PARAGON OFFSHORE PLC - FORM 10-K

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EX-21.1 - LIST OF SUBSIDIARIES - PARAGON OFFSHORE PLC	a2015q410-kexhibit211.htm
EX-31.2 - CERTIFICATION OF CFO (302) - PARAGON OFFSHORE PLC	a2015q410-kexhibit312.htm
EX-23.1 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - PARAGON OFFSHORE PLC	a2015q410-kexhibit231.htm
EX-31.1 - CERTIFICATION OF CEO (302) - PARAGON OFFSHORE PLC	a2015q410-kexhibit311.htm
EX-32.2 - CERTIFICATION OF CFO (906) - PARAGON OFFSHORE PLC	a2015q410-kexhibit322.htm
EX-32.1 - CERTIFICATION OF CEO (906) - PARAGON OFFSHORE PLC	a2015q410-kexhibit321.htm

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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, 2015



¨	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. ¨

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, 2015, the aggregate market value of the registered shares of Paragon Offshore plc held by non-affiliates of the registrant was $94 million based on the closing sale price as reported on the New York Stock Exchange.

Number of shares outstanding and trading at March 1, 2016: 86,558,423

DOCUMENTS INCORPORATED BY REFERENCE

The proxy statement for the 2016 annual general meeting of the shareholders of Paragon Offshore plc will be incorporated by reference into Part III of this Form 10-K.

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PARAGON OFFSHORE PLC

FORM 10-K

For the Year Ended December 31, 2015

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		PAGE
PART I
	GLOSSARY OF TERMS	3
Item 1.	Business	6
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	37
Item 2.	Properties	37
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39

PART II
Item 5.	Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	40
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	66
Item 8.	Financial Statements and Supplementary Data	67
	Report of Independent Registered Public Accounting Firm	67
	Consolidated and Combined Statements of Operations	68
	Consolidated and Combined Statements of Comprehensive Income (Loss)	69
	Consolidated Balance Sheets	70
	Consolidated and Combined Statements of Changes in Equity	71
	Consolidated and Combined Statements of Cash Flows	72
	Notes to Consolidated and Combined Financial Statements	73
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	105
Item 9A.	Controls and Procedures	106
Item 9B.	Other Information	107

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	108
Item 11.	Executive Compensation	109
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	109
Item 13.	Certain Relationships, Related Transactions and Director Independence	110
Item 14.	Principal Accounting Fees and Services	111

PART IV
Item 15.	Exhibits, Financial Statement Schedules	111

SIGNATURES		112

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GLOSSARY OF CERTAIN DEFINED TERMS


Adjusted EBITDA	Net income (loss) before taxes less interest expense, interest income, depreciation, losses on impairments, sale of assets and extinguishment of debt


AOCL	Accumulated Other Comprehensive Loss


ASC	Accounting Standards Codification


ASU	Accounting Standards Update


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


EPA	United States Environmental Protection Agency


Exchange Act	U.S. Securities Exchange Act of 1934, as amended


FASB	Financial Accounting Standards Board


IMO	International Maritime Organization


LIBOR	London Interbank Offered Rate


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


Revolving Credit Agreement	The Company’s senior secured revolving credit agreement entered into with a group of lenders on June 17, 2014

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Revolving Credit Facility	Commitments in the amount of $800 million provided by a group of lenders under the Revolving Credit Agreement


ROCE	Return on capital employed


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	U.S. 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 our proposed Plan, 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 operated fleet includes 34 jackups (including two high specification heavy duty/harsh environment jackups), four drillships and two semisubmersibles. We refer to our semisubmersibles and drillships collectively as “floaters.” 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 our geographically diverse fleet with well-established customer relationships. We operate in significant hydrocarbon-producing geographies throughout the world, including Mexico, Brazil, the North Sea, West Africa, the Middle East, and India. As of December 31, 2015, our contract backlog was $1.0 billion and included contracts with leading 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”). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned.

Voluntary Reorganization under Chapter 11

Plan Support Agreement

On February 12, 2016, the Debtors entered into a plan support agreement (the “PSA”) relating to a plan of reorganization (the “Plan”) pursuant to chapter 11 of the Bankruptcy Code with holders (the “Noteholder Group”) representing an aggregate of 77% of the outstanding $457 million of our 6.75% senior unsecured notes maturing July 2022 (the “2022 Senior Notes”) and the outstanding $527 million of our 7.25% senior unsecured notes maturing August 2024 (the “2024 Senior Notes” and, together with the 2022 Senior Notes, the “Senior Notes”) together with lenders (“Revolver Group”) representing an aggregate of 96% of the amounts outstanding (including letters of credit) under our Senior Secured Revolving Credit Agreement, dated June 17, 2014 (the “Revolving Credit Agreement”). The terms of the transactions contemplated by the Plan are as follows:

•

Lenders in our Revolving Credit Agreement shall receive a $165 million cash payment and corresponding permanent reduction in lending commitments. The Revolving Credit Agreement will be amended and all remaining amounts outstanding will be converted into a term loan with an extension of the maturity to 2021, a rate increase to LIBOR + 4.50% with a 1.00% LIBOR floor, a minimum liquidity covenant at all times set at $110 million (subject to a grace period if the minimum liquidity falls below $110 million but remains above $95 million), a suspension of the net leverage ratio and interest coverage covenants until the first quarter of 2018, as well as certain other amendments.

•

Holders of our Senior Notes (the “Noteholders”) shall receive: (i) a pro rata share of a cash payment of $345 million (the “Noteholder Cash Payment”); (ii) a pro rata share of 35% of the ordinary shares of reorganized Paragon (the “Noteholder Equity”); and (iii) a deferred cash payment of $20 million if our consolidated Earnings Before Interest, Taxes, Depreciation and Amortization, and other adjustments as defined in the PSA (“Deferred Payment EBITDA”) for 2016 equals or exceeds $209 million, and a deferred cash payment of $15 million if our consolidated Deferred Payment EBITDA for 2017 equals or exceeds $248 million but is less than $276 million or $30 million if our consolidated Deferred Payment EBITDA for 2017 equals or exceeds $276 million (the “2017 Payment”). The Noteholder Group will also be entitled to designate one member to our board of directors.


•	Existing shareholders will retain ownership of 65% of the ordinary shares of reorganized Paragon following emergence from bankruptcy.


•	General unsecured claims are unimpaired under the Plan, and the Company’s Senior Secured Term Loan (the “Term Loan Facility”) shall be reinstated.


•	The Plan does not contemplate restructuring the financing arrangements created by the Sale-Leaseback Transaction as the Prospector subsidiaries are not Debtors in the chapter 11 filing.

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Settlement with Noble Corporation

We also entered into a binding term sheet (the “Term Sheet”) with Noble with respect to the “Noble Settlement Agreement” (as described below). Upon execution of the Noble Settlement Agreement, certain conditions of the Tax Sharing Agreement executed between Noble and Paragon for the Spin-Off will be modified. 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 16 - “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. As of December 31, 2015, our estimated Mexican Tax Assessments totaled approximately $200 million, with assessments for 2009 and 2010 yet to be received. Additionally, 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 following the defense of the Mexican Tax Assessments. 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. The Term Sheet has been approved by the boards of directors of both companies, but remains subject to execution of a definitive Noble Settlement Agreement and the approval of such agreement by the Bankruptcy Court in our chapter 11 proceedings. Upon the execution and approval by Bankruptcy Court of a final Noble Settlement Agreement, a material portion of our Mexican Tax Assessments, and any corresponding ultimate tax liability, will be assumed by Noble. Until such time, the current Tax Sharing Agreement remains in effect.

Chapter 11 Filing

On February 14, 2016, the Debtors filed voluntary petitions for relief under chapter 11of the Bankruptcy Code in the Bankruptcy Court (“the Bankruptcy cases”). The Plan remains subject to approval of the Bankruptcy Court. During the pendency of the bankruptcy proceedings, we will continue to operate our business as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

The reorganization is not expected to have a material impact on our operations and we are seeking to pay unsecured trade and other creditors in full either in the ordinary course of business or at the conclusion of the chapter 11 process. We are seeking to emerge from bankruptcy by the end of the second quarter of 2016.

Events Leading to Proposed Restructuring

For a general description of factors that ultimately led us to enter into a restructuring plan to restructure our liabilities and maximize recoveries to holders of interests and claims including the collapse in oil prices, contract terminations and renegotiations and certain deleveraging initiatives see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Overview.”

Delisting from the New York Stock Exchange

On December 18, 2015, the Company announced that it received notification from the NYSE that the NYSE had suspended trading in our shares effective immediately. The NYSE determined that our 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 was December 17, 2015. On December 18, 2015, the Company’s ordinary shares began trading on the OTC Market Group Inc.’s OTCQX market. Upon filing our voluntary petitions for relief under chapter 11 of the Bankruptcy Code, we began trading on the OTC Pink.

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 performance. In aligning our strategy with our vision, we pursue the following strategic objectives:


•	maximize the utilization of our global asset base in important oil and gas producing areas throughout the world;

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•	operate in a manner that delivers industry-leading operational uptime and provides exceptional customer service through a diverse fleet operated 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 strategic 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 leading national, international and independent oil and gas companies in some of the world’s most active hydrocarbon producing markets. We believe that, while current market conditions are challenging, our geographic diversity and strong customer relationships could generally reduce our exposure to market volatility and position us well to identify, react quickly to and benefit from positive market dynamics.

We currently have a large, well-maintained and diversified fleet of drilling rigs, which allows us to provide reliable and effective drilling services to our customers across multiple geographies and water depths. 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 prolong our rigs’ useful lives, reduce operational downtime and generate better value for our shareholders. 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.

The offshore drilling industry is a large and highly fragmented industry. In the current business environment, we believe we are unlikely to acquire assets. The restrictions in our Revolving Credit Agreement, as proposed to be amended under the Plan, may also further constrain our ability to acquire assets.

We currently have three high-specification jackups under construction in China owned by subsidiaries of Prospector Offshore, our 2015 acquisition. These units are technically complete or are nearing technical completion, however, we have reached agreements with the construction company to defer delivery of these units 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 consistent with the negative covenants in our Debt Facilities. We cannot guarantee that we will accept delivery of any of these jackups.

We intend to maintain a responsible capital structure and appropriate levels of liquidity. We intend to make investment decisions, including refurbishments, maintenance, upgrades and acquisitions, in a disciplined and diligent manner, carefully evaluating these investments based on their ability to maintain or improve our competitive position and strengthen our financial profile. As part of our evaluation, we also look at opportunities to sell rigs that we consider not core to our fleet, as well as scrap assets that will not be profitable in the future.

Demand for our services is a function of the worldwide supply of mobile offshore drilling units. In recent years, there has been a significant expansion of supply of both jackups and ultra-deepwater units, the vast majority of which are currently under

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construction without a contract for future employment. The introduction of non-contracted newbuild rigs into the marketplace will increase the supply of rigs which compete for drilling service contracts and could negatively impact both the 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 additional shareholder value while minimizing risk.

Additionally, we continue to focus on strengthening our balance sheet and preserving liquidity.

We place considerable importance on maintaining a skilled and dedicated workforce and focus on operational excellence to benefit both our customers as well as our employees and their families. 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. Our drilling contracts with Pemex in Mexico, for example, have allowed early cancellation with 30 days notice to us without Pemex making an early termination payment. For additional information, please read “Our inability to renew or replace existing contracts or the loss of a significant customer or contract could have a material adverse effect on our financial results” included in Item 1A, “Risk Factors.”

The terms of some of our drilling contracts permit us to earn bonus revenue incentive payments based on performance. Our drilling contracts with Petrobras in Brazil, for example, contain these bonus provisions.

As our rigs are mobilized from one geographic location to another, labor and other operating and maintenance costs can vary significantly. If we relocate a rig to another geographic location without a customer contract, we will incur costs that will not be reimbursable by future customers, and even if we relocate a rig with a customer contract, we may not be fully compensated during the mobilization period.

For a discussion of our backlog of commitments for contract drilling services, see Part II, Item 7, “Management’s

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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, 2015, 2014 and 2013. We conduct our contract drilling operations principally in Mexico, Brazil, the North Sea, West Africa, the Middle East, and India. For the years ended December 31, 2015, 2014 and 2013, our five largest customers in the aggregate accounted for approximately 61%, 57%, and 55%, respectively of our operating revenues. Revenues from Petrobras accounted for approximately 21%, 23% and 17% of our total operating revenues in 2015, 2014 and 2013, respectively. Revenues from Total S.A. accounted for approximately 16%, 3% and 4% of our total operating revenues in 2015, 2014 and 2013, respectively. Revenues from Pemex accounted for approximately 9%, 16% and 19% of our total operating revenues in 2015, 2014 and 2013, respectively. No other single customer accounted for more than 10% of our total operating revenues in 2015, 2014 and 2013.

Labor Contracts

We provide drilling and maintenance services (but do not provide a rig) on the Hibernia Project in the Canadian Atlantic under a contract with Hibernia Management and Development Company Ltd. that extends through June 30, 2016 and in which Exxon is the primary operator. Under this contract, we provide the personnel necessary to manage and perform the drilling operations from a drilling platform owned by the operator.

Competition

The offshore contract drilling industry is a competitive and cyclical business characterized by high capital and maintenance costs. We compete with other providers of offshore drilling rigs. Some of our competitors have access to greater financial resources than we do.

In the provision of contract drilling services, competition involves numerous factors, including price, rig availability and suitability, experience of the workforce, efficiency, safety performance record, condition and age of equipment, operating integrity, reputation, industry standing and client relations. We believe that we compete favorably with respect to most of these factors and that price is a key determinative factor. We follow a policy of investing capital to maintain, refurbish and strategically upgrade our assets and intend to continue to optimize the quality and performance profile of our fleet by investing in strategic upgrades to increase the longevity and competitive capabilities of our rigs. However, our equipment could be made obsolete by the development of new techniques and equipment, regulations or customer preferences. See Part II, Item 8, Note 6 -“Property and Equipment and Other assets” for a discussion on the $1.1 billion non-cash impairment loss recognized on our fleet during the year ended December 31, 2015. 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.

In addition, industry-wide shortages of supplies, services, skilled personnel and equipment necessary to conduct our business have historically occurred. We cannot assure that any such shortages experienced in the past will not happen again in the future.

Governmental Regulations and Environmental Matters

Drilling contractors may be affected by the regulations of various host countries in which they are invited to operate in addition to international regulations ratified into existence by the International Maritime Organization (“IMO”). Several of the laws imposed against our industry can directly or indirectly affect the construction and servicing of offshore oil wells as well as the equipment utilized for such operations. Our contract drilling operations are also subject to laws and regulations such as mandating the reduction of greenhouse gas emissions, currency conversions and repatriation, taxation of company earnings and earnings of expatriate personnel, and use of local employees and suppliers.

Several countries, including member states of 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 decision not to cut oil production in the face of declining commodity prices has and may continue to contribute to unstable oil prices and the volatility of the market.

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In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by oil and gas companies and their need for drilling services, and likely will continue to do so.

The regulations applicable to our operations include provisions that regulate the discharge of materials into the environment and/or require clean up if contamination has taken place. Many of the countries in whose waters we operate regulate the discharge of fluids associated with the exploration and exploitation of offshore oil wells through operating permits issued by the local authority. Failure to comply with these laws and regulations, or failure to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of clean up requirements, and the imposition of injunctions to force future compliance.

Our Company has made, and will continue to make, expenditures to comply with environmental requirements. We do not believe that our compliance with such requirements will have a material adverse effect on our operations, our competitive position, or materially increase our capital expenditures. Although we have not observed any direct impact on our operations, mandated requirements may indirectly affect our customers’ ability to pursue exploration and production activities, which consequently will introduce a lesser demand on our services and/or increased costs that may be imposed on us or the industry in general.

International Regulatory Regime(s)

The following is a summary of some of the existing laws and regulations that apply to our international operations and also serve as an example of the various laws and regulations to which we are subject. While laws vary widely in each jurisdiction, each of the laws and regulations below addresses environmental issues similar to those in most of the other jurisdictions in which we operate. All of our drilling rigs are in substantial compliance with the applicable regulations specified below.

The IMO provides international regulations governing shipping and international maritime trade. IMO regulations have been widely adopted by U.N. member countries, and in some jurisdictions in which we operate, these regulations have been expanded upon. The requirements contained in the International Management Code for the Safe Operation of Ships and for Pollution Prevention, (the “ISM Code”) promulgated by the IMO, govern much of our drilling operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and describing procedures for responding to emergencies.

The IMO has adopted the International Convention for the Prevention of Pollution from Ships/Rigs (the “MARPOL Convention”) which is the main international convention covering prevention of pollution of the marine environment from operational or accidental causes. The MARPOL Convention includes regulations aimed at preventing and minimizing pollution, both accidental pollution and that from routine operations, and currently includes six technical annexes, four of which are applicable to our operations. The concept of special areas with strict controls on operational discharges are included in most Annexes. Below is a brief summary of the annexes applicable to our operations:

Annex I - Regulations for the Prevention of Pollution by Oil. Annex I details the discharge criteria and requirements for the prevention of pollution by oil and oily substances. It maintains predominantly the oil discharge criteria prescribed in the 1969 amendments to the 1954 Oil Pollution Convention. In addition to technical guidelines, it contains the concept of “special areas” which are considered to be vulnerable to pollution by oil. Discharges of oil within these areas has been completely prohibited, with minor well-defined exceptions.

Annex IV - Prevention of Pollution by Sewage. Annex IV contains requirements to control pollution of the sea by sewage; prohibits the discharge of sewage into the sea, except when the ship has in operation an approved sewage treatment plant or when the ship is discharging comminuted and disinfected sewage using an approved system at a distance of more than three nautical miles from the nearest land; and contains requirements to discharge sewage which is not comminuted or disinfected at a distance of more than 12 nautical miles from the nearest land.

Annex V - Prevention of Pollution by Garbage. Annex V deals with different types of garbage and specifies the distances from land and the manner in which they may be disposed. The most important feature of Annex V is the complete ban imposed on the disposal into the sea of all forms of plastics. In July 2011, IMO adopted extensive amendments to Annex V which prohibits the discharge of all garbage into the sea, except as provided otherwise, under specific circumstances.

Annex VI Prevention of Air Pollution. Annex VI sets limits on sulphur oxide (“SOx”) and nitrogen oxide (“NOx”) emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances and designated emission control areas set more stringent standards for SOx, NOx and particulate matter. In 2011, after extensive work and debate, IMO adopted ground breaking mandatory technical and operational energy efficiency measures which will significantly reduce the amount of greenhouse gas emissions from ships.

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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. As of November 2015, 47 Member States have adopted and ratified the BWM Convention and is anticipated to come into force November 24^th 2016. 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.

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 40CFR110. Any material release that has the potential for causing discoloration or producing a sheen on the receiving water surface is a violation of the Clean Water Act (“CWA”) and is required to be reported to the EPA, United States Coast Guard, and/or the Bureau of Safety and Environmental Enforcement (“BSEE”).

The Oil Pollution Act. The U.S. Oil Pollution Act of 1990 (“OPA”) and similar regulations, including but not limited to the MARPOL Convention, as implemented in the United States through the Act to Prevent Pollution from Ships, impose certain operational requirements on offshore rigs operating in the U.S. and govern liability for leaks, spills and blowouts involving pollutants. The OPA imposes strict liability, and may impose joint and several liability on “responsible parties” for removal costs, natural resource damages, and certain other losses resulting from oil spills into or upon navigable waters of the U.S. and its adjoining shorelines. A “responsible party” includes the owner or operator of an onshore facility, the lessee, or “permit holder,” of the area in which an offshore facility is located, and any person owning, operating, or demise chartering a vessel.

Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA, and we believe that compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.

Waste Handling. The U.S. Resource Conservation and Recovery Act (“RCRA”), and similar state and local laws and regulations govern the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. RCRA regulations specifically exclude from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements as our operations generate minimal quantities of hazardous wastes.

Water Discharges. The U.S. Federal Water Pollution Control Act, also known as the “Clean Water Act,” and similar state laws and regulations impose restrictions and controls on the discharge of pollutants into federal and state waters. These laws also regulate the discharge of storm water in process areas. Pursuant to these laws and regulations, we are required to obtain and maintain approvals or permits for the discharge of wastewater. In addition, the U.S. Coast Guard has promulgated requirements which include limits applicable to specific discharge streams, such as deck runoff, bilge water and gray water. We do not anticipate that compliance with these laws will cause a material impact on our operations or financial condition.

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,

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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 and other similar laws and regulations govern the protection of the health and safety of employees. The U.S. Occupational Safety and Health Administration hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governments or citizens. We believe that we are in substantial compliance with these requirements and with other applicable OSHA requirements.

Safety Regulations

On June 10, 2013, the European Union adopted a new directive, Directive 2013/30/EU, on the safety of offshore oil and gas operations within the exclusive economic zone (which can extend up to 200 nautical miles from a coast) or the continental shelf of any of its member states. The directive establishes minimum requirements for preventing major accidents in offshore oil and gas operations, and aims to limit the consequences of such accidents. All European Union member states will be required to adopt national legislation or regulations by July 19, 2015 to implement the new directive’s requirements, which also include reporting requirements related to major safety and environmental hazards that must be satisfied before drilling can take place, as well as the use of “all suitable measures” to both prevent major accidents and limit the human health and environmental consequences of such a major accident should one occur. We believe that our operations are in substantial compliance with the requirements of the directive (as well as the extensive current health and safety regimes implemented in the member states in which we operate), but future developments could require the company to incur significant costs to comply with its implementation.

Climate Change Regulations

There is increasing public and regulatory attention concerning the issue of climate change and the effect of greenhouse gas (“GHG”). The following is a summary of regulatory developments relevant to our emission of GHG in 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 (UNFCC) on December 12, 2015 adopted ‘Paris Agreement’ by consensus, but 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 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 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.

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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 baseline data (indirect emissions from purchased electricity) was aggregated from all operating divisional offices for the 2015 year, this figure amounted to 1,397 MWh.

At year end, December 31, 2015, our estimated carbon dioxide equivalent (“CO₂e”) gas emissions was 299,410 tonnes, as compared to 347,062 tonnes the year prior (13.7% reduction), for operating 40 drilling units worldwide. When expressed as an intensity measure of tonnes of C0₂e gas emissions per dollar of contract drilling revenues, both the 2015 and 2014 intensity measure was 0.0002 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.

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 differing interpretations, and enforcement of those provisions may be limited by public policy and other considerations.

Employees

As of December 31, 2015, we had approximately 1,987 employees, excluding approximately 885 persons engaged through labor contractors or agencies. Approximately 77% of our employees are located offshore. Of our shorebased employees, approximately 69% 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

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work stoppages at any of our facilities due to labor union activities in recent years. We believe our relations with our employees are good.

We place considerable value on the involvement of our employees and maintain a practice of keeping them informed on matters affecting them, as well as on the performance of the Company. Accordingly, we conduct formal and informal meetings with employees, maintain a Company intranet website with matters of interest, issue a quarterly publication of Company activities and other matters of interest, and offer a variety of in-house training.

We are committed to a policy of recruitment and promotion on the basis of aptitude and ability without discrimination of any kind. Management actively pursues both the employment of disabled persons whenever a suitable vacancy arises and the continued employment and retraining of employees who become disabled while employed by the company. Training and development is undertaken for all employees, including disabled persons.

Basis of Presentation

The consolidated and combined 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 and combined financial statements and related discussion of financial condition and results of operations include historical results of the Noble Standard-Spec Business (our “Predecessor”), which comprised most of Noble’s standard specification drilling fleet and related operations. Our Predecessor’s historical combined financial statements include three standard specification drilling units that were retained by Noble and three standard specification drilling units that were sold by Noble prior to the Separation. We consolidate the historical combined financial results of our Predecessor in our consolidated and combined financial statements for all periods prior to the Spin-Off. All financial information presented after the Spin-Off represents the consolidated results of operations, financial position and cash flows of Paragon.

Our Predecessor’s historical combined financial statements for the periods prior to the Spin-Off include assets and liabilities that are specifically identifiable or have been allocated to our Predecessor. Revenues and costs directly related to our Predecessor have been included in the accompanying consolidated and combined financial statements. Our Predecessor received service and support functions from Noble and the costs associated with these support functions have been allocated to our Predecessor using various inputs, such as head count, services rendered, and assets assigned to our Predecessor. Our management considers the allocation methodologies used to be reasonable and appropriate reflections of the related expenses attributable to us for purposes of the carve-out financial statements; however, the expenses reflected in the results of our Predecessor and included in these consolidated and combined statements may not be indicative of the actual expenses that would have been incurred during the periods presented if our Predecessor had operated as a separate standalone entity and may not be indicative of expenses incurred in the future by us. These allocated costs are primarily related to corporate administrative expenses including executive oversight, employee related costs including pensions and other benefits, and corporate and shared employees for the following functional groups:


•	information technology,


•	legal, accounting, finance and treasury services,


•	human resources,


•	marketing, and


•	other corporate and infrastructural services.

Financial Information About Segments and Geographic Areas

Information regarding our operating revenues and identifiable assets attributable to each of our geographic areas of operation for the last three fiscal years is presented in Part II, Item 8, Note 19 - “Segment and Related Information.” At December 31, 2015, we have a single reportable segment, Contract Drilling Services, which reflects how our business is managed, and the fact that all of our drilling fleet is dependent upon the worldwide oil industry. Our contract drilling services segment conducts contract drilling operations in Mexico, Brazil, the North Sea, West Africa, the Middle East, and India.

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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 U.S. Securities Exchange Act of 1934 are available free of charge at our website at http://www.paragonoffshore.com. These filings are also available to the public at the SEC Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC’s website at http://www.sec.gov.

You may also find information related to our corporate governance, board committees and company code of ethics (and any amendments or waivers of compliance) at our website. Among the documents you can find there are the following:


•	Corporate Governance Guidelines;


•	Audit Committee Charter;


•	Nominating and Corporate Governance Committee Charter;


•	Compensation Committee Charter;


•	Finance and Risk Management Committee Charter; and


•	Code of Business Conduct and Ethics.

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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

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;


•	our ability to develop, prosecute, confirm and consummate the 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.

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 the effectiveness of 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

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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 Plan could materially change 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 businesses could suffer from a long and protracted restructuring.

Our future results are dependent upon the successful confirmation and implementation of the 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 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 Plan is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders to do business with a company that recently emerged from bankruptcy proceedings.

We may not be able to obtain confirmation of the Plan as outlined in the PSA, and our emergence from the Bankruptcy cases is not assured.

There can be no assurance that the Plan as outlined in the PSA (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 to confirm the Plan. Moreover, we might receive official objections to confirmation of the 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 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 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 current 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.

We may experience increased levels of employee attrition as a result of the Bankruptcy cases.

As a result of the Bankruptcy cases, we may experience increased levels of employee attrition, and our employees likely will face considerable distraction and uncertainty. 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.

Our substantial indebtedness, which will not be fully discharged under the Plan as set forth in the PSA, could adversely affect our business, financial condition and results of operations and prevent us from fulfilling our obligations under the terms of our indebtedness.

We have, and we will continue to have, a significant amount of indebtedness. As of December 31, 2015, we had total indebtedness of approximately $2.6 billion. Under the Plan, we would still have in excess of $1 billion of total indebtedness following our emergence from bankruptcy.

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In addition, if we take delivery of all three of the newbuild high specification jackup rigs under construction, we must pay approximately $600 million. This would likely require us to arrange a separate financing facility to fund this amount consistent with the negative covenants in our Debt Facilities.

Our substantial indebtedness could make it more difficult for us to satisfy our obligations with respect to the terms of our indebtedness and has had and could continue to have other material adverse consequences for our business, including:


•	requiring us to dedicate a large portion of our cash flow to pay principal and interest on our indebtedness, which will reduce the availability of our cash flow to fund working capital, capital expenditures and other business activities;


•	increasing our vulnerability to general adverse economic and industry conditions;


•	limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;


•	further restricting us from making strategic acquisitions, dispositions or exploiting business opportunities;


•	placing us at a competitive disadvantage compared to our competitors that have less debt; and


•	limiting our ability to borrow additional funds (even when necessary to maintain adequate liquidity) or dispose of assets.

Our ability to service and refinance our debt following our emergence from bankruptcy will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, it may be necessary to take actions such as to further reduce and delay planned capital expenditures or other business activities, or to seek additional capital or refinance our indebtedness. Our ability to obtain additional capital or refinance our debt will depend on the conditions of the capital markets and our financial position at such time and may be further compromised by the additional negative covenants under the amendments to our Revolving Credit Agreement as contemplated by the Plan.

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 our proposed Plan, we would be discharged from any claims arising under the 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 is likely not 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, we may be required to adopt fresh start accounting. If fresh start accounting is applicable, 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, if fresh start accounting is required, 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.

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Risks Related to Our Business

The worldwide demand for drilling services significantly declined as a result of the continued decline 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;


•	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.

For instance, oil prices have declined substantially throughout 2015 and have continued to decline in 2016 as have forward, or “strip” prices. As a result, many of our customers have announced significant reductions to their capital spending budgets. Lower capital spending has greatly increased competitive pressure and has, and could continue to, adversely impact both our ability to secure new contracts for our drilling rigs and the dayrates we are paid. As a consequence, we could earn substantially less, experience lower levels of utilization and may be forced to idle, stack, or scrap rigs, which would adversely affect our revenues and profitability. Prolonged periods of low utilization and lower day rates could also result in the recognition of impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

The contract drilling industry is a competitive and cyclical business with intense price competition. If we are unable to compete successfully, our profitability may be reduced.

The offshore contract drilling industry is a highly competitive and cyclical business characterized by high capital and operating costs and evolving capability of newer rigs. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition, rig availability, location and suitability, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing and client relations are all factors in determining which contractor is awarded a job. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors. Other drilling companies, including those with both high specification and standard specification rigs, may have greater financial, technical and personnel resources that allow them to upgrade equipment and implement new technical capabilities before we can. If current competitors or new market entrants implement new technical capabilities, services or standards that are more attractive to our customers, it could have a material adverse effect on our operations.

In addition to intense competition, our industry is highly cyclical. It has been especially cyclical with respect to the jackup market, where market conditions are subject to rapid change. There have been periods of high demand, short rig supply and high dayrates, followed by periods of lower demand, excess rig supply and low dayrates. Periods of low demand or excess rig supply intensify the competition in the industry and may result in some of our rigs being idle or earning substantially lower dayrates for long periods of time. Additionally, drilling contracts for our jackups generally have shorter terms than contracts for our floaters, meaning that most of our fleet does not have the benefits of the price protection that longer-term contracts provide. The volatility of the industry, coupled with the short-term nature of many of our contracts could have a material adverse effect on our business, financial condition and results of operations.

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 annually assess whether the carrying value of long-lived assets has been impaired, or more frequently if an event occurs or circumstances change which could indicate 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, 2015, the Company recorded non-cash impairment charges of $1.1 billion and $37 million related to its property and equipment and goodwill, respectively. During the year ended December 31, 2014, the Company recorded a non-cash impairment charge of $1.1 billion related to its property and equipment. As of December 31, 2015, the Company had no remaining goodwill.

An over-supply of jackup rigs and floaters may lead to a reduction in dayrates and demand for our rigs and therefore could have a material adverse impact on our profitability.

Our industry recently exited a period of high utilization and high dayrates during which industry participants increased the supply of drilling rigs by building new drilling rigs, including some drilling rigs that have not yet entered service. Historically, this has often resulted in an oversupply of drilling rigs, which has contributed to a decline in utilization and dayrates, sometimes for extended periods of time. New fixtures for both standard and high specification jackup rigs and floaters have recently come under pressure as a result of a recent reduction in customer spending and the delivery of new rigs.

The increase in supply created by the number and types of rigs being built, as well as changes in our competitors’ drilling rig fleets, could intensify price competition and require higher capital investment to keep our rigs competitive. According to a third-party industry source, as of February 22, 2016, the total non-U.S jackup fleet comprised 475 units (22 of which were cold stacked and three of which were “out of service”). An additional 125 jackup drilling rigs, including one being built in the U.S. and capable of operating internationally, were under construction, on order, or have been completed, but remain in the shipyard

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awaiting work. These additional rigs could bring the total non-U.S. jackup fleet to 600 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 70 floating rigs under construction, on order, or planned with deliveries between 2016 and 2020. To the extent that the drilling rigs currently under construction or on order have not been contracted for future work, there may be increased price competition as such vessels become operational, which could lead to a reduction in dayrates. Lower utilization and dayrates would adversely affect our revenues and profitability. Prolonged periods of low utilization or low dayrates could result in the recognition of additional impairment charges on certain of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not be recoverable.

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. If the demand for offshore drilling rigs were to continue to decrease for a prolonged period of time, it is possible that higher specification rigs would begin to compete with standard specification rigs for the same contracts. In that case, higher specification rigs would have an advantage over standard specification rigs in securing those contracts and demand for and utilization of standard specification rigs may decrease. Such a decrease in demand for and utilization of standard specification rigs could have a material adverse effect on our business, financial condition and results of operations.

Many of our competitors have fleets that include high specification rigs and may be more operationally diverse. Some of our customers, including Pemex, 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.

If we are unable to comply with the financial covenants in our Revolving Credit Agreement, it would result in default under the Revolving Credit Agreement, which would result in an acceleration of repayment of all of our outstanding obligations under our Revolving Credit Facility and Term Loan Facility.

The amendments to our Revolving Credit Agreement contemplated by our proposed Plan as outlined by our PSA would require us to maintain a minimum liquidity of $110 million at all times (subject to a grace period if our minimum liquidity remains above $95 million) and, beginning in 2018, will require us to (i) maintain a certain net leverage ratio (defined as total debt, net of cash and cash equivalents, divided by earnings excluding interest, taxes, depreciation and amortization charges) and (ii) a certain minimum interest coverage ratio (defined as earnings excluding interest, taxes, depreciation and amortization charges divided by interest expense). Reduced activity levels in the oil and natural gas industry, such as we are currently experiencing, could negatively affect our financial position and adversely impact our ability to comply with these covenants in the future. Our failure to comply with such covenants would result in an event of default under the proposed amended Revolving Credit Agreement if we are unable to obtain a waiver under such agreement. An event of default would result in our having to immediately repay all amounts outstanding under the proposed amended Revolving Credit Facility and our Term Loan Facility.

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Our business involves numerous operating hazards.

Our operations are subject to many hazards inherent in the drilling business, including:


•	well blowouts;


•	fires;


•	collisions or groundings of offshore equipment;


•	punch-throughs;


•	mechanical or technological failures;


•	failure of our employees to comply with our internal environmental, health and safety guidelines;


•	pipe or cement failures and casing collapses, which could release oil, gas or drilling fluids;


•	geological formations with abnormal pressures;


•	spillage handling and disposing of materials; and


•	adverse weather conditions, including hurricanes, typhoons, winter storms and rough seas.

These hazards could cause personal injury or loss of life, suspend drilling operations, result in regulatory investigation or penalties, seriously damage or destroy property and equipment, result in claims by employees, customers or third parties, cause environmental damage and cause substantial damage to oil and gas producing formations or facilities. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, and failure of subcontractors to perform or supply goods or services or personnel shortages. Accordingly, the occurrence of any of the hazards we face could have a material adverse effect on our business, financial condition and results of operations.

Our inability to renew or replace existing contracts or the loss of a significant customer or contract could have a material adverse effect on our financial results.

Our ability to renew our customer contracts or obtain new contracts and the terms of any such contracts will depend on many factors beyond our control, including market conditions, the global economy and our customers’ financial condition and 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, 2015, 2014 and 2013, our five largest customers in the aggregate accounted for approximately 61%, 57%, and 55% respectively, of our operating revenues. We do not expect Petrobras, which accounted for approximately 21% of our operating revenues for the year ended December 31, 2015, 23% of our operating revenues for the year ended December 31, 2014, and 17% of our operating revenues for the year ended December 31, 2013 to remain a significant customer in 2016. Our contract drilling backlog as of December 31, 2015 consists of $253 million, or approximately 25% of our total backlog attributable to contracts with Petrobras for operations offshore Brazil. Petrobras is contesting 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 29, 2015. The Paragon DPDS3 is currently expected to work until August 2016, according to Petrobras’ interpretation of the contract. As of December 31, 2015, the Paragon DPDS3 drilling contract constitutes $225 million of our contract drilling services backlog, which includes $142 million being contested by Petrobras.

Our customers may generally terminate our term drilling contracts if a drilling rig is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In the case of nonperformance and under certain other conditions, our drilling contracts generally allow our customers to terminate without any payment to us. The terms of some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. Our drilling contract with Pemex allows early cancellation with 30 days or less notice to us without any early termination payment. Petrobras has the right to terminate its contracts in the event of downtime that exceeds certain thresholds. The early termination of a contract may result in a rig being idle for an extended period of time and a reduction in our contract backlog and associated revenue, which could have a material adverse effect on our business, financial condition and results of operations.

Many of our contracts, especially those relating to our jackup rigs, are shorter term in nature, and many of our existing contracts will expire in 2016. 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. Any

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new contracts for such rigs may be at dayrates substantially below existing dayrates or on terms less favorable than existing contract terms, which could have a material adverse effect on our revenues and profitability.

Our customers, which include many national oil companies, often have significant bargaining leverage over us. During periods of depressed market conditions, we may be subject to an increased risk of our customers seeking to renegotiate or repudiate their contracts, including customers seeking to lower dayrates paid under existing contracts. 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;


•	complications associated with repairing and replacing equipment in remote locations;


•	repudiation, nullification, modification or renegotiation of contracts;


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


•	import-export quotas, wage and price controls, imposition of trade barriers and other forms of government regulation and economic conditions that are beyond our control;


•	delays in implementing private commercial arrangements as a result of government oversight;


•	financial or operational difficulties in complying with foreign bureaucratic actions;


•	changing tax laws, regulations or policies;


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


•	governmental corruption;


•	piracy; and


•	terrorist acts, war, revolution and civil disturbances.

Further, we operate in certain less-developed countries with legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings. Examples of challenges of operating in these countries include:


•	potential restrictions presented by local content regulations in countries such as Nigeria or Angola;

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•	ongoing changes in Brazilian laws related to the importation of rigs and equipment that may impose bonding, insurance or duty-payment requirements; and


•	procedural requirements for temporary import permits, which may be difficult to obtain.

Our ability to mobilize our drilling rigs between locations and the time and costs of such mobilization could be material to our business.

Our ability to mobilize our drilling rigs to more desirable locations may be impacted by governmental regulation and customs practices, the significant costs of moving a drilling rig, weather, political instability, civil unrest, military actions and the technical capability of the drilling rig to relocate and operate in various environments. In addition, as our rigs are mobilized from one geographic location to another, labor and other operating and maintenance costs can vary significantly. If we relocate a rig to another geographic location without a customer contract, we will incur costs that will not be reimbursable by future customers, and even if we relocate a rig with a customer contract, we may not be fully compensated during the mobilization period. These impacts of rig mobilization could have a material adverse effect on our business, results of operations and financial condition.

Operating and maintenance costs of our operating rigs and costs relating to idle rigs may be significant and may not correspond to revenue earned.

Our operating expenses and maintenance costs depend on a variety of factors including crew costs, costs of provisions, equipment, insurance, maintenance and repairs, and shipyard costs, many of which are beyond our control. Our total operating costs are generally related to the number of drilling rigs in operation and the cost level in each country or region where such drilling rigs are located. Equipment maintenance costs fluctuate depending upon the type of activity that the drilling rig is performing and the age and condition of the equipment. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. While operating revenues may fluctuate as a function of changes in dayrate, costs for operating a rig may not be proportional to the dayrate received and may vary based on a variety of factors, including the scope and length of required rig preparations and the duration of the contractual period over which such expenditures are amortized. Any investments in our rigs may not result in an increased dayrate for or income from such rigs. A disproportionate amount of operating and maintenance costs in comparison to dayrates could have a material adverse effect on our business, financial condition and results of operations.

During idle periods, to reduce our costs, we may decide to “warm stack” a rig, which means the rig is kept fully operational and ready for redeployment, and maintains most of its crew. As a result, our operating expenses during a warm stacking will not 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.

Any violation of anti-bribery or anti-corruption laws, including the U.S. Foreign Corrupt Practices Act, the United Kingdom Bribery Act, or similar laws and regulations could result in significant expenses, divert management attention, and otherwise have a negative impact on us.

We operate in countries known to have a reputation for corruption. We are subject to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take action determined to be in violation of such anti-corruption laws, including the U.S. Foreign Corrupt Practices Act of 1977, or FCPA, the United Kingdom Bribery Act 2010, or U.K. Bribery Act, and similar laws in other countries.

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. Following the news reports relating to the agent’s involvement in the Brazil investigation in connection with his activities with other companies, we have been conducting an independent review of our relationship with the agent and with Petrobras. We have contacted the SEC and the U.S. Department of Justice to advise them of our internal 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

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business, results of operations or financial condition. Actual or alleged violations could damage our reputation and ability to do business. Further, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

Changes in, compliance with, or our failure to comply with the certain laws and regulations could adversely impact our operations and could have a material adverse effect on our results of operations.

Our operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to:


•	the importing, exporting, equipping and operation of drilling rigs;


•	repatriation of foreign earnings;


•	currency exchange controls;


•	oil and gas exploration and development;


•	taxation of company earnings and earnings of expatriate personnel; and


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

Legal and regulatory proceedings relating to the energy industry, and the complex government regulations to which our business is subject, have at times adversely affected our business and may do so in the future. Governmental actions and the market behavior of certain OPEC members may continue to cause oil price volatility. In some areas of the world, this activity has adversely affected the amount of exploration and development work done by major oil companies, which may continue. In addition, some governments favor or effectively require the awarding of drilling contracts to local contractors, require use of a local agent or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete and our results of operations.

Public and regulatory scrutiny of the energy industry has resulted in increased regulations being either proposed or implemented. In addition, existing regulations might be revised or reinterpreted, new laws, regulations and permitting requirements might be adopted or become applicable to us, our rigs, our customers, our vendors or our service providers, and future changes in laws and regulations could significantly increase our costs and could have a material adverse effect on our business, financial condition and results of operations. In addition, we may be required to post additional surety bonds to secure performance, tax, customs and other obligations relating to our rigs in jurisdictions where bonding requirements are already in effect and in other jurisdictions where we may operate in the future. These requirements would increase the cost of operating in these countries and may reduce our available liquidity, which could have a material adverse effect on our business, financial condition and results of operations.

Adverse effects may continue as a result of the uncertainty of ongoing inquiries, investigations and court proceedings, or additional inquiries and proceedings by federal or state regulatory agencies or private plaintiffs. In addition, we cannot predict the outcome of any of these inquiries or whether these inquiries will lead to additional legal proceedings against us, civil or criminal fines or penalties, or other regulatory action, including legislation or increased permitting requirements. Legal proceedings or other matters against us, including environmental matters, suits, regulatory appeals, challenges to our permits by citizen groups and similar matters, might result in adverse decisions against us. The result of such adverse decisions, either individually, or in the aggregate, could be material and may not be covered fully or at all by insurance.

Shipyard projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our results of operation and financial condition.

We currently have three high specification newbuild projects we acquired with our acquisition of Prospector. In addition, we may make significant repairs, refurbishments and upgrades to our fleet from time to time, particularly given the age of our fleet. Some of these expenditures will be unplanned. In addition, we may decide to construct new rigs or acquire rigs under construction. These projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:


•	shortages of equipment, materials or skilled labor;


•	work stoppages and labor disputes;


•	unscheduled delays in the delivery of ordered materials and equipment;

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•	local customs strikes or related work slowdowns that could delay importation of equipment or materials;


•	weather interferences;


•	difficulties in obtaining necessary permits or approvals or in meeting permit or approval conditions;


•	design and engineering problems;


•	inadequate regulatory support infrastructure in the local jurisdiction;


•	latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions;


•	unforeseen increases in the cost of equipment, labor and raw materials, particularly steel;


•	unanticipated actual or purported change orders;


•	client acceptance delays;


•	disputes with shipyards and suppliers;


•	delays in, or inability to obtain, access to funding;


•	shipyard availability, failures and difficulties, including as a result of financial problems of shipyards or their subcontractors; and


•	failure or delay of third-party equipment vendors or service providers.

The failure to complete a rig repair, refurbishment or upgrade on time, or at all, may result in loss of revenues, the imposition of penalties, or delay, renegotiation or cancellation of a drilling contract or the recognition of an asset impairment. Additionally, capital expenditures for rig upgrade, refurbishment, repair and newbuild projects could materially exceed our planned capital expenditures. Moreover, our rigs undergoing upgrade, refurbishment and repair typically do not earn a dayrate during the period they are out of service. If we experience substantial delays and cost overruns in our shipyard projects, it could have a material adverse effect on our business, financial condition and results of operations.

We may have significant financial commitments with respect to three newbuild high specification jackup rigs under construction.

In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China. At December 31, 2015, we had purchase commitments of $600 million currently due in 2016 on the construction of three high-specification jackup rigs related to the Prospector Acquisition, as defined in Part II, Note 4 - “Acquisition”, the Prospector 6, Prospector 7 and Prospector 8, or collectively the “Three High-Spec Jackups Under Construction”. 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-Spec Jackups Under Construction, we will lose ownership of the applicable rig, at which time, the associated costs (primarily representing down-payments on these rigs) will be forfeited. These subsidiaries have currently pre-paid to SWS only 1%, 7% and 7%, respectively, of the purchase price for each newbuild pursuant to the contracts with SWS. Upon delivery, these subsidiaries will be required to pay the remaining purchase price in full for the newbuild being delivered, or $201 million, $199 million and $199 million, respectively.

Prospector 8 is scheduled to be delivered in the first quarter of 2016. In July 2015, we agreed with SWS to an extension of the delivery of the Prospector 6 to the second quarter of 2016. Subsequently in October 2015, we agreed with SWS to an extension of the delivery of the Prospector 7 to the fourth quarter of 2016. During the year ended December 31, 2015, we recorded a full impairment of $43 million of all the capitalized costs associated with the Three High-Spec Jackups Under Construction in connection with our annual long-lived asset impairment evaluation described in Part II, Note 5 - “Property and Equipment and Other Assets”.

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 chapter 11 proceedings. 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

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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, 2015, our contract backlog was $1.0 billion for contracted future work extending, in some cases, until 2018, with approximately 64% expected to be earned in 2016. Generally, contract backlog only includes future revenues under firm commitments; however, from time to time, we may report anticipated commitments for which definitive agreements have not yet been, but are expected to be, executed. In addition, we may not receive some or all of the bonuses that we include in our backlog. We can provide no assurance that we will be able to perform under these contracts due to events beyond our control or that we will be able to ultimately execute a definitive agreement in cases where one does not currently exist. In addition, we generally do not expect to recontract our floaters until late in their contract terms. Our floaters accounted for 26% of our backlog at December 31, 2015. Due to the higher dayrates earned by our floaters, until these rigs are recontracted, our total backlog may decline, which could have a material adverse effect on our business and financial condition. Moreover, we can provide no assurance that our customers will be able to or willing to fulfill their contractual commitments to us. Our inability to perform under our contractual obligations or to execute definitive agreements or our customers’ inability or unwillingness to fulfill their contractual commitments to us could have a material adverse effect on our business, financial condition and results of operations.

If we are unable to make acquisitions on economically acceptable terms, or at all, our future growth will be limited, and any acquisition we make may not be successful and may have an adverse effect on our results of operations.

Part of our strategy is dependent on our ability to make acquisitions that result in an increase in revenues and customer contracts. The consummation and timing of any future acquisitions will depend upon, among other things, the availability of attractive targets in the marketplace, our ability to negotiate acceptable purchase agreements and our ability to obtain financing on acceptable terms, and we can offer no assurance that we will be able to consummate any future acquisition.

Our debt agreements restrict our ability to make acquisitions involving the payment of cash or the incurrence of indebtedness. If we are unable to make acquisitions, our future growth will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, we may have difficulty integrating its operations, systems, management, personnel and technology with our own, or could assume unidentified or unforeseen liabilities, such that an acquisition may produce less revenue than expected as a result of incorrect assumptions in our evaluation of such acquisitions or unforeseen consequences or other external events beyond our control. If we consummate any future acquisitions, shareholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating any such acquisitions.

Operational interruptions or maintenance or repair work may cause our customers to suspend or reduce payment of dayrates until operation of the respective drilling rig is resumed, which would lead to loss of revenue or termination or renegotiation of the drilling contract.

If our drilling rigs are idle for reasons that are not related to the ability of the rig to operate, our customers pay a waiting or standby rate which is lower than the full operational rate. In addition, if our drilling rigs are taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in our drilling contracts, we will not be entitled to payment of dayrates until the rig is able to work. Several factors could cause operational interruptions, including:


•	breakdowns of equipment and other unforeseen engineering problems;


•	work stoppages, including labor strikes;


•	shortages of material and skilled labor;


•	delays in repairs by suppliers;


•	surveys by government and maritime authorities;


•	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

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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.

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

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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 and operation 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.

In addition, a tax law was enacted in Brazil, effective January 1, 2015, that under certain circumstances would impose a 15% to 25% withholding tax on charter hire payments made to a non-Brazilian related party exceeding certain thresholds of total contract value. Although we believe that our operations are not subject to this law, the tax is being 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.

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.

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Our operations are subject to numerous laws and regulations relating to the protection of the environment and of human health and safety, and compliance with these laws and regulations could impose significant costs and liabilities that exceed our current expectations.

Substantial costs, liabilities, delays and other significant issues could arise from environmental, health and safety laws and regulations covering our operations, and we may incur substantial costs and liabilities in maintaining compliance with such laws and regulations. Our operations are subject to extensive international conventions and treaties, and national or federal, state and local laws and regulations, governing health and safety and environmental protection, including with respect to the discharge of materials into the environment and the security of chemical and industrial facilities. These laws govern a wide range of issues, including:


•	employee safety;


•	the release of oil, drilling fluids, natural gas or other materials into the environment;


•	air emissions from our drilling rigs or our facilities;


•	handling, cleanup and remediation of solid and hazardous wastes at our drilling rigs or our facilities or at locations to which we have sent wastes for disposal;


•	restrictions on chemicals and other hazardous substances; and


•	wildlife protection, including regulations that ensure our activities do not jeopardize endangered or threatened animals, fish and plant species, or destroy or modify the critical habitat of such species.

Various governmental authorities have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits, or the release of oil or other materials into the environment, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of moratoria or injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases, or could affect our relationship with certain consumers.

There is an inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our customers’ hydrocarbon products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint, several or strict liability may be incurred without regard to fault under certain environmental laws and regulations for the remediation of contaminated areas and in connection with past, present or future spills or releases of natural gas, oil and wastes on, under, or from past, present or future facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our 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

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liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under environmental laws. Therefore, it is possible that we could be subject to liability upon a judgment against us or any one of our subsidiaries.

We are subject to risks associated with climate change and climate change regulation.

There is an ongoing debate about emissions of greenhouse gases, or GHGs, and climate change. Climate change, and the costs that may be associated with its impacts, and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our services, the demand for and consumption of our services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHGs and climate change create the potential for financial risk. There have been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional or federal requirements to reduce or mitigate GHG emissions.

The passage or promulgation of any new climate change laws or regulations by the IMO at the international level, or by national or regional legislatures in the jurisdictions in which we operate, including the European Union, could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our services by making our services more or less desirable than services associated with competing sources of energy.

Finally, some scientists have concluded that increasing GHG concentrations in the atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of hurricanes and other storms, which could have a material adverse effect on our business, financial condition and results of operations.

Failure to attract and retain skilled personnel or an increase in personnel costs could adversely affect our operations.

We require skilled personnel to operate and provide technical services and support for our drilling units. As the demand for drilling services and the size of the worldwide industry fleet increases, shortages of qualified personnel have occurred from time to time. These shortages could result in our loss of qualified personnel to competitors, impair our ability to attract and retain qualified personnel for our new or existing drilling units, impair the timeliness and quality of our work and create upward pressure on personnel costs, any of which could have a material adverse effect on our operations.

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

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compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines or other penalties and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have contracts with countries identified by the U.S. government as state sponsors of terrorism. In addition, our reputation and the market for our securities may be adversely affected if we engage in certain other activities, such as entering into drilling contracts with individuals or entities in countries subject to significant U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments.

Our operations present hazards and risks that require significant and continuous oversight, and we depend upon the security and reliability of our technologies, systems and networks in numerous locations where we conduct business.

Our floaters and high specification units utilize certain technologies that may make us vulnerable to cyber-attacks that we may not be able to adequately protect against. These cybersecurity risks could disrupt certain of our operations for an extended period of time and result in the loss of critical data and in higher costs to correct and remedy the effects of such incidents. If our systems for protecting against information technology and cybersecurity risks prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our proprietary information altered, lost or stolen, or our business operations and safety procedures disrupted.

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

We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies or where we do not hedge an exposure to a foreign currency. We may also incur losses as a result of an inability to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital.

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-

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incidents or attacks continue to grow. In addition, breaches to our systems could go unnoticed for some period of time. Risks associated with these threats include disruptions of certain systems on our rigs; other impairments of our ability to conduct our operations; loss of intellectual property, proprietary information or customer data; disruption of our customer’s operations; loss or damage to our customer data delivery systems; and increased costs to prevent, respond to or mitigate cybersecurity events. If such a cyber-incident were to occur, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Acts of terrorism, piracy and social unrest could affect the markets for drilling services.

Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy, and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums could increase and coverages may be unavailable in the future.

Our drilling contracts do not generally provide indemnification against loss of capital assets or loss of revenues resulting from acts of terrorism, piracy and social unrest. We have limited insurance for our assets providing coverage for physical damage losses from risks, such as terrorist acts, piracy, civil unrest, expropriation and acts of war, and we do not carry insurance for loss of revenue resulting from such risks. Government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.

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. If we continue not to pay cash dividends, it could have a negative effect on the market price of our stock. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant factors at that time. As proposed by our Plan, the contemplated amendments to our Revolving Credit Facility would prohibit us from paying any dividends following our emergence from bankruptcy.

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Risks Related to the Spin-Off

Our historical combined financial statements of our Predecessor are not necessarily indicative of our future financial condition, future results of operations or future cash flows nor do they reflect what our financial condition, results of operations or cash flows would have been as an independent public company during the periods presented prior to July 31, 2014.

The historical combined financial information of our Predecessor that we have included in this annual report does not reflect what our financial condition, results of operations or cash flows would have been as an independent public company during the periods presented and is not necessarily indicative of our future financial condition, future results of operations or future cash flows. This is primarily a result of the following factors:


•	our Predecessor’s historical combined financial information reflects allocations of expenses for services historically provided by Noble, and those allocations may be significantly lower than the comparable expenses we would have incurred as an independent public company;


•	our cost of debt and other capitalization may be significantly different from that reflected in our historical combined financial statements;


•	our Predecessor’s historical combined financial information does not reflect the changes that occurred in our cost structure, management, financing arrangements and business operations as a result of our separation from Noble, including the costs related to being an independent public company;


•	our Predecessor’s historical combined financial information does not reflect the effects of certain liabilities that were assumed by our Company, and reflects the effects of certain assets and liabilities that were to be retained by Noble; and


•	our Predecessor’s historical combined financial information includes three standard specification drilling rigs retained by Noble as well as one jackup and two cold stacked submersibles that were sold by Noble in July 2013 and January 2014, respectively.

The terms of our Separation from Noble, the related agreements and other transactions with Noble were determined by Noble and thus may be less favorable to us than the terms we could have obtained from an unaffiliated third party.

Prior to the completion of the Distribution, we entered into various agreements to complete the separation of our business from Noble and govern our ongoing relationships, including, among others, Master Separation Agreement, employee matters agreement, Tax Sharing Agreement, a transition services agreement relating to services provided to each other on an interim basis and a transition services agreement relating to Noble’s offshore Brazil operations.

Under one of the transition services agreements, Noble provides various interim corporate support services to us and we provide various interim support services to Noble. Under the transition services agreement for Brazil, we provide both rig-based and shore-based support services for Noble’s continuing offshore Brazil operations through the term of the existing rig contracts. The Master Separation Agreement provides for, among other things, our responsibility for liabilities relating to our business and the responsibility of Noble for liabilities unrelated to our business. Among other things, the master separation agreement contains indemnification obligations and ongoing commitments of us and Noble designed to make our company financially responsible for substantially all liabilities that may exist relating to our business activities, whether incurred prior to or after the Separation. Our indemnification of Noble under the circumstances set forth in the Master Separation Agreement could subject us to substantial liabilities.

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.

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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.

As part of the PSA, we entered into a definitive Term Sheet with Noble with respect to the Noble Settlement Agreement. While the Term Sheet has been approved by the boards of directors of both companies, the Noble Settlement Agreement remains subject to execution of a definitive agreement and the approval of such agreement by the Bankruptcy Court in our chapter 11 proceedings.

The Tax Sharing Agreement may limit our ability to engage in certain strategic corporate transactions and equity issuances.

Under the Tax Sharing Agreement, we and our affiliates agree not to take any action, or fail to take any action, after the effective date of the Tax Sharing Agreement, which action or failure to act is inconsistent with the Spin-Off qualifying as tax free under Sections 355 and 368(a)(1)(D) of the Code. In particular, we may determine to continue to operate certain of our business operations for the foreseeable future even if a sale or discontinuance of such business may otherwise have been advantageous. Moreover, in light of the requirements of Section 355(e) of the Code, we might determine to forgo certain transactions, including share repurchases, stock issuances, certain asset dispositions or other strategic transactions for some period of time following the Spin-Off. In addition, our indemnity obligation under the Tax Sharing Agreement may discourage, delay or prevent a change of control transaction for some period of time following the Spin-Off. In the event that we take action or fail to take action that affects the tax free nature of the Spin-Off, it would have a material impact on our financial position.

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 1, 2016. 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 is secured by substantially all of our rigs, excluding the two Prospector rigs in operation and the three Prospector rigs under construction in the shipyard.

Name

Make

Year Built/Rebuilt⁽¹⁾

Water

Depth

Rating

(feet)

Drilling

Depth

Capacity

(feet)

Location

Status⁽²⁾

Semisubmersibles — 2

Paragon MSS2

Pentagone 85

1977 / 2004 R

4,000

25,000

Brazil

Active

Paragon MSS1 (3)

Offshore Co. SCP III Mark 2

1979 / 2000 R

1,500

25,000

U.K.

Active

Drillships — 4

Paragon MDS1

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

South Africa

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

Brazil

Active

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

Paragon L1112

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

Active

Paragon M842

MLT Class 84-E.R.C.

1975 / 1995 R

390

25,000

Mexico

Active

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

U.K.

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.

Active

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

Tanzania

Active

Paragon C461 (3)

MSC/CJ-46

1982

250

25,000

The Netherlands

Active

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

Active

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

Benin

Stacked

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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

U.K.

Active

Prospector 5 (3)

Friede and Goldman JU-2000E

2014

400

35,000

U.K.

Active

Footnotes to Drilling Fleet Table


1.	Rigs designated with an “R” were modified, refurbished or otherwise upgraded in the year indicated by capital expenditures in an amount deemed material by management.


2.	Rigs listed as “Active” were either operating under contract or were actively seeking contracts. Rigs listed as “Stacked” are idle without a contract and are not actively marketed in present market conditions.


3.	Harsh environment capability.


4.	Although designed for a water depth rating of 390 feet of water in a non-harsh environment, the rig is currently equipped with legs adequate to drill in approximately 200 feet of water in a harsh environment. We own the additional leg sections required to extend the drilling depth capability to 390 feet of water.

Facilities

Our corporate headquarters is located in Houston, Texas. In addition, we own and lease administrative and marketing offices, and sites used primarily for storage, maintenance and repairs for drilling rigs and equipment in various locations worldwide.

ITEM 3. LEGAL PROCEEDINGS

Information regarding legal proceedings is set forth in Part II, Item 8, Note 1 - “Organization, Current Events and Basis of Presentation” and Note 16 - “Commitments and Contingencies” .

As of December 31, 2015, 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 and Combined Statements of Operations and Consolidated and Combined 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.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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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. On March 1, 2016 the closing price of our shares as reported by the OTC Pink was $0.29 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 1, 2016, there were 86,558,423 shares outstanding held by 218 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 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.



2015	High		Low		Dividends Declared and Paid
Fourth quarter	$	0.34	$	0.06	$	—
Third quarter	1.15		0.22		—
Second quarter	2.19		1.08		—
First quarter	3.40		1.05		—

2014
Fourth quarter	$	6.35	$	2.64	$	0.125
Third quarter	11.78		5.92		—

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 its statutory balance sheet. We are not permitted to pay dividends out of share capital, which includes share premiums. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on our board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our board considers relevant factors at that time. As proposed by our Plan, the contemplated amendments to our Revolving Credit Facility would prohibit us from paying any dividends following our emergence from bankruptcy.

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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, 2015. The graph also shows the cumulative total returns for the same period of the S&P Small Cap 600 Index and the Dow Jones U.S. Oil Equipment & Services Index. The graph assumes that $100 was invested in our shares and the two indices on August 4, 2014 and that all dividends or distributions and returns of capital were reinvested on the date of payment.



	INDEXED RETURNS
Company Name / Index	8/4/2014	9/30/2014	12/31/2014	3/31/2015	6/30/2015	9/30/2015	12/31/2015
Paragon Offshore	100.00	55.91	25.86	12.14	10.18	2.24	0.84
S&P Small Cap 600 Index	100.00	98.09	107.75	112.02	112.24	101.83	105.63
Dow Jones U.S. Oil Equipment & Services	100.00	91.81	71.07	68.52	70.17	55.60	55.10

Investors are cautioned against drawing any conclusions from the data contained in the graph, as past results are not necessarily indicative of future performance.

The above graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that we specifically incorporate it by reference into such filing.

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ITEM 6. SELECTED CONSOLIDATED AND COMBINED FINANCIAL DATA

The following table includes our selected consolidated and combined financial data over the five-year period ended December 31, 2015, which information is derived from our audited consolidated and combined financial statements. This information should be read in connection with, and is qualified in its entirety by, the more detailed information in our financial statements included in Item 8,“Financial Statements and Supplementary Data”.



	Year Ended December 31,
(In thousands, except per share amounts and percentages)	2015			2014			2013			2012			2011
Statement of Operations Data:
Operating revenues	$	1,492,428		$	1,993,762		$	1,893,002		$	1,541,857		$	1,370,557
Operating income (loss)	(941,374		)	(524,677		)	453,745			176,712			136,947
Net income (loss) attributable to Paragon Offshore	(999,643		)	(646,746		)	360,305			126,237			104,823

Per Share Data (1):
Earnings (loss) per share - basic and diluted	$	(11.65	)	$	(7.63	)	$	4.25		$	1.49		$	1.24
Weighted average shares outstanding - basic and diluted	85,785			84,753			84,753			84,753			84,753

Balance Sheet Data (at end of period):
Cash and cash equivalents (2)	$	773,571		$	56,772		$	36,581		$	70,538		$	75,767
Property and equipment, net	1,111,098			2,410,360			3,459,684			3,551,813			3,373,817
Total assets	2,383,865			3,253,389			3,982,799			4,118,072			3,866,756
Long-term debt (3)	2,559,462			1,888,439			1,561,141			339,806			975,000
Total debt (3) (4)	2,600,091			2,160,605			1,561,141			339,806			975,000
Total Paragon equity	(506,590		)	491,608			2,005,333			3,365,232			2,441,823

Cash Flows Data:
Net cash from operating activities	$	483,733		$	696,989		$	822,475		$	405,484		$	466,100
Net cash from investing activities	(204,444		)	(453,218		)	(317,726		)	(540,867		)	(493,255		)
Net cash from financing activities	437,510			(223,580		)	(538,706		)	130,154			26,030

Other Data (5):
Working capital	$	869,034		$	(9,000	)	$	217,450		$	253,816		$	123,004
Average dayrate (6)
Jackups	$	121,980		$	115,622		$	102,974		$	88,120		$	79,257
Floaters	262,521			290,408			261,827			236,767			233,052
Average utilization (7)
Jackups	62		%	79		%	90		%	81		%	77		%
Floaters	75		%	76		%	66		%	62		%	61		%
Total capital expenditures	$	202,909		$	261,641		$	366,361		$	532,404		$	518,455

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(1)

No earnings were allocated to unvested share-based payment awards in our earnings per share calculation for the years ended December 31, 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.


(2)	Consists of cash and cash equivalents as reported on our Consolidated Balance Sheets.


(3)	Predecessor historical Long-term debt and Total debt represents outstanding indebtedness under Noble’s commercial paper program which was repaid with payments from Paragon to Noble in connection with the Spin-Off.


(4)	Consists of long-term debt and current portion of long-term debt.


(5)	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.


(6)	See 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.

(7)

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

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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, 2015 and 2014, and our results of operations for each of the years in the three-year period ended December 31, 2015, and should be read in conjunction with the accompanying consolidated and combined financial statements and related notes in Item 8,“Financial Statements and Supplementary Data”.

OVERVIEW

Our 2015 financial and operating results include:


•	operating revenues totaling $1.5 billion;


•	net loss of $1.0 billion or a loss of $11.65 per diluted share;


•	pre-tax impairment charge of $1.2 billion; and


•	net cash from operating activities totaling $484 million

The Company

We are a global provider of offshore drilling rigs. Our operated fleet includes 34 jackups (including two high specification heavy duty/harsh environment jackups), four drillships and two semisubmersibles. We refer to our semisubmersibles and drillships collectively as “floaters.” 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.

Voluntary Reorganization under Chapter 11

On February 14, 2016, the Debtors filed voluntary petitions for relief under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. During the pendency of the bankruptcy proceedings, we will continue to operate our business as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

Events Leading to Proposed Restructuring

The following is a general description of factors that ultimately led us to enter into a restructuring plan to restructure our liabilities and maximize recoveries to holders of interests and claims:

•

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historically been an indicator of drilling activity. Because of the amount of debt we incurred in connection with the Spin-Off and the nature of the assets acquired, we were not equipped to absorb the ongoing and precipitous decline in oil and gas prices and the corresponding decline in demand for their services. Although we do not face any maturities on our secured debt until 2019, the severity and duration of the market downturn has increased the risk that existing customer contracts, some of which are due to expire in the near term, will not be renewed or will be renewed at materially reduced prices.

•

Contract Terminations and Renegotiations - Throughout 2015, a number of drilling contractors reported contract cancellations by their customers. The terms of certain 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. In May 2015, one of our subsidiaries received written notices of termination from Pemex with respect to drilling contracts on three of our jackups (the “Pemex Contracts”). Under these contracts, Pemex had the right to terminate upon 30 days’ notice without making an early termination payment. The three rigs are currently stacked. Additionally, Pemex offered us the option of accepting significantly lower dayrates or facing early termination with respect to rigs that remained under contract to Pemex. By the end of 2015, Pemex went from being one of our largest customers to employing only a single working rig and also disputing certain receivables. In addition to Pemex, another large customer, Petrobras, notified us that it was disputing contract language regarding the lengths of contracts for our two dynamically positioned drillships operating in Brazil (the “Petrobras Contracts”). This dispute resulted in the early termination of the drilling contract for one drillship in September 2015, significantly earlier than the original contract expiration date of March 2017. Based on communications from Petrobras, we expect that the other drillship will likely be terminated later this year. The contracts at issue constitute $142 million of our contract drilling services backlog. We continue to discuss the matter with Petrobras and plan to vigorously pursue all legal remedies available under these contracts. Furthermore, as exploration and production companies seek to reduce expenses, they have approached us and other drilling companies to seek reductions in current contract dayrates. Referred to as “blend and extend” discussions, these conversations are sometimes mutually beneficial, for example, if a drilling contractor agrees to lower its contract dayrate in exchange for an exploration and production company’s agreement to add time to the contract term. In some cases, such as those we faced in Mexico, drilling contractors may have no choice but to lower their dayrates or face termination. We have been (and may continue to be) engaged in similar discussions, which could have negative near-term impacts on revenues despite potentially providing longer-term benefits.

•

Deleveraging Initiatives - Due to the continuing decline in Brent crude oil prices and corresponding decline in demand for offshore drilling services, we did not expect to remain in compliance with the leverage ratio covenant under the Revolving Credit Facility during the four quarters in 2016. Accordingly, under the direction of an independent committee of our board of directors, we retained restructuring advisors to explore long term solutions to improve our overall balance sheet strength and to engage our lenders and noteholders with the intent of maximizing value for our shareholders and other stakeholders. As a result of these discussions, our board of directors ultimately decided to commence our Bankruptcy cases.

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”.

Acquisition of Prospector Offshore Drilling S. A.

The Prospector Acquisition expanded and enhanced our global fleet by adding two high specification jackups (the Prospector 1 and Prospector 5) contracted to Total E&P U.K. Limited and Elf Exploration U.K. Limited (collectively, “Total S.A.”) for use in the U.K. sector of the North Sea. Additionally, three subsidiaries of Prospector have contracted for the construction of three high-specification jackup rigs, the Prospector 6, Prospector 7 and Prospector 8 (collectively, the “Three High-Spec Jackups Under Construction”) by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China. These newbuild rigs are currently scheduled for delivery in the first quarter of 2016, second quarter of 2016 and fourth quarter of 2016, respectively. Each newbuild is being 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 Item 8, Note 4 -“Acquisition” for additional detail on the Prospector Acquisition.

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Sale-Leaseback Transaction

On July 24, 2015, we executed a combined $300 million Sale-Leaseback Transaction with the Lessors for our two high specification jackup units, Prospector 1 and Prospector 5 (collectively, the “Rigs”). We sold the Rigs to the Lessors and immediately leased the Rigs from the Lessors for a period of five years pursuant to the Lease Agreements. Net of fees and expenses and certain lease prepayments, we received net proceeds of approximately $292 million, including amounts used to fund certain required reserve accounts. The Prospector 1 and the Prospector 5 are each currently operating under drilling contracts with Total S.A. until mid-September 2016 and November 2017, respectively.

Basis of Presentation

Three of Noble’s standard specification drilling units included in the results of our Predecessor were retained by Noble and three were sold by Noble prior to the Separation. In addition, our Predecessor’s historical combined financial statements may also not be reflective of what our results of operations, effective tax rate, comprehensive income, financial position, equity or cash flows would have been as a standalone public company as a result of the matters discussed below.

Centralized Support Functions

The historical combined financial results of our Predecessor in our consolidated and combined financial statements for all periods prior to the Spin-Off include expense allocations for certain support functions that were provided on a centralized basis within Noble, including, but not limited to, general corporate expenses related to communications, corporate administration, finance, legal, information technology, human resources, compliance, and employee benefits and incentives. These allocated costs are not necessarily indicative of the costs that we would have incurred as a standalone public company. Following the Spin-Off, Noble continues to provide us with some of the services related to these functions on a transitional basis pursuant to a transition services agreement relating to our business.

Compensation and Benefit Plan Matters

During the periods prior to the Spin-Off, most of our employees were eligible to participate in various Noble benefit programs. The results of our Predecessor included in these consolidated and combined financial statements include an allocation of the costs of such employee benefit plans. These costs were allocated based on our employee population for each of the periods presented prior to Spin-Off. We consider the expense allocation methodology and results to be reasonable for the periods presented.

Income Taxes

The operations of our Predecessor have been included in certain income tax returns of Noble. The income tax provisions and related deferred tax assets and liabilities that have been reflected in our Predecessor’s historical combined financial statements have been computed as if our Predecessor were a separate taxpayer using the separate return method. As a result, actual tax transactions that would not have occurred had our Predecessor been a separate entity have been eliminated in the preparation of these consolidated and combined financial statements. Income taxes of our Predecessor include results of the operations of the standard specification drilling units. In instances where the operations of the standard specification drilling units of our Predecessor were included in the filing of a return with high specification units, an allocation of income tax expense was made.

We operate through various subsidiaries in numerous countries throughout the world. Consequently, income taxes have been based on the laws and rates in effect in the countries in which our operations are conducted, and 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 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.

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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 2015, Brent prices continued to fall, decreasing 23% to close on December 31, 2015 at $37.28 per barrel. For the full year 2015, Brent crude finished 35% below its closing price of $57.33 on December 31, 2014. Since January 1, 2016, Brent crude oil prices have been volatile, reaching a low $27.88 per barrel on January 20, 2016 and rebounding to close on March 2, 2016 at $36.93 per barrel. Despite falling oil prices and a significant reduction in both onshore and offshore exploration and development activity, member countries of OPEC, particularly Saudi Arabia, have not reduced their production levels and as a result, the world faces an ongoing oversupply of oil, resulting in the current low commodity price environment. Public announcements from companies such as Chevron and ConocoPhillips and industry spending surveys produced by third parties all indicate that oil and gas companies, including supermajors, independents, and national oil companies, plan to reduce their capital spending for 2016 by 25% or more from 2015 levels, which were 20% to 25% below 2014 levels. Accordingly, we anticipate significantly reduced offshore drilling activity in 2016 as compared with 2015.

During the fourth quarter of 2015, contracting activity for the offshore drilling industry was essentially flat as compared to the third quarter of 2015. According to industry data, there were 60 new jackup contract announcements or fixtures during the fourth quarter of 2015 compared to 64 new fixtures during the third quarter of 2015. Both totals exclude instances where companies agreed to renegotiate dayrates which numbered three and nine in the fourth and third quarters of 2015, respectively. Sixteen of the new fixtures were the result of the Chinese National Oil Company CNOOC signing new contracts with units owned by various Chinese drilling contractors and do not reflect a competitive bidding situation, nor is there any information as to the dayrates for these fixtures. The fourth quarter 2015 total represents a 24% decline in activity relative to the fourth quarter 2014, when 79 new fixtures were observed. In the floater segment, there were 28 new fixtures and no renegotiations during the fourth quarter of 2015 compared to 15 new fixtures and 2 renegotiations during the third quarter of 2015 and 35 new fixtures and four renegotiations during the fourth quarter of 2014.

Average dayrates for new fixtures were essentially flat between the third and fourth quarters of 2015 for rigs where data has been published by third party services. During the third and fourth quarters of 2015, dayrates for new jackup fixtures averaged approximately $113,000 as compared to $115,000 in the fourth quarter of 2014. Dayrates for new floater fixtures decreased slightly, averaging at approximately $271,000 in the fourth quarter of 2015 compared to $277,000 in the third quarter of 2015 and $388,000 in the fourth quarter of 2014.

Media reports continue to indicate that Petrobras is seeking to reduce 2016 capital expenditures. Petrobras is contesting 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 29, 2015. We continue to discuss the matter with Petrobras and will vigorously pursue all legal remedies available to us under these contracts. The Paragon DPDS3 is currently expected to work until August 2016, according to Petrobras’ interpretation of the contract. As of December 31, 2015, the Paragon DPDS3 drilling contract constitutes $225 million of our contract drilling services backlog, including $142 million being contested by Petrobras. Any material changes in these contract terms will have a material impact on our financial position.

On February 17, 2016, Mexico’s government announced it would cut Pemex’ 2016 budget in response to the deteriorating global demand outlook for oil and gas. Pemex also previously announced its new policy of paying suppliers on a schedule that will take up to 180 days due to budget austerity brought on by low oil prices. See Item 8, Note 14 - “Concentration on Market and Credit Risk.”

As of February 22, 2016, there were 125 jackup drilling rigs under construction, on order, or planned for construction. These rigs are currently scheduled for delivery between 2016 through as late as 2020. Certain drilling contractors with jackups under construction, including us, 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 70 floating rigs under construction, on order, or planned with deliveries between 2016 and 2020. The oil prices required for a project to break even for projects requiring the use of floating assets is significantly

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higher than for projects requiring jackup rigs. Also, a greater portion of the industry’s exploration work is done in deepwater as compared with 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. In the third quarter of 2015, we took an impairment charge on five of our six floating assets as we anticipate that the future utility of these units is limited after each finishes its current contract. We may choose to stack, sell, or scrap these assets.

In summary, the near-term outlook for the offshore drilling industry is poor. Dayrates and utilization for both floaters and jackups are challenged and could remain so for a period of time. We anticipate that in 2016, the industry will experience few tenders for new drilling activity; continued negotiations on existing contracts to reduce dayrates and/or contract term; and additional contract cancellations. However, we believe that reduced drilling activity will ultimately have a negative effect on global oil supply. Coupled with what is anticipated to be generally increasing global demand for hydrocarbons, we believe this will, in time, support oil prices at a level which will cause oil and gas companies to resume drilling activity and we continue to have confidence in the longer-term fundamentals for the industry.

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, 2015, 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		2016			2017			2018

Floaters ⁽¹⁾	$	262	$	173		$	89		$	—
Jackups	746		469			242			35
Total	$	1,008	$	642		$	331		$	35
Percent of available days committed ⁽²⁾			33		%	20		%	4		%

(1)

Our drilling contracts with Petrobras provide an opportunity for us to earn performance bonuses based on targets for minimizing downtime on our rigs operating offshore Brazil, which we have included in our backlog in an amount equal 50% of potential performance bonuses for such rigs, or $17 million. Petrobras has indicated to us that it will contest the term of our drilling contract for the Paragon DPDS3 in connection with the length of prior shipyard projects relating to the rig. As of December 31, 2015, total backlog related to this contract was approximately $225 million, including $142 million that will be contested by Petrobras and included in the table above.

(2)

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, 2015, our contract drilling services backlog did not include any letters of intent.

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,

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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.

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RESULTS OF OPERATIONS

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 consolidated results of Paragon for the five months ended December 31, 2014, and the combined 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.

Rig Utilization, Operating Days and Average Dayrates

Operating results for our 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		%

Jackups	62	%	79	%	7,680	10,188	(25	)%	$	121,980	$	115,622	5	%
Floaters (3)	75	%	76	%	1,645	2,371	(31	)%	262,521		290,408		(10	)%
Total (4)	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.

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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.

(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 the current year as compared to the prior year 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 the current year as compared to the prior year.

The decrease in floater revenues of $257 million in the current year 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 the prior year.

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 the current year but experienced full utilization in Brazil during the prior year. 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 the current year 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 the prior year.

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The decrease in jackup operating days was due to seven of our rigs in Mexico, which were uncontracted for a portion of the current year but experienced close to full utilization during the prior year. 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 the prior year. 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 the current year but were contracted for most of the prior year. The decrease in operating days was partially offset by 749 additional operating days in the current year due to the Prospector 1, Prospector 5, and the Paragon C20051 operating in the North Sea, 438 additional operating days in the current year due to the Paragon L786 and the Paragon M1161 operating in the Middle East 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 the current year as compared to the prior year 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 the current year.

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 the current year from the prior year were primarily due to transition support services we have provided, on a cost-plus basis, to Noble’s remaining Brazil operations. We will continue to provide both rig-based and shore-based support services to Noble through the term of Noble’s existing rig contracts and pursuant to the transition service agreement for Brazil (See Item 8, Note 16 -‘Commitments and Contingencies” for additional detail).

Depreciation and Amortization — The $83 million decrease in depreciation and amortization in the current year was primarily attributable to lower depreciation in the current year 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 the current year represent actual costs incurred for periods subsequent to the Spin-Off. Costs incurred during the current year include $9 million of professional fees related to our financial restructuring. Excluding the restructuring fees, costs were 19% lower than the prior year 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 the prior year 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 the current year, 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 during the current year.

During the prior year, 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 the current year 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.

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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. All senior note repurchases were made using available cash balances.

In the prior year, we repurchased and canceled an aggregate principal amount of $85 million of our senior notes at an aggregate cost of $67 million including accrued interest. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of issuance costs, of approximately $19 million. All senior note repurchases were made using available cash balances.

Income tax provision/benefit — Our income tax benefit increased $142 million in the current year compared to the prior year, 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 current year net operating losses offset by valuation allowance if appropriate in certain jurisdictions, and certain discrete tax items.

2014 Compared to 2013

Our results of operations for the year ended December 31, 2014 consist of the consolidated results of Paragon for the five months ended December 31, 2014, and the combined results of our Predecessor for the prior months. Our results of operations for the year ended December 31, 2013 consist entirely of the combined results of our Predecessor.

Net loss for 2014 was $647 million, or a loss of $7.63 per diluted share, on operating revenues of $2.0 billion, compared to net income for 2013 of $360 million, or $4.25 per diluted share, on operating revenues of $1.9 billion.

Rig Utilization, Operating Days and Average Dayrates



	Average Rig Utilization ⁽¹⁾				Operating Days ⁽²⁾				Average Dayrates
(Dollars in thousands)	2014		2013		2014	2013	%		2014		2013		%

Jackups	79	%	90	%	10,188	12,032	(15	)%	$	115,622	$	102,974	12	%
Floaters	76	%	66	%	2,371	2,173	9	%	290,408		261,827		11	%
Total ⁽³⁾	78	%	82	%	12,559	14,205	(12	)%	$	148,620	$	127,275	17	%


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


(2)	Information reflects the number of days that our rigs were operating under contract.


(3)	Excludes the Paragon FPSO1, which was retired from service in 2014.

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Operating Results

The following table includes our operating results for the years ended December 31, 2014 and 2013.



							Change
(Dollars in thousands)	2014			2013			$			%

Operating revenues
Contract drilling services	$	1,866,497		$	1,807,952		$	58,545		3	%
Labor contract drilling services	33,401			35,146			(1,745		)	(5	)%
Reimbursables and other (1)	93,864			49,904			43,960			88	%
	1,993,762			1,893,002			100,760			5	%
Operating costs and expenses:
Contract drilling services	890,694			914,702			(24,008		)	(3	)%
Labor contract drilling services	24,774			24,333			441			2	%
Reimbursables (1)	77,843			38,341			39,502			103	%
Depreciation and amortization	422,235			413,305			8,930			2	%
General and administrative	62,081			64,907			(2,826		)	(4	)%
Loss on impairments	1,059,487			43,688			1,015,799			**
Gain on sale of assets, net	—			(35,646		)	35,646			**
Gain on contract settlements/extinguishments, net	—			(24,373		)	24,373			**
Gain on repurchase of long-term debt	(18,675		)	—			(18,675		)	**
	2,518,439			1,439,257			1,079,182			75	%
Operating income (loss) (2)	$	(524,677	)	$	453,745		$	(978,422	)	(216	)%


**	Not a meaningful percentage.


(1)	We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. See below for additional explanation on the increase in 2014 as compared to 2013.


(2)	The rigs retained and sold by Noble represent revenues of $117 and $182 million for the years ended December 31, 2014 and 2013, respectively. The expenses for these same periods are $72 and $114 million, respectively, not including the $36 million pre-tax gain recorded on the sale of the Noble Lewis Dugger during the third quarter of 2013.

Contract Drilling Services Operating Revenues—Changes in contract drilling services revenues for 2014 as compared to 2013 were driven by a 17% increase in average dayrates which increased revenues by $197 million. This increase was partially offset by a 12% decrease in operating days which negatively impacted revenues by $138 million.

The increase in contract drilling services revenues was driven by our floaters, which generated approximately $120 million more revenue in 2014. The increase in revenue from our floaters was partially offset by a $61 million decrease in revenues from our jackups.

The increase in floater revenues of $120 million in 2014 was driven by a 11% increase in average dayrates coupled with a 9% increase in operating days which resulted in a $68 million and a $52 million increase in revenues, respectively, from 2013.

The increase in both average dayrates and operating days for our floaters was impacted by the Paragon DPDS3 operating during all of 2014 after undergoing its reliability upgrade project in the shipyard during 2013. The increase in average dayrates was also driven by increased bonus revenues on the Paragon DPDS1 and the Paragon DPDS2 from improvements in operational performance during 2014 while operating in Brazil. The increase in operating days was partially offset by the Noble Driller, which was retained by Noble after the Separation.

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The $61 million decrease in jackup revenues in 2014 was driven by a 15% decrease in jackup operating days which resulted in a $190 million decrease in revenues. This decline was partially offset by a 12% increase in average dayrates which positively impacted revenues by $129 million from 2013.

The decrease in jackup operating days was primarily driven by our rigs operating in the Middle East such as the Paragon M1161, the Paragon M822, the Paragon L1111, and the Paragon L786, which were off contract for all, or significant portions of 2014 but experienced full utilization during 2013. This decrease is coupled with increased shipyard time on jackups in other regions, including the Paragon M825 and the Paragon L782 both in Africa, the Paragon C20051 in the North Sea, and the Paragon L1116 in Mexico. Additionally, the decrease in operating days is partially attributable to the Noble Alan Hay and the Noble David Tinsley, which were retained by Noble after the Separation. The increase in average dayrates resulted from favorable market conditions in the shallow water market, particularly for our rigs in the Middle East and North Sea.

Contract Drilling Services Operating Costs and Expenses — Contract drilling services operating costs and expenses remained relatively consistent in 2014 as compared to 2013, as the reduction in contract drilling operating costs and expenses in 2014 from the rigs retained by Noble was partially offset by increases from rigs returning to service in late 2013 and early 2014.

Labor Contract Drilling Services Operating Revenues and Costs and Expenses — The decline in revenues associated with our Canadian labor contract drilling services was primarily related to fluctuations in foreign currency exchange rates. Expenses associated with our labor contract drilling services remained relatively constant.

Reimbursables Operating Revenues and Costs and Expenses —The $44 million increase in reimbursable revenues and the related $40 million increase in reimbursable costs in 2014 from 2013 were primarily due to transition support services we have provided, on a cost-plus basis, to Noble’s remaining Brazil operations. We will continue to provide both rig-based and shore-based support services to Noble through the term of Noble’s existing rig contracts and pursuant to the transition service agreement for Brazil (See Item 8, Note 16 -‘Commitments and Contingencies” for additional detail).

Depreciation and Amortization — The $9 million increase in depreciation and amortization in 2014 was primarily attributable to completion of the Paragon DPDS3 shipyard upgrade. This upgrade was completed and the rig returned to service during the fourth quarter of 2013. The increase is partially offset by lower depreciation on assets subject to the impairment charge taken in the third quarter of 2014.

General and Administrative — General and administrative expenses in 2013 represent costs allocated to our Predecessor based on certain support functions that were provided by Noble on a centralized basis. Costs in 2014 include both allocated costs for periods prior to the Spin-Off and actual costs incurred for periods subsequent to the Spin-Off. Costs incurred during 2014 were less than 2013 due to differences in staffing levels of our organization relative to Noble’s levels prior to the Distribution.

Loss on Impairment — During 2014, we identified indicators of impairment, including lower crude oil prices, a decrease in contracting activities (particularly for floating rigs), and resultant projected declines in dayrates and utilization. We concluded that a triggering event occurred requiring us to perform an impairment analysis of our fleet of drilling rigs. As a result of this analysis, we determined that the Paragon DPDS1, Paragon DPDS2 and Paragon DPDS3 drilling rigs were impaired. Additionally, we have decided to scrap the Paragon FPSO1, Paragon MSS3, Paragon B153, and Paragon DPDS4. Based on the above analysis, our estimates of fair value resulted in the recognition of an impairment loss of $1.1 billion for the year ended December 31, 2014.

In 2013, our Predecessor determined that our floating production storage and offloading unit (“FPSO”), formerly the Noble Seillean, was partially impaired as a result of its annual impairment test and the market outlook for this unit at that time. As a result, our Predecessor recognized a charge of $40 million for the year ended December 31, 2013. Also in 2013, our Predecessor recorded an impairment charge on two cold-stacked submersible rigs. These rigs had been impaired in 2011 due to the declining market outlook for drilling services for that rig type; however, in 2013 an additional impairment charge of approximately $3.6 million was recorded as a result of the potential disposition of these assets to an unrelated third party. These submersible rigs were sold by our Predecessor in January 2014.

Gain on sale of assets, net — Gain on sale of assets, net, during 2013 was attributable to the sale of the Noble Lewis Dugger to an unrelated third party in Mexico.

Gain on contract settlements/extinguishments, net — During the third quarter of 2013, Noble received $45 million related to the settlement of all claims against the former investors of FDR Holdings, Ltd., which Noble acquired in July 2010, relating to alleged breaches of various representations and warranties contained in the purchase agreement. A portion of the settlement

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related to standard specification rigs. This portion, totaling $23 million, was pushed down to our Predecessor in 2013, through an allocation, using the acquired rig values of the purchased rigs.

Gain on repurchase of long-term debt — In 2014, we repurchased and canceled an aggregate principal amount of $85 million of our senior notes at an aggregate cost of $67 million including accrued interest. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of issuance costs, of approximately $19 million. All senior note repurchases were made using available cash balances.

Other Expenses

Income tax provision — Our income tax provision decreased $16 million in 2014 compared to 2013 primarily due to tax benefit from impairment losses, partially offset by higher tax expense due to Noble’s restructuring prior to the Spin-Off and certain unfavorable discrete tax items. Prior to the Spin-Off, Noble restructured certain aspects of our business to affect the Separation. This restructuring resulted in significant tax changes for our business and operations following the Spin-Off. These changes include limitations on our ability to offset taxable income with interest expense attributable to borrowings under our senior note indenture and term loan agreement, and ownership of our rigs operating in certain jurisdictions which are in structures subject to higher tax rates than prior to the restructuring. Additionally, certain unfavorable discrete tax items were recorded during the third quarter of 2014, including one in connection with legislation enacted by the U.K. government that restricts deductions on certain intercompany transactions, such as those relating to the bareboat charter agreements used in connection with our U.K. continental shelf operations.

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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 regulations 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. 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 GAAP. However, we believe Adjusted EBITDA is useful to an investor in evaluating our operating performance because this measure: (1) is widely used by investors in the energy 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 to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital structure and asset base from its operating structure; and (3) is used by our management for various purposes, including as a measure of operating performance, in presentations to our Board of Directors, as a basis for strategic planning and forecasting, and as a component for setting incentive compensation. 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)	2015			2014			2013
Net loss	$	(999,643	)	$	(646,746	)	$	360,305
Adjustments:
Depreciation and amortization	339,268			422,235			413,305
Loss on impairments	1,181,358			1,059,487			43,688
Gain on sale of assets, net	(13,217		)	—			(35,646		)
Gain on contract settlements/extinguishments, net	—			—			(24,373		)
Gain on repurchase of long-term debt	(4,345		)	(18,675		)	—
Interest expense, net of amount capitalized	130,036			56,654			5,886
Income tax (benefit) provision	(72,108		)	69,394			85,605
Adjusted EBITDA	$	561,349		$	942,349		$	848,770

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LIQUIDITY AND CAPITAL RESOURCES

Financial Resources and Liquidity Overview

Our primary sources of liquidity are cash generated from operations, any future financing arrangements, and equity issuances, if necessary, 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, 2015, we had available liquidity of $776 million (which included $774 million in available cash, including $17 million of cash held in unrestricted subsidiaries, and $2 million remaining in our Revolving Credit Facility).

The table below includes a summary of our cash flow information for the year ended December 31, 2015, 2014, and 2013. Our cash flows for the year ended December 31, 2015 consist entirely of the consolidated results of Paragon while our cash flows for the year ended December 31, 2014 consist of the consolidated results of Paragon for the five months ended December 31, 2014 and the combined results of our Predecessor for the seven months ended July 31, 2014. Our cash flows for the year ended December 31, 2013 consist entirely of the combined results of our Predecessor.



	Year Ended December 31,
(In thousands)	2015			2014			2013
Cash flows provided by (used in):
Operating activities	$	483,733		$	696,989		$	822,475
Investing activities	(204,444		)	(453,218		)	(317,726		)
Financing activities	437,510			(223,580		)	(538,706		)

Changes in cash flows from operating activities for the year ended December 31, 2015 are driven by changes in net loss (see discussion of changes in net loss in “Results of Operations” above) and significant collections from our customers during the period. 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 $218 million in 2015 as compared to $260 million in 2014. During the year ended December 31, 2015, our cash flows used in investing activities were also impacted by our sale of the Paragon M822, the Paragon FPSO, the Paragon DPDS4, and drill pipe to unrelated third parties as well as an increase in restricted cash related to reserve requirements on the Sale-Leaseback Transaction. Changes in cash flows from financing activities for the year ended December 31, 2015 are primarily due to borrowings under our Revolving Credit Facility and proceeds from the Sale-Leaseback Transaction, both offset by repayments of the Prospector Senior Credit Facility and Prospector Bonds. See further discussions on our Revolving Credit Facility below.

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; and

•satisfaction of the cash payments under our proposed Plan.

We currently expect to fund these cash flow needs with cash generated by our operations, available cash balances, financing under credit facilities, 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.

In December 2015, we drew down substantially all of the available borrowing capacity under our Revolving Credit Facility to preserve liquidity. At December 31, 2015, we had $774 million of cash on hand and $2 million of committed financing available under our Revolving Credit Facility. 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. To avoid contested and lengthy chapter 11 cases, we utilized the 30-day grace period to continue

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negotiations with our stakeholders and prepare for an in-court restructuring. Accordingly, under the direction of an independent committee of our Board of Directors, we entered into the PSA.

The terms of the transactions contemplated by the Plan with respect to our Debt Facilities are as follows:

•

Lenders in our Revolving Credit Agreement shall receive a $165 million cash payment and corresponding permanent reductions in lending commitments. The Revolving Credit Agreement will be amended and all remaining amounts outstanding will be converted into a term loan with an extension of the maturity to 2021, a rate increase to LIBOR + 4.5% with a 1.00% LIBOR floor, a minimum liquidity covenant at all times set at $110 million (subject to a grace period if the minimum liquidity falls below $110 million but remains above $95 million), a suspension of the net leverage ratio and interest coverage covenants until the first quarter of 2018, as well as certain other amendments.

•


•	General unsecured claims are unimpaired under the Plan, and the Company’s Senior Secured Term Loan (the “Term Loan Facility”) shall be reinstated.


•	The Plan does not contemplate restructuring the financing arrangements created by the Sale-Leaseback Transaction as the Prospector subsidiaries are not Debtors in the chapter 11 filing.

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 the Bankruptcy Court’s approval of our reorganization plan. This represents a material uncertainty related to events and conditions that may cause significant 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. While operating as debtors in possession under chapter 11, 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, the 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 or as a consequence of the Bankruptcy cases.

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 initiated actions designed to improve our liquidity position by giving priority to generating cash flows 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 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. We anticipate that we will continue to incur significant professional fees and costs for the pendency of the Bankruptcy cases. Pursuant to the terms of the PSA and the Term Loan Agreement, we are obligated to pay the reasonable fees and costs of specified legal and financial advisors to each of the creditor parties to the PSA and the Term Loan agent.

Subject to the outcome of the Bankruptcy cases, we believe that our cash on hand and cash flow from operating activities will likely be adequate to meet the liquidity requirements of our existing business and maintain the minimum liquidity covenants contemplated under the Plan. See Part I, Item 1A, “Risk Factors - Risk Factors Related to Our Restructuring and Our Business”.

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Capital Expenditures

Cash used for capital expenditures, including capitalized interest, totaled $218 million, $260 million, and $379 million for 2015, 2014, and 2013, respectively. In connection with our capital expenditure program, we have outstanding commitments relating to ongoing major projects, upgrades and replacements to drilling equipment, and shipyard construction commitments of approximately $632 million and $657 million at December 31, 2015 and 2014, respectively. Our purchase commitments consist of obligations outstanding to external vendors primarily related to future capital purchases and include $600 million due in 2016 related to the Three High-Spec Jackups Under Construction. In connection with our acquisition of Prospector, we acquired subsidiaries that contracted for the construction of the Three High-Spec Jackups Under Construction by SWS in China. These newbuild rigs are currently scheduled for delivery in the first quarter of 2016, second quarter of 2016 and fourth quarter of 2016, respectively. Each newbuild is being 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 other subsidiaries other than the applicable subsidiary.

From time to time we consider possible projects that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units. Other factors that could cause actual capital expenditures to materially exceed plan include delays and cost overruns in shipyards (including costs attributable to labor shortages), shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, changes in governmental regulations and requirements and changes in design criteria or specifications during repair or construction.

Future Capital Expenditures

As discussed above, we have made, and expect to continue to make, investments in capital expenditures. Subject to our liquidity limitations and the execution of the Plan, we plan investments in 2016 to be primarily for expenditures to extend the useful life of our rigs. The negative covenants under the Plan restrict us from obtaining additional capital, which may limit our level of capital expenditures.

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. We are not permitted to pay dividends out of share capital, which includes share premiums. We had no distributable reserves at December 31, 2015. We had $300 million of distributable reserves at December 31, 2014. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on our Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant factors at that time. Also, as proposed by our Plan, the contemplated amendments to our Revolving Credit Facility would prohibit us from 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, 2015:



			Payments Due by Period
(In thousands)	Total		2016		2017		2018		2019		2020		Thereafter		Other
Contractual Cash Obligations
Debt obligations ^{(1) (2)}	$	2,333,957	$	6,500	$	6,500	$	6,500	$	715,000	$	6,500	$	1,592,957	$	—
Interest payments ^{(1) (3)}	741,699		113,101		112,787		112,540		112,293		92,414		198,564		—
Sale-leaseback⁽⁴⁾	330,573		51,073		41,245		32,371		30,660		175,224		—		—
Operating leases ⁽⁵⁾	21,766		8,479		4,218		2,859		2,328		1,959		1,923		—
Pension plan contributions ⁽⁶⁾	—		—		—		—		—		—		—		—
Purchase commitments ⁽⁷⁾	632,346		632,346		—		—		—		—		—		—
Tax reserves ⁽⁸⁾	18,504		—		—		—		—		—		—		18,504
Total	$	4,078,845	$	811,499	$	164,750	$	154,270	$	860,281	$	276,097	$	1,793,444	$	18,504

(1)

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. The acceleration of these obligations did not occur until February 14, 2016. (See Item 8, Note 1 - “Organization, Current Events, and Basis of Presentation” for additional detail). The debt obligations and interest payments do not reflect our commitments upon confirmation of the proposed Plan which remains subject to the approval of the Bankruptcy Court.


(2)	Our debt obligations include a balloon payment at maturity of our Senior Notes; quarterly principal payments and a balloon payment at maturity of our Term Loan Facility; and a balloon payment at maturity of our Revolving Credit Facility based on amount outstanding at December 31, 2015.


(3)	Interest amounts include fixed interest payments on our Senior Notes; interest and commitment fees on our Revolving Credit Facility (assuming interest rate as of December 31, 2015 and the amount outstanding and unused portion of the underlying commitment as of December 31, 2015); and interest payments on our Term Loan Facility (assuming fixed rate as of December 31, 2015).


(4)	Our capital lease obligations represent minimum annual rental payments assuming weighted average interest rates pursuant to the Sale-Leaseback Transaction. (See Item 8, Note 8 - “Debt” for additional detail)


(5)	We enter into operating leases in the normal course of business. Some lease agreements provide us with the option to renew the leases. Our future operating lease payments would change if we exercised these renewal options and if we entered into additional operating lease agreements.


(6)	We expect our aggregate minimum contributions to our plans in 2016, subject to applicable law, to be $8 million. We continue to monitor and evaluate funding options based upon market conditions and may increase contributions at our discretion.


(7)	Purchase commitments consist of obligations outstanding to external vendors primarily related to future capital purchases and includes $600 million in 2016 related to the three high-specification jackup rigs under construction.


(8)	Tax reserves are included in the “Other” column in the table above due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. (See Item 8, Note 9 - “Income Taxes.” for additional detail)

At December 31, 2015, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit and surety bonds that guarantee our performance as it relates to our drilling contracts, tax and other obligations in various jurisdictions. These letters of credit and surety bond obligations are not normally called, as we typically comply with the underlying performance requirement.

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The following table summarizes our other commercial commitments at December 31, 2015:



			Amount of Commitment Expiration Per Period
(In thousands)	Total		2016		2017		2018		2019		2020		Thereafter
Contractual Cash Obligations
Letters of Credit	$	89,312	$	79,644	$	—	$	4,934	$	2,622	$	1,839	$	273
Surety bonds	114,536		87,013		27,323		—		—		—		200
Total	$	203,848	$	166,657	$	27,323	$	4,934	$	2,622	$	1,839	$	473

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our consolidated and combined financial statements included in Item 8,“Financial Statements and Supplementary Data” are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. Critical accounting policies and estimates that most significantly impact our consolidated and combined financial statements are described below.

Allowance for Doubtful Accounts

We utilize the specific identification method for establishing and maintaining allowances for doubtful accounts. We review accounts receivable on a quarterly basis to determine the reasonableness of the allowance. Our allowance for doubtful accounts was $44 million and $1 million at December 31, 2015 and December 31, 2014, respectively. Bad debt expense of $38 million and $0.1 million was recorded for the years ended December 31, 2015 and December 31, 2014, respectively. No bad debt expense was recorded for the year ended December 31, 2013. Bad debt expense is reported as a component of “Contract drilling services operating costs and expense” in our Consolidated and Combined Statements of Operations.

Property and Equipment, at cost

Property and equipment is stated at cost, reduced by provisions to recognize economic impairment in value whenever events or changes in circumstances indicate an asset’s carrying value may not be recoverable. Major replacements and improvements are capitalized. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are eliminated from the accounts and the gain or loss is recognized. Drilling equipment and facilities are depreciated using the straight-line method over their estimated useful lives as of the date placed in service or date of major refurbishment. Estimated useful lives of our drilling equipment range from three to thirty years. Other property and equipment is depreciated using the straight-line method over useful lives ranging from two to twenty-five years.

Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred; however, the costs of the overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Property and equipment, at cost” in our Consolidated Balance Sheets. Such amounts, net of accumulated depreciation, totaled $108 million and $193 million at December 31, 2015 and 2014, respectively. Depreciation expense related to overhauls and asset replacement totaled $84 million, $85 million and $76 million for the years ended December 31, 2015, 2014 and 2013, respectively.

We evaluate the impairment of property and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis, we complete an impairment analysis on all of our rigs. An impairment loss on our property and equipment exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions we may take an impairment loss in the future. For discussion related to our impairment analysis see Item 8, Note 5 - “Property and Equipment and Other Assets.”

Goodwill Impairment Assessment

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and Other, we can opt to perform a qualitative assessment to test goodwill for impairment or we can directly perform a two-step impairment test. Based on our qualitative assessment, if we determine that the fair value of a reporting unit is more likely than not (i.e., a likelihood of more than 50 percent) to be less than its carrying amount, the two-step impairment test will be performed.

In the absence of sufficient qualitative factors, goodwill impairment is determined using a two-step process:


•	Step one- Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, the goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two.


•	Step two- Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit’s goodwill. The excess of the fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess.

For discussion related to our goodwill impairment assessment performed at September 30, 2015 see Item 8, Note 5 - “Property and Equipment and Other Assets”.

Certain Significant Estimates and Contingent Liabilities

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated and combined financial statements included elsewhere in Item 8, “Financial Statements and Supplementary Data.”

Revenue Recognition

Our typical dayrate drilling contracts require our performance of a variety of services for a specified period of time. We determine progress towards completion of the contract by measuring efforts expended and the cost of services required to perform under a drilling contract, as the basis for our revenue recognition. Revenues generated from our dayrate basis drilling contracts and labor contracts are recognized on a per day basis as services are performed and begin upon the contract commencement, as defined under the specified drilling or labor contract. Dayrate revenues are typically earned, and contract drilling expenses are typically incurred ratably over the term of our drilling contracts. We review and monitor our performance under our drilling contracts to confirm the basis for our revenue recognition. Revenues from bonuses are recognized when earned.

It is typical in our dayrate drilling contracts to receive compensation and incur costs for mobilization, equipment modification, or other activities prior to the commencement of the contract. Any such compensation may be paid through a lump-sum payment or other daily compensation. Pre-contract compensation and costs are deferred until the contract commences. The deferred pre-contract compensation and costs are amortized, using the straight-line method, into income over the term of the initial contract period, regardless of the activity taking place. This approach is consistent with the economics for which the parties have contracted. Once a contract commences, we may conduct various activities, including drilling and well bore related activities, rig maintenance and equipment installation, movement between well locations or other activities.

Deferred revenues from drilling contracts totaled $9 million at both December 31, 2015 and December 31, 2014. Such amounts are included in either “Other current liabilities” or “Other liabilities” in our Consolidated Balance Sheets, based upon the expected time of recognition of such deferred revenues. Deferred costs associated with deferred revenues from drilling contracts totaled $6 million at December 31, 2015 as compared to $2 million at December 31, 2014. Such amounts are included in either “Prepaid and other current assets” or “Other assets” in our Consolidated Balance Sheets, based upon the expected time of recognition of such deferred costs.

We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.

Income Taxes

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have been computed as if our Predecessor were a separate taxpayer using the separate return method. As a result, actual tax transactions that would not have occurred had our Predecessor been a separate entity have been eliminated in the preparation of these consolidated and combined financial statements. Income taxes of our Predecessor include results of the operations of the standard specification drilling units. In instances where the operations of the standard specification drilling units of our Predecessor were included in the filing of a return with high specification units, an allocation of income taxes was made.

We operate through various subsidiaries in numerous countries throughout the world. Due to our global presence, we are subject to tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in the U.K., the U.S., and any other jurisdictions in which we or any of our subsidiaries operate, were incorporated or otherwise determined to have a taxable presence. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If the taxing authorities do not agree with our assessment of the effects of such laws, policies, treaties and regulations, or our interpretation thereof, this could have a material adverse effect on us including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

In certain jurisdictions, we have recognized deferred tax assets and liabilities. Judgment and assumptions are required in determining whether deferred tax assets will be fully or partially utilized. When we estimate that all or some portion of certain deferred tax assets such as net operating loss carryforwards will not be utilized, we establish a valuation allowance for the amount ascertained to be unrealizable. We continually evaluate strategies that could allow for future utilization of our deferred tax assets. Any change in the ability to utilize such deferred tax assets will be accounted for in the period of the event affecting the valuation allowance. If facts and circumstances cause us to change our expectations regarding future tax consequences, the resulting adjustments could have a material effect on our financial results or cash flow.

In certain circumstances, we expect that, due to changing demands of the offshore drilling markets and the ability to redeploy our offshore drilling units, certain units will not reside in a location long enough to give rise to future tax consequences. As a result, no deferred tax asset or liability has been recognized in these circumstances. Should our expectations change regarding the length of time an offshore drilling unit will be used in a given location, we will adjust deferred taxes accordingly.

NEW ACCOUNTING PRONOUNCEMENTS

In May 2014, the FASB issued ASU No. 2014-09, which amends ASC Topic 606, Revenue from Contracts with Customers. The amendments in this ASU are intended to provide a more robust framework for addressing revenue issues, improve comparability of revenue recognition practices and improve disclosure requirements. Based on ASU No. 2015-14, Revenue from Contracts with Customers: Deferral of the Effective Date, subsequently issued in August 2015, the amendments in this ASU are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. This ASU can be adopted either retrospectively or as a cumulative-effect adjustment as of the date of adoption. Entities reporting under U.S. GAAP are not permitted to adopt this standard earlier than the original effective date for public entities. We are evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.

In June 2014, the FASB issued ASU No. 2014-12, which amends ASC Topic 718, Compensation-Stock Compensation. The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in the estimate of the grant-date fair value of the award. The guidance is effective for annual periods, and interim periods within those annual periods beginning after December 15, 2015. The guidance can be applied prospectively for all awards granted or modified after the effective date or retrospectively to all awards with performance targets outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. We do not expect that our adoption will have a material impact on our financial statements or disclosures in our financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements - Going Concern. This ASU codifies management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and to provide related note disclosures. The guidance is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter, and early adoption is permitted. The Company has elected early adoption of this guidance and has included the related disclosures in the consolidated and combined financial statements for the year ended December 31, 2015.

In January 2015, the FASB issued ASU 2015-01, Income Statement - Extraordinary and Unusual Items. This ASU simplifies income statement classification by removing the concept of extraordinary items from U.S. GAAP. As a result, items that are both unusual and infrequent will no longer be separately reported net of tax after continuing operations. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015 and early adoption

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is permitted. If we have extraordinary or unusual items in the future, our adoption could have a material impact on our financial statements or disclosures in our financial statements.

In April 2015, the FASB issued ASU No. 2015-03, Simplifying the Presentation of Debt Issuance Costs. This ASU requires debt issuance costs to be 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. In August 2015, the FASB issued ASU No. 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements, which states that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. We will adopt this ASU retrospectively on January 1, 2016, which will result in a reduction of both our long-term assets and long-term debt balances of approximately $20 million based on deferred financing costs for our Senior Notes and Term Loan Facility at December 31, 2015.

In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires companies to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. In addition, companies will no longer allocate valuation allowances between current and noncurrent deferred tax assets because those allowances also will be classified as noncurrent. The guidance is effective for financial statements issued for annual periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for all companies in any interim or annual period. We have elected early adoption of this guidance retroactively. Early adoption had no impact on prior periods as reported in our financial statements for the year ended December 31, 2015.

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk is the potential for loss from a change in the value of a financial instrument as a result of fluctuations in interest rates, currency exchange rates or equity prices, as further described below.

Interest Rate Risk

For variable rate debt, interest rate changes generally do not affect the fair market value of such debt, but do impact future earnings and cash flows, assuming other factors are held constant. We are subject to market risk exposure related to changes in interest rates on borrowings under our Revolving Credit Facility and Term Loan Facility.

Interest on borrowings under the Revolving Credit Facility is at an agreed upon applicable margin over adjusted LIBOR, or base rate plus such applicable margin as stated in the agreement. At December 31, 2015, we had $709 million of borrowings outstanding under our Revolving Credit Facility. A 1% change in the interest rate on the floating rate debt would impact our annual earnings and cash flows by approximately $7 million.

Interest on borrowings under the Term Loan Facility is at an agreed upon percentage point spread over adjusted LIBOR (subject to a 1% floor), or base rate as stated in the agreement. At December 31, 2015, we had $639 million in borrowings outstanding under our Term Loan Facility, net of unamortized discount. Since we are currently subject to the 1% LIBOR floor, our Term Loan Facility effectively bears interest at a fixed interest rate. The fair value of our Term Loan Facility was approximately $236 million at December 31, 2015. Related interest expense for the year ended December 31, 2015 was $26 million. Holding other variables constant (such as debt levels), a 1% increase in interest rates would increase our annual interest expense by approximately $6 million.

Our Senior Notes bear interest at a fixed interest rate and fair value will fluctuate based on changes in prevailing market interest rates and market perceptions of our credit risk. The fair value of our Senior Notes was approximately $140 million at December 31, 2015, compared to the principal amount of $984 million.

Foreign Currency Risk

Although we are a U.K. company, we define foreign currency as any non-U.S. denominated currency. Our functional currency is primarily the U.S. dollar. However, outside the United States, a portion of our expenses are incurred in local currencies. Therefore, when the U.S. dollar weakens (strengthens) in relation to the currencies of the countries in which we operate, our expenses reported in U.S. dollars will increase (decrease).

We are exposed to risks on future cash flows to the extent that local currency expenses exceed revenues denominated in local currencies that are other than the U.S. dollar. To help manage this potential risk, we may periodically enter into derivative instruments to manage our exposure to fluctuations in foreign currency exchange rates, and we may conduct hedging activities in future periods to mitigate such exposure. These contracts are primarily accounted for as cash flow hedges, with the effective portion of changes in the fair value of the hedge recorded on the Consolidated Balance Sheet in AOCL. Amounts recorded in AOCL are reclassified into earnings in the same period or periods that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of the hedged item is recorded directly to earnings. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.

Our North Sea, Mexico and Brazil operations have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we may periodically enter into forward contracts, all of which would have a maturity of less than 12 months and would settle monthly in the operations’ respective local currencies. At December 31, 2015, we had no outstanding derivative contracts. Depending on market conditions, we may elect to utilize short-term forward currency contracts in the future.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Paragon Offshore plc

In our opinion, the accompanying balance sheets and the related statements of income, of comprehensive income, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Paragon Offshore plc and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our audits (which was an integrated audit in 2015). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company experienced continued reductions in overall global market dayrates and a decline in demand for services, which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also discussed in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

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

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 11, 2016

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PARAGON OFFSHORE PLC

CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)



	Year Ended December 31,
	2015			2014			2013
Operating revenues
Contract drilling services	$	1,368,731		$	1,866,497		$	1,807,952
Labor contract drilling services	29,108			33,401			35,146
Reimbursables and other	94,589			93,864			49,904
	1,492,428			1,993,762			1,893,002
Operating costs and expenses
Contract drilling services	769,373			890,694			914,702
Labor contract drilling services	20,599			24,774			24,333
Reimbursables	81,291			77,843			38,341
Depreciation and amortization	339,268			422,235			413,305
General and administrative	59,475			62,081			64,907
Loss on impairments	1,181,358			1,059,487			43,688
Gain on sale of assets, net	(13,217		)	—			(35,646		)
Gain on contract settlements/extinguishments, net	—			—			(24,373		)
Gain on repurchase of long-term debt	(4,345		)	(18,675		)	—
	2,433,802			2,518,439			1,439,257
Operating income (loss)	(941,374		)	(524,677		)	453,745
Other income (expense)
Interest expense, net of amount capitalized	(130,036		)	(56,654		)	(5,886		)
Other, net	(310		)	3,920			(1,949		)
Income (loss) before income taxes	(1,071,720		)	(577,411		)	445,910
Income tax benefit (provision)	72,108			(69,394		)	(85,605		)
Net income (loss)	$	(999,612	)	$	(646,805	)	$	360,305
Net (income) loss attributable to non-controlling interest	(31		)	59			—
Net income (loss) attributable to Paragon	$	(999,643	)	$	(646,746	)	$	360,305

Earnings (loss) per share
Basic and diluted	$	(11.65	)	$	(7.63	)	$	4.25

Weighted-average shares outstanding
Basic and diluted	85,785			84,753			84,753

See accompanying notes to the consolidated and combined financial statements.

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PARAGON OFFSHORE PLC

CONSOLIDATED AND COMBINED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)



	Year Ended December 31,
	2015			2014			2013
Net income (loss)	$	(999,612	)	$	(646,805	)	$	360,305
Other comprehensive income (loss), net of tax
Foreign currency translation adjustments	(7,430		)	(1,481		)	179
Foreign currency forward contracts	—			(4,027		)	—
Adjustments to pension plans	2,560			(1,141		)	—
Total other comprehensive income (loss), net	(4,870		)	(6,649		)	179
Total comprehensive income (loss)	$	(1,004,482	)	$	(653,454	)	$	360,484

See accompanying notes to the consolidated and combined financial statements.

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PARAGON OFFSHORE PLC

CONSOLIDATED BALANCE SHEETS

(In thousands)



	December 31,
	2015			2014
ASSETS
Current assets
Cash and cash equivalents	$	773,571		$	56,772
Restricted cash	3,000			12,502
Accounts receivable, net of allowance for doubtful accounts (Note 3)	266,325			539,376
Prepaid and other current assets	110,027			104,644
Total current assets	1,152,923			713,294
Property and equipment, at cost	2,652,537			4,842,112
Accumulated depreciation	(1,541,439		)	(2,431,752		)
Property and equipment, net	1,111,098			2,410,360
Other assets	119,844			129,735
Total assets	$	2,383,865		$	3,253,389

LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	40,629		$	272,166
Accounts payable and accrued expenses	85,374			160,874
Accrued payroll and related costs	48,246			81,416
Taxes payable	34,381			69,033
Interest payable	34,085			33,658
Other current liabilities	41,174			105,147
Total current liabilities	283,889			722,294
Long-term debt	2,559,462			1,888,439
Deferred income taxes	9,373			58,497
Other liabilities	37,731			89,910
Total liabilities	2,890,455			2,759,140
Commitments and contingencies (Note 16)
Equity
Ordinary shares, $0.01 par value, 186,457,393 shares authorized; with 86,026,247 and 84,753,393 issued and outstanding at December 31, 2015 and 2014, respectively	860			848
Additional paid-in capital	1,429,456			1,423,153
Accumulated deficit	(1,894,892		)	(895,249		)
Accumulated other comprehensive loss	(42,014		)	(37,144		)
Total shareholders’ equity (deficit)	(506,590		)	491,608
Non-controlling interest	—			2,641
Total equity (deficit)	(506,590		)	494,249
Total liabilities and equity	$	2,383,865		$	3,253,389

See accompanying notes to the consolidated and combined financial statements.

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PARAGON OFFSHORE PLC

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY

(In thousands)



	Ordinary Shares			Additional Paid-in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Net Parent Investment			Total Shareholders’ Equity and Net Parent Investment			Non Controlling Interest			Total Equity (Deficit)
	Shares	Amount		Additional Paid-in Capital			Accumulated Deficit			Accumulated Other Comprehensive Loss			Net Parent Investment			Total Shareholders’ Equity and Net Parent Investment			Non Controlling Interest			Total Equity (Deficit)
Balance at December 31, 2012	—	$	—	$	—		$	—		$	(185	)	$	3,365,417		$	3,365,232		$	—		$	3,365,232
Net income	—	—		—			—			—			360,305			360,305			—			360,305
Net transfers to parent	—	—		—			—			—			(1,720,383		)	(1,720,383		)	—			(1,720,383		)
Other comprehensive income, net	—	—		—			—			179			—			179			—			179
Balance at December 31, 2013	—	$	—	$	—		$	—		$	(6	)	$	2,005,339		$	2,005,333		$	—		$	2,005,333
Net income - Predecessor	—	—		—			—			—			237,428			237,428			—			237,428
Net loss - Paragon	—	—		—			(884,174		)	—			—			(884,174		)	(59		)	(884,233		)
Net changes in parent investment	—	—		—			—			—			(855,249		)	(855,249		)	—			(855,249		)
Distribution by former parent	84,753	848		1,417,119			—			(30,449		)	(1,387,518		)	—			—			—
Employee related equity activity:
Amortization of share-based compensation	—	—		7,689			—			—			—			7,689			—			7,689
Dividends paid	—	—		—			(11,075		)	—			—			(11,075		)	—			(11,075		)
Acquisition of Prospector	—	—		—			—			(40		)	—			(40		)	11,351			11,311
Acquisition of Prospector non-controlling interest	—	—		(1,655		)	—			—			—			(1,655		)	(8,651		)	(10,306		)
Other comprehensive loss, net	—	—		—			—			(6,649		)	—			(6,649		)	—			(6,649		)
Balance at December 31, 2014	84,753	$	848	$	1,423,153		$	(895,249	)	$	(37,144	)	$	—		$	491,608		$	2,641		$	494,249
Net income (loss)	—	—		—			(999,643		)	—			—			(999,643		)	31			(999,612		)
Adjustments to distribution by former parent	—	—		(9,493		)	—			—			—			(9,493		)	—			(9,493		)
Employee related equity activity:
Amortization of share-based compensation	—	—		16,089			—			—			—			16,089			—			16,089
Issuance of share-based compensation shares	1,273	12		(780		)	—			—			—			(768		)	—			(768		)
Acquisition of Prospector non-controlling interest	—	—		487			—			—			—			487			(2,672		)	(2,185		)
Other comprehensive loss, net	—	—		—			—			(4,870		)	—			(4,870		)	—			(4,870		)
Balance at December 31, 2015	86,026	$	860	$	1,429,456		$	(1,894,892	)	$	(42,014	)	$	—		$	(506,590	)	$	—		$	(506,590	)

See accompanying notes to the consolidated and combined financial statements.

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PARAGON OFFSHORE PLC

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(In thousands)



	Year Ended December 31,
	2015			2014			2013
Cash flows from operating activities
Net income (loss)	$	(999,612	)	$	(646,805	)	$	360,305
Adjustments to reconcile net income (loss) to net cash from operating activities:
Depreciation and amortization	339,268			422,235			413,305
Loss on impairments	1,181,358			1,059,487			43,688
Gain on sale of assets, net	(13,217		)	—			(35,646		)
Gain on repurchase of long-term debt	(4,345		)	(18,675		)	—
Deferred income taxes	(61,870		)	19,475			4,869
Share-based compensation	16,193			19,446			21,114
Provision for doubtful accounts	39,239			—			—
Net change in other assets and liabilities (Note 18)	(13,281		)	(158,174		)	14,840
Net cash provided by operating activities	483,733			696,989			822,475
Cash flows from investing activities
Capital expenditures	(202,909		)	(261,641		)	(366,361		)
Proceeds from sale of assets	30,816			6,570			61,000
Acquisition of Prospector Offshore Drilling S.A.	—			(176,569		)	—
Acquisition of Prospector Offshore Drilling S.A. non-controlling interest	(2,185		)	(10,306		)	—
Change in restricted cash	(15,528		)	(12,502		)	—
Change in accrued capital expenditures	(14,638		)	1,230			(12,365		)
Net cash used in investing activities	(204,444		)	(453,218		)	(317,726		)
Cash flows from financing activities
Net change in borrowings on Predecessor bank credit facilities	—			707,472			1,221,332
Net Activity – Revolving Credit Facility	11,000			154,000			—
Additional Borrowings – Revolving Credit Facility	543,500			—			—
Proceeds from issuance of Senior Notes and Term Loan Facility	—			1,710,550			—
Proceeds from Sale-Leaseback Financing, net	291,576			—			—
Repayment of Term Loan Facility	(6,500		)	(1,625		)	—
Repayment of Prospector Senior Credit Facility	(265,666		)	—			—
Repayment of Prospector Bonds	(101,000		)	—			—
Repayments on Sale-Leaseback Financing	(28,854		)	—			—
Purchase of Senior Notes	(6,546		)	(65,354		)	—
Dividends paid	—			(11,075		)	—
Debt issuance costs	—			(19,253		)	(2,484		)
Net transfers to parent	—			(2,698,295		)	(1,757,554		)
Net cash provided by (used in) financing activities	437,510			(223,580		)	(538,706		)
Net change in cash and cash equivalents	716,799			20,191			(33,957		)
Cash and cash equivalents, beginning of period	56,772			36,581			70,538
Cash and cash equivalents, end of period	$	773,571		$	56,772		$	36,581

Supplemental information for non-cash activities (Note 18)

See accompanying notes to the consolidated and combined financial statements.

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NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION, CURRENT EVENTS, AND BASIS OF PRESENTATION

Paragon Offshore plc (together with its subsidiaries, “Paragon,” the “Company,” “we,” “us” or “our”) is a global provider of offshore drilling rigs. Our operated fleet includes 34 jackups ( including two high specification heavy duty/harsh environment jackups), four drillships and two semisubmersibles. 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.

The Company operates its geographically diverse fleet with well-established customer relationships. We operate in significant hydrocarbon-producing geographies throughout the world, including Mexico, Brazil, the North Sea, West Africa, the Middle East, India and Southeast Asia. As of December 31, 2015, our contract backlog was $1.0 billion and included contracts with leading 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 transferred to us the assets and liabilities (the “Separation”) constituting most of Noble’s standard specification drilling units and related assets, liabilities and business. On August 1, 2014, Noble made a pro rata distribution to its shareholders of all of our issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned.

Voluntary Reorganization under Chapter 11

Plan Support Agreement

•


•	Existing shareholders will retain ownership of 65% of the ordinary shares of reorganized Paragon following emergence from bankruptcy.


•	General unsecured claims are unimpaired under the Plan, and the Company’s Senior Secured Term Loan (the “Term Loan Facility”) shall be reinstated.


•	The Plan does not contemplate restructuring the financing arrangements created by the Sale-Leaseback Transaction as the Prospector subsidiaries are not Debtors in the chapter 11 filing.

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Settlement with Noble Corporation

We also entered into a binding term sheet (the “Term Sheet”) with Noble with respect to the “Noble Settlement Agreement” (as described below). Upon execution of the Noble Settlement Agreement, certain conditions of the Tax Sharing Agreement executed between Noble and Paragon for the Spin-Off will be modified. 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 Note 16 - “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. As of December 31, 2015, our estimated Mexican Tax Assessments totaled approximately $200 million, with assessments for 2009 and 2010 yet to be received. Additionally, 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 following the defense of the Mexican Tax Assessments. 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. The Term Sheet has been approved by the boards of directors of both companies, but remains subject to execution of a definitive Noble Settlement Agreement and the approval of such agreement by the Bankruptcy Court in our chapter 11 proceedings. Upon the execution and approval by Bankruptcy Court of a final Noble Settlement Agreement, a material portion of our Mexican Tax Assessments, and any corresponding ultimate tax liability, will be assumed by Noble. Until such time, the current Tax Sharing Agreement remains in effect.

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 (“the Bankruptcy cases”). The Plan remains subject to approval of the Bankruptcy Court. During the pendency of the bankruptcy proceedings, we will continue to operate our business as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

Events Leading to Proposed Restructuring

The following is a general description of factors that ultimately led us to enter into a restructuring plan to restructure our liabilities and maximize recoveries to holders of interests and claims:

•

Collapse in Oil Prices - In the summer of 2014, Brent crude oil prices - a key factor in determining customer activity levels - began to decline, dropping from roughly $115 per barrel in June 2014 to approximately $60 per barrel by December of the same year. As a result of this swift and substantial decline in oil prices, many of our customers (which include national, international, and independent oil and gas companies) reduced their exploration and development capital expenditures by 20% to 25% in 2015. Oil prices continued to decline in 2015, closing at $37.28 per barrel on December 31, 2015, an additional 35% decrease over the course of a volatile year. This reduced demand has led to an oversupply of rigs competing for limited tendering activity. The oversupply of rigs has been compounded by a significant expansion of supply of (mostly non-contracted) newbuild rigs in recent years. As of February 4, 2016, Brent crude oil prices have declined by an additional approximately 8%. Several exploration and production companies have made announcements that they plan to reduce capital spending by 20% or more in 2016 as a result of expectations of continued low commodity prices. We expect that further reductions in activity will follow in 2016, as capital spending has historically been an indicator of drilling activity. Because of the amount of debt we incurred in connection with the Spin-Off and the nature of the assets acquired, we were not equipped to absorb the ongoing and precipitous decline in oil and gas prices and the corresponding decline in demand for their services. Although we do not face any maturities on our secured debt until 2019, the severity and duration of the market downturn has increased the risk that existing customer contracts, some of which are due to expire in the near term, will not be renewed or will be renewed at materially reduced prices.


•	Contract Terminations and Renegotiations - Throughout 2015, a number of drilling contractors reported contract cancellations by their customers. The terms of certain of our drilling contracts permit early termination of the contract

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by the customer, without cause, generally exercisable upon advance notice to us and, in some cases, without requiring an early termination payment. In May 2015, one of our subsidiaries received written notices of termination from Pemex with respect to drilling contracts on three of our jackups (the “Pemex Contracts”). Under these contracts, Pemex had the right to terminate upon 30 days’ notice without making an early termination payment. The three rigs are currently stacked. Additionally, Pemex offered us the option of accepting significantly lower dayrates or facing early termination with respect to rigs that remained under contract to Pemex. By the end of 2015, Pemex went from being one of our largest customers to employing only a single working rig and also disputing certain receivables. In addition to Pemex, another large customer, Petrobras, notified us that it was disputing contract language regarding the lengths of contracts for our two dynamically positioned drillships operating in Brazil (the “Petrobras Contracts”). This dispute resulted in the early termination of the drilling contract for one drillship in September 2015, significantly earlier than the original contract expiration date of March 2017. Based on communications from Petrobras, we expect that the other drillship will likely be terminated later this year. The contracts at issue constitute $142 million of our contract drilling services backlog. We continue to discuss the matter with Petrobras and plan to vigorously pursue all legal remedies available under these contracts. Furthermore, as exploration and production companies seek to reduce expenses, they have approached us and other drilling companies to seek reductions in current contract dayrates. Referred to as “blend and extend” discussions, these conversations are sometimes mutually beneficial, for example, if a drilling contractor agrees to lower its contract dayrate in exchange for an exploration and production company’s agreement to add time to the contract term. In some cases, such as those we faced in Mexico, drilling contractors may have no choice but to lower their dayrates or face termination. We have been (and may continue to be) engaged in similar discussions, which could have negative near-term impacts on revenues despite potentially providing longer-term benefits.

•

Going Concern

Delisting from the New York Stock Exchange

Basis of Presentation

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“Predecessor”), which comprised most of Noble’s standard specification drilling fleet and related operations. Our Predecessor’s historical combined financial statements include three standard specification drilling units that were retained by Noble and three standard specification drilling units that were sold by Noble prior to the Separation. We consolidate the historical combined financial results of our Predecessor in our consolidated and combined financial statements for all periods prior to the Spin-Off. All financial information presented after the Spin-Off represents the consolidated results of operations, financial position and cash flows of Paragon.


•	information technology,


•	legal, accounting, finance and treasury services,


•	human resources,


•	marketing, and


•	other corporate and infrastructural services.

Prior to the Spin-Off, our total equity represented the cumulative net parent investment by Noble, including any prior net income attributable to our Predecessor as part of Noble. At the Spin-Off, Noble contributed its entire net parent investment in our Predecessor. Concurrent with the Spin-Off and in accordance with the terms of our Separation from Noble, certain assets and liabilities were transferred between us and Noble, which have been recorded as part of the net capital contributed by Noble. During the first quarter of 2015, we recorded an out-of-period adjustment to the opening balance sheet of our Predecessor of approximately $9 million to reflect transfers of fixed assets resulting from the Spin-Off between us and our former parent, as well as revisions in estimates of liabilities associated with the Spin-Off. This adjustment did not affect our Consolidated and Combined Statements of Operations.

As our Predecessor previously operated within Noble’s corporate cash management program for all periods prior to the Distribution, funding requirements and related transactions between our Predecessor and Noble have been summarized and reflected as changes in equity without regard to whether the funding represents a receivable, liability or equity. Based on the terms of our Separation from Noble, we ceased being a part of Noble’s corporate cash management program. Any transactions with Noble after August 1, 2014 have been, and will continue to be, cash settled in the ordinary course of business, and such amounts, which totaled approximately $0.2 million and $2 million at December 31, 2015 and 2014, respectively, are included in “Accounts payable” on our Consolidated Balance Sheets

NOTE 2—NEW ACCOUNTING PRONOUCEMENTS

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guidance is effective for annual periods, and interim periods within those annual periods beginning after December 15, 2015. The guidance can be applied prospectively for all awards granted or modified after the effective date or retrospectively to all awards with performance targets outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. We do not expect that our adoption will have a material impact on our financial statements or disclosures in our financial statements.

In November 2015, the FASB issued ASU No. 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires companies to classify all deferred tax assets and liabilities as noncurrent on the balance sheet instead of separating deferred taxes into current and noncurrent amounts. In addition, companies will no longer allocate valuation allowances between current and noncurrent deferred tax assets because those allowances also will be classified as noncurrent. The guidance is effective for financial statements issued for annual periods beginning after December 15 2016 and interim periods within those annual periods. Early adoption is permitted for all companies in any interim or annual period. We have elected early adoption of this guidance retroactively. Early adoption had no impact on prior periods as reported in our financial statements for the year ended December 31, 2015.

NOTE 3—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Combination and Consolidation

The consolidated and combined financial statements include our accounts, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. The combined financial statements of our Predecessor include our net assets and results of our operations as previously described. All significant intercompany accounts and transactions have been eliminated in combination and consolidation.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand deposits with banks and all highly liquid investments with original maturities of three months or less. Our cash, cash equivalents and short-term investments are subject to potential credit risk, and certain of our cash accounts carry balances greater than federally insured limits. Cash and cash equivalents are primarily held by major banks or investment firms. Our cash management and investment policies restrict investments to lower risk, highly liquid securities and we perform periodic evaluations of the relative credit standing of the financial institutions with which we conduct business.

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Restricted Cash

Restricted cash consists primarily of cash held to satisfy the requirements of our Sale-Leaseback Transaction (as described in Note 8 - “Debt”), which was executed in 2015. Under the terms of the lease agreements we are required to maintain two cash reserve accounts, a capital expenditure reserve account and a rental reserve account.

The capital expenditure reserve is available specifically for special survey costs (3-5 year surveys) provided that we replenish any amount withdrawn within twelve months from the date of the withdrawal. This cash is available to us, for a designated purpose, in the short-term, and therefore the restricted cash balance is included in “Current assets” on our Consolidated Balance Sheet.

The rental reserve account is the minimum amount established under the lease agreements which we are required to maintain on reserve at all times during the lease period. The balance in the account increases with periodic deposits of operating revenue in excess of allowed operating expenses. Any amount of cash in the account in excess of the minimum balance required on reserve is to be used repay our long-term debt obligation related to the Sale-Leaseback Transaction. We classify the $25 million restricted cash balance related to the rental reserve account as long-term and include the balance in “Other Assets” on our Consolidated Balance Sheets.

Allowance for Doubtful Accounts

We utilize the specific identification method for establishing and maintaining allowances for doubtful accounts. We review accounts receivable on a quarterly basis to determine the reasonableness of the allowance. Our allowance for doubtful accounts was $44 million and $1 million at December 31, 2015 and 2014, respectively. Bad debt expense of $38 million and $0.1 million was recorded for the year ended December 31, 2015 and 2014, respectively. No bad debt expense was recorded for the year ended December 31, 2013. Bad debt expense is reported as a component of “Contract drilling services operating costs and expense” in our Consolidated and Combined Statements of Operations.

Property and Equipment, at Cost

Scheduled maintenance of equipment is performed based on the number of hours operated in accordance with our preventative maintenance program. Routine repair and maintenance costs are charged to expense as incurred; however, the costs of overhauls and asset replacement projects that benefit future periods and which typically occur every three to five years are capitalized when incurred and depreciated over an equivalent period. These overhauls and asset replacement projects are included in “Property and equipment, at cost” in our Consolidated Balance Sheets. Such amounts, net of accumulated depreciation, totaled $108 million and $193 million at December 31, 2015 and 2014, respectively. Depreciation expense related to overhauls and asset replacement projects totaled $84 million, $85 million and $76 million for the years ended December 31, 2015, 2014 and 2013, respectively.

We evaluate the impairment of property and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. In addition, on an annual basis, we complete an impairment analysis on all of our rigs. An impairment loss on our property and equipment exists when the estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized represents the excess of the asset’s carrying value over the estimated fair value. As part of this analysis, we make assumptions and estimates regarding future market conditions. To the extent actual results do not meet our estimated assumptions we may take an impairment loss in the future. For discussion related to our impairment analysis see Note 5 - “Property and Equipment and Other Assets.”

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Goodwill Impairment Assessment

Goodwill represents, at the time of an acquisition, the excess of purchase price over fair value of net assets acquired. We assess our goodwill for impairment on an annual basis on September 30 of each year or on an interim basis if events or changes in circumstances indicate that the carrying value may not be recoverable. In accordance with ASC 350, Intangibles-Goodwill and Other, we can opt to perform a qualitative assessment to test goodwill for impairment or we can directly perform a two-step impairment test. Based on our qualitative assessment, if we determine that the fair value of a reporting unit is more likely than not (i.e., a likelihood of more than 50 percent) to be less than its carrying amount, the two-step impairment test will be performed.

In the absence of sufficient qualitative factors, goodwill impairment is determined using a two-step process:


•	Step one- Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, the goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two.


•	Step two- Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit’s goodwill. The excess of the fair value of a reporting unit over the amounts assigned to its assets and liabilities is the implied fair value of goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess.

For discussion related to our goodwill impairment assessment performed at September 30, 2015 see Note 5 - “Property and Equipment and Other Assets”.

Debt Issuance Costs

Deferred debt issuance costs are amortized through interest expense over the life of the debt securities.

Fair Value Measurements

We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability. Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) unobservable inputs that require significant judgment for which there is little or no market data (“Level 3”). When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Our cash and cash equivalents, accounts receivable and accounts payable are by their nature short-term. As a result, the carrying values included in the accompanying Consolidated Balance Sheets approximate fair value.

Certain Significant Estimates and Contingent Liabilities

Revenue Recognition

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and labor contracts are recognized on a per day basis as services are performed and begin upon the contract commencement, as defined under the specified drilling or labor contract. Dayrate revenues are typically earned, and contract drilling expenses are typically incurred ratably over the term of our drilling contracts. We review and monitor our performance under our drilling contracts to confirm the basis for our revenue recognition. Revenues from bonuses are recognized when earned.

We record reimbursements from customers for “out-of-pocket” expenses as revenues and the related direct cost as operating expenses.

Share-Based Compensation Plans

We record the grant date fair value of share-based compensation arrangements as compensation cost using a straight-line method over the service period. Share-based compensation is expensed or capitalized based on the nature of the employee’s activities.

Foreign Currency Translation

We define foreign currency as any non-U.S. denominated currency. In non-U.S. locations where the U.S. dollar has been designated as the functional currency (based on an assessment of the economic circumstances of the foreign operation), local currency transaction gains and losses are included in net income. In non-U.S. locations where the local currency is the functional currency, assets and liabilities are translated at the rates of exchange on the balance sheet date, while income and expense items are translated at average rates of exchange during the year. The resulting gains or losses arising from the translation of accounts from the functional currency to the U.S. dollar are included in AOCL in the accompanying Consolidated Balance Sheets. We did not recognize any material gains or losses on foreign currency transactions or translations during the years ended December 31, 2015, 2014 or 2013.

Income Taxes

The operations of our Predecessor have been included in certain income tax returns of Noble. The income tax provisions and related deferred tax assets and liabilities that have been reflected in our Predecessor’s historical combined financial statements have been computed as if our Predecessor were a separate taxpayer using the separate return method. As a result, actual tax transactions that would not have occurred had our Predecessor been a separate entity have been eliminated in the preparation of these unaudited consolidated and combined financial statements. Income taxes of our Predecessor include results of the operations of the standard specification drilling units. In instances where the operations of the standard specification drilling units of our Predecessor were included in the filing of a return with high specification units, an allocation of income taxes was made.

We operate through various subsidiaries in numerous countries throughout the world. Due to our global presence, we are subject to tax laws, policies, treaties and regulations, as well as the interpretation or enforcement thereof, in the U.K., the U.S., and any other jurisdictions in which we or any of our subsidiaries operate, were incorporated, or otherwise considered to have a tax presence. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If the taxing authorities do not agree with our assessment of the effects of such laws, policies, treaties and regulations, or the interpretation or enforcement thereof, this could have a material adverse effect on us including the imposition of a higher effective tax rate on our worldwide earnings or a reclassification of the tax impact of our significant corporate restructuring transactions.

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Earnings/Loss per Share

Our unvested share-based payment awards, which contain non-forfeitable rights to dividends, are participating securities and are included in the computation of earnings per share pursuant to the “two-class” method. The “two-class” method allocates undistributed earnings between ordinary shares and participating securities; however, in a period of net loss, losses are not allocated to our participating securities. The diluted earnings per share calculation under the “two-class” method would also include the dilutive effect of potential shares issued in connection with stock options. The dilutive effect of stock options would be determined using the treasury stock method. The diluted earnings per share calculation under the two class method is the same as our basic earnings per share calculation since we currently have no stock options or other potentially dilutive securities outstanding.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the current year presentation.

NOTE 4—ACQUISITION

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. As of December 31, 2014, we owned approximately 93.4 million shares, or 98.7%, of the outstanding shares of Prospector. In addition, we assumed aggregate debt of $367 million, which comprised the 2019 Second Lien Callable Bond of $100 million (“Prospector Bonds”) and the 2018 Senior Secured Credit Facility of $270 million (“Prospector Senior Credit Facility”) which at the time of acquisition had $266 million in borrowings outstanding. On January 22, 2015, we settled a mandatory tender offer for additional outstanding shares, increasing our ownership to approximately 99.6% of the outstanding shares of Prospector. On February 23, 2015, we acquired all remaining issued and outstanding shares in Prospector pursuant to the laws of Luxembourg. We spent approximately $202 million in aggregate to purchase 100% of the shares of Prospector and funded the purchase using proceeds from our revolving credit facility and cash on hand. Prospector’s results of operations were included in our results effective November 17, 2014.

During the first quarter of 2015, we repurchased $100 million par value of the Prospector Bonds at a price of 101% of par, plus accrued interest, pursuant to change of control provisions of the bonds. On March 16, 2015, we repaid the principal balance outstanding under the Prospector Senior Credit Facility, which totaled approximately $261 million, including accrued interest, through the use of cash on hand and borrowings under our senior secured revolving credit facility.

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Accounting for business combinations requires that the various assets acquired and liabilities assumed in a business combination be recorded at their respective fair values. The most significant estimates to us typically relate to acquired property and equipment. Deferred taxes are recorded for any differences between the fair value and tax basis of assets acquired and liabilities assumed. To the extent the purchase price plus the liabilities assumed (including deferred income taxes recorded in connection with the transaction) exceeds the fair value of the net assets acquired, we are required to record the excess as goodwill. We recorded $13 million of goodwill as a result of the Prospector acquisition. See Note 5 - “Property and Equipment and Other Assets” related to our goodwill impairment in the third quarter of 2015 which resulted in impairment of the entire Prospector goodwill balance. As the fair value of assets acquired and liabilities assumed is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The following table summarizes our final allocation of the purchase price to the estimated fair values of the assets acquired and liabilities assumed on the acquisition date of November 17, 2014:



(In thousands)	Fair Value
ASSETS
Current assets
Accounts receivable	$	26,169
Restricted cash	5,023
Prepaid and other current assets	17,967
Total current assets	49,159
Property and equipment	516,979
Goodwill	13,290
Other assets	25,520
Total assets acquired	$	604,948
LIABILITIES
Current liabilities
Current maturities of long-term debt	$	32,970
Accounts payable	16,227
Accrued payroll and related costs	3,754
Taxes payable	4,378
Interest payable	6,466
Other current liabilities	19,120
Total current liabilities	82,915
Long-term debt	333,697
Other liabilities	456
Total liabilities assumed	$	417,068
Accumulated other comprehensive loss	(40		)
Non-controlling interest	11,351
Purchase price, net of cash acquired	$	176,569

The fair value of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities was generally determined using historical carrying values given the short-term nature of these items. The fair values of drilling equipment and in-place contracts were determined using management’s estimates of future net cash flows. Such estimated future cash flows were discounted at an appropriate risk-adjusted rate of return. The fair values of the consolidated derivatives were determined based on a discounted cash flow model utilizing an appropriate market or risk-adjusted yield. The fair value of other assets and other liabilities, related to long-term tax items, was derived using estimates made by management. Fair value estimates for in-place contracts are recorded in “Prepaid and other current assets” and “Other assets” in our Consolidated Balance Sheet and will be amortized over the life of the respective contract. The average life of these contracts was approximately 2.5 years as of the date of the acquisition.

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We incurred $4 million in acquisition costs for the year ended December 31, 2014 related to the Prospector acquisition. These costs have been expensed and are included in “Contract drilling services expense” in our Consolidated and Combined Statement of Operations.

The following unaudited pro forma financial information for the years ended December 31, 2014 and 2013, gives effect to the Prospector acquisition as if it had occurred at the beginning of the periods presented. The pro forma financial information for the year ended December 31, 2014 includes pro forma results for the period prior to the closing date of November 17, 2014 and actual results for the period from November 17, 2014 through December 31, 2014. The pro forma results are based on historical data and were not intended to be indicative of the results of future operations.



(In thousands, except per share amounts)	2014			2013
Total operating revenues	$	2,036,218		$	1,897,202
Net income (loss)	(702,607		)	344,255
Net income (loss) to Paragon Offshore	(701,800		)	344,470
Income (loss) per share (basic and diluted)	$	(8.28	)	$	4.06

Revenues from the Prospector rigs totaled $8 million from the closing date of November 17, 2014 through December 31, 2014. Operating expenses for this same period totaled $8 million for the Prospector rigs. Revenues for the year ended December 31, 2015, which are included in our Consolidated Statement of Operations, were $143 million. Operating expenses for these rigs totaled $143 million for the year ended December 31, 2015, which included depreciation expense of $19 million and impairment charges of $43 million related to capitalized costs on the Three High-Spec Jackups Under Construction.

NOTE 5—PROPERTY AND EQUIPMENT AND OTHER ASSETS

Our capital expenditures, including capitalized interest, totaled $218 million and $260 million for the years ended December 31, 2015 and 2014, respectively. Interest incurred related to property under construction, including major overhaul, improvement and asset replacement projects, is capitalized as a component of construction costs. Interest capitalized in our Predecessor’s results for the period prior to Spin-Off relates to Noble’s revolving credit facilities and commercial paper program, while interest capitalized in our results relates to our Senior Notes, Term Loan Facility, and Revolving Credit Facility (each as described and defined in Note 8 - “Debt”). Interest expense capitalized for the years ended December 31, 2015 and 2014 was $0.1 million and $3 million, respectively.

Loss on Impairment

We assess the recoverability of our long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the expectation of cold stacking a rig in the near term, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project or major rig upgrade). In addition, we complete an impairment analysis on all of our rigs at least on an annual basis. An impairment loss on our property and equipment exists when the estimated fair value, which is based on estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition, is less than its carrying amount. Estimates of undiscounted future cash flows typically include (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses, (ii) long-term growth rates, and (iii) estimates of useful lives of the assets. Such estimates of future undiscounted cash flows are highly subjective and are based on numerous assumptions about future operations and market conditions.

During the year ended December 31, 2015, we identified indicators of impairment, including the downward movement of crude oil prices, the release of the Paragon DPDS2, the increased probability of lower activity in Brazil and Mexico and the resultant projected declines in dayrates and utilization. As a result of these indicators, we concluded that a triggering event existed, which required us to perform an impairment assessment of our fleet of drilling rigs. We determined the fair value of our fleet using a market approach (for scrap rigs) and an income approach (for operating rigs) utilizing a weighted average cost of capital of approximately 15% and significant unobservable inputs, representative of a Level 3 fair value measurement, including the following assumptions and estimates:


•	dayrate revenues by rig;


•	utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);


•	revenue escalation rates and factors;

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•	operating costs and related days and downtime percentages for each rig if active, warm stacked or cold stacked;


•	estimated annual capital expenditures and costs for rig replacements and/or enhancement programs;


•	estimated maintenance, inspection or other costs associated with a rig returning to work;


•	remaining useful life and salvage value for each rig; and


•	estimated proceeds that may be received on disposition of a rig.

The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios were developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment. Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil and gas prices, cancellations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different.

We compared the carrying value of each rig to its relative recoverable value determined using undiscounted cash flow projections for each rig. For each rig with a carrying value in excess of its undiscounted cash flows, we computed its impairment based on the difference between the carrying value and fair value of the rig. Based on this analysis and other operational analyses, we determined that five floaters, sixteen jackups, certain capital spares and the deposits related to the Three High-Spec Jackups Under Construction were impaired. In aggregate, we recognized non-cash impairment losses of approximately $1.1 billion during the year ended December 31, 2015, which is included in “Loss on impairments” in our Consolidated and Combined Statements of Operations.

During the year ended December 31, 2014, we also identified triggering events, which required us to perform an impairment assessment of our fleet of drilling rigs, especially our floaters in Brazil. Based on that analysis, we recognized an impairment loss of $1.1 billion on our three drillships in Brazil and our one cold-stacked floating production storage and offloading unit in the U.S. Gulf of Mexico for the year ended December 31, 2014.

During 2013, our Predecessor determined that the Paragon FPSO, formerly the Noble Seillean, was partially impaired as a result of its annual impairment test and the current market outlook for this unit. Our Predecessor estimated the fair value of this unit by considering both income and market-based valuation approaches utilizing statistics for comparable rigs (Level 2 fair value measurement). Based on these estimates, our Predecessor recognized a charge of $40 million for the year ended December 31, 2013.

Also in 2013, our Predecessor recorded an impairment charge on two cold stacked submersible rigs. These rigs had been impaired in 2011 due to the declining market outlook for drilling services for that rig type; however, in 2013 an additional impairment charge of approximately $4 million was recorded as a result of the potential disposition of these assets to an unrelated third party. These submersible rigs were sold by our Predecessor in January 2014.

Goodwill Impairment

Goodwill related to the Company’s previous acquisitions is included in “Other assets” on the accompanying Consolidated Balance Sheets as of December 31, 2014. For purposes of evaluating goodwill, we have a single reporting unit, which represents our Contract Drilling Services provided by our fleet of mobile offshore drilling units. Given the events impacting the Company during the current year, including the decrease in contractual activities, a sustained decline in the Company’s market capitalization and credit rating downgrades, the Company concluded that there were sufficient indicators to require a goodwill impairment analysis during the fourth quarter of 2015 in conjunction with our annual goodwill assessment. In accordance with the applicable accounting guidance, the Company performed a two-step impairment test.

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In the first step of the impairment test, we determined the Company had a negative carrying value resulting from our long-lived asset impairment (discussed above), therefore the second step was performed to measure the amount of impairment by comparing the implied fair value of our reporting unit’s goodwill (estimated using the income approach performed for the fixed assets impairment assessment) to the carrying amount of that goodwill. Based on this analysis, the Company determined goodwill was impaired and recognized a non-cash impairment charge of approximately $37 million for the year ended December 31, 2015, which is included in “Loss on impairments” in our Consolidated and Combined Statements of Operations. At December 31, 2015, the Company had no goodwill. We had no goodwill impairment during 2014.

Sales of Assets, net

In January 2015, we completed the sale of the Paragon M822 for $24 million to an unrelated third party. In connection with the sale, we recorded a pre-tax gain of approximately $17 million.

During the third quarter of 2013, our Predecessor completed the sale of the Noble Lewis Dugger for $61 million to an unrelated third party in Mexico. In connection with the sale, our Predecessor recorded a pre-tax gain of approximately $36 million.

NOTE 6—SHARE-BASED COMPENSATION

Predecessor Plan

For all periods prior to the Spin-Off, our Predecessor was managed in the normal course of business by Noble and its subsidiaries. Noble provides a stock-based compensation plan to its employees that is granted and settled in stock of Noble. Prior to the Spin-Off and to the extent that Company employees participated in this plan, the results of our Predecessor were allocated a portion of the associated expenses (see Note 17 - “Related Parties (Including Relationship with Parent and Corporate Allocations)” for total costs allocated to us by Noble).

Our employees’ participation in Noble 1991 Plan was terminated at the time of the Distribution. All Noble time-vested restricted stock units (“TVRSU’s”) held by our employees under the Noble 1991 Plan were canceled at the Distribution and we granted Paragon TVRSU’s that were intended to be of equivalent value and remaining duration with regard to these canceled awards. With respect to outstanding Noble performance-vested restricted stock units (“PVRSU’s”) held by our employees under the Noble 1991 Plan, a portion of such PVRSU’s continues to be held by those employees and a portion has been canceled. With regard to the canceled portion of Noble PVRSU’s at the time of the Distribution, we either granted the affected employee Paragon PVRSU’s that were intended to be of equivalent value and duration at the time of grant to the canceled portion of the Noble award, or provided the employee compensation of equivalent value to the benefit the employee would have received had the canceled portion of the Noble awards remained in effect.

Paragon Plans

In conjunction with the Spin-Off, we adopted new equity incentive plans for our employees and directors, the Employee Plan and the Director Plan. Replacement awards of Paragon TVRSU’s and PVRSU’s granted in connection with the Spin-Off, as well as new share-settled and cash-settled awards, have been granted under the Employee Plan and the Director Plan.

Shares available for issuance and outstanding restricted stock units under our two equity incentive plans as of December 31, 2015 are as follows: (excluding the impact of cash-settled awards):

We have awarded both TVRSU’s and PVRSU’s under our Employee Plan and TVRSU’s under our Director Plan. The TVRSU’s under our Employee Plan generally vest over a three-year period. The number of PVRSU’s which vest will depend on the degree of achievement of specified corporate accounting-based and market-based performance criteria over the service period. Under the Employee Plan we have also awarded TVRSU’s that may be settled only in cash (“CS-TVRSU’s”) and are accounted for as liability-based awards. The CS-TVRSU’s vest over a three-year period.

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TVRSU’s under our Employee Plan are valued on the date of award at our underlying share price. The total compensation for units that ultimately vest is recognized using a straight-line method over the service period. The shares and related nominal value are recorded when the restricted stock unit vests and additional paid-in capital is adjusted as the share-based compensation cost is recognized for financial reporting purposes. TVRSU’s under our Director Plan were modified in the second quarter of 2015 resulting in accounting treatment as liability instruments. While the restricted stock units granted under our Director Plan will ultimately vest in shares, these TVRSU’s are recorded as a liability and are valued at the end of each reporting period at our underlying share price. Our CS-TVRSU’s are also recorded as a liability and are valued at the end of each reporting period at our underlying share price. They are measured on each balance sheet date and total compensation for units that ultimately vest is recognized over the service period.

We have awarded both company-based and market-based PVRSU’s under our Employee Plan. Our company-based PVRSU’s are valued on the date of award at our underlying share price. Total compensation cost recognized for the company-based PVRSU’s depends on a performance measure, ROCE, over specified performance periods. Estimated compensation cost is determined based on numerous assumptions, including an estimate of the likelihood that our ROCE will achieve the targeted thresholds and forfeiture of the PVRSU’s based on annualized ROCE performance over the terms of the awards. Our market-based PVRSU’s are valued on the date of the grant based on an estimated fair value. These PVRSU’s are based on the Company’s achievement of a market-based objective, total shareholder return (“TSR”), relative to a peer group of companies as defined in the award agreement. Estimated fair value is determined based on numerous assumptions, including an estimate of the likelihood that our stock price performance will achieve the targeted thresholds and the expected forfeiture rate. The fair value is calculated using a Monte Carlo simulation model. The assumptions used to value these market-based PVRSU’s include risk-free interest rates and historical volatility of the trading price of the Company’s common shares over a time period commensurate with the remaining term prior to vesting, as follows:



Valuation assumptions:	2015
Expected volatility	34.0	%
Risk-free interest rate	1.07	%

Similar valuation assumptions were made for each of the companies included in the defined peer group of companies in order to simulate the future outcomes using the Monte Carlo Simulation Model.

A summary of restricted stock activity for the years ended December 31, 2015 and 2014 is as follows:



	TVRSU’s Outstanding (1)		Weighted Average Award-Date Fair Value		CS-TVRSU’s Outstanding		Share Price ⁽²⁾		PVRSU’s Outstanding ⁽³⁾	Weighted Average Award-Date Fair Value
Outstanding at December 31, 2014	3,753,766		$	10.54	—				261,746	$	11.00
Awarded	4,117,919		2.49		3,408,844				587,738	2.78
Vested	(1,627,403	)	9.40		—				—	—
Forfeited	(419,425	)	8.09		(761,279	)			—	—
Outstanding at December 31, 2015	5,824,857		$	5.34	2,647,565		$	0.09	849,484	$	5.31


(1)	This column includes 606,935 shares outstanding at December 31, 2015 that were granted under our Director Plan and are recorded as a liability valued at the end of each reporting period at our underlying share price recognized over the service period.


(2)	The share price represents the closing price of our shares on December 31, 2015 at which both our CS-TVRSU’s and TVRSU’s granted under our Director Plan are measured.


(3)	The number of PVRSU’s shown equals the units that would vest if the “maximum” level of performance is achieved. The minimum number of units is zero and the “target” level of performance is 50% of the amounts shown.

Share and liability-based award amortization recognized during the year ended December 31, 2015 totaled $16 million. Share-based amortization recognized during the five months ended December 31, 2014, not including amounts allocated to our

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Predecessor, totaled $8 million. At December 31, 2015, we had $17 million of total unrecognized compensation cost related to our TVRSU’s which is expected to be recognized over a remaining weighted-average period of 1.6 years. At December 31, 2015, we had $0.2 million of total unrecognized compensation cost related to our CS-TVRSU’s, which is expected to be recognized over a remaining weighted-average period of 2.1 years. At December 31, 2015, we had $2.0 million of total unrecognized compensation cost related to our PVRSU’s which is expected to be recognized over a remaining weighted-average period of 1.6 years. The total potential compensation for our PVRSU’s is recognized over the service period regardless of whether the performance thresholds are ultimately achieved.

NOTE 7—EARNINGS/LOSS PER SHARE

Our outstanding share-based payment awards currently consist solely of restricted stock units. These unvested restricted stock units, which contain non-forfeitable rights to dividends, are deemed to be participating securities and are included in the computation of earnings per share pursuant to the “two-class” method. The “two-class” method allocates undistributed earnings between ordinary shares and participating securities; however, in a period of net loss, losses are not allocated to our participating securities.

On August 1, 2014, approximately 85 million of our ordinary shares were distributed to Noble’s shareholders in conjunction with the Spin-Off. Weighted average shares outstanding, basic and diluted, has been computed based on the weighted average number of ordinary shares outstanding during the applicable period. Restricted stock units do not represent ordinary shares outstanding until they are vested and converted into ordinary shares. The diluted earnings per share calculation under the two class method is the same as our basic earnings per share calculation as we currently have no stock options or other potentially dilutive securities outstanding.

No earnings were allocated to unvested share-based payment awards in our earnings per share calculation for the years ended December 31, 2015 and 2014 due to our net losses in both periods. Our basis of presentation related to weighted average unvested shares outstanding for the period prior to the Spin-Off does not include our unvested restricted stock units that were granted to our employees in conjunction with Paragon’s 2014 Employee Omnibus Incentive Plan. As a result, we also have no earnings allocated to unvested share-based payment awards in our earnings per share calculation for periods prior to the Spin-Off.

The following table includes the computation of basic and diluted net income (loss) and earnings (loss) per share:



	Year Ended December 31,
(In thousands, except per share amounts)	2015			2014			2013
Allocation of income (loss) - basic and diluted
Net income (loss) attributable to Paragon	$	(999,643	)	$	(646,746	)	$	360,305
Earnings allocated to unvested share-based payment awards	—			—			—
Net income (loss) to ordinary shareholders - Basic and diluted	$	(999,643	)	$	(646,746	)	$	360,305

Weighted average shares outstanding
Basic and diluted	85,785			84,753			84,753

Weighted average unvested share-based payment awards	6,197			1,761			—

Earnings (loss) per share
Basic and diluted	$	(11.65	)	$	(7.63	)	$	4.25

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NOTE 8—DEBT

A summary of long-term debt at December 31, 2015 and 2014 is as follows:



	December 31,
(In thousands)	2015			2014
Revolving Credit Facility	$	708,500		$	154,000
Term Loan Facility, bearing interest at 3.75%, net of unamortized discount	639,321			645,357
Senior Notes due 2022, bearing fixed interest at 6.75% per annum	456,572			457,572
Senior Notes due 2024, bearing fixed interest at 7.25% per annum	527,010			537,010
Sale-Leaseback Transaction	268,688			—
Prospector 2019 Second Lien Callable Bond	—			101,000
Prospector 2018 Senior Secured Credit Facility	—			265,666
Total debt	2,600,091			2,160,605
Less: Current maturities of long-term debt	(40,629		)	(272,166		)
Long-term debt	$	2,559,462		$	1,888,439

Revolving Credit Facility, Term Loan Facility and Senior Notes

On June 17, 2014, we entered into the Revolving Credit Agreement with lenders that provided commitments in the amount of $800 million. The Revolving Credit Agreement, which is secured by substantially all of our rigs, has a term of five years and matures in July 2019. Borrowings under the Revolving Credit Facility bear interest, at our option, at either (i) an adjusted LIBOR, plus an applicable margin ranging between 1.50% to 2.50%, depending on our leverage ratio, or (ii) a base rate plus an applicable margin ranging between 1.50% to 2.50%. Under the Revolving Credit Agreement, we may also obtain letters of credit, the issuance of which would reduce a corresponding amount available for borrowing. As of December 31, 2015, we had $709 million in borrowings outstanding at a weighted average interest rate of 2.78% and an aggregate amount of $89 million of letters of credit issued under the Revolving Credit Facility.

As of December 31, 2015, we have drawn down substantially all of the available borrowing capacity under our Revolving Credit Facility and have outstanding borrowings in the amount of approximately $709 million. The proceeds from the borrowing were used to enhance the Company’s liquidity and financial flexibility.

On July 18, 2014, we issued $1.08 billion of Senior Notes and also borrowed $650 million under the Term Loan Facility. The Term Loan Facility is secured by substantially all of our rigs. The proceeds from the Term Loan Facility and the Senior Notes were used to repay $1.7 billion of intercompany indebtedness to Noble incurred as partial consideration for the Separation. The Senior Notes consisted of $500 million of 6.75% senior notes and $580 million of 7.25% senior notes, which mature on July 15, 2022 and August 15, 2024, respectively. The Senior Notes were issued without an original issue discount. Interest on the 6.75% senior notes is payable semi-annually, in January and July, and interest on the 7.25% senior notes is payable semi-annually, in February and August. Borrowings under the Term Loan Facility bear interest at an adjusted LIBOR rate plus 2.75%, subject to a minimum LIBOR rate of 1% or a base rate plus 1.75%, at our option. We are required to make quarterly principal payments of $1.6 million plus interest and may prepay all or a portion of the Term Loan Facility at any time. The Term Loan Facility matures in July 2021. The loans under the Term Loan Facility were issued with 0.50% original issue discount.

In connection with the issuance of the aforementioned Debt Facilities, we incurred $35 million of issuance costs, in aggregate, which is being amortized over the respective term of each Debt Facility. We had total debt issuance costs related to these Debt Facilities of $26 million and $31 million included in “Other assets” on our Consolidated Balance Sheets as of December 31, 2015 and 2014, respectively.

During 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. The repurchases consisted of $1 million aggregate principal amount of our 6.75% senior notes due July 2022 and $10 million aggregate principal amount of our 7.25% senior notes due August 2024. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of issuance costs, of approximately $4 million in “Gain on repurchase of long-term debt.” All Senior Note repurchases were made using available cash balances.

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During the year ended December 31, 2014, we repurchased and canceled an aggregate principal amount of $85 million of our Senior Notes at an aggregate cost of $67 million including accrued interest. The repurchases consisted of $42 million aggregate principal amount of our 6.75% senior notes due July 2022 and $43 million aggregate principal amount of our 7.25% senior notes due August 2024. As a result of the repurchases, we recognized a total gain on debt retirement, net of the write-off of issuance costs, of approximately $19 million in “Gain on repurchase of long-term debt.” All Senior Note repurchases were made using available cash balances.

The agreements related to our Debt Facilities contain covenants that place restrictions on certain merger and consolidation transactions; our ability to sell or transfer certain assets; payment of dividends; making distributions; redemption of stock; incurrence or guarantee of debt; issuance of loans; prepayment; redemption of certain debt; as well as incurrence or assumption of certain liens. The covenants and events of default under our Revolving Credit Facility, Senior Notes, and Term Loan Facility are substantially similar. In addition to these covenants, the Revolving Credit Agreement includes an additional covenant requiring us to maintain a net leverage ratio less than 4.00 to 1.00 and a covenant requiring us to maintain a minimum interest coverage ratio greater than 3.00 to 1.00. We must comply with these financial covenants at the end of each fiscal quarter based upon our financial results for the prior twelve-month period. As of December 31, 2015, we were in compliance with the covenants under our Revolving Credit Agreement by maintaining a net leverage ratio of 3.78 and an interest coverage ratio of 4.55 . These calculations do not include the corresponding financial information of certain of our subsidiaries, including Prospector, designated as unrestricted for purposes of our debt agreements. As a result, the assets, liabilities, and financial results of our unrestricted subsidiaries are excluded from the financial covenants applicable to us and our other subsidiaries under these Debt Facilities.

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 indenture governing the Senior Notes.

The commencement of the Bankruptcy cases in February 2016 constituted an event of default subsequent to the balance sheet date 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. Because the acceleration of these obligations did not occur until February 14, 2016, we were in compliance with the covenants, and had the liquidity to make the January 15, 2016 interest payment as mentioned above, the long-term portion of our Term Loan Facility, Revolving Credit Facility, and Senior Notes remained classified as long-term liabilities in the accompanying consolidated and combined financial statements as of December 31, 2015.

Sale-Leaseback Transaction

While it has been determined that the Lessors are variable interest entities (“VIEs”), we are not the primary beneficiary of the VIEs for accounting purposes since we do not have the power to direct the operation of the VIEs and we do not have the obligation to absorb losses nor the right to receive benefits that could potentially be significant to the VIEs. As a result, we did not consolidate the Lessors in our consolidated financial statements. We have accounted for the Sale-Leaseback Transaction as a capital lease.

The following table includes our minimum annual rental payments using weighted-average effective interest rates of 5.2% for the Prospector 1 and 7.5% for the Prospector 5.



(In millions)	2016		2017		2018		2019		2020		Total
Minimum annual rental payments	$	51	$	41	$	33	$	31	$	175	$	331

We made rental payments, including interest, of approximately $26 million during the year ended December 31, 2015. This includes pre-payments or Excess Cash Amounts (as defined below) of $5 million and $7 million for the Prospector 1 and Prospector 5, respectively.

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Following the third and fourth anniversaries of the closing dates of the Lease Agreements, we have the option to repurchase each Rig for an amount as defined in the Lease Agreements. At the end of the lease term, we have an obligation to repurchase each Rig for a maximum amount of $88 million per Rig, less any pre-payments made by us during the term of the Lease Agreements.

The Lease Agreements obligate us to make certain termination payments upon the occurrence of certain events of default, including payment defaults, breaches of representations and warranties, termination of the underlying drilling contract for each Rig, covenant defaults, cross-payment defaults, certain events of bankruptcy, material judgments and actual or asserted failure of any credit document to be in force and effect. The Lease Agreements contain certain representations, warranties, obligations, conditions, indemnification provisions and termination provisions customary for sale and leaseback financing transactions. The Lease Agreements contain certain affirmative and negative covenants that, subject to exceptions, limit our ability to, among other things, incur additional indebtedness and guarantee indebtedness, pay dividends or make other distributions or repurchase or redeem capital stock, prepay, redeem or repurchase certain debt, make loans and investments, sell, transfer or otherwise dispose of certain assets, create or incur liens, enter into certain types of transactions with affiliates, consolidate, merge or sell all or substantially all of our assets, and enter into new lines of business. In addition, we will be required to maintain a cash reserve of $11.5 million for each Rig throughout the term of the Lease Agreements. During the term of the current drilling contract for each Rig, we will also be required to pay to the Lessors any excess cash amounts earned under such contract, after payment of bareboat charter fees and operating expenses for such Rig and maintenance of any mandatory reserve cash amounts (the “Excess Cash Amounts”), as prepayment for the remaining rental payments under the applicable Lease Agreement (the “Cash Sweep”). We had restricted cash balances of $25 million related to the Lease Agreements in “Other assets” on our Consolidated Balance Sheet as of December 31, 2015. Following the conclusion of the current drilling contract for each Rig, the Cash Sweep will be reduced, requiring us to make prepayments to the Lessors of up to 25% of the Excess Cash Amounts.

The sale-leaseback financing is not included in the PSA as the Prospector subsidiaries are not Debtors in the chapter 11 filing, but we are required to get a waiver from the Lessors to allow us to file without defaulting on the Lease Agreements.

Extinguished Obligations

At the time of our acquisition of Prospector, Prospector had the following outstanding debt instruments: (i) the Prospector Bonds and (ii) the Prospector Senior Credit Facility.

The Prospector Bonds were originally entered into by a subsidiary of Prospector on May 19, 2014 in the Oslo Alternative Bond Market. The Prospector Bonds had a fixed interest rate of 7.75% per annum, payable semi-annually on December 19 and June 19 each year and maturity of June 19, 2019. In January 2015, the bondholders put $99.6 million par value of their bonds back to us at the put price of 101% of par plus accrued interest pursuant to change of control provisions of the bonds. The remaining $0.4 million par value of the Prospector bonds outstanding was called and retired on March 26, 2015. We funded the repayment of the debt using borrowings from our Revolving Credit Facility and available cash.

The Prospector Senior Credit Facility was originally entered into by a subsidiary of Prospector on June 12, 2014 with a group of lenders. The Prospector Senior Credit Facility comprised a $140 million Prospector 5 tranche and a $130 million Prospector 1 tranche, which were both fully drawn at the time of acquisition. The Prospector Senior Credit Facility had an interest rate of LIBOR plus a margin of 3.5%. Prospector was required to hedge at least 50% of the Prospector Senior Credit Facility against fluctuations in the interest rate. Under the swaps, Prospector paid a fixed interest rate of 1.512% and received the three-month LIBOR rate. On March 16, 2015, the remaining principal balance outstanding under the Prospector Senior Credit Facility in the amount of approximately $261 million, including accrued interest, was paid in full through the use of cash on hand and borrowings under our Revolving Credit Facility, and all associated interest rate swaps were terminated. The related requirement for a fully funded debt service reserve account, classified as restricted cash on our Consolidated Balance Sheet as of December 31, 2014, was also released as a result of the payment in full on the Prospector Senior Credit Facility.

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NOTE 9—INCOME TAXES

Income before income taxes consists of the following:



	Year Ended December 31,
(In thousands)	2015			2014			2013
United States	$	(456,093	)	$	70,949		$	114,314
Non-U.S.	(615,627		)	(648,360		)	331,596
Total	$	(1,071,720	)	$	(577,411	)	$	445,910

The income tax provision/benefit consists of the following:



	Year Ended December 31,
(In thousands)	2015			2014			2013
Current - United States	$	(17,354	)	$	45,754		$	20,732
Current - Non-U.S.	7,116			43,115			55,691
Deferred - United States	(66,583		)	(30,391		)	13,425
Deferred - Non-U.S.	4,713			10,916			(4,243		)
Total	$	(72,108	)	$	69,394		$	85,605

Our annual effective tax rate for the year ended December 31, 2015 was approximately 6.7%, on a pre-tax loss of $1.1 billion. Changes in our effective tax rate from period to period is primarily attributable to changes in the profitability or loss mix of our operations in various jurisdictions. As our operations continually change among numerous jurisdictions, and methods of taxation in these jurisdictions vary greatly, there is little direct correlation between the income tax provision/benefit and income/loss before taxes. The Company is based in the U.K., which had a blended statutory income tax rate of 20.3% for 2015.

A reconciliation of the U.K. statutory tax rate to our effective rate is shown below:



	Year Ended December 31,
	2015		2014		2013
U.K. statutory income tax rate	20.3	%	21.5	%	23.3	%
Tax rates which are different from the U.K. rate	(4.8	)%	(36.8	)%	(5.9	)%
Tax effect of asset impairment	1.8	%	4.3	%	—	%
Change in valuation allowance	(11.1	)%	—	%	2.0	%
Adjustments to uncertain tax positions	0.5	%	(1.0	)%	(0.2	)%
Total	6.7	%	(12.0	)%	19.2	%

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The components of the net deferred taxes are as follows:



(In thousands)	2015			2014
Deferred tax assets
Deferred loss on asset dispositions	$	102,382		$	—
Accrued expenses not currently deductible	18,922			3,556
Net operating losses	17,901			22,645
Excess of tax basis over book basis of Property and Equipment	7,575			—
Bad debt	6,118			—
Other	7,152			—
Deferred tax assets	160,050			26,201
Less: Valuation allowance	(118,768		)	—
Net deferred tax assets	41,282			26,201
Deferred tax liabilities
Excess of net book basis over remaining tax basis of Property and equipment	(11,385		)	(58,844		)
Deferred taxes on unremitted earnings	(6,043		)	(6,043		)
Contract market valuation	(3,567		)	(5,434		)
Other	(2,421		)	(838		)
Deferred tax liabilities	(23,416		)	(71,159		)
Net deferred tax asset (liabilities)	$	17,866		$	(44,958	)

The deferred tax assets related to our net operating losses were generated in various tax jurisdictions worldwide, including $2.7 million that do not expire, $13.5 million and $1.7 million that will expire, if not utilized, in 2036 and 2021-2022, respectively. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if estimates of future taxable income change.

We conduct business globally and, as a result, we file numerous income tax returns, or are subject to withholding taxes, in various jurisdictions. In the normal course of business we are generally subject to examination by taxing authorities throughout the world. With few exceptions, we are no longer subject to examinations of tax matters for years prior to 1999.

The following is a reconciliation of the liabilities related to our unrecognized tax benefits, excluding interest and penalties:



(In thousands)	2015			2014			2013
Gross balance at January 1,	$	29,679		$	32,336		$	37,969
Additions based on tax positions related to the current year	—			4,442			532
Additions for tax positions of prior years	1,056			1,424			4,599
Reductions for tax positions of prior years	(4,966		)	(7,298		)	(214		)
Expiration of statutes	(221		)	(1,225		)	(2,712		)
Tax settlements	(15,122		)	—			(7,838		)
Gross balance at December 31,	10,426			29,679			32,336
Related tax benefits	—			—			(1,983		)
Net balance at December 31,	$	10,426		$	29,679		$	30,353

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The liabilities related to our unrecognized tax benefits comprise the following:



(In thousands)	2015		2014
Unrecognized tax benefits, excluding interest and penalties	$	10,426	$	29,679
Interest and penalties included in “Other liabilities”	8,079		10,517
Unrecognized tax benefits, including interest and penalties	$	18,505	$	40,196

We include, as a component of our income tax provision, potential interest and penalties related to liabilities for our unrecognized tax benefits within our global operations. Interest and penalties resulted in an income tax expense of $1 million, $2 million and $1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

At December 31, 2015, the liabilities related to our unrecognized tax benefits, including estimated accrued interest and penalties, totaled $19 million, and if recognized, would reduce our income tax provision by $19 million. At December 31, 2014, the liabilities related to our unrecognized tax benefits totaled $40 million. The decrease in unrecognized tax benefits is primarily attributable to the liability settlement of 2008-2011 for our U.K. operations upon receipt of the formal closure notices dated June 4, 2015 from HM Revenue & Customs. It is reasonably possible that our existing liabilities related to our unrecognized tax benefits may increase or decrease in the next twelve months primarily due to the progression of open audits or the expiration of statutes of limitation. However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties, such as the unresolved nature of various audits.

NOTE 10—GAIN ON CONTRACT SETTLEMENTS/EXTINGUISHMENT, NET

During the third quarter of 2013, Noble received $45 million related to the settlement of all claims against the former investors of FDR Holdings, Ltd., which Noble acquired in July 2010, relating to alleged breaches of various representations and warranties contained in the purchase agreement. A portion of the settlement related to standard specification rigs. This portion, totaling $23 million, was pushed down to our Predecessor in 2013, through an allocation, using the acquired rig values of the purchased rigs.

NOTE 11—EMPLOYEE BENEFIT PLANS

We have instituted competitive compensation policies and programs, as well as carried over certain plans as a standalone public company. During the periods prior to Spin-Off, most of our employees were eligible to participate in various Noble benefit programs. The results of our Predecessor in these consolidated and combined financial statements include an allocation of the costs of such employee benefit plans, which is consistent with the accounting for multi-employer plans. These costs were allocated based on our employee population for each of the periods presented. We consider the expense allocation methodology and results to be reasonable for all periods presented; however, the allocated costs included in the results of our Predecessor and included in these consolidated and combined financial statements may differ from compensation expense incurred by us as a standalone public company.

Defined Benefit Plans

At Spin-Off, Noble sponsored two non-U.S. noncontributory defined benefit pension plans, the Paragon Offshore Enterprise Ltd and the Paragon Offshore Nederland B.V. pension plans, which were carried over by us and cover certain Europe-based salaried, non-union employees.

For the years ended December 31, 2015 and 2014 pension benefit expense related to our defined benefit pension plans, based on actuary estimates, are presented in the table below.

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A reconciliation of the changes in projected benefit obligations (“PBO”) for our pension plans is as follows:



	Year Ended December 31,
(In thousands)	2015			2014
Benefit obligation at beginning of year	$	124,362		$	95,101
Service cost	5,375			4,819
Interest cost	1,946			2,601
Actuarial loss (gain)	(2,163		)	39,499
Amendments	—			(139		)
Benefits paid	(1,184		)	(1,240		)
Plan participants’ contribution	641			512
Foreign exchange rate changes	(12,909		)	(14,806		)
Other: curtailment	—			(1,985		)
Benefit obligation at end of year	$	116,068		$	124,362

A reconciliation of the changes in fair value of plan assets is as follows:



	Year Ended December 31,
(In thousands)	2015			2014
Fair value of plan assets at beginning of year	$	125,591		$	97,453
Actual return on plan assets	(1,790		)	38,252
Employer contribution	4,868			6,565
Benefits paid	(813		)	(833		)
Plan participants’ contributions	635			512
Expenses paid	(371		)	(407		)
Foreign exchange rate changes	(12,955		)	(15,951		)
Fair value of plan assets at end of year	$	115,165		$	125,591

The funded status of the plans is as follows:



	Year Ended December 31,
(In thousands)	2015			2014
Funded status	$	(903	)	$	1,229

Amounts recognized in the Consolidated Balance Sheets consist of:



	Year Ended December 31,
(In thousands)	2015			2014
Other assets - noncurrent	$	938		$	1,229
Other liability - noncurrent	(1,841		)	—
Net pension asset (liability)	(903		)	1,229
Accumulated other comprehensive loss recognized in financial statements	20,351			22,911
Net amount recognized	$	19,448		$	24,140

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Amounts recognized in AOCL consist of:



	Year Ended December 31,
(In thousands)	2015			2014
Net gain (loss)	$	(21,327	)	$	(21,924	)
Prior service (cost) credit	239			(2,048		)
Amortization of net actuarial gain (loss)	755			1,077
Amortization of prior service (cost) credit	(18		)	(16		)
Accumulated other comprehensive loss	$	(20,351	)	$	(22,911	)

The pension gains or losses and prior service costs or credits are recognized on a net-of-tax basis in AOCL and are amortized from AOCL to net periodic benefit cost over the expected average remaining working lives of the employees participating in the plan.

Pension cost includes the following components:



	Year Ended December 31,
(In thousands)	2015			2014
Service cost	$	5,375		$	4,819
Interest cost	1,946			2,601
Expected return on plan assets	(1,773		)	(2,625		)
Amortization of prior service cost	(18		)	(16		)
Amortization net actuarial loss (gain)	755			1,077
Net curtailment (gain)	—			(66		)
Net pension expense	$	6,285		$	5,790

Amortization related to prior service cost and net actuarial loss is estimated to be less than $0.1 million and $0.8 million, respectively, in 2016.

Defined Benefit Plans - Disaggregated Plan Information

Disaggregated information regarding our pension plans is summarized below:



	Year Ended December 31,
(In thousands)	2015		2014
Projected benefit obligation	$	116,068	$	124,362
Accumulated benefit obligation	111,366		119,632
Fair value of plan assets	115,165		125,591

Defined Benefit Plans - Key Assumptions

The key assumptions for the plans are summarized below:



	Year Ended December 31,
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost	2015		2014
Discount rate	2.6% to 2.9%		2.7% to 3.9%
Expected long-term return on plan assets	1.3	%	2.7% to 2.8%
Rate of compensation increase	3.6	%	3.6	%

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The discount rates used to calculate the net present value of future benefit obligations are determined by using a yield curve of high quality bond portfolios with an average maturity approximating that of the liabilities.

We employ third-party consultants who use a portfolio return model to assess the initial reasonableness of the expected long-term rate of return on plan assets. To develop the expected long-term rate of return on assets, we considered the current level of expected returns on risk free investments (primarily government bonds), the historical level of risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets for the portfolio.

Defined Benefit Plans - Plan Assets

Both the Paragon Offshore Enterprise Ltd and the Paragon Offshore Nederland B.V. pension plans have a targeted asset allocation of 100% debt securities. The investment objective for Paragon Offshore Enterprise Ltd and Paragon Offshore Nederland B.V. Non-US plans are to earn a favorable return against the Barclays Capital Euro - Treasury AAA 1 - 3 year benchmark. We evaluate the performance of these plans on an annual basis.

The actual fair value of our pension plans as of December 31, 2015 and 2014 is as follows:



			Estimated Fair Value Measurements
(In thousands)	Carrying Amount		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
December 31, 2015
Fixed Income securities:
Corporate Bonds	$	28,228	$	—	$	28,228	$	—
Other	86,937		—		—		86,937
Total	$	115,165	$	—	$	28,228	$	86,937

December 31, 2014
Fixed Income securities:
Corporate Bonds	$	32,476	$	—	$	32,476	$	—
Other	93,115		—		—		93,115
Total	$	125,591	$	—	$	32,476	$	93,115

At December 31, 2015, assets of Paragon Offshore Enterprise Ltd and Paragon Offshore Nederland B.V. were invested in instruments that are similar in form to a guaranteed insurance contract. There are no observable market values for the assets (Level 3); however, the amounts listed as plan assets were materially similar to the anticipated benefit obligations that were anticipated under the plans. The following table details the activity related to these investments during the year.



	Market Value
Balance as of December 31, 2013	$	68,280
Assets sold/benefits paid	(735		)
Return on plan assets	25,570
Balance as of December 31, 2014	93,115
Assets sold/benefits paid	$	(791	)
Return on plan assets	(5,387		)
Balance at December 31, 2015	$	86,937

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Defined Benefit Plans - Cash Flows

In 2015 and 2014, we made total contributions of $5 million and $7 million to our pension plans. We expect our aggregate minimum contributions to our plans in 2016, subject to applicable law, to be $8 million. We continue to monitor and evaluate funding options based upon market conditions and may increase contributions at our discretion.

The following table summarizes our benefit payments at December 31, 2015 estimated to be paid within the next ten years:



			Payments by Period
	Total		2016	2017	2018	2019	2020	Five Years Thereafter
Estimated benefit payments	$	19,209	891	1,047	1,247	1,451	1,651	12,922

Other Benefit Plans

We sponsor a 401(k) defined contribution plan and a profit sharing plan, which covers our employees who are not otherwise enrolled in the above defined benefit plans. Other post-retirement benefit expense related to these other benefit plans included in the accompanying Consolidated and Combined Statements of Operations for the years ended December 31, 2015 and 2014 were $1 million and $2 million, respectively.

NOTE 12—DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES

We have historically entered into derivative instruments to manage our exposure to fluctuations in foreign currency exchange rates, and we may conduct hedging activities in future periods to mitigate such exposure. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.

Cash Flow Hedges

We did not enter into any hedging activity during 2015. Depending on market conditions, we may elect to utilize short-term forward currency contracts in the future. During 2014, we entered into and settled forward contracts, expressed in U.S. dollars, of approximately $58 million all of which settled within 2014.

We had no outstanding derivative contracts and thus no unrealized gains recorded as a part of AOCL at December 31, 2015 or at December 31, 2014. See Note 15 - “Accumulated Other Comprehensive Loss” for changes in AOCL related to our cash flow hedges. Subsequent to the Spin-Off, total realized losses related to these forward contracts were $14 thousand and were classified as “Contract drilling services operating costs and expenses” on the consolidated and combined Statement of Operations for the year ended December 31, 2014. As of December 31, 2014, these forward contracts were designated as cash flow hedging instruments.

Prospector Interest Rate Swaps Acquired

The Prospector Senior Credit Facility exposed Prospector to short-term changes in market interest rates as interest obligations on these instruments were periodically redetermined based on the prevailing LIBOR rate. Upon our acquisition of Prospector, Prospector had interest rate swaps originally entered into by a subsidiary of Prospector with an aggregate maximum notional amount of $135 million. The interest rate swaps were entered into to reduce the variability of the cash interest payments under the Prospector Senior Credit Facility and to fix the interest on 50% of the outstanding borrowings under the Prospector Senior Credit Facility. Prospector received interest at three-month LIBOR and paid interest at a fixed rate of 1.512% over the expected term of the Prospector Senior Credit Facility

As of the first quarter of 2015, we had repaid in full the remaining principal balance outstanding under the Prospector Senior Credit Facility; therefore, in March 2015, the related interest rate swaps were terminated. The termination resulted in a settlement at fair market value plus accrued interest of approximately $1 million recorded in “Interest expense net of amount capitalized.” We did not apply hedge accounting with respect to these interest rate swaps and therefore, changes in fair values were recognized as either income or loss in our Consolidated and Combined Statements of Operations in “Interest expense, net of amount capitalized.” As of December 31, 2014, we had approximately $2 million recorded in “Other current liabilities” and approximately $1 million recorded in “Other long-term assets” related to the interest rate swaps (see Note 13 -“Fair Value of Financial Instruments”). Since these contracts were terminated prior to December 31, 2015, we had no amounts outstanding in our Consolidated Balance Sheets related to the interest rate swaps as of December 31, 2015.

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NOTE 13—FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair Value of Derivatives

We had no outstanding foreign currency forward contracts or interest rate swaps at December 31, 2015. As of December 31, 2014, the fair values of our interest rate swaps were determined based on a discounted cash flow model utilizing an appropriate market or risk-adjusted yield representative of Level 2 fair value measurements. The effects of discounting are immaterial for interest rate swaps. We recorded our interest rate swaps on our December 31, 2014 Consolidated Balance Sheet at fair value including $2 million in “Other current liabilities” and $1 million in “Other long-term assets.”

Fair Value of Debt

The following table presents the estimated fair value of our Senior Notes, Term Loan Facility and Prospector Bonds as of December 31, 2015 and 2014, respectively:



	December 31, 2015				December 31, 2014
(In thousands)	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
6.75% Senior Notes due July 15, 2022	$	456,572	$	65,062	$	457,572	$	275,115
7.25% Senior Notes due August 15, 2024	527,010		75,099		537,010		319,521
Total senior unsecured notes	$	983,582	$	140,161	$	994,582	$	594,636

Term Loan Facility, bearing interest at 3.75%, excluding unamortized discount of $2,554 and $3,018 for December 31, 2015 and December 31, 2014, respectively	$	641,875	$	235,889	$	648,375	$	523,250

Prospector 2019 Second Lien Callable Bond	$	—	$	—	$	101,000	$	101,000

The carrying amount of our variable-rate debt, the Revolving Credit Facility, approximates fair value as such debt bears short-term, market-based interest rates. We have classified this instrument as Level 2 as valuation inputs used for purposes of determining our fair value disclosure are readily available published LIBOR rates.

NOTE 14—CONCENTRATION OF MARKET AND CREDIT RISK

The market for our services is the offshore oil and gas industry, and our customers consist primarily of government-owned oil companies, major integrated oil companies and independent oil and gas producers. We perform ongoing credit evaluations of our customers and do not require material collateral. We maintain reserves for potential credit losses when necessary. Our results of operations and financial condition should be considered in light of the fluctuations in demand experienced by drilling contractors as changes in oil and gas producers’ expenditures and budgets occur. These fluctuations can impact our results of operations and financial condition as supply and demand factors directly affect utilization and dayrates, which are the primary determinants of our net cash provided by operating activities.

Revenues from Petrobras accounted for approximately 21%, 23%, and 17% of our operating revenues in 2015, 2014 and 2013, respectively. Receivables from Petrobras accounted for approximately 5% and 23% of our accounts receivable balance at December 31, 2015 and 2014, respectively. Revenues from Total S.A. accounted for approximately 16%, 3%, and 4% of our total operating revenues in 2015, 2014 and 2013, respectively. Receivables from Total S.A. accounted for approximately 12% and 7% of our accounts receivable balance at December 31, 2015 and 2014, respectively. Revenues from Pemex accounted for approximately 9%, 16%, and 19% of our operating revenues in 2015, 2014 and 2013 respectively. Receivables from Pemex accounted for approximately 26% and 31% of our accounts receivables balance at December 31, 2015 and 2014, respectively. No other customer accounted for more than 10% of our operating revenues in 2015, 2014 and 2013.

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NOTE 15—ACCUMULATED OTHER COMPREHENSIVE LOSS

The following table includes the components of AOCL for the years ended December 31, 2015, 2014 and 2013 and changes in AOCL by component for the years ended December 31, 2015 and 2014. All accounts within the tables are shown net of tax.



(In thousands)	Gains / (Losses) on Cash Flow Hedges (1)			Defined Benefit Pension Items (2)			Foreign Currency Items			Total
Balance at December 31, 2013	$	—		$	—		$	(6	)	$	(6	)
Activity during period:
AOCL recorded in connection with Spin-Off	4,027			(21,770		)	(12,706		)	(30,449		)
Other comprehensive loss before reclassification	(4,041		)	—			(1,481		)	(5,522		)
Amounts reclassified from AOCL	14			(1,141		)	—			(1,127		)
AOCL recorded in connection with Prospector Acquisition	—			—			(40		)	(40		)
Net other comprehensive income (loss)	—			(22,911		)	(14,227		)	(37,138		)
Balance at December 31, 2014	$	—		$	(22,911	)	$	(14,233	)	$	(37,144	)
Activity during period:
Other comprehensive loss before reclassification	—			1,823			(7,430		)	(5,607		)
Amounts reclassified from AOCL	—			737			—			737
Net other comprehensive income (loss)	—			2,560			(7,430		)	(4,870		)
Balance at December 31, 2015	$	—		$	(20,351	)	$	(21,663	)	$	(42,014	)


(1)	Gains / (losses) on cash flow hedges are related to our foreign currency forward contracts. Reclassifications from AOCL are recognized through “Contract drilling services operating costs and expenses” on our Consolidated and Combined Statements of Operations. See Note 12 - “Derivative Instruments and Hedging Activities” for additional information.

(2)

Defined benefit pension items relate to actuarial losses, prior service credits, and the amortization of actuarial losses and prior service credits. Reclassifications from AOCL are recognized as expense on our Consolidated and Combined Statements of Operations through either “Contract drilling services” or “General and administrative for the year ended December 31, 2015, see Note 11 - “Employee Benefit Plans” for additional information.

NOTE 16—COMMITMENTS AND CONTINGENCIES

Operating Leases

Future minimum lease payments for operating leases for years ending December 31 are as follows:



(in thousands)	2016		2017		2018		2019		2020		Thereafter		Total
Minimum lease payments	$	8,479	$	4,218	$	2,859	$	2,328	$	1,959	$	1,923	$	21,766

Total rent expense under operating leases was approximately $17 million and $16 million for the years ended December 31, 2015 and 2014, respectively.

Purchase Commitments

In connection with our capital expenditure program, we have outstanding commitments, including shipyard and purchase commitments of approximately $632 million at December 31, 2015. Our purchase commitments consist of obligations outstanding to external vendors primarily related to future capital purchases and includes $600 million due in 2016 related to the Three High-Spec Jackups Under Construction.

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Litigation

We are a defendant in certain claims and litigation arising out of operations in the ordinary course of business, the resolution of which, in the opinion of management, will not have a material adverse effect on our financial position, results of operations or cash flows. There is inherent risk in any litigation or dispute and no assurance can be given as to the outcome of these claims.

Other Contingencies

We operate in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. As of December 31, 2015, we have received tax audit claims of approximately $357 million, of which $81 million is subject to indemnity by Noble, primarily in Mexico and Brazil, attributable to our income, customs and other business taxes. In addition, as of December 31, 2015, approximately $34 million of tax audit claims in Mexico assessed against Noble are subject to indemnity by us as a result of the Spin-Off. We have contested, or intend to contest, these assessments, including through litigation if necessary. Tax authorities may issue additional assessments or pursue legal actions as a result of tax audits, and we cannot predict or provide assurance as to the ultimate outcome of such assessments and legal actions. In some cases, we will be required to post cash deposit as collateral while we defend these claims. We could be required to post such collateral in the near future, and such amounts could be substantial and could have a material adverse effect on our liquidity, financial condition, results of operations and cash flows. We have no surety bonds or letters of credit associated with tax audit claims outstanding as of December 31, 2015.

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 with Noble if Noble is ultimately determined to be liable for any amounts. We are presently unable to determine a timeline on this matter, nor are we able to determine the extent of our liability. We have considered this matter under ASC 460, Guarantees, and concluded that our liability under this matter is reasonably possible. Due to these current uncertainties, we are not able to reasonably estimate the magnitude of any liability at this time.

On February 11, 2016, as part of the PSA, we entered into the Term Sheet with Noble with respect to the Noble Settlement Agreement. Upon execution of the Noble Settlement Agreement, certain conditions of the Tax Sharing Agreement executed between Noble and Paragon for the Spin-Off will be modified. 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 were originally assigned to us by Noble pursuant to the Tax Sharing Agreement which was entered into in connection with the Spin-Off. The Company has contested or intends to contest the Mexico Tax Assessments and may be required to post bonds in connection thereto. As of December 31, 2015, our estimated Mexican Tax Assessments totaled approximately $200 million, with assessments for 2009 and 2010 yet to be received. Additionally, 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 following the defense of the Mexican Tax Assessments. 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. The Term Sheet has been approved by the boards of directors of both companies, but remains subject to execution of a definitive Noble Settlement Agreement and the approval of such agreement by the Bankruptcy Court in our chapter 11 proceedings. Upon the execution and approval by Bankruptcy Court of a final Noble Settlement Agreement, a material portion of our Mexican Tax Assessments, and any corresponding ultimate tax liability, will be assumed by Noble. Until such time, the current Tax Sharing Agreement remains in effect.

Petrobras has notified us, along with other industry participants that it is currently challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs for its operations in Brazil during the years 2008 and 2009 totaling $71 million, of which $20 million is subject to indemnity by Noble. Petrobras has also notified us that if they must pay such withholding taxes, they will seek reimbursement from us. We believe that we are contractually indemnified by Petrobras for these amounts and dispute the validity of the assessment. We have notified Petrobras of our position. We will, if necessary, vigorously defend our rights. If we were required to pay such reimbursement, however, the amount of such reimbursement could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.

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. Following the news reports relating to the agent’s involvement in the Brazil investigation in connection with his activities with other companies, we have been conducting an independent review of our

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relationship with the agent and with Petrobras. We have contacted the SEC and the U.S. Department of Justice to advise them of our internal review.

Insurance

In connection with the Separation on July 31, 2014, we replaced our Predecessor’s insurance policies, which were supported by Noble, with substantially similar standalone insurance policies. We maintain certain insurance coverage against specified marine perils, which include physical damage and loss of hire for certain units.

We maintain insurance in the geographic areas in which we operate, although pollution, reservoir damage and environmental risks generally are not fully insurable. Our insurance policies and contractual rights to indemnity may not adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet or named windstorm perils with respect to our rigs located in the U.S. Gulf of Mexico. Uninsured exposures may include expatriate activities prohibited by U.S. laws and regulations, radiation hazards, certain loss or damage to property on board our rigs and losses relating to shore-based terrorist acts or strikes. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could materially adversely affect our financial position, results of operations or cash flows. Additionally, there can be no assurance that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks.

Other

At December 31, 2015, we had letters of credit of $89 million and performance bonds totaling $115 million supported by surety bonds outstanding and backed by $75 million in letters of credit and a $9 million cash deposit. Certain of our subsidiaries issued guarantees to the temporary import status of rigs or equipment imported into certain countries in which we operated. These guarantees are issued in lieu of payment of custom, value added or similar taxes in those countries.

Separation Agreements

In connection with the Spin-Off, we entered into several definitive agreements with Noble or its subsidiaries that, among other things, set forth the terms and conditions of the Spin-Off and provide a framework for our relationship with Noble after the Spin-Off, including the following agreements:


•	Master Separation Agreement;


•	Tax Sharing Agreement;


•	Employee Matters Agreement;


•	Transition Services Agreement relating to services Noble and Paragon will provide to each other on an interim basis; and


•	Transition Services Agreement relating to Noble’s Brazil operations.

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Pursuant to these agreements with Noble, our Consolidated Balance Sheets include the following balances due from and to Noble as of December 31, 2015 and 2014:



	December 31,
(In thousands)	2015		2014
Accounts receivable	$	22,695	$	15,716
Other current assets	3,032		26,386
Other assets	6,686		6,875
Due from Noble	$	32,413	$	48,977

Accounts payable	$	211	$	1,655
Other current liabilities	6,067		51,169
Other liabilities	3,268		23,563
Due to Noble	$	9,546	$	76,387

These receivables and payables primarily relate to rights and obligations under the Master Separation, Tax Sharing Agreement and the Transition Services Agreement (Brazil).

Master Separation Agreement

We entered into the Master Separation Agreement with Noble Corporation, Noble-Cayman, which provided for, among other things, the Distribution of our ordinary shares to Noble shareholders and the transfer to us of the assets and the assumption by us of the liabilities relating to our business and the responsibility of Noble for liabilities related to Noble’s, and in certain limited cases, our business. The Master Separation Agreement identified which assets and liabilities constitute our business and which assets and liabilities constitute Noble’s business.

Tax Sharing Agreement

We entered into the Tax Sharing Agreement with Noble, which governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and certain other matters regarding taxes following the Distribution.

See discussion above on Term Sheet entered into with Noble with respect to the Noble Settlement Agreement. Upon the execution and approval by Bankruptcy Court of a final Noble Settlement Agreement, a material portion of our Mexican Tax Assessments, and any corresponding ultimate tax liability, will be assumed by Noble. Until such time, the current Tax Sharing Agreement remains in effect.

Employee Matters Agreement

We entered into an Employee Matters Agreement with Noble-Cayman to allocate liabilities and responsibilities relating to our employees and their participation in certain compensation and benefit plans maintained by Noble or a subsidiary of Noble. The Employee Matters Agreement provides that, following the Distribution, most of our employee benefits are provided under compensation and benefit plans adopted or assumed by us. In general, our plans are substantially similar to the plans of Noble or its subsidiaries that covered our employees prior to the completion of the Distribution. The Employee Matters Agreement also addresses the treatment of outstanding Noble equity awards held by transferring employees, including the grant of our equity awards or other rights with respect to Noble equity awards held by transferring employees that were canceled in connection with the Spin-Off.

Transition Services Agreement

We entered into a Transition Services Agreement with Noble-Cayman pursuant to which Noble-Cayman provides, on a transitional basis, certain administrative and other assistance, generally consistent with the services that Noble provided to us before the Separation, and we provide certain transition services to Noble and its subsidiaries. The charges for the transition services are generally intended to allow the party providing the services to fully recover the costs directly associated with providing the services, plus all out-of-pocket costs and expenses, generally without profit. The charges for each of the transition

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services generally are based on either a pre-determined flat fee or an allocation of the costs incurred, including certain fees and expenses of third-party service providers.

Transition Services Agreement (Brazil)

We and Noble-Cayman and certain other subsidiaries of Noble entered into a Transition Services Agreement (and a related rig charter) pursuant to which we provide certain transition services to Noble and its subsidiaries in connection with Noble’s Brazil operations. We continue to provide both rig-based and shore-based support services in respect of Noble’s remaining business through the term of Noble’s existing rig contracts. Noble currently has one rig operating in Brazil. Noble-Cayman compensates us on a cost-plus basis for providing such services and also indemnifies us for liabilities arising out of the services agreement. This agreement will terminate when the current Noble semisubmersible working in Brazil finishes its existing contract, which is expected to occur in 2016.

NOTE 17—RELATED PARTIES (INCLUDING RELATIONSHIP WITH NOBLE AND CORPORATE ALLOCATIONS)

For all periods prior to the Spin-Off, our Predecessor was managed in the normal course of business by Noble and its subsidiaries. Accordingly, certain shared costs have been allocated to our Predecessor and are reflected as expenses in these unaudited consolidated and combined financial statements for periods prior to Spin-Off. Our management considers the allocation methodologies used to be reasonable and appropriate reflections of the related expenses attributable to us for purposes of the carve-out financial statements; however, the expenses reflected in the results of our Predecessor and included in these consolidated and combined financial statements may not be indicative of the actual expenses that would have been incurred during the periods presented if our Predecessor had operated as a separate standalone entity.

Allocated costs include, but are not limited to: corporate accounting, human resources, information technology, treasury, legal, employee benefits and incentives (excluding allocated post-retirement benefits described in Note 11 - “Employee Benefit Plans”) and stock-based compensation. Our Predecessor’s allocated costs included in contract drilling services in the accompanying Consolidated and Combined Statements of Operations totaled $70 million and $147 million for the years ended December 31, 2014 and 2013, respectively. Our Predecessor’s allocated costs included in general, and administrative expenses in the accompanying Consolidated and Combined Statements of Operations totaled $25 million and $58 million for the years ended December 31, 2014 and 2013 respectively. The costs were allocated to our Predecessor using various inputs, such as head count, services rendered, and assets assigned to our Predecessor. All financial information presented after the Spin-Off represents the results of operations, financial position and cash flows of Paragon, accordingly, no Predecessor allocated costs are included in the accompanying Consolidated Statements of Operations for the year ended December 31, 2015.

NOTE 18—SUPPLEMENTAL CASH FLOW INFORMATION

The net effect of changes in other assets and liabilities on cash flows from operating activities is as follows:



	Year Ended December 31,
(In thousands)	2015			2014			2013
Accounts receivable	$	233,812		$	(178,108	)	$	(34,582	)
Other current assets	(5,383		)	42,922			22,181
Other assets	(479		)	(33,637		)	16,451
Accounts payable	(57,246		)	25,890			8,530
Other current liabilities	(132,195		)	14,273			18,645
Other liabilities	(51,790		)	(29,514		)	(16,385		)
Net change in other assets and liabilities	$	(13,281	)	$	(158,174	)	$	14,840

Additional cash flow information is as follows:

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	Year Ended December 31,
(In thousands)	2015		2014		2013
Cash paid during the period for:
Interest	$	124,763	$	21,109	$	5,791
U.S. and Non-U.S. income taxes	66,657		85,248		76,423
Supplemental information for non-cash activities:
Assets related to Sale-Leaseback Transaction	$	465,043	$	—	$	—
Adjustments to distributions by former parent	9,493		—		—
Accrued capital expenditures	10,305		24,003		—
Transfer from parent of property and equipment	—		18,124		16,057

NOTE 19—SEGMENT AND RELATED INFORMATION

At December 31, 2015, our contract drilling operations were reported as a single reportable segment, Contract Drilling Services, which reflects how our business is managed, and the fact that all of our drilling fleet is dependent upon the worldwide oil industry. The mobile offshore drilling units that comprise our offshore rig fleet operated in a single, global market for contract drilling services and are often redeployed globally due to changing demands of our customers, which consisted largely of major non-U.S. and government owned/controlled oil and gas companies throughout the world. Our contract drilling services segment conducts contract drilling operations in Mexico, Brazil, the North Sea, West Africa, the Middle East, and India.

Operations by Geographic Area

The following table presents revenues and identifiable assets by country based on the location of the service provided:



	Revenues						Identifiable Assets
	Year Ended December 31,						As of December 31,
(In thousands)	2015		2014		2013		2015		2014
Country:
Brazil	$	368,502	$	488,884	$	312,287	$	169,626	$	1,821,017
United Kingdom	305,499		193,908		245,789		1,122,653		85,638
The Netherlands	242,128		284,651		179,768		252,686		163,153
United Arab Emirates	135,747		139,318		108,256		229,351		219,711
Mexico	133,970		326,352		367,732		183,944		459,975
India	71,743		79,201		103,282		102,054		131,431
Cameroon	70,901		35,224		55,803		100,828		95,036
Qatar	36,234		94,320		139,891		25,844		93,625
USA	340		85,060		117,951		158,146		91,921
Nigeria	—		—		107,750		6,697		11,281
Other	127,364		266,844		154,493		32,036		80,601
	$	1,492,428	$	1,993,762	$	1,893,002	$	2,383,865	$	3,253,389

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NOTE 20—UNAUDITED INTERIM FINANCIAL DATA

Summarized quarterly results for years ended December 31, 2015 and 2014 are as follows:



	Quarter Ended
(In thousands, except per share amounts)	March 31		June 30		September 30			December 31
2015
Operating revenues	$	430,648	$	393,244	$	368,973		$	299,563
Operating income (loss)	95,653		57,727		(1,105,344		)	10,590
Net income (loss) attributable to Paragon Offshore	61,127		47,331		(1,084,838		)	(23,263		)	(2)
Earnings (loss) per share - basic and diluted (1)	0.69		0.51		(12.46		)	(0.27		)	(2)

2014
Operating revenues	$	514,590	$	478,957	$	505,222		$	494,993
Operating income (loss)	147,461		119,972		(796,421		)	4,311
Net income (loss) attributable to Paragon Offshore	124,566		95,045		(869,160		)	2,744
Earnings (loss) per share - basic and diluted (1)	$	1.47	$	1.12	$	(10.26	)	$	0.03


(1)	Earnings (loss) per share is computed independently for each of the quarters presented. Therefore, the sum of the quarters’ net income per share may not equal the total computed for the year.


(2)	Certain corrections of errors related to overaccrual of expenses for prior periods, and having net positive impacts of approximately $10.2 million to net income, were recorded during the three months ended December 31, 2015. We consider these errors to be immaterial to 2015 and all prior periods.


ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A.	CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Randall D. Stilley, President, Chief Executive Officer, and Director of Paragon, and Steven A. Manz, Senior Vice President and Chief Financial Officer of Paragon, with the participation of our management, have evaluated the disclosure controls and procedures of Paragon as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on their evaluation as of December 31, 2015, our Chief Executive Officer and Chief Financial Officer have concluded that the Company’s “disclosure controls and procedures” (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934) were effective at the reasonable assurance level.

Previously Identified Material Weakness and Its Remediation

As first disclosed in the 2014 Form 10-K (filed on March 13, 2015), our management concluded that we had a material weakness in our internal control over financial reporting related to a lack of segregation of duties in the recording of manual journal entries. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

As previously disclosed, the company has made changes to its internal controls over financial reporting to remediate the material weakness reported in 2014 Form 10-K for the year ended December 31, 2014.

After completing our testing of the design and operational effectiveness of these controls, our management concluded that we have remediated the material weakness as of December 31, 2015.

Management’s Report on Internal Control Over Financial Reporting

Our management, including the Chief Executive Officer and the Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rule 13a-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:


•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;


•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorization of our management and directors; and


•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

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

Under the supervision and with the participation of management, including the Company’s Chief Executive Officer and Chief Financial Officer, the Company conducted an evaluation on the effectiveness of its internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2015.

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Our independent registered public accounting firm, PricewaterhouseCoopers LLP, has audited the effectiveness of our internal control over financial reporting as of December 31, 2015. Their report is included in Item 8 of this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2015, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


ITEM 9B.	OTHER INFORMATION

None.

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PART III


ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The sections entitled “Election of Directors”, “Additional Information Regarding the Board of Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, and “Other Matters” appearing in the proxy statement for the 2016 annual general meeting of shareholders (the “2016 Proxy Statement”), will set forth certain information with respect to directors, certain corporate governance matters and reporting under Section 16(a) of the Securities Exchange Act of 1934, and are incorporated in this report by reference.

Executive Officers of the Registrant

The following table sets for certain information as of March 1, 2016 with respect to our executive officers:



Name	Age	Position
Randall D. Stilley	62	President, Chief Executive Officer and Director
Steven A. Manz	50	Senior Vice President and Chief Financial Officer
William C. Yester	65	Senior Vice President - Operations
Lee M. Ahlstrom	48	Senior Vice President - Investor Relations, Strategy, and Planning
Andrew W. Tietz	49	Senior Vice President - Marketing and Contracts
Anirudha Pangarkar	54	Senior Vice President - Special Projects, Supply Chain and Maintenance
Todd D. Strickler	38	Vice President - General Counsel and Corporate Secretary
Julie A. Ferro	44	Vice President - Human Resources
Alejandra Veltmann	47	Vice President - Chief Accounting Officer

Randall D. Stilley was named President and Chief Executive Officer effective August 1, 2014. Mr. Stilley served as Executive Vice President of Noble Drilling Services, Inc from February 2014 to July 2014. From May 2011 to February 2014, Mr. Stilley served as an independent business consultant and managed private investments. Mr. Stilley served as President and Chief Executive Officer of Seahawk Drilling, Inc. from August 2009 to May 2011 and Chief Executive Officer of the mat-supported jackup rig business at Pride International Inc. from September 2008 to August 2009. Seahawk Drilling filed for reorganization under chapter 11 of the United States Bankruptcy Code in 2011. From October 2004 to June 2008, Mr. Stilley served as President and Chief Executive Officer of Hercules Offshore, Inc. Prior to that, Mr. Stilley was Chief Executive Officer of Seitel, Inc., an oilfield services company, President of the Oilfield Services Division at Weatherford International, Inc., and served in a variety of positions at Halliburton Company. He is a registered professional engineer in the State of Texas and a member of the Society of Petroleum Engineers. Mr. Stilley holds a Bachelor of Science degree in Aerospace Engineering from the University of Texas at Austin.

Steven A. Manz was named Senior Vice President and Chief Financial Officer effective August 1, 2014. Mr. Manz has more than 25 years of experience in the offshore drilling and financial services industries. From 1995 to 2005, Mr. Manz served in a variety of management roles at Noble Corporation, including Managing Director, Noble Technology Services Division, Vice President of Strategic Planning, and Director of Accounting and Investor Relations. Most recently Mr. Manz served at Prospector Offshore Drilling S.A., Seahawk Drilling, Inc. and Hercules Offshore, Inc., where he held the position of Chief Financial Officer of each company. Mr. Manz holds a Bachelor of Business Administration degree in Finance from the University of Texas at Austin.

William C. Yester was named Senior Vice President of Operations effective August 1, 2014. Mr. Yester has more than 40 years of experience in the drilling business, with more than 22 years in offshore operations, and has been employed with Noble in a number of operational roles since 1996. He has served most recently as Vice President –Division Manager (Africa) and prior to that, Vice President – Division Manager (Middle East and India). Mr. Yester began his career with Noble in 1974, and from 1990 to 1994 served as a Division Manager with Helmerich and Payne International Drilling Company. In 1994-1995 he held a number of operational roles with Triton Engineering Company before returning to Noble in 1995. Mr. Yester holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.

Lee M. Ahlstrom was named Senior Vice President of Investor Relations, Strategy and Planning effective August 1, 2014. Mr. Ahlstrom has more than 20 years of experience in the oil and gas industry. He has served as Senior Vice President – Strategic Development of Noble since May 2011 and was Vice President of Investor Relations and Planning of Noble from May 2006 to

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May 2011. Prior to joining Noble, Mr. Ahlstrom served as Director of Investor Relations at Burlington Resources, held various management positions at UNOCAL Corporation and served as an Engagement Manager with McKinsey & Company. Mr. Ahlstrom began his career with Exxon, where he held a variety of surface and subsurface engineering positions. He holds Bachelor of Science and Master’s degrees in Mechanical Engineering from the University of Delaware.

Andrew W. Tietz was named Senior Vice President of Marketing and Contracts effective August 1, 2014. Mr. Tietz has more than 20 years of experience in the offshore drilling industry. He has served as Vice President – Marketing and Contracts of Noble since May 2010 and was Director – Marketing and Contracts from December 2009 to April 2010. Prior to joining Noble, Mr. Tietz served as Director – Marketing and Business Development for Transocean Ltd. He served in various marketing and finance positions with Transocean and GlobalSantaFe and Global Marine, prior to their mergers with Transocean, including positions in Dubai, Egypt and Kuala Lumpur. Mr. Tietz holds a Bachelor of Science-Finance degree from the University of Colorado – Boulder and a Master of Business Administration degree from the University of St. Thomas.

Anirudha Pangarkar was named Senior Vice President - Special Projects, Supply Chain and Maintenance effective August 1, 2015. Mr. Pangarkar has more than 30 years of experience in the offshore drilling industry. He joined Paragon Offshore in January 2015 following the acquisition of Prospector Offshore, where he had been Vice President of Operations since co-founding the company in 2009. Prior to that, he served as Vice President of Operations at Premium Drilling, Inc. from 2005 to 2009 where he directed operations for 13 jackup rigs. Before joining Premium Drilling, Mr. Pangarkar was General Manager of Schlumberger Drilling Services where he managed business for 37 drilling rigs across eight countries. Mr. Pangarkar holds a Bachelor of Science degree in Mechanical Engineering from M.S. University, India and a Master of Business Administration from MIT Sloan School of Management.

Todd D. Strickler was named Vice President, General Counsel and Corporate Secretary effective August 1, 2014. Mr. Strickler has more than 15 years of experience in the offshore and legal services industries. He has served as Associate General Counsel – Corporate of Noble since January 2013 and was Senior Counsel for Noble since February 2009. Prior to his joining Noble, he specialized in corporate and securities law at the law firm of Andrews Kurth LLP. Mr. Strickler holds a Bachelor of Science degree in Mechanical Engineering from the University of Texas at Austin and a Juris Doctorate from the University of Texas School of Law.

Julie A. Ferro was named Vice President of Human Resources effective January 12, 2015. Ms. Ferro has more than 20 years of human resources experience working for both public and private companies in the energy and commercial real estate industries including her most recent role as Vice President of Human Resources at Endeavour International Corporation. She also spent three years as a Managing Director for a leading compensation consulting firm in Houston. Ms. Ferro has a Bachelor of Arts degree from the University of Houston, and holds the Certified Compensation Professional (CCP), Certified Executive Compensation Professional (CECP), Certified Equity Professional (CEP), Professional in Human Resources (PHR), and SHRM-CP designations.

Alejandra Veltmann was named Vice President - Chief Accounting Officer effective June 1, 2015. Ms. Veltmann previously served as Vice President and Chief Accounting Officer at Geokinetics Inc. from December 2012 to May 2015, and Corporate Controller from May 2011 to November 2012. Ms. Veltmann has over 23 years of experience in financial management roles for public and private companies in the energy, financial services, and manufacturing industries, including consulting in the role of CFO for entrepreneurial companies. Ms. Veltmann served as senior manager for KPMG and is a certified public accountant. Ms. Veltmann holds a BBA degree in Accounting from The University of New Mexico.

ITEM 11. EXECUTIVE COMPENSATION

The sections entitled “Executive Compensation” and “Compensation Committee Report” appearing in the 2016 Proxy Statement set forth certain information with respect to the compensation of our management and our compensation committee report, and are incorporated in this report by reference.


ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS

The sections entitled “Equity Compensation Plan Information” and “Security Ownership of Certain Beneficial Owners and Management” appearing in the 2016 Proxy Statement set forth certain information with respect to securities authorized for issuance under equity compensation plans and the ownership of our voting securities and equity securities, and are incorporated in this report by reference.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The sections entitled “Additional Information Regarding the Board of Directors—Board Independence” and “Policies and Procedures Relating to Transactions with Related Persons” appearing in the 2016 Proxy Statement set forth certain information with respect to director independence and transactions with related persons, and are incorporated in this report by reference.

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ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

The section entitled “Auditors” appearing in the 2016 Proxy Statement includes certain information with respect to accounting fees and services, and is incorporated in this report by reference.

PART IV


ITEM 15.	EXHIBITS AND FINANCIAL STATEMENTS


(1)	Financial Statements –

Our Consolidated and Combined Financial Statements, together with the notes thereto and the report of PricewaterhouseCoopers LLP dated March 11, 2016, was included in Item 8 of this Form 10-K.


(2)	Financial Statement Schedules –

All financial statement schedules have been omitted because they are not applicable or not required, the information is not significant, or the information is presented elsewhere in the financial statements.


(3)	Exhibits –

The information required by this Item 15(a)(3) is set forth in the Index to Exhibits accompanying this Annual Report on Form 10-K and is incorporated herein by reference.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Paragon Offshore plc, a company registered under the laws of England and Wales



Date:	March 11, 2016	By:	/s/ Randall D. Stilley
			Randall D. Stilley
			President, Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.



Signature	Capacity In Which Signed	Date

/s/ Randall D. Stilley	President, Chief Executive Officer and Director	March 11, 2016
Randall D. Stilley	(Principal Executive Officer)

/s/ Steven A. Manz	Senior Vice President and Chief Financial Officer	March 11, 2016
Steven A. Manz	(Principal Financial Officer)

/s/ Alejandra Veltmann	Vice President and Chief Accounting Officer	March 11, 2016
Alejandra Veltmann	(Principal Accounting Officer)

/s/ J. Robinson West	Director	March 11, 2016
J. Robinson West

/s/ Anthony R. Chase	Director	March 11, 2016
Anthony R. Chase

/s/ Thomas L. Kelly II	Director	March 11, 2016
Thomas L. Kelly II

/s/ John P. Reddy	Director	March 11, 2016
John P. Reddy

/s/ Dean E. Taylor	Director	March 11, 2016
Dean E. Taylor

/s/ William L. Transier	Director	March 11, 2016
William L. Transier

/s/ David W. Wehlmann	Director	March 11, 2016
David W. Wehlmann

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Index to Exhibits



Number		Description
2.1		Master Separation Agreement, dated as of July 31, 2014, between Noble Corporation and Paragon Offshore plc (incorporated by reference to Exhibit 2.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
3.1		Articles of Association of Paragon Offshore plc (incorporated by reference to Exhibit 3.1 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
4.1		Senior Secured Revolving Credit Agreement dated as of June 17, 2014 among Paragon Offshore Limited, Paragon International Finance Company, the Lenders from time to time parties thereto; JPMorgan Chase Bank, N.A., as Administrative Agent, Swingline Lender and an Issuing Bank; Deutsche Bank Securities Inc. and Barclays Bank PLC, as Syndication Agents; and J.P. Morgan Securities LLC, Deutsche Bank Securities Inc. and Barclays Bank PLC, as Joint Lead Arrangers and Joint Lead Bookrunners (incorporated by reference to Exhibit 4.1 to Paragon Offshore Limited’s Registration Statement on Form 10 filed on July 3, 2014).
4.2		Indenture, dated as of July 18, 2014, by and among Paragon Offshore plc, the guarantors listed therein, Deutsche Bank Trust Company Americas, as trustee, and Deutsche Bank Luxembourg S.A., as paying agent and transfer agent (incorporated by reference to Exhibit 4.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on July 22, 2014).
4.3		Senior Secured Term Loan Credit Agreement, dated as of July 18, 2014, by and among Paragon Offshore plc, as parent guarantor, Paragon Offshore Finance Company, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 4.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on July 22, 2014).
10.1		Tax Sharing Agreement, dated as of July 31, 2014, between Noble Corporation plc and Paragon Offshore plc (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.2		Employee Matters Agreement, dated as of July 31, 2014, between Noble Corporation and Paragon Offshore plc (incorporated by reference to Exhibit 10.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.3		Transition Services Agreement, dated as of July 31, 2014, between Noble Corporation and Paragon Offshore plc (incorporated by reference to Exhibit 10.3 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.4		Transition Services Agreement (Brazil), dated as of July 31, 2014, among Paragon Offshore do Brasil Limitada, Paragon Offshore (Nederland) B.V., Paragon Offshore plc, Noble Corporation, Noble Dave Beard Limited and Noble Drilling (Nederland) II B.V. (incorporated by reference to Exhibit 10.4 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.5†		Paragon Offshore plc 2014 Employee Omnibus Incentive Plan (incorporated by reference to Exhibit 10.5 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.6†		Paragon Offshore plc 2014 Director Omnibus Plan (incorporated by reference to Exhibit 10.6 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.7†		Paragon Grandfathered 401(k) Savings Restoration Plan (incorporated by reference to Exhibit 10.7 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.8†		Paragon 401(k) Savings Restoration Plan (incorporated by reference to Exhibit 10.8 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.9†		Form of Deeds of Indemnity between Paragon Offshore plc and certain directors and officers (incorporated by reference to Exhibit 10.9 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 5, 2014).
10.10†		Paragon Offshore Services LLC 2014 Short-Term Incentive Program (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 18, 2014).
10.11†		Form of Change of Control Agreement between Paragon Offshore plc and certain officers thereof (incorporated by reference to Exhibit 10.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on August 18, 2014).
10.12†		Form of Performance Vested Restricted Stock Unit Replacement Award Agreement (incorporated by reference to Exhibit 10.12 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
10.13†		Form of Time Vested Restricted Stock Unit Replacement Award Agreement (incorporated by reference to Exhibit 10.13 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
10.14†		Form of Employee Time Vested Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.14 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
10.15†		Form of Director Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.15 to Paragon Offshore plc’s Quarterly Report on Form 10-Q filed on August 29, 2014).
10.16		Form of Share Purchase Agreement, dated November 17, 2014, between Paragon Offshore plc and each seller party thereto (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on November 19, 2014).
10.17†		Paragon Offshore Executive Bonus Plan, dated February 19, 2015 (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on February 25, 2015).
10.18†		Form of Time Vested Stock Unit Award Agreement, dated February 19, 2015 (incorporated by reference to Exhibit 10.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on February 25, 2015).
10.19†		Form of Performance Vested Restricted Stock Unit Award Agreement, dated February 19, 2015 (incorporated by reference to Exhibit 10.3 to Paragon Offshore plc’s Current Report on Form 8-K filed on February 25, 2015).
10.20†		Paragon Offshore plc 2014 Employee Omnibus Incentive Plan (Amended and Restated) (Filed as Annex A to Paragon Offshore plc’s Definitive Proxy Statement on Schedule 14A filed with the Commission on March 20, 2015).
10.21†		Paragon Offshore plc 2014 Director Omnibus Plan (Amended and Restated) (Filed as Annex B to Paragon Offshore plc’s Definitive Proxy Statement on Schedule 14A filed with the Commission on March 20, 2015).
10.22		Lease Agreement in Respect of Prospector 1 dated June 3, 2015, by and between Prospector One Corporation, as Lessor, and Prospector Rig 1 Contracting Company S.à r.l., as Lessee (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on June 5, 2015).
10.23		Lease Agreement in Respect of Prospector 5 dated June 3, 2015, by and between Prospector Five Corporation, as Lessor, and Prospector Rig 5 Contracting Company S.à r.l., as Lessee (incorporated by reference to Exhibit 10.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on June 5, 2015).
10.24†		Form of Key Employee Retention Plan Agreement (incorporated by reference to Exhibit 10.1 to Paragon Offshore plc’s Current Report on Form 8-K filed on October 30, 2015).
10.25		Term Sheet Regarding Noble Settlement, dated February 11, 2016 (incorporated by reference to Exhibit 99.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on February 12, 2016).
10.26		Plan Support Agreement, dated February 12, 2016 (incorporated by reference to Exhibit 99.2 to Paragon Offshore plc’s Current Report on Form 8-K filed on February 16, 2016).
21.1*		List of Subsidiaries of Paragon Offshore plc.
23.1*		Consent of Independent Registered Public Accounting Firm
31.1*		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document
101.SC*		XBRL Schema Document
101.CA*		XBRL Calculation Linkbase Document
101.DE*		XBRL Definition Linkbase Document
101.LA*		XBRL Label Linkbase Document
101.PR*		XBRL Presentation Linkbase Document


*	Filed herewith.


**	Furnished herewith.


†	Management contract or compensatory plan or arrangement.

113

(In shares)

Employee Plan

Director Plan

Shares available for future awards or grants

Outstanding unvested restricted stock units