs		590
Taxes payable		389
Other current liabilities		26
Total current liabilities		44,635
Long-term debt (Note 8)		94,797
Other liabilities		924
Total liabilities		140,356
Equity
Total equity		146,462
Total liabilities and equity	$	286,818

NOTE 7—SHARE-BASED COMPENSATION

In December 2017, we granted time-vested restricted stock units (“TVRSU’s”) under the Paragon Offshore Limited Long Term Incentive Plan for our employees and directors (the “Employee and Director Plan”).

Shares available for issuance and outstanding restricted stock units under the Employee and Director Plan as of December 31, 2017 are as follows:

(In shares)	Employee and Directors
Shares available for future awards or grants		56,870
Outstanding unvested restricted stock units		468,443

F-93

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The TVRSU’s under the Employee and Director Plan are valued on the date of award at an estimated share price. In order to estimate the share price of our TVRSU grant, we estimated the business enterprise value and fair value of equity on a non-controlling, marketable basis using the NAV Method and calculated the marketable fair value per share based on the outstanding and granted shares of the Company. Due to the fact that we are a privately held company and our shares do not trade freely on an open exchange, we then applied a discount for lack of marketability on the marketable fair value per share. In order to determine an appropriate discount for lack of marketability we utilized a protective put analysis, restricted stock studies, and pre-IPO studies.

The total compensation for TVRSU’s that ultimately vests is recognized using a straight-line method over a 2.6 year service period. The shares and related nominal value are recorded when the restricted stock unit vests and additional paid-in capital is adjusted as the share-based compensation cost is recognized for financial reporting purposes.

A summary of restricted stock activity for the Successor period from July 18, 2017 to December 31, 2017 is as follows:

	TVRSU’s Outstanding			Weighted Average Award-Date Fair Value
Outstanding as of July 18, 2017		—		$	—
Awarded		498,686			43.50
Vested		(30,243	)		43.50
Outstanding as of December 31, 2017		468,443		$	43.50

On the Effective Date, all the Predecessor’s TVRSU’s, cash-settled awards (“CS-TVRSU’s”) and performance-vested restricted stock units (“PVRSU’s”) were extinguished and deemed cancelled. No new awards were granted during the Predecessor period from January 1, 2017 to July 18, 2017.

The Predecessor recognized all remaining unrecognized share-based compensation expense related to the cancelled awards in “Reorganization items, net” on the Consolidated Statement of Operations for the period from July 1, 2017 to July 18, 2017.

A summary of restricted stock activity for the Predecessor period from January 1, 2017 to July 18, 2017 is as follows:

	TVRSU’s Outstanding			Weighted Average Award-Date Fair Value		CS-TVRSU’s Outstanding			Share Price		PVRSU’s Outstanding			Weighted Average Award-Date Fair Value
Outstanding as of December 31, 2016		1,910,893		$	5.31		1,292,601					602,219		$	5.39
Vested		(845,107	)		5.20		(530,604	)				—			—
Forfeited		(1,065,786	)		5.41		(761,997	)				(602,219	)		5.39
Outstanding as of July 18, 2017		—					—		$	—		—

F-94

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8—DEBT

A summary of long-term debt at December 31, 2017

	Successor
(In thousands)	December 31, 2017
New Term Loan Facility with Secured Lenders	$	85,000
New Term Loan Facility with Secured Lenders - PIK Interest(1)		1,370
Sale-Leaseback Transaction(2)		—
Unamortized debt issuance costs		—
Total debt		86,370
Less: Current maturities of long-term debt(2)		—
Long-term debt	$	86,370

(1) Paid-in-kind (“PIK”) interest is calculated on the New Term Loan Facility. We are required to pay a minimum of 1% of interest in cash and the remaining portion of interest payable is reclassified into the outstanding debt balance upon the maturity date of the quarterly LIBOR borrowing.

(2) As a result of the deconsolidation of the Prospector Group on July 20, 2017, the Sale-Leaseback Transaction obligation is not consolidated in the Successor’s “Current maturities of long-term debt” or “Long-term debt” as of December 31, 2017. See Note 6,“Investment in Equity Method Affiliate” for the Prospector Group’s Condensed Consolidated Balance Sheet as of December 31, 2017 and the related long-term debt and current maturities of long-term debt balances.

New Term Loan Facility with Secured Lenders

On the Effective Date, we entered into the Amended and Restated Senior Secured Term Loan Facility with lenders to provide for loans in the aggregate principal amount of $85 million, which are deemed outstanding pursuant to the Consensual Plan (the “New Term Loan Facility”). The maturity date of the New Term Loan Facility is July 18, 2022. Until such maturity date, the New Term Loan Facility shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 5.00% or (ii) adjusted LIBOR plus an applicable margin of 6.00%.

We may elect to prepay any borrowing outstanding under the New Term Loan Facility without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the New Term Loan Facility).

The New Term Loan Facility contains restrictions on certain merger and consolidation transactions; our ability to sell or transfer certain assets; payment of dividends; making distributions; redemption of stock; incurrence or guarantee of debt; issuance of loans; prepayment; redemption of certain debt; as well as incurrence or assumption of certain liens.

Predecessor Revolving Credit Facility, Term Loan Facility and Senior Notes

On the Effective Date, in connection with the effectiveness of the Consensual Plan, all outstanding obligations of the Predecessor under the Senior Notes and the indenture governing such obligations were cancelled and discharged, and the Predecessor and certain of its subsidiaries were released from their respective obligations under the Revolving Credit Facility and the Term Loan Facility.

On June 17, 2014, the Predecessor entered into the Revolving Credit Agreement with lenders that provided commitments in the amount of $800 million. The Revolving Credit Agreement, which was secured by substantially all of our rigs, had a term of five years and matured in July 2019. Borrowings under the Revolving Credit Facility bore interest, at our option, at either (i) an adjusted LIBOR, plus an applicable margin ranging between 1.50% to 2.50%, depending on our leverage ratio, or (ii) a base rate plus an applicable margin ranging between 1.50% to 2.50%. The Predecessor continued to make interest payments on the Revolving Credit Facility in the ordinary course of business, based on Bankruptcy Court approval up to the Effective Date

F-95

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The Predecessor’s Senior Notes consisted of $500 million of 6.75% senior notes and $580 million of 7.25% senior notes, which matured on July 15, 2022 and August 15, 2024, respectively. The approximate $1 billion balance of the Predecessor’s Senior Notes, accrued pre-petition interest, and unamortized deferred debt issuance costs was classified as liabilities subject to compromise in the accompanying consolidated financial statements as of December 31, 2016. As interest on the Predecessor’s unsecured Senior Notes subsequent to February 14, 2016 was not expected to be an allowed claim, the Predecessor’s ceased accruing interest on the Senior Notes on this date. Results for the Predecessor periods from January 1, 2017 to July 18, 2017 and year ended December 31, 2016 would have included contractual interest expense of $39 million and $62 million, respectively. These costs would have been incurred had the unsecured Senior Notes not been classified as subject to compromise.

Borrowings under the Term Loan Facility bore interest at an adjusted LIBOR rate plus 2.75%, subject to a minimum LIBOR rate of 1% or a base rate plus 1.75%, at the Predecessor’s option. The Term Loan Facility had a maturity date of July 2021. The loans under the Term Loan Facility were issued with .50% original issue discount. The Predecessor continued to make interest payments on the Term Loan Facility in the ordinary course of business, based on Bankruptcy Court approval up to the Effective Date.

See Note 4 - “Fresh-Start Accounting” which reflects the settlement of the liabilities subject to compromise balance comprising the Predecessor Debt Facilities as of the Effective Date and in accordance with the Consensual Plan.

Sale-Leaseback Transaction

On July 24, 2015, the Predecessor executed a combined $300 million Sale-Leaseback Transaction with the Lessors for the Prospector Rigs. The Predecessor sold the Prospector Rigs to the Lessors and immediately leased the Prospector Rigs from the Lessors for a period of five year pursuant to the Lease Agreements for each of the Prospector Rigs, respectively. Net of fees and expenses and certain lease prepayments, the Predecessor received net proceeds of approximately $292 million, including amounts used to fund certain required reserve accounts. The Prospector 5 ended its drilling contract with Total S.A. in December 2017. The Prospector 1 is not operating as of December 2017 and has commenced operations under its drilling contract with Oranje-Nassau Energie B.V. in February 2018.

The Sale-Leaseback Transaction has been accounted for as a capital lease.

On July 20, 2017, the Prospector Debtors commenced the Prospector Bankruptcy cases. The commencement of the Prospector Bankruptcy cases constituted an event of default that accelerated the Prospector Group’s obligations under the Sale-Leaseback Transaction and in accordance with U.S. GAAP, resulted in the deconsolidation of the Prospector Group. Any efforts to enforce payments related to these obligations are automatically stayed as a result of the filing of the petitions and are subject to the applicable provisions of the Bankruptcy Code. The Prospector Group continues to make lease payments, including interest, to the Lessors in the ordinary course of business.

The following table includes the total minimum annual rental payments. In addition, it includes amounts representing interest on those rental payments using weighted-average effective interest rates of 5.2% for the Prospector 1 and 7.5% for the Prospector 5 and amortization of the fair value adjustment recorded as a discount to the obligation in conjunction with fresh-start accounting. The final payoff amount in 2020 is not reported net of any cash held in reserve accounts required under the Lease Agreements.

(In thousands)	2018			2019			2020			2021		Thereafter		Total
Minimum annual rental payments	$	32,371		$	30,660		$	83,713		$	—	$	—	$	146,744
Interest on rental payments		(6,980	)		(5,395	)		(2,075	)		—		—		(14,450	)
Amortization of fair value adjustment		(4,721	)		(4,721	)		(2,664	)		—		—		(12,106	)
	$	20,670		$	20,544		$	78,974		$	—	$	—	$	120,188

F-96

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Following the third and fourth anniversaries of the closing dates of the Lease Agreements, the Prospector Group has the option to repurchase each Prospector Rig for an amount as defined in the Lease Agreements. At the end of the lease term, the Prospector Group has an obligation to repurchase each Prospector Rig for a maximum amount of $88 million per rig, less any pre-payments made by us during the term of the Lease Agreements. As of December 31, 2017, the Prospector Group’s 2020 obligation for the Prospector 1 is expected to be $71 million and for the Prospector 5 is expected to be $12 million. These amounts include final rental payments as well as the repurchase amounts of $63 million and $5 million for Prospector 1 and Prospector 5, respectively, after consideration of the Prospector Group’s prepayments of Excess Cash Amounts (as defined below) pursuant to the Lease Agreement.

	Successor		Predecessor
(In thousands)	July 18, 2017 to December 31, 2017		January 1, 2017 to July 18, 2017
Prospector 1 - Rental payments	$	7,728	$	7,602
Prospector 1 - Excess cash sweep payments		124		3,188
Prospector 5 - Rental payments		13,064		12,851
Prospector 5 - Excess cash sweep payments		17,281		14,379
Total payments	$	38,197	$	38,020

The Lease Agreements obligate the Prospector Group to make certain termination payments upon the occurrence of certain events of default, including payment defaults, breaches of representations and warranties, termination of the underlying drilling contract for each rig, covenant defaults, cross-payment defaults, certain events of bankruptcy, material judgments and actual or asserted failure of any credit document to be in force and effect. The Lease Agreements contain certain representations, warranties, obligations, conditions, indemnification provisions and termination provisions customary for sale and leaseback financing transactions. The Lease Agreements contain certain affirmative and negative covenants that, subject to exceptions, limit the Prospector Group’s ability to, among other things, incur additional indebtedness and guarantee indebtedness, pay inter-company dividends or make other inter-company distributions or repurchase or redeem capital stock, prepay, redeem or repurchase certain debt, make loans and investments, sell, transfer or otherwise dispose of certain assets, create or incur liens, enter into certain types of transactions with affiliates, consolidate, merge or sell all or substantially all of our assets, and enter into new lines of business.

In addition, the Prospector Group is required to maintain a cash reserve of $11.5 million for each of the Prospector Rigs throughout the term of the Lease Agreements. During the term of the initial drilling contract for each of the Prospector Rigs, the Prospector Group was also required to pay to the Lessors any excess cash amounts earned under such contract, after payment of rig rental payments and operating expenses for such Prospector Rig and maintenance of any mandatory reserve cash amounts (the “Excess Cash Amounts”). These excess cash payments represent prepayment for the remaining rental payments under the applicable Lease Agreement (the “Cash Sweep”). See Note 3 - “Summary of Significant Accounting Policies” for a discussion on the Prospector Group’s restricted cash balances. Following the conclusion of the initial drilling contract for each Rig, the Cash Sweep was reduced, requiring the Prospector Group to make prepayments to the Lessors of up to 25% of the Excess Cash Amounts. Currently, both the Prospector 1 and the Prospector 5 are subject to lower Cash Sweep prepayments up to 25% of the Excess Cash Amounts.

NOTE 9—LIABILITIES SUBJECT TO COMPROMISE

See Note 4 - “Fresh-Start Accounting” which reflects the settlement of the liabilities subject to compromise balance as of the Effective Date in accordance with the Consensual Plan.

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PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10—REORGANIZATION ITEMS

ASC 852 requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. We use “Reorganization items, net” on our Consolidated Statements of Operations to reflect the net revenues, expenses, gains and losses that are the direct result of the reorganization of the business for the Predecessor period. The following table summarizes the components included in “Reorganization items, net”:

	Predecessor
(In thousands)	January 1, 2017 to July 18, 2017
Gain on settlement of liabilities subject to compromise	$	1,228,781
Fresh-start adjustments		(236,468	)
Professional fees and other		(96,382	)
Total Reorganization items, net	$	895,931

Included in “Reorganization items, net” for January 1, 2017 to July 18, 2017, is approximately $44 million of cash paid for professional fees.

Subsequent to the Effective Date, the Successor incurred a net gain of $1.1 million, directly related to the Paragon Bankruptcy cases. These charges were recorded as “Other non-operating items” in the Successor’s Consolidated Statements of Operations for the period from July 18, 2017 to December 31, 2017.

NOTE 11—INCOME TAXES

Income before income taxes consists of the following:

	Successor			Predecessor
(In thousands)	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
United States	$	(4,544	)	$	(245,080	)
Non-U.S.		(74,767	)		1,051,513
Total	$	(79,311	)	$	806,433

The income tax provision/benefit consists of the following:

	Successor			Predecessor
(In thousands)	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Current - United States	$	—		$	526
Current - Non-U.S.		1,803			3,781
Deferred - United States		—			—
Deferred - Non-U.S.		(3,174	)		(6,385	)
Total	$	(1,371	)	$	(2,078	)

The Successor’s effective tax rate for the period July 18, 2017 to December 31, 2017 was approximately 1.7%, on a pre-tax loss of $79 million. The Predecessor’s effective tax rate for the period January 1, 2017 to July 18, 2017 was approximately (0.3%), on pre-tax income of $806 million. The change in our effective tax

F-98

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

rate from period to period is primarily attributable to changes in the profitability or loss mix of our operations in various jurisdictions. As our operations continually change among numerous jurisdictions, and methods of taxation in these jurisdictions vary greatly, there is little direct correlation between the income tax provision/benefit and income/loss before taxes.

A reconciliation of the Cayman and U.K. statutory tax rate to our effective rate is shown below:

	Successor			Predecessor
	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Cayman/U.K. statutory income tax rate		—	%		19.3	%
Tax rates different from the statutory rate		(2.0	)%		(19.8	)%
Tax effect of asset impairment		—	%		—	%
Change in valuation allowance		4.0	%		—	%
Adjustments to uncertain tax positions		(0.3	)%		0.2	%
Total		1.7	%		(0.3	)%

The components of the net deferred taxes are as follows:

(In thousands)	Successor December 31, 2017
Deferred tax assets
Deferred loss on asset dispositions	$	9,558
Accrued expenses not currently deductible		2,899
Net operating losses		99,230
Excess of tax basis over book basis of Property and Equipment		39,296
Other		4,850
Deferred tax assets		155,833
Less: Valuation allowance		(152,123	)
Net deferred tax assets		3,710
Deferred tax liabilities
Other		(535	)
Deferred tax liabilities		(535	)
Net deferred tax asset (liabilities)	$	3,175

The deferred tax assets related to our Successor’s net operating losses were generated in various tax jurisdictions worldwide, a portion of which will expire in 2037 and 2038, if not utilized. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if estimates of future taxable income change.

We conduct business globally and, as a result, we file numerous income tax returns, or are subject to withholding taxes, in various jurisdictions. In the normal course of business we are generally subject to examination by taxing authorities throughout the world, including major jurisdictions we operate or used to operate, such as Cyprus, Denmark, Egypt, Equatorial Guinea, India, Israel, Luxembourg, Mexico, the Netherlands, Nigeria, Qatar, Saudi Arabia, Singapore, Switzerland, the United Kingdom, the United States, and Tanzania. We are no longer subject to examinations of tax matters for years prior to 1999.

F-99

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following is a reconciliation of the liabilities related to our unrecognized tax benefits, excluding interest and penalties:

(In thousands)
Predecessor
Gross balance at January 1, 2017	$	10,634
Additions based on tax positions related to the current year		—
Additions for tax positions of prior years		589
Reductions for tax positions of prior years		—
Expiration of statutes		—
Tax settlements		—
Gross balance at July 18, 2017		11,223
Related tax benefits		—
Net balance at July 18, 2017	$	11,223
Successor
Gross balance at July 18, 2017	$	3,920
Additions based on tax positions related to the current year		—
Additions for tax positions of prior years		—
Reductions for tax positions of prior years		—
Expiration of statutes		—
Tax settlements		—
Gross balance at December 31, 2017		3,920
Related tax benefits		—
Net balance at December 31, 2017	$	3,920

The liabilities related to our unrecognized tax benefits comprise the following:

(In thousands)	Successor December 31, 2017
Unrecognized tax benefits, excluding interest and penalties	$	3,920
Interest and penalties included in “Other liabilities”		2,744
Unrecognized tax benefits, including interest and penalties	$	6,664

We include, as a component of our income tax provision, potential interest and penalties related to liabilities for our unrecognized tax benefits within our global operations. Interest and penalties resulted in an income tax expense of $0.2 and $1 million for the period July 18, 2017 to December 31, 2017 for the Successor, and the period January 1, 2017 to July 18, 2017 for the Predecessor, respectively.

At December 31, 2017, the liabilities related to our unrecognized tax benefits, including estimated accrued interest and penalties, totaled $6.6 million, and if recognized, would reduce our income tax provision by $6.6 million.

NOTE 12 — RESTRUCTURING CHARGES

During 2016 and 2017, we initiated a workforce reduction program across our offshore crews, onshore bases and corporate office to align the size and composition of our workforce with our expected future operating and capital plans and our strategy to focus on fewer markets and utilize a smaller fleet. The workforce reduction program was in response to the lack of significant improvement in the drilling market coupled with our decision to exit operations in certain markets, such as Mexico, Brazil, West Africa and Canada.

F-100

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As related to the workforce reduction, appropriate communications to impacted personnel have been completed. As a result, the Predecessor recorded restructuring expense of $4 million for the period from January 1, 2017 to July 18, 2017 and the Successor recorded restructuring expense of $2 million for the period from July 18, 2017 to December 31, 2017 consisting of employee severance and other termination benefits which were included in “Contract drilling services”, “Labor contract drilling services” and “General and administrative” operating costs and expenses on our Consolidated Statement of Operations. During 2017, the Predecessor paid approximately $10 million and the Successor paid approximately $2 million in restructuring and employee separation related costs.

We had $4 million of accrued restructuring expense consisting of employee severance and other termination benefits in “Accrued payroll and related costs” on our Consolidated Balance Sheets as of December 31, 2017 (Successor).

NOTE 13 — EMPLOYEE BENEFIT PLANS

Defined Benefit Plans

The Predecessor sponsored two non-U.S. noncontributory defined benefit pension plans, the Paragon Offshore Enterprise Ltd and the Paragon Offshore Nederland B.V. pension plans, which cover certain Europe-based salaried employees.

As of January 1, 2017, all active employees under the defined benefit pension plans were transferred to a defined contribution pension plan as related to their future service. The accrued benefits under the defined benefit plans were frozen and all employees became deferred members. Our defined benefit pension plans were recorded at fair value upon adoption of fresh-start accounting on July 18, 2017.

For the Predecessor period from January 1, 2017 to July 18, 2017 pension benefit expense related to our defined benefit pension plans totaled $0.3 million. Information on these plans, based on actuary estimates, is presented in the tables below.

A reconciliation of the changes in projected benefit obligations (“PBO”) for our pension plans is as follows:

	Successor			Predecessor
(In thousands)	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Benefit obligation at beginning of period	$	127,478		$	132,214
Service cost		—			42
Interest cost		896			1,128
Actuarial loss (gain)		4,298			(12,937	)
Benefits and expenses paid		(472	)		(616	)
Plan participants’ contribution		—			—
Foreign exchange rate changes		(247	)		7,647
Benefit obligation at end of period	$	131,953		$	127,478

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PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

A reconciliation of the changes in fair value of plan assets is as follows:

	Successor			Predecessor
(In thousands)	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Fair value of plan assets at beginning of period	$	126,987		$	136,668
Actual return on plan assets		5,194			(16,942	)
Employer contribution		—			—
Benefits paid		(472	)		(616	)
Plan participants’ contributions		—			—
Expenses paid		—			—
Foreign exchange rate changes		(246	)		7,877
Fair value of plan assets at end of period	$	131,463		$	126,987

The funded status of the plans is as follows:

(In thousands)	Successor December 31, 2017
Funded status	$	(491	)

Amounts recognized in the Consolidated Balance Sheets consist of:

(In thousands)	Successor December 31, 2017
Other assets - noncurrent	$	921
Other liabilities - noncurrent		(1,412	)
Net pension asset (liability)		(491	)
Accumulated other comprehensive loss recognized in financial statements		—
Net amount recognized	$	(491	)

Amounts recognized in AOCL consist of:

(In thousands)	Successor December 31, 2017
Net loss	$	—
Accumulated other comprehensive income (loss)	$	—

Pension cost includes the following components:

	Successor			Predecessor
(In thousands)	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Service cost	$	871		$	42
Interest cost		(836	)		1,128
Expected return on plan assets		(30	)		(881	)
Amortization of prior service credit		—			—
Amortization net actuarial loss		—			25
Net curtailment gain		—			—
Net pension expense	$	5		$	314

F-102

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

In 2017, the balance in AOCL, including deferred pension actuarial losses, was reflected as zero upon adoption of fresh-start accounting on July 18, 2017 and recorded to “Reorganization items, net” in the Predecessor’s Consolidated Statements of Operations for the period from January 1, 2017 to July 18, 2017.

Defined Benefit Plans - Disaggregated Plan Information

Disaggregated information regarding our pension plans is summarized below:

(In thousands)	Successor December 31, 2017
Projected benefit obligation	$	131,953
Accumulated benefit obligation		131,953
Fair value of plan assets		131,463

Defined Benefit Plans - Key Assumptions

The key assumptions for the plans are summarized below:

Weighted Average Assumptions Used to Determine Benefit Obligations	Successor December 31, 2017
Discount rate	1.09% to 1.49%
Rate of compensation increase	Not applicable

	Successor	Predecessor
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	July 18, 2017 to December 31, 2017	January 1, 2017 to July 18, 2017
Discount rate	1.09% to 1.49%	1.26% to 1.62%
Expected long-term return on plan assets	1.09% to 1.49%	1.03% to 1.06%
Rate of compensation increase	Not applicable	3.6%

The discount rates used to calculate the net present value of future benefit obligations are determined by using a yield curve of high quality bond portfolios with an average maturity approximating that of the liabilities.

We employ third-party consultants who use a portfolio return model to assess the initial reasonableness of the expected long-term rate of return on plan assets. To develop the expected long-term rate of return on assets, we considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets for the portfolio.

Defined Benefit Plans - Plan Assets

At December 31, 2017, assets of Paragon Offshore Enterprise Ltd and Paragon Offshore Nederland B.V. pension plans were invested in instruments that are similar in form to a guaranteed insurance contract. There are no observable market values for the assets (Level 3); however, the amounts listed as plan assets were materially similar to the anticipated benefit obligations that were anticipated under the plans.

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PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The actual fair value of our pension plans as of December 31, 2017:

				Estimated Fair Value Measurements
(In thousands)		Carrying Amount		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Successor	December 31, 2017
	Fixed Income securities:
	Corporate Bonds	$	—	$	—	$	—	$	—
	Other		131,463		—		—		131,463
	Total	$	131,463	$	—	$	—	$	131,463

The following table details the activity related to the guaranteed insurance contract during the years.

		Market Value
	Balance as of December 31, 2016	$	100,580
	Assets sold/benefits paid		(616	)
	Increase due to Corporate Bonds		36,089
	Return on plan assets		(9,064	)
	Balance at July 18, 2017	$	126,989
Successor	Balance as of July 18, 2017	$	126,989
	Assets sold/benefits paid		(472	)
	Return on plan assets		4,946
	Balance as of December 31, 2017	$	131,463

Defined Benefit Plans - Cash Flows

In 2017 we made no contributions to our pension plans. We expect our aggregate minimum contributions to our plans in 2018, subject to applicable law, to be $0.5 million.

The following table summarizes our benefit payments at December 31, 2017 estimated to be paid within the next ten years:

			Payments by Period
	Total		2018		2019		2020		2021		2022		Five Years Thereafter
Estimated benefit payments	$	26,398		1,367		1,583		1,786		2,009		2,286		17,367

Other Benefit Plans

We sponsor a 401(k) defined contribution plan and a profit sharing plan. Other post-retirement benefit expense related to these other benefit plans included in the accompanying Consolidated Statements of Operations was $0.7 million for the Successor period from July 18, 2017 to December 31, 2017, and $1.5 million for the Predecessor period from January 1, 2017 to July 18, 2017.

NOTE 14—CONCENTRATION OF MARKET AND CREDIT RISK

The market for our services is the offshore oil and gas industry, and our customers consist primarily of government-owned oil companies, major integrated oil companies and independent oil and gas producers. We perform ongoing credit evaluations of our customers and do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial condition should

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PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

be considered in light of the fluctuations in demand experienced by drilling contractors as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial condition as supply and demand factors directly affect utilization and dayrates, which are the primary determinants of our net cash provided by operating activities.

Revenues from Total S.A. accounted for approximately 27% of our total operating revenues in 2017. Revenues from Dynamic Drilling accounted for approximately 26% of our total operating revenues in 2017. Revenues from National Drilling Company accounted for approximately 22% of our total operating revenues in 2017. Revenues from Oranje-Nassau Energie accounted for approximately 18% of our total operating revenues in 2017. No other single customer accounted for more than 10% of our total operating revenues in 2017.

NOTE 15—ACCUMULATED OTHER COMPREHENSIVE LOSS

(In thousands)	Defined Benefit Pension Items(1)			Foreign Currency Items			Total
Balance as of December 31, 2016	$	(14,329	)	$	(24,329	)	$	(38,658	)
Activity during period:
Other comprehensive loss before reclassification		—			2,977			2,977
Amounts reclassified from AOCL		(82	)		—			(82	)
Net other comprehensive income (loss)		(82	)		2,977			2,895
Elimination of Predecessor AOCL		14,411			21,352			35,763
Balance as of July 18, 2017	$	—		$	—		$	—
Successor
Balance as of July 18, 2017	$	—		$	—		$	—
Activity during period:
Other comprehensive loss before reclassification		—			—			—
Amounts reclassified from AOCL		—			—			—
Net other comprehensive income (loss)		—			—			—
Balance as of December 31, 2017	$	—		$	—		$	—

(1) Defined benefit pension items relate to actuarial losses, prior service credits, and the amortization of actuarial losses and prior service credits. In 2017, the balance in AOCL, was reflected as zero upon adoption of fresh-start accounting on July 18, 2017 and recorded to “Reorganization items, net” in Predecessor’s Consolidated Statements of Operations for the period from January 1, 2017 to July 18, 2017. Reclassifications from AOCL were reorganized as expense on our Consolidated Statements of Operations through either “Contract drilling services” or “General and administrative expenses for the year ended December 31, 2016. See Note 13—“Employee Benefit Plans” for additional information.

NOTE 16—COMMITMENTS AND CONTINGENCIES

Operating Leases

Future minimum lease payments for operating leases for years ending December 31 are as follows:

(in thousands)	2018		2019		2020		2021		2022		Thereafter		Total
Minimum lease payments	$	4,291	$	2,195	$	1,747	$	1,683	$	1,598	$	266	$	11,780

Total rent expense under operating leases was approximately $8 million for the year ended December 31, 2017.

F-105

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Litigation

In March 2018, we entered into a settlement agreement with a former customer relating to an outstanding arbitration award we had against such customer. The settlement agreement contemplates the payment of the settlement amount in two installments, both in March 2018. Under the settlement agreement, we expect to receive approximately $4 million by March 9, 2018 and between $5 million and $9 million by March 20, 2018, depending on certain conditions. If the customer makes all payments required under the settlement agreement, the arbitration award will be settled in full and dismissed. We cannot be certain that our customer will make the payments required under the settlement agreement, and if they fail to make such payments, we will continue enforcement proceedings under the existing arbitration award.

We are a defendant in certain claims and litigation arising out of operations in the ordinary course of business, the resolution of which, in the opinion of management, will not have a material adverse effect on our financial position, results of operations or cash flows. There is inherent risk in any litigation or dispute and no assurance can be given as to the outcome of these claims.

Tax Contingencies

We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. As of December 31, 2017, the Successor has tax assessments of approximately $10 million. We have contested, or intend to contest, these assessments, including through litigation if necessary. Tax authorities may issue additional assessments or pursue legal actions as a result of tax audits, and we cannot predict or provide assurance as to the ultimate outcome of such assessments and legal actions.

Insurance

We maintain certain insurance coverage against specified marine perils, which include physical damage and loss of hire for certain units.

We maintain insurance in the geographic areas in which we operate, although pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet or named windstorm perils with respect to our rigs cold-stacked in the U.S. Gulf of Mexico. Uninsured exposures may include expatriate activities prohibited by U.S. laws and regulations, radiation hazards, certain loss or damage to property on board our rigs and losses relating to shore-based terrorist acts or strikes. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could materially adversely affect our financial position, results of operations or cash flows. Additionally, there can be no assurance that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks.

Other

As of December 31, 2017, we had letters of credit of $38 million and performance bonds totaling $28 million supported by surety bonds outstanding. Approximately $10 million of the letters of credit related to the Successor activity, and $28 million of the letters of credit back surety bonds that support performance bonds issued by the Predecessor. Under the Consensual Plan, the Successor is not obligated to repay the issuing banks if the letters of credit are drawn by the beneficiaries. On the Effective Date, we entered into the Letter of Credit Agreement (the “LC Agreement”) among lenders and issuing banks of the letters of credit. Pursuant to the LC Agreement, the Successor must pay a 2.5% monthly fee for all letters of credit that were outstanding at the emergence date until such time as the letter of credit is extinguished. The LC Agreement has a term of five years. The performance bonds of $28 million outstanding at December 31, 2017 were primarily obligations of the Predecessor.

F-106

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Separation Agreements

In connection with the Spin-Off, the Predecessor entered into several definitive agreements with Noble or its subsidiaries (collectively, the “Noble Separation Agreements”) that, among other things, set forth the terms and conditions of the Spin-Off and provide a framework for the Predecessor’s relationship with Noble after the Spin-Off, including the following agreements:

• Master Separation Agreement;

• Tax Sharing Agreement;

• Employee Matters Agreement;

• Transition Services Agreement relating to services Noble and Paragon will provide to each other on an interim basis; and

• Transition Services Agreement relating to Noble’s Brazil operations.

On the Effective Date, the Predecessor rejected the Separation Agreements pursuant to the terms of the Consensual Plan. As a result of rejecting the Tax Sharing Agreement, the Predecessor is no longer entitled to indemnity from Noble with respect to the tax liabilities. In addition, Noble may assert claims against the Predecessor for indemnification amounts that would have been owed to Noble pursuant to the Tax Sharing Agreement.

NOTE 17—SUPPLEMENTAL CASH FLOW INFORMATION

The net effect of changes in other assets and liabilities on cash flows from operating activities is as follows:

	Successor			Predecessor
(In thousands)	July 18, 2017 to December 31, 2017			January 1, 2017 to July 18, 2017
Accounts receivable	$	5,835		$	13,391
Other current assets		19,383			6,881
Other assets		(6,129	)		2,451
Accounts payable and accrued payroll		(43,810	)		(65,918	)
Other current liabilities		3,027			(19,689	)
Other liabilities		44			(2,829	)
Net change in other assets and liabilities	$	(21,650	)	$	(65,713	)

Additional cash flow information is as follows:

	Successor		Predecessor
(In thousands)	July 18, 2017 to December 31, 2017		January 1, 2017 to July 18, 2017
Cash paid (refunded) during the period for:
Interest	$	676	$	41,247
U.S. and Non-U.S. income taxes		942		4,657
Supplemental information for non-cash activities:
Accrued capital expenditures	$	4,565	$	1,615
Netting of VAT receivables and payables		—		12,307

F-107

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 18—SEGMENT AND RELATED INFORMATION

As of December 31, 2017, our contract drilling operations were reported as a single reportable segment, Contract Drilling Services, which reflects how our business is managed, and the fact that all of our drilling fleet is dependent upon the worldwide oil industry. The mobile offshore drilling units that comprise our offshore rig fleet operate in a single, global market for contract drilling services and are often redeployed globally due to changing demands of our customers, which consisted largely of major non-U.S. and government owned/controlled oil and gas companies throughout the world. Our contract drilling services segment currently offers contract drilling operations in the North Sea, the Middle East and India and included operations in Brazil, Mexico, West Africa and Southeast Asia in prior periods.

Operations by Geographic Area

The following table presents revenues and identifiable assets by country based on the location of the service provided:

	Successor		Predecessor
Revenues (In thousands)	July 18, 2017 to December 31, 2017		January 1, 2017 to July 18, 2017
Country:
India	$	24,817	$	31,183
United Arab Emirates		19,479		27,477
United Kingdom		11,735		70,032
Brazil		—		665
The Netherlands		—		14
Mexico		—		52
Other		—		—
	$	56,031	$	129,423

Identifiable Assets (In thousands)	Successor December 31, 2017
Country:
USA	$	190,819
United Kingdom		185,251
United Arab Emirates		108,910
The Netherlands		96,111
Denmark		43,384
Qatar		4,122
India		2,621
Brazil		1,323
Other		—
	$	632,541

F-108

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Report of Independent Auditors

To the board of directors of Borr Drilling Limited

We have audited the accompanying consolidated financial statements of Paragon Offshore Limited and its subsidiaries (the “Company”), which comprise the consolidated balance sheet as of March 28, 2018, and the related consolidated statement of operations, consolidated statement of comprehensive loss, consolidated statement of cash flows and consolidated statement of changes in shareholders’ equity for the period from January 1, 2018 to March 28, 2018.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of March 28 2018, and the results of its operations and its cash flows for the period then ended in accordance with accounting principles generally accepted in the United States of America.

Emphasis of Matter

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company is dependent on loans and/or equity issuances to finance its obligations and working capital requirements which raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to this matter

/S/ PricewaterhouseCoopers AS
Stavanger, Norway
April 29, 2019

F-109

PARAGON OFFSHORE LIMITED
CONSOLIDATED FINANCIAL STATEMENT
CONSOLIDATED STATEMENT OF OPERATIONS
(In $ millions)

	Notes	January 1, 2018 to March 28, 2018
Operating revenues
Contract drilling services	3,15		26.6
Reimbursable revenue			0.6
Remeasurement gain equity method affiliate	7		8.6
Total operating revenues			35.8
Operating cost and expenses
Rig operating and maintenance expenses			(29.2	)
Depreciation of non-current assets	8		(10.7	)
Impairment of non-current assets	8		(187.6	)
General and administrative expenses	12		(34.5	)
Legal Settlement	14		15.4
Gain on sale of assets, net			7.9
Total operating expenses			(238.7	)
Operating loss before interest and income taxes			(202.9	)
Interest expenses, net			(1.9	)
Other, net	4		0.4
Earnings (loss) from equity affiliate	6		(46.5	)
Income (loss) before income taxes			(250.9	)
Income tax expense	5		(2.7	)
Net income (loss) for the period			(253.6	)

See accompanying notes to the consolidated financial statements.

F-110

PARAGON OFFSHORE LIMITED
CONSOLIDATED FINANCIAL STATEMENT
CONSOLIDATED STATEMENT COMPREHENSIVE LOSS
(In $ millions)

	Notes	January 1, 2018 to March 28, 2018
Net loss for the period			(253.6	)
Other comprehensive loss			—
Total comprehensive loss for the period			(253.6	)

See accompanying notes to the consolidated financial statements.

F-111

PARAGON OFFSHORE LIMITED
CONSOLIDATED FINANCIAL STATEMENT
CONSOLIDATED STATEMENT OF BALANCE SHEET
(In $ millions except per share data)

	Notes	March 28, 2018
ASSETS
Current assets
Cash and cash equivalents			41.7
Restricted cash			4.2
Trade receivables			19.5
Accrued revenue			10.4
Other current assets	9		20.3
Total current assets			96.1
Non-current assets
Property, Plant and Equipment, net	8		272.2
Other long-term assets	10		12.0
Total non-current assets			284.2
Total assets			380.3
LIABILITIES AND EQUITY
Current liabilities
Trade payables			10.5
Current debt	11		87.8
Accruals and other current liabilities	13		32.2
Total current liabilities			130.5
Non-Current liabilities
Other liabilities			9.2
Onerous contract			4.4
Total non-current liabilities			13.6
Total liabilities			144.1
Commitments and contingencies	16
Shareholders’ equity
Ordinary Shares, $0.001 par value, 15,000,000 shares authorized; with 5,485,989 issued and outstanding as of March 28, 2018			0.0
Additional paid in capital			567.8
Accumulated deficit			(331.6	)
Total shareholders’ equity			236.2
Total liabilities and equity			380.3

See accompanying notes to the consolidated financial statements.

F-112

PARAGON OFFSHORE LIMITED
CONSOLIDATED FINANCIAL STATEMENT
CONSOLIDATED STATEMENT OF CASH FLOWS
(In $ millions)

	Notes	January 1, 2018 to March 28, 2018
Cash Flows from Operating Activities
Net loss			(253.6	)
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
Depreciation of non-current assets	8		10.7
Impairment of non-current assets	8		187.6
Gain on sale of assets, net			(7.9	)
Share-based compensation	12		20.3
Earnings from equity method affiliate	6		46.5
Remeasurement gain equity method affiliate	7		(8.6	)
Recoveries of doubtful accounts	14		(6.6	)
Change in other current and non-current assets	8,9,10		(81.6	)
Change in current and non-current liabilities	11		(32.0	)
Net cash (used in)/provided by operating activities			(125.2	)
Cash Flows from Investing Activities
Proceeds from sale of fixed assets			11.1
Prospector reconsolidation, net of cash acquired	7		5.2
Net cash (used in)/provided by investing activities			16.3
Cash Flows from Financing Activities
Net cash (used in)/provided by financing activities			—
Net increase (decrease) in cash, cash equivalents and restricted cash			(108.9	)
Cash and cash equivalents and restricted cash at beginning of the period			154.8
Cash and cash equivalents and restricted at the end of period			45.9
Income taxes paid			5.4

See accompanying notes to the consolidated financial statements.

F-113

PARAGON OFFSHORE LIMITED
CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED STATEMENT OF CHANGES IN SHAREHOLDERS’ EQUITY
(In $ millions except per share data)

	Number of shares		Common shares		Additional paid in capital		Other Comprehensive Income		Accumulated Deficit			Total equity
Consolidated balance at January 1, 2018		5,017,556		0.005		547.5		—		(78.0	)		469.5
Net Loss		—		—		—		—		(253.6	)		(253.6	)
Amortization of share-based compensation		—		—		20.3		—		—			20.3
Vesting of restricted stock units		468,433		—		—		—		—			—
Consolidated balance at March 28, 2018		5,485,989		0.005		567.8		—		(331.6	)		236.2

See accompanying notes to the consolidated financial statements.

F-114

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Note 1 – General information

Paragon Offshore plc (in administration), (the “Former Parent Company”), (together with its subsidiaries) is the “Predecessor” of Paragon Offshore Limited (together with its subsidiaries, the “Successor”), a leading provider of standard specification offshore drilling services. Reference to “we,” “us,” “our” or the “Company” throughout these financial statements (the “consolidated financial statements”) is intended to mean the contract drilling operations and business conducted by both the Predecessor and Successor companies.

The Predecessor is a private limited company registered under the Companies Act 2006 of England. In July 2014, Noble Corporation plc (“Noble”) transferred to the Predecessor the assets and liabilities (the “Separation”) constituting most of Noble’s standard specification drilling units and related assets, liabilities and business. On August 1, 2014, Noble made a pro rata distribution to its shareholders of all of the Predecessor’s issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”).

The Successor is an exempted company limited by shares incorporated under the laws of the Cayman Islands.

On July 18, 2017 (the “Effective Date”), the Successor acquired substantially all of the Predecessor’s assets pursuant to the Consensual Plan which became effective and had been confirmed by the Bankruptcy Court on June 7, 2017 (as defined and described below). In connection with the Paragon Bankruptcy cases and the Consensual Plan, on and prior to the Effective Date, the Predecessor and certain of its subsidiaries effectuated certain restructuring transactions, pursuant to which the Predecessor formed Paragon Offshore Limited, as a wholly-owned subsidiary of the Predecessor. On the Effective Date, in order to separate the results and financial position of the Former Parent Company and its Liquidating Subsidiaries from the ongoing operational business, the Predecessor transferred to Paragon Offshore Limited certain direct and indirect subsidiaries and certain other assets of the Predecessor (excluding Prospector Offshore Drilling S.à r.l. (“Prospector Offshore”) and its direct and indirect subsidiaries (collectively, the “Prospector Group”)). In accordance with the Consensual Plan, the Former Parent Company and certain remaining subsidiaries (excluding the Prospector Group) (the “Liquidating Subsidiaries”) will, in due course, be wound down and dissolved by the Joint Administrators in accordance with applicable law. The Successor will constitute the ongoing operational business after the Effective Date.

Our primary business is contracting our rigs, related equipment and work crews to conduct oil and gas drilling and workover operations for exploration and production customers on a dayrate basis around the world. We currently operate in significant hydrocarbon-producing geographies throughout the world, including the North Sea, the Middle East and India. Our fleet includes 22 jack up rigs and one semisubmersible.

Basis of presentation

We have prepared our accompanying consolidated financial statements in accordance with accounting principles generally accepted in the United States (“U.S.”). The consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows. The amounts are presented in millions of United States dollar (U.S. dollar), unless otherwise stated. The financial statements have been prepared on a going concern basis.

Going concern

The consolidated financial statements have been prepared on a going concern basis. Following the acquisition of the Company by Borr Drilling Limited (“Borr” or the “Borr Drilling Group”), the going concern assumption must be evaluated as part of the Borr Drilling Group. The Company, together with the Borr Drilling Group is dependent on loans and/or equity issuances to finance the remaining payment obligations under its current secured loans and newbuilding contracts and to meet working capital requirements, which raises

F-115

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

substantial doubt about the Company’s ability to continue as a going concern. Given the recent execution of the Borr Drilling Group’s March 2019 bank facility, the approval by board of Borr of current plans to increase Borr’s long-term debt, including the receipt of an indicative terms sheet for loan financing up to $550.0 million, and Borr’s track record of raising equity financing, we believe the Company together with the Borr Drilling Group will be able to meet the anticipated liquidity requirements for at least the next twelve months as of the date of these consolidated financial statements. There is no assurance that the Borr Drilling Group will be able to execute this financing.

Basis of Presentation and Fresh-Start Accounting

Upon emergence from bankruptcy on the Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which resulted in the Predecessor becoming a new Successor entity for financial reporting purposes. As such, fresh-start accounting is reflected in the consolidated balance sheet as of December 31, 2017 and fresh-start adjustments are included in the statement of operations for the period from January 1, 2017 through July 18, 2017. All financial information presented prior to the Effective Date represents the consolidated results of operations, financial position and cash flows of the Predecessor. All financial information presented after the Effective Date represents the consolidated results of operations, financial position and cash flows of the Successor. As a result of the application of fresh-start accounting and the effects of the implementation of the Consensual Plan, the Successor’s financial statements subsequent to July 18, 2017 are not comparable to the Predecessor’s financial statements prior to that date. The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.

The consolidated financial statements present the financial position of Paragon Offshore Limited and its subsidiaries. Investments in companies in which the Company controls, or directly or indirectly holds more than 50% of the voting control are consolidated in the financial statements.

We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes, except for certain subsidiaries that were deconsolidated on July 20, 2017 as a result of their voluntary filing for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Accordingly, we apply the equity method of accounting for an investment if we have the ability to exercise significant influence over an entity that meets the variable interest entity (“VIE”) criteria, but for which we are not deemed to be the primary beneficiary. A primary beneficiary requires both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses and the right to receive benefits from the VIE that potentially could be significant to the VIE. In accordance with U.S. GAAP, when a subsidiary whose financial statements were previously consolidated becomes subject to the control of a government, court, administrator or regulator (including filing for protection under the Bankruptcy Code), whether solvent or insolvent, deconsolidation of that subsidiary is generally required.

Basis of consolidation

The consolidated financial statements include the assets and liabilities of the Company. All intercompany balances, transactions and internal sales have been eliminated on consolidation. Unrealized gains and losses arising from transactions with associates are eliminated to the extent of the Company’s interest in the entity. Profit or loss and each component of other comprehensive income are attributed to the equity holders of the Borr Drilling Group.

Use of estimates

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

F-116

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Note 2 – Accounting policies

Operating Revenues and Expenses

Our typical dayrate drilling contracts require our performance of a variety of services for a specified period of time. We determine progress towards completion of the contract by measuring efforts expended and the cost of services required to perform under a drilling contract, as the basis for our revenue recognition. Revenues generated from our dayrate basis drilling contracts and labor contracts are recognized on a per day basis as services are performed and begin upon the contract commencement, as defined under the specified drilling or labor contract. Dayrate revenues are typically earned, and contract drilling expenses are typically incurred ratably over the term of our drilling contracts. We review and monitor our performance under our drilling contracts to confirm the basis for our revenue recognition. Revenues from bonuses are recognized when earned.

It is typical in our dayrate drilling contracts to receive compensation and incur costs for mobilization, equipment modification, or other activities prior to the commencement of the contract. Any such compensation may be paid through a lump-sum payment or other daily compensation. Pre-contract compensation and costs are deferred until the contract commences. The deferred pre-contract compensation and costs are amortized, using the straight-line method, into income over the term of the initial contract period, regardless of the activity taking place. This approach is consistent with the economics for which the parties have contracted. Once a contract commences, we may conduct various activities, including drilling and well bore related activities, rig maintenance and equipment installation, movement between well locations or other activities.

We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.

Cash and Cash Equivalents and Restricted Cash

We consider all highly liquid investments with maturities of three months or less to be cash equivalents.

Allowance for Doubtful Accounts

We utilize the specific identification method for establishing and maintaining allowances for doubtful accounts. We review accounts receivable on a quarterly basis to determine the reasonableness of the allowance. We monitor the accounts receivable from our customers for any collectability issues. An allowance for doubtful accounts is established based on reviews of individual customer accounts, recent loss experience, current economic conditions, and other pertinent factors.

Long-lived Assets and Impairments

The carrying amount of our property and equipment, consisting primarily of offshore drilling rigs and related equipment, are based on our estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our rigs. These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations.

Successor property and equipment were recorded at fair value upon adoption of fresh-start accounting. Accumulated depreciation and impairment were therefore reset to zero as of that date. Subsequent purchases of major replacements and improvements have been recorded at cost.

When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and a gain or loss is recognized. Property and equipment are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment.

Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred. The amount of depreciation expense we record is dependent upon certain

F-117

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

assumptions, including an asset’s estimated useful life, rate of consumption and corresponding salvage value. We periodically review these assumptions and may change one or more of these assumptions. Changes in our assumptions may require us to recognize, on a prospective basis, increased or decreased depreciation expense. In connection with the adoption of fresh-start accounting, the useful lives for drilling rigs and equipment were reset based on fair value assumptions and standardization of rig components. The new useful lives of the drilling rig components range between 3 and 30 years.

In accordance with our policy, the estimated useful lives of our property and equipment are as follows:

Years

• Drilling rigs 7 – 30

• Drilling machinery and equipment 3 – 5

• Other 3 – 10

We evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. For assets classified as held and used, we determine recoverability by evaluating the estimated undiscounted future net cash flows based on projected dayrates and utilization. An impairment loss on our long-lived assets exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition is less than its carrying amount. For property and equipment whose carrying values are determined not to be recoverable, we calculate an impairment loss as a difference between the fair value and carrying amount. We estimate the fair values by applying either an income approach, using projected discounted cash flows, or a market approach. Estimates of discounted future cash flows typically include (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses, (ii) long-term growth rates, and (iii) estimates of useful lives of the assets. Such estimates of future discounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions. In a market approach, the fair value would be based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants.

Fair Value Measurements

We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability, respectively. Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows:

Level 1. Unadjusted quoted prices for identical assets or liabilities in active markets,

Level 2. Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets, and

Level 3. Unobservable inputs that require significant judgment for which there is little or no market data.

When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Our cash and cash equivalents, accounts receivable and accounts payable are by their nature short-term. As a result, the carrying values included in the accompanying Consolidated Balance Sheets approximate fair value.

Foreign Currency

Our reporting currency is the U.S. dollar. All subsidiaries of the Predecessor and Successor maintain their books and records in their functional currency. The functional currency of the Predecessor was primarily the U.S. dollar. The functional currency is the U.S. dollar for all our Successor’s operations. We therefore

F-118

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

define foreign currency transactions as any transaction denominated in a currency other than the U.S. dollar. Monetary assets and liabilities denominated in a foreign currency are measured to U.S. dollars at the rate of exchange in effect as of each respective period end; items of income and expense are measured at average monthly rates; and property and equipment and other non-monetary assets are measured at historical rates. Realized and unrealized gains and losses on foreign currency transactions are recorded in “Other, net” on our Consolidated Statement of Operations.

Certain Significant Estimates and Contingent Liabilities

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. On an ongoing basis, the Company evaluates its estimates, including those related to allowance for doubtful accounts, long-lived asset impairment, useful lives for depreciation, income taxes, insurance claims, employment benefits and contingent liabilities. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions.

Income Taxes

We operate through various subsidiaries in numerous countries throughout the world. Due to our global presence, we are subject to tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in the U.K., the U.S., and any other jurisdictions in which we or any of our subsidiaries operate, were incorporated, or otherwise considered to have a tax presence. 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. If the taxing authorities do not agree with our assessment of the effects of such laws, policies, treaties and regulations, or the interpretation or enforcement thereof, this could have a material adverse effect on us including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

In certain jurisdictions, we have recognized deferred tax assets and liabilities. Judgment and assumptions are required in determining whether deferred tax assets will be fully or partially utilized. When we estimate that all or some portion of certain deferred tax assets such as net operating loss carryforwards will not be utilized, we establish a valuation allowance for the amount ascertained to be unrealizable. We continually evaluate strategies that could allow for future utilization of our deferred tax assets. Any change in the ability to utilize such deferred tax assets will be accounted for in the period of the event affecting the valuation allowance. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting adjustments could have a material effect on our financial results or cash flow.

In certain circumstances, we expect that, due to changing demands of the offshore drilling markets and the ability to redeploy our offshore drilling units, certain units will not reside in a location long enough to give rise to future tax consequences. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should our expectations change regarding the length of time an offshore drilling unit will be used in a given location, we will adjust deferred taxes accordingly.

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the other party in making financial and operating decisions. Parties are also related if they are subject to common control or common significant influence.

F-119

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Subsequent Events

The Company's consolidated financial statements were evaluated for subsequent events through April 29, 2019, the date the consolidated financial statements were available to be issued.

Share-based compensation

The TVRSU’s under the Employee and Director Plan are valued on the date of award at an estimated share price. In order to estimate the share price of our TVRSU grant, we estimated the business enterprise value and fair value of equity on a non-controlling, marketable basis using the NAV Method and calculated the marketable fair value per share based on the outstanding and granted shares of the Company. Due to the fact that we are a privately held company and our shares do not trade freely on an open exchange, we then applied a discount for lack of marketability on the marketable fair value per share. In order to determine an appropriate discount for lack of marketability we utilized a protective put analysis, restricted stock studies, and pre-IPO studies.

The total compensation for TVRSU’s that ultimately vests is recognized using a straight-line method over a 2.6 year service period. The shares and related nominal value are recorded when the restricted stock unit vests and additional paid-in capital is adjusted as the share-based compensation cost is recognized for financial reporting purposes.

Recently Issued Accounting Standards

Adoption of new accounting standards

In January 2017, the FASB issued guidance to ASU 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business”. The amendments provide guidance on evaluating whether transactions should be accounted for as an asset acquisition or a business combination (or disposal). The guidance requires that in order to be considered a business, a transaction must include, at a minimum, an input and a substantial process that together significantly contribute to the ability to create output. The guidance removes the evaluation of whether a market participant could replace the missing elements. The revised guidance is effective for annual reporting periods beginning after December 15, 2017, including interim reporting periods within those annual reporting periods. The adoption did not have a material impact on the Consolidated Financial Statements and related Disclosures.

In May 2017, the FASB issued ASU No. 2017-09, Compensation — Stock Compensation (Topic 718): Scope of Modification. The amendments apply to entities that change the terms or conditions of a share-based payment award. The FASB Accounting Standards Codification currently defines the term modification as “a change in any of the terms or conditions of a share-based payment award”. These amendments require the entity to account for the effects of a modification unless all the following conditions are met:

• The fair value (or calculated value or intrinsic value, if such an alternative measurement method is used) of the modified award is the same as the fair value (or value using an alternative measurement method) of the original award immediately before the original award is modified. If the modification does not affect any of the inputs to the valuation technique that the entity uses to value the award, the entity is not required to estimate the value immediately before and after the modification;

• The vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the original award is modified; and

• The classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the original award is modified.

The amendments are effective for all entities for annual periods, and interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted. The Company has adopted this standard as of January 1, 2018 with no impact on the Consolidated financial statements.

F-120

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. The amendments require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. As a result, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendments do not provide a definition of restricted cash or restricted cash equivalents. The amendments should be applied using a retrospective transition method to each period presented and is effective beginning after December 15, 2017. The Company has adopted this standard as of January 1, 2018 and has applied the new guidance for restricted cash presentation. Due to this adoption, the Company has included restricted cash of $4.2 million as part of cash, cash equivalents and restricted cash in the Consolidated Statement of Cash Flows for the period ended March 28, 2018.

Issued not effective accounting standards

In May 2014, the FASB issued ASU No. 2014-09 (“ASU 2014-09”), which creates ASC Topic 606, Revenue from Contracts with Customers and supersedes the revenue recognition requirements in Topic 605 and industry-specific standards that currently exist under U.S. GAAP. The amendments in this ASU are intended to provide a more robust framework for addressing revenue issues, improve comparability of revenue recognition practices and improve disclosure requirements. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. In March, April, May and November 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients, and ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, respectively. These updates clarify important aspects of the guidance and improve its operability and implementation. ASC Topic 606 is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual reporting periods beginning after December 15, 2019. The effective date for this Company is annual periods beginning after December 15, 2018, and interim periods beginning in 2020 and must be adopted using either a full retrospective method or a modified retrospective method We are still evaluating methods of adoption and what impact the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures which will be based on contract-specific facts and circumstances that could introduce variability to the timing of our revenue recognition relative to current accounting standards.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). The update requires an entity to recognize right-of-use assets and lease liabilities on its balance sheet and disclose key information about leasing arrangements. It also offers specific accounting guidance for a lessee, a lessor and sale and leaseback transactions. Lessees and lessors are required to disclose qualitative and quantitative information about leasing arrangements to enable a user of the financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. The guidance will be effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years and early adoption is permitted. We expect to elect the new optional transition method of adoption. With respect to our drilling contracts, which could contain a lease component, we expect to apply the practical expedient and recognize revenues based on the service component, which we have determined is the predominant component of our contracts. With respect to the lease arrangements under which we are the lessee as of March 28, 2018, we are still evaluating the effects of adoption.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which revises guidance for the accounting for credit losses on financial instruments within its scope. The new standard introduces an approach, based on expected losses, to estimate credit losses on certain types of financial instruments and modifies the

F-121

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

impairment model for available-for-sale debt securities. The guidance will be effective January 1, 2020, with early adoption permitted. Entities are required to apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Company is in the process of evaluating the impact of this standard update on its consolidated financial statements and related disclosures.

In March 2017 the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” The amendments in this update require that an employer disaggregate the service cost component from the other components of net benefit cost and provide guidance on how to present the service cost component and the other components of net benefit cost in the income statement. The guidance is effective for private company financial statements issued for annual reporting periods beginning after December 15, 2018, and interim periods within annual periods beginning after December 15, 2019. The amendment for the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost should be applied retrospectively. We do not expect that our adoption will have a material impact on our financial condition, results of operations, cash flows or financial disclosures.

In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities. This ASU refines and expands hedge accounting for both financial (e.g. interest rate) and commodity risks and creates more transparency around how economic results are presented, both on the face of the financial statements and in the footnotes, for investors and analysts. The amendments are effective for annual periods beginning after December 15, 2018 for public entities, including interim periods within that period, with early adoption permitted. The Company believes that the adoption will not have a material effect on the consolidated financial statements.

Note 3 – Revenues

In the period January 1, 2018 to March 28, 2018, the Company recognised revenues of $27.2 million, primarily relating to dayrate revnue.

Our typical dayrate drilling contracts require our performance of a variety of services for a specified period of time. We determine progress towards completion of the contract by measuring efforts expended and the cost of services required to perform under a drilling contract, as the basis for our revenue recognition. Revenues generated from our dayrate basis drilling contracts and labor contracts are recognized on a per day basis as services are performed and begin upon the contract commencement, as defined under the specified drilling or labor contract. Dayrate revenues are typically earned, and contract drilling expenses are typically incurred ratably over the term of our drilling contracts. We review and monitor our performance under our drilling contracts to confirm the basis for our revenue recognition. Revenues from bonuses are recognized when earned.

It is typical in our dayrate drilling contracts to receive compensation and incur costs for mobilization, equipment modification, or other activities prior to the commencement of the contract. Any such compensation may be paid through a lump-sum payment or other daily compensation. Pre-contract compensation and costs are deferred until the contract commences. The deferred pre-contract compensation and costs are amortized, using the straight-line method, into income over the term of the initial contract period, regardless of the activity taking place. This approach is consistent with the economics for which the parties have contracted. Once a contract commences, we may conduct various activities, including drilling and well bore related activities, rig maintenance and equipment installation, movement between well locations or other activities.

F-122

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Note 4 – Other, net

Financial income (expense), net is comprised of the following:

(In $ millions)	January 1, 2018 to March 28, 2018
Interest income		0.4
Total		0.4

Note 5 – Income Taxes

We operate through various subsidiaries in numerous countries throughout the world. Due to our global presence, we are subject to tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in the U.K., the U.S., and any other jurisdictions in which we or any of our subsidiaries operate, were incorporated, or otherwise considered to have a tax presence. 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. If the taxing authorities do not agree with our assessment of the effects of such laws, policies, treaties and regulations, or the interpretation or enforcement thereof, this could have a material adverse effect on us including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

In certain jurisdictions, we have recognized deferred tax assets and liabilities. Judgment and assumptions are required in determining whether deferred tax assets will be fully or partially utilized. When we estimate that all or some portion of certain deferred tax assets such as net operating loss carryforwards will not be utilized, we establish a valuation allowance for the amount ascertained to be unrealizable. We continually evaluate strategies that could allow for future utilization of our deferred tax assets. Any change in the ability to utilize such deferred tax assets will be accounted for in the period of the event affecting the valuation allowance. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting adjustments could have a material effect on our financial results or cash flow.

In certain circumstances, we expect that, due to changing demands of the offshore drilling markets and the ability to redeploy our offshore drilling units, certain units will not reside in a location long enough to give rise to future tax consequences. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should our expectations change regarding the length of time an offshore drilling unit will be used in a given location, we will adjust deferred taxes accordingly.

Income tax expense is comprised of the following:

(In $ millions)	January 1, 2018 to March 28, 2018
Current tax		2.7
Change in deferred tax		—
Total		2.7

The effective tax rate for the period January 1, 2018 to March 28, 2018 was approximately (1.1%) on a pre-tax loss of $250.9 million. The change in our effective tax rate from period to period is primarily attributable to changes in the profitability or loss mix of our operations in various jurisdictions. As our operations continually change among numerous jurisdictions, and methods of taxation in these jurisdictions vary greatly, there is little direct correlation between the income tax provision/benefit and income/loss before taxes.

F-123

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

A reconciliation of the Cayman statutory tax rate to our effective rate is shown below:

	January 1, 2018 to March 28, 2018
Cayman statutory income tax rate		0	%
Tax rates different from the statutory rate		(1.0	%)
Change in valuation allowance		0	%
Adjustments to uncertain tax positions		(0.1	%)
Total		(1.1	%)

The components of the net deferred taxes are as follows:

(In $ millions)	March 28, 2018
Deferred tax assets
Net operating losses		2.9
Excess of tax basis over book basis of Property, Plant and Equipment		36.3
Other		1.3
Deferred tax assets		40.5
Less: Valuation allowance		(37.3	)
Net deferred tax assets		3.2
Deferred tax liabilities
Deferred tax liabilities		—
Net deferred tax asset (liabilities)		3.2

The deferred tax assets related to net operating losses were generated in United Kingdom, which will not expire. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if estimates of future taxable income change.

We conduct business globally and, as a result, we file numerous income tax returns, or are subject to withholding taxes, in various jurisdictions. In the normal course of business we are generally subject to examination by taxing authorities throughout the world, including major jurisdictions we operate or used to operate, such as Cyprus, Denmark, Egypt, Equatorial Guinea, India, Israel, Luxembourg, Mexico, the Netherlands, Nigeria, Qatar, Saudi Arabia, Singapore, Switzerland, the United Kingdom, the United States, and Tanzania. We are no longer subject to examinations of tax matters for years prior to 1999.

There is no change to the liabilities related to our unrecognized tax benefits, excluding interest and penalties, during January 1, 2018 and March 28, 2018.

The liabilities related to our unrecognized tax benefits comprise the following:

(In millions)	January 1, 2018 to March 28, 2018
Unrecognized tax benefits, excluding interest and penalties	$	3.9
Interest and penalties included in “Other liabilities”		2.9
Unrecognized tax benefits, including interest and penalties	$	6.8

We include, as a component of our income tax provision, potential interest and penalties related to liabilities for our unrecognized tax benefits within our global operations. Interest and penalties resulted in an income tax expense of $0.1 million for the period January 1, 2018 to March 28, 2018.

F-124

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

At March 28, 2018, the liabilities related to our unrecognized tax benefits, including estimated accrued interest and penalties, totalled $6.8 million, and if recognized, would reduce our income tax provision by $6.8 million. It is reasonably possible that our existing liabilities related to our unrecognized tax benefits may increase or decrease in the next twelve months primarily due to the progression of open audits or the expiration of statutes of limitation. However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties, such as the unresolved nature of various audits.

Note 6 – Earnings from Equity affiliate

The Prospector Group was not transferred from the Predecessor to the Successor on the Effective Date; however, it will not be wound down and dissolved by the Joint Administrators. As such, the Prospector Group is intended to constitute part of our ongoing operational business. On the Effective Date, the Prospector Group remained held by the Predecessor; however, pursuant to the Management Agreement, the Successor has the power to direct the activities that most significantly impact the Prospector Group’s economic performance, and the obligation to absorb losses and the right to receive benefits that could potentially be significant to the Prospector Group. As a result, the Prospector Group is a VIE for accounting purposes for which the Successor is the primary beneficiary, and as of the Effective Date, the Successor continued to consolidate the Prospector Group in our Consolidated Financial Statements.

On July 20, 2017, the Prospector Debtors commenced the Prospector Bankruptcy cases by filing voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court in order to implement a restructuring plan to effectuate the transfer of the Prospector Group to the Successor. In accordance with U.S. GAAP, when a subsidiary whose financial statements were previously consolidated (as the Prospector Group’s were with ours) becomes subject to the control of a government, court, administrator or regulator (including filing for protection under the Bankruptcy Code), whether solvent or insolvent, deconsolidation of that subsidiary is generally required. Accordingly, the Prospector Group is no longer fully consolidated with the Successor subsequent to the Prospector Debtors’ voluntarily filing for reorganization on July 20, 2017. Our investment in the Prospector Group is recorded under the equity method of accounting. The equity method requires us to present the net assets of the Prospector Group as an investment and recognize the income or loss from the Prospector Group in our results of operations during the reorganization period. As a result of fresh-start accounting on the Effective Date, we did not record a gain or loss on the deconsolidation of the Prospector Group since the Prospector Group’s net assets approximated fair value on July 20, 2017. When the Prospector Group emerges from the jurisdiction of the Bankruptcy Court, the subsequent accounting will be determined based upon the applicable circumstances and facts at such time, see note 13.

The financial statements below represent the Condensed Consolidated Financial Statement of the Prospector Group. The financial statements below have been prepared assuming that the Prospector Group will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. The Prospector Group’s ability to continue as a going concern is contingent upon the Bankruptcy Court’s approval of it’s financial restructuring as described above. This represents a material uncertainty related to events and conditions that raises substantial doubt on the Prospector Group’s ability to continue as a going concern and, therefore, the Prospector Group may be unable to utilize its assets and discharge its liabilities in the normal course of business.

During the period that the Prospector Group is operating as debtors-in-possession under chapter 11 of the Bankruptcy Code, it may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions in the Lease Agreements), for amounts other than those reflected in the financial statements below. Further, the results of the financial restructuring could materially change the amounts and classifications of assets and liabilities reported in the financial statement. The financial statement does not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should the Prospector Group be unable to continue as a going concern.

F-125

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Intercompany transactions among the Prospector Group have been eliminated in the financial statements presented below. Intercompany transactions between the Prospector Group and the Successor are included in the Prospector Group’s financial statements presented below. However, “Investment in equity method affiliate” as reported on the Successor’s Consolidated Balance Sheet as of March 28, 2018 and “Earnings from equity method affiliate” as reported on the Successor’s Consolidated Statement of Operations for the Successor period from January 1, 2018 to March 28, 2018 include intercompany transactions between the Prospector Group and the Successor, see note 16.

A total of $139.4 million was paid prior to reconsolidation of the Prospector Group as settlement of the sale-leaseback obligation.

Please refer to note 7 Business Combination for change in consolidation of the Prospector group on March 27, 2018 when the Company gained control over the Prospector Group.

PROSPECTOR GROUP’S CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(DEBTOR-IN-POSSESSION)
(Unaudited)
(In $ million)

	January 1, 2018 To March 27, 2018
Operating Revenues		4.0
Operating cost and expenses
Rig operating and maintenance expenses		(10.1	)
Depreciation and impairment of non-current assets		(3.8	)
General and administrative expenses		(0.5	)
Reorganisation items		(33.1	)
Total operating expenses		(47.5	)
Operating loss		(43.5	)
Financial expense, net		(2.9	)
Loss before income taxes		(46.4	)
Income tax expense		(0.1	)
Net loss for the period		(46.5	)

Note 7 – Business combination

On July 20, 2017, the Prospector Group commenced the bankruptcy cases by filing voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court in order to implement a restructuring plan to effectuate the transfer of the Prospector Group to Paragon Offshore Limited. In accordance with U.S. GAAP, when a subsidiary whose financial statements were previously consolidated (as the Prospector Group’s were with ours) becomes subject to the control of a government, court, administrator or regulator (including filing for protection under the Bankruptcy Code), whether solvent or insolvent, deconsolidation of that subsidiary is generally required. Accordingly, the Prospector Group is no longer fully consolidated with Paragon Offshore Limited subsequent to the Prospector Group voluntarily filing for reorganization on July 20, 2017. Our investment in the Prospector Group is recorded under the equity method of accounting effective July 20, 2017. The equity method requires us to present the net assets of the Prospector Group at July 20, 2017 as an investment and recognize the income or loss from the Prospector Group in our results of operations during the reorganization period. When the Prospector Group emerges from the jurisdiction of the Bankruptcy Court, the subsequent accounting will be determined based upon the applicable circumstances and facts at such time.

F-126

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

The Prospector Group has an interest in two high specification jackup units, Prospector 1 and Prospector 5 (collectively, the “Prospector Rigs”) pursuant to two sale-leaseback agreements (the “Lease Agreements”) executed with subsidiaries of SinoEnergy Capital Management Ltd. (the “Lessors”). On March 27, 2018, the Prospector Group settled with SinoEnergy Capital Management, thus emerging from the jurisdiction of the Bankruptcy Court. The Prospector Group assets, liabilities, income and loss will be consolidated back into Paragon Offshore Limited financial statements and will no longer be treated as an equity method subsidiary.

On March 27, 2018, the Company gained control over the Prospector Group. No consideration was paid by the Company as part of change of control in the Prospector Group. The Company remeasured its existing equity method investment in the Prospector Group and recorded a remeasurement gain of $8.6 million. The remeasurement gain was attributable to an increase in the value of the Prospector Group rigs.

(In $ millions)
Fair value of consideration transferred	0
Fair value of previously held equity interest	206.5
Subtotal	206.5
Recognized value of 100% of the identifiable net assets, as measured in accordance with the Standards	206.5
Goodwill	0

Prospector reconsolidation (in $ millions):

	March 27, 2018
ASSETS
Current assets
Cash and cash equivalents		5.2
Trade receivables		2.8
Other current assets		0.8
Total current assets		8.8
Non-current assets
Property, Plant and Equipment		220.0
Other long-term assets		0.2
Total non-current assets		220.2
Total assets		229.0
LIABILITIES AND EQUITY
Current liabilities
Trade payables		19.8
Accruals and other current liabilities		2.7
Total current liabilities		22.5
Non-Current liabilities
Other liabilities		0.9
Total non-current liabilities		0.9
Total liabilities		23.4
EQUITY
Total equity		206.5
Total liabilities and equity		229.0

F-127

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Unaudited pro forma combined statements of operations for the period ended March 28, 2018 to give effect to the Prospector reconsolidation as if it had occurred on January 1, 2018 has not been provided since Paragon Offshore held 100% of the shares prior to the business combination. Application of the equity method and full consolidation would as such not result in a material difference to net income.

Note 8 – Property and equipment and other assets

(In $ millions)
Property and equipment and other assets as of January 1, 2018 at cost	270.8
Additions	1.8
Prospector reconsolidation (see note 7)	220.0
Property and equipment and other assets at cost	492.6
Accumulated depreciation as of January 1, 2018	(22.1	)
Less: accumulated depreciation for the period ended March 28, 2018	(10.7	)
Less: accumulated impairment	(187.6	)
Property and equipment and other assets as of March 28, 2018	272.2

Impairment assessment of jack-up rigs

Drilling rigs are reviewed for impairment, whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. Management identified indications of impairment for the period ended March 28, 2018. As of March 28, 2018, its more likely than not, our rigs will be sold or otherwise disposed of before the end of their previously estimated useful lives.

In estimating fair value of the jack-up rigs, management has assumed the purchase values set forth in the acquisition by Borr on March 28,2018. Rigs with a carrying value exceeding acquisition value is impaired down to the purchase price set forth in the purchase agreement. As a consequence, the Company recognized an impairment loss of $187.6 million for the period ended March 28, 2018.

Note 9 – Other current assets

Other current assets are comprised of the following:

(In $ millions)	March 28, 2018
Prepaid assets		5.8
Taxes receivable		3.1
Tax retentions receivable		11.4
Total		20.3

Note 10 – Other long-term assets

Other long-term assets are comprised of the following:

(In $ millions)	March 28, 2018
Deferred Regulatory Inspection		0.4
Long term tax refund		4.2
Litigation trust loan receivable		3.5
Other receivable		0.7
Deferred tax asset		3.2
Total		12.0

F-128

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Note 11 – Current debt

As of March 28, 2018

Current debt is comprised of the following:

									Maturities
(In $ millions)	Carrying value		Fair value		Principal		PIK interest		Less than 6 months		6 months to 1 year		1-5 years
Term loan Facility with Secured Lenders		87.8		87.8		85.0		2.8		87.8		—		—
Total		87.8		87.8		85.0		2.8		87.8		—		—

New Term Loan Facility with Secured Lenders

We entered into the Amended and Restated Senior Secured Term Loan Facility with lenders to provide for loans in the aggregate principal amount of $85 million, which are deemed outstanding pursuant to the Consensual Plan (the “Term Loan Facility”). The maturity date of the Term Loan Facility is July 18, 2022. In the event of a change of control, all outstanding loans, including both principal and interest shall become immediately due and payable. The loan is classified as current due to the settlement immediately following the Borr acquisition. Until such maturity date, the Term Loan Facility shall bear interest at a rate per annum equal to (i) the alternative base rate plus an applicable margin of 5.00% or (ii) adjusted LIBOR plus an applicable margin of 6.00%. Effective interest rate for the period ended March 28, 2018 was 7.7%.

The following rigs were pledged as collateral for the Senior Secured Term Loan Facility: MSS1, C20051, Dhabi II, B152, HZ1, B391, C461, C462, C463, L784, L785, M825, M826, M1162, M841, M1161, M823, L786, M824, L1112 and M531. As of March 28, 20108, book value of the pledged rigs was $36.1 million.

We may elect to prepay any borrowing outstanding under the Term Loan Facility without premium or penalty (except with respect to any break funding payments which may be payable pursuant to the terms of the Term Loan Facility).

The Term Loan Facility contains restrictions on certain merger and consolidation transactions; our ability to sell or transfer certain assets; payment of dividends; making distributions; redemption of stock; incurrence or guarantee of debt; issuance of loans; prepayment; redemption of certain debt; as well as incurrence or assumption of certain liens.

Note 12 – Share-based compensation

In December 2017, we granted 496,686 time vested restricted stock units (“TVRSU’s”) to the Company's employees. The total estimated cost of the restricted stock will be approximately $21.7 million, which will be expensed over the requisite service period. The share-based payment charge for the period January 1, 2018 to March 28, 2018 was $20.3 million.

Shares available for issuance and outstanding restricted stock units under the Employee and Director Plan as of December 31, 2017 are as follows:

(In shares)	Employee and Directors
Shares available for future awards or grants		56,870
Outstanding unvested restricted stock units		468,443

The TVRSU’s under the Employee and Director Plan are valued on the date of award at an estimated share price. In order to estimate the share price of our TVRSU grant, we estimated the business enterprise value and fair value of equity on a non-controlling, marketable basis using the NAV Method and calculated the marketable fair value per share based on the outstanding and granted shares of the Company. Due to the fact that we are a privately held company and our shares do not trade freely on an open exchange, we then

F-129

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

applied a discount for lack of marketability on the marketable fair value per share. In order to determine an appropriate discount for lack of marketability we utilized a protective put analysis, restricted stock studies, and pre-IPO studies.

The total compensation for TVRSU’s that ultimately vests is recognized using a straight-line method over a 2.6 year service period. The shares and related nominal value are recorded when the restricted stock unit vests and additional paid-in capital is adjusted as the share-based compensation cost is recognized for financial reporting purposes.

A summary of restricted stock activity for the Successor period from July 18, 2017 to March 28, 2018 is as follows:

	TVRSU’s Outstanding			Weighted Average
Outstanding as of July 18, 2017		—		$	—
Awarded		498,686			43.50
Vested		(30,243	)		43.50
Outstanding as of December 31, 2017		468,443		$	43.50
Vested(i)		(468,433	)		43.50
Outstanding as of March 28, 2018		—		$	—

(i) All TVRSU’s outstanding were vested due to the acquisition of the Paragon Offshore Limited by Borr Drilling and $21.1million was subsequently paid by Borr Drilling as part of the purchase consideration.

Note 13 – Accruals and other current liabilities

Accruals and other current liabilities are comprised of the following:

(In $ millions)	March 28, 2018
Accrued expenses		6.3
Accrued payroll and related costs		14.8
Other taxes payable		1.6
Income tax payable		4.6
Interest payable		1.4
Other current liabilities		3.5
Total accruals and other current liabilities		32.2

Note 14 – Legal settlement

In 2015, arbitration was commenced by Paragon arising under an agreement for the charter of a jack-up rig to a customer in Asia. Following the arbitration, in June 2016, a total balance of $6.4 million outstanding receivable and all associated taxes were written off to bad debt expense. In February 2018, a legal settlement was reached with the customer. In March 2018, the Company received payment for receivables previously written off as part of the legal settlement. The gross amount of cash collected was $8.8 million and includes payment of previously written down receivable of $6.4 million and interest and legal fees of $2.4 million. The $15.4 million gain as a result of the legal settlement consists of:

(In $ millions)
Net cash collected	8.8
Taxes paid by counterpart on behalf of Paragon	5.2
Relief of debit notes	1.4
Total legal settlement	15.4

F-130

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Note 15 – Concentration of market and credit risk

The market for our services is the offshore oil and gas industry, and our customers consist primarily of government-owned oil companies, major integrated oil companies and independent oil and gas producers. We perform ongoing credit evaluations of our customers and do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial condition should be considered in light of the fluctuations in demand experienced by drilling contractors as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial condition as supply and demand factors directly affect utilization and dayrates, which are the primary determinants of our net cash provided by operating activities.

Major Customers

For the period ended March 28, 2018 the following customers accounted for more than 10% of our contract revenues:

(in % of Operating revenues)	For the Period Ended March 28, 2018
ONE		13	%
National Drilling Company (ADOC)		36	%
Dynamic		37	%
Total		86	%

Note 16 – Commitments and contingencies

Operating Leases

Future minimum lease payments for operating leases for at March 28, 2018 are as follows:

(In $ millions)	2018		2019		2020		2021		2022		Thereafter		Total
Minimum lease payments	$	4.8	$	4.4	$	3.9	$	3.9	$	0.6	$	—	$	17.6

Of the future minimum lease payment, $4.4 million is recognized as onerous lease liability.

Pledged rigs

The following rigs were pledged as collateral for the Senior Secured Term Loan Facility: MSS1, C20051, Dhabi II, B152, HZ1, B391, C461, C462, C463, L784, L785, M825, M826, M1162, M841, M1161, M823, L786, M824, L1112 and M531. As of March 28, 2018, book value of the pledged rigs as of March 28, 2018 was $36.1 million, see note 11.

Tax Contingencies

We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. As of March 28, 2018, the Successor has tax assessments of approximately $10 million. We have contested, or intend to contest, these assessments, including through litigation if necessary. Tax authorities may issue additional assessments or pursue legal actions as a result of tax audits, and we cannot predict or provide assurance as to the ultimate outcome of such assessments and legal actions.

A tax law was enacted in Brazil, effective January 1, 2015, that under certain circumstances would impose a 15% to 25% withholding tax on charter hire payments made to a non-Brazilian related party exceeding certain thresholds of total contract value. Although we believe that our operations are not subject to this law, the tax has been withheld at the source by our customer and we have recorded approximately $8 million withholding tax expense since inception of the law. We have been in discussions with our customer over the applicability of this legislation, and while we have reached a settlement agreement with our customer in regard to the amount withheld, we cannot be certain any of this amount will be collected.

F-131

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Other Commercial commitments

We have other commercial commitments which contractually obligate us to settle with cash under certain circumstances. Surety bonds and parent company guarantees entered into between certain customers and governmental bodies guarantee our performance regarding certain drilling contracts, customs import duties and other obligations in various jurisdictions.

The principal amount of the outstanding surety bonds was $28.0 million as of March 28, 2018. In addition, we had performance bonds amounting to $9.8 million.

As of March 28, 2018, these obligations stated in $ equivalent and their expiry dates are as follows:

(In $ millions)	2018		2019		2020		2021		Thereafter		Total
Surety bonds and other guarantees		4.9		32.6		—		—		0.3		37.8

Other commitments and contingencies

The Predecessor, Successor, certain of the reorganized Debtors and the Joint Administrators entered into a Litigation Trust Agreement (the “Litigation Trust Agreement”) with Drivetrain, LLC, as Litigation Trust Management, and certain members of a litigation trust committee, pursuant to which a trust (the “Litigation Trust”) was established for the benefit of certain holders of allowed claims under the Consensual Plan. Pursuant to the Consensual Plan and the Confirmation Order, the Predecessor and the reorganized Debtors transferred to the Litigation Trust certain claims against Noble relating to the Predecessor’s separation from Noble (the “Noble Claims”). In addition, Noble may assert damages against the Predecessor for indemnification amounts that would have been owed to Noble pursuant to the Noble Separation Agreements. Pursuant to the terms of the Litigation Trust Agreement, a subsidiary of the Successor agreed to provide the Litigation Trust with an interest-free delayed draw term loan of up to $10 million in cash to fund the reasonable costs and expenses associated with the administration of the Litigation Trust (the “Litigation Trust Term Loan”). The Litigation Trust may prosecute the Noble Claims and conduct such other action as described in and authorized by the Consensual Plan, make timely and appropriate distributions to the beneficiaries of the Litigation Trust and otherwise carry out the provisions of the Litigation Trust Agreement. None of the Predecessor, Successor or any of the reorganized Debtors is a beneficiary to, or investor in, the Litigation Trust.

Separation Agreements

In connection with the Spin-Off, the Predecessor entered into several definitive agreements with Noble or its subsidiaries (collectively, the “Noble Separation Agreements”) that, among other things, set forth the terms and conditions of the Spin-Off and provide a framework for the Predecessor’s relationship with Noble after the Spin-Off, including the following agreements:

• Master Separation Agreement;

• Tax Sharing Agreement;

• Employee Matters Agreement;

• Transition Services Agreement relating to services Noble and Paragon will provide to each other on an interim basis; and

• Transition Services Agreement relating to Noble’s Brazil operations.

On the Effective Date, the Predecessor rejected the Separation Agreements pursuant to the terms of the Consensual Plan. As a result of rejecting the Tax Sharing Agreement, the Predecessor is no longer entitled to indemnity from Noble with respect to the tax liabilities. In addition, Noble may assert claims against the Predecessor for indemnification amounts that would have been owed to Noble pursuant to the Tax Sharing Agreement.

F-132

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Note 17 – Related parties

Prospector group

We have invoiced certain labour secondments and onshore management charges from Paragon to the Prospector group. Sales to Prospector group were $4.4 million for the period ended March 28, 2018.

Note 18 – Pension

Defined Benefit Plans

As of March 28, 2018, the Company sponsored two non-U.S. noncontributory defined benefit pension plans, the Paragon Offshore Enterprise Ltd and the Paragon Offshore Nederland B.V. pension plans, which cover certain Europe-based salaried employees. As of January 1, 2017, all active employees under the defined benefit pension plans were transferred to a defined contribution pension plan as related to their future service. The accrued benefits under the defined benefit plans is frozen and all employees are deferred members. The transfer to a defined contribution pension plan was accounted for as a curtailment during the year ended December 31, 2016. Our defined benefit pension plans were recorded at fair value upon adoption of fresh-start accounting on July 18, 2017.

At March 28, 2018 our pension obligations represented an aggregate liability of $147.2 million and an aggregate asset of $146.5 million, representing the funded status of the plans. In the year ended December 31, 2018, aggregate periodic benefit costs showed interest income of $0.5 million, and expected return on plan assets of $0.5 million. See Note 2 - Accounting Policies - Issued not effective accounting standards.

A reconciliation of the changes in projected benefit obligations (“PBO”) for our pension plans is as follows:

(In $ millions)	March 28, 2018
Benefit obligation at beginning of period		132.0
Service cost		—
Interest cost		0.5
Actuarial loss (gain)		0.6
Benefits and expenses paid		(0.4	)
Plan participants’ contribution		—
Foreign exchange rate changes		14.5
Other: curtailment gain
Benefit obligation at end of period		147.2

A reconciliation of the changes in fair value of plan assets is as follows:

(In $ millions)	March 28, 2018
Fair value of plan assets at beginning of period		131.5
Actual return on plan assets		0.9
Employer contribution		—
Benefits paid		(0.3	)
Plan participants’ contributions		—
Expenses paid		—
Foreign exchange rate changes		14.4
Fair value of plan assets at end of period		146.5

The funded status of the plans is as follows:

(In $ millions)	March 28, 2018
Funded status		(0.8	)

F-133

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Amounts recognized in the Consolidated Balance Sheets consist of:

(In $ millions)	March 28, 2018
Other assets - noncurrent		1.0
Other liabilities - noncurrent		(1.8	)
Net pension asset (liability)		(0.8	)
Accumulated other comprehensive loss recognized in financial statements		—
Net amount recognized		0.8

Amounts recognized in OCI consist of:

(In $ millions)	March 28, 2018
Net loss		—
Accumulated other comprehensive income (loss)		—

Pension cost includes the following components:

(In $ millions)	January 1, 2018 to March 28, 2018
Interest cost		0.5
Expected return on plan assets		(0.5	)
Net pension expense		—

Defined Benefit Plans - Disaggregated Plan Information

Disaggregated information regarding our pension plans is summarized below:

(In $ millions)	March 28, 2018
Projected benefit obligation		147.2
Accumulated benefit obligation		147.2
Fair value of plan assets		146.5

Defined Benefit Plans - Key Assumptions

The key assumptions for the plans are summarized below:

Weighted Average Assumptions Used to Determine Benefit Obligations	March 28, 2018
Discount rate	1.09% to 1.49%
Rate of compensation increase	Not applicable

Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	January 1, 2018 to March 28, 2018
Discount rate	1.09% to 1.49%
Expected long-term return on plan assets	1.09% to 1.49%
Rate of compensation increase	Not applicable

The discount rates used to calculate the net present value of future benefit obligations are determined by using a yield curve of high-quality bond portfolios with an average maturity approximating that of the liabilities.

We employ third-party consultants who use a portfolio return model to assess the initial reasonableness of the expected long-term rate of return on plan assets. To develop the expected long-term rate of return on assets, we considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets for the portfolio.

F-134

PARAGON OFFSHORE LIMITED
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
For The Period Ended March 28, 2018

Defined Benefit Plans - Plan Assets

At March 28, 2018, assets of Paragon Offshore Enterprise Ltd and Paragon Offshore Nederland B.V. pension plans were invested in instruments that are similar in form to a guaranteed insurance contract. The plan assets are based on surrender values. Surrender values are calculated based on the Dutch Central Bank interest curve. This yield curve is based on inter-bank swap rates. There are no observable market values for the assets (Level 3); however, the amounts listed as plan assets were materially similar to the anticipated benefit obligations that were anticipated under the plans. As the plan is fully insured, any over or under financing to be covered by the insurer at the time of valuation is presented in the line item “Other” below.

The actual fair value of our pension assets as of March 28, 2018 is as follows:

				Estimated Fair Value Measurements
(In $ millions)	Carrying Amount			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
March 28, 2018
Fixed Income securities:
Guaranteed insurance contracts		147.2			—		—		147.2
Other		(0.8	)		—		—		(0.8	)
Total		146.5			—		—		146.5

The following table details the activity related to the guaranteed insurance contract during the years.

	Fair market Value
Balance as of January 1, 2018	$	131.5
Assets sold/benefits paid		(0.4	)
Return on plan assets		0.9
Foreign exchange rate changes		14.4
Balance as of March 28, 2018		146.5

Defined Benefit Plans - Cash Flows

For the period ended March 28, 2018 we made $nil in contributions to our defined benefit plans.

The following table summarizes benefit payments at March 28, 2018 estimated to be paid within the next ten years by the issuer of the guaranteed insurance contract:

			Payments by Period
	Total		2018		2019		2020		2021		2022		Five Years Thereafter
Estimated benefit payments		27.3		1.4		1.6		1.8		2.1		2.4		18.0

Note 19 – Subsequent events

Acquisition by Borr Drilling

On February 22, 2018, we signed a tender offer agreement (the “Tender Offer Agreement”) with Borr, a public limited liability company incorporated under the laws of Bermuda and listed on the Oslo Stock Exchange. Borr agreed to commence a tender offer to acquire all of our outstanding shares (the “Shares”) at a purchase price of $42.28 per share (the “Offer”). The Offer commenced on February 26. The transaction closed on March 29, 2018.

F-135

5,000,000 Shares

Borr Drilling Limited

Common Shares

 

Goldman Sachs & Co. LLC
DNB Markets
BTIG
Citigroup
Danske Markets
Evercore ISI
Fearnley Securities

Until August 25, 2019 (the 25th day after the date of this Prospectus), all dealers that buy, sell or trade Common Shares, whether or not participating in this Offering, may be required to deliver a prospectus. This is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.