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Form 10-Q PARAGON OFFSHORE PLC For: Sep 30

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November 9, 2015 5:04 PM EST

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

FORM 10-Q
________________________________________________________
x    
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 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
001-36465
98-1146017
(State or other jurisdiction of
incorporation or organization)
(Commission
file number)
(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
______________________________________________________
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 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

Number of shares outstanding and trading at October 30, 2015: 86,026,247
 
 


PARAGON OFFSHORE plc
FORM 10-Q
For the Quarter Ended September 30, 2015
TABLE OF CONTENTS
 
 
 
 
 
PAGE
 
 
 
 
 
 
 
 
 
 
 
 
 


2

PART I.
FINANCIAL INFORMATION
ITEM 1.
UNAUDITED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
PARAGON OFFSHORE plc
CONSOLIDATED AND COMBINED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
September 30,
 
2015
 
2014
2015
 
2014
Operating revenues
 
 
 
 
 
 
 
 
Contract drilling services
 
$
338,710

 
$
456,174

 
$
1,101,618

 
$
1,410,471

Labor contract drilling services
 
6,853

 
8,562

 
21,224

 
24,919

Reimbursables and other
 
23,410

 
40,486

 
70,023

 
63,379

 
 
368,973

 
505,222

 
1,192,865

 
1,498,769

Operating costs and expenses
 
 
 
 
 
 
 
 
Contract drilling services
 
190,536

 
217,378

 
612,610

 
666,158

Labor contract drilling services
 
4,792

 
6,593

 
16,086

 
19,029

Reimbursables
 
19,517

 
35,592

 
58,173

 
51,442

Depreciation and amortization
 
95,826

 
108,027

 
280,574

 
331,147

General and administrative
 
12,800

 
12,037

 
41,901

 
37,965

Loss on impairments
 
1,150,846

 
928,947

 
1,152,547

 
928,947

Gain on disposal of assets, net
 
—

 
—

 
(12,717
)
 
—

Gain on repurchase of long-term debt
 
—

 
(6,931
)
 
(4,345
)
 
(6,931
)
 
 
1,474,317

 
1,301,643

 
2,144,829

 
2,027,757

Operating loss
 
(1,105,344
)
 
(796,421
)
 
(951,964
)
 
(528,988
)
Other income (expense)
 
 
 
 
 
 
 
 
Interest expense, net of amount capitalized
 
(33,900
)
 
(22,453
)
 
(93,107
)
 
(28,690
)
Other, net
 
(983
)
 
340

 
1,421

 
830

Loss before income taxes
 
(1,140,227
)
 
(818,534
)
 
(1,043,650
)
 
(556,848
)
Income tax benefit (provision)
 
55,389

 
(50,626
)
 
67,301

 
(92,701
)
Net loss
 
$
(1,084,838
)
 
$
(869,160
)
 
$
(976,349
)
 
$
(649,549
)
Net income attributable to non-controlling interest
 
—

 
—

 
(31
)
 
—

Net loss attributable to Paragon
 
$
(1,084,838
)
 
$
(869,160
)
 
$
(976,380
)
 
$
(649,549
)
 
 
 
 
 
 
 
 
 
Loss per share
 
 
 
 
 
 
 
 
Basic and diluted
 
$
(12.46
)
 
$
(10.26
)
 
$
(11.39
)
 
$
(7.66
)
 
 
 
 
 
 
 
 
 
Weighted-average shares outstanding
 
 
 
 
 
 
 
 
Basic and diluted
 
87,077

 
84,753

 
85,703


84,753

See accompanying notes to the unaudited consolidated and combined financial statements.

3

PARAGON OFFSHORE plc
CONSOLIDATED AND COMBINED STATEMENTS OF COMPREHENSIVE LOSS
(In thousands)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
September 30,
September 30,
 
2015
 
2014
2015
 
2014
Net loss
 
$
(1,084,838
)
 
$
(869,160
)
 
$
(976,349
)
 
$
(649,549
)
Other comprehensive income (loss), net of tax
 
 
 
 
 
 
 
 
Foreign currency translation adjustments
 
(5,145
)
 
(1,854
)
 
(6,818
)
 
(1,827
)
Foreign currency forward contracts
 
—

 
(3,073
)
 
—

 
(3,073
)
Amortization of net actuarial loss
 
195

 
—

 
584

 
—

Amortization of prior service cost
 
(5
)
 
—

 
(14
)
 
—

Total other comprehensive loss, net
 
(4,955
)
 
(4,927
)
 
(6,248
)
 
(4,900
)
Total comprehensive loss
 
$
(1,089,793
)
 
$
(874,087
)
 
$
(982,597
)
 
$
(654,449
)
See accompanying notes to the unaudited consolidated and combined financial statements.

4

PARAGON OFFSHORE plc
CONSOLIDATED BALANCE SHEETS
(In thousands)
(Unaudited)
 
 
September 30,
 
December 31,
 
 
2015
 
2014
ASSETS
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
732,960

 
$
56,772

Restricted cash
 
3,000

 
12,502

Accounts receivable, net of allowance for doubtful accounts (Note 3)
 
335,132

 
539,376

Prepaid and other current assets
 
106,355

 
104,644

Total current assets
 
1,177,447

 
713,294

Property and equipment, at cost
 
2,641,058

 
4,842,112

Accumulated depreciation
 
(1,488,992
)
 
(2,431,752
)
Property and equipment, net
 
1,152,066

 
2,410,360

Other assets
 
145,114

 
129,735

Total assets
 
$
2,474,627

 
$
3,253,389

 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
Current liabilities
 
 
 
 
Current maturities of long-term debt
 
$
40,990

 
$
272,166

Accounts payable
 
122,269

 
160,874

Accrued payroll and related costs
 
51,438

 
81,416

Taxes payable
 
48,644

 
69,033

Interest payable
 
13,579

 
33,658

Other current liabilities
 
71,709

 
105,147

Total current liabilities
 
348,629

 
722,294

Long-term debt
 
2,569,435

 
1,888,439

Deferred income taxes
 
9,585

 
58,497

Other liabilities
 
34,981

 
89,910

Total liabilities
 
2,962,630

 
2,759,140

Commitments and contingencies (Note 15)
 

 

Equity
 
 
 
 
Ordinary shares, $0.01 par value, 186,457,393 shares authorized; with 86,026,247 and
84,753,393 issued and outstanding at September 30, 2015 and December 31, 2014, respectively
 
860

 
848

Additional paid-in capital
 
1,426,158

 
1,423,153

Accumulated deficit
 
(1,871,629
)
 
(895,249
)
Accumulated other comprehensive loss
 
(43,392
)
 
(37,144
)
Total shareholders’ equity (deficit)
 
(488,003
)
 
491,608

Non-controlling interest
 
—

 
2,641

              Total equity (deficit)
 
(488,003
)
 
494,249

              Total liabilities and equity
 
$
2,474,627

 
$
3,253,389

See accompanying notes to the unaudited consolidated and combined financial statements.

5

PARAGON OFFSHORE plc
CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY
(In thousands)
(Unaudited)
 
Ordinary Shares
 
Additional Paid-in Capital
 
Accumulated Deficit
 
Accumulated Other Comprehensive Loss
 
Net Parent Investment
 
Total Stockholders’ Equity and Net Parent Investment
 
Non-Controlling
Interest
 
Total
Equity (Deficit)
 
Shares
 
Amount
 
 
 
 
 
 
 
Balance at December 31, 2013
—

 
$
—

 
$
—

 
$
—

 
$
(6
)
 
$
2,005,339

 
$
2,005,333

 
$
—

 
$
2,005,333

Net income (loss)
—

 
—

 
—

 
(886,977
)
 
—

 
237,428

 
(649,549
)
 
—

 
(649,549
)
Net changes in parent investment
—

 
—

 
—

 
—

 
—

 
(852,624
)
 
(852,624
)
 
—

 
(852,624
)
Distribution by former parent
84,753

 
848

 
1,419,744

 
—

 
(30,449
)
 
(1,390,143
)
 
—

 
—

 
—

Amortization of share-based compensation
—

 
—

 
2,643

 
—

 
—

 
—

 
2,643

 
—

 
2,643

   Other comprehensive loss, net
—

 
—

 
—


—


(5,850
)

—


(5,850
)

—


(5,850
)
Balance at September 30, 2014
84,753

 
$
848


$
1,422,387


$
(886,977
)

$
(36,305
)

$
—


$
499,953


$
—


$
499,953

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Balance at December 31, 2014
84,753

 
$
848

 
$
1,423,153

 
$
(895,249
)
 
$
(37,144
)
 
$
—

 
$
491,608

 
$
2,641

 
$
494,249

Net income (loss)
—

 
—

 
—

 
(976,380
)
 
—

 
—

 
(976,380
)
 
31

 
(976,349
)
Adjustments to distribution by former parent
—

 
—

 
(9,493
)
 
—

 
—

 
—

 
(9,493
)
 
—

 
(9,493
)
Employee related equity activity:
 
 
 
 
 
 
 
 
 
 
 
 

 
 
 
 
Amortization of share-based compensation
—

 
—

 
12,791

 
—

 
—

 
—

 
12,791

 
—

 
12,791

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
—

 
—

 
—

 
—

 
(6,248
)
 
—

 
(6,248
)
 
—

 
(6,248
)
Balance at September 30, 2015
86,026

 
$
860

 
$
1,426,158

 
$
(1,871,629
)
 
$
(43,392
)
 
$
—

 
$
(488,003
)
 
$
—

 
$
(488,003
)
See accompanying notes to the unaudited consolidated and combined financial statements.

6

PARAGON OFFSHORE plc
CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
Cash flows from operating activities
 
 
 
 
Net loss
 
$
(976,349
)
 
$
(649,549
)
Adjustments to reconcile net loss to net cash from operating activities:
 
 
 
 
Depreciation and amortization
 
280,574

 
331,147

Loss on impairments
 
1,152,547

 
928,947

Gain on disposal of assets, net
 
(12,717
)
 
—

Gain on repurchase of long-term debt
 
(4,345
)
 
(6,931
)
Deferred income taxes
 
(70,149
)
 
(36,481
)
Share-based compensation
 
12,937

 
14,400

Provision for doubtful accounts
 
26,479

 
—

Net change in other assets and liabilities (Note 16)
 
(22,226
)
 
(15,431
)
Net cash provided by operating activities
 
386,751

 
566,102

Cash flows from investing activities
 
 
 
 
Capital expenditures
 
(156,753
)
 
(182,351
)
Proceeds from sale of assets
 
29,316

 
6,570

Acquisition of Prospector Offshore Drilling S.A. non-controlling interest
 
(2,185
)
 
—

Change in restricted cash
 
(17,297
)
 
—

Change in accrued capital expenditures
 
(11,768
)
 
(3,000
)
Net cash used in investing activities
 
(158,687
)
 
(178,781
)
Cash flows from financing activities
 
 
 
 
Net change in borrowings on Predecessor bank credit facilities
 
—

 
707,472

Proceeds from issuance of Senior Notes and Term Loan Facility
 
—

 
1,710,550

Borrowings under Revolving Credit Facility
 
697,000

 
—

Net proceeds from Sale-Leaseback
 
291,576

 
—

Repayment of Revolving Credit Facility
 
(154,000
)
 
—

Repayment of Sale-Leaseback
 
(8,365
)
 

Repayment of Term Loan Facility
 
(4,875
)
 
—

Repayment of Prospector Senior Credit Facility
 
(265,666
)
 
—

Repayment of Prospector Bonds
 
(101,000
)
 
—

Purchase of Senior Notes
 
(6,546
)
 
(42,468
)
Debt issuance costs
 
—

 
(19,253
)
Net transfers to parent
 
—

 
(2,698,295
)
Net cash provided by (used in) financing activities
 
448,124

 
(341,994
)
Net change in cash and cash equivalents
 
676,188

 
45,327

Cash and cash equivalents, beginning of period
 
56,772

 
36,581

Cash and cash equivalents, end of period
 
$
732,960

 
$
81,908

Supplemental information for non-cash activities:
 
 
 
 
Assets related to Sale-Leaseback
 
465,043

 
—

Adjustments to distributions by former parent
 
9,493

 
—

Transfer from parent of property and equipment
 
—

 
18,124

See accompanying notes to the unaudited consolidated and combined financial statements.

7

NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
(Unaudited)


NOTE 1—ORGANIZATION AND BASIS OF PRESENTATION
Paragon Offshore plc (together with its subsidiaries, “Paragon,” the “Company,” “we,” “us” or “our”) is a global provider of offshore drilling rigs. Paragon’s operated fleet includes 34 jackups, including two high specification heavy duty/harsh environment jackups, and six floaters (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.
Spin-Off Transaction
On July 17, 2014, Paragon Offshore Limited, an indirect wholly owned subsidiary of Noble Corporation plc (“Noble”) incorporated under the laws of England and Wales, re-registered under the Companies Act 2006 as a public limited company under the name of Paragon Offshore plc.  Noble transferred to us the assets and liabilities (the “Separation”) constituting most of Noble’s standard specification drilling units and related assets, liabilities and business. On August 1, 2014, Noble made a pro rata distribution to its shareholders of all of our issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned.
Basis of Presentation
The unaudited consolidated and combined financial information for the three and nine months ended September 30, 2014 contained within this report includes periods prior to the Spin-Off on August 1, 2014.  For these periods prior to the Spin-Off, the unaudited consolidated and combined financial statements and related discussion of financial condition and results of operations contained in this report includes 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 unaudited 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 that will be incurred in the future by us. These allocated costs are primarily related to corporate administrative expenses including executive oversight, employee related costs including pensions and other benefits, and corporate and shared employees for the following functional groups:

•
information technology,
•
legal, accounting, finance and treasury services,  
•
human resources,
•
marketing, and
•
other corporate and infrastructural services.
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.

8

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 $0.3 million and $2 million at September 30, 2015 and December 31, 2014, respectively, are included in “Accounts payable” on our Consolidated Balance Sheets.
Liquidity
Prior to the Distribution, our working capital and capital expenditure requirements were a part of Noble’s cash management program. After the Distribution, we have been solely responsible for the provision of funds to finance our working capital and other cash requirements. Our primary sources of liquidity are cash generated from operations, any future financing arrangements, and equity issuances, if necessary. Our principal uses of liquidity will be to fund our operating expenditures and capital expenditures, including major projects, upgrades and replacements to drilling equipment and to service our outstanding indebtedness.
At September 30, 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 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 Offshore Drilling S.A. (“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. Prospector 8 is scheduled to be delivered in the first quarter of 2016. In July 2015, we agreed with the company contracted to construct these rigs, Shanghai Waigaoqiao Ship Co. Ltd. in China (“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 three months ended September 30, 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 Note 5, “Property and Equipment and Other Assets”.
In July 2015, we completed a sale-leaseback transaction for two of our jackup units, the Prospector 1 and the Prospector 5 (the “Sale-Leaseback Transaction”). We received net proceeds of $292 million, including amounts used to fund certain required reserve accounts, and have accounted for the transaction as a capital lease. As of September 30, 2015 and pursuant to the terms of the Sale-Leaseback Transaction, we are required to make an aggregate amount of remaining rental payments of approximately $360 million over the course of the five-year lease terms for these two rigs (see Note 9, “Debt”).
On September 3, 2015, we drew down substantially all of the available borrowing capacity under our senior secured revolving credit agreement (the “Revolving Credit Facility”). At September 30, 2015, we had $733 million of cash on hand and $3 million of committed financing available under our Revolving Credit Facility, which will mature in 2019.
Our Revolving Credit Facility, Term Loan Facility and Senior Notes (each as described and defined in Note 9, “Debt” and collectively referred to herein as the “Debt Facilities”) are subject to financial and non-financial covenants. As of September 30, 2015, we were in compliance with the covenants under our Revolving Credit Facility by maintaining a net leverage ratio of 3.07 and an interest coverage ratio of 5.91. Prospector has been designated as an unrestricted subsidiary under our Debt Facilities, and as a result, the assets, liabilities, and financial results of Prospector are excluded from the financial covenants applicable to Paragon and its other subsidiaries under our Debt Facilities.
While we currently satisfy our covenants, we have continued to experience a decline in demand for our services resulting in some of our rigs becoming idle or stacked much earlier than previously estimated. In September 2015, we received a notification from our customer, Petróleo Brasileiro S.A. (“Petrobras”), regarding their intent to terminate the contract of the Paragon DPDS2 effective September 2015. In addition, Petrobras notified their intent to terminate the contract of the Paragon DPDS3, effective August 2016. We continue to discuss the matter with Petrobras and will vigorously pursue all legal remedies available to us

9

under these contracts. In addition, we have experienced continued reductions in overall global market dayrates. As a consequence of these events, our cash flows have been adversely impacted and we anticipate that we will fall out of compliance with our Revolving Credit Facility leverage ratio covenant over the next twelve-month period. We have engaged financial and legal advisors to assist us in evaluating potential strategic alternatives related to our capital structure. However, there is no assurance that viable alternatives or a waiver from our lenders will be available to us.  Any corrective measures that we do implement may prove inadequate and, even if effective, could have negative long-term consequences to our business. If we are unable to comply with the financial covenants in our Revolving Credit Facility, it would result in a default under the Revolving Credit Facility, and in the absence of a waiver, could cause an acceleration of repayment of all of our outstanding obligations under our Debt Facilities.
Our ability to continue to fund our operations will be affected by several factors which are out of our control, including general economic, future contract amendments with our customers, competitive and other factors. To the extent current depressed market conditions continue for a prolonged period or worsen, funding our operations will become more challenging. If our future cash flows from operations and other capital resources are insufficient to fund our liquidity needs, we may be forced to reduce or delay our capital and operational expenditures, sell assets, obtain additional debt or equity financing, or refinance all or a portion of our debt. In light of a potential covenant breach under our Revolving Credit Facility and continuing adverse market developments, there is substantial doubt regarding our ability to continue as a going concern within the subsequent twelve-month period. For additional discussion of the risks associated with our indebtedness and current liquidity issues, see the discussion under “Risk Factors” in Item 1A of this Form 10-Q.
NOTE 2—UNAUDITED INTERIM INFORMATION
Included in this Quarterly Report on Form 10-Q of Paragon Offshore plc are the consolidated and combined interim financial statements and notes of Paragon Offshore plc and its subsidiaries. The consolidated and combined financial statements and notes are unaudited and have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. While the year-end balance sheet data was derived from audited financial statements, this interim report does not include all disclosures required by accounting principles generally accepted in the United States of America (“U.S. GAAP”) for annual periods and should be read in conjunction with the Annual Report on Form 10-K of Paragon Offshore plc for the year ended December 31, 2014. In management’s opinion, the accompanying interim consolidated and combined financial statements contain all adjustments necessary for a fair statement and are of a normal recurring nature. The interim financial results may not be indicative of the results to be expected for the full year.
New Accounting Pronouncements
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, which amends Accounting Standards Codification (“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

10

of this guidance and has included the related disclosures in the interim consolidated and combined financial statements for the quarter ended September 30, 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 is permitted. We do not expect that our adoption will 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 on our Consolidated Balance Sheets. We had total debt issuance costs related to our Debt Facilities of $27 million and $31 million included in “Other assets” on our Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, respectively.

NOTE 3— SIGNIFICANT ACCOUNTING POLICIES
Our unaudited consolidated and combined financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. Actual results could differ from those estimates. The significant accounting policies and estimates below update and supplement those described in our Annual Report on Form 10-K for the year ended December 31, 2014.
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 $27 million and $1 million at September 30, 2015 and December 31, 2014, respectively. Bad debt expense of $12 million and $27 million was recorded for the three and nine months ended September 30, 2015. No bad debt expense was recorded for the three and nine months ended September 30, 2014. Bad debt expense is reported as a component of “Contract drilling services operating costs and expense” in our Consolidated and Combined Statements of Operations for the three and nine months ended September 30, 2015.
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

11

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, refer to Note 5, “Property and Equipment and Other Assets”.

NOTE 4— ACQUISITION
Prospector Offshore Drilling S. A.
On November 17, 2014, Paragon 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 (the “Prospector Acquisition”). 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 acquire 100% of Prospector and funded the purchase of the shares of Prospector 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.
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 United Kingdom sector of the North Sea. Three subsidiaries of Prospector contracted SWS in China to build the Three High-Spec Jackups Under Construction, which are currently scheduled for delivery in the first quarter of 2016, second quarter of 2016 and fourth quarter of 2016, respectively.
Unaudited Pro Forma Financial Results

Our Consolidated and Combined Statements of Operations for the three and nine months ended September 30, 2014 do not include earnings from the Prospector Acquisition, which closed on November 17, 2014. The following table presents selected unaudited pro forma financial information, which includes our reported consolidated results of operations, for the three and nine months ended September 30, 2014, as if the Prospector Acquisition had occurred on January 1, 2014. The pro forma results below are based on Prospector’s historical financial data and reflects certain estimates and assumptions made by our management. Our unaudited pro forma financial information was prepared for comparative purposes only and is not necessarily indicative of what our consolidated financial results would have been had we actually acquired Prospector on January 1, 2014 or the results of future operations.

 
 
Three Months Ended
 
Nine Months Ended
(In thousands, except per share amounts)
 
September 30, 2014
Total operating revenues
 
$
515,741

 
$
1,520,703

Net loss
 
(875,606
)
 
(697,341
)
Loss per share (basic and diluted)
 
$
(10.33
)
 
$
(8.23
)
Revenues and operating expenses related to the Prospector rigs from the closing date of November 17, 2014 through December 31, 2014 totaled $8 million and $8 million, respectively. Revenues for the three and nine months ended September 30, 2015, which are included in our Consolidated and Combined Statements of Operations, were $38 million and $105 million respectively. Operating expenses for these rigs totaled $73 million and $118 million, respectively for the three and nine months

12

ended September 30, 2015, which included depreciation expense of $4 million and $14 million, respectively, and impairment charges of $43 million and $43 million, respectively 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 $44 million and $157 million for the three and nine months ended September 30, 2015, respectively, as compared to $72 million and $182 million for the three and nine months ended September 30, 2014. 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 Paragon’s results relates to our Senior Notes, Term Loan Facility, and Revolving Credit Facility (each as described and defined in Note 9, “Debt”). No interest was capitalized during the three months ended September 30, 2015 and $0.1 million was capitalized for the nine months ended September 30, 2015, as compared to $0.2 million and $2.6 million for the three and nine months ended September 30, 2014, respectively.
Loss on Impairment of Assets
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 three months ended September 30, 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;
•
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

13

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, we determined that five floaters, sixteen jackups 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 three and nine months ended September 30, 2015, which is included in “Loss on impairments” in our Consolidated and Combined Statements of Operations.
During the three months ended September 30, 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 $929 million 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 three and nine months ended September 30, 2014.
Goodwill Impairment
Goodwill related to the Company’s previous acquisitions is included in “Other assets” on the accompanying Consolidated Balance Sheet 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 period, 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 third 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. 
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 three and nine months ended September 30, 2015, which is included in “Loss on impairments” in our Consolidated and Combined Statements of Operations. At September 30, 2015, the Company had no goodwill. We had no goodwill impairment during the three and nine months ended September 30, 2014.
Disposal of Assets
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.

NOTE 6—DEFERRED REVENUES AND COSTS
It is typical in our dayrate drilling contracts for us to receive compensation and be reimbursed for costs we incur 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 $14 million at September 30, 2015 as compared to $9 million at 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

14

from drilling contracts totaled $8 million at September 30, 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.

NOTE 7—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 18, “Related Parties (Including Relationship with Parent and Corporate Allocations)” for total costs allocated to us by Noble).
Paragon employees’ participation in Noble’s 1991 Stock Option and Restricted Stock Plan (“Noble 1991 Plan”) was terminated 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 Paragon Offshore plc 2014 Employee Omnibus Incentive Plan (the “Employee Plan”) and the Paragon Offshore plc 2014 Director Omnibus Plan (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 September 30, 2015 are as follows (excluding the impact of cash-settled awards):
(In shares)
 
Employee Plan
 
Director Plan
Shares available for future awards or grants
 
4,344,240

 
434,048

Outstanding unvested restricted stock units
 
6,162,714

 
606,935

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.
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.

15

We have awarded both accounting-based and market-based PVRSU’s under our Employee Plan. Our accounting-based PVRSU’s are valued on the date of award at our underlying share price. Total compensation cost recognized for the accounting-based PVRSU’s depends on a performance measure, return on capital employed (“ROCE”), over specified performance periods. Estimated compensation cost is determined based on numerous assumptions, including an estimate of the likelihood that our ROCE will achieve the targeted thresholds and forfeiture of the PVRSU’s based on annualized ROCE performance over the terms of the awards. 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 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 nine months ended September 30, 2015 is as follows:
 
 
TVRSU’s Outstanding (1)
 
Weighted
Average
Grant-Date
Fair Value
 
CS-TVRSU’s Outstanding
 
Share
Price (2)
 
PVRSU’s
Outstanding (3)
 
Weighted
Average
Grant-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
 
(324,117
)
 
7.13

 
(402,791
)
 
 
 
—

 
—

Outstanding at September 30, 2015
 
5,920,165

 
$
5.44

 
3,006,053

 
$
0.24

 
849,484

 
$
5.31

(1)
This column includes 606,935 shares outstanding at September 30, 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 September 30, 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 three and nine months ended September 30, 2015 totaled $3 million and $13 million, respectively. At September 30, 2015, we had $21 million of total unrecognized compensation cost related to our TVRSU’s, which is expected to be recognized over a remaining weighted-average period of 1.9 years. At September 30, 2015, we had $0.6 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 2.4 years. At September 30, 2015, we had $2.5 million of total unrecognized compensation cost related to our PVRSU’s, which is expected to be recognized over a remaining weighted-average period of 1.9 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 8—LOSS PER SHARE

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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 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.
The following table sets forth the computation of basic and diluted loss per share:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
(In thousands, except per share amounts)
 
2015
 
2014
 
2015
 
2014
Allocation of loss - basic and diluted
 
 
 
 
 
 
 
 
Net loss attributable to Paragon
 
$
(1,084,838
)
 
$
(869,160
)
 
$
(976,380
)
 
$
(649,549
)
Earnings allocated to unvested share-based payment awards
 
—

 
—

 
—

 
—

Net loss attributable to ordinary shareholders - basic and diluted
 
$
(1,084,838
)
 
$
(869,160
)
 
$
(976,380
)
 
$
(649,549
)
 
 
 
 
 
 
 
 
 
Weighted average shares outstanding
 
 
 
 
 
 
 
 
Basic and diluted
 
87,077

 
84,753

 
85,703

 
84,753

 
 
 
 
 
 
 
 
 
Weighted average unvested share-based payment awards
 
6,947

 
2,973

 
6,023

 
1,002

 
 
 
 
 
 
 
 
 
Loss per share
 
 
 
 
 
 
 
 
Basic and diluted
 
$
(12.46
)
 
$
(10.26
)
 
$
(11.39
)
 
$
(7.66
)


17

NOTE 9—DEBT
A summary of long-term debt at September 30, 2015 and December 31, 2014 is as follows:
 
 
September 30,
 
December 31,
(In thousands)
 
2015
 
2014
Revolving Credit Facility
 
$
697,000

 
$
154,000

Term Loan Facility, bearing interest at 3.75%, net of unamortized discount
 
640,830

 
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
 
289,013

 
—

Prospector 2019 Second Lien Callable Bond
 
—

 
101,000

Prospector 2018 Senior Secured Credit Facility
 
—

 
265,666

Total debt
 
2,610,425

 
2,160,605

Less: Current maturities of long-term debt
 
(40,990
)
 
(272,166
)
Long-term debt
 
$
2,569,435

 
$
1,888,439

Revolving Credit Facility, Term Loan Facility and Senior Notes
On June 17, 2014, we entered into the Revolving Credit Facility with lenders that provided commitments in the amount of $800 million. The Revolving Credit Facility, 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 London Interbank Offered Rate (“LIBOR”), plus an applicable margin ranging between 1.50% to 2.50%, depending on our leverage ratio, or (ii) a base rate plus an applicable margin ranging between 1.50% to 2.50%. Under the Revolving Credit Facility, we may also obtain letters of credit, the issuance of which would reduce a corresponding amount available for borrowing. As of September 30, 2015, we had $697 million in borrowings outstanding at a weighted-average interest rate of 2.53%, and an aggregate amount of $100 million of letters of credit issued under the Revolving Credit Facility.
On July 18, 2014, we issued $1.08 billion of senior notes (the “Senior Notes”) and also borrowed $650 million under a term loan facility (the “Term Loan Facility”). The Term Loan Facility is secured by 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 and interest 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 0.5% 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 $27 million and $31 million included in “Other assets” on our Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, respectively.

18

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 Facility includes an additional covenant requiring us to maintain a net leverage ratio (defined as total debt, net of cash and cash equivalents, divided by earnings excluding interest, taxes, depreciation and amortization charges) less than 4.00 to 1.00 and a covenant requiring us to maintain a minimum interest coverage ratio (defined as earnings excluding interest, taxes, depreciation and amortization charges divided by interest expense) 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 September 30, 2015, we were in compliance with the covenants under our Revolving Credit Facility by maintaining a net leverage ratio of 3.07 and an interest coverage ratio of 5.91. These calculations do not include the corresponding financial information 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 Paragon and its other subsidiaries under these Debt Facilities.
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. 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. We had no debt repurchases during the second and third quarter of 2015.
On September 3, 2015, we borrowed approximately $332 million under our Revolving Credit Facility. The proceeds from the borrowing were used to enhance the Company’s liquidity and financial flexibility.

Sale-Leaseback Transaction
On July 24, 2015, we executed a combined $300 million Sale-Leaseback Transaction with subsidiaries of SinoEnergy (collectively, 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 a lease agreement for each unit (collectively, 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.
Paragon will not consolidate the Lessors in its consolidated financial statements. 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. We have accounted for the Sale-Leaseback Transaction as a capital lease.
The following table sets forth 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)
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Total
Minimum annual rental payments
 
$
13

 
$
51

 
$
41

 
$
33

 
$
31

 
$
191

 
$
360

We made rental payments, including interest, of approximately $13 million during the three and nine months ended September 30, 2015.
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

19

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 $27 million related to the Lease Agreements in “Other assets” on our Consolidated Balance Sheet as of September 30, 2015. We had no related restricted cash balance in “Other assets” as of December 31, 2014. 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.
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.

NOTE 10—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.
The income tax benefit for the three and nine months ended September 30, 2015 was $55 million and $67 million, respectively. The provision for income taxes for the three and nine months ended September 30, 2014 was $51 million and $93 million, respectively.
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

20

the effective tax rate from period to period is primarily attributable to changes in the profitability 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 and income before taxes.
Our estimated annual effective tax rate includes the effect of significant deferred tax benefits from the recognition of deferred tax assets attributable to current year projected losses in certain jurisdictions. Judgment and assumptions are required in determining whether deferred tax assets will be fully or partially utilized. 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. Based on our judgment of circumstances as of the current quarter, we established a valuation allowance for certain deferred tax assets that no longer meet the “more likely than not” standard of realization. If subsequent changes in circumstances cause further changes in judgment about our ability to realize any deferred tax assets, it could have a material adverse effect on our estimated annual effective tax rate. We continually evaluate strategies that could allow for future utilization of our deferred tax assets.
The United Kingdom (“U.K.”) recently passed new 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 new 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 new legislation are ongoing.
At September 30, 2015, the liabilities related to our unrecognized tax benefits, including estimated accrued interest and penalties, totaled $18 million, and if recognized, would reduce our income tax provision by $18 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, 2014 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 11—EMPLOYEE BENEFIT PLANS
During the periods prior to Spin-Off, most of our employees were eligible to participate in various Noble benefit programs. The results of our Predecessor in these unaudited 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 unaudited consolidated and combined financial statements could differ from amounts that would have been incurred by us if we operated on a standalone basis and are not necessarily indicative of costs to be incurred in the future.
We have instituted competitive compensation policies and programs, as well as carried over certain plans as a standalone public company, the expense for which may differ from the compensation expense allocated by Noble in our Predecessor’s historical combined financial statements.
Defined Benefit Plans
At Spin-Off, Noble sponsored two non-U.S. noncontributory defined benefit pension plans (the “Plans”), which were carried over by us and cover certain Europe-based salaried, non-union employees. For the three and nine months ended September 30, 2015, pension benefit expense related to the Plans that are based on actuary estimates are presented in the table below. For the three and nine months ended September 30, 2014, pension benefit expense for the Plans that were primarily based on costs allocated from our Predecessor were approximately $0.8 million and $4.5 million, respectively.

21

Pension cost includes the following components for the following periods:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
(In thousands)
 
2015
 
2015
 Service cost
 
$
1,361

 
$
4,097

 Interest cost
 
493

 
1,484

 Expected return on plan assets
 
(449
)
 
(1,352
)
 Amortization of prior service cost
 
(5
)
 
(15
)
 Amortization of net actuarial loss
 
195

 
579

 Net pension expense
 
$
1,595

 
$
4,793

During the three and nine months ended September 30, 2015, we contributed approximately $5 million to the Plans.
Other Benefit Plans
At Spin-Off, Noble sponsored a 401(k) defined contribution plan and a profit sharing plan, which covered our Predecessor’s employees who are not otherwise enrolled in the above defined benefit plans. Other post-retirement benefit expense related to these other benefit plans included in the accompanying Consolidated and Combined Statements of Operations for the three and nine months ended September 30, 2015 were $0.4 million and $0.6 million, respectively, as compared to $0.5 million and $2.5 million for the three and nine months ended September 30, 2014, respectively.

22



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 have not entered into any hedging activity during 2015. At September 30, 2015, we had no outstanding derivative contracts. Depending on market conditions, we may elect to utilize short-term forward currency contracts in the future.
Prospector Interest Rate Swaps
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 September 30, 2015, we had no amounts outstanding in our Consolidated Balance Sheets related to the interest rate swaps as of September 30, 2015 and for the nine months ended September 30, 2015, a gain of approximately $1 million resulting from the change in fair value of the interest rate swaps was recorded in “Interest expense, net of amount capitalized.”

NOTE 13—FAIR VALUE OF FINANCIAL INSTRUMENTS
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.
Fair Value of Derivatives
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.” We had no outstanding foreign currency forward contracts or interest rate swaps at September 30, 2015.
Fair Value of Debt
The estimated fair values of our Senior Notes and Term Loan Facility were based on the quoted market prices for similar issues or on the current rates offered to us for debt of similar remaining maturities representative of Level 2 fair value measurements. The fair value of our Prospector Bonds as of December 31, 2014 was based on the put price as per the change of control provisions in the agreement governing the Prospector Bonds.

23

The following table presents the estimated fair value of our Senior Notes, Term Loan Facility and Prospector Bonds as of September 30, 2015 and December 31, 2014, respectively:
 
September 30, 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

 
$
71,339

 
$
457,572

 
$
275,115

7.25% Senior Notes due August 15, 2024
527,010

 
79,052

 
537,010

 
319,521

Total senior unsecured notes
$
983,582

 
$
150,391

 
$
994,582

 
$
594,636

 
 
 
 
 
 
 
 
Term Loan Facility, bearing interest at 3.75%, net of unamortized discount
$
640,830

 
$
257,400

 
$
645,357

 
$
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—ACCUMULATED OTHER COMPREHENSIVE LOSS
The following table sets forth the changes in the accumulated balances for each component of “Accumulated other comprehensive loss” (“AOCL”) for the nine months ended September 30, 2015 and 2014. All amounts 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
 
(3,073
)
 
—

 
(1,827
)
 
(4,900
)
  Amounts reclassified from AOCL
 
(950
)
 
—

 
—

 
(950
)
Net other comprehensive income (loss)
 
4

 
(21,770
)
 
(14,533
)
 
(36,299
)
Balance at September 30, 2014
 
$
4

 
$
(21,770
)
 
$
(14,539
)
 
$
(36,305
)
 
 
 
 
 
 
 
 
 
Balance at December 31, 2014
 
$
—

 
$
(22,911
)
 
$
(14,233
)
 
$
(37,144
)
Activity during period:
 
 
 
 
 
 
 
 
Other comprehensive loss before reclassification
 
—

 
—

 
(6,818
)
 
(6,818
)
Amounts reclassified from AOCL
 
—

 
570

 
—

 
570

Net other comprehensive income (loss)
 
—

 
570

 
(6,818
)
 
(6,248
)
Balance at September 30, 2015
 
$
—

 
$
(22,341
)
 
$
(21,051
)
 
$
(43,392
)
(1)
Gains / (losses) on cash flow hedges are related to our foreign currency forward contracts.  Reclassifications from AOCL were recognized through “Contract drilling services operating costs and expenses” on our Consolidated and Combined Statements of Operations for the nine months ended September 30, 2014.  See Note 12, “Derivative Instruments and Hedging Activities” for additional information.

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(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 nine months ended September 30, 2015.” See Note 11, “Employee Benefit Plans” for additional information.

NOTE 15—COMMITMENTS AND CONTINGENCIES
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 September 30, 2015, we have received tax audit claims of approximately $348 million, of which $79 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 September 30, 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 September 30, 2015.
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 $70 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.
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 a 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.
We have used a commercial agent in Brazil in connection with our Petrobras drilling contracts.  We understand that this agent has represented a number of different companies in Brazil over many years, including several offshore drilling contractors. This agent has pleaded guilty in Brazil in connection with the award of a drilling contract to a competitor, as part of a wider investigation of Petrobras’ business practices. We are not aware of any improper activity by Paragon or the agent in connection with contracts we have with Petrobras, and we have not been contacted by any authorities regarding such contracts.
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

25

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.
Capital Expenditures
In connection with our capital expenditure program, we have outstanding commitments, including shipyard and purchase commitments of approximately $641 million at September 30, 2015. Our 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-Spec Jackups Under Construction.
Other
At September 30, 2015, we had letters of credit of $106 million and performance bonds totaling $79 million supported by surety bonds outstanding and backed by $100 million in letters of credit. 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.
Pursuant to these agreements with Noble, our Consolidated Balance Sheets include the following balances due from and to Noble as of September 30, 2015 and December 31, 2014:
 
 
September 30,
 
December 31,
(In thousands)
 
2015
 
2014
Accounts receivable
 
$
25,479

 
$
15,716

Other current assets
 
14,970

 
26,386

Other assets
 
7,228

 
6,875

Due from Noble
 
$
47,677

 
$
48,977

 
 
 
 
 
Accounts payable
 
$
332

 
$
1,655

Other current liabilities
 
30,406

 
51,169

Other liabilities
 
3,268

 
23,563

Due to Noble
 
$
34,006

 
$
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).

26

Master Separation Agreement
We entered into a Master Separation Agreement with Noble Corporation, a Cayman Islands company and an indirect, wholly-owned subsidiary of Noble (“Noble-Cayman”), which provided for, among other things, the Distribution of our ordinary shares to Noble shareholders and the transfer to us of the assets and the assumption by us of the liabilities relating to our business and the responsibility of Noble for liabilities related to Noble’s, and in certain limited cases, our business. The Master Separation Agreement identified which assets and liabilities constitute our business and which assets and liabilities constitute Noble’s business.
Tax Sharing Agreement
We entered into a Tax Sharing Agreement with Noble, which governs the parties’ respective rights, responsibilities and obligations with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings and certain other matters regarding taxes following the Distribution.
Employee Matters Agreement
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 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.


27

NOTE 16—SUPPLEMENTAL CASH FLOW INFORMATION
The net effect of changes in other assets and liabilities on cash flows from operating activities is as follows:
 
 
Nine Months Ended
 
 
September 30,
(In thousands)
 
2015
 
2014
Accounts receivable
 
$
177,765

 
$
(106,776
)
Other current assets
 
(1,711
)
 
5,391

Other assets
 
(11,687
)
 
8,518

Accounts payable
 
(25,003
)
 
32,950

Other current liabilities
 
(104,701
)
 
39,880

Other liabilities
 
(56,889
)
 
4,606

Net change in other assets and liabilities
 
$
(22,226
)
 
$
(15,431
)
We made income tax payments of approximately $66 million and $54 million during the nine months ended September 30, 2015 and 2014, respectively. For the nine months ended September 30, 2015, approximately $26 million was attributable to current period taxes, $30 million for prior period taxes settled in the current period, and $10 million for current period taxes which are refundable due to foreign tax credits. 

NOTE 17—SEGMENT AND RELATED INFORMATION
At September 30, 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, India, and Southeast Asia.

NOTE 18—RELATED PARTIES (INCLUDING RELATIONSHIP WITH PARENT AND CORPORATE ALLOCATIONS)
For all periods prior to the Spin-Off, our Predecessor was managed in the normal course of business by Noble and its subsidiaries. Accordingly, certain shared costs have been allocated to our Predecessor and are reflected as expenses in these 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 unaudited consolidated and combined financial statements may not be indicative of the actual expenses that would have been incurred during the periods presented if our Predecessor had operated as a separate standalone entity and may not be indicative of expenses that will be incurred in the future by us.
Allocated costs include, but are not limited to: corporate accounting, human resources, information technology, treasury, legal, employee benefits and incentives (excluding allocated 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 $1 million and $70 million for the three and nine months ended September 30, 2014. Our Predecessor’s allocated costs included in general and administrative expenses in the accompanying Consolidated and Combined Statements of Operations totaled $1 million and $25 million for the three and nine months ended September 30, 2014. 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 and Combined Statements of Operations for the three and nine months ended September 30, 2015.


28

ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATION
The following discussion and analysis of the consolidated and combined financial condition and results of operations should be read in conjunction with the accompanying unaudited consolidated and combined financial statements and related notes as of September 30, 2015 and for the three and nine months ended September 30, 2015 and 2014 contained in this Quarterly Report on Form 10-Q and the consolidated and combined financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014. Unless the context requires otherwise, or we specifically indicate otherwise, when used in this Management’s Discussion and Analysis of Financial Condition and Results of Operations, the terms “Paragon,” the “Company,” “we,” “us” or “our” refer to Paragon Offshore plc together with its subsidiaries. The financial information for periods prior to our Separation (as defined below) from Noble Corporation plc (“Noble”) pertains to the Noble standard specification business (our “Predecessor”), which comprised most of Noble’s standard specification drilling fleet and related operations. We have consolidated the historical combined financial results of our Predecessor in our consolidated and combined financial statements for all periods prior to the Spin-Off (as defined below).
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, and six floaters (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.
Market Outlook
With a decline during the third quarter of 2015 in the price of Brent crude oil, a key factor in determining customer activity levels, the business environment for offshore drillers has continued to deteriorate. The price of Brent crude decreased approximately 24% from $63.59 per barrel on June 30, 2015 to $48.37 per barrel on September 30, 2015. As of November 3, 2015, prices have slightly increased since the end of the third quarter 2015 to $50.54 per barrel. In an attempt to maintain global market share, member countries of the Organization of the Petroleum Exporting Countries (“OPEC”) have continued to refuse to reduce their production levels and despite slowing activity in the United States with respect to the development of unconventional shale plays, the world faces an ongoing oversupply of oil. In light of this low commodity price environment, third party industry spending surveys have indicated that oil and gas companies, including supermajors, independents, and national oil companies, have reduced exploration and development capital expenditures by 20 to 25 percent in 2015. The surveys indicate that further reductions could be made in 2016. Capital spending has historically been an indicator of drilling activity, suggesting that 2016 could see less activity than 2015.
During the third quarter of 2015, the offshore drilling industry experienced an increase in contracting activity compared to the second quarter of 2015. According to industry data, there were 64 new jackup contract announcements or fixtures during the third quarter of 2015 compared to 43 new fixtures during the second quarter of 2015. However, 17 of these fixtures were the result of a national oil company signing new contracts with units owned by the country’s national drilling contractor and do not reflect a competitive bidding situation. Nevertheless, the net number reflects a slight increase quarter over quarter, though it is a marked decrease from the 63 fixtures observed during the third quarter of 2014. In the floater segment, there were 15 new fixtures and 2 renegotiations during the third quarter of 2015 compared to 22 new fixtures and 3 renegotiations during the second quarter of 2015 and 33 new fixtures and 2 renegotiations during the third quarter of 2014. Average dayrates for new fixtures also continued to decline for rigs where data has been published by third party services. During the third quarter of 2015, dayrates for new jackup fixtures averaged approximately $113,000 per day compared to $111,000 in the second quarter of 2015 and $153,000 in the third quarter of 2014. Dayrates for new floater fixtures also continued to steadily decrease, averaging at approximately $277,000 in the third quarter of 2015 compared to $309,000 in the second quarter of 2015 and $387,000 in the third quarter of 2014. This trend appears to be continuing into the fourth quarter of 2015 as a competitor announced that it signed a short-term contract for a high specification semisubmersible at approximately $205,000 per day, a new low for ultradeepwater assets in this cycle.
During the third quarter of 2015, industry sources reported only 9 jackups with existing contracts where customers and drilling contractors agreed to reduce dayrates compared to 28 reported renegotiations in the second quarter of 2015. On average, dayrates declined approximately 20% as a result of the renegotiations. In certain cases, drilling contractors were able to exchange a lower dayrate for additional contract term, but in other cases, rates were reduced with no change in the term.

29

During the third quarter of 2015, a number of drilling contractors reported contract cancellations by their customers. As previously reported, in May 2015, one of our subsidiaries received written notices of termination from Petróleos Mexicanos (“Pemex”) of the drilling contracts on the Paragon L1113 and the Paragon B301 (the “Contracts”).  These Contracts were terminated by Pemex pursuant to Pemex’s right to terminate the Contracts on 30 days’ notice and both rigs are currently idle.  We continue to engage in discussions with Pemex regarding our one remaining drilling rig operating in Mexico.
Recently, Petróleo Brasileiro S.A. (“Petrobras”) announced it has for the fourth time reduced its near-term capital expenditure budget for 2015 and 2016 by 43% and 24% respectively. Media reports also indicate they are seeking to reduce their deepwater rig count for 2016 to 35, down approximately 10 units from their currently contracted fleet. 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 September 30, 2015, the Paragon DPDS3 drilling contract constitutes $260 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.
As of November 3, 2015, there were 127 jackup drilling rigs under construction, on order, or planned for construction. These rigs are currently scheduled for delivery between 2015 through as late as 2020. Certain drilling contractors 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 contract 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 rigs competitive or to stack or scrap rigs that are no longer marketable in the current environment.
In conclusion, the short-term outlook for dayrates and utilization for drilling rigs is challenging for both floaters and jackups and could remain so for a number of years.  However, we 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.

Separation from Noble
On July 17, 2014, Paragon Offshore Limited, an indirect wholly owned subsidiary of Noble incorporated under the laws of England and Wales, re-registered under the Companies Act 2006 as a public limited company under the name of Paragon Offshore plc. Noble transferred to us the assets and liabilities (the “Separation”) constituting most of Noble’s standard specification drilling units and related assets, liabilities and business. On August 1, 2014, Noble made a pro rata distribution to its shareholders of all of our issued and outstanding ordinary shares (the “Distribution” and, collectively with the Separation, the “Spin-Off”). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned.
We consolidate the historical combined financial results of the Noble Standard-Spec Business, (our “Predecessor”) in our consolidated and combined financial statements for all periods prior to the Spin-Off. Our Predecessor comprises most of Noble’s standard specification drilling fleet and related operations. 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.
Acquisition of Prospector Offshore Drilling S. A.
On November 17, 2014, Paragon initiated the acquisition of the outstanding shares of Prospector Offshore Drilling S.A. (“Prospector”), an offshore drilling company organized in Luxembourg and traded on the Oslo Axess, from certain shareholders and in open market purchases (the “Prospector Acquisition”). 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

30

outstanding shares in Prospector pursuant to the laws of Luxembourg. We spent approximately $202 million in aggregate to acquire 100% of Prospector and funded the purchase of the shares of Prospector using proceeds from our senior secured revolving credit agreement (the “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 Revolving Credit Facility.
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 United Kingdom 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 a Paragon parent company guarantee or other direct recourse to any other subsidiary of Paragon other than the applicable subsidiary.
Contract Drilling Services Backlog
We maintain a backlog (as defined below) of commitments for contract drilling services. The following table sets forth, as of September 30, 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
 
2015
 
2016
 
2017
 
2018
 
 
 
 
 
 
 
 
 
 
Floaters (1)
$
332

 
$
75

 
$
168

 
$
89

 
$
—

Jackups (2)
954

 
190

 
472

 
249

 
43

Total
$
1,286

 
$
265

 
$
640

 
$
338

 
$
43

Percent of available days committed (3)
 
 
51
%
 
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 to 50% of potential performance bonuses for such rigs, or $20 million. Petrobras has indicated to us that it may 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 September 30, 2015, total backlog related to this contract was approximately $260 million, including $142 million being contested by Petrobras.
(2)
Pemex has the ability to cancel its drilling contract on 30 days’ notice without Pemex making an early termination payment. Currently, our drilling contract with Pemex constitute $6 million and $4 million, respectively, of our contract drilling services backlog for the years ended December 31, 2015 and 2016.
(3)
Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period, or committed days, by the product of the total number of our rigs, including cold-stacked rigs, and the number of calendar days in such period. Committed days do not include the days that a rig is stacked or the days that a rig is expected to be out of service for significant overhaul repairs or maintenance. Available days used in calculating percent of available days committed excludes the Paragon M822 which was sold in January 2015, the Paragon FPSO1 which was sold in June 2015, the Paragon DPDS4 which was sold in October 2015, the Paragon MSS3 and Paragon B153 which have been retired from service.
Our contract drilling services backlog typically reflects estimated future revenues attributable to both signed drilling contracts and letters of intent that we expect to realize. A letter of intent is generally subject to customary conditions, including the execution of a definitive drilling contract. It is possible that some customers that have entered into letters of intent will not enter into signed drilling contracts. As of September 30, 2015, our contract drilling services backlog did not include any letters of intent.

31

We calculate backlog for any given rig and period by multiplying the full contractual operating dayrate for such rig by the number of days remaining in the period. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts.
The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods set forth in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, achievement of bonuses, weather conditions and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual revenues for the periods for which the backlog is calculated.

32

RESULTS OF OPERATIONS
We consolidate the historical combined financial results of our Predecessor in our results of operations for all periods prior to the Spin-Off. Historical operations of our Predecessor include standard specification rigs retained by or sold by Noble prior to the Distribution. All financial information presented after the Spin-Off represents the results of operations of Paragon.
For the Three Months Ended September 30, 2015 and 2014
Our results of operations for the three months ended September 30, 2015 consist entirely of the consolidated results of Paragon while our results of operations for the three months ended September 30, 2014 consist of the consolidated results of Paragon for the two months ended September 30, 2014, and the combined results of our Predecessor for the one month ended July 31, 2014. The results for the three months ended September 30, 2015 also include the results of Prospector.
Net loss for the three months ended September 30, 2015 was $1.1 billion, or a loss of $12.46 per diluted share, on operating revenues of $369 million, compared to a net loss for three months ended September 30, 2014 of $869 million, or a loss of $10.26 per diluted share, on operating revenues of $505 million.
Rig Utilization, Operating Days and Average Dayrates
Operating results for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days, and dayrates. The following table sets forth the average rig utilization, operating days, and average dayrates for our rig fleet for the three months ended September 30, 2015 (the “Current Quarter”) and for the three months ended September 30, 2014 (the “Comparable Quarter”):
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates
 
Three Months Ended
 
Three Months Ended
 
Three Months Ended
 
September 30,
 
September 30,
 
Change
 
September 30,
 
Change
 
2015
 
2014
 
2015
 
2014
 
%
 
2015
 
2014
 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jackups
60
%
 
77
%
 
1,891

 
2,447

 
(23
)%
 
$
116,071

 
$
116,967

 
(1
)%
Floaters (3)
83
%
 
76
%
 
459

 
583

 
(21
)%
 
259,844

 
291,498

 
(11
)%
       Total (4)
64
%
 
77
%
 
2,350

 
3,030

 
(22
)%
 
$
144,158

 
$
150,548

 
(4
)%
(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 62 operating days for the three months ended September 30, 2014.
(3)
Average rig utilization calculation reflects 184 fewer available days for our floater fleet in the Current Quarter 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 three months ended September 30, 2014.
(4)
Amounts exclude the Paragon FPSO1.


33

Operating Results
The following table sets forth our operating results for the three months ended September 30, 2015 and 2014.
 
 
Three Months Ended
 
 
 
 
September 30,
 
Change
(Dollars in thousands)
 
2015
 
2014
 
$
 
%
 
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
Contract drilling services
 
$
338,710

 
$
456,174

 
$
(117,464
)
 
(26
)%
Labor contract drilling services
 
6,853

 
8,562

 
(1,709
)
 
(20
)%
Reimbursables/Other (1)
 
23,410

 
40,486

 
(17,076
)
 
(42
)%
 
 
368,973

 
505,222

 
(136,249
)
 
(27
)%
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
190,536

 
$
217,378

 
$
(26,842
)
 
(12
)%
Labor contract drilling services
 
4,792

 
6,593

 
(1,801
)
 
(27
)%
Reimbursables (1)
 
19,517

 
35,592

 
(16,075
)
 
(45
)%
Depreciation and amortization
 
95,826

 
108,027

 
(12,201
)
 
(11
)%
General and administrative
 
12,800

 
12,037

 
763

 
6
 %
Loss on impairments
 
1,150,846

 
928,947

 
221,899

 
24%

Gain on repurchase of long-term debt
 
—

 
(6,931
)
 
6,931

 
**

 
 
1,474,317

 
1,301,643

 
172,674

 
13
 %
Operating Loss (2)
 
$
(1,105,344
)
 
$
(796,421
)
 
$
(308,923
)
 
(39
)%
**
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 Quarter 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 Quarter as compared to the Comparable Quarter.
(2)
The rigs retained and sold by Noble represent revenues and costs of $16 million and $10 million, respectively, for the three months ended September 30, 2014.
Contract Drilling Services Operating Revenues—Changes in contract drilling services revenues for the Current Quarter as compared to the Comparable Quarter were driven by a 22% decrease in operating days which negatively impacted revenues by $101 million. This was coupled with a 4% decrease in average dayrates, which decreased revenues by $16 million.
The decrease in contract drilling services revenues was attributable to both our floaters and jackups, which experienced decreases of $51 million and $67 million, respectively, in the Current Quarter as compared to the Comparable Quarter.
The decrease in floater revenues of $51 million in the Current Quarter was driven by a 21% decrease in operating days coupled with an 11% decrease in average dayrates, which resulted in a $36 million and a $15 million decrease in revenues, respectively, from the Comparable Quarter.
The decrease in both average dayrates and operating days for our floaters was primarily attributable to the Paragon DPDS1, which was uncontracted for all of the Current Quarter but experienced full utilization in Brazil during the Comparable Quarter. The decrease is also due to the Noble Driller, which was retained by Noble after the Separation.
The $67 million decrease in jackup revenues in the Current Quarter was driven by a 23% decrease in jackup operating days which resulted in a $65 million decrease in revenues. This was coupled with a slight 1% decrease in average dayrates, which resulted in decreased revenues of $2 million from the Comparable Quarter.

34

The decrease in jackup operating days was due to seven of our rigs in Mexico that were uncontracted for all of the Current Quarter but experienced full utilization during the Comparable Quarter. The decrease was also the result of the Noble Alan Hay which was retained by Noble after the Separation. The remaining decrease in operating days is due to the Noble Ed Holt currently in India, the Paragon L785 currently in Southeast Asia, the Paragon C20052 currently in the North Sea, and the Paragon M826 and the Paragon L783 both currently in Africa which were uncontracted for all or a portion of the Current Quarter but were contracted for all of the Comparable Quarter. The decrease in operating days was partially offset by 246 additional operating days in the Current Quarter due to the Prospector 1, Prospector 5, and the Paragon C20051 operating in the North Sea, 184 additional operating days in the Current Quarter due to the Paragon L786 and the Paragon M1161 operating in the Middle East, and 87 additional operating days due to the Paragon M825 operating in West Africa.
The slight decrease in jackup average dayrates during the Current Quarter was due to an overall decrease in dayrates across our fleet. The decrease in average dayrates was offset by the addition of contracts with higher dayrates for the Prospector 1 and the Prospector 5.
Contract Drilling Services Operating Costs and Expenses — Contract drilling services operating costs and expenses decreased in the Current Quarter as compared to the Comparable Quarter 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 collections on customer receivables that were recorded in the Current Quarter.
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 $17 million decrease in reimbursable revenues and the related $16 million decrease in reimbursable costs in the Current Quarter from the Comparable Quarter were primarily due to reduction in the 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 contract and pursuant to the transition service agreement for Brazil (See Note 15,“Commitments and Contingencies” for additional detail).
Depreciation and Amortization — The $12 million decrease in depreciation and amortization in the Current Quarter was primarily attributable to lower depreciation on assets subject to the impairment charge taken in 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 Comparable Quarter primarily represent costs allocated to our Predecessor based on certain support functions that were provided by Noble on a centralized basis. Costs in the Current Quarter represent actual costs incurred for periods subsequent to the Spin-Off. Costs incurred during the Current Quarter were 6% higher than the Comparable Quarter due to costs associated with our operating as a standalone public company.
Loss on Impairment — In the Current Quarter, as a result of the identification of certain indicators of impairment, consisting of the continuing decline of the drilling industry during the three months ended September 30, 2015, 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 resultantly recorded an impairment loss of $1.1 billion on five floaters, sixteen jackups and deposits related to the Three High-Spec Jackups Under Construction. In addition, we determined goodwill was impaired and recorded an impairment loss of $37 million during the Current Quarter.
During the Comparable Quarter, similar triggering events, particularly for our floating fleet, required us to perform an impairment analysis and we recognized an impairment loss of $929 million on our three drillships in Brazil and our one cold-stacked FPSO in the U.S. Gulf of Mexico. We had no goodwill impairment loss during the Comparable Quarter.
Gain on repurchase of long-term debt — In the Comparable Quarter, we repurchased and canceled an aggregate principal amount of $50 million of our senior notes at an aggregate cost of $43 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 $7 million. All senior notes were made using available cash balances.

35


Other Expenses
Income tax benefit (provision) — Our income tax benefit increased $106 million in the Current Quarter compared to the Comparable Quarter, primarily due to the tax effect of the aforementioned aggregate impairment loss of $1.2 billion during the Current Quarter, a $322 million increase in pre-tax book loss and underlying changes in the profitability/loss associated with our operations in various jurisdictions, including current year projected losses in certain jurisdictions.
For the Nine Months Ended September 30, 2015 and 2014
Our results of operations for the nine months ended September 30, 2015 consist entirely of the consolidated results of Paragon while our results of operations for the nine months ended September 30, 2014 consist of the consolidated results of Paragon for the two months ended September 30, 2014 and the combined results of our Predecessor for the seven months ended July 31, 2014. The results for the nine months ended September 30, 2015 also include the results of Prospector.
Net loss for nine months ended September 30, 2015 was $1.0 billion, or a loss of $11.39 per diluted share, on operating revenues of $1.2 billion, compared to net loss for nine months ended September 30, 2014 of $650 million, or a loss of $7.66 per diluted share, on operating revenues of $1.5 billion.
Rig Utilization, Operating Days and Average Dayrates
Operating results for our contract drilling services segment are dependent on three primary metrics: rig utilization, operating days, and dayrates. The following table sets forth the average rig utilization, operating days, and average dayrates for our rig fleet for the nine months ended September 30, 2015 (the “Current Period”) and for the nine months ended September 30, 2014 (the “Comparable Period”):
 
Average Rig Utilization (1)
 
Operating Days (2)
 
Average Dayrates
 
Nine Months Ended
 
Nine Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
Change
 
September 30,
 
Change
 
2015
 
2014
 
2015
 
2014
 
%
 
2015
 
2014
 
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Jackups
65
%
 
79
%
 
6,054

 
7,640

 
(21
)%
 
$
122,327

 
$
114,078

 
7
 %
Floaters (3)
83
%
 
77
%
 
1,364

 
1,850

 
(26
)%
 
264,665

 
291,283

 
(9
)%
       Total (4)
68
%
 
78
%
 
7,418

 
9,490

 
(22
)%
 
$
148,499

 
$
148,622

 
—
 %
(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 nine months ended September 30, 2014.
(3)
Average rig utilization calculation reflects 546 fewer available days for our floater fleet in the Current Period 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 nine months ended September 30, 2014.
(4)
Amounts exclude the Paragon FPSO1.


36

Operating Results
The following table sets forth our operating results for the nine months ended September 30, 2015 and 2014.
 
 
Nine Months Ended
 
 
 
 
September 30,
 
Change
(Dollars in thousands)
 
2015
 
2014
 
$
 
%
 
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
Contract drilling services
 
$
1,101,618

 
$
1,410,471

 
$
(308,853
)
 
(22
)%
Labor contract drilling services
 
21,224

 
24,919

 
(3,695
)
 
(15
)%
Reimbursables/Other (1)
 
70,023

 
63,379

 
6,644

 
10
 %
 
 
1,192,865

 
1,498,769

 
(305,904
)
 
(20
)%
Operating costs and expenses:
 
 
 
 
 
 
 
 
Contract drilling services
 
$
612,610

 
$
666,158

 
$
(53,548
)
 
(8
)%
Labor contract drilling services
 
16,086

 
19,029

 
(2,943
)
 
(15
)%
Reimbursables (1)
 
58,173

 
51,442

 
6,731

 
13
 %
Depreciation and amortization
 
280,574

 
331,147

 
(50,573
)
 
(15
)%
General and administrative
 
41,901

 
37,965

 
3,936

 
10
 %
Loss on impairments
 
1,152,547

 
928,947

 
223,600

 
24%

Gain on disposal of assets, net
 
(12,717
)
 
—

 
(12,717
)
 
**

Gain on repurchase of long-term debt
 
(4,345
)
 
(6,931
)
 
2,586

 
**

 
 
2,144,829

 
2,027,757

 
117,072

 
6
 %
Operating Loss (2)
 
$
(951,964
)
 
$
(528,988
)
 
$
(422,976
)
 
(80
)%
**
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 Period 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 Period as compared to the Comparable Period.
(2)
The rigs retained and sold by Noble represent revenues and costs of $117 million and $70 million, respectively, for the nine months ended September 30, 2014.
Contract Drilling Services Operating Revenues—Changes in contract drilling services revenues for the Current Period as compared to the Comparable Period were driven by a 22% decrease in operating days which negatively impacted revenues by $322 million. This decrease was partially offset by a slight increase in average dayrates which increased revenues by $14 million.
The decrease in contract drilling services revenues was attributable to both our floaters and jackups which experienced decreases of $178 million and $131 million, respectively, in the Current Period as compared to the Comparable Period.
The decrease in floater revenues of $178 million in the Current Period was driven by a 26% decrease in operating days coupled with a 9% decrease in average dayrates which resulted in a $142 million and a $36 million decrease in revenues, respectively, from the Comparable Period.
The decrease in both average dayrates and operating days for our floaters was primarily due the Paragon DPDS1 which was uncontracted for all of the Current Period but experienced full utilization in Brazil during the Comparable Period. The decrease is also due to the Noble Driller, which was retained by Noble after the Separation.
The $131 million decrease in jackup revenues in the Current Period was driven by a 21% decrease in jackup operating days which resulted in a $181 million decrease in revenues. This decline was partially offset by a 7% increase in average dayrates which positively impacted revenues by $50 million from the Comparable Period.

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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 Period but experienced close to full utilization during the Comparable Period. 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 Comparable Period. The remaining decrease in operating days is primarily due to the Paragon L784 currently in the Middle East, the Paragon M826 currently in Africa, the Paragon C20052 currently in the North Sea, the Noble Ed Holt currently in India, and the Paragon L785 currently in Southeast Asia which were uncontracted for all or a portion of the Current Period but were contracted for all of the Comparable Period. The decrease in operating days was partially offset by 627 additional operating days in the Current Period due to the Prospector 1, Prospector 5, and the Paragon C20051 operating in the North Sea, 318 additional operating days due to the Paragon M825 and the Paragon L782 operating in West Africa, and 254 additional operating days in the Current Period due to the Paragon L786 and the Paragon M1161 operating in the Middle East.
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 Period as compared to the Comparable Period 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 collections on customer receivables that was recorded in the Current Period.
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 $7 million increase in reimbursable revenues and the related $7 million increase in reimbursable costs in the Current Period from the Comparable Period were primarily due to increase in 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 contract and pursuant to the transition service agreement for Brazil (See Note 15, “Commitments and Contingencies” for additional detail).
Depreciation and Amortization — The $51 million decrease in depreciation and amortization in the Current Period was primarily attributable to lower depreciation in the Current Period on assets subject to the impairment charge taken in 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 Comparable Period primarily represent costs allocated to our Predecessor based on certain support functions that were provided by Noble on a centralized basis. Costs in the Current Period represent actual costs incurred for periods subsequent to the Spin-Off. Costs incurred during the Current Period were 10% higher than the Comparable Period due to costs associated with our operating as a standalone public company.
Loss on Impairment — In the Current Period, as a result of the identification of certain indicators of impairment, consisting of the continuing decline of the drilling industry during the nine months ended September 30, 2015, 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 resultantly recorded an impairment loss of $1.1 billion on five floaters, sixteen jackups and deposits related to the Three High-Spec Jackups Under Construction. In addition, we determined goodwill was impaired and recorded an impairment loss of $37 million during the Current Period.
During the Comparable Period, similar triggering events, particularly for our floating fleet, required us to perform an impairment analysis and we recognized an impairment loss of $929 million on our three drillships in Brazil and our one cold-stacked floating production storage and offloading unit in the U.S. Gulf of Mexico. We had no goodwill impairment loss during the Comparable Period.
Gain on disposal of assets, net — Gain on disposal of assets, net during the Current Period was attributable to the sale of the Paragon M822 to an unrelated third party during the first quarter of 2015 partially offset by a loss on the sale and disposal of drill pipe during the second quarter of 2015.

38

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.
Other Expenses
Income tax benefit (provision) — Our income tax benefit increased $160 million in the Current Period compared to the Comparable Period, primarily due to the tax effect of the aforementioned aggregate impairment loss of $1.2 billion during the Current Period, a $487 million increase in pre-tax book loss and underlying changes in the profitability/loss associated with our operations in various jurisdictions, including current year projected losses in certain jurisdictions.

39

LIQUIDITY AND CAPITAL RESOURCES
Overview
The table below sets forth a summary of our cash flow information for the nine months ended September 30, 2015 and 2014. Our cash flows for the nine months ended September 30, 2015 consist entirely of the consolidated results of Paragon while our cash flows for the nine months ended September 30, 2014 consist of the consolidated results of Paragon for the two months ended September 30, 2014 and the combined results of our Predecessor for the seven months ended July 31, 2014.
 
 
Nine Months Ended
 
 
September 30,
(In thousands)
 
2015
 
2014
Cash flows provided by (used in):
 
 
 
 
Operating activities
 
$
386,751

 
$
566,102

Investing activities
 
(158,687
)
 
(178,781
)
Financing activities
 
448,124

 
(341,994
)
Changes in cash flows from operating activities for the nine months ended September 30, 2015 are driven by changes in net loss (see discussion of changes in net loss in “Results of Operations”) 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. During the nine months ended September 30, 2015, our cash flows used in investing activities were also impacted by our sale of the Paragon M822, the Paragon FPSO, and drill pipe to unrelated third parties as well as an increase in restricted cash related to reserve requirements on the Sale-Leaseback Transaction, as defined below. Changes in cash flows from financing activities for the nine months ended September 30, 2015 are primarily due to additional borrowings under our Revolving Credit Facility and proceeds from the Sale-Leaseback Transaction, both offset by repayments of the Revolving Credit Facility, 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;
•
service of outstanding indebtedness
•
acquisitions; and
•
share repurchases.
We currently expect to fund these cash flow needs with cash generated by our operations, available cash balances, potential issuances of long-term debt or equity, other financings, or asset sales.
At September 30, 2015, we had a total contract drilling services backlog of approximately $1.3 billion, which includes $307 million with Petrobras, of which $142 million related to the Paragon DPDS3 is being contested by Petrobras. Our backlog as of September 30, 2015 reflects a commitment of 51% of available days for the remainder of 2015 and 33% of available days for 2016. For additional information regarding our backlog, see “Contract Drilling Services Backlog” discussion above.
Revolving Credit Facility, Term Loan Facility and Senior Notes
In connection with the Separation, we entered into a senior secured revolving credit agreement, a term loan agreement, and a senior note indenture described below that contain customary covenants relating to, among other things, the incurrence of additional indebtedness, dividends and other restricted payments and mergers, consolidations or the sale of substantially all of our assets. In addition, we have obtained surety lines to provide performance bonds for drilling contracts.

40

On June 17, 2014, we entered into the Revolving Credit Facility with lenders that provided commitments in the amount of $800 million. The Revolving Credit Facility, 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 London Interbank Offered Rate (“LIBOR”), plus an applicable margin ranging between 1.50% to 2.50%, depending on our leverage ratio, or (ii) a base rate plus an applicable margin ranging between 1.50% to 2.50%. Under the Revolving Credit Facility, we may also obtain letters of credit, the issuance of which would reduce a corresponding amount available for borrowing. As of September 30, 2015, we had $697 million in borrowings outstanding at a weighted-average interest rate of 2.53%, and an aggregate amount of $100 million of letters of credit issued under the Revolving Credit Facility.
On July 18, 2014, we issued $1.08 billion of senior notes (the “Senior Notes”) and also borrowed $650 million under a term loan facility (the “Term Loan Facility”). The Term Loan Facility is secured by 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 and interest 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 0.5% original issue discount.
In connection with the issuance of the aforementioned Revolving Credit Facility, Term Loan Facility and Senior Notes agreements (collectively referred to herein as the “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 $27 million and $31 million included in “Other assets” on our Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, respectively.
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 Debt Facilities are substantially similar. In addition to these covenants, the Revolving Credit Facility includes an additional covenant requiring us to maintain a net leverage ratio (defined as total debt, net of cash and cash equivalents, divided by earnings excluding interest, taxes, depreciation and amortization charges) less than 4.00 to 1.00 and a covenant requiring us to maintain a minimum interest coverage ratio (defined as earnings excluding interest, taxes, depreciation and amortization charges divided by interest expense) 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 September 30, 2015, we were in compliance with the covenants under our Revolving Credit Facility by maintaining a net leverage ratio of 3.07 and an interest coverage ratio of 5.91. These calculations do not include the corresponding financial information 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 Paragon and its other subsidiaries under these Debt Facilities.
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. 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. We had no debt repurchases during the second and third quarter of 2015.
On September 3, 2015, we borrowed approximately $332 million under our Revolving Credit Facility. The proceeds from the borrowing were used to enhance the Company’s liquidity and financial flexibility.

Sale-Leaseback Transaction
On July 24, 2015, we executed a combined $300 million transaction with subsidiaries of SinoEnergy (collectively, the “Lessors”) for our two high specification jackup units, Prospector 1 and Prospector 5, collectively, the “Rigs” (the “Sale-Leaseback Transaction”). We sold the Rigs to the Lessors and immediately leased the Rigs from the Lessors for a period of five

41

years pursuant to a lease agreement for each unit (collectively, 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 September 2016 and November 2017, respectively.
Paragon will not consolidate the Lessors in its consolidated financial statements. 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. We have accounted for the Sale-Leaseback Transaction as a capital lease.
The following table sets forth 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)
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Total
Minimum annual rental payments
 
$
13

 
$
51

 
$
41

 
$
33

 
$
31

 
$
191

 
$
360

We made rental payments, including interest, of approximately $13 million during the three and nine months ended September 30, 2015.
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 $27 million related to the Lease Agreements in “Other assets” on our Consolidated Balance Sheet as of September 30, 2015. We had no related restricted cash balance in “Other assets” as of December 31, 2014. 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.
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.

42

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.
Liquidity
Prior to the Distribution, our working capital and capital expenditure requirements were a part of Noble’s cash management program. After the Distribution, we have been solely responsible for the provision of funds to finance our working capital and other cash requirements. Our primary sources of liquidity are cash generated from operations, any future financing arrangements, and equity issuances, if necessary. Our principal uses of liquidity will be to fund our operating expenditures and capital expenditures, including major projects, upgrades and replacements to drilling equipment and to service our outstanding indebtedness.
At September 30, 2015, we had purchase commitments of $600 million currently due in 2016 on the construction of 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. Prospector 8 is scheduled to be delivered in the first quarter of 2016. In July 2015, we agreed with the company contracted to construct these rigs, 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 three months ended September 30, 2015, we recorded a full impairment of $43 million of all of the capitalized costs associated with the Three High-Spec Jackups Under Construction in connection with our annual long-lived asset impairment evaluation described in Note 5, “Property and Equipment and Other Assets”.
In July 2015, we completed a Sale-Leaseback Transaction for two of our jackup units, the Prospector 1 and the Prospector 5. We received net proceeds of $292 million, including amounts used to fund certain required reserve accounts, and have accounted for the transaction as a capital lease. As of September 30, 2015 and pursuant to the terms of the Sale-Leaseback Transaction, we are required to make an aggregate amount of remaining rental payments of approximately $360 million over the course of the five-year lease terms for the two rigs.
On September 3, 2015, we drew down substantially all of the available borrowing capacity under our Revolving Credit Facility in the amount of approximately $332 million. At September 30, 2015, we had $733 million of cash on hand and $3 million of committed financing available under our Revolving Credit Facility, which will mature in 2019.
Our Debt Facilities are subject to financial and non-financial covenants. As of September 30, 2015, we were in compliance with the covenants under our Revolving Credit Facility by maintaining a net leverage ratio of 3.07 and an interest coverage ratio of 5.91. Prospector has been designated as an unrestricted subsidiary under our Debt Facilities, and as a result, the assets, liabilities, and financial results of Prospector are excluded from the financial covenants applicable to Paragon and its other subsidiaries under our Debt Facilities.
While we currently satisfy our covenants, we have continued to experience a decline in demand for our services resulting in some of our rigs becoming idle or stacked much earlier than previously estimated. In September 2015, we received a notification from our customer, Petrobras, regarding their intent to terminate the contract of the Paragon DPDS2 effective September 2015. In addition, Petrobras notified their intent to terminate the contract of the Paragon DPDS3, effective August 2016. We continue to discuss the matter with Petrobras and will vigorously pursue all legal remedies available to us under these contracts. In addition, we have experienced continued reductions in overall global market dayrates. As a consequence of these events, our cash flows have been adversely impacted and we anticipate that we will fall out of compliance with our Revolving Credit Facility leverage ratio covenant over the next twelve-month period. We have engaged financial and legal advisors to assist us in evaluating potential strategic alternatives related to our capital structure. However, there is no assurance that viable alternatives or a waiver

43

from our lenders will be available to us.  Any corrective measures that we do implement may prove inadequate and, even if effective, could have negative long-term consequences to our business. If we are unable to comply with the financial covenants in our Revolving Credit Facility, it would result in a default under the Revolving Credit Facility, and in the absence of a waiver, could cause an acceleration of repayment of all of our outstanding obligations under our Debt Facilities.
Our ability to continue to fund our operations will be affected by general economic, competitive and other factors, including any future contracts with our customers, many of which are outside of our control. To the extent current depressed market conditions continue for a prolonged period or worsen, funding our operations will become more challenging. If our future cash flows from operations and other capital resources are insufficient to fund our liquidity needs, we may be forced to reduce or delay our capital and operational expenditures, sell assets, obtain additional debt or equity financing, or refinance all or a portion of our debt. In light of a potential covenant breach under our Revolving Credit Facility and continuing adverse market developments, there is substantial doubt regarding our ability to continue as a going concern within the subsequent twelve month period. For additional discussion of the risks associated with our indebtedness and current liquidity issues, please the discussion under “Risk Factors” in Item 1A of this Form 10-Q.
Capital Expenditures
Capital expenditures, including capitalized interest, totaled $157 million during the nine months ended September 30, 2015 and $182 million during the nine months ended September 30, 2014. As of September 30, 2015, we had approximately $41 million in capital commitments related to ongoing major projects, upgrades and replacements to existing drilling equipment (excluding shipyard commitments related to the three high specification jackups under construction). Capital commitments include all open purchase orders issued to vendors to procure capital equipment.
From time to time we consider possible projects that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, we will continue to evaluate acquisitions of drilling units. Other factors that could cause actual capital expenditures to materially exceed plan include delays and cost overruns in shipyards (including costs attributable to labor shortages), shortages of equipment, latent damage or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions, changes in governmental regulations and requirements and changes in design criteria or specifications during repair or construction.

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Dividends
In February 2015, we announced that we were suspending the declaration and payment of dividends for the foreseeable future in order to preserve liquidity.
The declaration and payment of dividends require authorization of our Board of Directors, provided that such dividends on issued share capital may be paid only out of Paragon Offshore plc’s “distributable reserves” on its statutory balance sheet. Paragon Offshore plc is not permitted to pay dividends out of share capital, which includes share premiums. 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, outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant factors at that time.
OFF-BALANCE SHEET ARRANGEMENTS
We have no off-balance sheet arrangements as that term is defined in Item 303(a)(4)(ii) of Regulation S-K.
COMMITMENTS AND CONTRACTUAL OBLIGATIONS
For additional information about our commitments and contractual obligations as of December 31, 2014, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2014. As of September 30, 2015, other than payments made for our debt obligations, there were no other material changes to this disclosure regarding our commitments and contractual obligations.
In July 2015, we agreed with SWS to an extension of the delivery of the Prospector 6 to the second quarter of 2016 and likewise in October 2015, to an extension of the delivery of the Prospector 7 to the fourth quarter of 2016. The extensions reduce our 2015 commitments by $400 million and resultantly increases our 2016 commitments by the same amount relating to the final installment payment due upon delivery of the Prospector 6 and the Prospector 7. See Note 9, “Debt” for our capital lease obligations resulting from the Sale-Leaseback Transaction and minimum rent payments.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our unaudited consolidated and combined financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. Actual results could differ from those estimates. The significant accounting policies and estimates below updates and supplements those described in our Annual Report on Form 10-K for the year ended December 31, 2014.
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 $27 million and $1 million at September 30, 2015 and December 31, 2014, respectively. Bad debt expense of $12 million and $27 million was recorded for the three and nine months ended September 30, 2015. No bad debt expense was recorded for the three and nine months ended September 30, 2014. Bad debt expense is reported as a component of “Contract drilling services operating costs and expense” in our Consolidated and Combined Statements of Operations for the three and nine months ended September 30, 2015.
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:

45

•
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, refer to Note 5, “Property and Equipment and Other Assets”.

NEW ACCOUNTING PRONOUNCEMENTS
In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, which amends Accounting Standards Codification (“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 interim consolidated and combined financial statements for the quarter ended September 30, 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 is permitted. We do not expect that our adoption will 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 on our Consolidated Balance Sheets. We had total debt issuance costs related to our Debt Facilities of $27 million and $31 million included in “Other assets” on our Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014, respectively.

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Forward-Looking Statements
This Quarterly Report on Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the U.S. Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this report are forward-looking statements, including statements regarding contract backlog, fleet status, our financial position, business strategy, taxes, timing or results of acquisitions or dispositions, repayment of debt, borrowings under our credit facilities or other instruments, future capital expenditures, contract commitments, dayrates, contract commencements, extension or renewals, contract tenders, the outcome of any dispute, litigation, audit or investigation, plans and objectives of management for future operations, foreign currency requirements, indemnity and other contract claims, construction and upgrade of rigs, industry conditions, access to financing, impact of competition, governmental regulations and permitting, availability of labor, worldwide economic conditions, taxes and tax rates, indebtedness covenant compliance, dividends and distributable reserves, and timing for compliance with any new regulations. When used in this report, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this report on Form 10-Q and we undertake no obligation to revise or update any forward-looking statement for any reason, except as required by law. We have identified factors, including but not limited to, operating hazards and delays, operations outside the U.S., actions by regulatory authorities, customers, contractors, lenders and other third parties, legislation and regulations affecting drilling operations, costs and difficulties relating to the integration of businesses, factors affecting the level of activity in the oil and gas industry, supply and demand of drilling rigs, factors affecting the duration of contracts, the actual amount of downtime, factors that reduce applicable dayrates, hurricanes and other weather conditions, and the future price of oil and gas that could cause actual plans or results to differ materially from those included in any forward-looking statements. These factors include those referenced or described in Part I, Item 1A, “Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2014, our Quarterly Reports on Form 10-Q and in our other filings with the SEC. We cannot control such risk factors and other uncertainties, 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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ITEM 3.
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 our 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 September 30, 2015, we had $697 million 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 our 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 September 30, 2015, we had $641 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 $257 million at September 30, 2015. Related interest expense for the three and nine months ended September 30, 2015 was approximately $7 million and $19 million, respectively. 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 $150 million at September 30, 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 our Consolidated Balance Sheet in “Accumulated other comprehensive loss” (“AOCL”). Amounts recorded in AOCL are reclassified into earnings in the same period or periods that the hedged item is recognized in earnings. The ineffective portion of changes in the fair value of the hedged item is recorded directly to earnings. We have documented policies and procedures to monitor and control the use of derivative instruments. We do not engage in derivative transactions for speculative or trading purposes, nor are we a party to leveraged derivatives.
Our North Sea, Mexico and Brazil operations have a significant amount of their cash operating expenses payable in local currencies. To limit the potential risk of currency fluctuations, we may periodically enter into forward contracts, all of which would have a maturity of less than twelve months and would settle monthly in the operations’ respective local currencies. At September 30, 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 4.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Randall D. Stilley, President, Chief Executive Officer, and Director of Paragon, and Steven A. Manz, Senior Vice President and Chief Financial Officer of Paragon, under the supervision and with the participation of our management, have evaluated the disclosure controls and procedures of Paragon as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Our controls over restricted access and segregation of duties within our SAP system were improperly designed and not effective as certain personnel have the ability to prepare and post journal entries without an independent review required by someone other than the preparer. Specifically, the controls as designed did not provide reasonable assurance that incompatible access within the system, including the ability to record transactions, was appropriately segregated, impacting the accuracy and completeness of all key accounts and disclosures. This control deficiency did not result in any adjustments to the consolidated financial statements for the year ended December 31, 2014 or for the nine months ended September 30, 2015. However, the deficiency could result in misstatements to key accounts and disclosures that would result in a material misstatement of the consolidated financial statements that would not be prevented or detected. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis.

In light of the material weakness described above, which is currently in the process of remediation further described below, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of September 30, 2015.

Remediation Activities
Management has taken steps to address and improve our controls over restricted access and segregation of duties within our SAP system and a remediation plan is currently in process.  We have designed and implemented a remediation plan that includes new accounting processes and control procedures around journal entry review to remediate the identified material weakness.   We will not be able to conclude the material weakness has been remediated until we are able to test the operational effectiveness of these processes and controls. We expect to test the controls and conclude as to whether the material weakness has been remediated in the fourth quarter of 2015. Additionally, we continue to take steps to comprehensively document and analyze our system of internal control over financial reporting in preparation for our first management report on internal control over financial reporting required in connection with our Annual Report on Form 10-K for the year ended December 31, 2015.

Changes in Internal Control over Financial Reporting
As our remediation efforts are still in progress, as described above, there were changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) related to the above that occurred during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 

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PART II.
OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS
Information regarding legal proceedings is set forth in Note 15, “Commitments and Contingencies” to our unaudited consolidated and combined financial statements included in Item I, Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.
As of September 30, 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 and combined statements of financial position, results of operations or 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 1A.
RISK FACTORS
Except as set forth below, there have been no material changes to the risk factors previously disclosed in our our Annual Report on Form 10-K for the year ended December 31, 2014. For additional information about our risk factors see the risks described in Part I, Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2014.
Risks Relating to Our Business
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 three and nine months ended September 30, 2015, the Company recorded non-cash impairment charges of $1.1 billion and $37 million related to its property and equipment and goodwill, respectively. As of September 30, 2015, the Company had no goodwill. 
If we are unable to comply with the financial covenants in our Revolving Credit Facility, it would result in default under the Revolving Credit Facility, which would result in an acceleration of repayment of all of our outstanding obligations under our Revolving Credit Facility, Term Loan Facility and our Senior Notes.
Our Revolving Credit Facility includes financial covenants that require us to (i) maintain a net leverage ratio (defined as total debt, net of cash and cash equivalents, divided by earnings excluding interest, taxes, depreciation and amortization charges) less than 4.00 to 1.00 and (ii) a minimum interest coverage ratio (defined as earnings excluding interest, taxes, depreciation and amortization charges divided by interest expense) greater than 3.00 to 1.00. As of September 30, 2015, our net leverage ratio was 3.07 and our interest coverage ratio was 5.91. We must comply with each of these financial covenants at the end of each fiscal quarter based upon our financial results for the prior twelve month period. 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 our Revolving Credit Facility if we are unable to obtain a waiver under such facility. An event of default would prevent us from borrowing under our Revolving Credit Facility, which would in turn have a material adverse effect on our available liquidity. In addition, an event of default would result in our having to immediately repay all amounts outstanding under the Revolving Credit Facility, our Term Loan and our Senior Notes. 
 While we may take certain corrective measures to maintain compliance with this financial covenant, including reducing operating and capital expenditures or seeking a waiver of this covenant from our lenders, there is no assurance that these measures will be effective or available to us. Any corrective measures that we do implement may prove inadequate and could have negative long-term consequences for our business.
We have engaged financial and legal advisors to assist us in evaluating potential strategic alternatives related to our capital structure. We are currently reviewing our alternatives, and we may adopt other strategies that may include actions such as a refinancing or restructuring of our indebtedness or capital structure, reducing or delaying capital investments, or seeking to raise additional capital through debt or equity financing.  However, our current credit rating limits our ability to access the debt capital markets.  In addition, the recent low trading price of our common stock severely limits our ability to raise capital in the equity

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capital markets.  Our ability to timely raise sufficient capital may also be limited by New York Stock Exchange (“NYSE”) stockholder approval requirements for certain transactions involving the issuance of our shares or securities convertible into our shares.
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, 2014, 2013 and 2012, our five largest customers in the aggregate accounted for approximately 57%, 55%, and 61% respectively, of our operating revenues. We expect Petrobras, which accounted for approximately 23% of our operating revenues for the year ended December 31, 2014, and 23% of our operating revenues for the nine months ended September 30, 2015 to continue to be a significant customer in 2015. Our contract drilling backlog as of September 30, 2015 consists of $307 million or approximately 24% 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 September 30, 2015, the Paragon DPDS3 drilling contract constitutes $260 million of our contract drilling services backlog, which includes $142 million being contested by Petrobras.
Petrobras announced a program to construct up to 29 newbuild floaters in Brazilian shipyards. However, in light of the decline of the commodity markets in combination with a widespread corruption scandal involving Petrobras, various drilling contractors and some of the shipyards, a number of these rigs have been cancelled. Currently, it is expected that 18 of the original 29 rigs could still be built. These new drilling units are targeted at pre-salt exploration and development in water depths where our rigs cannot operate. Nevertheless, if the rigs are built and Petrobras shifts more of its capital budget to fund pre-salt activity, it could have a material adverse effect on our drilling units in Brazil. Further, some national oil companies have considered regulations limiting the age of rigs in operation, and if adopted, this could significantly increase our costs or render some of our rigs ineligible for contracts with such companies.
 Our customers may generally terminate our term drilling contracts if a drilling rig is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In the case of nonperformance and under certain other conditions, our drilling contracts generally allow our customers to terminate without any payment to us. The terms of some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. Our drilling 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 late 2015. Due to the recent decline in demand for our services, some of our rigs have completed contracts and remain idle, or have been stacked. When rigs complete a contract without a renewal contract in place, they may be idle or stacked for a prolonged period of time. Any new contracts for such rigs may be at dayrates substantially below existing dayrates or on terms less favorable than existing contract terms, which could have a material adverse effect on our revenues and profitability.
 Our customers, which include many national oil companies, often have significant bargaining leverage over us. During periods of depressed market conditions, we may be subject to an increased risk of our customers seeking to renegotiate or repudiate their contracts, including customers seeking to lower dayrates paid under existing contracts. Recently, Petrobras announced that it reduced its near term capital expenditure budget by 40%, and as a result, it has terminated or amended drilling contracts with us and a number of competitors.
 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.

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Risks Related to our Common Shares
If we cannot meet the continued listing requirements of the NYSE, the NYSE may delist our common shares, which would have an adverse impact on the trading volume, liquidity and market price of our common shares.
 On August 6, 2015, we received a letter from the NYSE notifying us that, for 30 consecutive trading days, the average closing price for our common shares was below the minimum $1.00 per share requirement for continued listing on the NYSE under Item 802.01C of the NYSE’s Listed Company Manual. The notice does not have an immediate effect on the listing of our common shares, and our common shares will continue to trade on the NYSE under the symbol “PGN.” It is also standard for the NYSE to automatically de-list any stock that has any trade (even intra-day) below $0.15 per share. As of November 3, 2015, our common shares closed at a price of $0.24 per share.
We have 180 days, or until February 5, 2016, to regain compliance with the NYSE’s $1.00 minimum share price requirement. We can regain compliance at any time during the six-month cure period if on the last trading day of any calendar month during the cure period our common shares have a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30 trading-day period ending on the last trading day of such month. Notwithstanding the foregoing, if we determine that we must cure the price condition by taking an action that will require approval of our shareholders, we may also regain compliance by: (i) obtaining the requisite shareholder approval by no later than our next annual meeting, (ii) implementing the action promptly thereafter and (iii) the price of our common shares promptly exceeding $1.00 per share, and the price remaining above that level for at least the following 30 trading days.
A delisting of our common shares from the NYSE would negatively impact us because it would: (i) reduce the liquidity and market price of our common shares; (ii) reduce the number of investors willing to hold or acquire our common shares, which could negatively impact our ability to raise equity financing; (iii) limit our ability to use a registration statement to offer and sell freely tradable securities, thereby preventing us from accessing the public capital markets, and (iv) impair our ability to provide equity incentives to our employees.

ITEM 6.
EXHIBITS
The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report on Form 10-Q and is incorporated herein by reference.

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SIGNATURES
Pursuant to the requirements 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
/s/ Randall D. Stilley
 
November 9, 2015
Randall D. Stilley
 
Date
President, Chief Executive Officer and Director
 
 
(Principal Executive Officer)
 
 
 
 
 
/s/ Steven A. Manz
 
November 9, 2015
Steven A. Manz
 
Date
Senior Vice President and Chief Financial Officer
 
 
(Principal Financial Officer)
 
 
 
 
 
/s/ Alejandra Veltmann
 
November 9, 2015
Alejandra Veltmann
 
Date
Vice President and Chief Accounting Officer
 
 
(Principal Accounting Officer)
 
 



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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 Restricted Stock Unit Award Agreement (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 (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).
 
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*
 
Interactive Data Files
 

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

54
Exhibit 31.1


Paragon Offshore plc, a company registered under the laws of England and Wales
I, Randall D. Stilley, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Paragon Offshore plc;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Paragraph omitted in accordance with instructions of the United States Securities and Exchange Commission;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November 9, 2015
 
/s/ Randall D. Stilley
Randall D. Stilley
President, Chief Executive Officer and Director
of Paragon Offshore plc, a company registered under the laws of England and Wales




Exhibit 31.2


Paragon Offshore plc, a company registered under the laws of England and Wales
I, Steven A. Manz, certify that:
1.
I have reviewed this quarterly report on Form 10-Q of Paragon Offshore plc;
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)
Paragraph omitted in accordance with instructions of the United States Securities and Exchange Commission;
c)
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: November 9, 2015
 
/s/ Steven A. Manz
Steven A. Manz
Senior Vice President and Chief Financial Officer
of Paragon Offshore plc, a company registered under the laws of England and Wales



Exhibit 32.1


Paragon Offshore plc, a company registered under the laws of England and Wales
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Paragon Offshore plc, a company registered under the laws of England and Wales (the “Company”), on Form 10-Q for the period ended September 30, 2015, as filed with the United States Securities and Exchange Commission on the date hereof (the “Report”), I, Randall D. Stilley, President, Chief Executive Officer and Director of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
November 9, 2015
 
/s/ Randall D. Stilley
 
 
Randall D. Stilley
 
 
President, Chief Executive Officer and Director
 
 
of Paragon Offshore plc, a company registered under the laws of England and Wales



Exhibit 32.2


Paragon Offshore plc, a company registered under the laws of England and Wales
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Paragon Offshore plc, a company registered under the laws of England and Wales (the “Company”), on Form 10-Q for the period ended September 30, 2015, as filed with the United States Securities and Exchange Commission on the date hereof (the “Report”), I, Steven A. Manz, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
 
November 9, 2015
 
/s/ Steven A. Manz
 
 
Steven A. Manz
 
 
Senior Vice President and Chief Financial Officer
 
 
of Paragon Offshore plc, a company registered under the laws of England and Wales




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