10-K 1 a2016q410-k12312016xpgn.htm FORM 10-K FOR FISCAL YEAR ENDED DECEMBER 31, 2016 Document


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, 2016
¨
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: None

Securities registered pursuant to Sections 12(g) of the Act:
Ordinary Shares, Nominal Value $0.01 per Share

______________________________________________________
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 or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. 
Yes   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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) .  Yes   x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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. x
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  x
Non-accelerated filer  
 
 
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 June 30, 2016, the aggregate market value of the registered shares of Paragon Offshore plc held by non-affiliates of the registrant was $66 million based on the closing sale price as reported on the OTC Markets.
Number of shares outstanding and trading at March 3, 2017: 88,641,896

DOCUMENTS INCORPORATED BY REFERENCE
The information required to be included in Part III of this Annual Report on Form 10-K will be provided in accordance with Instruction G(3) to Form 10-K no later than
May 1, 2017.

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PARAGON OFFSHORE PLC
FORM 10-K
For the Year Ended December 31, 2016
TABLE OF CONTENTS
 
 
 
 
 
PAGE 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


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GLOSSARY OF CERTAIN DEFINED TERMS
Adjusted EBITDA
Net income (loss) before taxes plus interest expense, depreciation and amortization, losses on impairments, foreign currency losses and reorganization items, less gains on the sale of assets, interest income and foreign currency gains
AOCL
Accumulated Other Comprehensive Loss
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
Bankruptcy cases
The chapter 11 cases commenced by the Debtors filing voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court
Bankruptcy Code
United States Bankruptcy Code
Bankruptcy Court
United States Bankruptcy Court for the District of Delaware
Debt Facilities
Revolving Credit Facility, Term Loan Facility and Senior Notes, collectively
Debtors
Paragon Offshore plc and the following subsidiaries: Paragon Offshore Finance Company, Paragon International Finance Company, Paragon Offshore Holdings US Inc., Paragon Offshore Drilling LLC, Paragon FDR Holdings Ltd., Paragon Duchess Ltd., Paragon Offshore (Luxembourg) S.à.r.l., PGN Offshore Drilling (Malaysia) Sdn. Bhd., Paragon Offshore (Labuan) Pte. Ltd., Paragon Holding SCS 2 Ltd., Paragon Asset Company Ltd., Paragon Holding SCS 1 Ltd., Paragon Offshore Leasing (Luxembourg) S.à.r.l., Paragon Drilling Services 7 LLC, Paragon Offshore Leasing (Switzerland) GmbH, Paragon Offshore do Brasil Ltda., Paragon Asset (ME) Ltd., Paragon Asset (UK) Ltd., Paragon Offshore International Ltd., Paragon Offshore (North Sea) Ltd., Paragon (Middle East) Limited, Paragon Holding NCS 2 S.à r.l., Paragon Leonard Jones LLC, Paragon Offshore (Nederland) B.V., and Paragon Offshore Contracting GmbH
Distribution
The August 1, 2014 pro rata distribution by Noble to its shareholders of all our issued and outstanding ordinary shares. Noble shareholders received one ordinary share of Paragon for every threes shares of Noble owned.                
Exchange Act
United States Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
LIBOR
London Interbank Offered Rate
New Plan
Third amended plan of reorganization for the Debtors as filed with the Bankruptcy Court on February 7, 2017
Noble
Noble Corporation plc
NYSE
The New York Stock Exchange
OPEC
Organization of Petroleum Exporting Countries
OTCQX
Marketplace trading over-the-counter stocks provided and operated by the OTC Markets Group
OTC Pink
Marketplace trading over-the-counter stocks provided and operated by the OTC Markets Group
Pemex
Petróleos Mexicanos
Petrobras
Petróleo Brasileiro S.A.
Prospector
Prospector Offshore Drilling S.á.r.l

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Revolving Credit Agreement
The Company’s senior secured revolving credit agreement entered into with a group of lenders on June 17, 2014
Revolving Credit Facility
Commitments in the amount of $800 million provided by a group of lenders under the Revolving Credit Agreement
Sale-Leaseback Transaction
Sale-leaseback agreement with subsidiaries of SinoEnergy Capital Management Ltd. for two high specification jackup units, Prospector 1 and Prospector 5 entered into on July 24, 2015
SEC
United States Securities and Exchange Commission
Senior Notes
The Company’s 6.75% senior notes due in 2022 and 7.25% senior notes due in 2024, collectively
Spin-Off
The Company’s separation from Noble on August 1, 2014
Tax Sharing Agreement
Agreement entered into with Noble at Spin-Off 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
Term Loan Agreement
The Company’s senior secured term loan agreement entered into June 18, 2014
Term Loan Facility
The Company’s $650 million term loan debt entered into under the Term Loan Agreement
Total S.A.
Total E&P U.K. Limited and Elf Exploration U.K. Limited
U.K.
United Kingdom
U.S. GAAP
Accounting principles generally accepted in the United States


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FORWARD LOOKING STATEMENTS
This Annual Report on Form 10-K includes “forward-looking statements”. 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, our ability to implement the New Plan (or an alternative plan of reorganization), the Bankruptcy cases, 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 Part I, Item 1A, “Risk Factors”, 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.


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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. Our fleet includes 34 jackups (including two high specification heavy duty/harsh environment jackups), four drillships and one semisubmersible. Our primary business is contracting our 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 in significant hydrocarbon-producing geographies throughout the world, including the North Sea, the Middle East and India. As of December 31, 2016, our contract backlog was $242 million and included contracts with national, international and independent oil and gas companies.
We are a public limited company registered under the Companies Act 2006 of England. In July 2014, Noble Corporation 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 (our “Predecessor”). 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”).
Going Concern
The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Our ability to continue as a going concern is contingent upon obtaining the requisite vote of creditors and the Bankruptcy Court’s approval of our plan of reorganization as described below. This represents a material uncertainty related to events and conditions that raises substantial doubt on our ability to continue as a going concern and, therefore, we may be unable to utilize our assets and discharge our liabilities in the normal course of business.
During the period that we are operating as debtors-in-possession under chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions in our debt agreements), for amounts other than those reflected in the accompanying consolidated financial statements. Further, any reorganization plan could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should we be unable to continue as a going concern.
Chapter 11 Filing
On February 12, 2016, the Debtors entered into a plan support agreement (the “PSA”) relating to a plan of reorganization (including all amendments thereto, the “Original Plan”) pursuant to chapter 11 of the Bankruptcy Code with holders representing an aggregate of 77% of the outstanding $457 million of our 6.75% senior unsecured notes maturing July 2022 and the outstanding $527 million of our 7.25% senior unsecured notes maturing August 2024 together with lenders representing an aggregate of 96% of the amounts outstanding (including letters of credit) under our Revolving Credit Agreement (the “Noteholder Group”).
On February 14, 2016, the Debtors commenced their chapter 11 cases (the “Bankruptcy cases”) by filing voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Upon filing the Bankruptcy cases, we began trading on the OTC Pink.
On April 19, 2016, the Bankruptcy Court approved the Company’s disclosure statement and certain amendments to the Original Plan.
Effective August 5, 2016, the Company entered into an amendment to the PSA (the “PSA Amendment”) with the lenders under our Revolving Credit Agreement (the “Revolver Lenders”) and lenders holding approximately 69% in principal amount of our Senior Notes. The PSA Amendment supported certain revisions to the Original Plan. On August 15, 2016, the Debtors filed the amended Original Plan and a supplemental disclosure statement with the Bankruptcy Court.

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By oral ruling on October 28, 2016, and by written order dated November 15, 2016, the Bankruptcy Court denied confirmation of the Debtors’ amended Original Plan. Consequently, on November 29, 2016, the Noteholder Group terminated the PSA effective as of December 2, 2016.
On January 18, 2017, the Company announced that it reached agreement in principle with a steering committee of lenders under our Revolving Credit Agreement and an ad hoc committee of lenders under our Term Loan Agreement to support a new chapter 11 plan of reorganization for the Debtors (the “New Plan”). On February 7, 2017, the Company filed the New Plan and related disclosure statement with the Bankruptcy Court. The New Plan provides for, among other things, the (i) elimination of approximately $2.4 billion of the Company’s existing debt in exchange for a combination of cash, debt and new equity to be issued under the New Plan; (ii) allocation to the Revolver Lenders and lenders under our Term Loan Agreement (collectively, the “Secured Lenders”) of new senior first lien debt in the original aggregate principal amount of $85 million maturing in 2022; (iii) projected distribution to the Secured Lenders of approximately $418 million in cash, subject to adjustment on account of claims reserves and working capital and other adjustments at the time of the Company’s emergence from the Bankruptcy cases, and an estimated 58% of the new equity of the reorganized company; (iv) projected distribution to holders of the Company’s Senior Notes (the “Bondholders”) of approximately $47 million in cash, subject to adjustment on account of claims reserves and working capital and other adjustments at the time of the Company’s emergence from the Bankruptcy cases, and an estimated 42% of the new equity of the reorganized company; and (v) commencement of an administration of the Company in the United Kingdom to, among other things, implement a sale of all or substantially all of the assets of the Company to a new holding company to be formed, which administration may be effected on or prior to effectiveness of the New Plan. Existing shareholders of the Company will not receive a recovery under the New Plan. The New Plan will be subject to usual and customary conditions to plan confirmation, including obtaining the requisite vote of creditors and approval of the Bankruptcy Court. The Company has been and remains in discussions with the Bondholders, who have currently not agreed to support the New Plan, and therefore, there is no guarantee that the New Plan will be approved.
Debtors-in-Possession
Since the filing date, the Debtors have operated their business as “debtors-in-possession”. Under the Bankruptcy cases, the Debtors’ trade creditors and vendors are being paid in full in the ordinary course of business and all of the Company’s contracts have remained in effect in accordance with their terms, preserving the rights of all parties. Certain subsidiaries of the Company were not party to the chapter 11 filing (the “Non-Filing entities”). The Non-Filing entities have continued to operate in the ordinary course of business. For additional discussion of the risks associated with debtors-in-possession, see Item 1A, “Risk Factors”.
Settlement with Noble Corporation
On February 12, 2016, we entered into a binding term sheet with Noble with respect to the “Noble Settlement Agreement” (as described below), which we executed on April 29, 2016. The Noble Settlement Agreement will become effective upon the effective date of the Debtors’ plan of reorganization if such plan is substantially similar to the Debtors Original Plan. The New Plan contemplates that the Noble Settlement Agreement will become effective upon the effective date of the New Plan. In light of the differences in the Original Plan and the New Plan, we intend to discuss this requirement with Noble. The Noble Settlement Agreement provides that Noble may only unilaterally terminate the Noble Settlement Agreement if: (i) the Debtors’ file a plan of reorganization with the Bankruptcy Court that does not incorporate the terms and conditions of the Noble Settlement Agreement, (ii) the Debtors file a motion before the Bankruptcy Court to terminate their obligations under the Noble Settlement Agreement, or (iii) the release of claims by the Debtors in favor of Noble, as detailed below, is deemed invalid or unenforceable.
Pursuant to the Noble Settlement Agreement, Noble will provide direct bonding in fulfillment of the requirements necessary to challenge tax assessments in Mexico relating to our business for the tax years 2005 through 2010 (the “Mexican Tax Assessments”). The Mexican Tax Assessments were originally assigned to us by Noble pursuant to the Tax Sharing Agreement which was entered into in connection with the Spin-Off. See Part II, Item 8, Note 19 - “Commitments and Contingencies” for additional information. The Company has contested or intends to contest the Mexico Tax Assessments and may be required to post bonds in connection thereto.
In addition, on August 5, 2016, we entered into a binding term sheet with respect to an amendment to the Noble Settlement Agreement (the “Noble Settlement Agreement Amendment”). Upon effectiveness of the Noble Settlement Agreement Amendment, certain provisions of the Tax Sharing Agreement will be further amended to permit us, at our option, to defer up to $5 million in amounts owed to Noble under the Tax Sharing Agreement with respect to the Mexican Tax Assessments (the “Deferred Noble Payment Amount”). In consideration for this deferral, we would issue an unsecured promissory note to Noble in the amount of the Deferred Noble Payment Amount (the “Noble Note”) which would be due and payable on the fourth anniversary of the effective date of the New Plan. The Noble Note would accrue interest, quarterly, to be paid either: (x) in cash at 12% per annum, or (y) in kind at 15% per annum (in our discretion).

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As of December 31, 2016, our estimated Mexican Tax Assessments totaled approximately $165 million, with assessments for 2009 and 2010 yet to be received. Noble will be responsible for all of the ultimate tax liability for Noble legal entities and 50% of the ultimate tax liability for our legal entities relating to the Mexican Tax Assessments upon effective date of the Noble Settlement Agreement.
In consideration for this support, we have agreed to release Noble, fully and unconditionally, from any and all claims in relation to the Spin-Off. Upon the effectiveness of the Noble Settlement Agreement, a material portion of our Mexican Tax Assessments, and any corresponding ultimate tax liability, will be assumed by Noble on the effective date in connection with certain amendments to the Tax Sharing Agreement executed between Noble and Paragon for the Spin-Off. Until such time, the current Tax Sharing Agreement remains in effect.
Business Strategy
Our company’s vision is to be the preferred high-quality, low-cost offshore drilling contractor in our industry. In our business, we believe that drilling contractors are evaluated based on their people, processes, principles, and operational and safety performance. In aligning our strategy with our vision, we pursue the following objectives:

maximize the utilization of our asset base in core oil and gas producing areas throughout the world including the North Sea, Middle East and India;

operate in a manner that delivers industry-leading operational uptime and provides exceptional customer service through a fleet operated safely by competent and skilled personnel;

focus on continuous improvement in our onshore and offshore business processes to reduce costs and improve efficiency;

provide a safe work atmosphere for our employees while protecting the environment and our assets;

leverage strategic relationships with high-quality, long-term customers;

continue to invest in our existing fleet through maintenance, refurbishment and capital upgrades;

pursue strategic growth opportunities, opportunistically expanding our worldwide fleet capabilities;

sell or scrap non-core assets to reduce costs; and

remain financially disciplined.
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 national, international and independent oil and gas companies in some of the world’s most active hydrocarbon producing markets.

We currently have a well-maintained fleet of drilling rigs, excluding our stacked rigs, which allows us to provide reliable and effective drilling services to our customers across multiple geographies. We intend to continue to invest capital in a disciplined manner 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 selectively 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 extend our rigs’ useful lives, reduce operational downtime and generate better value. We believe that 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. Nevertheless, during the current industry downturn, we will spend capital judiciously to conserve cash.


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We currently have three high specification jackups under construction in China owned by non-Debtor subsidiaries. These units are technically complete, however, we have reached agreements with the construction company to defer delivery of these units until October 2017 as there are no opportunities to secure contracts for the assets in the current business environment. For us to take delivery of these assets, we would require an acceptable contract to justify the purchase price and suitable financing. We cannot guarantee that we will accept delivery of any of these jackups. In the current business environment, we believe we are unlikely to acquire these drilling rigs. Restrictions under the New Plan may also further constrain our ability to acquire drilling rigs.

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 price of oil and natural gas, customer activity, and the worldwide supply of mobile offshore drilling units. In recent years, there has been a significant expansion of 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 has increased the supply of rigs which compete for drilling service contracts and has negatively impacted both the 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, subject to the considerations discussed above. In doing so, we will be able to apply one of our competitive strengths, the ability to operate assets and generate value while minimizing risk.
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. Our 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. We offer 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 of 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 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. For

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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 Item 1A, “Risk Factors.

The terms of some of our drilling contracts permit us to earn bonus revenue incentive payments based on performance.

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, see Part II, Item 7, “Management’s
Discussion and Analysis of Financial Condition and Results of Operations - Market Outlook.”

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, 2016, 2015 and 2014. We conduct our contract drilling operations principally in the North Sea, the Middle East, and India. For the years ended December 31, 2016, 2015 and 2014, our five largest customers in the aggregate accounted for approximately 72%, 61%, and 57%, respectively of our operating revenues. Revenues from Total S.A. accounted for approximately 24%, 16% and 3% of our total operating revenues in 2016, 2015 and 2014, respectively. Revenues from National Drilling Company accounted for approximately 17%, 9%, and 6% of our total operating revenues in 2016, 2015 and 2014, respectively. Revenues from Petrobras accounted for approximately 17%, 21% and 23% of our total operating revenues in 2016, 2015 and 2014, respectively. Revenues from Pemex accounted for approximately 3%, 9% and 16% of our total operating revenues in 2016, 2015 and 2014, respectively. No other single customer accounted for more than 10% of our total operating revenues in 2016, 2015 or 2014.
Labor Contracts
For the six months ended June 30, 2016, we provided drilling and maintenance services (but did not provide a rig) on the Hibernia Project in the Canadian Atlantic under a contract with Hibernia Management and Development Company Ltd. and in which Exxon was the primary operator. Under this contract, we provided the personnel necessary to manage and perform the drilling operations from a drilling platform owned by the operator. Our labor contract ended on June 30, 2016, at which time Paragon ceased providing these services.
Competition
The offshore contract drilling industry is a 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, 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. See Part II, Item 8, Note 5 -“Property and Equipment and Other assets” for a discussion on the $130 million non-cash impairment loss recognized on our fleet and capital spares during the year ended December 31, 2016. For additional information, please read “The contract drilling industry is a competitive and cyclical business with intense price competition. If we are unable to compete successfully, our profitability may be reduced,” included in Item 1A “Risk Factors.
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.

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In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business have historically occurred. We cannot assure investors 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 relating to 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 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 to cut oil production in the face of declining commodity prices has caused an increase in oil prices. However, we have not seen an increase in the amount of offshore exploration and development work done by oil and gas companies and their need for drilling offshore services, and may not for some time.
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 could lead to lesser demand for 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 the laws and regulations 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.

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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 in 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 Convention (BWM Convention). In 2004, IMO adopted the International Convention for the Control and Management of Ships’ Ballast Water and Sediments. BWM Convention is purposed with preventing the spread of non-native aquatic species into lakes, rivers and coastal waters. Ballast water is defined as water taken on for means of trim and stability during voyages. The BWM Convention will apply to all vessels and specifically to our units with a ballast capacity of ≥1500 cubic meters. The BWM Convention was ratified by a sufficient number of states on September 8, 2016, exceeding the required gross tonnage of 35% from the signatory states. BWM convention will enter into force on September 8, 2017. Ballast water exchange will be accepted up until the first IOPP Certificate Renewal, once the BWM Convention enters in to force. Thereafter, ballast water treatment will be the only acceptable method of complying with the 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 portion of our drilling fleet is cold stacked 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 40 CFR110. 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.

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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.
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 CAA and associated state laws and regulations. In general, we believe that compliance with the CAA 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 (“OSHA”) 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 Comprehensive Environmental Response, Compensation, and Liability Act 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 were 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 the European Union.
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. The United Nations Framework Convention on Climate Change on December 12, 2015 adopted the ‘Paris Agreement’ by consensus, which has not entered in force yet. Member countries agreed to reduce their carbon output “as soon as possible” and to do their best to keep global warming below 2°C. The member countries will pursue efforts to limit the temperature increase to 1.5°C. The agreement will become legally binding if joined by at least 55 countries which together represent at least 55 percent of global greenhouse emissions. Such parties will need to sign the agreement in New York between April 22, 2016 and April 21, 2017. 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

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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. 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 ETS 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. Scope 2 data (indirect emissions from purchased electricity) was aggregated from all operating divisional offices for the 2015 and 2016 year, this figure amounted to 1,397 MWh and 1,588 MWh, respectively.
At year end December 31, 2016, our estimated carbon dioxide equivalent (“CO2e”) gas emissions was 144,690 tonnes, as compared to 299,410 tonnes the year prior (52% reduction). This reduction in emissions is due to reduction in drilling activity, total number of on-contract days reduced by 49% compared to prior year. When expressed as an intensity measure of tonnes of C02e gas emissions per dollar of contract drilling revenues, the 2016 and 2015 intensity measures were 0.0003 and 0.0002, respectively. 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.

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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 Item 1A, “Risk Factors.
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 change differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.
Employees
As of December 31, 2016, we had approximately 942 employees, excluding approximately 277 persons engaged through labor contractors or agencies. Approximately 67% 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 generally good, though challenged by the present bankruptcy proceedings.
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 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.
Basis of Presentation
The financial information contained within this report includes periods prior to the Spin-Off on August 1, 2014. For these periods prior to the Spin-Off, the consolidated financial statements and related discussion of financial condition and results of operations include historical results of our Predecessor, which comprised most of Noble’s standard specification drilling fleet and related operations. We consolidate the historical financial results of our Predecessor in our consolidated financial statements for all periods prior to the Spin-Off. All financial information presented after the Spin-Off represents the consolidated results of operations, financial position and cash flows of Paragon. For more detailed information, refer to Part II, Item 8, “Financial Statements and Supplementary Data”.

Financial Information About Segments and Geographic Areas
At December 31, 2016, 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 offers contract drilling operations in the North Sea, the Middle East, India, Brazil, Mexico, West Africa and Southeast Asia. Under the New Plan, if approved, we will focus on the North Sea, the Middle East and India. 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, Note 22 - “Segment and Related Information.

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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 Exchange Act are available free of charge at our website at http://www.paragonoffshore.com. These filings are also available to the public at the SEC Public Reference Room at 100 F Street, 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 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;
Finance and Risk Committee Charter; and
Code of Business Conduct and Ethics.
We intend to satisfy the disclosure requirements of Item 5.05 of Form 8-K regarding certain amendments to, or waivers from our Code of Business Conduct and Ethics, if any, by posting such information to our website.


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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.
Risk Factors Related to Our Restructuring
Trading in our securities during the pendency of our bankruptcy proceedings is extremely speculative and poses substantial risks.  There is significant risk that investors will lose their entire investment.

The New Plan of reorganization, which is subject to confirmation including approval of the Bankruptcy Court, contemplates the cancellation of all of our existing common shares without consideration. The holders of our common shares would not be entitled to receive any distributions, interest or other property, rendering such common shares worthless. We caution and urge existing and future investors to carefully consider these and other risks with respect to investments in our common shares and other securities or claims.

We and certain of our subsidiaries filed for reorganization under chapter 11 of the Bankruptcy Code on February 14, 2016 and are subject to the risks and uncertainties associated with the Bankruptcy cases.
 
For the duration of the Bankruptcy cases, our operations and our ability to execute our business strategy will be subject to the risks and uncertainties associated with bankruptcy.  These risks include:
our ability to continue as a going concern;
our ability to obtain Bankruptcy Court approval with respect to motions filed in the Bankruptcy cases from time to time and the outcome of the Bankruptcy Court ruling in general;
our ability to develop, prosecute, confirm and consummate the New Plan (or an alternative plan of reorganization) with respect to the Bankruptcy cases;
the ability of third parties to seek and obtain court approval to terminate or shorten the exclusivity period for us to propose and confirm a plan of reorganization, to appoint a U.S. trustee or to convert the Bankruptcy cases to chapter 7 cases;
our ability to obtain and maintain normal payment and other terms with customers, vendors and service providers;
our senior management will be required to spend significant time and effort dealing with bankruptcy and restructuring activities rather than focusing exclusively on business operations;
our ability to maintain contracts that are critical to our operations;
our ability to attract, motivate and retain key employees through the process of reorganization, and to attract new employees;
our ability to retain key vendors or secure alternative supply sources;
our ability to fund and execute our business plan; and
our ability to obtain acceptable and appropriate financing.
 We will also be subject to risks and uncertainties with respect to the actions and decisions of our creditors and other third parties who have interests in the Bankruptcy cases that may be inconsistent with our plans, and the costs of the bankruptcy proceedings may be higher than we expect.
 
These risks and uncertainties could affect our business and operations in various ways.  For example, negative events or publicity associated with the Bankruptcy cases could adversely affect our relationships with our vendors and employees, as well as with customers, which in turn could adversely affect our operations and financial condition.  Also, pursuant to the Bankruptcy Code, we need Bankruptcy Court approval for transactions outside the ordinary course of business, which may limit our ability to respond timely to events or take advantage of opportunities.  Because of the risks and uncertainties associated with the Bankruptcy cases, we cannot predict or quantify the ultimate impact that events occurring during the chapter 11 proceedings will have on our business, financial condition and results of operations, and there is no certainty as to our ability to continue as a going concern.

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We are not filing certain of our subsidiaries as part of the Bankruptcy cases. If we determine to file additional subsidiaries, it could delay the restructuring or impact our ability to effect the restructuring. In addition, the Noble Settlement Agreement is conditioned upon our emergence from the Bankruptcy cases. If we are unable to effect the restructuring as contemplated for any reason, the benefits of the Noble Settlement Agreement would not be realized.
 
As a result of the Bankruptcy cases, realization of assets and liquidation of liabilities are subject to uncertainty.  While operating under the protection of the Bankruptcy Code, and subject to Bankruptcy Court approval or otherwise as permitted in the normal course of business, we may sell or otherwise dispose of assets and liquidate or settle liabilities for amounts other than those reflected in our consolidated financial statements.  Further, the New Plan contemplates material changes to the amounts and classifications reported in our consolidated historical financial statements, which do not give effect to any adjustments to the carrying value of assets or amounts of liabilities that might be necessary as a consequence of confirmation of a plan of reorganization.
 
Our business could suffer from a long and protracted restructuring.
 
Our Bankruptcy cases have continued for a significant period of time, far longer than we had anticipated when we filed them in February of 2016. Our future results are dependent upon the successful confirmation and implementation of the New Plan.  Failure to obtain this approval in a timely manner could adversely affect our operating results, as our ability to obtain financing to fund our operations may be harmed by protracted bankruptcy proceedings.  If a liquidation or continued protracted reorganization were to occur, there is a significant risk that the value of our enterprise would be substantially eroded to the detriment of all stakeholders.
 
Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization.  Even once the New Plan is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and customers to do business with a company that recently emerged from bankruptcy proceedings.
 
We may not be able to obtain confirmation of the New Plan (or any other plan of reorganization), and our emergence from the Bankruptcy cases is not assured.
 
Our Original Plan was not approved by the Bankruptcy Court and there can be no assurance that the New Plan (or any other plan of reorganization) will be approved by the Bankruptcy Court, so we urge caution with respect to existing and future investments in our securities.
 
There can be no assurances that we will receive the requisite votes of our creditors to confirm the New Plan.  Moreover, we might receive official objections to confirmation of the New Plan from the various bankruptcy committees and stakeholders in the Bankruptcy cases. We cannot predict the impact that any objection might have on the Bankruptcy Court’s decision whether to confirm the New Plan.  Any objection may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition and results of operations.
 
If the New Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against us, including holders of our secured and unsecured debt and equity, would ultimately receive with respect to their claims.  Our creditors would likely incur significant costs in connection with developing and seeking approval of an alternative plan of reorganization, which might not be supported by any of the other debt holders, various bankruptcy committees or other stakeholders.  If an alternative reorganization could not be agreed upon, it is possible that we would have to liquidate our assets, in which case it is likely that holders of claims would receive substantially less favorable treatment than they would receive if we were to emerge as a viable, reorganized entity.  There can be no assurance as to whether we will successfully reorganize and emerge from the Bankruptcy cases or, if we do successfully reorganize, as to when we would emerge from the Bankruptcy cases.
 

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We have experienced increased levels of employee attrition as a result of the Bankruptcy cases.

As a result of the prolonged Bankruptcy cases, we have experienced increased levels of employee attrition, and our employees likely will continue to face considerable distraction and uncertainty during the pendency of our Bankruptcy cases. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. While we implemented a key employee retention plan prior to bankruptcy, our ability to engage, motivate and retain key employees or take other measures intended to motivate and incent key employees to remain with us through the pendency of the Bankruptcy cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, liquidity and results of operations.
 
We may be subject to claims that will not be discharged in the Bankruptcy cases, which could have a material adverse effect on our results of operations and profitability.
 
The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from specified debts arising prior to confirmation and specified debts arising afterwards.  Under the New Plan, which has not yet been approved, we would be discharged from any claims arising under the Revolving Credit Agreement, Term Loan Agreement and Senior Notes. Any claims not ultimately discharged by the Bankruptcy Court could have an adverse effect on our results of operations and profitability after we emerge from bankruptcy.
 
Our financial results may be volatile and may not reflect historical trends.
 
While in bankruptcy, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections, and claims assessments may significantly impact our consolidated financial statements.  As a result, our historical financial performance prior to the date of the bankruptcy filing has not been indicative of our financial performance after the date of the bankruptcy filing.  In addition, if we emerge from bankruptcy, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, a result of revisions to our operating plans pursuant to a plan of reorganization.  In addition, if we emerge from bankruptcy under the New Plan, we would be required to adopt fresh start accounting.  Under fresh start accounting, our assets and liabilities will be recorded at fair value as of the fresh start reporting date.  The fair value of our assets and liabilities may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets.  In addition, our financial results after the application of fresh start accounting may be different from historical trends.

The chapter 11 filing could result in a material adverse tax effect for the Company upon emergence from bankruptcy.
There is no assurance that the chapter 11 filing will not cause a material adverse tax effect for the Company. For example, it is possible that the ownership change upon emergence from bankruptcy could trigger with respect to the U.S. Debtors an annual limitation to the utilization of pre-existing net operating loss carryforwards and other tax attributes under the existing U.S. tax law. In addition, no assurance can be given that non-U.S. taxing authorities will respect the chapter 11 filing in Delaware, to qualify as a local country equivalent of “statutory insolvency arrangement,” and as a result, the Company could be subject to tax on discharge of indebtedness, which could have a material adverse effect on our financial condition.

The February 14, 2016 filing for bankruptcy by Paragon Offshore plc constituted an event of default under our Lease Agreements for the Prospector 1 and Prospector 5.

The commencement of proceedings under chapter 11 of the Bankruptcy Code by Paragon Offshore plc constituted an event of default under the Lease Agreements for the Prospector 1 and the Prospector 5. If the Lessors do not continue to forbear taking action or grant us a waiver with respect to this event of default, we will be in default under both the Lease Agreement for the Prospector 1 and the Lease Agreement for the Prospector 5. As a result of the default, all rent amounts outstanding under the Lease Agreements (the “Outstanding Lease Balances”) will become immediately due and payable. In addition to the Outstanding Lease Balances, the following will also become due and payable: (i) a fee representing 3% of the Outstanding Lease Balances and (ii) any broken funding costs incurred by the Lessors (together with the Outstanding Lease Balances, the “Termination Fee”). If we are unable to pay the Termination Fee within three (3) calendar months of becoming due, the Lessors will have the right to sell the Prospector Rigs through a transparent sale process. If the Lessors do not continue to forbear taking action with respect to this event of default, we would have to consider commencing a chapter 11 proceeding for the applicable Prospector entity.



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Risks Related to Our Business
The worldwide demand for drilling services significantly declined as a result of the continued instability in oil prices. Our business is dependent on the level of activity in the oil and gas industry.
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;
strategic decisions by our customers to focus on onshore activity rather than offshore
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 OPEC to set and maintain production levels and pricing;
the level of production in non-OPEC countries; and
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

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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.
The contract drilling industry is a 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, 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.
The cyclical nature of, or a prolonged downturn in, our industry, can affect the carrying value of our long-lived assets and negatively impact our results of operations.
 We are required to evaluate the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.  Recoverability is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset.  If management determines that the carrying value of our long-lived assets may not be recoverable, our results of operations could be impacted by additional non-cash impairment charges. During the year ended December 31, 2016, we recognized a non-cash impairment charge of $130 million on our fleet and capital spares. During the year ended December 31, 2015,we recorded non-cash impairment charges of $1.1 billion and $37 million related to our property and equipment and all of our goodwill, respectively.
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 exited a period of high utilization and high dayrates prior to 2015, 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. Since 2015, new fixtures for both standard and high specification jackup rigs and floaters have come under pressure as a result of a 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 1, 2017, the total non-U.S. jackup fleet comprised 490 units (38 of which were cold stacked and three of which were “out of service”). An additional 103 jackup drilling rigs were under construction, on order, or have been completed, but remain in the shipyard awaiting work. These additional rigs could bring the total non-U.S. jackup fleet to 593 units (assuming no further newbuilds are ordered and delivered and there is no attrition of the current fleet). In addition, there are reported to be 48 floating rigs under construction, on order, or planned with deliveries between 2017 and 2021. 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 cause a delay in the recovery of 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.

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Our standard specification rigs are at a relative disadvantage to higher specification rigs.
Our standard specification rigs lack 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. We have observed that higher specification rigs are competing with standard specification rigs for the same contracts and higher specification rigs would have an advantage over standard specification rigs in securing those contracts resulting in a decrease in 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. In addition, our cold stacked rigs will require significant capital investment prior to re-entering service. The amount of capital investment required for reactivating these cold stacked rigs increases in relation to the amount of time that the rig remained cold stacked.
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 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;
jackup leg punch-throughs (on the sea floor);
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

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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 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, 2016, 2015 and 2014, our five largest customers in the aggregate accounted for approximately 72%, 61%, and 57% respectively, of our operating revenues. We do not expect Petrobras, which accounted for approximately 17% of our operating revenues for the year ended December 31, 2016, 21% of our operating revenues for the year ended December 31, 2015, and 23% of our operating revenues for the year ended December 31, 2014 to be a significant customer in 2017.
 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. 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 2017. 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 and may require a substantial amount of capital investment to resume operations thereafter. Any new contracts for such rigs may be at dayrates substantially below prior dayrates or on terms less favorable than prior contract terms, which could have a material adverse effect on our revenues and profitability.
Our customers, which include 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. In addition, our customers may attempt to use the Bankruptcy cases as a means to renegotiate or repudiate their contracts with us.
 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;

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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;
the exit of the United Kingdom from the European Union;
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.
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 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. The amount of capital expenditures required to return the cold stacked rig to operation will increase in proportion to the amount of time the rig is cold stacked.

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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 some 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.
As previously reported, our subsidiary used a commercial agent in Brazil in connection with Petrobras drilling contracts. The agent pleaded guilty in Brazil in connection with the award by Petrobras of a drilling contract to one of our competitors as part of a wider investigation of Petrobras’ business practices. The agent has represented a number of different companies in Brazil over many years, including several offshore drilling contractors. Since mid-2015, we have been conducting an independent review of our relationship with the agent and with Petrobras. Our review to date has found no evidence of wrongdoing by our employees or the commercial agent on our behalf. The SEC and the U.S. Department of Justice are aware of our review.
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

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or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups 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.
We may have significant financial commitments with respect to three newbuild high specification jackup rigs.
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. At December 31, 2016, we had purchase commitments of $579 million due in 2017 on the construction of three high specification jackup rigs related to the Prospector acquisition, the Prospector 6, Prospector 7 and Prospector 8. The delivery of these newbuild rigs has been rescheduled to the fourth quarter of 2017.
Each of these rigs is being built pursuant to a contract between a subsidiary of Prospector and the shipyard, without a Paragon parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary. In the event we are unable to extend delivery of any of the three high specification jackups, we will lose ownership of the applicable rig, at which time, the associated costs (primarily representing down-payments on these rigs, which have been written-off by us) will be forfeited. These subsidiaries have currently pre-paid to SWS 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 $195 million, $192 million and $192 million, respectively. In 2016, we did not make any payments on the commitments related to the three high specification jackups and in the current business environment, we believe we are unlikely to acquire these drilling rigs.
While we would require an acceptable drilling contract to justify the purchase price, 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.  Such financing may be increasingly difficult to secure during the pendency of the Bankruptcy cases.  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, 2016, our contract backlog was $242 million for contracted future work extending, in some cases, until 2018, with approximately 89% expected to be earned in 2017. 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. 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. 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.
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;

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surveys by government and maritime authorities;
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:
servicing and repayment of debt;
committed capital expenditures, including expenditures for newbuild projects currently underway;
normal recurring operating expenses; and
discretionary capital expenditures, including various capital upgrades;
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.

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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, 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 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 could be highly volatile due to legislative or operational changes.
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 could be highly volatile, 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 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 or loss mix of our operations in various jurisdictions. As our operations continually change among numerous jurisdictions, and methods of taxation in these jurisdictions vary greatly, there is little direct correlation between the income tax provision/benefit and income/loss before taxes.
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 U.K., the U.S. and any other jurisdictions in which we or any of our subsidiaries operate or are incorporated. For example, the U.K. passed legislation 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. Although we do not believe that we are affected by the law at this time, uncertainty exists with respect to the legislation’s impact to our operations. 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.
A tax law was enacted in Brazil, effective January 1, 2015, that under certain circumstances would impose a 15% to 25% withholding tax on charter hire payments made to a non-Brazilian related party exceeding certain thresholds of total contract

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value.   Although we believe that our operations are not subject to this law, the tax has been withheld at the source by our customer and we have recorded the amount withheld as tax expense. Discussions with our customer over the applicability of this legislation are ongoing.
On November 23, 2016, the U.K. government announced the Autumn Statement proposals, which included, among other provisions, rules with respect to tax deductions for interest expense, amendment to current loss relief rules, and anti-hybrid legislation. Finance Bill 2017 is expected to include these changes to the legislation. On December 14, 2016, the Luxembourg Parliament approved a law making changes to the Luxembourg corporate, personal, and value-added tax regimes. On December 27, 2016, the Luxembourg Tax Authorities issued a new Circulaire, effective January 1, 2017, that closely followed the application of the arm’s-length principle of the Organisation for Economic Co-operation and Development Transfer Pricing Guidelines, and made any existing unilateral transfer pricing rulings no longer valid as from that date. We are evaluating the impact to our operations as a result of these new legislations or impending changes.
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 U.K., 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

29


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 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 increasing public and regulatory attention being paid to 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.

30


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, including negative tax effects on currency exchange fluctuations, 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.

31


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, the Zika 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 has occurred or 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.


32


Risks Related to our Ordinary Shares
Our shares are subject to risks associated with trading in an over the counter market.
 
On December 18, 2015, our shares were delisted from the NYSE and, subsequently, began trading on the OTCQX. On February 14, 2016, we were removed from the OTCQX and began trading on the OTC Pink due to the commencement of our Bankruptcy cases. Securities traded in the over-the-counter market generally have significantly less liquidity than securities traded on a national securities exchange, such as the NYSE, through factors such as a reduction in the number of investors that will consider investing in the securities, the number of market makers in the securities, reduction in securities analyst and news media coverage and lower market prices than might otherwise be obtained.  As a result, holders of shares may find it difficult to resell their shares at prices quoted in the market or at all.  Furthermore, because of the limited market and generally low volume of trading in our shares that could occur, our share price could be more likely to be affected by broad market fluctuations, general market conditions, fluctuations in our operating results, changes in the markets perception of our business, and announcements made by us, our competitors or parties with whom we have business relationships. The lack of liquidity in our shares may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future.  In addition, we may experience other adverse effects, including, without limitation, the loss of confidence in us by current and prospective suppliers, customers, employees and others with whom we have or may seek to initiate business relationships.
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.  Any determination to declare a dividend, as well as the amount of any dividend that may be declared, would 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 would consider relevant factors at that time. As proposed by the New Plan, we will not be paying any dividends following our emergence from bankruptcy.
   

33


Risks Related to the Spin-Off
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, Master Separation Agreement, employee matters agreement, Tax Sharing Agreement and a transition services agreement relating to Noble’s offshore Brazil operations.
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.
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 if Noble is ultimately determined to be liable for any amounts. 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 the magnitude of any liability at this time, nor determine a timeline on this matter.
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.

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ITEM 1B.    UNRESOLVED STAFF COMMENTS
None.
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 saltwater 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 and motions. 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, defined as station-keeping, 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 system 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 and preloading operations continues until the hull is raised out of the water, and drilling operations are conducted with the hull in its raised position.

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Offshore Fleet Table
The following table includes certain information concerning our offshore fleet at March 3, 2017. 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 Revolving Credit Facility and Term Loan Facility are secured by substantially all of our rigs, excluding the two Prospector rigs in operation and the three Prospector rigs in the shipyard.
Name
 
Make
 
Year Built/Rebuilt(1)
 
Water
Depth
Rating
(feet)
 
Drilling
Depth
Capacity
(feet)
 
Location
 
Status(2)
Semisubmersible — 1
Paragon MSS1 (3)
 
Offshore Co. SCP III Mark 2
 
1979 / 2000 R
 
1,500

 
25,000

 
U.K.
 
Active
 
 
 
 
 
 
 
 
 
 
 
 
 
Drillships — 4
Noble Duchess
 
Conversion
 
1950 / 2012 R
 
1,500

 
25,000

 
U.A.E.
 
Stacked
Paragon DPDS2
 
Gusto Engineering Pelican Class
 
1978 / 2012 R
 
5,600

 
20,000

 
Puerto Rico
 
Stacked
Paragon DPDS1
 
Gusto Engineering Pelican Class
 
1979 / 2009 R
 
5,000

 
25,000

 
GOM
 
Stacked
Paragon DPDS3
 
NAM Nedlloyd-C
 
1963 / 2013 R
 
7,200

 
25,000

 
Puerto Rico
 
Stacked
 
 
 
 
 
 
 
 
 
 
 
 
 
Standard Specification, Independent Leg Cantilevered Jackups — 32
Paragon C20051 (3)
 
CFEM T-2005-C
 
1982 / 2005 R
 
360

 
30,000

 
The Netherlands
 
Active
Paragon M841
 
MLT Class 84-E.R.C.
 
1975 / 1997 R
 
390

 
25,000

 
GOM
 
Stacked
Paragon C20052 (3)
 
CFEM T-2005-C
 
1982
 
300

 
30,000

 
The Netherlands
 
Active
Paragon M821
 
MLT Class 82-C
 
1976 / 2003 R
 
250

 
20,000

 
GOM
 
Stacked
Paragon M1161
 
MLT Class 116-C
 
1980
 
300

 
25,000

 
India
 
Active
Paragon B152
 
Baker Marine BMC 150
 
1982 / 2004 R
 
150

 
20,000

 
U.A.E.
 
Active
Paragon M823
 
MLT Class 82-SD-C
 
1979 / 1999 R
 
250

 
20,000

 
GOM
 
Stacked
Noble Ed Holt
 
Levingston Class 111-C
 
1981 / 2003 R
 
300

 
25,000

 
India
 
Active
Paragon M825
 
MLT Class 82-SD-C
 
1984 / 2003 R
 
250

 
20,000

 
Cameroon
 
Stacked
Paragon M842
 
MLT Class 84-E.R.C.
 
1975 / 1995 R
 
390

 
25,000

 
Mexico
 
Stacked
Paragon L1116
 
Levingston Class 111-C
 
1977 / 1996 R
 
300

 
25,000

 
GOM
 
Stacked
Paragon L785
 
F&G L-780 MOD II
 
1981 / 1995 R
 
300

 
25,000

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

 
25,000

 
The Netherlands
 
Active
Paragon L1111
 
Levingston Class 111-C
 
1982 / 2004 R
 
300

 
30,000

 
U.A.E.
 
Stacked
Paragon L1115
 
Levingston Class 111-C
 
1977 / 2001 R
 
300

 
25,000

 
U.A.E.
 
Stacked
Paragon L784
 
F&G L-780 MOD II
 
1982 / 2002 R
 
300

 
25,000

 
U.A.E.
 
Stacked
Paragon L1113
 
Levingston Class 111-C
 
1975 / 1995 R
 
300

 
25,000

 
GOM
 
Stacked
Paragon B301
 
Baker Marine BMC 300
 
1976 / 1993 R
 
300

 
25,000

 
GOM
 
Stacked
Paragon B391 (3)(4)
 
BMC 300 Harsh Weather Class
 
1982 / 2001 R
 
390

 
25,000

 
U.K.
 
Active
Paragon L786
 
F&G L-780 MOD II
 
1982 / 1998 R
 
300

 
25,000

 
India
 
Active
Paragon M531
 
MLT Class 53-E.R.C.
 
1972 / 1998 R
 
390

 
25,000

 
GOM
 
Stacked
Paragon M826
 
MLT Class 82-SD-C
 
1983 / 1990 R
 
250

 
20,000

 
U.A.E.
 
Stacked
Paragon C461 (3)
 
MSC/CJ-46
 
1982
 
250

 
25,000

 
The Netherlands
 
Stacked
Paragon L782
 
F&G L-780 MOD II
 
1981 / 1995 R
 
300

 
25,000

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

 
25,000

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

 
25,000

 
The Netherlands
 
Stacked
Paragon L781
 
F&G L-780 MOD II
 
1982 / 1998 R
 
300

 
25,000

 
GOM
 
Stacked
Paragon M1162
 
MLT Class 116-C
 
1979 / 2009 R
 
300

 
25,000

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

 
25,000

 
GOM
 
Stacked
Paragon M824
 
MLT Class 82-SD-C
 
1982
 
250

 
25,000

 
GOM
 
Stacked
Paragon L783
 
F&G L-780 MOD II
 
2003 R
 
300

 
25,000

 
Cameroon
 
Stacked

36


Name
 
Make
 
Year Built/Rebuilt(1)
 
Water
Depth
Rating
(feet)
 
Drilling
Depth
Capacity
(feet)
 
Location
 
Status(2)
Dhabi II
 
Baker Marine BMC 150 ILC
 
1981 / 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

 
The Netherlands
 
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 may not be 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
Additional information regarding legal proceedings, including our Bankruptcy cases, is set forth in Part II, Item 8, Note 1 - “Organization, Current Events and Basis of Presentation” and Note 19 - “Commitments and Contingencies” .
As of December 31, 2016, we were involved in a number of lawsuits and matters which have arisen in the ordinary course of business for which we do not expect the liability, if any, to have a material adverse effect on our Consolidated Balance Sheets, Consolidated Statements of Operations and Consolidated Statements of Cash Flows. We cannot predict with certainty the outcome or effect of 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 could materially differ from management’s current estimates.
On August 23, 2016, we received notice from the Brazilian Institute of Environmental and Renewable Natural Resources (“IBAMA”) regarding an infraction that occurred on a Noble vessel operated by our subsidiary prior to the Spin-Off. The infraction related to an incident onboard the Noble Dave Beard in May 2011 regarding the discharge of oil into the sea and the subsequent communication to IBAMA regarding such discharge. We filed an administrative defense to the infraction on September 12, 2016. As the incident related to a Noble vessel prior to the Spin-Off, we intend to seek indemnification from Noble with respect to any fines assessed by IBAMA regarding this incident pursuant to the Brazil Transition Services Agreement.
ITEM 4.    MINE SAFETY DISCLOSURES
Not applicable.

37


PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market for Shares and Related Shareholder Information
Our shares began regular-way trading on the NYSE on August 4, 2014. On December 17, 2015, we received a letter from the NYSE notifying us that the NYSE had suspended trading in our shares effective immediately. The NYSE determined that the Company’s ordinary shares were no longer suitable for listing based on “abnormally low” price levels, pursuant to Section 802.01D of the NYSE’s Listed Company Manual. The last day that the Company’s ordinary shares traded on the NYSE under the symbol “PGN” was December 17, 2015. On December 18, 2015, the Company’s ordinary shares began trading on the OTC Market Group Inc.’s OTCQX market under the ticker symbol “PGNPF.” Upon filing our voluntary petitions for relief under chapter 11 of the Bankruptcy Code, we began trading on the OTC Pink under the symbol “PGNPQ”. On March 3, 2017 the closing price of our shares as reported by the OTC Pink was $0.07 per share.

Although our ordinary shares are currently quoted on the OTC Pink, there is no broadly followed or established public trading market for our ordinary shares and there is no assurance that an established public trading market will develop or be maintained. The OTC Pink is a significantly more limited market than the national securities exchanges. The quotation of our ordinary shares on the OTC Pink may result in a less liquid market available for our shareholders to trade our ordinary shares, could depress the trading price of our ordinary shares, and could have a long-term adverse impact on our ability to raise capital in the future.

On March 3, 2017, there were 88,641,896 shares outstanding held by 217 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.
The following table includes, for the periods indicated, the high and low sales prices and dividends or returns of capital declared and paid in U.S. dollars on the OTC Pink, OTCQX or NYSE (as applicable), for the quarters presented. Prices represent inter-dealer quotations without adjustments for markups, markdowns, and commissions, and may not represent actual transactions.
2016
 
High
 
Low
 
Fourth quarter
 
$
0.77

 
$
0.15

 
Third quarter
 
0.81

 
0.38

 
Second quarter
 
1.09

 
0.25

 
First quarter
 
0.37

 
0.07

 
 
 
 
 
 
 
2015
 
 
 
 
 
Fourth quarter
 
$
0.34

 
$
0.06

 
Third quarter
 
1.15

 
0.22

 
Second quarter
 
2.19

 
1.08

 
First quarter
 
3.40

 
1.05

 
The declaration and payment of dividends requires authorization of our Board of Directors provided that such dividends on issued share capital may be paid only out of our “distributable reserves” on our statutory balance sheet. We are not permitted to pay dividends out of share capital, which includes share premiums. Any determination to declare a dividend, will be based on our board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook, business needs and other factors that our board considers relevant factors at that time. As proposed by the New Plan, if approved, we will not be paying any dividends following our emergence from bankruptcy.

38


Share 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) and ending December 31, 2016. 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.
capturea28.jpg
 
 
INDEXED RETURNS
Company Name / Index
 
8/4/2014
 
12/31/2014
 
6/30/2015
 
12/31/2015
 
6/30/2016
 
12/31/2016
Paragon Offshore
 
$
100.00

 
$
25.86

 
$
10.18

 
$
0.84

 
$
7.00

 
$
2.15

S&P Small Cap 600 Index
 
100.00

 
107.75

 
112.24

 
105.63

 
112.20

 
133.68

Dow Jones U.S. Oil Equipment & Services
 
100.00

 
71.07

 
70.17

 
55.10

 
61.43

 
70.15

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 Exchange Act, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

39


ITEM 6.    SELECTED CONSOLIDATED FINANCIAL DATA
The following table includes our selected consolidated financial data over the five-year period ended December 31, 2016, which information is derived from our audited consolidated 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 Item 8,“Financial Statements and Supplementary Data”.
 
 
Year Ended December 31,
(In thousands, except per share amounts and percentages)
 
2016
 
2015
 
2014
 
2013
 
2012
Statement of Operations Data:
 
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
636,176

 
$
1,492,428

 
$
1,993,762

 
$
1,893,002

 
$
1,541,857

Operating income (loss)
 
(169,376
)
 
(941,374
)
 
(524,677
)
 
453,745

 
176,712

Loss on impairments (1)
 
(129,915
)
 
(1,181,358
)
 
(1,059,487
)
 
(43,688
)
 

Reorganization items, net (2)
 
(70,670
)
 

 

 

 

Net income (loss) attributable to Paragon Offshore
 
(338,356
)
 
(999,643
)
 
(646,746
)
 
360,305

 
126,237

 
 
 
 
 
 
 
 
 
 
 
Per Share Data (3):
 
 
 
 
 
 
 
 
 
 
Earnings (loss) per share -
basic and diluted
 
$
(3.87
)
 
$
(11.65
)
 
$
(7.63
)
 
$
4.25

 
$
1.49

Weighted average shares outstanding - basic and diluted
 
87,534

 
85,785

 
84,753

 
84,753

 
84,753

 
 
 
 
 
 
 
 
 
 
 
Balance Sheet Data (at end of period):
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents (4)
 
$
883,794

 
$
773,571

 
$
56,772

 
$
36,581

 
$
70,538

Property and equipment, net
 
812,772

 
1,111,098

 
2,410,360

 
3,459,684

 
3,551,813

Total assets (5)
 
1,903,731

 
2,362,847

 
3,230,170

 
3,982,799

 
4,118,072

Long-term debt (5) (6)
 
165,963

 
2,538,444

 
1,865,220

 
1,561,141

 
339,806

Total debt (5) (6) (7)
 
195,700

 
2,579,073

 
2,137,386

 
1,561,141

 
339,806

Liabilities subject to compromise (8)
 
2,344,563

 

 

 

 

Total Paragon equity (deficit)
 
(832,757
)
 
(506,590
)
 
491,608

 
2,005,333

 
3,365,232

 
 
 
 
 
 
 
 
 
 
 
Cash Flows Data:
 
 
 
 
 
 
 
 
 
 
Net cash from operating activities
 
$
253,372

 
$
483,733

 
$
696,989

 
$
822,475

 
$
405,484

Net cash from investing activities
 
(70,339
)
 
(204,444
)
 
(453,218
)
 
(317,726
)
 
(540,867
)
Net cash from financing activities
 
(72,810
)
 
437,510

 
(223,580
)
 
(538,706
)
 
130,154

 
 
 
 
 
 
 
 
 
 
 
Other Data (9):
 
 
 
 
 
 
 
 
 
 
Working capital
 
$
836,959

 
$
869,034

 
$
(9,000
)
 
$
217,450

 
$
253,816

Average dayrate (10)
 
 
 
 
 
 
 
 
 
 
Jackups
 
$
105,526

 
$
121,980

 
$
115,622

 
$
102,974

 
$
88,120

Floaters
 
283,799

 
262,521

 
290,408

 
261,827

 
236,767

Average utilization (11)
 
 
 
 
 
 
 
 
 
 
Jackups
 
34
%
 
62
%
 
79
%
 
90
%
 
81
%
Floaters
 
20
%
 
75
%
 
76
%
 
66
%
 
62
%
Total capital expenditures
 
$
43,405

 
$
202,909

 
$
261,641

 
$
366,361

 
$
532,404



40


(1)
See Part II, Item 8, Note 5 - “Property and Equipment and Other Assets” for discussion on the non-cash impairment losses recognized.
(2)
See Part II, Item 8, Note 10 - “Reorganization Items” for discussion on reorganization items.
(3)
No earnings were allocated to unvested share-based payment awards in our earnings per share calculation for the years ended December 31, 2016, 2015 and 2014 due to our net losses in those years. 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.
(4)
Consists of cash and cash equivalents as reported on our Consolidated Balance Sheets.
(5)
In the first quarter of 2016, we adopted the guidance issued by the FASB in April 2015 in ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. Debt issuance cost are presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount and are being amortized over the life of the debt. In our December 31, 2015 and 2014 balance sheet data presented in this five-year table, we reclassified $21 million and $23 million, respectively, of debt issuance costs for our Senior Notes, Term Loan Facility, and Sale-Leaseback Transaction from “Other assets” to “Long-term debt” to conform to the current period presentation of debt issuance costs.
(6)
Predecessor historical long-term debt and total debt represent outstanding indebtedness under Noble’s commercial paper program which was repaid with payments from Paragon to Noble in connection with the Spin-Off. See note (8) for long-term debt balance as of December 31, 2016.
(7)
Consists of long-term debt and current portion of long-term debt.
(8)
As a result of the filing of the Bankruptcy cases on February 14, 2016, we have classified pre-petition liabilities that may be affected by a plan of reorganization as liabilities subject to compromise in our consolidated financial statements as of December 31, 2016. The Revolving Credit Facility, Senior Notes, and Term Loan Facility may be affected by a plan of reorganization which is subject to confirmation by the Bankruptcy Court. As such, the outstanding balances of these debt instruments and related accrued pre-petition interest (for the Senior Notes only), unamortized debt issuance costs and unamortized discount (for Term Loan Facility only) have been classified as liabilities subject to compromise in the Consolidated Balance Sheet as of December 31, 2016. See Part II, Item 8, Note 9 - “Liabilities Subject to Compromise” for additional discussion on the amounts currently classified as liabilities subject to compromise.
(9)
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.
(10)
See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Market Outlook and Results of Operations” for a discussion of trends in the industry relating to dayrates and the impact of average dayrates on our operating results.
(11)
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. See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations ” for a discussion of the impact of average utilization on our operating results.


41


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, 2016 and 2015, and our results of operations for each of the years in the three-year period ended December 31, 2016, and should be read in conjunction with the accompanying consolidated financial statements and related notes in Item 8, “Financial Statements and Supplementary Data”.
OVERVIEW
Our 2016 financial and operating results include:
operating revenues totaling $636 million;
net loss of $338 million or a loss of $3.87 per diluted share;
pre-tax impairment charge of $130 million; and
net cash from operating activities totaling $253 million
The Company
We are a global provider of offshore drilling rigs. Our fleet includes 34 jackups (including two high specification heavy duty/harsh environment jackups), four drillships and one semisubmersible. Our primary business is contracting our 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 in significant hydrocarbon-producing geographies throughout the world, including the North Sea, the Middle East and India. As of December 31, 2016, our contract backlog was $242 million and included contracts with national, international and independent oil and gas companies.
We are a public limited company registered under the Companies Act 2006 of England. In July 2014, Noble Corporation 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”).
Chapter 11 Filing
On February 14, 2016, the Debtors filed voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On April 19, 2016, the Bankruptcy Court approved the Company’s disclosure statement and certain amendments to the Original Plan. On August 15, 2016, the Debtors filed certain amendments to the Original Plan and a supplemental disclosure statement with the Bankruptcy Court. By oral ruling on October 28, 2016, and by written order dated November 15, 2016, the Bankruptcy Court denied confirmation of the Debtors’ amended Original Plan. Consequently, on November 29, 2016, the Noteholder Group terminated the PSA effective as of December 2, 2016.
On February 7, 2017, the Company filed the New Plan and related disclosure statement with the Bankruptcy Court. The New Plan provides for, among other things, the elimination of approximately $2.4 billion of previously existing debt in exchange for a combination of cash, debt and new equity. Existing shareholders of the Company will not receive a recovery under the New Plan. The New Plan will be subject to the usual and customary conditions to plan confirmation, including obtaining the requisite vote of creditors and the approval of the Bankruptcy Court.
Since the filing date, the Debtors have operated their business as “debtors-in-possession”. Under the Bankruptcy cases, the Debtor’s trade creditors and vendors are being paid in full in the ordinary course of business and all of the Company’s contracts have remained in effect in accordance with their terms preserving the rights of all parties.
As required by FASB ASC 852, Reorganizations (“ASC 852”) we intend to adopt fresh start accounting upon emergence from chapter 11 of the Bankruptcy Code.
For additional discussion of the Bankruptcy cases and its effects, see See Item 8, Note 1 -“Organization, Current Events and Basis of Presentation” and Part I, Item 1A, “Risk Factors - Risk Factors Related to Our Restructuring”.

42


Acquisition of Prospector Offshore Drilling S. A.

On November 17, 2014, we initiated the acquisition of the outstanding shares of Prospector, an offshore drilling company organized in Luxembourg and traded on the Oslo Axess, from certain shareholders and in open market purchases. On February 23, 2015, we acquired all remaining issued and outstanding shares of Prospector.
The Prospector acquisition expanded and enhanced our global fleet by adding two high specification jackups (the Prospector 1 and Prospector 5) at the date of acquisition for use in the U.K. sector of the North Sea. Additionally, three subsidiaries of Prospector contracted for the construction of three high specification jackup rigs, the Prospector 6, Prospector 7 and Prospector 8 by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China. In December 2016, we agreed with SWS to an extension of the delivery of the Prospector 6, Prospector 7 and Prospector 8 to the fourth quarter of 2017. Each newbuild has been built pursuant to a contract between one of these subsidiaries and SWS, without our parent company guarantee or other direct recourse to any of our subsidiaries other than the applicable subsidiary. The Prospector subsidiaries were not included in the Bankruptcy cases. See Part I, Item 1A, “Risk Factors - Risk Factors Related to Our Business”.
Basis of Presentation
The financial information contained within this report includes periods prior to the Spin-Off on August 1, 2014.  For these periods prior to the Spin-Off, the consolidated financial statements and related discussion of financial condition and results of operations include historical results of our Predecessor, which comprised most of Noble’s standard specification drilling fleet and related operations. We consolidate the historical financial results of our Predecessor in our consolidated financial statements for all periods prior to the Spin-Off. All financial information presented after the Spin-Off represents the consolidated results of operations, financial position and cash flows of Paragon. For more detailed information, refer to Item 8, “Financial Statements and Supplementary Data”.
The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Our ability to continue as a going concern is contingent upon obtaining the requisite vote of creditors and the Bankruptcy Court’s approval of our plan of reorganization as described below. This represents a material uncertainty related to events and conditions that raises substantial doubt on our ability to continue as a going concern and, therefore, we may be unable to realize our assets and discharge our liabilities in the normal course of business.
MARKET OUTLOOK
Brent crude oil prices are a key factor in determining our customers’ current activity levels, as well as a critical input customers use to set future budgets and define drilling programs. In the fourth quarter of 2016, Brent prices rose nearly 16% from the September 30, 2016 closing price of $49.06 per barrel following the announcement of an OPEC agreement to limit production, closing at $56.82 per barrel on December 31, 2016. For the full year 2016, Brent crude finished 52% higher than its closing price of $37.28 per barrel on December 31, 2015. Year-to-date, as of March 3, 2017, Brent crude oil prices have declined by approximately 2% to $55.90 per barrel.
Fixture activity in the fourth quarter of 2016 for both jackups and floaters increased as compared to the third quarter of 2016. According to industry data, there were 56 new jackup contract announcements or fixtures during the fourth quarter of 2016 compared to 46 new fixtures during the third quarter of 2016. Both totals exclude instances where companies mutually agreed to renegotiate dayrates which numbered five and zero in the fourth and third quarters of 2016, respectively. Nineteen of the fixtures in the fourth quarter of 2016 were between a Chinese drilling contractor and a Chinese oil company and generally not considered to be competitive opportunities for international drilling contractors. This is consistent with activity from the fourth quarter 2015 where 16 of the fixtures were between a Chinese drilling contractor and a Chinese oil company.
Activity for jackups was lower than in fourth quarter of 2015, when 60 new fixtures were reported. In the floater segment, there was an increase in activity quarter-on-quarter with 31 new fixtures and 2 renegotiations during the fourth quarter of 2016 compared to 21 new fixtures and 2 renegotiations during the third quarter of 2016. New contracting activity for floaters was higher year-on-year when compared with fourth quarter 2015, which saw 28 new fixtures and no renegotiations.
Average jackup dayrates for new fixtures in the fourth quarter of 2016 were approximately $74,000. This is below the average new jackup fixture dayrate of $77,000 for the third quarter of 2016, excluding a $275,000 per day fixture for a high specification jackup in the Norwegian sector of the North Sea, a region not comparable to the rest of the global market due to the special technical requirements of jackups which operate in those waters. Compared to $113,000 per day for the average new dayrate fixture in the fourth quarter of 2015, dayrates in fourth quarter of 2016 were 34% lower.

43


During the fourth quarter of 2016, dayrates for new floater fixtures fell 9% quarter-over-quarter, averaging approximately $241,000 per day compared to $264,000 per day in the third quarter of 2016. New floater fixture dayrates in the fourth quarter 2016 were 11% lower than the average in fourth quarter 2015 of $271,000 per day. The dayrate data is based on information provided by third party sources and excludes fixtures for which no dayrate has been publicly reported.
As of February 1, 2017, there were 103 jackup drilling rigs under construction according to third party data sources. These rigs are currently scheduled for delivery between 2017 through as late as 2020. Certain drilling contractors with jackups under construction, including Paragon, have reported that they have reached agreements with the shipyards where their rigs are under construction to delay the delivery of their rigs as a result of the challenging market environment. This combination of new supply and lower activity levels has negatively impacted the contracting environment, and has intensified price competition. If this persists, we could be required to increase our capital investment to keep our jackup rigs competitive or to stack or scrap rigs that are no longer marketable in the current environment.
In addition, there are reported to be 48 floating rigs under construction or on order according to third party data sources with deliveries between 2017 and 2020. Break even oil prices for projects requiring the use of floating assets are significantly higher than for projects requiring jackup rigs. Also, a greater portion of the industry’s exploration work is done in deepwater as compared to shallow water and exploration budgets are often reduced or eliminated in periods of low commodity prices. We believe these factors will continue to put pressure on the dayrates and utilization for floating assets for the next several years. We also believe that older floating assets will be at a disadvantage in securing new work because new floating rigs offer greater technical capabilities and efficiencies, which is generally not the case in the jackup segment.
Despite the increase in commodity prices during 2016 and the agreement announced in the fourth quarter of 2016 by OPEC to limit oil production beginning January 2017, there has not been a significant increase in either dayrates or utilization for offshore contract drilling companies. Thus, we remain cautious in our near-term outlook. Third party surveys of expected capital spending by upstream oil and gas companies suggest that there could be an increase in capital spending in 2017 onshore North America, where breakeven costs are expected to be below offshore breakeven costs. We believe a natural progression of increased industry activity would be for our customers to begin to pursue shallow water opportunities utilizing jackup rigs followed by an eventual recovery for deep and ultradeepwater projects utilizing floating rigs. However, we cannot predict when this increase in activity across the various segments may occur. While Paragon is positioning itself to benefit from an eventual industry recovery, we are not expecting one in the immediate future and we may experience low dayrates relative to historical highs and low utilization levels for some time.
Contract Drilling Services Backlog
We maintain a backlog (as defined below) of commitments for contract drilling services. The following table includes, as of December 31, 2016, 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
 
2017
 
2018
 
 
 
 
 
 
 
 
 
Drilling service backlog
 
$
242

 
$
215

 
$
27

 
Percent of available days committed (1)
 
 
 
21
%
 
6
%
 
(1)
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.
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, 2016, our contract drilling services backlog did not include any letters of intent.
Petrobras has contested the term of each of our drilling contracts for the Paragon DPDS2 and the Paragon DPDS3 in connection with the length of prior shipyard projects relating to these rigs and released the Paragon DPDS2 effective September

44


29, 2015. Under our interpretation of the contract, the Paragon DPDS3 was scheduled to work until August 2017. However, in accordance with Petrobras’ interpretation of the contract, the Paragon DPDS3 was released in August 2016. Both rigs are currently stacked in a shipyard in Puerto Rico and Paragon is winding down its operational presence in Brazil. Backlog related to this dispute is not included in our reported backlog as of December 31, 2016. Paragon will vigorously pursue all legal remedies available to us under these contracts.
We calculate backlog for any given rig and period by multiplying the full contractual operating dayrate for such rig 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 revenues for the periods for which the backlog is calculated.


45


RESULTS OF OPERATIONS
2016 Compared to 2015
Net loss for 2016 was $338 million, or a loss of $3.87 per diluted share, on operating revenues of $636 million, compared to a net loss for 2015 of $1.0 billion, or a loss of $11.65 per diluted share, on operating revenues of $1.5 billion.
Rig Utilization, Operating Days and Average Dayrates
Our operating results for contract drilling services segment are dependent on two primary metrics: rig utilization and dayrates. The following table includes the average rig utilization, operating days, and average dayrates for our rig fleet for 2016 and 2015:
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates
(Dollars in thousands)
2016
 
2015
 
2016
 
2015
 
% Change
 
2016
 
2015
 
% Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jackups
34
%
 
62
%
 
4,282

 
7,680

 
(44
)%
 
$
105,526

 
$
121,980

 
(13
)%
Floaters
20
%
 
75
%
 
434

 
1,645

 
(74
)%
 
283,799

 
262,521

 
8
 %
       Total
32
%
 
64
%
 
4,716

 
9,325

 
(49
)%
 
$
121,919

 
$
146,779

 
(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.

Operating Results
The following table includes our operating results for the years ended December 31, 2016 and 2015.
 
 
 
 
 
 
Change
(Dollars in thousands)
 
2016
 
2015
 
$
 
%
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
Contract drilling services
 
$
574,976

 
$
1,368,731

 
$
(793,755
)
 
(58
)%
Labor contract drilling services
 
16,876

 
29,108

 
(12,232
)
 
(42
)%
Reimbursables and other
 
44,324

 
94,589

 
(50,265
)
 
(53
)%
 
 
636,176

 
1,492,428

 
(856,252
)
 
(57
)%
Operating costs and expenses
 
 
 
 
 
 
 
 
Contract drilling services
 
$
360,783

 
$
769,373

 
$
(408,590
)
 
(53
)%
Labor contract drilling services
 
13,691

 
20,599

 
(6,908
)
 
(34
)%
Reimbursables
 
37,366

 
81,291

 
(43,925
)
 
(54
)%
Depreciation and amortization
 
220,237

 
339,268

 
(119,031
)
 
(35
)%
General and administrative
 
43,560

 
59,475

 
(15,915
)
 
(27
)%
Loss on impairments
 
129,915

 
1,181,358

 
(1,051,443
)
 
(89
)%
Gain on sale of assets, net
 

 
(13,217
)
 
13,217

 
**

Gain on repurchase of long-term debt
 

 
(4,345
)
 
4,345

 
**

 
 
805,552

 
2,433,802

 
(1,628,250
)
 
(67
)%
Operating loss
 
$
(169,376
)
 
$
(941,374
)
 
$
771,998

 
(82
)%
**
Not a meaningful percentage.

46


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 49% decrease in operating days which negatively impacted revenues by $733 million. This was coupled with a 17% decrease in average dayrates, which resulted in a $61 million decrease in revenues from the prior year.
The decrease in contract drilling services revenues was attributed to both our floaters and jackups which experienced decreases of $309 million and $485 million, respectively, in the current year as compared to the prior year.
The decrease in floater revenues of $309 million in the current year was driven by a 74% decrease in operating days partially offset by a 8% increase in average dayrates which resulted in a $318 million decrease and a $9 million increase in revenues, respectively, from the prior year.
The decrease in operating days for our floaters in the current year as compared to the prior year was primarily attributable to Noble Duchess and Paragon DPDS2, which were uncontracted for all of the current year but experienced utilization in India and Brazil, respectively, in the prior year. Paragon MSS1 operating in the North Sea, Paragon MSS2 and Paragon DPDS3 both operating in Brazil also experienced a decrease in operating days in the current year as compared to the prior year. The overall increase in average dayrates in the current year resulted from additional revenue earned for unused shipyard days upon contract completion of Paragon MSS2 in the second quarter of 2016.
The $485 million decrease in jackup revenues in the current year was driven by a 44% decrease in jackup operating days which resulted in a $414 million decrease in revenues. This was coupled with a 13% decrease in average dayrates which resulted in decreased revenues of $71 million from the prior year.
The decrease in jackup operating days was primarily related to the rigs operating in Mexico, Paragon M841, Paragon M824, Paragon B301, Paragon L1113, Paragon L781, Paragon M842, and Paragon M821 which were uncontracted for a portion of the current year but were contracted for a greater portion of the prior year. The remaining decrease in operating days is due to Paragon L785 operating in Southeast Asia, Paragon M825, Paragon M826, Paragon L782 and Paragon L783 operating in West Africa, Paragon L1115, Paragon M1162 and Dhabi II operating in the Middle East, and Paragon C461, Paragon C462, Paragon C463, Paragon C20051, Paragon HZ1, Paragon B391, Paragon C20052 and Prospector 1 operating in the North Sea which were uncontracted for a portion of the current year but were contracted for all or a greater portion of the prior year. The decrease in operating days was partially offset by 229 additional operating days in the current year attributable to Paragon L784, Paragon M1161 and Paragon L786 operating in India and 197 additional operating days in the current year attributable to Noble Ed Holt operating in India.
The decrease in jackup average dayrates during the current year was due to an overall decrease in dayrates across our fleet. The decrease in average dayrates was offset by the realization of higher dayrates on contracts for Paragon M842 operating in Mexico, Paragon M826 operating in West Africa, Paragon L784 operating in the Middle East and Prospector 5 operating in the North Sea.
Contract Drilling Services Operating Costs and Expenses — The decrease in contract drilling services operating costs and expenses of $409 million in the current year as compared to the prior year was related to reduced operating days across our fleet as well as cost reduction initiatives implemented across our operations as part of the Company’s strategy to focus on fewer markets and utilize a smaller fleet. In the current year, we initiated a workforce reduction program to align the size and composition of Paragon’s workforce with the Company’s strategy. As a result, we recorded restructuring expense of $12 million consisting of employee severance and other termination benefits in the current year.
Labor Contract Drilling Services Operating Revenues and Costs and Expenses — The decline in revenues and expenses associated with our Canadian labor contract drilling services was primarily related to the termination of the labor contract with Hibernia Management and Development Ltd. in June 2016.
Reimbursables Operating Revenues and Costs and Expenses — Margin on our reimbursables remained relatively constant. 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


Reimbursables in both the current year and prior year include the services we provided to Noble in Brazil, on a cost-plus basis, as part of the Transition Services Agreement entered into in connection with the Spin-Off. We provided both rig-based and shore-based support services to Noble through the term of Noble’s rig contract pursuant to the transition service agreement for Brazil. Noble’s contract in Brazil and the services provided by us concluded in the second quarter of 2016 (See Item 8, Note 19 - “Commitments and Contingencies” for additional detail).
Depreciation and Amortization — Depreciation and amortization decreased $119 million in the current year as compared to the prior year primarily as a result of lower depreciation on assets subject to the impairment charges taken in the third and fourth quarters of 2015.
General and Administrative — General and administrative expenses decreased $16 million in the current year as compared to the prior year. In the prior year, these expenses included professional fees of $9 million incurred in connection with our financial restructuring prior to filing for bankruptcy. In the current year, all professional fees related to the bankruptcy are included in “Reorganization items, net.” The remaining decrease of $7 million was primarily attributable to cost reduction initiatives implemented across the Company.
Loss on Impairment — We identified indicators of impairment in the fourth quarter of 2016, including the possibility for the continued reduction in contracting activity from the delay in our emergence from bankruptcy after the Bankruptcy Court denied confirmation of our Original Plan; no significant improvement in the drilling market in 2016 coupled with our decision to exit our operations in Brazil; and a change of the Company’s strategy to focus on fewer markets and utilize a smaller fleet. Because of these indicators, we performed an impairment assessment of our rig fleet and recorded an impairment loss of $130 million, consisting of $98 million related primarily to six jackups and $32 million related to other capital spares.
During the prior year, we also recorded an impairment loss of $1.1 billion on five floaters, sixteen jackups, deposits related to the three high specification jackups and capital spares. In addition, we determined goodwill was impaired and recorded an impairment loss of $37 million in 2015.
Gain on sale of assets, net — Gain on sale of assets, net during the prior year was attributable to the sale of two of our rigs, Paragon M822 and Paragon DPDS4, partially offset by a loss on the sale and disposal of drill pipe.
Gain on repurchase of long-term debt — In the prior year, we repurchased and canceled an aggregate principal amount of $11 million of our senior notes at an aggregate cost of $7 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 $4 million in the prior year.
Other Expenses
Income tax provision/benefit — Our income tax provision increased $93 million in the current year compared to the prior year, primarily due to the tax benefit of prior year aggregate impairment loss of $1.2 billion, the underlying changes in the profitability and loss associated with our operations in various jurisdictions, including current year valuation allowance in certain jurisdictions, and certain discrete tax items.
Reorganization items, net — The Company uses “Reorganization items, net” to reflect the expenses that are the direct result of the reorganization of the business. Reorganization items of $71 million in the current year primarily relate to professional fees for legal and financial advisors incurred in connection with preparation and handling of the Bankruptcy cases. During the current year, the Company paid cash of approximately $45 million for reorganization items. (See Item 8, Note 10, “Reorganization Items” for additional detail).

2015 Compared to 2014
Our results of operations for the year ended December 31, 2015 consist of the consolidated results of Paragon while our results of operations for the year ended December 31, 2014 consist of results of Paragon for the five months ended December 31, 2014, and the results of our Predecessor for the prior months.
Net loss for 2015 was $1.0 billion, or a loss of $11.65 per diluted share, on operating revenues of $1.5 billion, compared to a net loss for 2014 of $647 million, or a loss of $7.63 per diluted share, on operating revenues of $2.0 billion.


48


Rig Utilization, Operating Days and Average Dayrates
Our operating results for contract drilling services segment are dependent on two primary metrics: rig utilization and dayrates. The following table includes the average rig utilization, operating days, and average dayrates for our rig fleet for 2015 and 2014:
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates
(Dollars in thousands)
2015
 
2014
 
2015
 
2014
 
% Change
 
2015
 
2014
 
% Change
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jackups
62
%
 
79
%
 
7,680

 
10,188

 
(25
)%
 
$
121,980

 
$
115,622

 
5
 %
Floaters
75
%
 
76
%
 
1,645

 
2,371

 
(31
)%
 
262,521

 
290,408

 
(10
)%
       Total (3)
64
%
 
78
%
 
9,325

 
12,559

 
(26
)%
 
$
146,779

 
$
148,620

 
(1
)%
(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. The rigs retained or sold by Noble contributed 493 operating days for the year ended December 31, 2014.
(3)
Average rig utilization calculation reflects 730 fewer available days for our floater fleet in 2015 due to our decision in the fourth quarter of 2014 to retire from service the Paragon MSS3 and the Paragon DPDS4. These rigs were not operating during the year ended December 31, 2014.
(4)
Excludes the Paragon FPSO1, which was retired from service in 2014.

Operating Results
The following table includes our operating results for the years ended December 31, 2015 and 2014.
 
 
 
 
 
 
Change
(Dollars in thousands)
 
2015
 
2014
 
$
 
%
 
 
 
 
 
 
 
 
 
Operating revenues
 
 
 
 
 
 
 
 
Contract drilling services
 
$
1,368,731

 
$
1,866,497

 
$
(497,766
)
 
(27
)%
Labor contract drilling services
 
29,108

 
33,401

 
(4,293
)
 
(13
)%
Reimbursables and other (1)
 
94,589

 
93,864

 
725

 
1
 %
 
 
1,492,428

 
1,993,762

 
(501,334
)
 
(25
)%
Operating costs and expenses
 
 
 
 
 
 
 
 
Contract drilling services
 
769,373

 
890,694

 
(121,321
)
 
(14
)%
Labor contract drilling services
 
20,599

 
24,774

 
(4,175
)
 
(17
)%
Reimbursables (1)
 
81,291

 
77,843

 
3,448

 
4
 %
Depreciation and amortization
 
339,268

 
422,235

 
(82,967
)
 
(20
)%
General and administrative
 
59,475

 
62,081

 
(2,606
)
 
(4
)%
Loss on impairments
 
1,181,358

 
1,059,487

 
121,871

 
12
 %
Gain on sale of assets, net
 
(13,217
)
 

 
(13,217
)
 
**

Gain on repurchase of long-term debt
 
(4,345
)
 
(18,675
)
 
14,330

 
(77
)%
 
 
2,433,802

 
2,518,439

 
(84,637
)
 
(3
)%
Operating loss (2)
 
$
(941,374
)
 
$
(524,677
)
 
$
(416,697
)
 
79
 %
**
Not a meaningful percentage.

49


(1)
We record reimbursements from customers for “out-of-pocket” expenses as operating revenues and the related direct costs as operating expenses. Reimbursables in the current and prior year also include the services we provide Noble in Brazil as part of the Transition Services Agreement entered into in connection with the Spin-Off. 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 the current year as compared to the prior year.
(2)
The rigs retained and sold by Noble represent revenues and costs of $117 million and $72 million, respectively, for the year ended December 31, 2014.
Contract Drilling Services Operating Revenues—Changes in contract drilling services revenues for 2015 as compared to 2014 were driven by a 26% decrease in operating days which negatively impacted revenues by $501 million. This decrease was partially offset by a slight increase in revenues of $3 million attributable to changes in dayrates.
The decrease in contract drilling services revenues was attributed to both our floaters and jackups which experienced decreases of $257 million and $241 million, respectively, in 2015 as compared to 2014.
The decrease in floater revenues of $257 million in 2015 was driven by a 31% decrease in operating days coupled with a 10% decrease in average dayrates which resulted in a $211 million and a $46 million decrease in revenues, respectively, from 2014.
The decrease in both average dayrates and operating days for our floaters was primarily due to the Paragon DPDS1 which was uncontracted for all of 2015 but experienced full utilization in Brazil during 2014. The decrease is also due to the Noble Driller, which was retained by Noble after the Separation.
The $241 million decrease in jackup revenues in 2015 was driven by a 25% decrease in jackup operating days which resulted in a $290 million decrease in revenues. This decline was partially offset by a 5% increase in average dayrates which positively impacted revenues by $49 million from 2014.
The decrease in jackup operating days was due to seven of our rigs in Mexico, which were uncontracted for a portion of 2015 but experienced close to full utilization during 2014. The decrease was also the result of the Noble Alan Hay and the Noble David Tinsley, which were retained by Noble after the Separation. In January 2015, we sold the Paragon M822 which worked 129 days in 2014. The remaining decrease in operating days is primarily due to the Paragon L785 currently in Asia, the Paragon M826 and the Paragon L783 currently in Africa, the Paragon C20052 currently in the North Sea, the Noble Ed Holt currently in India and Paragon L784 currently in the Middle East which were uncontracted for all or a portion of 2015 but were contracted for most of 2014. The decrease in operating days was partially offset by 749 additional operating days in 2015 due to the Prospector 1, Prospector 5, and the Paragon C20051 operating in the North Sea, 438 additional operating days in 2015 due to the Paragon L786 and the Paragon M1161 operating in the Middle East and India and 230 additional operating days due to the Paragon M825 and the Paragon L782 operating in West Africa .
The increase in average dayrates for our jackups resulted from the addition of contracts for the Prospector 1, the Prospector 5 and other contracts entered into during the second half of 2014 in the shallow water market, particularly for our rigs in the North Sea and Africa.
Contract Drilling Services Operating Costs and Expenses — Contract drilling services operating costs and expenses decreased in 2015 as compared to 2014 due to the reduction in contract drilling operating costs from the rigs retained by Noble as well as reduced contracting activity for our floaters in Brazil and jackups in Mexico. These decreases were partially offset by an increase attributable to the operating costs of the Prospector 1 and Prospector 5 added as a result of the Prospector acquisition, as well as an increase in provision for doubtful accounts associated with customer receivables that was recorded in 2015.
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. Revenues and expenses associated with our labor contract drilling services remained relatively constant.
Reimbursables Operating Revenues and Costs and Expenses —The $1 million increase in reimbursable revenues and the related $3 million increase in reimbursable costs in 2015 from 2014 were primarily due to transition support services we provided, on a cost-plus basis, to Noble’s remaining Brazil operations. We continued 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 Item 8, Note 19 -‘Commitments and Contingencies for additional detail).

50


Depreciation and Amortization — The $83 million decrease in depreciation and amortization in 2015 was primarily attributable to lower depreciation in 2015 on assets subject to the impairment charge taken in the third quarter of 2015 and the third and fourth quarters of 2014 as well as the rigs retained by Noble, partially offset by increased depreciation for the Prospector 1 and Prospector 5.
General and Administrative — General and administrative expenses in 2015 represent actual costs incurred for periods subsequent to the Spin-Off. Costs incurred during 2015 include $9 million of professional fees related to our financial restructuring. Excluding the restructuring fees, costs were 19% lower than 2014 due to differences in staffing levels of our organization relative to Noble’s levels prior to the Distribution and other cost control measures taken. Costs in 2014 primarily represent costs allocated to our Predecessor based on certain support functions that were provided by Noble on a centralized basis.
Loss on Impairment — In 2015, as a result of the identification of certain indicators of impairment, consisting of the continuing decline of the drilling industry, coupled with the release of the Paragon DPDS2, the increased probability of lower activity in Brazil and Mexico, and the downward trend of dayrates, we performed an impairment assessment of our rig fleet and recorded an impairment loss of $1.1 billion on five floaters, sixteen jackups, deposits and other Construction in Progress (“CIP”) assets and capital spares. We determined goodwill was impaired and recorded an impairment loss of $37 million for the year ended December 31, 2015.
During 2014, we also identified triggering events, which required us to perform an impairment assessment of our fleet of drilling rigs. We determined that the Paragon DPDS1, Paragon DPDS2 and Paragon DPDS3 drilling rigs were impaired. Additionally, we decided to scrap the Paragon FPSO1, Paragon MSS3, Paragon B153 and Paragon DPDS4. Based on that analysis, we recognized an impairment loss of $1.1 billion for the year ended December 31, 2014.
Gain on sale of assets, net — Gain on sale of assets, net during 2015 was attributable to the sale of two of our rigs, the Paragon M822 and the Paragon DPDS4, partially offset by a loss on the sale and disposal of drill pipe.
Gain on repurchase of long-term debt — During the first quarter of 2015, we repurchased and canceled an aggregate principal amount of $11 million of our senior notes at an aggregate cost of $7 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 $4 million.
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.
Income tax provision/benefit — Our income tax benefit increased $142 million in 2015 compared to 2014, primarily due to the tax effect of the aforementioned aggregate impairment loss of $1.2 billion during the current year, the underlying changes in the profitability and loss associated with our operations in various jurisdictions, including net operating losses in 2015 offset by valuation allowance if appropriate in certain jurisdictions, and certain discrete tax items.


51


Non-GAAP Performance Measure: Adjusted EBITDA

Item 10(e) of Regulation S-K, Regulation G, General Rules Regarding Disclosure of Non-GAAP Financial Measures and other SEC rules, regulations and interpretations define and prescribe the conditions for use of certain Non-Generally Accepted Accounting Principles (“Non-GAAP”) financial measures. We use the Non-GAAP measure Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) before taxes plus interest expense, depreciation and amortization, losses on impairments, foreign currency losses and reorganization items, less gains on the sale of assets, interest income and foreign currency gains. Adjusted EBITDA, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with U.S. GAAP. Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by or used in operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with U.S. GAAP. However, we believe Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure: (1) is used by investors in our industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors; (2) helps investors and creditors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of certain non-recurring transactions, our capital structure and asset base from its operating structure; and (3) is used by our management as a basis for strategic planning and forecasting. There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, and the lack of comparability of results of operations of different companies.
The reconciliation from net loss to Adjusted EBITDA is as follows:
 
 
 
Year Ended December 31,
(in thousands)
 
2016
 
2015
 
2014
Net loss
 
$
(338,356
)
 
$
(999,643
)
 
$
(646,746
)
Adjustments:
 
 
 
 
 
 
Depreciation and amortization
 
220,237

 
339,268

 
422,235

Loss on impairments
 
129,915

 
1,181,358

 
1,059,487

Gain on sale of assets, net
 

 
(13,217
)
 

Gain on repurchase of long-term debt
 

 
(4,345
)
 
(18,675
)
Interest expense, net
 
77,271

 
130,036

 
56,654

Other, net
 
553

 
310

 
(3,920
)
Reorganization items, net
 
70,670

 

 

Income tax (benefit) provision
 
20,486

 
(72,108
)
 
69,394

Adjusted EBITDA
 
$
180,776

 
$
561,659

 
$
938,429

 


52


LIQUIDITY AND CAPITAL RESOURCES
Going Concern
The accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business. Our ability to continue as a going concern is contingent upon obtaining the requisite vote of creditors and the Bankruptcy Court’s approval of our plan of reorganization as described below. This represents a material uncertainty related to events and conditions that raises substantial doubt on our ability to continue as a going concern and, therefore, we may be unable to realize our assets and discharge our liabilities in the normal course of business.
During the period that we are operating as debtors-in-possession under chapter 11 of the Bankruptcy Code, we may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business (and subject to restrictions in our debt agreements), for amounts other than those reflected in the accompanying consolidated financial statements. Further, our reorganization plan could materially change the amounts and classifications of assets and liabilities reported in the consolidated financial statements. The accompanying consolidated financial statements do not include any adjustments related to the recoverability and classification of assets or the amounts and classification of liabilities or any other adjustments that might be necessary should we be unable to continue as a going concern.
Financial Resources and Liquidity Overview
Our primary sources of liquidity are cash generated from operations, any future financing arrangements, and equity issuances, subject to the restrictions in our Debt Facilities. Our principal uses of liquidity will be to fund our operating expenditures and capital expenditures, including major projects, upgrades and replacements to drilling equipment and to service our outstanding indebtedness.
As of December 31, 2016, we had available liquidity of $884 million in cash and cash equivalents.
The table below includes a summary of our cash flow information for the years ended December 31, 2016, 2015, and 2014. Our cash flows for the years ended December 31, 2016 and 2015 consist entirely of the consolidated results of Paragon while our cash flows for the year ended December 31, 2014 consist of the results of Paragon for the five months ended December 31, 2014 and the results of our Predecessor for the seven months ended July 31, 2014.
 
 
Year Ended December 31,
(In thousands)
 
2016
 
2015
 
2014
Cash flows provided by (used in):
 
 
 
 
 
 
Operating activities
 
$
253,372

 
$
483,733

 
$
696,989

Investing activities
 
(70,339
)
 
(204,444
)
 
(453,218
)
Financing activities
 
(72,810
)
 
437,510

 
(223,580
)
Changes in cash flows from operating activities for the year ended December 31, 2016 are driven by the overall decrease in our business activity (see discussion of changes in net loss in “Results of Operations” above). Changes in cash flows used in investing activities are dependent upon our level of capital expenditures, which varies based on the timing of projects. Cash used for capital expenditures totaled $52 million, $218 million, and $260 million in 2016, 2015, and 2014, respectively. During the year ended December 31, 2016, our net cash from investing activities was also impacted by an increase in restricted cash related to cash collateral for an outstanding performance bond and reserve requirements on the Sale-Leaseback Transaction. Changes in cash flows used in financing activities for the year ended December 31, 2016 are due to the reduction of debt activity during the bankruptcy proceedings, except for repayments on our Sale-Leaseback Transaction.
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; and
service of outstanding indebtedness, including mandatory pre-payments.

53


We currently expect to fund these cash flow needs with cash generated by our operations, available cash balances, or asset sales as allowed under our credit agreements.
Revolving Credit Facility, Senior Notes and Term Loan Facility
See Item 8, Note 8 -“Debt for descriptions of our debt instruments.
As of December 2015, we drew down substantially all of the available borrowing capacity under our Revolving Credit Facility to preserve liquidity. On January 15, 2016 we elected to defer an interest payment of approximately $15 million due on our 6.75% senior unsecured notes maturing July 2022, and to operate under the 30-day grace period provided for in the notes indenture. We utilized the 30-day grace period to continue negotiations with our stakeholders and prepare for an in-court restructuring. Accordingly, under the direction of an independent committee of our Board of Directors, on February 12, 2016, the Debtors entered into the Original Plan.
On February 14, 2016, the Debtors filed the Bankruptcy cases. The commencement of the Bankruptcy cases constituted an event of default that accelerated our obligations under the Term Loan Agreement, Revolving Credit Agreement, and Senior Notes. Any efforts to enforce payments related to these obligations are automatically stayed as a result of the filing of the petitions and are subject to the applicable provisions of the Bankruptcy Code.
Upon filing the Bankruptcy cases, we began trading on the OTC Pink.
On April 19, 2016, the Bankruptcy Court approved the Company’s disclosure statement and certain amendments to the Original Plan.
Effective August 5, 2016, the Company entered into the PSA Amendment with the Revolver Lenders and lenders holding approximately 69% in principal amount of our Senior Notes. The PSA Amendment supported certain revisions to the Original Plan. On August 15, 2016, the Debtors filed the amended Original Plan and a supplemental disclosure statement with the Bankruptcy Court.
By oral ruling on October 28, 2016, and by written order dated November 15, 2016, the Bankruptcy Court denied confirmation of the Debtors’ amended Original Plan. Consequently, on November 29, 2016, the Noteholder Group terminated the PSA effective as of December 2, 2016.
On January 18, 2017, the Company announced that it reached agreement in principle with a steering committee of lenders under our Revolving Credit Agreement and an ad hoc committee of lenders under our Term Loan Agreement to support a new chapter 11 plan of reorganization for the Debtors (the “New Plan”). On February 7, 2017, the Company filed the New Plan and related disclosure statement with the Bankruptcy Court. The New Plan provides for, among other things, the (i) elimination of approximately $2.4 billion of the Company’s existing debt in exchange for a combination of cash, debt and new equity to be issued under the New Plan; (ii) allocation to the Secured Lenders of new senior first lien debt in the original aggregate principal amount of $85 million maturing in 2022; (iii) projected distribution to the Secured Lenders of approximately $418 million in cash, subject to adjustment on account of claims reserves and working capital and other adjustments at the time of the Company’s emergence from the Bankruptcy cases, and an estimated 58% of the new equity of the reorganized company; (iv) projected distribution to the Bondholders of approximately $47 million in cash, subject to adjustment on account of claims reserves and working capital and other adjustments at the time of the Company’s emergence from the Bankruptcy cases, and an estimated 42% of the new equity of the reorganized company; and (v) commencement of an administration of the Company in the United Kingdom to, among other things, implement a sale of all or substantially all of the assets of the Company to a new holding company to be formed, which administration may be effected on or prior to effectiveness of the New Plan. Existing shareholders of the Company will not receive a recovery under the New Plan. The New Plan will be subject to usual and customary conditions to plan confirmation, including obtaining the requisite vote of creditors and approval of the Bankruptcy Court. The Company has been and remains in discussions with the Bondholders, who have currently not agreed to support the New Plan, and therefore, there is no guarantee that the New Plan will be approved.
For additional discussion of the risks associated with our indebtedness and current issues, see Part I, Item 1A, “Risk Factors”.
Meeting Our Liquidity Needs
We have maintained our liquidity position by giving priority to generating cash flows, including cost and capital expenditure reductions, while maintaining our long-term commitment to providing high quality services.  During the pendency of the Bankruptcy cases and upon emergence from bankruptcy, we expect that our primary sources of liquidity will continue to

54


be cash on hand and cash flows from operations. In addition to the cash requirements to fund ongoing operations, we have incurred and continue to incur significant professional fees and other costs in connection with preparation and handling of the Bankruptcy cases. As of December 31, 2016, we have paid $45 million in professional fees. We anticipate that we will continue to incur significant professional fees and costs for the pendency of the Bankruptcy cases.
For additional discussion, see Part I, Item 1A, “Risk Factors - Risk Factors Related to Our Restructuring and Our Business”.
Capital Expenditures
Cash used for capital expenditures, totaled $52 million, $218 million and $260 million for 2016, 2015 and 2014, respectively.
In the future, we expect to continue making investments in capital expenditures. Subject to our liquidity limitations, we plan investments in 2017 to be primarily for expenditures to extend the useful life of our rigs.
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.
We currently have three high specification jackups under construction in China owned by non-Debtor subsidiaries. These units are technically complete, however, we have reached agreements with the construction company to defer delivery of these units until October 2017 as there are no opportunities to secure contracts for the assets in the current business environment. For us to take delivery of these assets, we would require an acceptable contract to justify the purchase price and suitable financing. We cannot guarantee that we will accept delivery of any of these jackups. In the current business environment, we believe we are unlikely to acquire these drilling rigs. Restrictions under the New Plan may also further constrain our ability to acquire drilling rigs.
Dividends
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 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.
The declaration and payment of dividends requires authorization of our Board of Directors, provided that such dividends on issued share capital may be paid only out of our “distributable reserves” on our statutory balance sheet. Paragon Offshore plc is not permitted to pay dividends out of share capital, which includes share premiums. We had no distributable reserves as of December 31, 2016 and December 31, 2015. 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, outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our board of directors considers relevant factors at that time. As proposed by the New Plan, we will not be paying any dividends following our emergence from bankruptcy.

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.

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COMMITMENTS AND CONTRACTUAL CASH OBLIGATIONS
The following table summarizes our contractual cash obligations and commitments at December 31, 2016:
 
 
 
 
Payments Due by Period
 
 
(In thousands)
 
Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
Other
Contractual Cash Obligations