UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________________________________________

FORM 10-K
________________________________________________________
x    
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                     

COMMISSION FILE NUMBER: 001-36465
________________________________________________________
Paragon Offshore plc
________________________________________________________

England and Wales
98-1146017
(State or other jurisdiction of
incorporation or organization)
(I.R.S. employer
identification number)
3151 Briarpark Drive Suite 700, Houston, Texas 77042
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: + 1 832 783 4000

Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Ordinary Shares, Nominal Value $0.01 per Share
New York Stock Exchange

Securities registered pursuant to Sections 12(g) of the Act: None
______________________________________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No   x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No   x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.    Yes   x    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months.    Yes   x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer  ¨
 
 
Accelerated filer  ¨
Non-accelerated filer  x
 
 
Smaller reporting company  ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
As of August 4, 2014, the aggregate market value of the registered shares of Paragon Offshore plc held by non-affiliates of the registrant was $932 million based on the closing sale price as reported on the New York Stock Exchange.
Number of shares outstanding and trading at February 27, 2015: 85,526,352

DOCUMENTS INCORPORATED BY REFERENCE
The proxy statement for the 2015 annual general meeting of the shareholders of Paragon Offshore plc will be incorporated by reference into Part III of this Form 10-K.



PARAGON OFFSHORE PLC
FORM 10-K
For the Year Ended December 31, 2014
TABLE OF CONTENTS
 
 
 
 
 
PAGE 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2


PART I
ITEM 1.    BUSINESS
General
Paragon Offshore plc (together with its subsidiaries, “Paragon,” the “Company,” “we,” “us” or “our”) is a global provider of offshore drilling rigs with a fleet that currently includes 34 jackups and six floaters (four drillships and two semisubmersibles). We refer to our semisubmersibles and drillships collectively as “floaters.” Our primary business is to contract our drilling rigs, related equipment and work crews to conduct oil and gas drilling and workover operations for our exploration and production customers on a dayrate basis around the world.
We operate our geographically diverse fleet with well-established customer relationships. We operate in significant hydrocarbon-producing geographies throughout the world, including Mexico, Brazil, the North Sea, West Africa, the Middle East, India and Southeast Asia. As of December 31, 2014, our contract backlog was $2.2 billion and included contracts with leading national, international and independent oil and gas companies.
Spin-off Transaction
On July 17, 2014, Paragon Offshore Limited, an indirect wholly owned subsidiary of Noble Corporation plc (“Noble”) incorporated under the laws of England and Wales, re-registered under the Companies Act 2006 as a public limited company under the name of Paragon Offshore plc.  Noble transferred to us 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 our issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned.
Acquisition of Prospector Offshore Drilling S. A.
On November 17, 2014, Paragon acquired 89.3 million, or 94.4%, of the outstanding shares of Prospector Offshore Drilling S.A. (“Prospector”), an offshore drilling company organized in Luxembourg and traded on the Oslo Axess, from certain shareholders and in open market purchases for approximately $190 million in cash. In December 2014, we purchased an additional 4.1 million shares for approximately $10 million in cash, increasing our ownership to approximately 93.4 million shares, or 98.7%, of the outstanding shares of Prospector. On January 22, 2015, we settled a mandatory tender offer for additional outstanding shares, increasing our ownership to approximately 99.6% of the outstanding shares of Prospector. On February 23, 2015, we acquired all remaining issued and outstanding shares in Prospector pursuant to the laws of Luxembourg. We spent approximately $202 million to acquire 100% of Prospector and funded the purchase of the shares of Prospector using proceeds from our revolving credit facility and cash on hand.
The Prospector acquisition expanded and enhanced our global fleet by adding two high specification jackups contracted to Total E&P U.K. Limited and Elf Exploration U.K. Limited (“Total S.A.”) for use in the United Kingdom sector of the North Sea. In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China.  These rigs are currently scheduled for delivery in April 2015, September 2015 and March 2016, respectively. Each newbuild is being built pursuant to a contract between one of these subsidiaries and SWS, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary.  Prospector's results of operations are included in our results beginning on November 17, 2014.
Basis of Presentation
The consolidated and combined financial information contained in this report includes periods that ended prior to the Spin-Off on August 1, 2014.  For all periods prior to the Spin-Off, the combined financial statements and related discussion of financial condition and results of operations contained in this report pertain to the historical results of the Noble Standard-Spec Business (our “Predecessor”), which comprised the entire standard specification drilling fleet and related operations of Noble.  Our Predecessor’s historical combined financial statements include three standard specification drilling units that were retained by Noble and three standard specification drilling units that were sold by Noble prior to the Separation.

3


Our Predecessor’s historical combined financial statements for the periods prior to the Spin-Off include assets and liabilities that are specifically identifiable or have been allocated to our Predecessor. Revenues and costs directly related to our Predecessor have been included in the accompanying consolidated and combined financial statements. Our Predecessor received service and support functions from Noble and the costs associated with these support functions have been allocated to our Predecessor using various inputs, such as head count, services rendered, and assets assigned to our Predecessor. Our management considers the allocation methodologies used to be reasonable and appropriate reflections of the related expenses attributable to us for purposes of the carve-out financial statements; however, the expenses reflected in the results of our Predecessor and included in these consolidated and combined statements may not be reflective of the actual expenses that would have been incurred during the periods presented if our Predecessor had operated as a separate standalone entity and may not be indicative of expenses that will be incurred by us in the future. These allocated costs are primarily related to corporate administrative expenses including executive oversight, employee related costs including pensions and other benefits, and corporate and shared employees for the following functional groups:
information technology,
legal, accounting, finance and treasury services,  
human resources,
marketing, and
other corporate and infrastructural services.
We consolidate the historical combined financial results of our Predecessor in our consolidated and combined financial statements for all periods prior to the Spin-Off. All financial information presented after the Spin-Off represents the results of operations, financial position and cash flows of Paragon. Accordingly:
Our Consolidated and Combined Statements of Income and Comprehensive Income for the year ended December 31, 2014 consist of the consolidated results of Paragon for the five months ended December 31, 2014 and the combined results of our Predecessor for the prior months. Our Combined Statements of Income and Comprehensive Income for the years ended December 31, 2013 and 2012 consist entirely of the combined results of our Predecessor. Our net income for the periods prior to July 31, 2014 was recorded to “Net parent investment.”
Our Consolidated and Combined Balance Sheet at December 31, 2014 consists of the balances of Paragon, while at December 31, 2013, the Combined Balance Sheet consists of the balances of our Predecessor.
Our Consolidated and Combined Statement of Cash Flows for the year ended December 31, 2014 consists of the consolidated results of Paragon for the five months ended December 31, 2014, and the combined results of our Predecessor for the prior months. Our Combined Statements of Cash Flows for the years ended December 31, 2013 and 2012 consist entirely of the combined results of our Predecessor.
Our Consolidated and Combined Statement of Changes in Equity for the year ended December 31, 2014 consists of both the activity for Paragon completed in connection with, and subsequent to, the Distribution on August 1, 2014 through the five months ended December 31, 2014 and for our Predecessor for the prior months. Our Combined Statements of Changes in Equity for the years ended December 31, 2013 and 2012 consist of activity for our Predecessor recorded to “Net parent investment.”
As our Predecessor previously operated within Noble’s corporate cash management program for all periods prior to the Distribution, funding requirements and related transactions between our Predecessor and Noble have been summarized and reflected on our consolidated and combined balance sheet as “Net parent investment” without regard to whether the funding represents a receivable, liability or equity. Based on the terms of our Separation from Noble, we ceased being a part of Noble’s corporate cash management program.  Any transactions with Noble after August 1, 2014 have been, and will continue to be, cash settled in the ordinary course of business, and such amounts are included in “Accounts payable” on our consolidated and combined balance sheet.
Separation from Noble
Prior to the Spin-off, our total equity represented the cumulative net parent investment by Noble, including any prior net income attributable to our Predecessor as part of Noble. At the Spin-off, Noble contributed to us its entire net parent investment in our Predecessor. Concurrent with the Spin-off and in accordance with the terms of our Separation from Noble, certain assets and liabilities were transferred between us and Noble, which have been recorded as part of the net capital contributed by Noble.

4


Business Strategy
Our principal business objective is to provide long-term value to shareholders. We expect to achieve this objective through the following strategies:
operate in a manner that provides a safe work atmosphere for our employees while protecting the environment and our assets;
leverage strategic relationships with high-quality, long-term customers;
pursue strategic growth opportunities;
strategically sell or scrap non-core assets;
remain financially disciplined and return capital to shareholders as appropriate;
deliver exceptional customer service through a diverse fleet operated by competent and skilled personnel;
opportunistically expand our worldwide fleet capabilities primarily through the acquisition of rigs, some of which could be under construction;
continue to invest in our existing fleet through maintenance, refurbishment and strategic capital upgrades; and
deploy our drilling assets in important oil and gas producing areas throughout the world.
We believe that customers recognize our commitment to safety and that our performance history and reputation for safe, reliable, efficient operations provide us with a competitive advantage. As a key component of our commitment to safety and quality, we continuously train our personnel in operational practices, safety standards and procedures. We believe that safety and operational excellence promote stronger relationships with multiple important stakeholders, including our employees, our customers and the local communities in which we operate, and reduce both downtime and costs.
We are committed to maintaining and leveraging the geographic diversity of our operations and the quality and longevity of our customer relationships. Our fleet operates for leading national, international and independent oil and gas companies in some of the world's most active hydrocarbon producing markets. We believe that our geographic diversity and strong customer relationships will reduce our exposure to market volatility and position us well to identify, react quickly to and benefit from positive market dynamics. Relative to more geographically concentrated, less established contractors, we believe this will benefit us in times of economic uncertainty.
We currently have a large, well-maintained and diversified fleet of drilling rigs, which allows us to provide reliable and effective drilling services to our customers across multiple geographies and water depths. Prior to the Spin-Off, Noble actively invested in our assets and we intend to continue to invest capital to maintain, refurbish and strategically upgrade our assets in order to build on our fleet's strong operational history. We also intend to continue to optimize the quality and performance profile of our fleet by investing in strategic upgrades to increase the longevity and competitive capabilities of our rigs which we believe will lead to increased drilling efficiencies and the ability to continue to meet and exceed the needs of our customers in a cost-effective manner. By investing in our fleet, we believe we can prolong our rigs' useful lives, reduce operational downtime and generate better value for our shareholders. We believe that Noble’s history of consistent investment, and our continued investment in our fleet has allowed us to provide safe, reliable and effective offshore drilling services for our customers and has made our rigs more competitive in the global marketplace.
The offshore drilling industry is a large and highly fragmented industry. Given our global operating footprint and strong balance sheet, we believe we are well positioned to take advantage of acquisition opportunities around the world, as demonstrated in our recent acquisition of Prospector. We intend to continue to pursue acquisitions that add to our fleet's average capability, customer base and geographic diversification. We plan to consider opportunistic, value-adding acquisitions of rigs, concentrating on rigs with contracted backlog.
We intend to maintain a responsible capital structure and appropriate levels of liquidity. We intend to make investment decisions, including refurbishments, maintenance, upgrades and acquisitions, in a disciplined and diligent manner, carefully evaluating these investments based on their ability to maintain or improve our competitive position and strengthen our financial profile. As part of our evaluation, we also look at opportunities to sell rigs that we consider not core to our fleet, as well as scrap assets that will not be profitable in the future.
Demand for our services is a function of the worldwide supply of mobile offshore drilling units. In recent years, there has been a significant expansion of industry supply of both jackups and ultra-deepwater units, the vast majority of which are currently under construction without a contract for future employment. The introduction of non-contracted newbuild rigs into the marketplace will increase the supply of rigs which compete for drilling service contracts, and could negatively impact both the

5


utilization for our rigs and the dayrates we are able to achieve for our fleet. However, the speculative nature of these newbuilds and the current challenging economic and market conditions may provide us with strategic opportunities to continue renewing our fleet. In doing so, we will be able to apply one of Paragon’s competitive strengths, the ability to operate assets and generate additional shareholder value while minimizing risk. Beyond this, our strategy will be to focus on strengthening our balance sheet and preserving liquidity.
We place considerable importance on maintaining a skilled and dedicated workforce and focus on operational excellence to benefit both our customers as well as our employees and their families. Paragon's human resource management systems are designed to integrate health, safety, environmental and quality policies and practices to ensure consistent compliance with our Company's safety standards. Paragon offers competitive compensation, benefits and other rewards to our employees including training and career development, comprehensive medical coverage for our employees and their dependents, and short-term and long-term incentive programs. We believe these programs and benefits are necessary to attract and retain the skilled personnel we need to maintain a safe and efficient operating environment.
Drilling Contracts
We typically employ each drilling unit under an individual contract. Although the final terms of the contracts result from negotiations with our customers, many contracts are awarded based upon a competitive bidding process. Our drilling contracts generally contain the following terms:
contract duration extending over a specific period of time or a period necessary to drill a defined number wells;
provisions permitting early termination of the contract by the customer under certain circumstances, such as (i) if the unit is lost or destroyed or (ii) if operations are suspended for a specified period of time due to breakdown of equipment;
provisions allowing the impacted party to terminate the contract if specified “force majeure” events beyond the contracting parties’ control occur for a defined period of time;
payment of compensation to us (generally in U.S. dollars although some customers, typically national oil companies, require a portion of the compensation to be paid in local currency) on a “daywork” basis, so that we receive a fixed amount for each day (“dayrate”) that the drilling unit is operating under contract (a lower rate or no compensation is payable during periods of equipment breakdown and repair or adverse weather or in the event operations are interrupted by other conditions, some of which may be beyond our control);
payment by us of the operating expenses of the drilling unit, including labor costs and the cost of incidental supplies; and
provisions that allow us to recover certain cost increases from our customers in certain long-term contracts.
The terms of some of our drilling contracts permit early termination of the contract by the customer, without cause, generally exercisable upon advance notice to us and in some cases without requiring an early termination payment to us. Our drilling contracts with Petróleos Mexicanos (“Pemex”) in Mexico, for example, allow early cancellation with 30 days notice to us without Pemex making an early termination payment. For additional information, please read “Our inability to renew or replace existing contracts or the loss of a significant customer or contract could have a material adverse effect on our financial results” included in Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K.
The terms of some of our drilling contracts permit us to earn bonus revenue incentive payments based on performance. Our drilling contracts with Petróleo Brasileiro S.A. (“Petrobras”) in Brazil, for example, contain these bonus provisions.
As our rigs are mobilized from one geographic location to another, labor and other operating and maintenance costs can vary significantly. If we relocate a rig to another geographic location without a customer contract, we will incur costs that will not be reimbursable by future customers, and even if we relocate a rig with a customer contract, we may not be fully compensated during the mobilization period.
For a discussion of our backlog of commitments for contract drilling services, please read, Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contract Drilling Services Backlog.”

6


Offshore Drilling Operations
Contract Drilling Services
We conduct offshore contract drilling operations, which accounted for over 98% of our operating revenues for the years ended December 31, 2014, 2013 and 2012. We conduct our contract drilling operations principally in Mexico, Brazil, the North Sea, West Africa, the Middle East, India, and Southeast Asia. For the years ended December 31, 2014, 2013, and 2012, our five largest customers in the aggregate accounted for approximately 57%, 55%, and 61%, respectively of our operating revenues. Revenues from Petrobras accounted for approximately 23%, 17% and 18% of our total operating revenues in 2014, 2013 and 2012. respectively. Revenues from Pemex accounted for approximately 16%, 19% and 21% of our total operating revenues in 2014, 2013 and 2012, respectively. No other single customer accounted for more than 10% of our total operating revenues in 2014, 2013 or 2012.
Labor Contracts
We provide drilling and maintenance services (but do not provide a rig) on the Hibernia Project in the Canadian Atlantic under a contract with Hibernia Management and Development Company Ltd. that extends through June 30, 2018 and in which Exxon is the primary operator. Under this contract, we provide the personnel necessary to manage and perform the drilling operations from a drilling platform owned by the operator.
Competition
The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and maintenance costs. We compete with other providers of offshore drilling rigs. Some of our competitors have access to greater financial resources than we do.
In the provision of contract drilling services, competition involves numerous factors, including price, rig availability and suitability, experience of the workforce, efficiency, safety performance record, condition and age of equipment, operating integrity, reputation, industry standing and client relations. We believe that we compete favorably with respect to most of these factors and that price is a key determinative factor. We follow a policy of investing capital to maintain, refurbish and strategically upgrade our assets and intend to continue to optimize the quality and performance profile of our fleet by investing in strategic upgrades to increase the longevity and competitive capabilities of our rigs. However, our equipment could be made obsolete by the development of new techniques and equipment, regulations or customer preferences. For additional information, please read “The contract drilling industry is a highly competitive and cyclical business with intense price competition. If we are unable to compete successfully, our profitability may be reduced” included in Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K.
We compete on a worldwide basis, but competition may vary by region at any particular time. Demand for offshore drilling equipment also depends on the exploration and development programs of oil and gas producers, which in turn are influenced by the financial condition of such producers, by general economic conditions, prices of oil and gas and by political considerations and policies.
In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business have historically occurred. We cannot assure that any such shortages experienced in the past will not happen again in the future.
Governmental Regulations and Environmental Matters
Drilling contractors may be affected by the regulations of various host countries in which they are invited to operate in addition to international regulations ratified into existence by the International Maritime Organization (“IMO”). Several of the laws imposed against our industry can directly or indirectly affect the construction and servicing of offshore oil wells as well as the equipment utilized for such operations. Our contract drilling operations are also subject to laws and regulations such as mandating the reduction of greenhouse gas emissions, currency conversions and repatriation, taxation of company earnings and earnings of expatriate personnel, and use of local employees and suppliers.
Several countries, including member states of the Organization of Petroleum Exporting Countries (“OPEC”) actively regulate and control the ownership of oil derived concessions, the companies holding those concessions, and ultimately the exportation of oil and gas. OPEC's recent decision not to cut oil production in the face of declining commodity prices has and may continue to contribute to unstable oil prices and the volatility of the market. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by oil and gas companies and their need for drilling services, and likely will continue to do so.

7


The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment and/or require clean up if contamination has taken place. Many of the countries in whose waters we operate regulate the discharge of fluids associated with the exploration and exploitation of offshore oil wells through operating permits issued by the local authority. Failure to comply with these laws and regulations, or failure to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of clean up requirements, and the imposition of injunctions to force future compliance.
Our Company has made, and will continue to make, expenditures to comply with environmental requirements. We do not believe that our compliance with such requirements will have a material adverse effect on our operations, our competitive position, or materially increase our capital expenditures. Although we have not observed any direct impact on our operations, mandated requirements may indirectly affect our customers’ ability to pursue exploration and production activities, which consequently will introduce a lesser demand on our services and/or increased costs that may be imposed on us or the industry in general.
International Regulatory Regime(s)
The following is a summary of some of the existing laws and regulations that apply to our international operations and also serve as an example of the various laws and regulations to which we are subject. While laws vary widely in each jurisdiction, each of the laws and regulations below addresses environmental issues similar to those in most of the other jurisdictions in which we operate. All of our drilling rigs are in substantial compliance with the applicable regulations specified below.

The IMO provides international regulations governing shipping and international maritime trade. IMO regulations have been widely adopted by U.N. member countries, and in some jurisdictions in which we operate, these regulations have been expanded upon. The requirements contained in the International Management Code for the Safe Operation of Ships and for Pollution Prevention, (the “ISM Code”) promulgated by the IMO, govern much of our drilling operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.
The IMO has adopted the International Convention for the Prevention of Pollution from Ships/Rigs (the “MARPOL Convention”) which is the main international convention covering prevention of pollution of the marine environment from operational or accidental causes. The MARPOL Convention includes regulations aimed at preventing and minimizing pollution, both accidental pollution and that from routine operations, and currently includes six technical annexes, four of which are applicable to our operations. The concept of special areas with strict controls on operational discharges are included in most Annexes. Below is a brief summary of the annexes applicable to our operations:
Annex I - Regulations for the Prevention of Pollution by Oil. Annex I details the discharge criteria and requirements for the prevention of pollution by oil and oily substances. It maintains predominantly the oil discharge criteria prescribed in the 1969 amendments to the 1954 Oil Pollution Convention. In addition to technical guidelines, it contains the concept of special areas which are considered to be vulnerable to pollution by oil. Discharges of oil within these areas has been completely prohibited, with minor well-defined exceptions.
Annex IV - Prevention of Pollution by Sewage. Annex IV contains requirements to control pollution of the sea by sewage; prohibits the discharge of sewage into the sea, except when the ship has in operation an approved sewage treatment plant or when the ship is discharging comminuted and disinfected sewage using an approved system at a distance of more than three nautical miles from the nearest land; and contains requirements to discharge sewage which is not comminuted or disinfected at a distance of more than 12 nautical miles from the nearest land.
Annex V - Prevention of Pollution by Garbage. Annex V deals with different types of garbage and specifies the distances from land and the manner in which they may be disposed. The most important feature of Annex V is the complete ban imposed on the disposal into the sea of all forms of plastics. In July 2011, IMO adopted extensive amendments to Annex V which prohibits the discharge of all garbage into the sea, except as provided otherwise, under specific circumstances.
Annex VI Prevention of Air Pollution. Annex VI sets limits on sulphur oxide (“SOx”) and nitrogen oxide (“NOx”) emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances and designated emission control areas set more stringent standards for SOx, NOx and particulate matter. In 2011, after extensive work and debate, IMO adopted ground breaking mandatory technical and operational energy efficiency measures which will significantly reduce the amount of greenhouse gas emissions from ships.
IMO Ballast water management. In 2004, IMO adopted the International Convention for the Control and Management of Ships’ Ballast Water and Sediments. Ballast water management (the “BWM Convention”) is principally concerned with

8


preventing the spread of non-native aquatic species in lakes, rivers and coastal waters. The BWM Convention will enter into force 12 months after it has been ratified by 30 states representing 35 percent of the world’s merchant shipping tonnage. As of December 31, 2014, the BWM Convention had not been ratified by the requisite number of states required for it to take effect. The BWM Convention will apply to all ships and offshore structures that carry ballast water and are engaged in international voyages. Under the requirements of the BWM Convention for rigs with ballast water capacity of more than 1500 cubic meters that were constructed in 2009 or before, ballast water management exchange or treatment will be accepted until 2016. From 2016 (or not later than the first intermediate or renewal survey after 2016), only ballast water treatment will be accepted by the BWM Convention.
International Convention on Civil Liability for Bunker Oil Pollution Damage (the “Bunker Convention”). The Bunker Convention was adopted to ensure that adequate, prompt, and effective compensation is available to persons who suffer damage caused by spills of oil, when carried as fuel in ships' bunkers. The Bunker Convention applies to damage caused on the territory, including the territorial sea, and in exclusive economic zones of states.
The IMO continues to review and introduce new regulations. It is impossible to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.
United States Regulatory Regime(s)
While the majority of our current fleet is primarily focused internationally, a small portion of our drilling fleet resides within US waters at the present time. The following regulations are applied in conjunction with international regulations but are generally more stringent in nature:
Spills and Releases.  The United States has promulgated its requirements for the duties surrounding spills and releases of oil pollutants within the Code of Federal Regulations, specifically 40CFR110. Any material release that has the potential for causing discoloration or producing a sheen on the receiving water surface is a violation of the Clean Water Act (“CWA”) and is required to be reported to the United States Environmental Protection Agency (“EPA”), United States Coast Guard, and/or the Bureau of Safety and Environmental Enforcement (“BSEE”).
The Oil Pollution Act. The U.S. Oil Pollution Act of 1990 (“OPA”) and similar regulations, including but not limited to the MARPOL Convention, as implemented in the United States through the Act to Prevent Pollution from Ships, impose certain operational requirements on offshore rigs operating in the U.S. and govern liability for leaks, spills and blowouts involving pollutants. The OPA imposes strict liability, and may impose joint and several liability on “responsible parties” for removal costs, natural resource damages, and certain other losses resulting from oil spills into or upon navigable waters of the U.S. and its adjoining shorelines. A “responsible party” includes the owner or operator of an onshore facility, the lessee, or “permit holder,” of the area in which an offshore facility is located, and any person owning, operating, or demise chartering a vessel.
Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA, and we believe that compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.
Waste Handling. The U.S. Resource Conservation and Recovery Act (“RCRA”), and similar state and local laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA regulations specifically exclude from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements as our operations generate minimal quantities of hazardous wastes.
Water Discharges. The U.S. Federal Water Pollution Control Act, also known as the “Clean Water Act,” and similar state laws and regulations impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater. In addition, the U.S. Coast Guard has promulgated requirements which include limits applicable to specific discharge streams, such as deck runoff, bilge water and gray water. We do not anticipate that compliance with these laws will cause a material impact on our operations or financial condition.

9


Air Emissions. The U.S. Federal Clean Air Act (“CAA”) and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits, or incur costs for emissions controls, before operations can commence, and existing facilities may be required to obtain additional permits, or incur capital costs, in order to remain in compliance. Federal and State regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
Safety. The U.S. Occupational Safety and Health Act and other similar laws and regulations govern the protection of the health and safety of employees. The U.S. Occupational Safety and Health Administration hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments or citizens. We believe that we are in substantial compliance with these requirements and with other applicable OSHA requirements.
Safety Regulations
On June 10, 2013, the European Union adopted a new directive, Directive 2013/30/EU, on the safety of offshore oil and gas operations within the exclusive economic zone (which can extend up to 200 nautical miles from a coast) or the continental shelf of any of its member states. The directive establishes minimum requirements for preventing major accidents in offshore oil and gas operations, and aims to limit the consequences of such accidents. All European Union member states will be required to adopt national legislation or regulations by July 19, 2015 to implement the new directive’s requirements, which also include reporting requirements related to major safety and environmental hazards that must be satisfied before drilling can take place, as well as the use of “all suitable measures” to both prevent major accidents and limit the human health and environmental consequences of such a major accident should one occur. We believe that our operations are in substantial compliance with the requirements of the directive (as well as the extensive current health and safety regimes implemented in the member states in which we operate), but future developments could require the company to incur significant costs to comply with its implementation.
Climate Change Regulations
There is increasing public and regulatory attention concerning the issue of climate change and the effect of greenhouse gas (“GHG”). The following is a summary of regulatory developments relevant to our emission of GHG in both the U.S. as well as the European Union.
In December 2009, the EPA determined that current and projected concentrations of six key GHG’s in the atmosphere threaten public health and welfare. The EPA subsequently finalized GHG standards for motor vehicles, the effect of which could be to reduce demand for motor fuels refined from crude oil, and a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The PSD program requires emission limits based on the use of “best available control technology” (“BACT”) for emissions from new and modified major stationary sources, which can sometimes include dynamically positioned drilling rigs. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from specified sources in the United States, including, among other things, certain onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2 equivalent per year. From time to time proposed legislation has been introduced in the U.S. Congress to address GHG emissions on an economy-wide basis. In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, established a binding set of greenhouse gas targets for all countries that had ratified it, including the members of the European Union. Recent international discussions in advance of the United Nations Climate Change Conference in Paris in 2015 are exploring options to supplement the Kyoto Protocol. While it is not possible at this time to predict how new treaties and legislation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. Moreover, incentives to conserve energy or use alternative energy sources could have a negative impact on our business if such incentives reduce the worldwide demand for oil and gas.
Countries in the European Union implement the U.N.’s Kyoto Protocol on GHG emissions through the Emissions Trading System (“ETS”), which they have extended to require reductions beyond the Kyoto Protocol and related agreements. The ETS program establishes a GHG “cap and trade” system for certain industry sectors, including power generation at some offshore facilities. Total GHG from these sectors is capped, and the cap is reduced over time to achieve a 21% GHG reduction from these sectors between 2005 and 2020. More generally, the EU Commission has proposed a roadmap for reducing emissions by 80% by 2050 compared to 1990 levels. Some EU member states have enacted additional and more long-term legally binding targets.

10


For example, the U.K. has committed to reduce greenhouse gas emissions by 80% by 2050. These reduction targets may also be affected by future negotiations under the United Nations Framework Convention on Climate Change and its Kyoto Protocol.
Entities operating under the cap must either reduce their GHG emissions, purchase tradable emissions allowances, or EUAs, from other program participants, or purchase international GHG offset credits generated under the Kyoto Protocol’s Clean Development Mechanisms or Joint Implementation. As the cap declines, prices for emissions allowances or GHG offset credits may rise. However, due to the over-allocation of EUAs by EU member states in earlier phases and the impact of the recession in the EU, there has been a general over-supply of EUAs. The EU has recently approved amending legislation to withhold the auction of EUAs in a process known as “backloading.” EU proposals for wider structural reform of the EU ETS may follow the enactment of the backloading proposal. Both backloading and wider structural reforms are aimed at reviving the EU carbon price.
In addition, the U.K. government, which implements ETS in the U.K. North Sea, has introduced a carbon price floor mechanism to place an incrementally increasing minimum price on carbon. Thus, the cost of compliance with ETS can be expected to increase over time. Additional member state climate change legislation may result in potentially material capital expenditures.
We have determined that combustion of diesel fuel (Scope 1) aboard all of our vessels worldwide is the primary source of our greenhouse gas emissions, including carbon dioxide, methane, and nitrous oxide. The data necessary to report indirect emissions from generation of purchased power (Scope 2) has not been previously collected. However, we will establish the necessary procedures to collect and report Scope 2 data during the 2015 year.
At year end, December 31, 2014, our estimated carbon dioxide equivalent (“CO2e”) gas emissions was 347,062 tonnes, as compared to 357,549 tonnes the year prior, for operating 39 drilling units worldwide. When expressed as an intensity measure of tonnes of C02e gas emissions per dollar of contract drilling revenues, both the 2014 and 2013 intensity measure was 0.0002. Our Scope 1 CO2e gas emissions reporting has been prepared with reference to the requirements set out in the UK Companies Act 2006 and supporting regulations, the Environmental Reporting Guidelines (June 2013) issued by the Department for Environment Food & Rural Affairs, the World Resources Institute and World Business Council for Sustainable Development GHG Protocol Corporate Accounting and Reporting Standard Revised and the International Organization for Standardization (“ISO”) 14064-1, and the “Specification with guidance at the organizational level for quantification and reporting of greenhouse gas emissions and removals (2006).”
Insurance and Indemnification Matters
Our operations are subject to many hazards inherent in the drilling business, including blowouts, fires and collisions or groundings of offshore equipment, and damage or loss from adverse weather and sea conditions. These hazards could cause personal injury or loss of life, loss of revenues, pollution and other environmental damage, damage to or destruction of property and equipment and oil and natural gas producing formations, and could result in claims by employees, customers or third parties.
Our drilling contracts provide for varying levels of indemnification from our customers and in most cases also require us to indemnify our customers for certain losses. Under our drilling contracts, liability with respect to personnel and property is typically assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. In addition, our customers may indemnify us in certain instances for damage to our down-hole equipment and, in some cases, our subsea equipment.
Our customers typically assume responsibility for and indemnify us from loss or liability resulting from pollution or contamination, including third-party damages and clean-up and removal, arising from operations under the contract and originating below the surface of the water. We are generally responsible for pollution originating above the surface of the water and emanating from our drilling units. Additionally, our customers typically indemnify us for liabilities incurred as a result of a blow-out or cratering of the well and underground reservoir loss or damage.
In addition to the contractual indemnities described above, we also carry Protection and Indemnity (“P&I”) insurance, which is a comprehensive general liability insurance program covering liability resulting from offshore operations. Our P&I insurance includes coverage for liability resulting from personal injury or death of third parties and our offshore employees, third party property damage, pollution, spill clean-up and containment and removal of wrecks or debris. Our insurance policy does not exclude losses resulting from our gross negligence or willful misconduct. Our P&I insurance program is renewed in March of each year and currently has a standard deductible of $2 million per occurrence, with maximum liability coverage of $500 million.
Our insurance policies and contractual rights to indemnity may not adequately cover our losses and liabilities in all cases. For additional information, please read “We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all of the risks and hazards we face” included in Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K.

11


The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the time of preparation of this report, and is general in nature. Our insurance program and the terms of our drilling contracts may change in the future. In addition, the indemnification provisions of our drilling contracts may be subject to differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.
Employees
As of December 31, 2014, we had approximately 2,625 employees, excluding approximately 1,500 persons engaged through labor contractors or agencies. Approximately 79% of our employees are located offshore. Of our shorebased employees, approximately 70% are male. Certain of our employees in the U.K., Canada and Brazil are parties to collective bargaining agreements. In various countries, local law requires our participation in work councils. We have not experienced any material work stoppages at any of our facilities due to labor union activities in recent years. We believe our relations with our employees are good.
We place considerable value on the involvement of our employees and maintain a practice of keeping them informed on matters affecting them, as well as on the performance of the Company. Accordingly, we conduct formal and informal meetings with employees, maintain a Company intranet website with matters of interest, issue a quarterly publication of Company activities and other matters of interest, and offer a variety of in-house training.
We are committed to a policy of recruitment and promotion on the basis of aptitude and ability without discrimination of any kind. Management actively pursues both the employment of disabled persons whenever a suitable vacancy arises and the continued employment and retraining of employees who become disabled while employed by the company. Training and development is undertaken for all employees, including disabled persons.
Financial Information About Segments and Geographic Areas
Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operation for the last three fiscal years is presented in, Part II, Item 8, Financial Statements and Supplementary Data, Note 17 — Segment and Related Information. At December 31, 2014, we have 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. Our contract drilling services segment conducts contract drilling operations in Mexico, Brazil, the North Sea, West Africa, the Middle East, India, and Southeast Asia.
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the U.S. Securities Exchange Act of 1934 are available free of charge at our website at http://www.paragonoffshore.com. These filings are also available to the public at the U.S. Securities and Exchange Commission’s (“SEC”) Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC’s website at http://www.sec.gov.
You may also find information related to our corporate governance, board committees and company code of ethics (and any amendments or waivers of compliance) at our website. Among the documents you can find there are the following:
Corporate Governance Guidelines;
Audit Committee Charter;
Nominating and Corporate Governance Committee Charter;
Compensation Committee Charter; and
Code of Business Conduct and Ethics.

12


ITEM 1A.    RISK FACTORS
You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K. Each of these risk factors could affect our business, financial condition and results of operations.
Risks Relating to Our Business
Our business depends on the level of activity in the oil and gas industry and the worldwide demand for drilling services significantly declined as a result of the decline in oil prices during the second half of 2014.
Demand for drilling services depends on a variety of economic and political factors and the level of activity in offshore oil and gas exploration and development and production markets worldwide. Commodity prices, and market expectations of potential changes in these prices, may significantly affect this level of activity, as well as dayrates for our services. However, higher prices do not necessarily translate into increased drilling activity because our clients’ expectations of future commodity prices typically drive demand for our rigs. Oil and gas prices and the level of activity in offshore oil and gas exploration and development are extremely volatile and are affected by numerous factors beyond our control, including:
the cost of exploring for, developing, producing and delivering oil and gas;
potential acceleration in the development, and the price and availability, of alternative fuels;
increased supply of oil and gas resulting from growing onshore hydraulic fracturing activity and shale development;
worldwide production and demand for oil and gas, which are impacted by changes in the rate of economic growth in the global economy;
worldwide financial instability or recessions;
regulatory restrictions or any moratorium on offshore drilling;
expectations regarding future oil and gas prices;
the discovery rate of new oil and gas reserves;
the rate of decline of existing and new oil and gas reserves;
available pipeline and other oil and gas transportation capacity;
oil refining capacity;
the ability of oil and gas companies to raise capital;
the level of spending on E&P programs;
advances in exploration, development and production technology;
technical advances affecting energy consumption;
merger and divesture activity among oil and gas producers;
the availability of, and access to, suitable locations from which our customers can produce hydrocarbons;
rough seas and adverse weather conditions, including hurricanes and typhoons;
tax laws, regulations and policies;
laws and regulations related to environmental matters, including those addressing alternative energy sources and the risks of global climate change;
 the political environment of oil-producing regions, including uncertainty or instability resulting from civil disorder, an outbreak or escalation of armed hostilities or acts of war or terrorism;
the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain production levels and pricing;
the level of production in non-OPEC countries; and

13


the laws and regulations of governments regarding exploration and development of their oil and gas reserves or speculation regarding future laws or regulations.
Adverse developments affecting the industry as a result of one or more of these factors, including a decline in oil or gas prices, a global recession, reduced demand for oil and gas products and increased regulation of drilling and production, particularly if several developments were to occur in a short period of time, could have a material adverse effect on our business, financial condition and results of operations.
For instance, oil prices have declined substantially over the last several months as have forward, or “strip” prices. As a result, many of our customers have announced significant reductions to their capital spending budgets. Lower capital spending will increase competitive pressure and could adversely impact both our ability to secure new contracts for our drilling rigs and the dayrates we are paid. As a consequence, we could earn substantially less, experience lower levels of utilization and may be forced to idle, stack, or scrap rigs, which would adversely affect our revenues and profitability. Prolonged periods of low utilization and lower day rates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.
The contract drilling industry is a highly competitive and cyclical business with intense price competition. If we are unable to compete successfully, our profitability may be reduced.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and operating costs and evolving capability of newer rigs. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition, rig availability, location and suitability, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing and client relations are all factors in determining which contractor is awarded a job. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors. Other drilling companies, including those with both high specification and standard specification rigs, may have greater financial, technical and personnel resources that allow them to upgrade equipment and implement new technical capabilities before we can. If current competitors or new market entrants implement new technical capabilities, services or standards that are more attractive to our customers, it could have a material adverse effect on our operations.
In addition to intense competition, our industry is highly cyclical. It has been especially cyclical with respect to the jackup market, where market conditions are subject to rapid change. There have been periods of high demand, short rig supply and high dayrates, followed by periods of lower demand, excess rig supply and low dayrates. Periods of low demand or excess rig supply intensify the competition in the industry and may result in some of our rigs being idle or earning substantially lower dayrates for long periods of time. Additionally, drilling contracts for our jackups generally have shorter terms than contracts for our floaters, meaning that most of our fleet does not have the benefits of the price protection that longer-term contracts provide. The volatility of the industry, coupled with the short-term nature of many of our contracts could have a material adverse effect on our business, financial condition and results of operations.
An over-supply of jackup rigs and floaters may lead to a reduction in dayrates and demand for our rigs and therefore could have a material adverse impact on our profitability.
Our industry recently exited a period of high utilization and high dayrates during which, industry participants increased the supply of drilling rigs by building new drilling rigs, including some drilling rigs that have not yet entered service. Historically, this has often resulted in an oversupply of drilling rigs, which has contributed to a decline in utilization and dayrates, sometimes for extended periods of time. New fixtures for both standard and high specification jackup rigs and floaters have recently come under pressure as a result of a recent reduction in customer spending and the delivery of new rigs.
The increase in supply created by the number and types of rigs being built, as well as changes in our competitors’ drilling rig fleets, could intensify price competition and require higher capital investment to keep our rigs competitive. According to a third-party industry source, as of February 24, 2015, the total non-U.S. jackup fleet comprised 493 units (14 of which were cold stacked and three of which were "out of service"). An additional 126 jackup drilling rigs were under construction or on order, which could bring the total non-U.S. jackup fleet to 602 units (assuming no further newbuilds are ordered and delivered and there is no attrition of the current fleet). In addition, as of February 24, 2015, 79 new floating units were under construction according to a third-party industry source. To the extent that the drilling rigs currently under construction or on order have not been contracted for future work, there may be increased price competition as such vessels become operational, which could lead to a reduction in dayrates. Lower utilization and dayrates would adversely affect our revenues and profitability. Prolonged periods of low utilization or low dayrates could result in the recognition of additional impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

14


Our standard specification rigs are at a relative disadvantage to higher specification rigs.
Our standard specification rigs do not have certain capabilities and technology that can be found on higher specification rigs and that may increase the operating parameters and efficiency of higher specification drilling rigs. If the demand for offshore drilling rigs were to continue to decrease for a prolonged period of time, it is possible that higher specification rigs would begin to compete with standard specification rigs for the same contracts. In that case, higher specification rigs would have an advantage over standard specification rigs in securing those contracts and demand for and utilization of standard specification rigs may decrease. Such a decrease in demand for and utilization of standard specification rigs could have a material adverse effect on our business, financial condition and results of operations.
Many of our competitors have fleets that include high specification rigs and may be more operationally diverse. Some of our customers have expressed a preference for newer rigs and, in some areas, higher specification rigs may be more likely to obtain contracts than standard specification rigs such as ours. Our rigs are further constrained by the water depths in which they are capable of operating. In recent years, an increasing amount of exploration and production expenditures have been concentrated in deepwater drilling programs and deeper formations, requiring higher specification jackup rigs, semisubmersibles or drillships. This trend could result in a decline in demand for standard specification rigs like ours, which could have a material adverse effect on our business, financial condition and results of operations.
The majority of our drilling rigs are more than 30 years old and may require significant amounts of capital for upgrades and refurbishment.
The majority of our drilling rigs were initially put into service during the years 1976 to 1982 and may require significant capital investment to continue operating in the future, particularly as compared to their newer high specification counterparts. From time to time, some of our customers, including Pemex, express a preference for newer rigs. We may be required to spend significant capital on upgrades and refurbishment to maintain the competitiveness of our fleet in the offshore drilling market. Our rigs typically do not generate revenue while they are undergoing refurbishment and upgrades. Rig upgrade or refurbishment projects for older assets such as ours could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total rig value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we will have fewer rigs available for service or our rigs may not be attractive to potential or current customers. Such demands on our capital or reductions in demand for our fleet could have a material adverse effect on our business, financial condition and results of operations.
Our debt instruments could limit our operations and our debt level may limit our flexibility to obtain financing and to pursue business opportunities.
As of December 31, 2014, we had total indebtedness of approximately $2.2 billion. While we have the ability to incur additional debt, subject to limitations in our debt agreements, certain of our debt agreements and revolving credit facility contain covenants requiring us to maintain a maximum funded leverage ratio and minimum interest coverage ratio. In addition, our debt agreements contain various covenants that may in certain instances restrict our ability to, among other things:
incur, assume or guarantee additional indebtedness;
incur liens;
make loans or certain types of investments;
sell or otherwise dispose of assets;
enter into new lines of business; and
merge or consolidate.
Any debt instruments that we enter into in the future may include, among other things, additional or more restrictive limitations that could adversely affect our ability to finance our future operations or capital needs or engage in, expand or pursue our business activities. Our failure to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default under that indebtedness and an event of default under any other indebtedness we may have. A default or event of default may result in the acceleration of the maturity of our indebtedness, which could have a material adverse effect on our available liquidity and adversely affect our business, financial condition and results of operations.
In addition, we must pay approximately $600 million if we take delivery of all three of the newbuild high specification jackup rigs under construction. This would likely require us to arrange a separate financing facility to fund this amount.

15


In addition, our level of debt could have important consequences to us, including the following:
our ability to obtain additional financing, if necessary, for working capital, letters of credit or other forms of guarantees, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
our funds available for operations, future business opportunities and dividends to our shareholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally;
our flexibility in responding to changing business and economic conditions may be limited;
we may be subjected to increased sensitivity to interest rate increases; and
we may be placed at a disadvantage to competitors that have less debt than we have.
Our ability to service and refinance our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, it may be necessary to take actions such as reducing or eliminating dividends as announced in February 2015, reducing or delaying our planned capital expenditures or other business activities, or to seek additional capital or restructure or refinance our indebtedness. Our ability to obtain additional capital and restructure or refinance our debt will depend on the condition of the capital markets and our financial position at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business activities. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, if we breach our covenants under our debt agreements and seek a waiver, we may not be able to obtain a waiver from the required lenders.
Our business involves numerous operating hazards.
Our operations are subject to many hazards inherent in the drilling business, including:
well blowouts;
fires;
collisions or groundings of offshore equipment;
punch-throughs;
mechanical or technological failures;
failure of our employees to comply with our internal environmental, health and safety guidelines;
pipe or cement failures and casing collapses, which could release oil, gas or drilling fluids;
geological formations with abnormal pressures;
spillage handling and disposing of materials; and
adverse weather conditions, including hurricanes, typhoons, winter storms and rough seas.
These hazards could cause personal injury or loss of life, suspend drilling operations, result in regulatory investigation or penalties, seriously damage or destroy property and equipment, result in claims by employees, customers or third parties, cause environmental damage and cause substantial damage to oil and gas producing formations or facilities. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services or personnel shortages. Accordingly, the occurrence of any of the hazards we face could have a material adverse effect on our business, financial condition and results of operations.
Our inability to renew or replace existing contracts or the loss of a significant customer or contract could have a material adverse effect on our financial results.
Our ability to renew our customer contracts or obtain new contracts and the terms of any such contracts will depend on many factors beyond our control, including market conditions, the global economy and our customers’ financial condition and

16


drilling programs. Moreover, any concentration of customers increases the risks associated with any possible termination or nonperformance of drilling contracts. For the years ended December 31, 2014, 2013 and 2012, our five largest customers in the aggregate accounted for approximately 57%, 55%, and 61% respectively, of our operating revenues. We expect Pemex and Petrobras, which accounted for approximately 16% and 23% of our operating revenues for the year ended December 31, 2014, respectively, 19% and 17% of our operating revenues for the year ended December 31, 2013, respectively, and 21% and 18% of our operating revenues for the year ended December 31, 2012 to continue to be significant customers in 2015. Our contract drilling backlog as of December 31, 2014 includes $744 million, or approximately 35%, and $160 million, or approximately 7%, attributable to contracts with Petrobras and Pemex, respectively, for operations offshore Brazil and Mexico. Our floaters working for Petrobras are under contracts that expire beginning in 2016. Petrobras has announced a program to construct 29 newbuild floaters, which may reduce or eliminate its need for our rigs. These new drilling units, if built, would compete with, and could displace, our floaters completing contracts and could have a material adverse effect on our utilization rates, particularly in Brazil. Further, some national oil companies have considered regulations limiting the age of rigs in operation. Such reforms, if adopted, could significantly increase our costs or render some of our rigs ineligible for contracts with such companies.
Our customers may generally terminate our term drilling contracts if a drilling rig is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In the case of nonperformance and under certain other conditions, our drilling contracts generally allow our customers to terminate without any payment to us. The terms of some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. Our drilling contracts with our largest customer, Pemex, allow early cancellation with 30 days or less notice to us without any early termination payment. Our second largest customer, Petrobras, has the right to terminate its contracts in the event of downtime that exceeds certain thresholds. The early termination of a contract may result in a rig being idle for an extended period of time and a reduction in our contract backlog and associated revenue, which could have a material adverse effect on our business, financial condition and results of operations.
Many of our contracts, especially those relating to our jackup rigs, are shorter term in nature, and many of our existing contracts will expire in 2015. Due to the recent decline in demand for our services, some of our rigs have completed contracts and remain idle, or have been stacked. When rigs complete a contract without a renewal contract in place, they may be idle or stacked for a prolonged period of time. Any new contracts for such rigs may be at dayrates substantially below existing dayrates or on terms less favorable than existing contract terms, which could have a material adverse effect on our revenues and profitability.
Our customers, which include many national oil companies, often have significant bargaining leverage over us. During periods of depressed market conditions, we may be subject to an increased risk of our customers seeking to renegotiate or repudiate their contracts, including customers seeking to lower dayrates paid under existing contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by restricted credit markets and economic downturns. If our customers cancel or are unable to renew some of their contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, if contracts are disputed or suspended for an extended period of time or if a number of our contracts are renegotiated, it could have a material adverse effect on our business, financial condition and results of operations.
We are exposed to credit risk relating to nonperformance by our customers.
We are exposed to credit risk with respect to our accounts receivable for services provided to our customers. If any of our customers have credit or financial problems, they may be unable to timely pay for services provided by us. Customers may also refuse to pay or delay payment for services provided by us for reasons that are beyond our control, especially during periods of depressed market conditions. Enforcement of contractual remedies against our customers may take many years, and even if ultimately resolved in our favor, may not result in payment for our services. Any such delay in payment or failure to pay for our services could have a material adverse effect on our business, financial position or results of operations.
We are exposed to risks relating to operations in international locations.
We operate in various regions throughout the world that may expose us to political and other uncertainties, including risks of:
seizure, nationalization or expropriation of property or equipment;
monetary policies, government credit rating downgrades and potential defaults, and foreign currency fluctuations and devaluations;
limitations on the ability to repatriate income or capital;

17


complications associated with repairing and replacing equipment in remote locations;
repudiation, nullification, modification or renegotiation of contracts;
limitations on insurance coverage, such as war risk coverage, in certain areas;
import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;
delays in implementing private commercial arrangements as a result of government oversight;
financial or operational difficulties in complying with foreign bureaucratic actions;
changing tax laws, regulations or policies;
other forms of government regulation and economic conditions that are beyond our control and that create operational uncertainty;
governmental corruption;
piracy; and
terrorist acts, war, revolution and civil disturbances.
Further, we operate in certain less-developed countries with legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings. Examples of challenges of operating in these countries include:
potential restrictions presented by local content regulations in countries such as Nigeria or Angola;
ongoing changes in Brazilian laws related to the importation of rigs and equipment that may impose bonding, insurance or duty-payment requirements; and
procedural requirements for temporary import permits, which may be difficult to obtain.
Our ability to mobilize our drilling rigs between locations and the time and costs of such mobilization could be material to our business.
Our ability to mobilize our drilling rigs to more desirable locations may be impacted by governmental regulation and customs practices, the significant costs of moving a drilling rig, weather, political instability, civil unrest, military actions and the technical capability of the drilling rig to relocate and operate in various environments. In addition, as our rigs are mobilized from one geographic location to another, labor and other operating and maintenance costs can vary significantly. If we relocate a rig to another geographic location without a customer contract, we will incur costs that will not be reimbursable by future customers, and even if we relocate a rig with a customer contract, we may not be fully compensated during the mobilization period. These impacts of rig mobilization could have a material adverse effect on our business, results of operations and financial condition.
Operating and maintenance costs of our operating rigs and costs relating to idle rigs may be significant and may not correspond to revenue earned.
Our operating expenses and maintenance costs depend on a variety of factors including crew costs, costs of provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control. Our total operating costs are generally related to the number of drilling rigs in operation and the cost level in each country or region where such drilling rigs are located. Equipment maintenance costs fluctuate depending upon the type of activity that the drilling rig is performing and the age and condition of the equipment. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. While operating revenues may fluctuate as a function of changes in dayrate, costs for operating a rig may not be proportional to the dayrate received and may vary based on a variety of factors, including the scope and length of required rig preparations and the duration of the contractual period over which such expenditures are amortized. Any investments in our rigs may not result in an increased dayrate for or income from such rigs. A disproportionate amount of operating and maintenance costs in comparison to dayrates could have a material adverse effect on our business, financial condition and results of operations.
During idle periods, to reduce our costs, we may decide to “warm stack” a rig, which means the rig is kept fully operational and ready for redeployment, and maintains most of its crew. As a result, our operating expenses during a warm stacking will not

18


be substantially different than those we would incur if the rig remained active. We may also decide to cold stack the rig, which means the rig is neither operational nor ready for deployment, does not maintain a crew and is stored in a harbor, shipyard or a designated offshore area. However, reductions in costs following the decision to cold stack a rig may not be immediate, as a portion of the crew may be required to prepare the rig for such storage. Cold stacked rigs may require significant capital expenditures to return them to operation, making reactivation of such assets more financially demanding.
Any violation of anti-bribery or anti-corruption laws, including the U.S. Foreign Corrupt Practices Act, the United Kingdom Bribery Act, or similar laws and regulations could result in significant expenses, divert management attention, and otherwise have a negative impact on us.
We operate in countries known to have a reputation for corruption. We are subject to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977, or FCPA, the United Kingdom Bribery Act 2010, or U.K. Bribery Act, and similar laws in other countries.
Any violation of the FCPA, the U.K. Bribery Act or other applicable anti-corruption laws 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. Actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.
Changes in, compliance with, or our failure to comply with the certain laws and regulations could adversely impact our operations and could have a material adverse effect on our results of operations.
Our operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:
the importing, exporting, equipping and operation of drilling rigs;
repatriation of foreign earnings;
currency exchange controls;
oil and gas exploration and development;
taxation of company earnings and earnings of expatriate personnel; and
use and compensation of local employees and suppliers by foreign contractors.
Legal and regulatory proceedings relating to the energy industry, and the complex government regulations to which our business is subject, have at times adversely affected our business and may do so in the future. Governmental actions and the market behavior of certain OPEC members may continue to cause oil price volatility. In some areas of the world, this activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.
Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our rigs, our customers, our vendors or our service providers, and future changes in laws and regulations could significantly increase our costs and could have a material adverse effect on our business, financial condition and results of operations. In addition, we may be required to post additional surety bonds to secure performance, tax, customs and other obligations relating to our rigs in jurisdictions where bonding requirements are already in effect and in other jurisdictions where we may operate in the future. These requirements would increase the cost of operating in these countries and may reduce our available liquidity, which could have a material adverse effect on our business, financial condition and results of operations.
 Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups

19


and similar matters, might result in adverse decisions against us. The result of such adverse decisions, either individually, or in the aggregate, could be material and may not be covered fully or at all by insurance.
Shipyard projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our results of operation and financial condition.
We currently have three high specification newbuild projects we acquired with our acquisition of Prospector. In addition, we may make significant repairs, refurbishments and upgrades to our fleet from time to time, particularly given the age of our fleet. Some of these expenditures will be unplanned. In addition, we may decide to construct new rigs or acquire rigs under construction. These projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:
shortages of equipment, materials or skilled labor;
work stoppages and labor disputes;
unscheduled delays in the delivery of ordered materials and equipment;
local customs strikes or related work slowdowns that could delay importation of equipment or materials;
weather interferences;
difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;
design and engineering problems;
inadequate regulatory support infrastructure in the local jurisdiction;
latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;
unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;
unanticipated actual or purported change orders;
client acceptance delays;
disputes with shipyards and suppliers;
delays in, or inability to obtain, access to funding;
shipyard availability, failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and
failure or delay of third-party equipment vendors or service providers.
The failure to complete a rig repair, refurbishment or upgrade on time, or at all, may result in loss of revenues, the imposition of penalties, or delay, renegotiation or cancellation of a drilling contract or the recognition of an asset impairment. Additionally, capital expenditures for rig upgrade, refurbishment, repair and newbuild projects could materially exceed our planned capital expenditures. Moreover, our rigs undergoing upgrade, refurbishment and repair typically do not earn a dayrate during the period they are out of service. If we experience substantial delays and cost overruns in our shipyard projects, it could have a material adverse effect on our business, financial condition and results of operations.
We may have significant financial commitments with respect to three newbuild high specification jackup rigs under construction.
In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China.  These rigs are currently scheduled for delivery in April 2015, September 2015 and March 2016, respectively. Each newbuild is being built pursuant to a contract between one of these subsidiaries and SWS, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary.  These subsidiaries have currently pre-paid to SWS only 1%, 7% and 7%, respectively, of the purchase price for each newbuild pursuant to the contracts with SWS. Upon delivery, these subsidiaries will be required to pay the remaining purchase price in full for the newbuild being delivered, or $201 million, $199 million and $199 million, respectively.
These subsidiaries may not have contracts or financing in place when these newbuilds are completed, and may request that SWS extend the delivery date for one or more of the newbuilds.  These subsidiaries may not be successful in negotiating any

20


such extensions with SWS, and if successful in negotiating such extensions, may have to pay SWS for granting the extension.  Such amounts may include interest, stacking costs or additional prepayments on the newbuilds.
Taking delivery of the newbuilds will require each of these subsidiaries to secure additional capital to finance the remaining purchase price, which they may not be able to obtain at all or on commercially acceptable terms.  Any financing may also be contingent upon securing a drilling contract for such newbuild.  Should one of these subsidiaries ultimately not accept delivery for a newbuild for any reason, they will forfeit any pre-paid portion of the purchase price to SWS, including any amounts paid in connection with any extensions of delivery.  In addition, SWS could pursue a contractual claim against our subsidiary holding the applicable newbuild contract for the remaining purchase price of such newbuild.  While SWS has no contractual recourse to any of our subsidiaries other than these subsidiaries holding the SWS contracts, if a court of competent jurisdiction finds that one or more of our other subsidiaries who are not party to such contracts are liable to SWS, it could have a material adverse effect on our business, financial condition and results of operations.
We can provide no assurance that our current backlog of contract drilling revenue will be ultimately realized.
As of December 31, 2014, our contract backlog was $2.2 billion for contracted future work extending, in some cases, until 2018, with approximately 60% expected to be earned in 2015. Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. In addition, we may not receive some or all of the bonuses that we include in our backlog. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, we generally do not expect to recontract our floaters until late in their contract terms. Our floaters accounted for 40% of our backlog at December 31, 2014. Due to the higher dayrates earned by our floaters, until these rigs are recontracted, our total backlog may decline, which could have a material adverse effect on our business and financial condition. Moreover, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability or unwillingness to fulfill their contractual commitments to us could have a material adverse effect on our business, financial condition and results of operations.
If we are unable to make acquisitions on economically acceptable terms, or at all, our future growth will be limited, and any acquisition we make may not be successful and may have an adverse effect on our results of operations.
Part of our strategy to grow our business is dependent on our ability to make acquisitions that result in an increase in revenues and customer contracts. The consummation and timing of any future acquisitions will depend upon, among other things, the availability of attractive targets in the marketplace, our ability to negotiate acceptable purchase agreements and our ability to obtain financing on acceptable terms, and we can offer no assurance that we will be able to consummate any future acquisition.
Our debt agreements may restrict our ability to make acquisitions involving the payment of cash or the incurrence of indebtedness. If we are unable to make acquisitions, our future growth will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, we may have difficulty integrating its operations, systems, management, personnel and technology with our own, or could assume unidentified or unforeseen liabilities, such that an acquisition may produce less revenue than expected as a result of incorrect assumptions in our evaluation of such acquisitions or unforeseen consequences or other external events beyond our control. If we consummate any future acquisitions, shareholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating any such acquisitions.
Operational interruptions or maintenance or repair work may cause our customers to suspend or reduce payment of dayrates until operation of the respective drilling rig is resumed, which would lead to loss of revenue or termination or renegotiation of the drilling contract.
If our drilling rigs are idle for reasons that are not related to the ability of the rig to operate, our customers pay a waiting or standby rate which is lower than the full operational rate. In addition, if our drilling rigs are taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in our drilling contracts, we will not be entitled to payment of dayrates until the rig is able to work. Several factors could cause operational interruptions, including:
breakdowns of equipment and other unforeseen engineering problems;
work stoppages, including labor strikes;
shortages of material and skilled labor;
delays in repairs by suppliers;
surveys by government and maritime authorities;

21


periodic classification surveys;
inability to obtain permits;
severe weather, strong ocean currents or harsh operating conditions; and
force majeure events.
If the interruption of operations were to exceed a determined period due to an event of force majeure, our customers have the right to pay a rate that is significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject rig. Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract as a result of an interruption of operations as described herein could have a material adverse effect on our business, financial condition and results of operations and our ability to make distributions to our shareholders.
As a result of our significant cash flow needs, we may be required to incur additional indebtedness, and in the event of lost market access, may have to delay or cancel discretionary capital expenditures.
Our currently anticipated cash flow needs, both in the short-term and long-term, may include the following:
committed capital expenditures, including expenditures for newbuild projects currently underway;
normal recurring operating expenses;
discretionary capital expenditures, including various capital upgrades;
servicing and repayment of debt; and
payments of dividends.
In order to fund our capital expenditures, we may need funding beyond the amount available to us from cash generated by our operations, cash on hand and borrowings under our credit facilities. We may raise such additional capital in a number of ways, including accessing capital markets, obtaining additional lines of credit or disposing of assets. However, we can provide no assurance that any of these options will be available to us on terms acceptable to us or at all.
Our ability to obtain financing or to access the capital markets may be limited by our financial condition at the time of any such financing and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and uncertainties that are beyond our control. Worldwide instability in financial markets or another recession could reduce the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide. Even if we are successful in obtaining additional capital through debt financings, incurring additional indebtedness may significantly increase our interest expense and may reduce our flexibility to respond to changing business and economic conditions or to fund working capital needs, because we will require additional funds to service our outstanding indebtedness.
We may delay or cancel discretionary capital expenditures, which could have certain adverse consequences including delaying upgrades or equipment purchases that could make the affected rigs less competitive, adversely affect customer relationships and negatively impact our ability to contract such rigs.
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 material adverse effect on our financial condition.
Income tax returns that we file will be 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 on tax filings, including but not limited to, our operational structure, intercompany pricing policies or the taxable presence of our subsidiaries in certain countries, 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 result in a material adverse effect on our financial condition.
We may record losses or impairment charges related to sold, idle, or scrapped rigs.
Prolonged periods of low utilization or low dayrates, the cold stacking of idle assets, the sale of assets below their then carrying value or the decline in market value of our assets may cause us to experience losses. These events could result in the recognition of additional impairment charges on our fleet, as we have recently recorded on several of our rigs and our FPSO, if

22


future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable or if we sell assets at below their then carrying value.
We may have difficulty obtaining or maintaining insurance in the future and our insurance coverage and contractual indemnity rights may not protect us against all of the risks and hazards we face.
We do not procure insurance coverage for all of the potential risks and hazards we may face. Furthermore, no assurance can be given that we will be able to obtain insurance against all of the risks and hazards we face or that we will be able to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable.
Our insurance carriers may interpret our insurance policies such that they do not cover losses for which we make claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include expatriate activities prohibited by U.S. laws, radiation hazards, certain loss or damage to property onboard our rigs and losses relating to shore-based terrorist acts or strikes. 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. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could have a material adverse effect on our business, financial condition and results of operations.
Although we maintain insurance in the geographic areas in which we operate, pollution, reservoir damage and environmental risks generally are not fully insurable. Furthermore, the damage sustained to offshore oil and gas assets as a result of hurricanes in recent years has negatively impacted the energy insurance market, resulting in more restrictive and expensive coverage for U.S. named windstorm perils. If one or more future significant weather-related events occur in the Gulf of Mexico, or in any other geographic area in which we operate, we may experience increases in insurance costs, additional coverage restrictions or unavailability of certain insurance products.
Under our drilling contracts, liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and our customers assume liability for our respective personnel and property, irrespective of the fault or negligence of the party indemnified. Although our drilling contracts generally provide for indemnification from our customers for certain liabilities, including liabilities resulting from pollution or contamination originating below the surface of the water, enforcement of these contractual rights to indemnity may be limited by public policy and other considerations and, in any event, may not adequately cover our losses from such incidents. There can also be no assurance that those parties with contractual obligations to indemnify us will necessarily be in a financial position to do so.
Our effective tax rate as a standalone business could be substantially higher than our effective tax rate as a wholly-owned subsidiary of Noble.
Prior to the Spin-Off, Noble restructured certain aspects of our business to effect the Separation. This restructuring resulted in significant tax changes for our business and operations following the Spin-Off. These changes include limitations on our ability to offset taxable income with interest expense attributable to borrowings under our senior note indenture and term loan agreement, and ownership of our rigs operating in certain jurisdictions which are in structures subject to higher tax rates than prior to the restructuring. In addition, legislation enacted or expected to be enacted, as well as changes in the interpretation or application of tax legislation, in jurisdictions in which we or our subsidiaries are incorporated or operating could increase our taxes. As a result, our effective tax rate as a standalone entity could be substantially higher than our effective tax rate prior to the Spin-off, which could have a material adverse effect on our business, financial condition and results of operations.
We operate through various subsidiaries in numerous countries throughout the world. Consequently, income taxes have been based on the laws and rates in effect in the countries in which operations are conducted, or in which we and our subsidiaries or our Predecessor and its subsidiaries were considered to have a taxable presence. The change in the effective tax rate from period to period may be attributable to changes in the profitability mix of our operations in various jurisdictions when compared to operations prior to the Spin-off. Because 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 and income before taxes.
Possible changes in tax laws, or the interpretation or application thereof could affect us and our shareholders.
Due to our global presence, we are subject to changes in tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in the United Kingdom, the U.S. and any other jurisdictions in which we or any of our subsidiaries operate or are incorporated. For example, the recently enacted U.K. legislation will restrict deductions on certain intercompany transactions, such as those relating to the bareboat charter agreements used in connection with our U.K. continental shelf operations. Further, the U.K. has recently released a draft of proposed legislation, expected to be effective from April 1, 2015, which levies a 25% tax on profits deemed to have been “diverted” from U.K. taxpayers to low tax jurisdictions.  We are currently evaluating the impact of this legislation.  There is no published guidance from the government, and significant uncertainty

23


exists with respect to the legislation’s impact to our operations.  We are participating in industry meetings with the U.K. government and will continue to monitor developments. Should this legislation be applicable to our operations in the U.K., our financial position, results of operations and cash flows could be materially affected.
In addition, a new 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 new law, the tax is withheld at the source by our customer, who may not agree with our position. Discussions with our customer over the applicability of this new legislation are ongoing.
Tax laws, policies, treaties and regulations are highly complex and subject to interpretation. Our income tax expense is based upon our interpretation of the tax laws, policies, treaties and regulations in effect in various countries at the time that the expense was incurred. If any laws, policies, treaties or regulations change or taxing authorities do not agree with our interpretation of such laws, policies, treaties and regulations, 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.
The manner in which our shareholders are taxed on distributions from, and dispositions of, our shares could be affected by changes in tax laws, policies, treaties or regulations or the interpretation or enforcement thereof in the United Kingdom, the U.S. or other jurisdictions in which our shareholders are resident. Any such changes could result in increased taxes for our shareholders and affect the trading price of our shares.
Our operations are subject to numerous laws and regulations relating to the protection of the environment and of human health and safety, and compliance with these laws and regulations could impose significant costs and liabilities that exceed our current expectations.
Substantial costs, liabilities, delays and other significant issues could arise from environmental, health and safety laws and regulations covering our operations, and we may incur substantial costs and liabilities in maintaining compliance with such laws and regulations. Our operations are subject to extensive international conventions and treaties, and national or federal, state and local laws and regulations, governing health and safety and environmental protection, including with respect to the discharge of materials into the environment and the security of chemical and industrial facilities. These laws govern a wide range of issues, including:
employee safety;
the release of oil, drilling fluids, natural gas or other materials into the environment;
air emissions from our drilling rigs or our facilities;
handling, cleanup and remediation of solid and hazardous wastes at our drilling rigs or our facilities or at locations to which we have sent wastes for disposal;
restrictions on chemicals and other hazardous substances; and
wildlife protection, including regulations that ensure our activities do not jeopardize endangered or threatened animals, fish and plant species, or destroy or modify the critical habitat of such species.
Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits, or the release of oil or other materials into the environment, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of moratoria or injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases, or could affect our relationship with certain consumers.
There is an inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our customers’ hydrocarbon products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint, several or strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with past, present or future spills or releases of natural gas, oil and wastes on, under, or from past, present or future facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our

24


compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or by non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs. In addition, the steps we could be required to take to bring certain facilities into regulatory compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our operations, as well as waste management and air emissions. For instance, governmental agencies could impose additional safety requirements, which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.
Finally, although some of our drilling rigs will be separately owned by our subsidiaries, under certain circumstances a parent company and all of the unit-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.
We are subject to risks associated with climate change and climate change regulation.
There is an ongoing debate about emissions of greenhouse gases, or GHGs, and climate change. Climate change, and the costs that may be associated with its impacts, and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our services, the demand for and consumption of our services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. There have been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional or federal requirements to reduce or mitigate GHG emissions.
The passage or promulgation of any new climate change laws or regulations by the IMO at the international level, or by national or regional legislatures in the jurisdictions in which we operate, including the European Union, could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our services by making our services more or less desirable than services associated with competing sources of energy.
Finally, some scientists have concluded that increasing GHG concentrations in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of hurricanes and other storms, which could have a material adverse effect on our business, financial condition and results of operations.
Failure to attract and retain skilled personnel or an increase in personnel costs could adversely affect our operations.
We require skilled personnel to operate and provide technical services and support for our drilling units. As the demand for drilling services and the size of the worldwide industry fleet increases, shortages of qualified personnel have occurred from time to time. These shortages could result in our loss of qualified personnel to competitors, impair our ability to attract and retain qualified personnel for our new or existing drilling units, impair the timeliness and quality of our work and create upward pressure on personnel costs, any of which could have a material adverse effect on our operations.

25


Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.
The shipment of goods, services and technology across international borders subjects our business to extensive trade laws and regulations. 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. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions, in particular, are targeted against certain countries that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.
The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.
Currently, we do not, nor do we intend to, operate in countries that are subject to significant sanctions and embargoes imposed by the U.S. government or identified by the U.S. government as state sponsors of terrorism, such as Cuba, Iran, Sudan and Syria. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time. Although we believe that we will be in compliance with all applicable sanctions and embargo laws and regulations at the closing of this offering, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have contracts with countries identified by the U.S. government as state sponsors of terrorism. In addition, our reputation and the market for our securities may be adversely affected if we engage in certain other activities, such as entering into drilling contracts with individuals or entities in countries subject to significant U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments.
Our operations present hazards and risks that require significant and continuous oversight, and we depend upon the security and reliability of our technologies, systems and networks in numerous locations where we conduct business.
Our floaters and high specification units utilize certain technologies that may make us vulnerable to cyber-attacks that we may not be able to adequately protect against. These cybersecurity risks could disrupt certain of our operations for an extended period of time and result in the loss of critical data and in higher costs to correct and remedy the effects of such incidents. If our systems for protecting against information technology and cybersecurity risks prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our proprietary information altered, lost or stolen, or our business operations and safety procedures disrupted.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.

26


We are subject to litigation that could have a material adverse effect on us.
We are, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, asbestos and other toxic tort claims, environmental claims or proceedings, employment matters, governmental claims for taxes or duties, and other litigation that arises in the ordinary course of our business. Although we intend to defend these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter, and there can be no assurance as to the ultimate outcome of any litigation. Litigation may have a material adverse effect on us because of potential negative outcomes, costs of attorneys, the allocation of management’s time and attention, and other factors.
We are a holding company, and we are dependent upon cash flow from subsidiaries to meet our obligations.
We currently conduct our operations through both U.S. and foreign subsidiaries, and our operating income and cash flow are generated by our subsidiaries. As a result, cash we obtain from our subsidiaries is the principal source of funds necessary to meet our debt service obligations. Contractual provisions or laws, as well as our subsidiaries’ financial condition and operating requirements, may limit our ability to obtain cash from our subsidiaries that we require to pay our debt service obligations. Applicable tax laws may also subject such payments to us by our subsidiaries to further taxation.
The inability of our subsidiaries to transfer cash to us may mean that, even though we may have sufficient resources on a consolidated basis to meet our obligations, we may not be permitted to make the necessary transfers from subsidiaries to us in order to provide funds for the payment of our obligations.
Public health threats could have a material adverse effect on our operations and our financial results.
Public health threats, such as Ebola, the H1N1 flu virus, Severe Acute Respiratory Syndrome, and other highly communicable diseases, outbreaks of which have already occurred in various parts of the world in which we operate, could adversely impact our operations, the operations of our customers and the global economy, including the worldwide demand for oil and natural gas and the level of demand for our services. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, could have a material adverse impact on our operations and financial results.
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. Threats to our information technology systems associated with cybersecurity risks and cyber- incidents or attacks continue to grow. In addition, breaches to our systems could go unnoticed for some period of time. Risks associated with these threats include disruptions of certain systems on our rigs; other impairments of our ability to conduct our operations; loss of intellectual property, proprietary information or customer data; disruption of our customer’s operations; loss or damage to our customer data delivery systems; and increased costs to prevent, respond to or mitigate cybersecurity events. If such a cyber-incident were to occur, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.
Acts of terrorism, piracy and social unrest could affect the markets for drilling services.
Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy, and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums could increase and coverages may be unavailable in the future.
Our drilling contracts do not generally provide indemnification against loss of capital assets or loss of revenues resulting from acts of terrorism, piracy and social unrest. We have limited insurance for our assets providing coverage for physical damage losses from risks, such as terrorist acts, piracy, civil unrest, expropriation and acts of war, and we do not carry insurance for loss of revenue resulting from such risks. Government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.

27


Although we paid a cash dividend in the past, our Board of Directors has elected to suspend the declaration and payment of dividends, and we may not pay cash dividends in the future.
We pay dividends at the discretion of our Board of Directors. In November 2014, our Board of Directors declared a regular quarterly dividend of $0.125 per share, but in February 2015, we announced that we would be suspending the declaration and payment of dividends for the foreseeable future in order to preserve liquidity. If we continue not to pay cash dividends, it could have a negative effect on the market price of our stock.  Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant factors at that time.

Risks Relating to the Spin-Off
Our Separation from Noble may increase the volatility of our results of operations, increase our operating costs and decrease our flexibility to respond to changes in competitive environment.
By separating from Noble, our results of operations and cash flows may be susceptible to greater volatility due to fluctuations in our business levels and other factors that could have a material adverse effect on our operating and financial performance. As part of the Noble group of companies, we historically enjoyed certain benefits of Noble’s operating diversity, purchasing power and opportunities to pursue integrated strategies. In addition, we enjoyed certain benefits from Noble’s financial resources, including substantial borrowing capacity and capital for investment. Following the Distribution, as an independent, publicly-traded company, we no longer participate in cash management and funding arrangements with Noble.
Because Noble’s other operations are no longer available to offset any volatility in our results of operations and cash flows, after the Distribution, volatility in our earnings may be more pronounced than our peers. In addition, investors and securities analysts may not place as great a value on our business as an independent public company as they did when our business was a part of Noble.
Since our Separation from Noble, Noble’s financial and other resources have not been available to us, despite our ongoing need to make capital investments and maintain the competitiveness of our fleet. Our debt ratings may be restrained by the age of our fleet and by our fleet’s older-generation standard capabilities. As a result, our access to the debt markets is more restricted than when we were a part of Noble, and we have a greater cost of capital and our financial covenants are more restrictive than prior to our separation from Noble.
Our historical combined financial statements of our Predecessor are not necessarily indicative of our future financial condition, future results of operations or future cash flows nor do they reflect what our financial condition, results of operations or cash flows would have been as an independent public company during the periods presented prior to July 31, 2014.
The historical combined financial information of our Predecessor that we have included in this annual report does not reflect what our financial condition, results of operations or cash flows would have been as an independent public company during the periods presented and is not necessarily indicative of our future financial condition, future results of operations or future cash flows. This is primarily a result of the following factors:
our Predecessor’s historical combined financial information reflects allocations of expenses for services historically provided by Noble, and those allocations may be significantly lower than the comparable expenses we would have incurred as an independent public company;
our cost of debt and other capitalization may be significantly different from that reflected in our historical combined financial statements;
our Predecessor’s historical combined financial information does not reflect the changes that occurred in our cost structure, management, financing arrangements and business operations as a result of our separation from Noble, including the costs related to being an independent public company;
our Predecessor’s historical combined financial information does not reflect the effects of certain liabilities that were assumed by our Company, and reflects the effects of certain assets and liabilities that were to be retained by Noble; and

28


our Predecessor’s historical combined financial information includes three standard specification drilling rigs retained by Noble as well as one jackup and two cold stacked submersibles that were sold by Noble in July 2013 and January 2014, respectively.
The terms of our Separation from Noble, the related agreements and other transactions with Noble were determined by Noble and thus may be less favorable to us than the terms we could have obtained from an unaffiliated third party.
Prior to the completion of the Distribution, we entered into various agreements to complete the separation of our business from Noble and govern our ongoing relationships, including, among others, a master separation agreement, employee matters agreement, a tax sharing agreement, a transition services agreement relating to services provided to each other on an interim basis and a transition services agreement relating to Noble’s offshore Brazil operations.
Under one of the transition services agreements, Noble provides various interim corporate support services to us and we provide various interim support services to Noble. Under the transition services agreement for Brazil, we provide both rig-based and shore-based support services for Noble’s continuing offshore Brazil operations through the term of the existing rig contracts. The master separation agreement provides for, among other things, our responsibility for liabilities relating to our business and the responsibility of Noble for liabilities unrelated to our business. Among other things, the master separation agreement contains indemnification obligations and ongoing commitments of us and Noble designed to make our company financially responsible for substantially all liabilities that may exist relating to our business activities, whether incurred prior to or after the Separation. Our indemnification of Noble under the circumstances set forth in the master separation agreement could subject us to substantial liabilities.
The corporate opportunity provisions in our master separation agreement could enable Noble to benefit from corporate opportunities that might otherwise be available to us.
The master separation agreement contains provisions related to corporate opportunities that may be of interest to both Noble and us. The master separation agreement provides that if a corporate opportunity is offered to one member of our board of directors, while she is also an officer of Noble, that opportunity will belong to Noble unless expressly offered to that person primarily in her capacity as our director, in which case such opportunity will belong to us.
In addition, the master separation agreement provides that any corporate opportunity that belongs to Noble or to us, as the case may be, may not be pursued by the other, unless and until the party to whom the opportunity belongs determines not to pursue the opportunity and so informs the other party. These provisions create the possibility that a corporate opportunity that may be pertinent to us may be used for the benefit of Noble.
Potential liabilities associated with certain obligations under the tax sharing agreement cannot be precisely quantified at this time.
Under the terms of the tax sharing agreement we entered into in connection with the Spin-Off, we generally are responsible for all taxes attributable to our business, whether accruing before, on or after the date of the Spin-Off. Noble generally is responsible for any taxes arising from the Spin-Off, and certain related transactions, that are imposed on us, Noble or its other subsidiaries, with the exception that we are responsible for any such taxes to the extent resulting from certain actions or failures to act by us that occur after the effective date of the tax sharing agreement. Our liabilities under the tax sharing agreement could have a material adverse effect on us. At this time, we cannot precisely quantify the total amount of liabilities we may have under the tax sharing agreement and there can be no assurances as to their final amounts.
In January 2015, a subsidiary of Noble received an unfavorable ruling from the Mexican Supreme Court on a tax depreciation position claimed in periods prior to the Spin-Off. Although the ruling does not constitute mandatory jurisprudence in Mexico, it does create potential indemnification exposure for us under the tax sharing agreement. Noble is the primary obligor to the Mexican tax authorities and, to our understanding, has yet to decide on a course of action in this matter, which could include an appeal against this ruling. As a result, while we are in discussions with Noble, we are presently unable to determine next steps or a timeline on this matter; nor are we able to determine the extent of our liability. Due to these current uncertainties, we are not able to reasonably estimate a loss at this time.
The tax sharing agreement may limit our ability to engage in certain strategic corporate transactions and equity issuances.
Under the tax sharing agreement, we and our affiliates agree not to take any action, or fail to take any action, after the effective date of the tax sharing agreement, which action or failure to act is inconsistent with the Spin-Off qualifying as tax free under Sections 355 and 368(a)(1)(D) of the Code. In particular, we may determine to continue to operate certain of our business operations for the foreseeable future even if a sale or discontinuance of such business may otherwise have been advantageous. Moreover, in light of the requirements of Section 355(e) of the Code, we might determine to forgo certain transactions, including

29


share repurchases, stock issuances, certain asset dispositions or other strategic transactions for some period of time following the spin-off. In addition, our indemnity obligation under the tax sharing agreement may discourage, delay or prevent a change of control transaction for some period of time following the Spin-Off.
Potential indemnification liabilities to Noble pursuant to the master separation agreement could have a material adverse effect on our company.
The master separation agreement with Noble provides for, among other things, the principal corporate transactions required to effect the Spin-Off, certain conditions to the Spin-Off and provisions governing the relationship between our company and Noble with respect to and resulting from the Spin-Off. Among other things, the master separation agreement provides for indemnification obligations designed to make our company financially responsible for substantially all liabilities that may exist relating to our business activities whenever incurred. Our indemnification of Noble under the circumstances set forth in the master separation agreement could subject us to substantial liabilities.
In connection with our Separation, Noble has agreed to indemnify us for certain liabilities. However, there can be no assurance that the indemnity will be sufficient to insure us against the full amount of such liabilities, or that Noble’s ability to satisfy its indemnification obligation will not be impaired in the future.
Pursuant to the master separation agreement, tax sharing agreement, transition services agreement and transition services agreement relating to Noble’s offshore Brazil operations, Noble has agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities that Noble has agreed to retain, and there can be no assurance that the indemnity from Noble will be sufficient to protect us against the full amount of such liabilities, or that Noble will be able to fully satisfy its indemnification obligations. Moreover, even if we ultimately succeed in recovering from Noble any amounts for which we are held liable, we may be temporarily required to bear these losses. If Noble is unable to satisfy its indemnification obligations, the underlying liabilities could have a material adverse effect on our business, financial condition and results of operations.
Several members of our board and management may have conflicts of interest because of their ownership of Noble ordinary shares.
Following the Spin-Off, certain members of our board and management continue to own Noble ordinary shares because of their prior relationships with Noble. This share ownership could create, or appear to create, potential conflicts of interest when our directors and executive officers are faced with decisions that could have different implications for our company and Noble.
Forward-Looking Statements
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this report are forward-looking statements, including statements regarding contract backlog, fleet status, our financial position, business strategy, taxes, timing or results of acquisitions or dispositions, repayment of debt, borrowings under our credit facilities or other instruments, future capital expenditures, contract commitments, dayrates, contract commencements, extension or renewals, contract tenders, the outcome of any dispute, litigation, audit or investigation, plans and objectives of management for future operations, foreign currency requirements, indemnity and other contract claims, construction and upgrade of rigs, industry conditions, access to financing, impact of competition, governmental regulations and permitting, availability of labor, worldwide economic conditions, taxes and tax rates, indebtedness covenant compliance, dividends and distributable reserves, and timing for compliance with any new regulations. When used in this report, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report on Form 10-K and we undertake no obligation to revise or update any forward-looking statement for any reason, except as required by law. These factors include those described in “Risk Factors” above, or in our other SEC filings, among others. Such risks and uncertainties are beyond our control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. You should consider these risks and uncertainties when you are evaluating us.
ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.

30


ITEM 2.    PROPERTIES
Drilling Fleet
Our drilling fleet is composed of the following types of units: semisubmersibles, drillships and jackups. Each type of drilling rig is described further below. Several factors determine the type of unit most suitable for a particular job, the most significant of which include the water depth and the environment of the intended drilling location, whether the drilling is being done over a platform or other structure, and the intended well depth.
 Semisubmersibles
Semisubmersibles are floating platforms which, by means of a water ballasting system, can be submerged to a predetermined depth so that a substantial portion of the hull is below the water surface during drilling operations in order to improve stability. These units maintain their position over the well through the use of either a fixed mooring system or a computer controlled dynamic positioning system and can drill in many areas where jackups cannot drill. Semisubmersibles normally require water depth of at least 200 feet in order to conduct operations.
Drillships
Our drillships are self-propelled vessels. These units maintain their position over the well through the use of either a fixed mooring system or a computer-controlled dynamic positioning system.
Jackups
Jackups are mobile, self-elevating drilling platforms equipped with legs that can be lowered to the ocean floor until a foundation is established for support. The rig hull includes the drilling rig, jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid materials, helicopter landing deck and other related equipment. All of our jackups are independent leg (i.e., the legs can be raised or lowered independently of each other) and cantilevered. A cantilevered jackup has a feature that permits the drilling platform to be extended out from the hull, allowing it to perform drilling or workover operations over pre-existing platforms or structures. Moving a rig to the drill site involves jacking up its legs until the hull is floating on the surface of the water. The hull is then towed to the drill site by tugs and the legs are jacked down to the ocean floor. The jacking operation continues until the hull is raised out of the water, and drilling operations are conducted with the hull in its raised position.

31


Offshore Fleet Table
The following table sets forth certain information concerning our offshore fleet at February 27, 2015. The table does not include any units owned by operators for which we had labor contracts. We operate and own all of the units included in the table.
Our $650 million term loan facility is secured by all but three of our rigs, excluding Prospector's two rigs, which are subject to a first priority mortgage under Prospector's $270 million senior secured credit facility, which is also guaranteed by Prospector and certain of its subsidiaries.
Name
 
Make
 
Year Built
or Rebuilt(1)
 
Water
Depth
Rating
(feet)
 
Drilling
Depth
Capacity
(feet)
 
Location
 
Status(2)
Semisubmersibles — 2
Paragon MSS2
 
Pentagone 85
 
2004 R
 
4,000

 
25,000

 
Brazil
 
Active
Paragon MSS1 (3)
 
Offshore Co. SCP III Mark 2
 
2000 R
 
1,500

 
25,000

 
U.K.
 
Active
 
 
 
 
 
 
 
 
 
 
 
 
 
Drillships — 4
Paragon MDS1
 
Conversion
 
2012 R
 
1,500

 
25,000

 
India
 
Active
Paragon DPDS2
 
Gusto Engineering Pelican Class
 
2012 R
 
5,600

 
20,000

 
Brazil
 
Active
Paragon DPDS1
 
Gusto Engineering Pelican Class
 
2009 R
 
5,000

 
25,000

 
GOM
 
Stacked
Paragon DPDS3
 
NAM Nedlloyd-C
 
2013 R
 
7,200

 
25,000

 
Brazil
 
Active
 
 
 
 
 
 
 
 
 
 
 
 
 
Standard Specification, Independent Leg Cantilevered Jackups — 32
Paragon C20051 (3)
 
CFEM T-2005-C
 
2005 R
 
360

 
30,000

 
U.K.
 
Active
Paragon M841
 
MLT Class 84-E.R.C.
 
1997 R
 
390

 
25,000

 
Mexico
 
Active
Paragon C20052 (3)
 
CFEM T-2005-C
 
1982
 
300

 
30,000

 
U.K.
 
Active
Paragon M821
 
MLT Class 82-C
 
2003 R
 
250

 
20,000

 
Mexico
 
Active
Paragon M1161
 
MLT Class 116-C
 
1980
 
300

 
25,000

 
U.A.E.
 
Active
Paragon B152
 
Baker Marine BMC 150
 
2004 R
 
150

 
20,000

 
U.A.E.
 
Active
Paragon M823
 
MLT Class 82-SD-C
 
1999 R
 
250

 
20,000

 
Mexico
 
Active
Paragon L1112
 
Levingston Class 111-C
 
2003 R
 
300

 
25,000

 
India
 
Active
Paragon M825
 
MLT Class 82-SD-C
 
2003 R
 
250

 
20,000

 
Cameroon
 
Active
Paragon M842
 
MLT Class 84-E.R.C.
 
1995 R
 
390

 
25,000

 
Mexico
 
Active
Paragon L1116
 
Levingston Class 111-C
 
1996 R
 
300

 
25,000

 
Mexico
 
Active
Paragon L785
 
F&G L-780 MOD II
 
1995 R
 
300

 
25,000

 
Malaysia
 
Active
Paragon HZ1 (3)
 
NAM Nedlloyd-C
 
1981
 
250

 
25,000

 
Germany
 
Active
Paragon L1111
 
Levingston Class 111-C
 
2004 R
 
300

 
30,000

 
Qatar
 
Active
Paragon L1115
 
Levingston Class 111-C
 
2001 R
 
300

 
25,000

 
Qatar
 
Active
Paragon L784
 
F&G L-780 MOD II
 
2002 R
 
300

 
25,000

 
Qatar
 
Active
Paragon L1113
 
Levingston Class 111-C
 
1995 R
 
300

 
25,000

 
Mexico
 
Active
Paragon B301
 
Baker Marine BMC 300
 
1993 R
 
300

 
25,000

 
Mexico
 
Active
Paragon B391 (3)(4)
 
BMC 300 Harsh Weather Class
 
2001 R
 
390

 
25,000

 
U.K.
 
Active
Paragon L786
 
F&G L-780 MOD II
 
1998 R
 
300

 
25,000

 
India
 
Active
Paragon M531
 
MLT Class 53-E.R.C.
 
1998 R
 
390

 
25,000

 
Mexico
 
Active
Paragon M826
 
MLT Class 82-SD-C
 
1990 R
 
250

 
20,000

 
Cameroon
 
Active
Paragon C461 (3)
 
MSC/CJ-46
 
1982
 
250

 
25,000

 
The Netherlands
 
Active
Paragon L782
 
F&G L-780 MOD II
 
1995 R
 
300

 
25,000

 
Cameroon
 
Active
Paragon C462 (3)
 
MSC/CJ-46
 
1982
 
250

 
25,000

 
The Netherlands
 
Active
Paragon C463 (3)
 
MSC/CJ-46
 
1982
 
250

 
25,000

 
The Netherlands
 
Active
Paragon L781
 
F&G L-780 MOD II
 
1998 R
 
300

 
25,000

 
Mexico
 
Active

32


Name
 
Make
 
Year Built
or Rebuilt(1)
 
Water
Depth
Rating
(feet)
 
Drilling
Depth
Capacity
(feet)
 
Location
 
Status(2)
Paragon M1162
 
MLT Class 116-C
 
2009 R
 
300

 
25,000

 
U.A.E.
 
Active
Paragon L1114
 
Levingston Class 111-C
 
1982
 
300

 
25,000

 
Mexico
 
Active
Paragon M824
 
MLT Class 82-SD-C
 
1982
 
250

 
25,000

 
Mexico
 
Active
Paragon L783
 
F&G L-780 MOD II
 
2003 R
 
300

 
25,000

 
Benin
 
Active
Dhabi II
 
Baker Marine BMC 150 ILC
 
2006 R
 
120

 
20,000

 
U.A.E.
 
Active
 
 
 
 
 
 
 
 
 
 
 
 
 
High Specification, Heavy Duty, Harsh Environment Jackups — 2
Prospector 1 (3)
 
Friede and Goldman JU-2000E
 
2013
 
400

 
35,000

 
U.K.
 
Active
Prospector 5 (3)
 
Friede and Goldman JU-2000E
 
2014
 
400

 
35,000

 
U.K.
 
Active
Footnotes to Drilling Fleet Table
1.
Rigs designated with an “R” were modified, refurbished or otherwise upgraded in the year indicated by capital expenditures in an amount deemed material by management.
2.
Rigs listed as “Active” were either operating under contract or were actively seeking contracts. Rigs listed as "Stacked" are idle without a contract and are not actively marketed in present market conditions.
3.
Harsh environment capability.
4.
Although designed for a water depth rating of 390 feet of water in a non-harsh environment, the rig is currently equipped with legs adequate to drill in approximately 200 feet of water in a harsh environment. We own the additional leg sections required to extend the drilling depth capability to 390 feet of water.
Facilities
Our corporate headquarters is located in Houston, Texas. In addition, we own and lease administrative and marketing offices, and sites used primarily for storage, maintenance and repairs for drilling rigs and equipment in various locations worldwide.
ITEM 3.    LEGAL PROCEEDINGS
We have certain actions, claims and other matters pending as discussed and reported in Note 15 – Commitments and Contingencies to our consolidated and combined financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
As of December 31, 2014, we were also involved in a number of other lawsuits and other matters which have arisen in the ordinary course of business for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated and combined statements of financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of the matters referred to above or of any such other pending or threatened litigation or legal proceedings. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management's current estimates.
ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.

33


PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market for Shares and Related Shareholder Information
Paragon shares are listed and traded on the New York Stock Exchange (“NYSE) under the symbol “PGN”. On February 27, 2015, there were 85,526,352 shares outstanding held by 203 shareholder accounts of record. On November 7, 2014, our Board of Directors declared an interim cash dividend of $0.125 per fully diluted share. The dividend was paid on November 25, 2014 to holders of record on November 17, 2014. In February 2015, we announced that we would be suspending the declaration and payment of dividends for the foreseeable future in order to preserve liquidity.
On February 27, 2015 the closing price of our shares as reported by the NYSE was $2.06 per share. The following table sets forth for the periods indicated the high and low sales prices and dividends or returns of capital declared and paid in U.S. Dollars. Paragon shares began regular-way trading on August 4, 2014.
2014
 
High
 
Low
 
Dividends
Declared and
Paid
Fourth quarter
 
$
6.35

 
$
2.64

 
$
0.125

Third quarter
 
11.78

 
5.92

 

The declaration and payment of dividends require authorization of our Board of Directors provided that such dividends on issued share capital may be paid only out of Paragon Offshore plc’s “distributable reserves” on its statutory balance sheet. Paragon Offshore plc is not permitted to pay dividends out of share capital, which includes share premiums. Our distributable reserves were approximately $300 million at December 31, 2014. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on our board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant factors at that time.

34


Stock Performance Graph
This graph shows the cumulative total shareholder return of our shares for the period commencing August 4, 2014 (the day our common shares began regular-way trading on the NYSE) and ending December 31, 2014. The graph also shows the cumulative total returns for the same period of the S&P Small Cap 600 Index and the Dow Jones U.S. Oil Equipment & Services Index. The graph assumes that $100 was invested in our shares and the two indices on August 4, 2014 and that all dividends or distributions and returns of capital were reinvested on the date of payment.
 
 
INDEXED RETURNS
Company Name / Index
 
8/4/2014
 
8/30/2014
 
9/30/2014
 
10/31/2014
 
11/30/2014
 
12/31/2014
Paragon Offshore
 
$
100.00

 
$
84.73

 
$
55.91

 
$
44.27

 
$
33.89

 
$
25.86

S&P Small Cap 600 Index
 
100.00

 
103.66

 
98.09

 
105.05

 
104.76

 
107.75

Dow Jones U.S. Oil Equipment & Services
 
100.00

 
100.83

 
91.81

 
84.76

 
73.02

 
71.07

Investors are cautioned against drawing any conclusions from the data contained in the graph, as past results are not necessarily indicative of future performance.
The above graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

35


ITEM 6.    SELECTED CONSOLIDATED AND COMBINED FINANCIAL DATA
The following table sets forth selected consolidated and combined financial data of us and our subsidiaries over the five-year period ended December 31, 2014, which information is derived from our audited consolidated and combined financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in our financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.
 
 
Year Ended December 31,
(In thousands, except per share amounts and percentages)
 
2014
 
2013
 
2012
 
2011
 
2010 (1)
Statement of Income Data:
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
1,993,762

 
$
1,893,002

 
$
1,541,857

 
$
1,370,557

 
$
1,667,370

Operating income (loss)
 
(524,677
)
 
453,745

 
176,712

 
136,947

 
536,802

Net income (loss) attributable to Paragon Offshore
 
(646,746
)
 
360,305

 
126,237

 
104,823

 
461,084

 
 
 
 
 
 
 
 
 
 
 
Per Share Data (2):
 
 
 
 
 
 
 
 
 
 
Earnings (loss) per share -
basic and diluted
 
$
(7.63
)
 
$
4.25

 
$
1.49

 
$
1.24

 
$
5.44

Weighted average shares outstanding -
basic and diluted
 
84,753

 
84,753

 
84,753

 
84,753

 
84,753

 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents (3)
 
$
69,274

 
$
36,581

 
$
70,538

 
$
75,767

 
$
76,892

Property and equipment, net
 
2,410,360

 
3,459,684

 
3,551,813

 
3,373,817

 
3,280,820

Total assets
 
3,253,389

 
3,982,799

 
4,118,072

 
3,866,756

 
3,780,121

Long-term debt (4)
 
1,888,439

 
1,561,141

 
339,806

 
975,000

 
40,000

Total debt (4) (5)
 
2,160,605

 
1,561,141

 
339,806

 
975,000

 
40,000

Total Paragon equity
 
491,608

 
2,005,333

 
3,365,232

 
2,441,823

 
3,247,743

 
 
 
 
 
 
 
 
 
 
 
Cash Flows Data:
 
 
 
 
 
 
 
 
 
 
Net cash from operating activities
 
$
696,989

 
$
822,475

 
$
405,484

 
$
466,100

 
$
1,029,552

Net cash from investing activities
 
(453,218
)
 
(317,726
)
 
(540,867
)
 
(493,255
)
 
(1,724,109
)
Net cash from financing activities
 
(223,580
)
 
(538,706
)
 
130,154

 
26,030

 
693,973

 
 
 
 
 
 
 
 
 
 
 
Other Data (6):
 
 
 
 
 
 
 
 
 
 
Working capital
 
$
(9,000
)
 
$
217,450

 
$
253,816

 
$
123,004

 
$
74,008

Average dayrate
 
 
 
 
 
 
 
 
 
 
Jackups
 
$
115,620

 
$
102,974

 
$
88,120

 
$
79,257

 
$
94,832

Floaters
 
290,408

 
261,827

 
236,767

 
233,052

 
230,596

Average utilization (7)
 
 
 
 
 
 
 
 
 
 
Jackups
 
79
%
 
90
%
 
81
%
 
77
%
 
80
%
Floaters
 
76
%
 
66
%
 
62
%
 
61
%
 
87
%
Total capital expenditures (8)
 
$
261,641

 
$
366,361

 
$
532,404

 
$
518,455

 
$
408,726

(1)
Balance sheet data for 2010 is unaudited.

36


(2)
No earnings were allocated to unvested share-based payment awards in our earnings per share calculation for the year ended December 31, 2014 due to our net loss in the current year. Our basis of presentation related to weighted average unvested shares outstanding for all periods prior to the Spin-Off does not include our unvested restricted stock units that were granted to our employees in conjunction with Paragon's 2014 Employee Omnibus Incentive Plan. As a result, we also have no earnings allocated to unvested share-based payment awards in our earnings per share calculation for periods prior to the Spin-Off.
(3)
Consists of cash and cash equivalents as reported on our consolidated and combined balance sheets.
(4)
Predecessor historical Long-term debt and Total debt represents outstanding indebtedness under Noble’s commercial paper program which was repaid with payments from Paragon to Noble in connection with the Spin-Off.
(5)
Consists of long-term debt and current portion of long-term debt.
(6)
Other Data for our Predecessor includes results from two standard specification jackups and one standard specification floater to be retained by Noble and one jackup sold by Noble in July 2013 and two submersibles sold by Noble in January 2014.
(7)
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold-stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet.
(8)
Capital expenditures for 2011-2013 include approximately $0.7 billion for floater-specific major upgrades that we do not expect to incur again for those rigs.

37


ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATION
The following discussion is intended to assist you in understanding our financial position at December 31, 2014 and 2013, and our results of operations for each of the years in the three-year period ended December 31, 2014, and should be read in conjunction with the accompanying consolidated and combined financial statements and related notes in Part II, Item 8 of this Annual Report on Form 10-K.
OVERVIEW
Our 2014 financial and operating results include:
operating revenues totaling $2.0 billion;
net loss of $647 million or a loss of $7.63 per diluted share;
pre-tax impairment charge of $1.1 billion;
net cash from operating activities totaling $697 million; and
the acquisition of Prospector Offshore Drilling S.A.
The Company
We are a global provider of offshore drilling rigs with a fleet that currently includes 34 jackups and six floaters (four drillships and two semisubmersibles). We refer to our semisubmersibles and drillships collectively as “floaters.” Our primary business is to contract our drilling rigs, related equipment and work crews to conduct oil and gas drilling and workover operations for our exploration and production customers on a dayrate basis around the world.
Separation from Noble
On July 17, 2014, Paragon Offshore Limited, an indirect wholly owned subsidiary of Noble incorporated under the laws of England and Wales, re-registered under the Companies Act 2006 as a public limited company under the name of Paragon Offshore plc. Noble transferred to us 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 our issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned.
We have consolidated the historical combined financial results of our Predecessor in our consolidated financial statements for all periods prior to the Spin-Off. Our Predecessor is comprised of the entire standard specification drilling fleet and related operations of Noble. Three of Noble’s standard specification drilling units included in the results of our Predecessor were retained by Noble and three were sold by Noble prior to the Separation. In addition, our Predecessor’s historical combined financial statements may also not be reflective of what our results of operations, effective tax rate, comprehensive income, financial position, equity or cash flows would have been as a standalone public company as a result of the matters discussed below.
Centralized Support Functions
The historical combined financial results of our Predecessor in our consolidated and combined financial statements for all periods prior to the Spin-Off include expense allocations for certain support functions that were provided on a centralized basis within Noble, including, but not limited to, general corporate expenses related to communications, corporate administration, finance, legal, information technology, human resources, compliance, and employee benefits and incentives. These allocated costs are not necessarily indicative of the costs that we would have incurred as a standalone public company. Following the Spin-Off, Noble continues to provide us with some of the services related to these functions on a transitional basis pursuant to a transition services agreement relating to our business.

38


Taxes
Income Taxes
We operate through various subsidiaries in numerous countries throughout the world. Consequently, income taxes have been based on the laws and rates in effect in the countries in which our operations are conducted, and in which we and our subsidiaries or our Predecessor and its subsidiaries were incorporated or considered to have a taxable presence.
The operations of our Predecessor have been included in certain income tax returns of Noble. The income tax provisions and related deferred tax assets and liabilities that have been reflected in our Predecessor’s historical combined financial statements have been computed as if our Predecessor were a separate taxpayer using the separate return method. As a result, actual tax transactions that would not have occurred had our Predecessor been a separate entity have been eliminated in the preparation of these consolidated and combined financial statements. Income taxes of our Predecessor include results of the operations of the standard specification drilling units. In instances where the operations of the standard specification drilling units of our Predecessor were included in the filing of a consolidated or combined return with high specification units, an allocation of income tax expense was made.
Prior to the Spin-Off, Noble restructured certain aspects of our business to effect the Separation. This restructuring resulted in significant tax changes for our business and operations following the Spin-Off. These changes include limitations on our ability to offset taxable income with interest expense attributable to borrowings under our senior indenture and term loan agreement, and ownership of our rigs operating in certain jurisdictions which are in structures subject to higher tax rates than prior to the restructuring. Additionally, certain unfavorable discrete tax items were recorded, including one in connection with legislation enacted by the U.K. government that restricts deductions on certain intercompany transactions, such as those relating to the bareboat charter agreements used in connection with our U.K. continental shelf operations.
Other Contingencies
We have received tax audit claims of approximately $267 million, of which $50 million is subject to indemnity by Noble, primarily in Mexico and Brazil, attributable to our income, customs and other business taxes. In addition, approximately $37 million of tax audit claims attributable to Mexico assessed against Noble may be allocable to us as a result of the Spin-Off. 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. In some cases we will be required to post a surety bond or a letter of credit as collateral. Although we have no surety bonds or letters of credit associated with tax audit claims outstanding as of December 31, 2014, we could be required to post collateral against our Mexico assessments during 2015. This collarteral requirement could be substantial and could have a material adverse effect on our financial condition, results of operation and cash flows.
In addition, Petróleo Brasileiro S.A. (“Petrobras”) has notified us, along with other industry participants, that it is currently challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs for its operations in Brazil during the years 2008 and 2009 totaling $106 million, of which $30 million is subject to indemnity by Noble. Petrobras has also notified us that if required to pay such withholding taxes, they will seek reimbursement from us. We believe that we are contractually indemnified by Petrobras for these amounts and dispute the validity of the assessment. We have notified Petrobras of our position. We will, if necessary, vigorously defend our rights. If we were required to pay such reimbursement, however, the amount of such reimbursement could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. See Note 15, “Commitments and Contingencies” to our consolidated and combined financial statements included in Part II, Item 8 of this Form 10-K.
In January 2015, a subsidiary of Noble received an unfavorable ruling from the Mexican Supreme Court on a tax depreciation position claimed in periods prior to the Spin-Off. Although the ruling does not constitute mandatory jurisprudence in Mexico, it does create potential indemnification exposure for us under the tax sharing agreement. Noble is the primary obligor to the Mexican tax authorities and, to our understanding, has yet to decide on a course of action in this matter, which could include an appeal against this ruling. As a result, while we are in discussions with Noble, we are presently unable to determine next steps or a timeline on this matter; nor are we able to determine the extent of our liability. Due to these current uncertainties, we are not able to reasonably estimate a loss at this time.

39


Compensation and Benefit Plan Matters
During the periods prior to the Spin-Off, most of our employees were eligible to participate in various Noble benefit programs. The results of our Predecessor included in these consolidated and combined financial statements include an allocation of the costs of such employee benefit plans. These costs were allocated based on our employee population for each of the periods presented. We consider the expense allocation methodology and results to be reasonable for all periods presented; however, the allocated costs included in the results of our Predecessor and included in these consolidated and combined financial statements differ from amounts that would have been incurred by us if we operated on a standalone basis and are not necessarily indicative of costs to be incurred in the future.
We have instituted competitive compensation policies and programs, as well as carried over several plans as a standalone public company, the expense for which may differ from the compensation expense allocated by Noble in our Predecessor’s historical combined financial statements.
Public Company Expenses
As a result of the Spin-Off, we became subject to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”) and the Securities and Exchange Commission (the “SEC”) rules and regulations thereunder. We are required to establish and maintain procedures and practices as a standalone public company in order to comply with our obligations under those laws and the related rules and regulations. As a result, we expect to incur additional costs for functions including external and internal audit, investor relations, share administration and regulatory compliance. The amount of these expenses will exceed the amount historically allocated to us from Noble for these types of expenses.
Acquisition of Prospector Offshore Drilling S. A.
On November 17, 2014, Paragon acquired 89.3 million, or 94.4%, of the outstanding shares of Prospector Offshore Drilling S.A. (“Prospector”), an offshore drilling company organized in Luxembourg and traded on the Oslo Axess, from certain shareholders and in open market purchases for approximately $190 million in cash. In December 2014, we purchased an additional 4.1 million shares for approximately $10 million in cash, increasing our ownership to approximately 93.4 million shares, or 98.7%, of the outstanding shares of Prospector. On January 22, 2015, we settled a mandatory tender offer for the additional outstanding shares, increasing our ownership to approximately 99.6% of the outstanding shares of Prospector. On February 23, 2015, we acquired all remaining issued and outstanding shares in Prospector pursuant to the laws of Luxembourg. We spent approximately $202 million to acquire 100% of Prospector and funded the purchase of the shares of Prospector using proceeds from our revolving credit facility and cash on hand.
The Prospector acquisition expanded and enhanced our global fleet by adding two high specification jackups contracted to Total E&P U.K. Limited and Elf Exploration U.K. Limited (“Total S.A.”) for use in the United Kingdom sector of the North Sea. In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China.  These rigs are currently scheduled for delivery in April 2015, September 2015 and March 2016, respectively. Each newbuild is being built pursuant to a contract between one of these subsidiaries and SWS, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary.  Prospector's results of operations are included in our results beginning on November 17, 2014.
MARKET OUTLOOK
The business environment for offshore drillers throughout 2014 was challenging. While the price of Brent crude oil, a key factor in determining customer activity levels, remained generally steady during the first six months of the year at an average price of $109/barrel, there was a significant decline beginning in August. By end of the year, the price had fallen to just above $57/barrel, and in the first quarter 2015 dropped below $47/barrel. In response to this significant decline, many of our customers have announced plans to make significant reductions to their 2015 capital spending budgets. We anticipate that this will have a substantial negative impact on drilling activity relative to previous years.
This challenging environment is evidenced by a decrease in contractual activity, particularly for floating rigs. New contract fixtures for high specification floating units have been reported at dayrates well below where they were twelve months ago. We made a decision in December 2014 to cold stack one of our drillships that had been operating in Brazil and to transfer the backlog from that asset to our moored floating asset, the Paragon MSS2. This decision preserved our

40


backlog, expanded our EBITDA margin, and extended the contract term for the Paragon MSS2 while meeting Petrobras’s desire to reduce its costs
Jackup activity and dayrates were relatively strong through the third quarter, but with the decline in oil price, we have seen a significant decline in contracting activity and reduction in dayrates. In addition, according to a third party source, as of February 24, 2015, there were 126 jackup drilling rigs under construction, on order, or planned for construction. These rigs are currently scheduled for delivery between 2015 and 2017. This combination of new supply and lower activity levels has negatively impacted the contracting environment, intensified price competition, and has led many customers to request that we reduce our dayrates on existing contracts. In some cases, we may choose to reduce dayrates in exchange for concessions from our customers, such as an increase in the term of the contract. However, we may not be able to secure such concessions in all cases. Additionally, the current environment could require us to increase our capital investment to keep our rigs competitive or require us to stack or retire rigs that are no longer marketable.
The short-term outlook for dayrates and utilization for drilling rigs is challenging for both floaters and jackups and could remain so for a number of years. However, we continue to have confidence in the longer-term fundamentals for the industry. Given the announced reductions in upstream exploration and production capital expenditures, the delay or cancellation of some projects, the ongoing rate of natural decline of production, and expectations for future demand growth, combined with greater potential access by our customers to promising offshore regions, such as Mexico, we believe that oil prices will, over time, remain above the break-even prices required to incentivize exploration and development.
Asset Impairments
As discussed above, the offshore drilling industry has been challenging during 2014, especially for the floating rig markets. Our floaters, especially the ones operating in Brazil, do not have the same operational capabilities as the newer rigs which are capable of operating in “ultra-deepwater” (10,000 feet or more). Our competitors have ordered over 79 ultra-deepwater rigs which are expected to be delivered in the next two years, and these rigs will be larger and more efficient than our floaters in Brazil. In addition, our customers’ cost of drilling wells in deeper water have increased dramatically over the past several years. The combination of higher costs and lower oil prices has reduced our customers’ profitability for drilling deepwater wells, and has put downward pressure on dayrates and reduced utilization. Certain deepwater drilling rigs have begun to compete for contracts in waters shallower than their full operational capabilities. Dayrates for recent new contract fixtures for some high specification floating drilling rigs have been lower than those contracts in place recently.
During 2014, we identified indicators of impairment, including lower crude oil prices, a decrease in contractual activities particularly for floating rigs, and resultant projected declines in dayrates and utilization. We concluded that a triggering event occurred requiring us to perform an impairment analysis of our fleet of drilling rigs. We compared the net book value of our drilling rigs to the relative recoverable value, which was determined using an undiscounted cash flow analysis. As a result of this analysis, we determined that the Paragon DPDS1, Paragon DPDS2, and Paragon DPDS3 drilling rigs were impaired. We calculated the fair value of these drilling rigs after considering quotes from rig brokers, a cost approach and an income approach, which utilized significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to estimated dayrate revenue, rig utilization and anticipated costs for the remainder of the rigs’ useful lives. Additionally, we decided to scrap the Paragon FPSO1, Paragon MSS3, Paragon B153 and Paragon DPDS4. We recognized an impairment on these units after we determined the fair values based on quotes from brokers, price indications from potential interested buyers, and estimates of salvage value. Based on the above analysis, our estimates of fair value resulted in the recognition of an impairment loss for the year ended December 31, 2014 of $1.1 billion, of which $130 million was recognized in the fourth quarter of 2014.
Management’s assumptions are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported.

41


Contract Drilling Services Backlog
We maintain a backlog (as defined below) of commitments for contract drilling services. The following table sets forth, as of December 31, 2014, the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:
 
For the Years Ending December 31,
(Dollars in millions)
Total
 
2015
 
2016
 
2017
 
2018
 
 
 
 
 
 
 
 
 
 
Floaters (1)
$
854

 
$
461

 
$
282

 
$
111

 
$

Jackups (2)
1,300

 
837

 
300

 
137

 
26

Total
$
2,154

 
$
1,298

 
$
582

 
$
248

 
$
26

Percent of available days committed (3)
 
 
55
%
 
23
%
 
12
%
 
3
%
(1)
Our drilling contracts with Petrobras provide an opportunity for us to earn performance bonuses based on reaching targets for downtime experienced for our rigs operating offshore Brazil, which we have included in our backlog in an amount equal to 50% of potential performance bonuses for such rigs, or $49 million.
(2)
Pemex has the ability to cancel its drilling contracts on 30 days notice without Pemex making an early termination payment. At December 31, 2014, we had seven rigs contracted to Pemex, and our backlog included approximately $160 million related to such contracts.
(3)
Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period, or committed days, by the product of the total number of our rigs, including cold-stacked rigs, and the number of calendar days in such period. Committed days do not include the days that a rig is stacked or the days that a rig is expected to be out of service for significant overhaul repairs or maintenance. Available days used in calculating percent of available days committed excludes the Paragon M822 which was sold in January 2015 and the Paragon DPDS4, Paragon MSS3, Paragon B153 and Paragon FPSO1 which have been retired from service.
Our contract drilling services backlog typically reflects estimated future revenues attributable to both signed drilling contracts and letters of intent that we expect to realize. A letter of intent is generally subject to customary conditions, including the execution of a definitive drilling contract. It is possible that some customers that have entered into letters of intent will not enter into signed drilling contracts. As of December 31, 2014, our contract drilling services backlog did not include any letters of intent.
We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts.
The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods set forth in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, achievement of bonuses, weather conditions and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. We generally do not expect to re-contract our floaters until late in their contract terms. Our floaters accounted for 40% of our backlog at December 31, 2014. Due to the higher dayrates earned by our floaters, until these rigs are re-contracted, our total backlog is expected to decline.

42


RESULTS OF OPERATIONS
2014 Compared to 2013
We consolidate the historical combined financial results of our Predecessor in our results of operations for all periods prior to the Spin-Off. Historical operations of our Predecessor includes standard specification rigs retained by Noble or sold by Noble prior to the Distribution. All financial information presented after the Spin-Off represents the results of operations of Paragon.
Our results of operations for the year ended December 31, 2014 consist of the consolidated results of Paragon for the five months ended December 31, 2014, and the combined results of our Predecessor for the prior months. Our results of operations for the year ended December 31, 2013 consist entirely of the combined results of our Predecessor.
Net loss for 2014 was $647 million, or a loss of $7.63 per diluted share, on operating revenues of $2.0 billion, compared to net income for 2013 of $360 million, or $4.25 per diluted share, on operating revenues of $1.9 billion.
Rig Utilization, Operating Days and Average Dayrates
Operating results for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days, and dayrates. The following table sets forth the average rig utilization, operating days, and average dayrates for our rig fleet for 2014 and 2013:
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates
(Dollars in thousands)
2014
 
2013
 
2014
 
2013
 
% Change
 
2014
 
2013
 
% Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jackups
79
%
 
90
%
 
10,188

 
12,032

 
(15
)%
 
$
115,622

 
$
102,974

 
12
%
Floaters
76
%
 
66
%
 
2,371

 
2,173

 
9
 %
 
290,408

 
261,827

 
11
%
       Total (3)
78
%
 
82
%
 
12,559

 
14,205

 
(12
)%
 
$
148,620

 
$
127,275

 
17
%
(1)
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold-stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet.
(2)
Information reflects the number of days that our rigs were operating under contract.
(3)
Excludes the Paragon FPSO1.

43


Operating Results
The following table sets forth our operating results for the years ended December 31, 2014 and 2013.
 
 
 
 
 
 
Change
(Dollars in thousands)
 
2014
 
2013
 
$
 
%
 
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
Contract drilling services
 
$
1,866,497

 
$
1,807,952

 
$
58,545

 
3
 %
Labor contract drilling services
 
33,401

 
35,146

 
(1,745
)
 
(5
)%
Reimbursables/Other (1)
 
93,864

 
49,904

 
43,960

 
88
 %
 
 
1,993,762

 
1,893,002

 
100,760

 
5
 %
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
890,694

 
$
914,702

 
$
(24,008
)
 
(3
)%
Labor contract drilling services
 
24,774

 
24,333

 
441

 
2
 %
Reimbursables (1)
 
77,843

 
38,341

 
39,502

 
103
 %
Depreciation and amortization
 
422,235

 
413,305

 
8,930

 
2
 %
General and Administrative
 
62,081

 
64,907

 
(2,826
)
 
(4
)%
Loss on impairment
 
1,059,487

 
43,688

 
1,015,799

 
**

Gain on disposal of assets, net
 

 
(35,646
)
 
35,646

 
**

Gain on contract settlements/extinguishments, net
 

 
(24,373
)
 
24,373

 
**

Gain on repurchase of long-term debt
 
(18,675
)
 

 
(18,675
)
 
**

 
 
2,518,439

 
1,439,257

 
1,079,182

 
75
 %
Operating Income (Loss) (2)
 
$
(524,677
)
 
$
453,745

 
$
(978,422
)
 
(216
)%
**
Not a meaningful percentage.
(1)
We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. See below for additional explanation on the increase in 2014 as compared to 2013.
(2)
The rigs retained and sold by Noble represent revenues of $117 and $182 million for the years ended December 31, 2014 and 2013, respectively. The expenses for these same periods are $72 and $114 million, respectively, not including the $36 million pre-tax gain recorded on the sale of the Noble Lewis Dugger during the third quarter of 2013.
Contract Drilling Services Operating Revenues—Changes in contract drilling services revenues for the current year as compared to the prior year were driven by a 17% increase in average dayrates which increased revenues by $197 million. This increase was partially offset by a 12% decrease in operating days which negatively impacted revenues by $138 million.
The increase in contract drilling services revenues was driven by our floaters, which generated approximately $120 million more revenue in the current year. The increase in revenue from our floaters was partially offset by a $61 million decrease in revenues from our jackups.
The increase in floater revenues of $120 million in the current year was driven by a 11% increase in average dayrates coupled with a 9% increase in operating days which resulted in a $68 million and a $52 million increase in revenues, respectively, from the prior year.
The increase in both average dayrates and operating days for our floaters was impacted by the Paragon DPDS3 operating during all of the current year after undergoing its reliability upgrade project in the shipyard during the prior year. The increase in average dayrates was also driven by increased bonus revenues on the Paragon DPDS1 and the Paragon

44


DPDS2 from improvements in operational performance during the current year while operating in Brazil. The increase in operating days was partially offset by the Noble Driller, which was retained by Noble after the Separation.
The $61 million decrease in jackup revenues in the current year was driven by a 15% decrease in jackup operating days which resulted in a $190 million decrease in revenues. This decline was partially offset by a 12% increase in average dayrates which positively impacted revenues by $129 million from the prior year.
The decrease in jackup operating days was primarily driven by our rigs operating in the Middle East such as the Paragon M1161, the Paragon M822, the Paragon L1111, and the Paragon L786, which were off contract for all, or significant portions of, the current year but experienced full utilization during the prior year. This decrease is coupled with increased shipyard time on jackups in other regions, including the Paragon M825 and the Paragon L782 both in Africa, the Paragon C20051 in the North Sea, and the Paragon L1116 in Mexico. Additionally, the decrease in operating days is partially attributable to the Noble Alan Hay and the Noble David Tinsley, which were retained by Noble after the Separation. The increase in average dayrates resulted from improved market conditions in the shallow water market, particularly for our rigs in the Middle East and North Sea.
Contract Drilling Services Operating Costs and Expenses — Contract drilling services operating costs and expenses remained relatively consistent in the current year as compared to the prior year, as the reduction in contract drilling operating costs and expenses in the current year from the rigs retained by Noble was partially offset by increases from rigs returning to service in late 2013 and early 2014.
Labor Contract Drilling Services Operating Revenues and Costs and Expenses — The decline in revenues associated with our Canadian labor contract drilling services was primarily related to fluctuations in foreign currency exchange rates. Expenses associated with our labor contract drilling services remained relatively constant.
Reimbursables Operating Revenues and Costs and Expenses —The $44 million increase in reimbursable revenues and the related $40 million increase in reimbursable costs in the current year from the prior year were primarily due to transition support services we have provided, on a cost-plus basis, to Noble’s remaining Brazil operations. We will continue to provide both rig-based and shore-based support services to Noble through the term of Noble’s existing rig contracts and pursuant to the transition service agreement for Brazil (See Part II, item 8, Financial Statement and Supplemental Data, Note 15 — Commitments and Contingencies for additional detail).
Depreciation and Amortization — The $9 million increase in depreciation and amortization in the current year was primarily attributable to completion of the Paragon DPDS3 shipyard upgrade. This upgrade was completed and the rig returned to service during the fourth quarter of 2013. The increase is partially offset by lower depreciation on assets subject to the impairment charge taken in the third quarter of 2014.
General and Administrative — General and administrative expenses in the prior year represent costs allocated to our Predecessor based on certain support functions that were provided by Noble on a centralized basis. Costs in the current year include both allocated costs for periods prior to the Spin-Off and actual costs incurred for periods subsequent to the Spin-Off. Costs incurred during the current year were less than the prior year due to differences in staffing levels of our organization relative to Noble’s levels prior to the Distribution.
Loss on Impairment — During 2014, we identified indicators of impairment, including lower crude oil prices, a decrease in contractual activities (particularly) for floating rigs, and resultant projected declines in dayrates and utilization. We concluded that a triggering event occurred requiring us to perform an impairment analysis of our fleet of drilling rigs. As a result of this analysis, we determined that the Paragon DPDS1, Paragon DPDS2 and Paragon DPDS3 drilling rigs were impaired. Additionally, we have decided to scrap the Paragon FPSO1, Paragon MSS3, Paragon B153, and Paragon DPDS4. Based on the above analysis, our estimates of fair value resulted in the recognition of an impairment loss of $1.1 billion for the year ended December 31, 2014.
In the prior year, our Predecessor determined that our floating production storage and offloading unit (“FPSO”), formerly the Noble Seillean, was partially impaired as a result of its annual impairment test and the market outlook for this unit at that time. As a result, our Predecessor recognized a charge of $40 million for the year ended December 31, 2013. Also in 2013, our Predecessor recorded an impairment charge on two cold-stacked submersible rigs. These rigs had been impaired in 2011 due to the declining market outlook for drilling services for that rig type; however, in 2013 an additional

45


impairment change of approximately $3.6 million was recorded as a result of the potential disposition of these assets to an unrelated third party. These submersible rigs were sold by our Predecessor in January 2014.
Gain on disposal of assets, net — Gain on disposal of assets, net, during 2013 was attributable to the sale of the Noble Lewis Dugger to an unrelated third party in Mexico.
Gain on contract settlements/extinguishments, net — During the third quarter of 2013, Noble received $45 million related to the settlement of all claims against the former investors of FDR Holdings, Ltd., which Noble acquired in July 2010, relating to alleged breaches of various representations and warranties contained in the purchase agreement. A portion of the settlement related to standard specification rigs. This portion, totaling $23 million, was pushed down to our Predecessor in 2013, through an allocation, using the acquired rig values of the purchased rigs.
Gain on repurchase of long-term debt — In 2014, we repurchased and canceled an aggregate principal amount of $85 million of our senior notes at an aggregate cost of $67 million including accrued interest. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of issuance costs, of approximately $19 million. All senior note repurchases were made using available cash balances.
Other Expenses
Income tax provision — Our income tax provision decreased $16 million in 2014 compared to 2013 primarily due to tax benefit from impairment losses, partially offset by higher tax expense due to Noble’s restructuring prior to the Spin-Off and certain unfavorable discrete tax items. Prior to the Spin-Off, Noble restructured certain aspects of our business to affect the Separation. This restructuring resulted in significant tax changes for our business and operations following the Spin-Off. These changes include limitations on our ability to offset taxable income with interest expense attributable to borrowings under our senior note indenture and term loan agreement, and ownership of our rigs operating in certain jurisdictions which are in structures subject to higher tax rates than prior to the restructuring. Additionally, certain unfavorable discrete tax items were recorded during the third quarter of 2014, including one in connection with legislation enacted by the U.K. government that restricts deductions on certain intercompany transactions, such as those relating to the bareboat charter agreements used in connection with our U.K. continental shelf operations.
2013 Compared to 2012
We consolidate the historical combined financial results of our Predecessor in our results of operations for all periods prior to the Spin-Off. Historical operations of our Predecessor includes standard specification rigs retained by Noble or sold by Noble prior to the Distribution. All financial information presented after the Spin-Off represents the results of operations of Paragon.
Our results of operations for the years ended December 31, 2013 and 2012 consist entirely of the combined results of our Predecessor.
Predecessor net income for 2013 was $360 million, or $4.25 per diluted share, on operating revenues of $1.9 billion, compared to net income for 2012 of $126 million, or $1.49 per diluted share, on operating revenues of $1.5 billion.

46


Rig Utilization, Operating Days and Average Dayrates
Operating results for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days, and dayrates. The following table sets forth the average rig utilization, operating days, and average dayrates for our rig fleet for 2013 and 2012:
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates
(Dollars in thousands)
2013
 
2012
 
2013
 
2012
 
% Change
 
2013
 
2012
 
% Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jackups
90
%
 
81
%
 
12,032

 
10,985

 
10
%
 
$
102,974

 
$
88,120

 
17
%
Floaters
66
%
 
62
%
 
2,173

 
2,030

 
7
%
 
261,827

 
236,767

 
11
%
       Total
80
%
 
73
%
 
14,205

 
13,015

 
9
%
 
$
127,275

 
$
111,303

 
14
%
(1)
We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold-stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet.
(2)
Information reflects the number of days that our rigs were operating under contract.

Operating Results
The following table sets forth our operating results for the years ended December 31, 2013 and 2012.
 
 
 
 
 
 
Change
(Dollars in thousands)
 
2013
 
2012
 
$
 
%
 
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
Contract drilling services
 
$
1,807,952

 
$
1,448,569

 
$
359,383

 
25
 %
Labor contract drilling services
 
35,146

 
36,591

 
(1,445
)
 
(4
)%
Reimbursables/Other (1)
 
49,904

 
56,697

 
(6,793
)
 
(12
)%
 
 
1,893,002

 
1,541,857

 
351,145

 
23
 %
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
914,702

 
874,805

 
39,897

 
5
 %
Labor contract drilling services
 
24,333

 
22,006

 
2,327

 
11
 %
Reimbursables (1)
 
38,341

 
44,535

 
(6,194
)
 
(14
)%
Depreciation and amortization
 
413,305

 
367,837

 
45,468

 
12
 %
General and Administrative
 
64,907

 
60,831

 
4,076

 
7
 %
Loss on impairment
 
43,688

 

 
43,688

 
**

Gain on disposal of assets, net
 
(35,646
)
 

 
(35,646
)
 
**

Gain on contract settlements/extinguishments, net
 
(24,373
)
 
(4,869
)
 
(19,504
)
 
**

 
 
1,439,257

 
1,365,145

 
74,112

 
5
 %
Operating Income (2)
 
$
453,745

 
$
176,712

 
$
277,033

 
157
 %
**
Not a meaningful percentage.
(1)
We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows.

47


(2)
The rigs retained and sold by Noble represent revenues of $182 and $196 million for the years ended December 31, 2013 and 2012, respectively. The expenses for these same periods are $114 and $154 million, respectively, not including the $36 million pre-tax gain recorded on the sale of the Noble Lewis Dugger during the third quarter of 2013.
Contract Drilling Services Operating Revenues—Changes in contract drilling services revenues for 2013 as compared to 2012 were driven by increases in both operating days and average dayrates. The 14% increase in average dayrates increased revenues by approximately $227 million while the 9% increase in operating days increased revenue by $132 million.
The increase in contract drilling services revenues was due to a $271 million increase in revenues from our jackups and a $88 million increase in revenues from our floaters.
The 17% increase in jackup average dayrates resulted in a $179 million increase in revenues, which was coupled with a 10% increase in operating days, resulting in a $92 million increase in revenues from 2012. The increase in average dayrates resulted from improved market conditions in the global shallow water market. The increase in utilization primarily related to certain jackup rigs in Mexico and the Middle East, which experienced a full period of operations in 2013 after being warm stacked for a portion of 2012.
The increase in floater revenues in 2013 was driven by an 11% increase in average dayrates coupled with a 7% increase in operating days which resulted in a $54 million and $34 million increase in revenues, respectively, from 2012. The Paragon MDS1 (formerly known as the Noble Duchess) and the Paragon DPDS2 (formerly known as the Noble Leo Segerius) had a full period of operations during 2013 after being off contract during 2012. These increases during 2013 were partially offset by a decrease in revenues attributable to the Paragon DPDS3 (formerly known as the Noble Roger Eason), which returned to work during the fourth quarter of 2013 after being in the shipyard for the majority of the year completing a major upgrade.
Contract Drilling Services Operating Costs and Expenses — Contract drilling services operating costs and expenses increased $40 million for 2013 as compared to 2012. The increase from period to period is primarily a function of improvements in utilization for rigs returning to work in 2013. Increases were reflected in most expense categories, with the largest increases in agency fees, primarily in Mexico and the Middle East ($5 million), and charges for rental equipment ($5 million). Additionally, we recognized an increase in cost allocations to us by Noble for shorebase and operations support primarily due to salary increases ($33 million).
Labor Contract Drilling Services Operating Revenues and Costs and Expenses — Both operating revenue and operating costs and expenses remained substantially consistent from period to period. The change in operating costs and expenses primarily related to foreign currency exchange fluctuations during the period coupled with an increase in labor costs during the period.
Depreciation and Amortization — The increase in depreciation and amortization in 2013 from 2012 was primarily attributable to a full period of depreciation after shipyard projects on the Paragon DPDS2, the Paragon MDS1, and the Paragon DPDS1 (formerly known as the Noble Leo Segerius, the Noble Duchess, and the Noble Phoenix, respectively), which were placed in service during the latter part of 2012 coupled with the completion of the Paragon DPDS3 (formerly known as the Noble Roger Eason) major upgrade during during the fourth quarter of 2013.
General and Administrative — General and administrative expenses in 2013 and 2012 represent costs allocated to our Predecessor based on certain support functions that were provided by Noble on a centralized basis.
Loss on Impairment — Loss on impairment during 2013 related to an impairment charge of approximately $40 million on the Paragon FPSO1 (formerly known as the Noble Seillean) recognized during our Predecessor's annual asset impairment test, coupled with an impairment charge on two cold-stacked submersible rigs. These rigs had been impaired in 2011 due to the declining market outlook for drilling services for that rig type; however, in 2013 an additional impairment change of approximately $4 million was recorded as a result of the potential disposition of these assets to an unrelated third party. These submersible rigs were sold by our Predecessor in January 2014.
Gain on disposal of assets, net — Gain on disposal of assets, net, during 2013 was attributable to the sale of the Noble Lewis Dugger to an unrelated third party in Mexico.

48


Gain on contract settlements/extinguishments, net — Gain on contract settlements/extinguishment, net during 2013 was attributable to the settlement of all claims against the former shareholders of FDR Holdings, Limited, which Noble acquired in July 2010, relating to alleged breaches of various representations and warranties contained in the purchase agreement. During 2012, our Predecessor received $5 million from a claims settlement on the Noble David Tinsley, which experienced a “punch-through” while being positioned on location in 2009.
Other Expenses
Income tax provision — Our income tax provision increased $37 million in 2013 primarily as a result of higher pre-tax income, partially offset by a lower effective tax rate. The increase in pre-tax earnings generated a $75 million increase in tax expense while the decrease in the income tax rate during 2013 decreased the income tax provision by $38 million. The decrease in the income tax rate was a result of a change in our geographic revenue mix and favorable discrete events that occurred during 2013.

49


LIQUIDITY AND CAPITAL RESOURCES
Financial Resources and Liquidity Overview
The table below sets forth a summary of our cash flow information for the years ended December 31, 2014, 2013, and 2012. Our cash flows for the year ended December 31, 2014 consist of the consolidated results of Paragon for the five months ended December 31, 2014, and the combined results of our Predecessor for the seven months ended July 31, 2014. Our cash flows for the years ended December 31, 2013 and 2012 consist entirely of the combined results of our Predecessor.
 
 
Year Ended December 31,
(In thousands)
 
2014
 
2013
 
2012
Cash flows provided by (used in):
 
 
 
 
 
 
Operating activities
 
$
696,989

 
$
822,475

 
$
405,484

Investing activities
 
(453,218
)
 
(317,726
)
 
(540,867
)
Financing activities
 
(223,580
)
 
(538,706
)
 
130,154

Changes in cash flows from operating activities from period to period are primarily driven by changes in net income. See discussion of changes in Net Income in “Results of Operations.” Additionally, changes in operating cash flows for 2014 were a result of increases in "Accounts receivable" for timing of payments from customers and changes in "Other current liabilities" for accruals of taxes and interest. Changes in cash flows from investing activities are dependent upon our and our Predecessor’s level of capital expenditures, which varies based on the timing of projects. During 2014, our cash flows from investing activities were also impacted by our purchase of Prospector. For the period prior to the Spin-Off, changes in cash flows from financing activities are based on activity under Noble’s commercial paper program and credit facilities and investments to and from Parent, while changes in cash flows from financing activities for the periods after the Spin-Off are based on activity under our Senior Notes and Term Loan Facility, including the repurchase of Senior Notes.
Our currently anticipated cash flow needs, both in the short-term and long-term, may include the following:
normal recurring operating expenses;
committed capital expenditures;
discretionary capital expenditures, including various capital upgrades;
repayment of outstanding debt;
acquisitions;
dividends; and
share repurchases.
We currently expect to fund these cash flow needs with cash generated by our operations, available cash balances, borrowings under credit facilities, potential issuances of long-term debt, or asset sales.
At December 31, 2014, we had a total contract drilling services backlog of approximately $2.2 billion. Our backlog as of December 31, 2014 reflects a commitment of 55% of available days for 2015 (excluding three of our rigs which have been retired from service, the Paragon FPSO1, and one rig sold in January 2015). For additional information regarding our backlog, see “Contract Drilling Services Backlog.”
Revolving Credit Facility, Senior Notes and Term Loan Facility
In connection with the Separation, we entered into a senior secured revolving credit agreement, a term loan agreement, and a senior note indenture described below that contain customary covenants relating to, among other things, the incurrence of additional indebtedness, dividends and other restricted payments and mergers, consolidations or the sale of substantially all of our assets. In addition, we have obtained surety lines to provide performance bonds for drilling contracts.

50


On June 17, 2014, we entered into a senior secured revolving credit agreement with lenders that provided commitments in the amount of $800 million (the “Revolving Credit Facility”). The Revolving Credit Facility has a term of five years after the funding date. Borrowings under the Revolving Credit Facility bear interest, at our option, at either (i) an adjusted London Interbank Offered Rate (“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%. Under the Revolving Credit Facility, we may also obtain up to $800 million of letters of credit. Issuance of letters of credit under the Revolving Credit Facility would reduce a corresponding amount available for borrowing. As of December 31, 2014, we had $154 million in borrowings outstanding at a weighted-average interest rate of 2.89%. There was an aggregate amount of $12 million of letters of credit issued under the Revolving Credit Facility.
On July 18, 2014, we issued $1.08 billion of senior notes (the “Senior Notes”) and also borrowed $650 million under a term loan facility (the “Term Loan Facility”). The Term Loan Facility is secured by all but three of our rigs. The proceeds from the Term Loan Facility and the Senior Notes were used to repay $1.7 billion of intercompany indebtedness to Noble incurred as partial consideration for the Separation. The Senior Notes consisted of $500 million of 6.75% senior notes and $580 million of 7.25% senior notes, which mature on July 15, 2022 and August 15, 2024, respectively. The Senior Notes were issued without an original issue discount. Borrowings under the Term Loan Facility bear 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 our option. We are required to make quarterly principal payments of $1.6 million and may prepay all or a portion of the term loans at any time. The Term Loan Facility matures in July 2021. The loans under the Term Loan Facility were issued with 0.5% original issue discount.
In connection with the issuance of the aforementioned debt, we and our Predecessor incurred $35 million of issuance costs.
The covenants and events of default under our Revolving Credit Facility, Senior Notes, and Term Loan Facility are substantially similar. The agreements governing these obligations contain covenants that place 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. In addition to these covenants, the Revolving Credit Facility includes a covenant requiring us to maintain a net leverage ratio (defined as total debt, net of cash and cash equivalents, divided by earnings excluding interest, taxes, depreciation and amortization charges) less than 4.00 to 1.00 and a covenant requiring us to maintain a minimum interest coverage ratio (defined as interest expense divided by earnings excluding interest, taxes, depreciation and amortization charges) greater than 3.00 to 1.00. As of December 31, 2014, we were in compliance with the covenants under our Revolving Credit Facility by maintaining a net leverage ratio of 2.0 and an interest coverage ratio of 8.3 (these calculations do not include the corresponding financial information from Prospector, which has been designated as a unrestricted subsidiary for purposes of our debt agreements). The impairment charge taken in the current quarter does not impact our debt covenant calculations because it is a non-cash charge and is excluded from our covenant calculations.
During the year ended December 31, 2014, we repurchased and canceled an aggregate principal amount of $85 million of our Senior Notes at an aggregate cost of $67 million including accrued interest. The repurchases consisted of $42 million aggregate principal amount of our 6.75% senior notes due July 2022 and $43 million aggregate principal amount of our 7.25% senior notes due August 2024. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of issuance costs, of approximately $19 million in “Gain on repurchase of long-term debt.” All Senior Note repurchases were made using available cash balances.
Subsequent to December 31, 2014, we repurchased and canceled an additional aggregate principal amount of $11 million of our Senior Notes at an aggregate cost of $7 million including accrued interest. The repurchases consisted of $1 million aggregate principal amount of our 6.75% senior notes due 2022 and $10 million aggregate principal amount of our 7.25% senior notes due 2024.
Prospector Debt
At the time of our acquisition of Prospector, Prospector had the following outstanding debt instruments: (i) 2019 Second Lien Callable Bond of $100 million (“Prospector Bonds”) and (ii) 2018 Senior Secured Credit Facility of $270 million (“Prospector Senior Credit Facility”).
The Prospector Bonds were originally entered into by a subsidiary of Prospector on May 19, 2014 in the Oslo Alternative Bond Market. The Prospector Bonds had a fixed interest rate of 7.75% per annum, payable semi-annually on

51


December 19 and June 19 each year and maturity of June 19, 2019. The Prospector Bonds were secured by a second priority mortgage on Prospector 1 and Prospector 5 and guaranteed by Prospector S.A. and certain subsidiaries. The Prospector Bonds have a provision that allows the bondholders to put their bonds back to Prospector at a price of 101% of the par value upon a Change of Control event. The put provision was triggered by our acquisition of a controlling interest in Prospector on November 17, 2014. Subsequent to December 31, 2014, the bondholders put $99.6 million par value of their bonds back to Prospector at the put price of 101% of par plus accrued interest. We funded the repayment of the debt using borrowings from our Revolving Credit Facility and available cash. The outstanding Prospector Bonds balance at December 31, 2014 was $101 million.
The Prospector Senior Credit Facility was originally entered into by a subsidiary of Prospector on June 12, 2014 with a group of lenders. The Prospector Senior Credit Facility comprises a $140 million Prospector 5 tranche and a $130 million Prospector 1 tranche which were both fully drawn at the time of acquisition. At December 31, 2014, $140 million and $126 million were outstanding on the Prospector 5 and Prospector 1 tranches, respectively.
The Prospector Senior Credit Facility is secured by a first priority mortgage on Prospector 1 and Prospector 5, and guaranteed by Prospector Offshore Drilling S.A. and certain subsidiaries. The Prospector Senior Credit Facility bears interest at LIBOR plus a margin of 3.5%. Prospector is required to hedge at least 50% of the Prospector Senior Credit Facility against fluctuations in the interest rate. As of December 31, 2014, interest rate swaps fix the interest on approximately $133 million of outstanding borrowings under the Prospector Senior Credit Facility. Under the swaps, Prospector pays a fixed interest rate of 1.512% and receives the three-month LIBOR rate. The Prospector Senior Credit Facility has certain financial covenants with which we are required to comply and test on a twelve month rolling basis commencing six months following the acceptance of Prospector 5 by Total S.A. This acceptance occurred in December 2014.
In addition to quarterly interest payments, the Prospector 1 tranche and the Prospector 5 tranche require quarterly principal repayments which commenced in October 2014 and January 2015, respectively. The remaining balance of the Prospector Senior Credit Facility is due in full in December 2018. The lenders under the Prospector Senior Credit Facility do not have recourse to Paragon for repayment of the loan.
The Prospector Senior Credit Facility also includes a Change of Control provision whereby the lenders can require us to prepay the outstanding principal balance and accrued interest. On February 13, 2015, the lenders under the Prospector Senior Credit Facility temporarily waived this prepayment requirement until March 16, 2015. We are currently in discussions with these lenders to permanently waive this requirement. However, we can provide no assurance that we will reach an agreement with the lenders prior to such date. If we are unable to do so, we will be required to repay in full the remaining principal balance outstanding under the Prospector Senior Credit Facility. We intend to use cash on hand and borrowings under our Revolving Credit Facility.
Liquidity
Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for Noble. After the Distribution, we have been solely responsible for the provision of funds to finance our working capital and other cash requirements. We expect our primary sources of liquidity in the future will be cash generated from operations, our Revolving Credit Facility and any future financing arrangements, if necessary. Our principal uses of liquidity will be to fund our operating expenditures and capital expenditures, including major projects, upgrades and replacements to drilling equipment, to service our outstanding indebtedness, acquisitions and to pay future dividends.
At December 31, 2014, we had $57 million of cash on hand and $634 million of committed financing available under our Revolving Credit Facility, which will expire in 2019. In January 2015, we repurchased $99.6 million par value of the Prospector Bonds at a price of 101% of par. As of March 12, 2015, approximately $0.4 million par value in Prospector Bonds remained outstanding. We are also currently in discussions with lenders to waive the prepayment requirement for the Prospector Senior Credit Facility of $270 million beyond March 16, 2015. In the event these lenders do not waive the prepayment requirement, we will repay in full the remaining principal balance outstanding under the Prospector Senior Credit Facility (approximately $260 million on March 12, 2015) through the use of cash on hand and borrowings under our Revolving Credit Facility.
At December 31, 2014, we have purchase commitments of $400 million and $199 million currently due in 2015 and 2016, respectively, related to three high specification jack up rigs under construction. Each of these rigs is being built

52


pursuant to a contract between a subsidiary of Prospector and the shipyard, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary. We are currently in discussions with the shipyard to extend delivery of these contracts. In the event we are unable to extend delivery, we will lose ownership of each rig individually. At that point, the associated costs currently capitalized (representing down-payments on these rigs) on our balance sheet totaling $32 million for all three rigs will be written off.
Our debt facilities are subject to financial and non-financial covenants. While we believe we will satisfy our covenants, current and foreseeable market conditions may prevent us from maintaining compliance at the December 31, 2015 measurement date. The current low oil price environment is having an impact on contract renewal rates and an extended downturn in our industry could be exacerbated by an oversupply of new rigs in the medium term. However, we believe that there are proactive measures we can take that are within our control to prevent us from breaching these financial and non-financial covenants, such as reducing our operating and capital expenses, and/or designating certain of the Prospector subsidiaries as restricted subsidiaries under our debt agreements, which would allow us to include such subsidiaries’ financial results in these covenant calculations of our debt agreements, or seek waiver on the covenants from our lenders.
Our operating cash flows, including collection of receivables outstanding at December 31, 2014, coupled with financing available under the Revolving Credit Facility will be sufficient to meet our liquidity needs for at least the next 12 months. Our ability to continue to fund our operations will be affected by general economic, competitive and other factors, many of which are outside of our control and becoming more challenging in the current market environment. If our future cash flows from operations and other capital resources are insufficient to fund our liquidity needs, we may be forced to reduce or delay our capital and operational expenditures, sell assets, obtain additional debt or equity financing, or refinance all or a portion of our debt.
Capital Expenditures
Capital expenditures, including capitalized interest, totaled $262 million, $366 million, and $532 million for 2014, 2013, and 2012, respectively. Capital expenditures for the year ended December 31, 2013 included $137 million related to upgrade projects on drillships in Brazil, which our Predecessor completed in 2013. As of December 31, 2014, we had approximately $58 million in capital commitments related to ongoing major projects, upgrades and replacements to drilling equipment. Capital commitments include all open purchase orders issued to vendors to procure capital equipment.
From time to time we consider possible projects that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units. Other factors that could cause actual capital expenditures to materially exceed plan include delays and cost overruns in shipyards (including costs attributable to labor shortages), shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, changes in governmental regulations and requirements and changes in design criteria or specifications during repair or construction.
In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China.  These rigs are currently scheduled for delivery in April 2015, September 2015 and March 2016, respectively. Each newbuild is being built pursuant to a contract between one of these subsidiaries and SWS, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary.  If we decide to take delivery of these rigs we will owe a final installment of approximately $200 million for each rig. If we do not take delivery of one or more of these rigs, we will lose ownership of each rig individually. We are evaluating all of our options, including but not limited to negotiating extensions on the delivery dates, taking delivery, or selling the rigs.
Dividends
On November 7, 2014, our Board of Directors declared an interim dividend payment to shareholders, totaling approximately $11 million (or $0.125 per fully diluted share). We paid the dividend on November 25, 2014 to holders of record on November 17, 2014. In February 2015, we announced that we would be suspending the declaration and payment of dividends for the foreseeable future in order to preserve liquidity.
The declaration and payment of dividends require authorization of our Board of Directors, provided that such dividends on issued share capital may be paid only out of Paragon Offshore plc’s “distributable reserves” on its statutory balance sheet. Paragon Offshore plc is not permitted to pay dividends out of share capital, which includes share premiums. Our distributable reserves were approximately $300 million at December 31, 2014. Any determination to declare a dividend,

53


as well as the amount of any dividend that may be declared, will be based on the board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant factors at that time.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.
COMMITMENTS AND CONTRACTUAL CASH OBLIGATIONS
The following table summarizes our contractual cash obligations and commitments at December 31, 2014:
 
 
 
 
Payments Due by Period
 
 
(In thousands)
 
Total
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Other
Contractual Cash Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Debt obligations (1)
 
$
2,165,248

 
$
272,166

 
$
6,500

 
$
6,500

 
$
6,500

 
$
261,500

 
$
1,612,082

 
$

Interest payments (2)
 
803,943

 
104,813

 
102,353

 
102,109

 
101,866

 
101,622

 
291,180

 

Operating leases (3)
 
38,189

 
14,734

 
10,871

 
4,494

 
2,596

 
2,032

 
3,462

 

Pension plan contributions
 
18,490

 
868

 
993

 
1,168

 
1,390

 
1,618

 
12,453

 

Purchase commitments (4)
 
653,259

 
454,098

 
199,161

 

 

 

 

 

Tax reserves (5)
 
40,196

 

 

 

 

 

 

 
40,196

Total
 
$
3,719,325

 
$
846,679

 
$
319,878

 
$
114,271

 
$
112,352

 
$
366,772

 
$
1,919,177

 
$
40,196

(1)
Paragon debt obligations include a balloon payment at maturity of our Senior Notes; quarterly principal payments and a balloon payment at maturity of our Term Loan Facility; and a balloon payment at maturity of our Revolving Credit Facility based on amount outstanding at December 31, 2014. Subsequent to December 31, 2014, the Prospector bondholders put their bonds back to Prospector at the put price of 101% of par plus accrued interest. We funded the repayment of the debt using borrowings from our Revolving Credit Facility and thus included this amount as a cash commitment payable under the terms of our Revolving Credit Facility. The Prospector Senior Credit Facility also includes a Change of Control provision whereby the lenders can require us to prepay the outstanding principal balance and accrued interest on March 16, 2015. The entire principal payment for the Prospector Senior Credit Facility has been included in 2015 relation to its short-term nature.
(2)
Interest amounts include fixed interest payments on our Senior Notes; interest and commitment fees on our Revolving Credit Facility (assuming interest rate as of December 31, 2014 and the amount outstanding and unused portion of the underlying commitment as of December 31, 2014); and interest payments on our Term Loan (assuming fixed rate as of December 31, 2014). Since we funded the repayment of the Prospector Bonds using borrowings from our Revolving Credit Facility, interest on the outstanding Prospector Bond amount assumes the same interest rate as noted above for our Revolving Credit Facility and considers the amount in the calculation of the unused portion of the underlying commitment as of the date the amount was drawn subsequent to December 31, 2014. Interest on the Prospector Senior Credit Facility, including the related swap interest, has been included through the expiration of the required prepayment date of March 16, 2015.
(3)
We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the leases. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements.
(4)
Purchase commitments consist of obligations outstanding to external vendors primarily related to future capital purchases and includes $400 million in 2015 and $199 million in 2016 related to the three high-specification jackup rigs under construction.
(5)
Tax reserves are included in the “Other” column in the table above due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See Note 9, “Income Taxes” to our consolidated and combined financial statements included in Item 8 of Part II of this Form 10-K.

54


At December 31, 2014, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, tax and other obligations in various jurisdictions. These letters of credit and surety bond obligations are not normally called, as we typically comply with the underlying performance requirement.
The following table summarizes our other commercial commitments at December 31, 2014:
 
 
 
 
Amount of Commitment Expiration Per Period
(In thousands)
 
Total
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
Contractual Cash Obligations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Letters of Credit
 
$
21,356

 
$
9,241

 
$
9,445

 
$

 
$

 
$

 
$
2,670

Surety bonds
 
110,073

 
68,218

 
3,202

 
38,653

 

 

 

Total
 
$
131,429

 
$
77,459

 
$
12,647

 
$
38,653

 
$

 
$

 
$
2,670

CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our consolidated and combined financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. Critical accounting policies and estimates that most significantly impact our consolidated and combined financial statements are described below.
Property and Equipment, at cost
Property and equipment is stated at cost, reduced by provisions to recognize economic impairment in value whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to twenty-five years.
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; however, the costs of the overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Property and equipment, at cost” in our consolidated and combined balance sheets. Such amounts, net of accumulated depreciation, totaled $193 million and $211 million at December 31, 2014 and 2013, respectively. Depreciation expense related to overhauls and asset replacement totaled $85 million, $76 million and $66 million for the years ended December 31, 2014, 2013 and 2012, respectively.
We evaluate the realization of property and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis, we complete an impairment analysis on all of our rigs. An impairment loss on our property and equipment exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset's carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions we may take an impairment loss in the future.
Revenue Recognition
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

55


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.
Deferred revenues from drilling contracts totaled $9 million at December 31, 2014 as compared to $22 million at December 31, 2013. Such amounts are included in either “Other current liabilities” or “Other liabilities” in our consolidated and combined balance sheets, based upon the expected time of recognition of such deferred revenues. Deferred costs associated with deferred revenues from drilling contracts totaled $2 million at December 31, 2014 as compared to $24 million at December 31, 2013. Such amounts are included in either “Prepaid and other current assets” or “Other assets” in our consolidated and combined balance sheets, based upon the expected time of recognition of such deferred costs.
We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.
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 United Kingdom, the U.S., and any other jurisdictions in which we or any of our subsidiaries operate or are incorporated. 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 our interpretation 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.
The operations of our Predecessor have been included in certain income tax returns of Noble. The income tax provisions and related deferred tax assets and liabilities that have been reflected in our Predecessor’s historical combined financial statements have been computed as if our Predecessor were a separate taxpayer using the separate return method. As a result, actual tax transactions that would not have occurred had our Predecessor been a separate entity have been eliminated in the preparation of these consolidated and combined financial statements. Income taxes of our Predecessor include results of the operations of the standard specification drilling units. In instances where the operations of the standard specification drilling units of our Predecessor were included in the filing of a consolidated or combined return with high specification units, an allocation of income taxes was made.
Income taxes are based on the laws and rates in effect in the countries in which operations are conducted or in which we or our subsidiaries are incorporated or considered resident for income tax purposes. 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

56


expectations change regarding the length of time an offshore drilling unit will be used in a given location, we will adjust deferred taxes accordingly.
Certain Significant Estimates and Contingent Liabilities
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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. 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 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 consolidated and combined financial statements included elsewhere in Part II, Item 8 of this Annual Report on Form 10-K.
NEW ACCOUNTING PRONOUNCEMENTS
In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” which amends FASB Accounting Standards Codification (“ASC”) Topic 205, “Presentation of Financial Statements” and ASC Topic 360, “Property, Plant, and Equipment.” This ASU alters the definition of a discontinued operation to cover only asset disposals that are a strategic shift with a major effect on an entity’s operations and finances, and calls for more extensive disclosures about a discontinued operation’s assets, liabilities, income and expenses. The guidance is effective for all disposals, or classifications as held-for-sale, of components of an entity that occur within annual periods, and interim periods within those annual periods, beginning on or after December 15, 2014. We do not expect that our adoption will have a material impact on our financial statements or disclosures in our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, which amends ASC Topic 606, “Revenue from Contracts with Customers.” 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. The amendments in this accounting standard update are effective for interim and annual reporting periods beginning after December 15, 2016. We are evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.
In June 2014, the FASB issued ASU No. 2014-12, which amends ASC Topic 718, “Compensation–Stock Compensation.” The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in the estimate of the grant-date fair value of the award. The guidance is effective for annual periods beginning after December 15, 2015. The guidance can be applied prospectively for all awards granted or modified after the effective date or retrospectively to all awards with performance targets outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. We are evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.
In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements – Going Concern.” This ASU codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. We are evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.
In January 2015, the FASB issued ASU 2015-01, “Income Statement – Extraordinary and Unusual Items.” This ASU simplifies income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. The guidance is effective for interim and annual periods ending after December 15, 2015 and early adoption is permitted. We do not expect that our adoption will have a material impact on our financial statements or disclosures in our financial statements.

57


ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risk is the potential for loss from a change in the value of a financial instrument as a result of fluctuations in interest rates, currency exchange rates or equity prices, as further described below.
Interest Rate Risk
For variable rate debt, interest rate changes generally do not affect the fair market value of such debt, but do impact future earnings and cash flows, assuming other factors are held constant. We are subject to market risk exposure related to changes in interest rates on borrowings under our Revolving Credit Facility, Prospector Senior Credit Facility, and Term Loan Facility.
Interest on borrowings under the Revolving Credit Facility is at an agreed upon applicable margin over adjusted LIBOR, or base rate plus such applicable margin as stated in the agreement. At December 31, 2014, we had $154 million borrowings outstanding under our Revolving Credit Facility. Similarly, interest on borrowings under the Prospector Senior Credit Facility is at an agreed upon percentage point spread over LIBOR. The provisions of our Prospector Senior Credit Facility provide for a variable interest rate cost on our $266 million outstanding principal balance as of December 31, 2014, and we employ an interest rate risk management strategy that utilizes interest rate swaps in order to minimize or eliminate unanticipated fluctuations in earnings and cash flows arising from changes in, and volatility of, interest rates. As a result of these interest rate swaps, only approximately $133 million of our variable borrowings outstanding under our Prospector Senior Credit Facility are subject to changes in interest rates. Thus a 1% change in the interest rate on the floating rate debt would have an immaterial impact on our annual earnings and cash flows.
Interest on borrowings under the Term Loan Facility is at an agreed upon percentage point spread over adjusted LIBOR (subject to a 1% floor), or base rate as stated in the agreement. At December 31, 2014, we had $645 million in borrowings outstanding under our Term Loan Facility, net of unamortized discount. Since we are currently subject to the 1% LIBOR floor, our Term Loan Facility effectively bears interest at a fixed interest rate. The fair value of our Term Loan Facility was approximately $523 million at December 31, 2014. Related interest expense for the year ended December 31, 2014 was $11 million. Holding other variables constant (such as debt levels), a 1% increase in interest rates would increase our annual interest expense by approximately $7 million.
Our Senior Notes and Prospector Bonds bear interest at a fixed interest rate and fair value will fluctuate based on changes in prevailing market interest rates and market perceptions of our credit risk. The fair value of our Senior Notes was approximately $595 million at December 31, 2014, compared to the principal amount of $995 million. The fair value and carrying value of the Prospector Bonds was $101 million at December 31, 2014.
Foreign Currency Risk
Although we are a U.K. company, we define foreign currency as any non-U.S. denominated currency. Our functional currency is primarily the U.S. dollar. However, outside the United States, a portion of our expenses are incurred in local currencies. Therefore, when the U.S. dollar weakens (strengthens) in relation to the currencies of the countries in which we operate, our expenses reported in U.S. dollars will increase (decrease).
We are exposed to risks on future cash flows to the extent that local currency expenses exceed revenues denominated in local currencies that are other than the U.S. dollar. To help manage this potential risk, we may periodically enter into derivative instruments to manage our exposure to fluctuations in foreign currency exchange rates, and we may conduct hedging activities in future periods to mitigate such exposure. These contracts are primarily accounted for as cash flow hedges, with the effective portion of changes in the fair value of the hedge recorded on the consolidated and combined balance sheet in “Accumulated other comprehensive loss” (“AOCL”). Amounts recorded in AOCL are reclassified into earnings in the same period or periods that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of the hedged item is recorded directly to earnings. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
Our North Sea, Mexico and Brazil operations have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we may periodically enter into forward contracts, all of which would have a maturity of less than 12 months and would settle monthly in the operations’ respective local currencies.

58


At December 31, 2014, we had no outstanding derivative contracts. Depending on market conditions, we may elect to utilize short-term forward currency contracts in the future.

59


ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Paragon Offshore plc:
In our opinion, the accompanying consolidated and combined balance sheets and the related consolidated and combined statements of income and comprehensive income, of equity and of cash flows present fairly, in all material respects, the financial position of Paragon Offshore plc and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 12, 2015


60


PARAGON OFFSHORE PLC
CONSOLIDATED AND COMBINED BALANCE SHEETS
(In thousands)
 
 
December 31,
 
December 31,
 
 
2014
 
2013
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
56,772

 
$
36,581

Restricted cash
 
12,502

 

Accounts receivable
 
539,376

 
356,241

Prepaid and other current assets
 
104,644

 
51,182

Total current assets
 
713,294

 
444,004

Property and equipment, at cost
 
4,842,112

 
6,067,066

Accumulated depreciation
 
(2,431,752
)
 
(2,607,382
)
Property and equipment, net
 
2,410,360

 
3,459,684

Other assets
 
129,735

 
79,111

Total assets
 
$
3,253,389

 
$
3,982,799

LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Current maturities of long-term debt
 
$
272,166

 
$

Accounts payable
 
160,874

 
124,442

Accrued payroll and related costs
 
81,416

 
60,738

Taxes payable
 
69,033

 

Interest payable
 
33,658

 
412

Other current liabilities
 
105,147

 
40,962

Total current liabilities
 
722,294

 
226,554

Long-term debt
 
1,888,439

 
1,561,141

Deferred income taxes
 
58,497

 
101,703

Other liabilities
 
89,910

 
88,068

Total liabilities
 
2,759,140

 
1,977,466

Commitments and contingencies
 

 

Equity
 
 
 
 
Ordinary shares, $0.01 par value, 186,457,393 shares authorized;
84,753,393 issued and outstanding at December 31, 2014
 
848

 

Additional paid-in capital
 
1,423,153

 

Retained earnings
 
(895,249
)
 

Net parent investment
 

 
2,005,339

Accumulated other comprehensive loss
 
(37,144
)
 
(6
)
Total shareholders' equity
 
491,608

 
2,005,333

 
 
 
 
 
Non-controlling interest
 
2,641

 

              Total equity
 
494,249

 
2,005,333

              Total liabilities and equity
 
$
3,253,389

 
$
3,982,799

See accompanying notes to the consolidated and combined financial statements.

61


PARAGON OFFSHORE PLC
CONSOLIDATED AND COMBINED STATEMENTS OF INCOME
(In thousands, except per share amounts)
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Operating revenues
 
 
 
 
 
 
Contract drilling services
 
$
1,866,497

 
$
1,807,952

 
$
1,448,569

Reimbursables
 
93,786

 
49,810

 
56,444

Labor contract drilling services
 
33,401

 
35,146

 
36,591

Other
 
78

 
94

 
253

 
 
1,993,762

 
1,893,002

 
1,541,857

Operating costs and expenses
 
 
 
 
 
 
Contract drilling services
 
890,694

 
914,702

 
874,805

Reimbursables
 
77,843

 
38,341

 
44,535

Labor contract drilling services
 
24,774

 
24,333

 
22,006

Depreciation and amortization
 
422,235

 
413,305

 
367,837

General and administrative
 
62,081

 
64,907

 
60,831

Loss on impairment
 
1,059,487

 
43,688

 

Gain on disposal of assets, net
 

 
(35,646
)
 

Gain on contract settlements/extinguishments, net
 

 
(24,373
)
 
(4,869
)
Gain on repurchase of long-term debt
 
(18,675
)
 

 

 
 
2,518,439

 
1,439,257

 
1,365,145

Operating income (loss)
 
(524,677
)
 
453,745

 
176,712

Other income (expense)
 
 
 
 
 
 
Interest expense, net of amount capitalized
 
(56,732
)
 
(5,938
)
 
(3,746
)
Interest income and other, net
 
3,998

 
(1,897
)
 
1,959

Income (loss) before income taxes
 
(577,411
)
 
445,910

 
174,925

Income tax provision
 
(69,394
)
 
(85,605
)
 
(48,688
)
Net income (loss)
 
$
(646,805
)
 
$
360,305

 
$
126,237

Net loss attributable to non-controlling interest
 
59

 

 

Net income (loss) attributable to Paragon Offshore
 
$
(646,746
)
 
$
360,305

 
$
126,237

 
 
 
 
 
 
 
Earnings (loss) per share
 
 
 
 
 
 
Basic and diluted
 
$
(7.63
)
 
$
4.25

 
$
1.49

 
 
 
 
 
 
 
Weighted-average shares outstanding
 
 
 
 
 
 
Basic and diluted
 
84,753


84,753

 
84,753

See accompanying notes to the consolidated and combined financial statements.

62


PARAGON OFFSHORE PLC
CONSOLIDATED AND COMBINED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Net income (loss)
 
$
(646,805
)
 
$
360,305

 
$
126,237

Other comprehensive income (loss), net of tax
 
 
 
 
 
 
Foreign currency translation adjustments
 
(1,481
)
 
179

 
1,743

Foreign currency forward contracts
 
(4,027
)
 

 

Net pension plan gain
 
1,153

 

 

Amortization of deferred pension plan amounts
 
(2,294
)
 

 

Total other comprehensive income (loss), net
 
(6,649
)
 
179

 
1,743

Total comprehensive income (loss)
 
$
(653,454
)
 
$
360,484

 
$
127,980

See accompanying notes to the consolidated and combined financial statements.

63


PARAGON OFFSHORE PLC
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(In thousands)
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Cash flows from operating activities
 
 
 
 
 
 
Net income (loss)
 
$
(646,805
)
 
$
360,305

 
$
126,237

Adjustments to reconcile net income to net cash from operating activities:
 
 
 
 
 
 
Depreciation and amortization
 
422,235

 
413,305

 
367,837

Loss on impairment
 
1,059,487

 
43,688

 

Gain on disposal of assets, net
 

 
(35,646
)
 

Gain on repurchase of Senior Notes
 
(18,675
)
 

 

Deferred income taxes
 
19,475

 
4,869

 
(14,141
)
Share-based compensation
 
19,446

 
21,114

 
18,565

Net change in other assets and liabilities
 
(158,174
)
 
14,840

 
(93,014
)
Net cash from operating activities
 
696,989

 
822,475

 
405,484

Cash flows from investing activities
 
 
 
 
 
 
Capital expenditures
 
(261,641
)
 
(366,361
)
 
(532,404
)
Proceeds from disposal of assets
 
6,570

 
61,000

 

Acquisition of Prospector Offshore Drilling S.A.
 
(176,569
)
 

 

Acquisition of Prospector Offshore Drilling S.A. non-controlling interest
 
(10,306
)
 

 

Change in restricted cash
 
(12,502
)
 

 

Change in accrued capital expenditures
 
1,230

 
(12,365
)
 
(8,463
)
Net cash from investing activities
 
(453,218
)
 
(317,726
)
 
(540,867
)
Cash flows from financing activities
 
 
 
 
 
 
Net change in borrowings on Predecessor bank credit facilities
 
707,472

 
1,221,332

 
(635,192
)
Net change in borrowings outstanding on Revolving Credit Facility
 
154,000

 

 

Proceeds from issuance of Senior Notes and Term Loan Facility
 
1,710,550

 

 

Repayment of Term Loan Facility
 
(1,625
)
 

 

Purchase of Senior Notes
 
(65,354
)
 

 

Dividends paid
 
(11,075
)
 

 

Debt issuance costs
 
(19,253
)
 
(2,484
)
 
(5,221
)
Net transfers to parent
 
(2,698,295
)
 
(1,757,554
)
 
770,567

Net cash from financing activities
 
(223,580
)
 
(538,706
)
 
130,154

Net change in cash and cash equivalents
 
20,191

 
(33,957
)
 
(5,229
)
Cash and cash equivalents, beginning of period
 
36,581

 
70,538

 
75,767

Cash and cash equivalents, end of period
 
$
56,772

 
$
36,581

 
$
70,538

Supplemental information for non-cash activities
 
 
 
 
 
 
Transfer from parent of property and equipment
 
18,124

 
16,057

 
5,310

Transfer from parent of other assets
 

 

 
987

 
 
$
18,124

 
$
16,057

 
$
6,297

See accompanying notes to the consolidated and combined financial statements.

64


PARAGON OFFSHORE PLC
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY
(In thousands)
 
Ordinary Shares
 
Additional Paid-in Capital
 
Retained Earnings
 
Accumulated Other Comprehensive (Loss)/Gain
 
Net Parent Investment
 
Total Stockholders' Equity and Net Parent Investment
 
Noncontrolling
Interest
 
Total
Equity
 
Shares
 
Amount
 
 
 
 
 
 
 
Balance at December 31, 2011

 
$

 
$

 
$

 
$
(1,928
)
 
$
2,443,751

 
$
2,441,823

 
$

 
$
2,441,823

Net income

 

 

 

 

 
126,237

 
126,237

 

 
126,237

Net transfers to parent

 

 

 

 

 
795,429

 
795,429

 

 
795,429

Foreign currency translation adjustments

 

 

 

 
1,743

 

 
1,743

 

 
1,743

Balance at December 31, 2012

 
$

 
$

 
$

 
$
(185
)
 
$
3,365,417

 
$
3,365,232

 
$

 
$
3,365,232

Net income

 

 

 

 

 
360,305

 
360,305

 

 
360,305

Net transfers to parent

 

 

 

 

 
(1,720,383
)
 
(1,720,383
)
 

 
(1,720,383
)
Foreign currency translation adjustments

 

 

 

 
179

 

 
179

 

 
179

Balance at December 31, 2013

 
$

 
$

 
$

 
$
(6
)
 
$
2,005,339

 
$
2,005,333

 
$

 
$
2,005,333

Net income Predecessor

 

 

 

 

 
237,428

 
237,428

 

 
237,428

Net loss Paragon

 

 

 
(884,174
)
 

 

 
(884,174
)
 
(59
)
 
(884,233
)
Net changes in parent investment

 

 

 

 

 
(855,249
)
 
(855,249
)
 

 
(855,249
)
Distribution by former parent
84,753

 
848

 
1,417,119

 

 
(30,449
)
 
(1,387,518
)
 

 

 

Stock-based compensation

 

 
7,689

 

 

 

 
7,689

 

 
7,689

Dividends paid

 

 

 
(11,075
)
 

 

 
(11,075
)
 

 
(11,075
)
Acquisition of Prospector

 

 

 

 
(40
)
 

 
(40
)
 
11,351

 
11,311

Acquisition of Prospector non-controlling interest

 

 
(1,655
)
 

 

 

 
(1,655
)
 
(8,651
)
 
(10,306
)
Other comprehensive income, net

 

 

 

 
(6,649
)
 

 
(6,649
)
 

 
(6,649
)
Balance at December 31, 2014
84,753

 
$
848

 
$
1,423,153

 
$
(895,249
)
 
$
(37,144
)
 
$

 
$
491,608

 
$
2,641

 
$
494,249

See accompanying notes to the consolidated and combined financial statements.

65


NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION
Paragon Offshore plc (together with its subsidiaries, “Paragon,” the “Company,” “we,” “us” or “our”) is a global provider of offshore drilling rigs with a fleet that currently includes 34 jackups and six floaters (four drillships and two semisubmersibles). We refer to our semisubmersibles and drillships collectively as “floaters.” Our primary business is to contract our drilling rigs, related equipment and work crews to conduct oil and gas drilling and workover operations for our exploration and production customers on a dayrate basis around the world.
Spin-off Transaction
On July 17, 2014, Paragon Offshore Limited, an indirect wholly owned subsidiary of Noble Corporation plc (“Noble”) incorporated under the laws of England and Wales, re-registered under the Companies Act 2006 as a public limited company under the name of Paragon Offshore plc.  Noble transferred to us 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 our issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned.
Acquisition of Prospector Offshore Drilling S. A.
On November 17, 2014, Paragon acquired 89.3 million, or 94.4%, of the outstanding shares of Prospector Offshore Drilling S.A. (Prospector), an offshore drilling company organized in Luxembourg and traded on the Oslo Axess, from certain shareholders and in open market purchases for approximately $190 million in cash. In December 2014, we purchased an additional 4.1 million shares for approximately $10 million in cash, increasing our ownership to approximately 93.4 million shares, or 98.7%, of the outstanding shares of Prospector. On January 22, 2015, we settled a mandatory tender offer for additional outstanding shares, increasing our ownership to approximately 99.6% of the outstanding shares of Prospector. On February 23, 2015, we acquired all remaining issued and outstanding shares in Prospector pursuant to the laws of Luxembourg. We spent approximately $202 million in aggregate to acquire 100% of Prospector and funded the purchase of the shares of Prospector using proceeds from our revolving credit facility and cash on hand.
The Prospector acquisition expanded and enhanced our global fleet by adding two high specification jackups contracted to Total E&P U.K. Limited and Elf Exploration U.K. Limited (“Total S.A.”) for use in the United Kingdom sector of the North Sea. In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China.  These rigs are currently scheduled for delivery in April 2015, September 2015 and March 2016, respectively. Each newbuild is being built pursuant to a contract between one of these subsidiaries and SWS, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary. Prospector's results of operations are included in our results beginning on November 17, 2014.
Basis of Presentation
The consolidated and combined financial information contained in this report includes periods that ended prior to the Spin-Off on August 1, 2014.  For all periods prior to the Spin-Off, the combined financial statements and related discussion of financial condition and results of operations contained in this report pertain to the historical results of the Noble Standard-Spec Business (our “Predecessor”), which comprised the entire standard specification drilling fleet and related operations of Noble.  Our Predecessor’s historical combined financial statements include three standard specification drilling units that were retained by Noble and three standard specification drilling units that were sold by Noble prior to the Separation.
Our Predecessor’s historical combined financial statements for the periods prior to the Spin-Off include assets and liabilities that are specifically identifiable or have been allocated to our Predecessor. Revenues and costs directly related to our Predecessor have been included in the accompanying consolidated and combined financial statements. Our Predecessor received service and support functions from Noble and the costs associated with these support functions have been allocated to our Predecessor using various inputs, such as head count, services rendered, and assets assigned to our Predecessor. Our management considers the allocation methodologies used to be reasonable and appropriate reflections of the related expenses attributable to us for purposes of the carve-out financial statements; however, the expenses reflected in the results of our

66


Predecessor and included in these consolidated and combined statements may not be indicative of the actual expenses that would have been incurred during the periods presented if our Predecessor had operated as a separate standalone entity and may not be indicative of expenses that will be incurred in the future by us. These allocated costs are primarily related to corporate administrative expenses including executive oversight, employee related costs including pensions and other benefits, and corporate and shared employees for the following functional groups:
information technology,
legal, accounting, finance and treasury services,  
human resources,
marketing, and
other corporate and infrastructural services.
We consolidate the historical combined financial results of our Predecessor in our consolidated and combined financial statements for all periods prior to the Spin-Off. All financial information presented after the Spin-Off represents the results of operations, financial position and cash flows of Paragon. Accordingly:
Our Consolidated and Combined Statements of Income and Comprehensive Income for the year ended December 31, 2014 consist of the consolidated results of Paragon for the five months ended December 31, 2014 and the combined results of our Predecessor for the prior months. Our Combined Statements of Income and Comprehensive Income for the years ended December 31, 2013 and 2012 consist entirely of the combined results of our Predecessor. Our net income for the periods prior to July 31, 2014 was recorded to “Net parent investment.”
Our Consolidated and Combined Balance Sheet at December 31, 2014 consists of the balances of Paragon, while at December 31, 2013, the Combined Balance Sheet consists of the balances of our Predecessor.
Our Consolidated and Combined Statement of Cash Flows for the year ended December 31, 2014 consists of the consolidated results of Paragon for the five months ended December 31, 2014, and the combined results of our Predecessor for prior months. Our Combined Statement of Cash Flows for the years ended December 31, 2013 and 2012 consist entirely of the combined results of our Predecessor.
Our Consolidated and Combined Statement of Changes in Equity for the year ended December 31, 2014 consists of both the activity for Paragon completed in connection with, and subsequent to, the Distribution on August 1, 2014 through the five months ended December 31, 2014 and for our Predecessor for the prior months. Our Combined Statements of Changes in Equity for the years ended December 31, 2013 and 2012 consist of activity for our Predecessor recorded to “Net parent investment.”
As our Predecessor previously operated within Noble’s corporate cash management program for all periods prior to the Distribution, funding requirements and related transactions between our Predecessor and Noble have been summarized and reflected on our consolidated and combined balance sheet as “Net parent investment” without regard to whether the funding represents a receivable, liability or equity. Based on the terms of our Separation from Noble, we ceased being a part of Noble’s corporate cash management program.  Any transactions with Noble after August 1, 2014 have been, and will continue to be, cash settled in the ordinary course of business, and such amounts are included in “Accounts payable” on our consolidated and combined balance sheet.
Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for Noble. After the Distribution, we have been solely responsible for the provision of funds to finance our working capital and other cash requirements. We expect our primary sources of liquidity in the future will be cash generated from operations, our Revolving Credit Facility and any future financing arrangements, if necessary. Our principal uses of liquidity will be to fund our operating expenditures and capital expenditures, including major projects, upgrades and replacements to drilling equipment, to service our outstanding indebtedness, acquisitions and to pay future dividends.
At December 31, 2014, we had $57 million of cash on hand and $634 million of committed financing available under our Revolving Credit Facility, which will expire in 2019. In January 2015, we repurchased $99.6 million par value of the Prospector Bonds at a price of 101% of par. As of March 12, 2015, approximately $0.4 million par value of Prospector Bonds remained outstanding. We are also currently in discussions with lenders to waive the prepayment requirement for

67


the Prospector Senior Credit Facility of $270 million beyond March 16, 2015. In the event these lenders do not waive the prepayment requirement, we will repay in full the remaining principal balance outstanding under the Prospector Senior Credit Facility (approximately $260 million on March 12, 2015) through the use of cash on hand and borrowings under our Revolving Credit Facility.
At December 31, 2014, we have purchase commitments of $400 million and $199 million currently due in 2015 and 2016, respectively, related to three high specification jack up rigs under construction. Each of these rigs is being built pursuant to a contract between a subsidiary of Prospector and the shipyard, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary. We are currently in discussions with the shipyard to extend delivery of these contracts. In the event we are unable to extend delivery, we will lose ownership of each rig individually. At that point, the associated costs currently capitalized (representing down-payments on these rigs) on our balance sheet totaling $32 million for all three rigs will be written off.
Our debt facilities are subject to financial and non-financial covenants. While we believe we will satisfy our covenants, current and foreseeable market conditions may prevent us from maintaining compliance at the December 31, 2015 measurement date. The current low oil price environment is having an impact on contract renewal rates and an extended downturn in our industry could be exacerbated by an oversupply of new rigs in the medium term. However, we believe that there are proactive measures we can take that are within our control to prevent us from breaching these financial and non-financial covenants, such as reducing our operating and capital expenses, and/or designating certain of the Prospector subsidiaries as restricted subsidiaries under our debt agreements, which would allow us to include such subsidiaries’ financial results in these covenant calculations of our debt agreements, or seek waiver on the covenants from our lenders.
Our operating cash flows, including collection of receivables outstanding at December 31, 2014, coupled with financing available under the Revolving Credit Facility will be sufficient to meet our liquidity needs for at least the next 12 months. Our ability to continue to fund our operations will be affected by general economic, competitive and other factors, many of which are outside of our control and becoming more challenging in the current market environment. If our future cash flows from operations and other capital resources are insufficient to fund our liquidity needs, we may be forced to reduce or delay our capital and operational expenditures, sell assets, obtain additional debt or equity financing, or refinance all or a portion of our debt.

68


Separation from Noble
Prior to the Spin-off, our total equity represented the cumulative net parent investment by Noble, including any prior net income attributable to our Predecessor as part of Noble. At the Spin-off, Noble contributed its entire net parent investment in our Predecessor. Concurrent with the Spin-off and in accordance with the terms of our Separation from Noble, certain assets and liabilities were transferred between us and Noble, which have been recorded as part of the net capital contributed by Noble. The following table presents the opening balance sheet of our Predecessor as of August 1, 2014 that was distributed to us in connection with the Spin-Off.
 
 
August 1,
(In thousands, except share amounts)
 
2014
ASSETS
 
 
Current assets
 
 
Cash and cash equivalents
 
$
104,152

Accounts receivable
 
377,324

Prepaid and other current assets
 
126,264

Total current assets
 
607,740

Property and equipment, at cost
 
5,615,161

Accumulated depreciation
 
(2,640,273
)
Property and equipment, net
 
2,974,888

Other assets
 
102,419

Total assets
 
$
3,685,047

LIABILITIES AND EQUITY
 
 
Current liabilities
 
 
Current maturities of long-term debt
 
$
4,875

Accounts payable
 
129,952

Accrued payroll and related costs
 
67,256

Taxes payable
 
53,384

Interest payable
 
3,770

Other current liabilities
 
117,887

Total current liabilities
 
377,124

Long-term debt
 
1,725,125

Deferred income taxes
 
79,659

Other liabilities
 
115,621

Total liabilities
 
2,297,529

 
 
 
Equity
 
 
Ordinary shares
 
848

Additional paid-in capital
 
1,417,119

Accumulated other comprehensive loss
 
(30,449
)
Total equity
 
1,387,518

Total liabilities and equity
 
$
3,685,047


69


NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Combination and Consolidation
The consolidated and combined financial statements include our accounts, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. The combined financial statements of our Predecessor include our net assets and results of our operations as previously described. All significant intercompany accounts and transactions have been eliminated in combination and consolidation.
Foreign Currency Translation
We define foreign currency as any non-U.S. denominated currency. In non-U.S. locations where the U.S. dollar has been designated as the functional currency (based on an assessment of the economic circumstances of the foreign operation), local currency transaction gains and losses are included in net income. In non-U.S. locations where the local currency is the functional currency, assets and liabilities are translated at the rates of exchange on the balance sheet date, while income and expense items are translated at average rates of exchange during the year. The resulting gains or losses arising from the translation of accounts from the functional currency to the U.S. dollar are included in “Accumulated other comprehensive loss” in the accompanying consolidated and combined balance sheets. We did not recognize any material gains or losses on foreign currency transactions or translations during the years ended December 31, 2014, 2013 or 2012.
Cash and Cash Equivalents
Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Our cash, cash equivalents and short-term investments are subject to potential credit risk, and certain of our cash accounts carry balances greater than federally insured limits. Cash and cash equivalents are primarily held by major banks or investment firms. Our cash management and investment policies restrict investments to lower risk, highly liquid securities and we perform periodic evaluations of the relative credit standing of the financial institutions with which we conduct business.
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. Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (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 (“Level 2”) and (3) unobservable inputs that require significant judgment for which there is little or no market data (“Level 3”). 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 and combined balance sheets approximate fair value.
Property and Equipment, at Cost
Property and equipment is stated at cost, reduced by provisions to recognize economic impairment in value whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to twenty-five years. Included in accounts payable were $24 million and $29 million of capital accruals as of December 31, 2014 and 2013, respectively.
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; however, the costs of overhauls and asset replacement projects that benefit future periods and which typically occur every three to five

70


years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Property and equipment, at cost” in our consolidated and combined balance sheets. Such amounts, net of accumulated depreciation, totaled $193 million and $211 million at December 31, 2014 and 2013, respectively. Depreciation expense related to overhauls and asset replacement totaled $85 million, $76 million and $66 million for the years ended December 31, 2014, 2013 and 2012, respectively.
We evaluate the impairment of property and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis, we complete an impairment analysis on all of our rigs. An impairment loss on our property and equipment exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions we may take an impairment loss in the future (see Note 6, “Property and Equipment”).
Debt Issuance Costs
Deferred debt issuance costs are amortized through interest expense over the life of the debt securities.
Revenue Recognition
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.
Deferred revenues from drilling contracts totaled $9 million at December 31, 2014 as compared to $22 million at December 31, 2013. Such amounts are included in either “Other current liabilities” or “Other liabilities” in our consolidated and combined balance sheets, based upon the expected time of recognition of such deferred revenues. Deferred costs associated with deferred revenues from drilling contracts totaled $2 million at December 31, 2014 as compared to $24 million at December 31, 2013. Such amounts are included in either “Prepaid and other current assets” or “Other assets” in our consolidated and combined balance sheets, based upon the expected time of recognition of such deferred costs.
We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.
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 United Kingdom, the U.S., and any other jurisdictions in which we or any of our subsidiaries operate, are 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.

71


The operations of our Predecessor have been included in certain income tax returns of Noble. The income tax provisions and related deferred tax assets and liabilities that have been reflected in our Predecessor’s historical combined financial statements have been computed as if our Predecessor were a separate taxpayer using the separate return method. As a result, actual tax transactions that would not have occurred had our Predecessor been a separate entity have been eliminated in the preparation of these consolidated and combined financial statements. Income taxes of our Predecessor include results of the operations of the standard specification drilling units. In instances where the operations of the standard specification drilling units of our Predecessor were included in the filing of a return with high specification units, an allocation of income taxes was made.
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.
Earnings/Loss per Share
Our unvested share-based payment awards, which contain non-forfeitable rights to dividends, are participating securities and are included in the computation of earnings per share pursuant to the “two-class” method. The “two-class” method allocates undistributed earnings between ordinary shares and participating securities; however, in a period of net loss, losses are not allocated to our participating securities. The diluted earnings per share calculation under the “two-class” method would also includes the dilutive effect of potential shares issued in connection with stock options. The dilutive effect of stock options would be determined using the treasury stock method. The diluted earnings per share calculation under the two class method is the same as our basic earnings per share calculation as we currently have no stock options or other potentially dilutive securities outstanding.
Share-Based Compensation Plans
We record the grant date fair value of share-based compensation arrangements as compensation cost using a straight-line method over the service period. Share-based compensation is expensed or capitalized based on the nature of the employee’s activities.
Certain Significant Estimates and Contingent Liabilities
The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“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. 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 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 consolidated and combined financial statements included elsewhere in this Annual Report on Form 10-K.
Reclassifications
Certain amounts in prior periods have been reclassified to conform to the current year presentation.

72


NOTE 3—ACQUISITION
On November 17, 2014, Paragon acquired 89.3 million, or 94.4%, of the outstanding shares of Prospector Offshore Drilling S.A. (“Prospector”), an offshore drilling company organized in Luxembourg and traded on the Oslo Axess, from certain shareholders and in open market purchases for approximately $190 million in cash. In December 2014, we purchased an additional 4.1 million shares for approximately $10 million in cash, increasing our ownership to approximately 93.4 million shares, or 98.7%, of the outstanding shares of Prospector. On January 22, 2015, we settled a mandatory tender offer for additional outstanding shares, increasing our ownership to approximately 99.6% of the outstanding shares of Prospector. On February 23, 2015, we acquired all remaining issued and outstanding shares in Prospector pursuant to the laws of Luxembourg. We spent approximately $202 million in aggregate to acquire 100% of Prospector and funded the purchase of the shares of Prospector using proceeds from our revolving credit facility and cash on hand.
The Prospector acquisition expanded and enhanced our global fleet by adding two high specification jackups contracted to Total S.A. for use in the United Kingdom sector of the North Sea. In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China.  These rigs are currently scheduled for delivery in April 2015, September 2015 and March 2016, respectively. Each newbuild is being built pursuant to a contract between one of these subsidiaries and SWS, without a Paragon or Prospector parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary. Prospector's results of operations are included in our results beginning on November 17, 2014.
Accounting for business combinations requires that the various assets acquired and liabilities assumed in a business combination be recorded at their respective fair values. The most significant estimates to us typically relate to acquired property and equipment. Deferred taxes are recorded for any differences between the fair value and tax basis of assets acquired and liabilities assumed. To the extent the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. As the fair value of assets acquired and liabilities assumed is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The following table summarizes our allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed on the acquisition date of November 17, 2014:

73


(In thousands)
 
Fair Value
ASSETS
 
 
Current assets
 
 
Accounts receivable
 
$
26,169

Restricted cash
 
5,023

Prepaid and other current assets
 
17,967

Total current assets
 
49,159

Property and equipment
 
516,979

Goodwill
 
13,290

Other assets
 
25,520

Total assets acquired
 
$
604,948

LIABILITIES
 
 
Current liabilities
 
 
Current maturities of long-term debt
 
$
32,970

Accounts payable
 
16,227

Accrued payroll and related costs
 
3,754

Taxes payable
 
4,378

Interest payable
 
6,466

Other current liabilities
 
19,120

Total current liabilities
 
82,915

Long-term debt
 
333,697

Other liabilities
 
456

Total liabilities assumed
 
$
417,068

Accumulated other comprehensive loss
 
(40
)
Non-controlling interest
 
11,351

Purchase price, net of cash acquired
 
$
176,569

The fair value of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities was generally determined using historical carrying values given the short-term nature of these items. The fair values of drilling equipment and in-place contracts were determined using management’s estimates of future net cash flows. Such estimated future cash flows were discounted at an appropriate risk-adjusted rate of return. The fair values of the consolidated derivatives were determined based on a discounted cash flow model utilizing an appropriate market or risk-adjusted yield. The fair value of other assets and other liabilities, related to long-term tax items, was derived using estimates made by management. Fair value estimates for in-place contracts are recorded in “Prepaid and other current assets” and “Other assets” in our consolidated and combined balance sheet and will be amortized over the life of the respective contract. The average life of these contracts totaled approximately 2.5 years as of the date of the acquisition.
Our purchase price allocation is preliminary. The preliminary allocation of the purchase consideration is based on management's estimates, judgments and assumptions. These estimates, judgments and assumptions are subject to change upon final valuation and should be treated as preliminary values. Management estimated that consideration paid exceeds the fair value of the net assets acquired. Therefore, goodwill of $13 million was recorded. The final allocation of purchase consideration could include changes in the estimated fair value of income tax obligations.
As of December 31, 2014, we have incurred $4 million in acquisition costs related to the Prospector acquisition. These costs have been expensed and are included in contract drilling services expense.

The following unaudited pro forma financial information for the year ended December 31, 2014 and 2013, gives effect to the Prospector acquisition as if it had occurred at the beginning of the periods presented. The pro forma financial information for the year ended December 31, 2014 includes pro forma results for the period prior to the closing date of

74


November 17, 2014 and actual results for the period from November 17, 2014 through December 31, 2014. The pro forma results are based on historical data and are not intended to be indicative of the results of future operations.

(In thousands, except per share amounts)
 
2014
 
2013
Total operating revenues
 
$
42,456

 
$
4,200

Net loss
 
(55,802
)
 
(16,050
)
Net loss to Paragon Offshore
 
(55,054
)
 
(15,835
)
Loss per share (basic and diluted)
 
$
(0.65
)
 
$
(0.19
)

Revenues from the Prospector rigs totaled $8 million from the closing date of November 17, 2014 through December 31, 2014. Operating expenses for this same period totaled $8 million for the Prospector rigs.

NOTE 4—EARNINGS/LOSS PER SHARE
Our outstanding share-based payment awards currently consist solely of restricted stock units. These unvested restricted stock units, which contain non-forfeitable rights to dividends, are participating securities and are included in the computation of earnings per share pursuant to the “two-class” method. The “two-class” method allocates undistributed earnings between ordinary shares and participating securities; however, in a period of net loss, losses are not allocated to our participating securities.
On August 1, 2014, approximately 85 million of our ordinary shares were distributed to Noble’s shareholders in conjunction with the Spin-Off. Weighted average shares outstanding, basic and diluted, has been computed based on the weighted average number of ordinary shares outstanding during the applicable period. Restricted stock units do not represent ordinary shares outstanding until they are vested and converted into ordinary shares. The diluted earnings per share calculation under the two class method is the same as our basic earnings per share calculation as we currently have no stock options or other potentially dilutive securities outstanding.
No earnings were allocated to unvested share-based payment awards in our earnings per share calculation for the year ended December 31, 2014 due to our net loss in the current year. Our basis of presentation related to weighted average unvested shares outstanding for all periods prior to the Spin-Off does not include our unvested restricted stock units that were granted to our employees in conjunction with Paragon's 2014 Employee Omnibus Incentive Plan. As a result, we also have no earnings allocated to unvested share-based payment awards in our earnings per share calculation for periods prior to the Spin-Off.
The following table sets forth the computation of basic and diluted net income and earnings (loss) per share:
 
 
Year Ended December 31,
(In thousands, except per share amounts)
 
2014
 
2013
 
2012
Allocation of income - basic and diluted
 
 
 
 
 
 
Net income (loss) attributable to Paragon
 
$
(646,746
)
 
$
360,305

 
$
126,237

Earnings allocated to unvested share-based payment awards
 

 

 

Net income (loss) to ordinary shareholders - Basic and diluted
 
$
(646,746
)
 
$
360,305

 
$
126,237

 
 
 
 
 
 
 
Weighted average shares outstanding
 
 
 
 
 
 
Basic and diluted
 
84,753

 
84,753

 
84,753

 
 
 
 
 
 
 
Earnings (loss) per share
 
 
 
 
 
 
Basic and diluted
 
$
(7.63
)
 
$
4.25

 
$
1.49


75


NOTE 5—SHARE-BASED COMPENSATION
Predecessor Plan
For all periods prior to the Spin-Off, our Predecessor was managed in the normal course of business by Noble and its subsidiaries. Noble provides a stock-based compensation plan that is granted and settled in stock of Noble. The Noble plan permits the granting of various types of awards including stock options and restricted stock units. Prior to the Spin-off and to the extent that Company employees participated in these programs, the results of our Predecessor were allocated a portion of the associated expenses (see Note 16, “Related Parties (Including Relationship with Parent and Corporate Allocations)” for total costs allocated to us by Noble).
Paragon employees’ participation in Noble’s 1991 Stock Option and Restricted Stock Plan (“Noble 1991 Plan”) was terminated as of our Separation from Noble at the time of the Distribution. The Noble 1991 Plan provided for the granting of options to purchase Noble shares and the awarding of restricted stock units in the form of both time-vested restricted stock units (“TVRSU’s”) and performance-vested restricted stock units (“PVRSU’s”).
Upon termination in Noble’s 1991 Plan, our employees’ rights to exercise Noble stock options continues for up to the shorter of five years or the remaining term of the option and the vesting of each option was accelerated so that each option is now fully vested. Paragon has no outstanding stock option grants as of December 31, 2014 under this arrangement.
All Noble TVRSU’s held by our employees under the Noble 1991 Plan were canceled at the Distribution. At the time of the Distribution, Paragon granted 2,675,839 TVRSU’s that were intended to be of equivalent value and remaining duration at the time with regard to such canceled awards.
With respect to outstanding Noble PVRSU’s held by our employees under the Noble 1991 Plan, a portion of such PVRSU’s continues to be held by those employees and a portion has been canceled. This apportionment was based on the performance cycle that relates to each applicable Noble performance-vested restricted stock unit award, and the ratio of the number of months remaining in the award’s performance cycle after our Separation from Noble relative to the total number of months (i.e., 36 months) of such performance cycle. This ratio has been applied to each applicable grant of Noble PVRSU’s to determine the portion thereof that were canceled, the remainder of which were continued. With regard to the canceled portion of Noble PVRSU’s, we either granted the affected employee Paragon PVRSU’s that were intended to be of equivalent value and duration at the time of grant to the canceled portion of the Noble award, or provided the employee compensation of equivalent value to the benefit the employee would have received had the canceled portion of the Noble awards remained in effect. At the time of the Distribution, Paragon granted 277,118 PVRSU’s that were intended to be of equivalent value and remaining duration with regard to the canceled portion.
Paragon Plans
With respect to the cancellations described above, we have adopted new equity incentive plans for our employees and directors to administer replacement awards of Paragon TVRSU’s and PVRSU’s, as well as to provide for the granting of new awards for the periods following our Separation from Noble. On June 30, 2014, our board of directors at the time adopted the Paragon Offshore plc 2014 Employee Omnibus Incentive Plan (the “Employee Plan”), which was approved by Noble as Paragon Offshore’s sole stockholder on July 15, 2014 and became effective as of the date of the Distribution. Subject to certain adjustments, up to 8,475,340, or 10% of the number of Paragon Offshore’s outstanding shares at the time of the Distribution, were authorized under our Employee Plan for issuance to eligible participants in the form of stock options, stock appreciation rights, restricted stock (and in certain limited cases, unrestricted stock), restricted stock units, performance units and cash awards. On June 30, 2014, our board of directors at the time also adopted the Paragon Offshore plc 2014 Director Omnibus Plan (the “Director Plan”), which was approved by Noble as Paragon Offshore’s sole stockholder on July 15, 2014 and became effective as of the date of the Distribution. The maximum number of Paragon Offshore ordinary shares that may be subject to awards granted under the Director Plan is 500,000 shares, subject to certain adjustments. The Director Plan provides that our board of directors may award stock options, stock appreciation rights, restricted stock (and in certain limited cases, unrestricted stock), restricted stock units, performance units and cash awards to directors as it may determine from time to time.

76


Shares available for issuance and outstanding restricted stock units for our two stock incentive plans as of December 31, 2014 are as follows:
(In shares)
 
Employee Plan
 
Director Plan
Shares available for future awards or grants
 
4,719,570

 
240,258

Outstanding unvested restricted stock units
 
3,755,770

 
259,742

As noted above, we have awarded both TVRSU’s and PVRSU’s under our Employee Plan and TVRSU's under our Director Plan. The TVRSU’s generally vest over a three year period. The number of PVRSU’s which vest will depend on the degree of achievement of specified corporate performance criteria over the service period.
Our TVRSU's are valued on the date of award at our underlying share price. The total compensation for units that ultimately vest is recognized over the 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.
Our PVRSU's are valued on the date of award at our underlying share price. Total compensation cost recognized for our PVRSU's depends on an accounting-based performance measure, return on capital employed (“ROCE”) over specified performance periods. Estimated compensation cost is determined based on numerous assumptions, including an estimate of the likelihood that our ROCE will achieve the targeted thresholds and forfeiture of the PVRSU's based on annualized ROCE performance over the terms of the awards.
A summary of restricted stock activity for the year ended December 31, 2014 is as follows:
 
 
TVRSU's Outstanding
 
Weighted
Average
Award-Date
Fair Value
 
PVRSU's
Outstanding (1)
 
Weighted
Average
Award-Date
Fair Value
Outstanding at August 1, 2014
 

 
$

 

 
$

Awarded
 
3,894,601

 
10.54

 
277,118

 
11.00

Vested
 

 

 

 

Forfeited
 
(140,835
)
 
10.70

 
(15,372
)
 
11.00

Outstanding at December 31, 2014
 
3,753,766

 
$
10.54

 
261,746

 
$
11.00

(1)
The number of PVRSU’s shown equals the units that would vest if the “maximum” level of performance is achieved. The minimum number of units is zero and the “target” level of performance is 50% of the amounts shown.
Share-based compensation cost is measured at the grant date, based on the calculated fair value of the award, and is recognized as compensation cost using a straight-line method over the service period. Share-based amortization recognized during the five months ended December 31, 2014, not including amounts allocated to our Predecessor, totaled $7.7 million. At December 31, 2014, there was $26 million of total unrecognized compensation cost related to our TVRSU’s which is expected to be recognized over a remaining weighted-average period of 1.8 years. At December 31, 2014, there was $1 million of total unrecognized compensation cost related to our PVRSU’s which is expected to be recognized over a remaining weighted-average period of 1.7 years. The total potential compensation for our PVRSU’s is recognized over the service period regardless of whether the performance thresholds are ultimately achieved.
NOTE 6—PROPERTY AND EQUIPMENT
Property and equipment is stated at cost. Interest incurred related to property under construction including major overhaul, improvement and asset replacement projects is capitalized as a component of construction costs. Interest capitalized in our Predecessor’s results relates to Noble’s revolving credit facilities and commercial paper program, while interest capitalized in Paragon’s results relates to our Senior Notes and Term Loan Facility (each as defined in Note 7, “Debt”). Our capital expenditures, including capitalized interest, totaled $262 million for the year ended December 31, 2014, as compared

77


to historical Predecessor capitalized expenditures, including capitalized interest, of $366 million for the year ended December 31, 2013.
Interest expense capitalized in these consolidated and combined financial statements for the year ended December 31, 2014 was $3 million, as compared to Predecessor capitalized interest of $6 million for the year ended December 31, 2013.
Loss on Impairment
We evaluate the impairment of property and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis, we complete an impairment analysis on all of our rigs. An impairment loss on our property and equipment exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions, we may take an impairment loss in the future.
During 2014, we identified indicators of impairment, including lower crude oil prices, a decrease in contractual activities particularly for floating rigs, and resultant projected declines in dayrates and utilization. We concluded that a triggering event occurred requiring us to perform an impairment analysis of our fleet of drilling rigs. We compared the net book value of our drilling rigs to the relative recoverable value, which was determined using an undiscounted cash flow analysis. As a result of this analysis, we determined that the Paragon DPDS1, Paragon DPDS2 and Paragon DPDS3 drilling rigs were impaired. We calculated the fair value of these drilling rigs after considering quotes from rig brokers, a cost approach and an income approach, which utilized significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to estimated dayrate revenue, rig utilization and anticipated costs for the remainder of the rigs’ useful lives. Additionally, we decided to scrap the Paragon FPSO1, Paragon MSS3, Paragon B153 and Paragon DPDS4. We recognized an impairment on these units after we determined the fair values based on quotes from brokers, price indications from potential interested buyers, and estimates of salvage values. Based on the above analysis, our estimates of fair value resulted in the recognition of an impairment loss of $1.1 billion for the year ended December 31, 2014, of which $130 million was recognized in the fourth quarter of 2014.
During 2013, our Predecessor determined that the Paragon FPSO, formerly the Noble Seillean, was partially impaired as a result of it's annual impairment test and the current market outlook for this unit. Our Predecessor estimated the fair value of this unit by considering both income and market-based valuation approaches utilizing statistics for comparable rigs (Level 2 fair value measurement). Based on these estimates, our Predecessor recognized a charge of $40 million for the year ended December 31, 2013.
Also in 2013, our Predecessor recorded an impairment charge on two cold stacked submersible rigs. These rigs had been impaired in 2011 due to the declining market outlook for drilling services for that rig type; however, in 2013 an additional impairment charge of approximately $4 million was recorded as a result of the potential disposition of these assets to an unrelated third party. These submersible rigs were sold by our Predecessor in January 2014.
Gain on Disposal of Assets, net
During the third quarter of 2013, our Predecessor completed the sale of the Noble Lewis Dugger for $61 million to an unrelated third party in Mexico. In connection with the sale, our Predecessor recorded a pre-tax gain of approximately $36 million.

78


NOTE 7—DEBT
A summary of long-term debt at December 31, 2014 and 2013 is as follows:
 
 
December 31,
 
December 31,
(In thousands)
 
2014
 
2013
Senior Notes due 2022, bearing fixed interest at 6.75% per annum
 
$
457,572

 
$

Senior Notes due 2024, bearing fixed interest at 7.25% per annum
 
537,010

 

Term Loan Facility, bearing interest at 3.75%, net of unamortized discount
 
645,357

 

Revolving Credit Facility
 
154,000

 

Prospector 2019 Second Lien Callable Bond
 
101,000

 

Prospector 2018 Senior Secured Credit Facility
 
265,666

 

Noble Credit Facilities / Commercial Paper Program
 

 
1,561,141

Less: Current maturities of long-term debt
 
(272,166
)
 

 
 
$
1,888,439

 
$
1,561,141

Predecessor Debt
Our Predecessor was supported by Noble’s three separate credit facilities which had an aggregate maximum available capacity of $2.9 billion (collectively, the “Noble Credit Facilities”). Predecessor long-term debt consisted of the amount drawn on the Noble Credit Facilities. Noble established a commercial paper program, which allowed Noble to issue up to $2.7 billion in unsecured commercial paper notes. Amounts issued under the commercial paper program were supported by the unused capacity under the Noble Credit Facilities. The outstanding amounts of commercial paper reduce availability under the Noble Credit Facilities.
As discussed below, Noble received approximately $1.7 billion in cash as settlement of intercompany notes in connection with the Separation. Noble used these proceeds to repay amounts outstanding under its commercial paper program. Accordingly, debt that is included in our Predecessor’s combined financial statements represents the amounts outstanding under Noble’s commercial paper program, and has been pushed down to our Predecessor in accordance with guidance of the SEC. The remaining outstanding debt not repaid from our Predecessor’s debt at the time of the settlement of the intercompany notes is considered as part of “Net parent investment” in our Predecessor.
Paragon Debt
On June 17, 2014, we entered into a senior secured revolving credit agreement with lenders that provided commitments in the amount of $800 million (the “Revolving Credit Facility”). The Revolving Credit Facility has a term of five years after the funding date. Borrowings under the Revolving Credit Facility bear interest, at our option, at either (i) an adjusted London Interbank Offered Rate (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%. Under the Revolving Credit Facility, we may also obtain up to $800 million of letters of credit. Issuance of letters of credit under the Revolving Credit Facility would reduce a corresponding amount available for borrowing. As of December 31, 2014, we had $154 million in borrowings outstanding at a weighted-average interest rate of 2.89%. There was an aggregate amount of $12 million of letters of credit issued under the Revolving Credit Facility.
On July 18, 2014, we issued $1.08 billion of senior notes (the “Senior Notes”) and also borrowed $650 million under a term loan facility (the “Term Loan Facility”). The Term Loan Facility is secured by all but three of our rigs. The proceeds from the Term Loan Facility and the Senior Notes were used to repay $1.7 billion of intercompany indebtedness to Noble incurred as partial consideration for the Separation. The Senior Notes consisted of $500 million of 6.75% senior notes and $580 million of 7.25% senior notes, which mature on July 15, 2022 and August 15, 2024, respectively. The Senior Notes were issued without an original issue discount. Borrowings under the Term Loan Facility bear 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 our option. We are required to make quarterly principal payments of $1.6 million and may prepay all or a portion of the term loans at any time. The Term Loan Facility matures in July 2021. The loans under the Term Loan Facility were issued with 0.5% original issue discount.

79


In connection with the issuance of the aforementioned debt, we and our Predecessor incurred $35 million of issuance costs.
The covenants and events of default under our Revolving Credit Facility, Senior Notes, and Term Loan Facility are substantially similar. The agreements governing these obligations contain covenants that place 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. In addition to these covenants, the Revolving Credit Facility includes a covenant requiring us to maintain a net leverage ratio (defined as total debt, net of cash and cash equivalents, divided by earnings excluding interest, taxes, depreciation and amortization charges) less than 4.00 to 1.00 and a covenant requiring us to maintain a minimum interest coverage ratio (defined as interest expense divided by earnings excluding interest, taxes, depreciation and amortization charges) greater than 3.00 to 1.00. As of December 31, 2014, we were in compliance with the covenants under our Revolving Credit Facility by maintaining a net leverage ratio of 2.0 and an interest coverage ratio of 8.3 (these calculations do not include the corresponding financial information from Prospector, which has been designated as a unrestricted subsidiary for purposes of our debt agreements). The impairment charge taken in the current quarter does not impact our debt covenant calculations because it is a non-cash charge and is excluded from our covenant calculations.
During the year ended December 31, 2014, we repurchased and canceled an aggregate principal amount of $85 million of our Senior Notes at an aggregate cost of $67 million including accrued interest. The repurchases consisted of $42 million aggregate principal amount of our 6.75% senior notes due July 2022 and $43 million aggregate principal amount of our 7.25% senior notes due August 2024. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of issuance costs, of approximately $19 million in “Gain on repurchase of long-term debt.” All Senior Note repurchases were made using available cash balances.
Subsequent to December 31, 2014, we repurchased and canceled an additional aggregate principal amount of $11 million of our Senior Notes at an aggregate cost of $7 million including accrued interest. The repurchases consisted of $1 million aggregate principal amount of our 6.75% senior notes due 2022 and $10 million aggregate principal amount of our 7.25% senior notes due 2024.
Prospector Debt
At the time of our acquisition of Prospector, Prospector had the following outstanding debt instruments: (i) 2019 Second Lien Callable Bond of $100 million (“Prospector Bonds”) and (ii) 2018 Senior Secured Credit Facility of $270 million (“Prospector Senior Credit Facility”).
The Prospector Bonds were originally entered into by a subsidiary of Prospector on May 19, 2014 in the Oslo Alternative Bond Market. The Prospector Bonds had a fixed interest rate of 7.75% per annum, payable semi-annually on December 19 and June 19 each year and maturity of June 19, 2019. The Prospector Bonds were secured by a second priority mortgage on Prospector 1 and Prospector 5 and guaranteed by Prospector S.A. and certain subsidiaries. The Prospector Bonds have a provision that allows the bondholders to put their bonds back to Prospector at a price of 101% of the par value upon a Change of Control event. The put provision was triggered by our acquisition of a controlling interest in Prospector on November 17, 2014. Subsequent to December 31, 2014, the bondholders put $99.6 million par value of their bonds back to Prospector at the put price of 101% of par plus accrued interest. We funded the repayment of the debt using borrowings from our Revolving Credit Facility and available cash. The outstanding Prospector Bonds balance at December 31, 2014 was $101 million.
The Prospector Senior Credit Facility was originally entered into by a subsidiary of Prospector on June 12, 2014 with a group of lenders. The Prospector Senior Credit Facility comprises a $140 million Prospector 5 tranche and a $130 million Prospector 1 tranche which were both fully drawn at the time of acquisition. At December 31, 2014, $140 million and $126 million were outstanding on the Prospector 5 and Prospector 1 tranches, respectively.
The Prospector Senior Credit Facility is secured by a first priority mortgage on Prospector 1 and Prospector 5, and guaranteed by Prospector Offshore Drilling S.A. and certain subsidiaries. The Prospector Senior Credit Facility bears interest at LIBOR plus a margin of 3.5%. Prospector is required to hedge at least 50% of the Prospector Senior Credit Facility against fluctuations in the interest rate. As of December 31, 2014, interest rate swaps fix the interest on approximately $133 million of outstanding borrowings under the Prospector Senior Credit Facility. Under the swaps, Prospector pays a fixed interest rate of 1.512% and receives the three-month LIBOR rate. The Prospector Senior Credit Facility has certain

80


financial covenants with which we are required to comply and test on a twelve month rolling basis commencing six months following the acceptance of Prospector 5 by Total S.A. This acceptance occurred in December 2014.
In addition to quarterly interest payments, the Prospector 1 tranche and the Prospector 5 tranche require quarterly principal repayments which commenced in October 2014 and January 2015, respectively. The remaining balance of the Prospector Senior Credit Facility is due in full in December 2018. The lenders under the Prospector Senior Credit Facility do not have recourse to Paragon for repayment of the loan.
The Prospector Senior Credit Facility also includes a Change of Control provision whereby the lenders can require us to prepay the outstanding principal balance and accrued interest. On February 13, 2015, the lenders under the Prospector Senior Credit Facility temporarily waived this prepayment requirement until March 16, 2015. We are currently in discussions with these lenders to permanently waive this requirement. However, we can provide no assurance that we will reach an agreement with the lenders prior to such date. If we are unable to do so, we will be required to repay in full the remaining principal balance outstanding under the Prospector Senior Credit Facility. We intend to use cash on hand and borrowings under our Revolving Credit Facility.
Fair Value of Debt
Fair value represents the amount at which an instrument could be exchanged in a current transaction between willing parties. The estimated fair values of our Senior Notes and Term Loan Facility were based on the quoted market prices for similar issues or on the current rates offered to us for debt of similar remaining maturities (Level 2 measurement). The fair value of our Prospector Bonds were based on the put price as per the change of control considerations in the bond agreement.
The following table presents the estimated fair value of our long-term debt as of December 31, 2014:
 
December 31, 2014
(In thousands)
Carrying Value
 
Estimated Fair Value
Senior unsecured notes:
 
 
 
6.75% Senior Notes due July 15, 2022
$
457,572

 
$
275,115

7.25% Senior Notes due August 15, 2024
537,010

 
319,521

Total senior unsecured notes
$
994,582

 
$
594,636

 
 
 
 
Term Loan Facility, bearing interest at 3.75%, net of unamortized discount
$
645,357

 
$
523,250

 
 
 
 
Prospector 2019 Second Lien Callable Bond
$
101,000

 
$
101,000

The carrying amounts of our variable-rate debt, the Revolving Credit Facility and the Prospector Senior Credit Facility, approximate fair value because such debt bears short-term, market-based interest rates. We have classified these instruments as Level 2 as valuation inputs used for purposes of determining our fair value disclosure are readily available published LIBOR rates.
NOTE 8—GAIN ON CONTRACT SETTLEMENTS/EXTINGUISHMENT, NET
During the third quarter of 2013, Noble received $45 million related to the settlement of all claims against the former investors of FDR Holdings, Ltd., which Noble acquired in July 2010, relating to alleged breaches of various representations and warranties contained in the purchase agreement. A portion of the settlement related to standard specification rigs. This portion, totaling $23 million, was pushed down to our Predecessor in 2013, through an allocation, using the acquired rig values of the purchased rigs.
During the fourth quarter of 2012, our Predecessor received a deposit of $2 million related to the potential sale of one of our drilling units to an unrelated third party. During the first quarter of 2013 negotiations led to the sale not being completed and the deposit was recognized as a gain.

81


During the second quarter of 2012, our Predecessor received $5 million from the settlement of a claim relating to the Noble David Tinsley, which experienced a “punch-through” while being positioned on location in 2009.
NOTE 9—INCOME TAXES
The operations of our Predecessor have been included in certain income tax returns of Noble. The income tax provisions and related deferred tax assets and liabilities that have been reflected in our Predecessor’s historical combined financial statements have been computed as if our Predecessor were a separate taxpayer using the separate return method. As a result, actual tax transactions that would not have occurred had our Predecessor been a separate entity have been eliminated in the preparation of these consolidated and combined financial statements. Income taxes of our Predecessor include results of the operations of the standard specification drilling units. In instances where the operations of the standard specification drilling units of our Predecessor were included in the filing of a return with high specification units, an allocation of income taxes was made.
We operate through various subsidiaries in numerous countries throughout the world. Consequently, income taxes have been based on the laws and rates in effect in the countries in which operations are conducted, or in which we and our subsidiaries or our Predecessor and its subsidiaries were incorporated or otherwise considered to have a taxable presence. The change in the effective tax rate from period to period is primarily attributable to changes in the profitability mix of our operations in various jurisdictions. Because 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 and income before taxes.
Income before income taxes consists of the following:
 
 
Year Ended December 31,
(In thousands)
 
2014
 
2013
 
2012
United States
 
$
70,949

 
$
114,314

 
$
65,574

Non-U.S.
 
(648,360
)
 
331,596

 
109,351

Total
 
$
(577,411
)
 
$
445,910

 
$
174,925

The income tax provision consists of the following:
 
 
Year Ended December 31,
(In thousands)
 
2014
 
2013
 
2012
Current - United States
 
$
45,754

 
$
20,732

 
$
14,637

Current - Non-U.S.
 
43,115

 
55,691

 
49,108

Deferred - United States
 
(30,391
)
 
13,425

 
(13,179
)
Deferred - Non-U.S.
 
10,916

 
(4,243
)
 
(1,878
)
Total
 
$
69,394

 
$
85,605

 
$
48,688

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. With few exceptions, we are no longer subject to examinations of tax matters for years prior to 1999.
Our effective tax rate for the year ended December 31, 2014 was approximately -12%, on a pre-tax loss of $577 million. The negative effective tax rate was primarily driven by an impairment loss of $1.1 billion during the third and fourth quarters of 2014.
The Company is based in the U.K., which has a statutory rate of 21% as of December 31, 2014. However, the income of our non-U.K. subsidiaries is not expected to be subject to U.K. corporate tax. Prior to being based in the U.K., our Predecessor was based in Switzerland. Similar to the U.K., the income of our non-Swiss subsidiaries was not subject to tax in Switzerland. A reconciliation of tax rates outside of Switzerland and the U.K. to our effective rate is shown below:

82


 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Effect of:
 
 
 
 
 
 
Tax rates which are different than the U.K. and Swiss rates
 
(15.3
)%
 
17.4
 %
 
28.0
 %
Tax effect from asset impairment
 
4.3
 %
 
 %
 
 %
Change in valuation allowance
 
 %
 
2.0
 %
 
 %
Reserve for (resolution of) tax authority audits
 
(1.0
)%
 
(0.2
)%
 
(0.2
)%
Total
 
(12.0
)%
 
19.2
 %
 
27.8
 %
The components of the net deferred taxes are as follows:
(In thousands)
 
2014
 
2013
Deferred tax assets
 
 
 
 
Accrued expenses not currently deductible
 
$
3,556

 
$

Net operating loss carry forwards
 
22,645

 
43,409

Deferred tax assets
 
26,201

 
43,409

Less: Valuation allowance
 

 
(8,672
)
Net deferred tax assets
 
26,201

 
34,737

Deferred tax liabilities
 
 
 
 
Excess of net book basis over remaining tax basis of Property and equipment
 
(58,844
)
 
(122,581
)
Deferred taxes on unremitted earnings
 
(6,043
)
 

Contract market valuation
 
(5,434
)
 

Other
 
(838
)
 

Deferred tax liabilities
 
(71,159
)
 
(122,581
)
Net deferred tax liabilities
 
$
(44,958
)
 
$
(87,844
)
The deferred tax assets related to our net operating losses were generated in various tax jurisdictions. With the exception of the $13 million tax effect of our Mexico net operating losses which will expire between 2021 and 2022, our net operating losses do 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.
The following is a reconciliation of the liabilities related to our unrecognized tax benefits, excluding interest and penalties:
(In thousands)
 
2014
 
2013
 
2012
Gross balance at January 1,
 
$
32,336

 
$
37,969

 
$
44,188

Additions based on tax positions related to the current year
 
4,442

 
532

 
536

Additions for tax positions of prior years
 
1,424

 
4,599

 
2,430

Reductions for tax positions of prior years
 
(7,298
)
 
(214
)
 

Expiration of statutes
 
(1,225
)
 
(2,712
)
 
(3,130
)
Tax settlements
 

 
(7,838
)
 
(6,055
)
Gross balance at December 31,
 
29,679

 
32,336

 
37,969

Related tax benefits
 

 
(1,983
)
 
(6,590
)
Net balance at December 31,
 
$
29,679

 
$
30,353

 
$
31,379


83


The liabilities related to our unrecognized tax benefits are comprised of the following:
(In thousands)
 
2014
 
2013
Unrecognized tax benefits, excluding interest and penalties
 
$
29,679

 
$
30,353

Interest and penalties included in Other liabilities
 
10,517

 
6,137

Unrecognized tax benefits, including interest and penalties
 
$
40,196

 
$
36,490

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 $2 million in 2014, an income tax expense of $1 million in 2013 and an income tax expense of $4 million in 2012.
If recognized, $40 million of our unrecognized tax benefit would reduce our income tax provision as of December 31, 2014.
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 10—EMPLOYEE BENEFIT PLANS
During the periods prior to Spin-Off, most of our employees were eligible to participate in various Noble benefit programs. The results of our Predecessor in these consolidated and combined financial statements include an allocation of the costs of such employee benefit plans, consistent with the accounting for multi-employer plans. These costs were allocated based on our employee population for each of the periods presented. We consider the expense allocation methodology and results to be reasonable for all periods presented; however, the allocated costs included in the results of our Predecessor and included in these consolidated and combined financial statements could differ from amounts that would have been incurred by us if we operated on a standalone basis and are not necessarily indicative of costs to be incurred in the future.
We have instituted competitive compensation policies and programs, as well as carried over certain plans as a standalone public company, the expense for which may differ from the compensation expense allocated by Noble in our Predecessor’s historical combined financial statements.
Defined Benefit Plans
At Spin-Off, Noble sponsored two non-U.S. noncontributory defined benefit pension plans which were carried over by us and cover certain Europe-based salaried, non-union employees. Pension benefit expense related to these plans included in the accompanying consolidated and combined statements of income for the year ended December 31, 2014 totaled $6 million.

84


A reconciliation of the changes in projected benefit obligations (PBO) for our pension plans is as follows:
 
 
Year Ended December 31,
(In thousands)
 
2014
Benefit obligation at beginning of year
 
$
95,101

 Service cost
 
4,819

 Interest cost
 
2,601

 Actuarial loss (gain)
 
39,499

 Amendments
 
(139
)
 Benefits paid
 
(1,240
)
 Plan participants' contribution
 
512

 Foreign exchange rate changes
 
(14,806
)
 Other: curtailment
 
(1,985
)
Benefit obligation at end of year
 
$
124,362

A reconciliation of the changes in fair value of plan assets is as follows:
 
 
Year Ended December 31,
(In thousands)
 
2014
 Fair value of plan assets at beginning of year
 
$
97,453

 Actual return on plan assets
 
38,252

 Employer contribution
 
6,565

 Benefits paid
 
(833
)
 Plan participants' contributions
 
512

 Expenses paid
 
(407
)
 Foreign exchange rate changes
 
(15,951
)
 Fair value of plan assets at end of year
 
$
125,591

The funded status of the plans is as follows:
 
 
Year Ended December 31,
(In thousands)
 
2014
 Funded status
 
$
1,229

Amounts recognized in the consolidated and combined balance sheets consist of:
 
 
Year Ended December 31,
(In thousands)
 
2014
Other assets (noncurrent)
 
$
1,229

Accumulated other comprehensive loss recognized in financial statements
 
22,911

 Net amount recognized
 
$
24,140

Amounts recognized in Accumulated other comprehensive loss (“AOCL”) consist of:
 
 
Year Ended December 31,
(In thousands)
 
2014
Actuarial loss (gain)
 
$
20,539

Prior service cost (credit)
 
2,063

Deferred income tax
309

Accumulated other comprehensive loss
 
$
22,911


85


Pension cost includes the following components:
 
 
Year Ended December 31,
(In thousands)
 
2014
 Service cost
 
$
4,819

 Interest cost
 
2,601

 Return on plan assets
 
(2,625
)
 Amortization of Prior Service Cost
 
(16
)
 Amortization of transition obligation
 

 Amortization net actuarial loss (gain)
 
1,077

 Net curtailment (gain)
 
(66
)
 Net pension expense
 
$
5,790

Amortization related to prior service cost and net actuarial loss is estimated to be less than $1 million in 2015.
Defined Benefit Plans - Disaggregated Plan Information
Disaggregated information regarding our pension plans is summarized below:
 
 
Year Ended December 31,
(In thousands)
 
2014
 Projected benefit obligation
 
$
124,362

 Accumulated benefit obligation
 
119,632

 Fair value of plan assets
 
125,591

Defined Benefit Plans - Key Assumptions
The key assumptions for the plans are summarized below:
 
 
Year Ended December 31,
 Weighted Average Assumptions Used to Determine Benefit Obligations
 
2014
 Discount rate
 
 2.3% to 2.4%

 Rate of compensation increase
 
3.6
%
 
 
Year Ended December 31,
 Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost
 
2014
 Discount rate
 
 2.7% to 3.9%

 Expected long-term return on plan assets
 
 2.7% to 2.8%

 Rate of compensation increase
 
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
Both the Paragon Offshore Enterprise Ltd and the Paragon Offshore Nederland B.V. pension plans have a targeted asset allocation of 100% debt securities. The investment objective for Paragon Offshore Enterprise Ltd and Paragon Offshore Nederland

86


B.V. Non-US plans are to earn a favorable return against the Barclays Capital Euro - Treasury AAA 1 - 3 year benchmark. We evaluate the performance of this plan on an annual basis.
The actual fair value of our pension plans as of December 31, 2014 is as follows:
 
 
 
 
December 31, 2014
 
 
 
 
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)
Fixed Income securities:
 
 
 
 
 
 
 
 
Corporate Bonds
 
$
32,476

 
$

 
$
32,477

 
$

Other
 
93,115

 

 

 
93,115

Total
 
$
125,591

 
$

 
$
32,477

 
$
93,115

At December 31, 2014, assets of Paragon Offshore Enterprise Ltd and Paragon Offshore Nederland B.V. 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. Amounts were therefore calculated using actuarial assumptions completed by third party consultants employed by Noble. The following table details the activity related to these investments during the year.
 
 
Market Value
Balance as of December 31, 2013
 
$
68,280

Assets sold/benefits paid
 
(735
)
Return on plan assets
 
25,570

Balance as of December 31, 2014
 
$
93,115

Defined Benefit Plans - Cash Flows
In 2014, we made total contributions of $7 million to our pension plans. We expect our aggregate minimum contributions to our plans in 2015, subject to applicable law, to be $5 million. We continue to monitor and evaluate funding options based upon market conditions and may increase contributions at our discretion.
The following table summarizes our benefit payments at December 31, 2014 estimated to be paid within the next ten years:
 
 
 
Payments by Period
 
Total
 
2015
 
2016
 
2017
 
2018
 
2019
 
Five Years
Thereafter
Estimated benefit payments
$
18,490

 
868

 
993

 
1,168

 
1,390

 
1,618

 
12,453

Other Benefit Plans
At Spin-Off, Noble sponsored a 401(k) defined contribution plan and a profit sharing plan, which covered our Predecessor’s employees who are not otherwise enrolled in the above defined benefit plans. Other post-retirement benefit expense related to these plans included in the accompanying consolidated and combined statements of income during the five months ended December 31, 2014, not including amounts allocated to our Predecessor, totaled $2 million.
NOTE 11—DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Although we are a U.K. company, we define foreign currency as any non-U.S. denominated currency. Our functional currency is primarily the U.S. dollar. However, outside the United States, a portion of our expenses are incurred in local currencies. We are exposed to risks on future cash flows to the extent that local currency expenses exceed revenues denominated in local currencies that are other than the U.S. dollar. To help manage this potential risk, we periodically enter into derivative instruments to manage our exposure to fluctuations in foreign currency exchange rates, and we may conduct

87


hedging activities in future periods to mitigate such exposure. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
Cash Flow Hedges
Our North Sea, Mexico and Brazil operations have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we may periodically enter into forward contracts all of which would have a maturity of less than twelve months and would settle monthly in the operations’ respective local currencies. During 2014, we, entered into forward contracts, expressed in U.S. dollars, of approximately $58 million, all of which settled during the year. We had no outstanding derivative contracts and thus no unrealized gains recorded as a part of AOCL at both December 31, 2014 and 2013. See Note 13, Accumulated Other Comprehensive Loss for changes in AOCL related to our cash flow hedges. Subsequent to the Spin-Off, total realized losses related to these forward contracts were $14 thousand and were classified as “Contract drilling services operating costs and expenses” on the consolidated and combined statement of operations for the year ended December 31, 2014. As of December 31, 2014, these forward contracts are designated as cash flow hedging instruments.
For our foreign currency forward contracts, hedge effectiveness is evaluated at inception based on the matching of critical terms between derivative contracts and the hedged item. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. For the year ended December 31, 2014, no loss was recognized on our consolidated and combined statement of income due to hedge ineffectiveness. Additionally, there were no gains or losses recognized in income for the year ended December 31, 2014 as a result of excluding amounts from the assessment of hedge effectiveness or as a result of reclassifications to earnings following the discontinuance of any cash flow hedges.
Prospector Interest Rate Swaps Acquired
Our Prospector Credit Facility exposes Prospector to short-term changes in market interest rates as our interest obligations on these instruments are periodically redetermined based on the prevailing LIBOR rate. Upon our acquisition of Prospector, Prospector had interest rate swaps originally entered into by a subsidiary of Prospector on June 13, 2014 with an aggregate maximum notional amount of $135 million. The interest rate swaps were entered into to reduce the variability of the cash interest payments under the Prospector Senior Credit Facility and currently fix the interest on approximately $133 million, or 50%, of outstanding borrowings under the Prospector Credit Facility. Prospector receives interest at three-month LIBOR and pays interest at a fixed rate of 1.512% over the expected term of the Prospector Senior Credit Facility. We do not apply hedge accounting with respect to these interest rate swaps and therefore, changes in fair values were recognized as either income or loss in our consolidated and combined statement of income. The fair values of our interest rate swaps were determined based on a discounted cash flow model utilizing an appropriate market or risk-adjusted yield. The effects of discounting are generally considered insignificant for interest rate swaps. As of December 31, 2014, the change in fair value of the interest rate swaps recorded in Interest expense net of amount capitalized is a gain of $78 thousand. The interest rate swaps are measured and recorded on our consolidated and combined balance sheet at fair value. As of December 31, 2014, we had approximately $2 million recorded in Other current liabilities and approximately $1 million recorded in Other long-term assets related to the interest rate swaps (see Note 12, “Concentration of Market and Credit Risk”).

88


NOTE 12—CONCENTRATION OF MARKET AND CREDIT RISK
Fair Value of Financial Instruments
The following table presents the carrying amount and estimated fair value of our financial instruments recognized at fair value on a recurring basis:
 
December 31, 2014
 
 
 
Estimated Fair Value Measurement
 
Carrying
 
Quoted
Prices in
Active
Markets
 
Significant
Other
Observable
Inputs
 
Significant
Unobservable
Inputs
(In thousands)
Amount
 
(Level 1)
 
(Level 2)
 
(Level 3)
Assets -
 
 
 
 
 
 
 
Interest rate swaps
$
531

 
$

 
$
531

 
$

 
 
 
 
 
 
 
 
Liabilities -
 
 
 
 
 
 
 
Interest rate swaps
$
1,530

 
$

 
$
1,530

 
$

We had no outstanding foreign currency forward contracts at December 31, 2014. The fair values of our interest rate swaps were determined based on a discounted cash flow model utilizing an appropriate market or risk-adjusted yield. The effects of discounting are generally considered insignificant for interest rate swaps. 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 and combined balance sheets approximates fair value. For the estimated fair value of our long-term debt, refer to Note 7, “Debt.”
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.
Revenues from Petróleos Mexicanos accounted for approximately 16%, 19%, and 21% of our operating revenues in 2014, 2013 and 2012, respectively. Revenues from Petrobras accounted for approximately 23%, 17% percent, and 18% of our operating revenues in 2014, 2013, and 2012, respectively. No other customer accounted for more than ten percent of our operating revenues in 2014, 2013 or 2012.

89


NOTE 13—ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the components of Accumulated other comprehensive loss(AOCL) for the years ended December 31, 2014 and 2013 and changes in AOCL by component for the year ended December 31, 2014. All accounts within the tables are shown net of tax.
(In thousands)
 
Gains /
(Losses) on
 Cash Flow
Hedges (1)
 
Defined
Benefit
Pension Items (2)
 
Foreign
Currency
Items
 
Total
Balance at December 31, 2013
 
$

 
$

 
$
(6
)
 
$
(6
)
Activity during period:
 
 
 
 
 
 
 
 
AOCL recorded in connection with Spin-Off
 
4,027

 
(21,770
)
 
(12,706
)
 
(30,449
)
AOCL recorded in connection with Prospector acquisition
 

 

 
(40
)
 
(40
)
Other comprehensive loss before reclassification
 
(4,041
)
 

 
(1,481
)
 
(5,522
)
Amounts reclassified from AOCL
 
14

 
(1,141
)
 

 
(1,127
)
Net other comprehensive income (loss)
 
(4,027
)
 
(1,141
)
 
(1,481
)
 
(6,649
)
Balance at December 31, 2014
 
$

 
$
(22,911
)
 
$
(14,233
)
 
$
(37,144
)
(1)
Gains / (losses) on cash flow hedges are related to our foreign currency forward contracts. Reclassifications from AOCL are recognized through “Contract drilling services operating costs and expenses” on our consolidated and combined statements of income. See Note 11, “Derivative instruments and hedging activities” for additional information.
(2)
Defined benefit pension items relate to actuarial losses, prior service credits, and the amortization of actuarial losses and prior service credits. Reclassifications from AOCL are recognized as expense on our consolidated and combined statements of income through either “Contract drilling services” or “General and administrative.” See Note 10, “Employee benefit plans” for additional information.
NOTE 14—DEFERRED REVENUES AND COSTS
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.
Deferred revenues from drilling contracts totaled $9 million at December 31, 2014 as compared to $22 million at December 31, 2013. Such amounts are included in either “Other current liabilities” or “Other liabilities” in our consolidated and combined balance sheets, based upon the expected time of recognition of such deferred revenues. Deferred costs associated with deferred revenues from drilling contracts totaled $2 million at December 31, 2014 as compared to $24 million at December 31, 2013. Such amounts are included in either “Prepaid and other current assets” or “Other assets” in our consolidated and combined balance sheets, based upon the expected time of recognition of such deferred costs.

90


NOTE 15—COMMITMENTS AND CONTINGENCIES
Operating Leases
Future minimum lease payments for operating leases for years ending December 31 are as follows (in thousands):
2015
$
14,734

2016
$
10,871

2017
$
4,494

2018
$
2,596

2019
$
2,032

Thereafter
$
3,462

Total rent expense under operating leases was approximately $16 million for the year ended December 31, 2014.
Purchase Commitments
At December 31, 2014, our purchase commitments which consist of obligations outstanding to external vendors primarily related to future capital purchases, were as follows (in thousands):
2015
$
454,098

2016
$
199,161

Litigation
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.
Other Contingencies
We have received tax audit claims of approximately $267 million, of which $50 million is subject to indemnity by Noble, primarily in Mexico and Brazil, attributable to our income, customs and other business taxes. In addition, approximately $37 million of tax audit claims attributable to Mexico assessed against Noble may be allocable to us as a result of the Spin-Off. 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. In some cases we will be required to post a surety bond or a letter of credit as collateral to defend us. Although we have no surety bonds or letters of credit associated with tax audit claims outstanding as of December 31, 2014, we could be required to post collateral against our Mexico assessments during 2015, which could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.
In addition, Petróleo Brasileiro S.A. (“Petrobras”) has notified us, along with other industry participants, that it is currently challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs for its operations in Brazil during the years 2008 and 2009 totaling $106 million, of which $30 million is subject to indemnity by Noble. Petrobras has also notified us that if they must pay such withholding taxes, they will seek reimbursement from us. We believe that we are contractually indemnified by Petrobras for these amounts and dispute the validity of the assessment. We have notified Petrobras of our position. We will, if necessary, vigorously defend our rights. If we were required to pay such reimbursement, however, the amount of such reimbursement could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.
In January 2015, a subsidiary of Noble received an unfavorable ruling from the Mexican Supreme Court on a tax depreciation position claimed in periods prior to the Spin-Off. Although the ruling does not constitute mandatory jurisprudence in Mexico, it does create potential indemnification exposure for us under the tax sharing agreement. Noble

91


is the primary obligor to the Mexican tax authorities and, to our understanding, has yet to decide on a course of action in this matter, which could include an appeal against this ruling. As a result, while we are in discussions with Noble, we are presently unable to determine next steps or a timeline on this matter; nor are we able to determine the extent of our liability. We have considered this matter under ASC 460, Guarantees, and concluded that our liability under this matter is reasonably possible. Due to these current uncertainties, we are not able to reasonably estimate a loss at this time.
Insurance
In connection with the Separation, we replaced our Predecessor’s insurance policies, which were supported by Noble, with substantially similar standalone insurance policies. We maintain certain insurance coverage against specified marine perils, which included physical damage and loss of hire. Damage caused by hurricanes has negatively impacted the energy insurance market, resulting in more restrictive and expensive coverage for named windstorm perils.
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. 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.
Capital Expenditures
In connection with our capital expenditure program, we have outstanding commitments, including shipyard and purchase commitments of approximately $653 million at December 31, 2014.
Other
At December 31, 2014, we had letters of credit of $21 million and performance bonds totaling $110 million supported by surety bonds outstanding. Certain of our subsidiaries issued guarantees to the temporary import status of rigs or equipment imported into certain countries in which we operated. These guarantees are issued in lieu of payment of custom, value added or similar taxes in those countries.
Separation Agreements
In connection with the Spin-off, on July 31, 2014, we entered into several definitive agreements with Noble or its subsidiaries that, among other things, set forth the terms and conditions of the Spin-Off and provide a framework for our 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.

92


Pursuant to these agreements with Noble, the consolidated and combined balance sheet consists of the following balances due from and to Noble as of December 31, 2014 (in thousands):
Balance Sheet Position
Amount
Other current assets
$
26,386

Other assets
6,875

Due from Noble
$
33,261

 
 
Accounts payable
$
1,655

Other current liabilities
51,169

Other liabilities
23,563

Due to Noble
$
76,387

These receivables and payables primarily relate to rights and obligations under the Tax Sharing Agreement.
Master Separation Agreement
On July 31, 2014, we entered into a Master Separation Agreement with Noble Corporation, a Cayman Islands company and an indirect, wholly-owned subsidiary of Noble (“Noble-Cayman”), which provided for, among other things, the Distribution of our ordinary shares to Noble shareholders and the transfer to us of the assets and the assumption by us of the liabilities relating to our business and the responsibility of Noble for liabilities related to Noble’s, and in certain limited cases, our business. The Master Separation Agreement identified which assets and liabilities constitute our business and which assets and liabilities constitute Noble’s business.
Tax Sharing Agreement
On July 31, 2014, we entered into a Tax Sharing Agreement with Noble, which governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and certain other matters regarding taxes following the Distribution.
Employee Matters Agreement
On July 31, 2014, we entered into an Employee Matters Agreement with Noble-Cayman to allocate liabilities and responsibilities relating to our employees and their participation in certain compensation and benefit plans maintained by Noble or a subsidiary of Noble. The Employee Matters Agreement provides that, following the Distribution, most of our employee benefits are provided under compensation and benefit plans adopted or assumed by us. In general, our plans are substantially similar to the plans of Noble or its subsidiaries that covered our employees prior to the completion of the Distribution. The Employee Matters Agreement also addresses the treatment of outstanding Noble equity awards held by transferring employees, including the grant of our equity awards or other rights with respect to Noble equity awards held by transferring employees that were canceled in connection with the Spin-Off.
Transition Services Agreement
On July 31, 2014, we entered into a Transition Services Agreement with Noble-Cayman pursuant to which Noble-Cayman provides, on a transitional basis, certain administrative and other assistance, generally consistent with the services that Noble provided to us before the separation, and we provide certain transition services to Noble and its subsidiaries. The charges for the transition services are generally intended to allow the party providing the services to fully recover the costs directly associated with providing the services, plus all out-of-pocket costs and expenses, generally without profit. The charges for each of the transition services generally are based on either a pre-determined flat fee or an allocation of the costs incurred, including certain fees and expenses of third-party service providers.
Transition Services Agreement (Brazil)
On July 31, 2014, we and Noble-Cayman and certain other subsidiaries of Noble entered into a Transition Services Agreement (and a related rig charter) pursuant to which we will provide certain transition services to Noble and its subsidiaries

93


in connection with Noble’s Brazil operations. We will continue to provide both rig-based and shore-based support services in respect of Noble’s remaining business through the term of Noble’s existing rig contracts. Noble currently has one rig operating in Brazil. Noble-Cayman will compensate us on a cost-plus basis for providing such services and also indemnify us for liabilities arising out of the services agreement. This agreement will terminate when the last of the Noble semisubmersibles working in Brazil finish the existing contract, which is expected to occur in 2016.
NOTE 16—RELATED PARTIES (INCLUDING RELATIONSHIP WITH PARENT AND CORPORATE ALLOCATIONS)
For all periods prior to the Spin-Off, our Predecessor was managed in the normal course of business by Noble and its subsidiaries. Accordingly, certain shared costs have been allocated to our Predecessor and are reflected as expenses in these combined financial statements for periods prior to Spin-Off. Our management considers the allocation methodologies used to be reasonable and appropriate reflections of the related expenses attributable to us for purposes of the carve-out financial statements; however, the expenses reflected in the results of our Predecessor and included in these consolidated and combined financial statements may not be indicative of the actual expenses that would have been incurred during the periods presented if our Predecessor had operated as a separate standalone entity and may not be indicative of expenses that will be incurred in the future by us.
Allocated costs include, but are not limited to: corporate accounting, human resources, information technology, treasury, legal, employee benefits and incentives (excluding allocated postretirement benefits described in “Note 10, Employee Benefit Plans,”) and stock-based compensation. Our Predecessor’s allocated costs included in contract drilling services in the accompanying consolidated and combined statements of income totaled $70 million, $147 million, and $113 million for the years ended December 31, 2014, 2013, and 2012, respectively. Our Predecessor’s allocated costs included in general, and administrative expenses in the accompanying consolidated and combined statements of income totaled $25 million, $58 million, and $53 million for the years ended December 31, 2014, 2013, and 2012 respectively. The costs were allocated to our Predecessor using various inputs, such as head count, services rendered, and assets assigned to our Predecessor.
NOTE 17—SEGMENT AND RELATED INFORMATION
At December 31, 2014, 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 operated 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 conducts contract drilling operations in Mexico, Brazil, the North Sea, West Africa, the Middle East, India, and Southeast Asia.

94


Operations by Geographic Area
The following table presents revenues and identifiable assets by country based on the location of the service provided:
 
 
Revenues
 
Identifiable Assets
 
 
Year Ended December 31,
 
As of December 31,
(In thousands)
 
2014
 
2013
 
2012
 
2014
 
2013
Country:
 
 
 
 
 
 
 
 
 
 
Mexico
 
$
326,352

 
$
367,732

 
$
320,436

 
$
472,032

 
$
351,123

Brazil
 
488,884

 
312,287

 
284,061

 
1,863,774

 
1,864,358

United Kingdom
 
193,908

 
245,789

 
141,435

 
90,410

 
196,479

The Netherlands
 
284,651

 
179,768

 
210,577

 
169,088

 
112,561

Qatar
 
94,320

 
139,891

 
74,889

 
96,702

 
130,515

United States
 
85,060

 
117,951

 
105,469

 
94,391

 
712,713

United Arab Emirates
 
139,318

 
108,256

 
79,940

 
228,284

 
152,699

Nigeria
 

 
107,750

 
148,961

 
11,308

 
54,539

India
 
79,201

 
103,282

 
58,355

 
135,909

 
200,799

Other
 
302,068

 
210,296

 
117,734

 
91,491

 
207,013

 
 
$
1,993,762

 
$
1,893,002

 
$
1,541,857

 
$
3,253,389

 
$
3,982,799

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION
The net effect of changes in other assets and liabilities on cash flows from operating activities is as follows:
 
 
Year Ended December 31,
(In thousands)
 
2014
 
2013
 
2012
Accounts receivable
 
$
(178,108
)
 
$
(34,582
)
 
$
(116,714
)
Other current assets
 
42,922

 
22,181

 
(2,941
)
Other assets
 
(33,637
)
 
16,451

 
39,484

Accounts payable
 
25,890

 
8,530

 
(12,485
)
Other current liabilities
 
14,273

 
18,645

 
4,562

Other liabilities
 
(29,514
)
 
(16,385
)
 
(4,920
)
Net change in other assets and liabilities
 
$
(158,174
)
 
$
14,840

 
$
(93,014
)
Additional cash flow information is as follows:
 
 
Year Ended December 31,
(In thousands)
 
2014
 
2013
 
2012
Cash paid during the period for:
 
 
 
 
 
 
Interest, net of amounts capitalized
 
$
21,109

 
$
5,791

 
$
3,856

U.S. and Non-U.S. income taxes
 
85,248

 
76,423

 
63,745

Non-cash activities:
 
 
 
 
 
 
Increase (decrease) in accounts payable and accrued liabilities related to capital expenditures
 
$
1,230

 
$
(12,365
)
 
$
(8,463
)
NOTE 19—NEW ACCOUNTING PRONOUCEMENTS
In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-08, “Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity,” which amends FASB Accounting Standards Codification (“ASC”) Topic 205, “Presentation of Financial Statements” and ASC Topic 360, “Property, Plant, and Equipment.” This ASU alters the definition of a discontinued operation to cover only asset disposals

95


that are a strategic shift with a major effect on an entity’s operations and finances, and calls for more extensive disclosures about a discontinued operation’s assets, liabilities, income and expenses. The guidance is effective for all disposals, or classifications as held-for-sale, of components of an entity that occur within annual periods, and interim periods within those annual periods, beginning on or after December 15, 2014. We do not expect that our adoption will have a material impact on our financial statements or disclosures in our financial statements.
In May 2014, the FASB issued ASU No. 2014-09, which amends ASC Topic 606, “Revenue from Contracts with Customers.” 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. The amendments in this accounting standard update are effective for interim and annual reporting periods beginning after December 15, 2016. We are evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.
In June 2014, the FASB issued ASU No. 2014-12, which amends ASC Topic 718, “Compensation–Stock Compensation.” The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in the estimate of the grant-date fair value of the award. The guidance is effective for annual periods beginning after December 15, 2015. The guidance can be applied prospectively for all awards granted or modified after the effective date or retrospectively to all awards with performance targets outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. We are evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.
In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements – Going Concern.” This ASU codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. The guidance is effective for interim and annual periods ending after December 15, 2016 and early adoption is permitted. We still evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.
In January 2015, the FASB issued ASU 2015-01, “Income Statement – Extraordinary and Unusual Items.” This ASU simplifies income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. The guidance is effective for interim and annual periods ending after December 15, 2015 and early adoption is permitted. We do not expect that our adoption will have a material impact on our financial statements or disclosures in our financial statements.

96


NOTE 20—UNAUDITED INTERIM FINANCIAL DATA
Summarized quarterly results for years ended December 31, 2014 and 2013 are as follows:
 
 
Quarter Ended
(In thousands, except per share amounts)
 
March 31
 
June 30
 
September 30
 
December 31
2014
 
 
 
 
 
 
 
 
Operating revenues
 
$
514,590

 
$
478,957

 
$
505,222

 
$
494,993

Operating income (loss)
 
147,461

 
119,972

 
(796,421
)
 
4,311

Net income (loss) attributable to Paragon Offshore
 
124,566

 
95,045

 
(869,160
)
(2)
2,803

Earnings (loss) per share -
basic and diluted (1)
 
$
1.47

 
$
1.12

 
$
(10.26
)
(3)
$
0.03

 
 
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
 
 
Operating revenues
 
$
454,070

 
$
464,945

 
$
489,682

 
$
484,305

Operating income
 
102,601

 
106,143

 
187,240

 
57,761

Net income
 
82,572

 
82,544

 
157,635

 
37,555

Earnings per share -
basic and diluted (1)
 
$
0.97

 
$
0.97

 
$
1.86

(3)
$
0.44

(1)
Earnings (loss) per share is computed independently for each of the quarters presented. Therefore, the sum of the quarters’ net income per share may not equal the total computed for the year.
(2)
Net income for the three month period ended September 30, 2014 has been revised to correct an error related to the amortization of our deferred tax liability related to the Paragon DPDS1. In connection with the impairment of the Paragon DPDS1 during the third quarter, a tax benefit should have been recorded to proportionally eliminate the deferred tax liability specifically related to the Paragon DPDS1.  The third quarter tax provision as reported was $75.7 million and after revision for this additional non-cash tax benefit of $25.1 million, or $0.28 per diluted share, the tax provision was revised to $50.6 million. This revision also changes the reported net loss from $894.2 million to an as revised $869.2 million of net loss for the third quarter. We have concluded that this misstatement was not material to our consolidated and combined financial statements for the aforementioned prior period.
(3)
Earnings per share - basic and diluted for the three month period ended September 30, 2014 and 2013 has been revised to correct an error related to the allocation of unvested share-based awards. No earnings should have been allocated to unvested share-based payment awards in our earnings per share calculation due to our net loss in the three months ended September 30, 2014. Our basis of presentation related to weighted average unvested shares outstanding for all periods prior to the Spin-Off should not include our unvested restricted stock units that were granted to our employees in conjunction with Paragon's 2014 Employee Omnibus Incentive Plan.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Randall D. Stilley, President, Chief Executive Officer, and Director of Paragon, and Steven A. Manz, Senior Vice President and Chief Financial Officer of Paragon, under the supervision and with the participation of our management, have evaluated the disclosure controls and procedures of Paragon as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal

97


executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Our controls over restricted access and segregation of duties within the legacy SAP system were improperly designed and not effective as certain personnel have the ability to prepare and post journal entries without an independent review required by someone other than the preparer. Specifically, the controls as designed did not provide reasonable assurance that incompatible access within the system, including the ability to record transactions, was appropriately segregated, impacting the accuracy and completeness of all key accounts and disclosures. This control deficiency did not result in any adjustments to the consolidated financial statements for the year ended December 31, 2014. However, the deficiency could result in misstatements to key accounts and disclosures that would result in a material misstatement of the consolidated financial statements that would not be prevented or detected. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

In light of the material weakness described above, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2014.

We are in the process of remediating the material weakness by implementing changes in our controls over restricted access and segregation of duties within the SAP systems.  Until we are able to implement the newly designed controls and test their operational effectiveness, we will not be able to conclude the material weakness has been remediated.

Management's Annual Report on Internal Control over Financial Reporting and Attestation Report of the Independent Registered Public Accounting Firm
Our management, with the participation of our principal executive and principal financial officers, will not be required to evaluate the effectiveness of our internal controls over financial reporting until the filing of our 2015 Annual Report on Form 10-K, due to a transition period established by the SEC rules applicable to new public companies. Therefore, this Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

Changes in Internal Control over Financial Reporting
There were no changes in Paragon's internal control over financial reporting that occurred during the quarter ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
ITEM 9B.
OTHER INFORMATION
None.

98


PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The sections entitled “Election of Directors”, “Additional Information Regarding the Board of Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, and “Other Matters” appearing in the proxy statement for the 2015 annual general meeting of shareholders (the “2015 Proxy Statement”), will set forth certain information with respect to directors, certain corporate governance matters and reporting under Section 16(a) of the Securities Exchange Act of 1934, and are incorporated in this report by reference.
Executive Officers of the Registrant
The following table sets for certain information as of February 27, 2015 with respect to our executive officers:
Name
 
Age
 
Position
Randall D. Stilley
 
61
 
President, Chief Executive Officer and Director
Steven A. Manz
 
49
 
Senior Vice President and Chief Financial Officer
William C. Yester
 
64
 
Senior Vice President - Operations
Lee M. Ahlstrom
 
47
 
Senior Vice President - Investor Relations, Strategy, and Planning
Andrew W. Tietz
 
48
 
Senior Vice President - Marketing and Contracts
Todd D. Strickler
 
37
 
Vice President - General Counsel and Corporate Secretary
Julie A. Ferro
 
43
 
Vice President - Human Resources
Randall D. Stilley was named President and Chief Executive Officer effective August 1, 2014. Mr. Stilley served as Executive Vice President of Noble Drilling Services, Inc from February 2014 to July 2014. From May 2011 to February 2014, Mr. Stilley served as an independent business consultant and managed private investments. Mr. Stilley served as President and Chief Executive Officer of Seahawk Drilling, Inc. from August 2009 to May 2011 and Chief Executive Officer of the mat-supported jackup rig business at Pride International Inc. from September 2008 to August 2009. Seahawk Drilling filed for reorganization under Chapter 11 of the United States Bankruptcy Code in 2011. From October 2004 to June 2008, Mr. Stilley served as President and Chief Executive Officer of Hercules Offshore, Inc. Prior to that, Mr. Stilley was Chief Executive Officer of Seitel, Inc., an oilfield services company, President of the Oilfield Services Division at Weatherford International, Inc., and served in a variety of positions at Halliburton Company. He is a registered professional engineer in the State of Texas and a member of the Society of Petroleum Engineers. Mr. Stilley holds a Bachelor of Science degree in Aerospace Engineering from the University of Texas at Austin.
Steven A. Manz was named Senior Vice President and Chief Financial Officer effective August 1, 2014. Mr. Manz has more than 25 years of experience in the offshore drilling and financial services industries. From 1995 to 2005, Mr. Manz served in a variety of management roles at Noble Corporation, including Managing Director, Noble Technology Services Division, Vice President of Strategic Planning, and Director of Accounting and Investor Relations. Most recently Mr. Manz served at Prospector Offshore Drilling S.A., Seahawk Drilling, Inc. and Hercules Offshore, Inc., where he held the position of Chief Financial Officer of each company. Mr. Manz holds a Bachelor of Business Administration degree in Finance from the University of Texas at Austin.
William C. Yester was named Senior Vice President of Operations effective August 1, 2014. Mr. Yester has more than 40 years of experience in the drilling business, with more than 22 years in offshore operations, and has been employed with Noble in a number of operational roles since 1996. He has served most recently as Vice President –Division Manager (Africa) and prior to that, Vice President – Division Manager (Middle East and India). Mr. Yester began his career with Noble in 1974, and from 1990 to 1994 served as a Division Manager with Helmerich and Payne International Drilling Company. In 1994-1995 he held a number of operational roles with Triton Engineering Company before returning to Noble in 1995. Mr. Yester holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.
Lee M. Ahlstrom was named Senior Vice President of Investor Relations, Strategy and Planning effective August 1, 2014. Mr. Ahlstrom has more than 20 years of experience in the oil and gas industry. He has served as Senior Vice President – Strategic Development of Noble since May 2011 and was Vice President of Investor Relations and Planning of Noble from May 2006 to May 2011. Prior to joining Noble, Mr. Ahlstrom served as Director of Investor Relations at Burlington

99


Resources, held various management positions at UNOCAL Corporation and served as an Engagement Manager with McKinsey & Company. Mr. Ahlstrom began his career with Exxon, where he held a variety of surface and subsurface engineering positions. He holds Bachelor of Science and master’s degrees in Mechanical Engineering from the University of Delaware.
Andrew W. Tietz was named Senior Vice President of Marketing and Contracts effective August 1, 2014. Mr. Tietz has more than 20 years of experience in the offshore drilling industry. He has served as Vice President – Marketing and Contracts of Noble since May 2010 and was Director – Marketing and Contracts from December 2009 to April 2010. Prior to joining Noble, Mr. Tietz served as Director – Marketing and Business Development for Transocean Ltd. He served in various marketing and finance positions with Transocean and GlobalSantaFe and Global Marine, prior to their mergers with Transocean, including positions in Dubai, Egypt and Kuala Lumpur. Mr. Tietz holds a Bachelor of Science-Finance degree from the University of Colorado – Boulder and a Master of Business Administration degree from the University of St. Thomas.
Todd D. Strickler was named Vice President, General Counsel and Corporate Secretary effective August 1, 2014. Mr. Strickler has more than 15 years of experience in the offshore and legal services industries. He has served as Associate General Counsel – Corporate of Noble since January 2013 and was Senior Counsel for Noble since February 2009. Prior to his joining Noble, he specialized in corporate and securities law at the law firm of Andrews Kurth LLP. Mr. Strickler holds a Bachelor of Science degree in Mechanical Engineering from the University of Texas at Austin and a Juris Doctorate from the University of Texas School of Law.
Julie A. Ferro was named Vice President of Human Resources effective January 12, 2015.  Ms. Ferro previously served as Vice President of Human Resources at Endeavour International Corporation from May 2011 until December 2014 and served Longnecker and Associates from April 2008 until May 2011. Ms. Ferro has over 18 years of experience in human resources, serving in human resources management roles for public and private companies in the energy and commercial real estate industries.  Ms. Ferro also spent three years as a managing director for a leading compensation consulting firm in Houston.   Ms. Ferro holds Bachelor of Arts degree from the University of Houston, and is a Certified Compensation Professional, a Certified Executive Compensation Professional, a Certified Equity Professional, and a Certified Professional in Human Resources.
ITEM 11.    EXECUTIVE COMPENSATION
The sections entitled “Executive Compensation” and “Compensation Committee Report” appearing in the 2015 Proxy Statement set forth certain information with respect to the compensation of our management and our compensation committee report, and are incorporated in this report by reference.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The sections entitled “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” appearing in the 2015 Proxy Statement set forth certain information with respect to securities authorized for issuance under equity compensation plans and the ownership of our voting securities and equity securities, and are incorporated in this report by reference.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The sections entitled “Additional Information Regarding the Board of Directors—Board Independence” and “Policies and Procedures Relating to Transactions with Related Persons” appearing in the 2015 Proxy Statement set forth certain information with respect to director independence and transactions with related persons, and are incorporated in this report by reference.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The section entitled “Auditors” appearing in the 2015 Proxy Statement sets forth certain information with respect to accounting fees and services, and is incorporated in this report by reference.

100


PART IV
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENTS
(1)
Financial Statements –
Our Consolidated and Combined Financial Statements, together with the notes thereto and the report of PricewaterhouseCoopers LLP dated March 12, 2015, was included in Item 8 of this Form 10-K.
(2)
Financial Statement Schedules –
All financial statement schedules have been omitted because they are not applicable or not required, the information is not significant, or the information is presented elsewhere in the financial statements.
(3)
Exhibits –
The information required by this Item 15(a)(3) is set forth in the Index to Exhibits accompanying this Annual Report on Form 10-K and is incorporated herein by reference.

101


SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Paragon Offshore plc, a company registered under the laws of England and Wales
Date:
March 12, 2015
 
By:
/s/ Randall D. Stilley
 
 
 
 
 
Randall D. Stilley
 
 
 
 
 
President, Chief Executive Officer and Director
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.  
Signature
 
Capacity In Which Signed
Date
 
 
 
 
/s/ Randall D. Stilley
 
President, Chief Executive Officer and Director
March 12, 2015
Randall D. Stilley
 
(Principal Executive Officer)
 
 
 
 
 
/s/ Steven A. Manz
 
Senior Vice President and Chief Financial Officer
March 12, 2015
Steven A. Manz
 
(Principal Financial and Accounting Officer)
 
 
 
 
 
/s/ J. Robinson West
 
Director
March 12, 2015
J. Robinson West
 
 
 
 
 
 
 
/s/ Anthony R. Chase
 
Director
March 12, 2015
Anthony R. Chase
 
 
 
 
 
 
 
/s/ Thomas L. Kelly II
 
Director
March 12, 2015
Thomas L. Kelly II
 
 
 
 
 
 
 
/s/ John P. Reddy
 
Director
March 12, 2015
John P. Reddy
 
 
 
 
 
 
 
/s/ Julie J. Robertson
 
Director
March 12, 2015
Julie J. Robertson
 
 
 
 
 
 
 
/s/ Dean E. Taylor 
 
Director
March 12, 2015
Dean E. Taylor
 
 
 
 
 
 
 
/s/ William L. Transier
 
Director
March 12, 2015
William L. Transier
 
 
 
 
 
 
 
/s/ David W. Wehlmann
 
Director
March 12, 2015
David W. Wehlmann
 
 
 

102


Index to Exhibits
 
Number
 
Description
 
2.1
 
Master Separation Agreement, dated as of July 31, 2014, between Noble Corporation and Paragon Offshore plc (incorporated by reference to Exhibit 2.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
3.1
 
Articles of Association of Paragon Offshore plc (incorporated by reference to Exhibit 3.1 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
 
4.1
 
Senior Secured Revolving Credit Agreement dated as of June 17, 2014 among Paragon Offshore Limited, Paragon International Finance Company, the Lenders from time to time parties thereto; JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and an Issuing Bank; Deutsche Bank Securities Inc. and Barclays Bank PLC, as Syndication Agents; and J.P. Morgan Securities LLC, Deutsche Bank Securities Inc. and Barclays Bank PLC, as Joint Lead Arrangers and Joint Lead Bookrunners (incorporated by reference to Exhibit 4.1 to Paragon Offshore Limited’s Registration Statement on Form 10 filed on July 3, 2014).
 
4.2
 
Indenture, dated as of July 18, 2014, by and among Paragon Offshore plc, the guarantors listed therein, Deutsche Bank Trust Company Americas, as trustee, and Deutsche Bank Luxembourg S.A., as paying agent and transfer agent (incorporated by reference to Exhibit 4.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on July 22, 2014).
 
4.3
 
Senior Secured Term Loan Credit Agreement, dated as of July 18, 2014, by and among Paragon Offshore plc, as parent guarantor, Paragon Offshore Finance Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on July 22, 2014).
 
10.1
 
Tax Sharing Agreement, dated as of July 31, 2014, between Noble Corporation plc and Paragon Offshore plc (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.2
 
Employee Matters Agreement, dated as of July 31, 2014, between Noble Corporation and Paragon Offshore plc (incorporated by reference to Exhibit 10.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.3
 
Transition Services Agreement, dated as of July 31, 2014, between Noble Corporation and Paragon Offshore plc (incorporated by reference to Exhibit 10.3 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.4
 
Transition Services Agreement (Brazil), dated as of July 31, 2014, among Paragon Offshore do Brasil Limitada, Paragon Offshore (Nederland) B.V., Paragon Offshore plc, Noble Corporation, Noble Dave Beard Limited and Noble Drilling (Nederland) II B.V. (incorporated by reference to Exhibit 10.4 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.5†
 
Paragon Offshore plc 2014 Employee Omnibus Incentive Plan (incorporated by reference to Exhibit 10.5 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.6†
 
Paragon Offshore plc 2014 Director Omnibus Plan (incorporated by reference to Exhibit 10.6 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.7†
 
Paragon Grandfathered 401(k) Savings Restoration Plan (incorporated by reference to Exhibit 10.7 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.8†
 
Paragon 401(k) Savings Restoration Plan (incorporated by reference to Exhibit 10.8 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.9†
 
Form of Deeds of Indemnity between Paragon Offshore plc and certain directors and officers (incorporated by reference to Exhibit 10.9 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
 
10.10†
 
Paragon Offshore Services LLC 2014 Short-Term Incentive Program (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 18, 2014).
 
10.11†
 
Form of Change of Control Agreement between Paragon Offshore plc and certain officers thereof (incorporated by reference to Exhibit 10.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 18, 2014).
 
10.12†
 
Form of Performance Vested Restricted Stock Unit Replacement Award Agreement (incorporated by reference to Exhibit 10.12 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
 
10.13†
 
Form of Time Vested Restricted Stock Unit Replacement Award Agreement (incorporated by reference to Exhibit 10.13 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
 
10.14†
 
Form of Employee Time Vested Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.14 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
 
10.15†
 
Form of Director Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.15 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
 
10.16
 
Form of Share Purchase Agreement, dated November 17, 2014, between Paragon Offshore plc and each seller party thereto (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on November 19, 2014).
 
10.17†
 
Paragon Offshore Executive Bonus Plan, dated February 19, 2015 (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc's Current Report on Form 8-K filed on February 25, 2015).
 
10.18†
 
Form of Time Vested Stock Unit Award Agreement, dated February 19, 2015 (incorporated by reference to Exhibit 10.2 to Paragon Offshore plc's Current Report on Form 8-K filed on February 25, 2015).
 
10.19†
 
Form of Performance Vested Restricted Stock Unit Award Agreement, dated February 19, 2015 (incorporated by reference to Exhibit 10.3 to Paragon Offshore plc's Current Report on Form 8-K filed on February 25, 2015).
 
21.1*
 
List of Subsidiaries of Paragon Offshore plc.
 
23.1*
 
Consent of Independent Registered Public Accounting Firm
 
31.1*
 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
31.2*
 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
32.1**
 
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
32.2**
 
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
101.INS*
 
XBRL Instance Document
 
101.SC*
 
XBRL Schema Document
 
101.CA*
 
XBRL Calculation Linkbase Document
 
101.DE*
 
XBRL Definition Linkbase Document
 
101.LA*
 
XBRL Label Linkbase Document
 
101.PR*
 
XBRL Presentation Linkbase Document
 

*
Filed herewith.
**
Furnished herewith.
Management contract or compensatory plan or arrangement.

103


Exhibit 21.1


Paragon Offshore plc Subsidiaries

Name
Country
Nature of business
Arktik Drilling Limited, Inc.
Bahamas
JV company; rig owner
Bawden Drilling Inc.
Delaware
Dormant
Bawden Drilling International Ltd.
Bermuda
Dormant
Frontier Discoverer Kft.
Hungary
Service company
Frontier Drilling do Brasil Ltda
Brazil
Dormant
Frontier Drilling Nigeria Limited
Nigeria
Contracting entity
Frontier Drilling Services Ltda
Brazil
Operator
Frontier Offshore Exploration India Limited
India
JV company; dormant
Kulluk Arctic Services, Inc.
Delaware
Dormant
Noble Drilling Nigeria Limited
Nigeria
Rig owner;
contracting entity
Paragon (Middle East) Limited
Cayman Islands
Rig owner
Paragon (Seillean) KS
Norway
Operator, rig owner
Paragon Asset (M E) Ltd.
Cayman Islands
Rig owner
Paragon Asset (U K) Ltd.
Cayman Islands
Contracting entity
Paragon Asset Company Ltd.
Cayman Islands
Rig owner
Paragon Drilling Services 7 LLC
Delaware
Rig owner
Paragon Drilling Ven, C.A.
Venezuela
Dormant
Paragon Duchess Ltd.
Cayman Islands
Holding company, rig owner
Paragon FDR Holdings Ltd.
Cayman Islands
Holding company
Paragon Holding NCS 2 S.à r.l.
Luxembourg
Holding company
Paragon Holding SCS 1 Ltd.
Cayman Islands
Holding company
Paragon Holding SCS 2 Ltd.
Cayman Islands
Holding company
Paragon International Finance Company
Cayman Islands
Financing company
Paragon Leonard Jones LLC
Delaware
Contracting entity
Paragon Offshore (Asia) Pte Ltd
Singapore
Administration,
office services
Paragon Offshore (Canada) Ltd.
Canada
Platform service company
Paragon Offshore (GOM) Inc.
Delaware
Contracting entity
Paragon Offshore (Labuan) Pte. Ltd.
Malaysia
Operator;
leasing company
Paragon Offshore (Land Support) Limited
Scotland
Logistic support for North Sea Operations
Paragon Offshore (Luxembourg) S.à r.l.
Luxembourg
Rig owner
Paragon Offshore (Nederland) B.V.
The Netherlands
Contracting entity; administration; operator - Brazil
Paragon Offshore (North Sea) Ltd.
Cayman Islands
Contracting entity
Paragon Offshore AS
Norway
Holding company, dormant
Paragon Offshore Brasil Investimentos Participasões Ltda.
Brazil
Holding company, rig guarantor
Paragon Offshore Contracting GmbH
Switzerland
Contracting entity
Paragon Offshore do Brasil Ltda.
Brazil
Personnel; administration;
contracting entity
Paragon Offshore Drilling (Cyprus) Limited
Cyprus
Dormant
Paragon Offshore Drilling AS
Norway
Holding company
 
 
 



Exhibit 21.1


Name
Country
Nature of business
Paragon Offshore Drilling LLC
Delaware
Holding company; rig owner
Paragon Offshore Enterprises Ltd.
Cayman Islands
Payroll/personnel entity for North Sea Operations
Paragon Offshore Finance Company
Cayman Islands
Financing company
Paragon Offshore Holdings US Inc.
Delaware
Holding company
Paragon Offshore International Ltd.
Cayman Islands
Contracting;
international personnel; rig owner
Paragon Offshore Leasing (Luxembourg) S.à r.l.
Luxembourg
Rig owner
Paragon Offshore Leasing (Switzerland) GmbH
Switzerland
Rig owner
Paragon Offshore Management Services, S. de R.L. de C.V.
Mexico
Management; administrative; payroll
Paragon Offshore Services LLC
United States
Management; administrative; payroll
Paragon Offshore Sterling Ltd.
Cayman Islands
Holding company
Paragon Offshore USA Inc.
Delaware
Contracting; operator; rig owner; payroll
Paragon Offshore Ven, C.A.
Venezuela
Dormant
Paragon Operating (M E) Ltd.
Cayman Islands
Contracting entity; operator
Paragon Seillean AS
Norway
Holding company
PGN Offshore Drilling (Malaysia) Sdn. Bhd.
Malaysia
Operator; services company
Prospector Finance II S.A.
Luxembourg
Financing company
Prospector Finance S.à.r.l.
Luxembourg
Financing company
Prospector New Building S.à.r.l.
Luxembourg
Marketing Service Company
Prospector Offshore Drilling (Singapore) PTE. LTD.
Singapore
Payroll/personnel entity for North Sea Operations
Prospector Offshore Drilling (UK) Ltd.
Scotland
Logistic support for North Sea Operations
Prospector Offshore Drilling Limited
Cyprus
Dormant
Prospector Offshore Drilling Rig Construction S.à.r.l.
Luxembourg
administrative on new rig constructions
Prospector Offshore Drilling S.A.
Luxembourg
Holding company
Prospector Rig 1 Contracting Company S.à.r.l.
Luxembourg
Contracting entity
Prospector Rig 1 Owning Company S.à.r.l.
Luxembourg
Rig owner
Prospector Rig 1 S.à.r.l.
Luxembourg
Financing company
Prospector Rig 5 Contracting Company S.à.r.l.
Luxembourg
Contracting entity
Prospector Rig 5 Owning Company S.à.r.l.
Luxembourg
Rig owner
Prospector Rig 6 Owning Company S.à.r.l.
Luxembourg
Rig owner
Prospector Rig 7 Owning Company S.à.r.l.
Luxembourg
Rig owner
Prospector Rig 8 Owning Company S.à.r.l.
Luxembourg
Rig owner
Prospector Support Services, Inc.
Texas
Management; administrative; payroll
Resolute Insurance Group Ltd.
Bermuda
Dormant





Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S‑8 (Nos. 333-198139 and 333-198140) of Paragon Offshore plc of our report dated March 12, 2015 relating to the financial statements, which appear in this Form 10‑K.


PricewaterhouseCoopers LLP
Houston, Texas
March 12, 2015





Exhibit 31.1


Paragon Offshore plc, a company registered under the laws of England and Wales
I, Randall D. Stilley, certify that:
1.
I have reviewed this annual report on Form 10-K of Paragon Offshore plc;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Paragraph omitted in accordance with instructions of the United States Securities and Exchange Commission;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 12, 2015
 
/s/ Randall D. Stilley
Randall D. Stilley
President, Chief Executive Officer and Director
of Paragon Offshore plc, a company registered under the laws of England and Wales






Exhibit 31.2


Paragon Offshore plc, a company registered under the laws of England and Wales
I, Steven A. Manz, certify that:
1.
I have reviewed this annual report on Form 10-K of Paragon Offshore plc;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Paragraph omitted in accordance with instructions of the United States Securities and Exchange Commission;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: March 12, 2015
 
/s/ Steven A. Manz
Steven A. Manz
Senior Vice President and Chief Financial Officer
of Paragon Offshore plc, a company registered under the laws of England and Wales





Exhibit 32.1


Paragon Offshore plc, a company registered under the laws of England and Wales
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Paragon Offshore plc, a company registered under the laws of England and Wales (the “Company”), on Form 10-K for the period ended December 31, 2014, as filed with the United States Securities and Exchange Commission on the date hereof (the “Report”), I, Randall D. Stilley, President, Chief Executive Officer and Director of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
March 12, 2015
 
/s/ Randall D. Stilley
 
 
Randall D. Stilley
 
 
President, Chief Executive Officer and Director
 
 
of Paragon Offshore plc, a company registered under the laws of England and Wales





Exhibit 32.2


Paragon Offshore plc, a company registered under the laws of England and Wales
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Paragon Offshore plc, a company registered under the laws of England and Wales (the “Company”), on Form 10-K for the period ended December 31, 2014, as filed with the United States Securities and Exchange Commission on the date hereof (the “Report”), I, Steven A. Manz, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
March 12, 2015
 
/s/ Steven A. Manz
 
 
Steven A. Manz
 
 
Senior Vice President and Chief Financial Officer
 
 
of Paragon Offshore plc, a company registered under the laws of England and Wales