PARAGON OFFSHORE PLC - FORM 10-Q

PARAGON OFFSHORE PLC - FORM 10-Q - August 13, 2015

Attached files

Attached files

PARAGON OFFSHORE PLC Reports

file	filename
EX-32.1 - SECTION 906 CEO CERTIFICATION - PARAGON OFFSHORE PLC	a2015q2exhibit321.htm
EX-31.2 - SECTION 302 CFO CERTIFICATION - PARAGON OFFSHORE PLC	a2015q2exhibit312.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - PARAGON OFFSHORE PLC	a2015q2exhibit311.htm
EX-32.2 - SECTION 906 CFO CERTIFICATION - PARAGON OFFSHORE PLC	a2015q2exhibit322.htm

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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: June 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 ¨
Non-accelerated filer x			Smaller reporting company ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Number of shares outstanding and trading at July 31, 2015: 85,985,541

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PARAGON OFFSHORE plc

FORM 10-Q

For the Quarter Ended June 30, 2015

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		PAGE
PART I	FINANCIAL INFORMATION	3
Item 1	Unaudited Consolidated and Combined Financial Statements
	Consolidated and Combined Statements of Income for the three and six months ended June 30, 2015 and 2014	3
	Consolidated and Combined Statements of Comprehensive Income for the three and six months ended June 30, 2015 and 2014	4
	Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	5
	Consolidated and Combined Statements of Changes in Equity for the six months ended June 30, 2015 and 2014	6
	Consolidated and Combined Statements of Cash Flows for the six months ended June 30, 2015 and 2014	7
	Notes to Unaudited Consolidated and Combined Financial Statements	8
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operation	26
Item 3	Quantitative and Qualitative Disclosures About Market Risk	43
Item 4	Controls and Procedures	44

PART II	OTHER INFORMATION
Item 1	Legal Proceedings	45
Item 1A	Risk Factors	45
	SIGNATURES	48
	Index to Exhibits	49

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PART I.	FINANCIAL INFORMATION


ITEM 1.	UNAUDITED CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

PARAGON OFFSHORE plc

CONSOLIDATED AND COMBINED STATEMENTS OF INCOME

(In thousands, except per share amounts)

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Operating revenues
Contract drilling services	$	363,089		$	462,334		$	762,908		$	954,297
Labor contract drilling services	7,206			8,146			14,371			16,357
Reimbursables and other	22,949			8,477			46,613			22,893
	393,244			478,957			823,892			993,547
Operating costs and expenses
Contract drilling services	196,969			222,317			422,074			448,780
Labor contract drilling services	5,681			6,223			11,294			12,436
Reimbursables	18,678			5,224			38,656			15,850
Depreciation and amortization	94,673			112,536			184,748			223,120
General and administrative	13,737			12,683			29,101			25,928
Loss on impairment	1,701			—			1,701			—
(Gain) loss on disposal of assets, net	4,078			—			(12,717		)	—
(Gain) on repurchase of long-term debt	—			—			(4,345		)	—
	335,517			358,983			670,512			726,114
Operating income	57,727			119,974			153,380			267,433
Other income (expense)
Interest expense, net of amount capitalized	(29,042		)	(2,972		)	(59,237		)	(6,272		)
Interest income and other, net	169			338			2,434			525
Income before income taxes	28,854			117,340			96,577			261,686
Income tax benefit (provision)	18,477			(22,292		)	11,912			(42,075		)
Net income	$	47,331		$	95,048		$	108,489		$	219,611
Net income attributable to non-controlling interest	—			—			(31		)	—
Net income attributable to Paragon Offshore	$	47,331		$	95,048		$	108,458		$	219,611

Earnings per share
Basic and diluted	$	0.51		$	1.12		$	1.19		$	2.59

Weighted-average shares outstanding
Basic and diluted	85,836			84,753			85,549			84,753

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

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PARAGON OFFSHORE plc

CONSOLIDATED AND COMBINED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

(Unaudited)



	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
Net income	$	47,331		$	95,048	$	108,489		$	219,611
Other comprehensive income (loss), net of tax
Foreign currency translation adjustments	525			63		(1,673		)	27
Net pension plan gain	192			—		389			—
Amortization of deferred pension plan amounts	(4		)	—		(9		)	—
Total other comprehensive income (loss), net	713			63		(1,293		)	27
Total comprehensive income	$	48,044		$	95,111	$	107,196		$	219,638

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

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PARAGON OFFSHORE plc

CONSOLIDATED BALANCE SHEETS

(In thousands)

(Unaudited)



	June 30,			December 31,
	2015			2014
ASSETS
Current assets
Cash and cash equivalents	$	112,359		$	56,772
Restricted cash	—			12,502
Accounts receivable, net of allowance for doubtful accounts	356,132			539,376
Prepaid and other current assets	99,531			104,644
Total current assets	568,022			713,294
Property and equipment, at cost	4,883,872			4,842,112
Accumulated depreciation	(2,565,412		)	(2,431,752		)
Property and equipment, net	2,318,460			2,410,360
Other assets	138,365			129,735
Total assets	$	3,024,847		$	3,253,389

LIABILITIES AND EQUITY
Current liabilities
Current maturities of long-term debt	$	6,500		$	272,166
Accounts payable	131,370			160,874
Accrued payroll and related costs	50,868			81,416
Taxes payable	63,107			69,033
Interest payable	28,837			33,658
Other current liabilities	68,601			105,147
Total current liabilities	349,283			722,294
Long-term debt	1,984,421			1,888,439
Deferred income taxes	39,034			58,497
Other liabilities	53,945			89,910
Total liabilities	2,426,683			2,759,140
Commitments and contingencies
Equity
Ordinary shares, $0.01 par value, 186,457,393 shares authorized; with 85,985,541 and 84,753,393 issued and outstanding at June 30, 2015 and December 31, 2014, respectively	860			848
Additional paid-in capital	1,422,532			1,423,153
Retained deficit	(786,791		)	(895,249		)
Accumulated other comprehensive loss	(38,437		)	(37,144		)
Total shareholders’ equity	598,164			491,608
Non-controlling interest	—			2,641
Total equity	598,164			494,249
Total liabilities and equity	$	3,024,847		$	3,253,389

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

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PARAGON OFFSHORE plc

CONSOLIDATED AND COMBINED STATEMENTS OF CHANGES IN EQUITY

(In thousands)

(Unaudited)



	Ordinary Shares			Additional Paid-in Capital			Retained Earnings/ (Deficit)			Accumulated Other Comprehensive Income/(Loss)			Net Parent Investment			Total Stockholders’ Equity and Net Parent Investment			Non-controlling Interest			Total Equity
	Shares	Amount		Additional Paid-in Capital			Retained Earnings/ (Deficit)			Accumulated Other Comprehensive Income/(Loss)			Net Parent Investment			Total Stockholders’ Equity and Net Parent Investment			Non-controlling Interest			Total Equity
Balance at December 31, 2013	—	$	—	$	—		$	—		$	(6	)	$	2,005,339		$	2,005,333		$	—		$	2,005,333
Net income	—	—		—			—			—			219,611			219,611			—			219,611
Net transfers to parent	—	—		—			—			—			(996,263		)	(996,263		)	—			(996,263		)
Foreign currency translation adjustments	—	—		—			—			27			—			27			—			27
Balance at June 30, 2014	—	$	—	$	—		$	—		$	21		$	1,228,687		$	1,228,708		$	—		$	1,228,708

Balance at December 31, 2014	84,753	$	848	$	1,423,153		$	(895,249	)	$	(37,144	)	$	—		$	491,608		$	2,641		$	494,249
Net income	—	—		—			108,458			—			—			108,458			31			108,489
Adjustments to distribution by former parent	—	—		(9,493		)	—			—			—			(9,493		)	—			(9,493		)
Employee related equity activity
Amortization of share-based compensation	—	—		9,154			—			—			—			9,154			—			9,154
Issuance of share-based compensation shares	1,233	12		(769		)	—			—			—			(757		)	—			(757		)
Acquisition of Prospector non-controlling interest	—	—		487			—			—			—			487			(2,672		)	(2,185		)
Other comprehensive loss, net	—	—		—			—			(1,293		)	—			(1,293		)	—			(1,293		)
Balance at June 30, 2015	85,986	$	860	$	1,422,532		$	(786,791	)	$	(38,437	)	$	—		$	598,164		$	—		$	598,164

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

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PARAGON OFFSHORE plc

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)



	Six Months Ended
	June 30,
	2015			2014
Cash flows from operating activities
Net income	$	108,489		$	219,611
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization	184,748			223,120
Loss on impairment	1,701			—
Gain on disposal of assets, net	(12,717		)	—
Gain on repurchase of long-term debt	(4,345		)	—
Deferred income taxes	(27,352		)	(4,640		)
Share-based compensation	9,705			11,757
Provision for doubtful accounts	14,302			—
Net change in other assets and liabilities	32,489			(44,160		)
Net cash provided by operating activities	307,020			405,688
Cash flows from investing activities
Capital expenditures	(113,071		)	(110,687		)
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	12,502			—
Change in accrued capital expenditures	(12,533		)	13,594
Net cash used in investing activities	(85,971		)	(90,523		)
Cash flows from financing activities
Net change in borrowings on Predecessor bank credit facilities	—			707,472
Net change in borrowings outstanding on Revolving Credit Facility	211,000			—
Repayment of Term Loan Facility	(3,250		)	—
Repayment of Prospector Senior Credit Facility	(265,666		)	—
Repayment of Prospector Bonds	(101,000		)	—
Purchase of Senior Notes	(6,546		)	—
Debt issuance costs	—			(386		)
Net transfers to parent	—			(1,026,144		)
Net cash used in financing activities	(165,462		)	(319,058		)
Net change in cash and cash equivalents	55,587			(3,893		)
Cash and cash equivalents, beginning of period	56,772			36,581
Cash and cash equivalents, end of period	$	112,359		$	32,688
Supplemental information for non-cash activities
Transfer from parent of property and equipment	—			18,124
Adjustments to distributions by former parent	9,493			—

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

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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.

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. 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 $100 million par value of Prospector’s 2019 Second Lien Callable Bond (“Prospector Bonds”) and Prospector’s 2018 Senior Secured Credit Facility (“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.

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 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 for the construction of three newbuild high specification jackup rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China. These rigs are currently scheduled for delivery in the third quarter of 2015, first quarter of 2016 and second 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.

Prospector’s results of operations were included in our results beginning on November 17, 2014. The following unaudited pro forma financial information for the three and six months ended June 30, 2014, gives effect to the Prospector acquisition as if it had occurred at the beginning of the comparable period presented. The pro forma results are based on historical data and are not intended to be indicative of the results of future operations.

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	Three Months Ended		Six Months Ended
(In thousands, except per share amounts)	June 30, 2014
Total operating revenues	$	488,620	$	1,004,962
Net income	70,342		178,265
Earnings per share (basic and diluted)	$	0.83	$	2.10

Revenues and operating expenses generated by 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 six months ended June 30, 2015 were $35 million and $67 million, respectively. Operating expenses for these rigs, including depreciation expense of $5 million and $10 million, for the three and six months ended June 30, 2015 totaled $21 million and $45 million, respectively.

Basis of Presentation

Included in this Quarterly Report on Form 10-Q of Paragon Offshore plc are the condensed consolidated and combined interim financial statements and notes (“Interim Condensed Financial Statements”) of Paragon Offshore plc and its subsidiaries. The Interim Condensed Financial Statements 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 condensed 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 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.

The consolidated and combined financial information contained in this report includes periods that ended prior to the Spin-Off on August 1, 2014. For all periods prior to the Spin-Off, the combined financial statements and related discussion of financial condition and results of operations contained in this report pertain to the historical results of Noble's standard specification business (our “Predecessor”), which comprised the entire standard specification drilling fleet and related operations of Noble. Our Predecessor’s historical combined financial statements include three standard specification drilling units that were retained by Noble and three standard specification drilling units that were sold by Noble prior to the Separation.

Our Predecessor’s historical combined financial statements for the periods prior to the Spin-Off include assets and liabilities that are specifically identifiable or have been allocated to our Predecessor. Revenues and costs directly related to our Predecessor have been included in the accompanying 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 combined statements may not be indicative of the actual expenses that would have been incurred during the periods presented if our Predecessor had operated as a separate standalone entity and may not be indicative of expenses that will be incurred in the future by us. These allocated costs are primarily related to corporate administrative expenses including executive oversight, employee related costs including pensions and other benefits, and corporate and shared employees for the following functional groups:


•	information technology,


•	legal, accounting, finance and treasury services,


•	human resources,


•	marketing, and


•	other corporate and infrastructural services.

We consolidate the historical combined financial results of our Predecessor in our 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.

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

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and liabilities were transferred between us and Noble, which have been recorded as part of the net capital contributed by Noble. During the first quarter of 2015, we recorded an out-of-period adjustment to the opening balance sheet of our Predecessor of approximately $9 million to reflect transfers of fixed assets resulting from the Spin-Off between us and our former parent, as well as revisions in estimates of liabilities associated with the Spin-Off. This adjustment did not affect our Consolidated and Combined Statement of Income.

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 $0.1 million and $2 million at June 30, 2015 and December 31, 2014, respectively, are included in “Accounts payable” on our Consolidated Balance Sheets.

Summary of Significant Accounting Policies and Estimates

Our 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 policy and estimate 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 $15 million and $1 million at June 30, 2015 and December 31, 2014, respectively. Bad debt expense of $5 million and $14 million was recorded for the three and six months ended June 30, 2015. No bad debt expense was recorded for the three and six months ended June 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 Income for the three and six months ended June 30, 2015.

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, borrowings under our senior secured revolving credit facility, 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, to service our outstanding indebtedness, acquisitions and to pay future dividends.

At June 30, 2015, we had $112 million of cash on hand and $343 million of committed financing available under our senior secured revolving credit facility, which will expire in 2019. 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, the remaining principal balance outstanding under the Prospector Senior Credit Facility in the amount of $261 million, including accrued interest, was paid in full through the use of cash on hand and borrowings under our senior secured revolving credit facility.

At June 30, 2015, we have purchase commitments of $199 million and $400 million currently due in 2015 and 2016, respectively, related to the construction of the three high specification jackup rigs as mentioned in the Prospector acquisition above. In July 2015, we agreed with SWS to an extension of the delivery of the Prospector 6 to the second quarter of 2016. 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 rig, we will lose ownership of that rig, at which time, the associated costs currently capitalized (primarily representing down-payments on these rigs) on our balance sheet will be written off. At June 30, 2015, we had approximately $42 million in capitalized costs associated with these three rigs.

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aggregate amount of rental payments equal to approximately $373 million over the course of the five-year lease terms for the two rigs (see Note 17, “Subsequent event”).

Our debt facilities are subject to financial and non-financial covenants. While we currently satisfy our covenants, current market conditions, including any future contract amendments with Petróleo Brasileiro S.A. (“Petrobras”) or other customers, may prevent us from maintaining compliance. There are measures within our control to help maintain compliance with these financial and non-financial covenants, such as reducing our operating and capital expenditures or seeking a waiver on the covenants from our lenders; however, there is no assurance that these alternatives would be available. Any corrective measures that we do implement may prove inadequate and, even if effective, could have negative long-term consequences to our business. Prospector has been designated as an unrestricted subsidiary under our Revolving Credit Facility, Term Loan Facility, and Senior Notes. 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 these debt facilities.

Our ability to continue to fund our operations will be affected by general economic, competitive and other factors, including any future contract amendments with Petrobras or other customers, many of which are outside of our control. To the extent current 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.

NOTE 2—NEW ACCOUNTING PRONOUNCEMENTS

In May 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-09, which amends ASC Topic 606, Revenue from Contracts with Customers. The amendments in this ASU are intended to provide a more robust framework for addressing revenue issues, improve comparability of revenue recognition practices and improve disclosure requirements. The amendments in this accounting standard update are effective for interim and annual reporting periods beginning after December 15, 2016. In April 2015, the FASB issued ASU No. 2015-24, Revenue from Contracts with Customers: Deferral of the Effective Date which proposed a deferral of the effective date by one year, and on July 7, 2015, the FASB decided to delay the effective date by one year. The deferral results in the new revenue standard being effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. We are therefore required to apply the new revenue guidance beginning in our 2018 interim and annual financial statements. 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 (that is, no earlier than 2017 for calendar year-end 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 footnote 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. We are evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures.

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

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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. 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 debt issuance costs related to our term debt and revolver of $29 million and $31 million included in “Other Assets” on our Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014, respectively.

NOTE 3—PROPERTY AND EQUIPMENT

Our capital expenditures, including capitalized interest, totaled $62 million and $113 million for the three and six months ended June 30, 2015, respectively, as compared to historical Predecessor capitalized expenditures, including capitalized interest, of $68 million and $111 million for the three and six months ended June 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 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 defined in Note 7, “Debt”). Interest capitalized in these consolidated and combined financial statements for the three and six months ended June 30, 2015 was $0.04 million and $0.1 million, respectively, as compared to Predecessor capitalized interest of $1 million and $2 million for the three and six months ended June 30, 2014.

Loss on Impairment

We have entered into negotiations to sell the Paragon MSS3, Paragon B153, and Paragon DPDS4. During the three and six months ended June 30, 2015, we recognized a total impairment loss of $2 million with respect to the Paragon MSS3 and the Paragon B153. We did not record an impairment loss on the Paragon DPDS4 in 2015. We estimated the fair value of these units using significant other observable inputs, representative of Level 2 fair value measurements, based on indicative market values for the drilling units.

Disposal of Assets

During the three months ended June 30, 2015, we completed the sale of the Paragon FPSO1 for $3.5 million to an unrelated third party. As of June 30, 2015, the carrying value of the rig, inclusive of an impairment charge taken in the prior fiscal year, approximated its sales price.

During the three months ended June 30, 2015, we identified drill pipe that we would no longer utilize in our operations. We sold these items for $2 million and recorded a pre-tax loss of approximately $4 million.

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.

If we commit to plans to sell or scrap additional rigs, we may be required to recognize additional losses in future periods associated with the impairment of such assets.

NOTE 4—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 $10 million at June 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

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Sheets, based upon the expected time of recognition of such deferred revenues. Deferred costs associated with deferred revenues from drilling contracts totaled $4 million at June 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 5—SHARE-BASED COMPENSATION

Predecessor Plan

For all periods prior to the Spin-Off, our Predecessor was managed in the normal course of business by Noble and its subsidiaries. Noble provides a stock-based compensation plan 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 16, “Related Parties (Including Relationship with Parent and Corporate Allocations)” for total costs allocated to us by Noble).

Paragon employees’ participation in Noble’s 1991 Stock Option and Restricted Stock Plan (“Noble 1991 Plan”) was terminated 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 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 June 30, 2015 are as follows (excluding the impact of cash-settled awards):

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

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 remeasured on each balance sheet date and total compensation for units that ultimately vest is recognized over the service period.

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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 Company 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 six months ended June 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	(1,571,382	)	9.40		—				—	—
Forfeited	(112,031	)	9.44		(113,099	)			—	—
Outstanding at June 30, 2015	6,188,272		$	5.49	3,295,745		$	1.09	849,484	$	5.31


(1)	This column includes 693,640 shares outstanding at June 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 June 30, 2015 at which both our CS-TVRSU’s and TVRSU’s granted under our Director Plan are remeasured.


(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 six months ended June 30, 2015 totaled $5 million and $10 million, respectively. At June 30, 2015, we had $26 million of total unrecognized compensation cost related to our TVRSU’s, which is expected to be recognized over a remaining weighted-average period of 2.1 years. At June 30, 2015, we had $3 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 2.6 years. At June 30, 2015, we had $3 million of total unrecognized compensation cost related to our PVRSU’s, which is expected to be recognized over a remaining weighted-average period of 2.1 years. The total potential compensation for our PVRSU’s is recognized over the service period regardless of whether the performance thresholds are ultimately achieved.

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NOTE 6—EARNINGS PER SHARE

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

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

The following table sets forth the computation of basic and diluted net income and earnings per share:



	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In thousands, except per share amounts)	2015			2014		2015			2014
Allocation of income - basic and diluted
Net income attributable to Paragon	$	47,331		$	95,048	$	108,458		$	219,611
Earnings allocated to unvested share-based payment awards	(3,532		)	—		(6,611		)	—
Net income to ordinary shareholders - Basic and diluted	$	43,799		$	95,048	$	101,847		$	219,611

Weighted average shares outstanding
Basic and diluted	85,836			84,753		85,549			84,753

Weighted average unvested share-based payment awards	6,922			—		5,553			—

Earnings per share
Basic and diluted	$	0.51		$	1.12	$	1.19		$	2.59

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NOTE 7—DEBT

A summary of long-term debt at June 30, 2015 and December 31, 2014 is as follows:



	June 30,			December 31,
(In thousands)	2015			2014
Revolving Credit Facility	$	365,000		$	154,000
Term Loan Facility, bearing interest at 3.75%, net of unamortized discount	642,339			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
Prospector 2019 Second Lien Callable Bond	—			101,000
Prospector 2018 Senior Secured Credit Facility	—			265,666
Total debt	1,990,921			2,160,605
Less: Current maturities of long-term debt	(6,500		)	(272,166		)
Long-term debt	$	1,984,421		$	1,888,439

Senior Notes, Term Loan Facility and Revolving Credit Facility

On June 17, 2014, we entered into a senior secured revolving credit agreement with lenders that provided commitments in the amount of $800 million (the “Revolving Credit Facility”). The Revolving Credit Facility has a term of five years 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 up to $800 million of letters of credit. Issuance of letters of credit under the Revolving Credit Facility would reduce a corresponding amount available for borrowing. As of June 30, 2015, we had $365 million in borrowings outstanding at a weighted-average interest rate of 2.40%, and an aggregate amount of $92 million of letters of credit issued under the Revolving Credit Facility.

On July 18, 2014, we issued $1.08 billion of senior notes (the “Senior Notes”) and also borrowed $650 million under a term loan facility (the “Term Loan Facility”). The Term Loan Facility is secured by all of our rigs. The proceeds from the Term Loan Facility and the Senior Notes were used to repay $1.7 billion of intercompany indebtedness to Noble incurred as partial consideration for the Separation. The Senior Notes consisted of $500 million of 6.75% senior notes and $580 million of 7.25% senior notes, which mature on July 15, 2022 and August 15, 2024, respectively. The Senior Notes were issued without an original issue discount. Borrowings under the Term Loan Facility bear interest at an adjusted LIBOR rate plus 2.75%, subject to a minimum LIBOR rate of 1% or a base rate plus 1.75%, at our option. We are required to make quarterly principal payments of $1.6 million and may prepay all or a portion of the Term 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, we incurred $35 million of issuance costs.

Our Revolving Credit Facility, Senior Notes, and Term Loan Facility agreements 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 June 30, 2015, we were in compliance with the covenants under our Revolving Credit Facility by maintaining a net leverage ratio of 2.57 and an interest coverage ratio of 7.51. 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.

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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 quarter of 2015.

Extinguished Obligations

At the time of our acquisition of Prospector, Prospector had the following outstanding debt instruments: (i) 2019 Second Lien Callable Bond of $100 million (“Prospector Bonds”) and (ii) 2018 Senior Secured Credit Facility of $270 million (“Prospector Senior Credit Facility”).

The Prospector Bonds were originally entered into by a subsidiary of Prospector on May 19, 2014 in the Oslo Alternative Bond Market. The Prospector Bonds had a fixed interest rate of 7.75% per annum, payable semi-annually on December 19 and June 19 each year and maturity of June 19, 2019. 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 8—INCOME TAXES

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

The income tax benefit for the three and six months ended June 30, 2015 was $18 million and $12 million, respectively. The provision for income taxes for the three and six months ended June 30, 2014 was $22 million and $42 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 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 and recorded other previously unrealized deferred tax assets that we now

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believe 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 June 30, 2015, the liabilities related to our unrecognized tax benefits, including estimated accrued interest and penalties, totaled $19 million, and if recognized, would reduce our income tax provision by $19 million. At December 31, 2014, the liabilities related to our unrecognized tax benefits totaled $40 million. The decrease in unrecognized tax benefits is primarily attributable to the liability settlement of 2008-2011 for our U.K. operations upon receipt of the formal closure notices dated June 4, 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 9—EMPLOYEE BENEFIT PLANS

During the periods prior to Spin-Off, most of our employees were eligible to participate in various Noble benefit programs. The results of our Predecessor in these consolidated and combined financial statements include an allocation of the costs of such employee benefit plans which is consistent with the accounting for multi-employer plans. These costs were allocated based on our employee population for each of the periods presented. We consider the expense allocation methodology and results to be reasonable for all periods presented; however, the allocated costs included in the results of our Predecessor and included in these consolidated and combined financial statements could differ from amounts that would have been incurred by us if we operated on a standalone basis and are not necessarily indicative of costs to be incurred in the future.

We have instituted competitive compensation policies and programs, as well as carried over certain plans as a standalone public company, the expense for which may differ from the compensation expense allocated by Noble in our Predecessor’s historical combined financial statements.

Defined Benefit Plans

At Spin-Off, Noble sponsored two non-U.S. noncontributory defined benefit pension plans which were carried over by us and cover certain Europe-based salaried, non-union employees. Pension benefit expense related to these plans included in the accompanying consolidated statement of income for the three and six months ended June 30, 2015 totaled $2 million and $3 million, respectively.

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Pension cost includes the following components:



	Three Months Ended			Six Months Ended
	June 30,			June 30,
(In thousands)	2015			2015
Service cost	$	1,361		$	2,736
Interest cost	493			991
Return on plan assets	(449		)	(903		)
Amortization of prior service cost	(5		)	(10		)
Amortization net actuarial loss	191			384
Net pension expense	$	1,591		$	3,198

During the three and six months ended June 30, 2015, we made no contributions to our pension 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 plans included in the accompanying consolidated statement of income during the six months ended June 30, 2015 totaled $0.2 million.

NOTE 10—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 June 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 Income 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 11, “Fair Value of Financial Instruments”). Since these contracts were terminated as of June 30, 2015, we had no amounts outstanding in our Consolidated Balance Sheet related to the interest rate swaps, and for the six months ended June 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.”

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NOTE 11—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 June 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.

The following table presents the estimated fair value of our long-term debt as of June 30, 2015 and December 31, 2014, respectively:



	June 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	$	158,088	$	457,572	$	275,115
7.25% Senior Notes due August 15, 2024	527,010		173,913		537,010		319,521
Total senior unsecured notes	$	983,582	$	332,001	$	994,582	$	594,636

Term Loan Facility, bearing interest at 3.75%, net of unamortized discount	$	642,339	$	483,844	$	645,357	$	523,250

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

The carrying amounts of our variable-rate debt, the Revolving Credit Facility, approximate 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.

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NOTE 12—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 six months ended June 30, 2015 and 2014. All amounts within the tables are shown net of tax.



(In thousands)	Defined Benefit Pension Items (1)			Foreign Currency Items			Total
Balance at December 31, 2013	$	—		$	(6	)	$	(6	)
Activity during period:
Other comprehensive income before reclassification	—			27			27
Net other comprehensive income	—			27			27
Balance at June 30, 2014	$	—		$	21		$	21

Balance at December 31, 2014	$	(22,911	)	$	(14,233	)	$	(37,144	)
Activity during period:
Other comprehensive loss before reclassification	—			(1,673		)	(1,673		)
Amounts reclassified from AOCL	380			—			380
Net other comprehensive income (loss)	380			(1,673		)	(1,293		)
Balance at June 30, 2015	$	(22,531	)	$	(15,906	)	$	(38,437	)

(1)

Defined benefit pension items relate to actuarial losses, prior service credits, and the amortization of actuarial losses and prior service credits. Reclassifications from AOCL are recognized as expense on our Consolidated and Combined Statements of Income through either “Contract drilling services” or “General and administrative.” See Note 9, “Employee Benefit Plans” for additional information.

NOTE 13—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 June 30, 2015, we have received tax audit claims of approximately $256 million, of which $50 million is subject to indemnity by Noble, primarily in Mexico and Brazil, attributable to our income, customs and other business taxes. In addition, as of June 30, 2015, approximately $38 million of tax audit claims in Mexico assessed against Noble are subject to indemnity by us as a result of the Spin-Off. On July 21, 2015, we received notice of an additional assessment from Mexico for $126 million, of which $43 million is subject to indemnity by Noble. We have contested, or intend to contest, these assessments, including through litigation if necessary. Tax authorities may issue additional assessments or pursue legal actions as a result of tax audits, and we cannot predict or provide assurance as to the ultimate outcome of such assessments and legal actions. In some cases we will be required to post a surety bond or a letter of credit as collateral while we defend these claims. Although we have no surety bonds or letters of credit associated with tax audit claims outstanding as of June 30, 2015, we could be required to post them during 2015, and such amounts could be substantial and could have a material adverse effect on our liquidity, financial condition, results of operations and cash flows.

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 $91 million, of which $26 million is subject to indemnity by Noble. Petrobras has also notified us that

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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 admitted to participation in illegal activity in Brazil in connection with the award of a drilling contract to a competitor, and has implicated several individuals, including at least one Petrobras official, 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 adequately cover our losses or may have exclusions of coverage for some losses. We do not have insurance coverage or rights to indemnity for all risks, including loss of hire insurance on most of the rigs in our fleet. Uninsured exposures may include expatriate activities prohibited by U.S. laws and regulations, radiation hazards, certain loss or damage to property on board our rigs and losses relating to shore-based terrorist acts or strikes. If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity, it could materially adversely affect our financial position, results of operations or cash flows. Additionally, there can be no assurance that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all these risks.

Capital Expenditures

In connection with our capital expenditure program, we have outstanding commitments, including shipyard and purchase commitments of approximately $636 million at June 30, 2015. Our purchase commitments consist of obligations outstanding to external vendors primarily related to future capital purchases and includes $199 million in 2015 and $400 million in 2016 related to the three high-specification jackup rigs under construction.

Other

At June 30, 2015, we had letters of credit of $102 million and performance bonds totaling $113 million supported by surety bonds outstanding and backed by $73 million 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;

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•	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 consist of the following balances due from and to Noble as of June 30, 2015 and December 31, 2014:



	June 30,		December 31,
(In thousands)	2015		2014
Other current assets	$	16,514	$	26,386
Other assets	7,110		6,875
Due from Noble	$	23,624	$	33,261

Accounts payable	$	120	$	1,655
Other current liabilities	37,226		51,169
Other liabilities	3,268		23,563
Due to Noble	$	40,614	$	76,387

These receivables and payables primarily relate to rights and obligations under the Master Separation and Tax Sharing Agreements.

Master Separation Agreement

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

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

Transition Services Agreement (Brazil)

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

NOTE 14—SUPPLEMENTAL CASH FLOW INFORMATION

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



	Six Months Ended
	June 30,
(In thousands)	2015			2014
Accounts receivable	$	168,942		$	(8,003	)
Other current assets	5,113			(6,704		)
Other assets	(7,710		)	2,962
Accounts payable	(16,572		)	(14,683		)
Other current liabilities	(78,866		)	(12,483		)
Other liabilities	(38,418		)	(5,249		)
Net change in other assets and liabilities	$	32,489		$	(44,160	)

NOTE 15—SEGMENT AND RELATED INFORMATION

At June 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 16—RELATED PARTIES (INCLUDING RELATIONSHIP WITH PARENT AND CORPORATE ALLOCATIONS)

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

Allocated costs include, but are not limited to: corporate accounting, human resources, information technology, treasury, legal, employee benefits and incentives (excluding allocated postretirement benefits described in “Note 9, Employee Benefit Plans,”) and stock-based compensation. Our Predecessor’s allocated costs included in contract drilling services in the

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accompanying combined statement of income totaled $35 million and $69 million for the three and six months ended June 30, 2014. Our Predecessor’s allocated costs included in general and administrative expenses in the accompanying combined statement of income totaled $12 million and $24 million for the three and six months ended June 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 Statement of Income for the three and six months ended June 30, 2015.

NOTE 17—SUBSEQUENT EVENT

On June 3, 2015, we entered into a combined $300 million transaction (the “Sale-Leaseback Transaction”) with subsidiaries of SinoEnergy (collectively, the “Lessors”) for our two heavy-duty, harsh-environment jackup units, Prospector 1 and Prospector 5 (collectively, the “Rigs”). The Sale-Leaseback Transaction closed on July 24, 2015. 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	$	26	$	51	$	41	$	33	$	31	$	191	$	373

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”). 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.

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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 June 30, 2015 and for the three and six months ended June 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 the entire standard specification drilling fleet and related operations of Noble. 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

Despite an improvement during the second 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 rose approximately 15% from $55.11 per barrel on March 31, 2015 to $63.59 per barrel on June 30, 2015, but prices have declined since the end of the second quarter 2015. As of August 10, 2015, oil prices have dropped to $50.12 per barrel. The Greek crisis, Iranian nuclear negotiations, and general economic and industry conditions in China, Brazil, and Mexico have all contributed to significant uncertainty in both global and local demand and supply, and in light of this highly volatile commodity price environment, oil and gas companies, including supermajors, independents, and national oil companies, have continued to reduce exploration and development activity.

The drilling industry continues to experience reduced contracting activity compared to the comparable period in 2014. According to industry data, there were 77 new jackup contract announcements or fixtures during the second quarter of 2014 compared to 43 new fixtures during the second quarter of 2015. In the floater segment, there were 35 floater fixtures during the second quarter of 2014 compared to 22 new fixtures and 3 renegotiations during the second quarter of 2015. Average dayrates for new fixtures also continued to decline for rigs where data has been published by third party services. During the second quarter 2014, dayrates for new jackup fixtures averaged approximately $142,000 per day compared to $119,000 in the first quarter of 2015 and $111,000 in the second quarter of 2015. Dayrates for new floater fixtures also continued to steadily decrease from $393,000 in the second quarter of 2014 to approximately $342,000 in the first quarter of 2015 and approximately $309,000 in the second quarter of 2015.

Drilling contractors also continue to engage in contract renegotiation discussions to reduce dayrates. During the second quarter of 2015, industry sources reported 28 jackups with existing contracts where customers and drilling contractors agreed to reduce dayrates. 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. It is possible that the industry, including Paragon, could see additional renegotiations or cancellations of contracts.

During the quarter, 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 three remaining drilling rigs operating in Mexico.

Recently, Petróleo Brasileiro S.A. (“Petrobras”) announced that it has reduced its near term capital expenditure budget by 40%, and as a result, it has terminated or amended drilling contracts with a number of competitors. Petrobras has indicated

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to us that it may contest 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. We continue to discuss the matter with Petrobras and will vigorously pursue all legal remedies available to us under these contracts. As of June 30, 2015, these drilling contracts constitute $493 million of our contract drilling services backlog with them. Any material changes in these contract terms will have a material impact on our financial position.

As of July 20, 2015, there were 124 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 combined financial statements for all periods prior to the Spin-Off. Our Predecessor comprises the entire standard specification drilling fleet and related operations of Noble. Three of Noble’s standard specification drilling units included in the results of our Predecessor were retained by Noble and three were sold by Noble prior to the Separation. In addition, our Predecessor’s historical combined financial statements may also not be reflective of what our results of operations, effective tax rate, comprehensive income, financial position, equity or cash flows would have been as a standalone public company as a result of the matters discussed below.

Acquisition of Prospector Offshore Drilling S. A.

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rigs by Shanghai Waigaoqiao Ship Co. Ltd. (“SWS”) in China. These rigs are currently scheduled for delivery in the third quarter of 2015, first quarter of 2016 and second 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 June 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⁾	$	615	$	222		$	282		$	111		$	—
Jackups ⁽²⁾	972		409			349			172			42
Total	$	1,587	$	631		$	631		$	283		$	42
Percent of available days committed ⁽³⁾			55		%	26		%	14		%	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 $38 million. Petrobras has indicated to us that it may contest 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. As of June 30, 2015, these drilling contracts constitute $493 million of our contract drilling services backlog with them.


(2)	Pemex has the ability to cancel its drilling contracts on 30 days’ notice without Pemex making an early termination payment. Currently, our drilling contracts with Pemex constitute $20 million and $5 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, and the Paragon DPDS4, 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 June 30, 2015, our contract drilling services backlog did not include any letters of intent.

We calculate backlog for any given rig and period by multiplying the full contractual operating dayrate for such rig by the number of days remaining in the period. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts.

The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods set forth in the table above due to various factors, including, but not limited to, 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

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a result, our backlog as of any particular date may not be indicative of our actual revenues for the periods for which the backlog is calculated.

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RESULTS OF OPERATIONS

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 June 30, 2015 and 2014

Our results of operations for the three months ended June 30, 2015 consist entirely of the consolidated results of Paragon while our results of operations for the three months ended June 30, 2014 consist entirely of the combined results of our Predecessor. The results for the three months ended June 30, 2015 also include the results of Prospector.

Net income for three months ended June 30, 2015 was $47 million, or $0.51 per diluted share, on operating revenues of $393 million, compared to net income for three months ended June 30, 2014 of $95 million, or $1.12 per diluted share, on operating revenues of $479 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 June 30, 2015 (the “Current Quarter”) and for the three months ended June 30, 2014 (the “Comparable Quarter”):



	Average Rig Utilization (1)				Operating Days (2)				Average Dayrates
	Three Months Ended				Three Months Ended				Three Months Ended
	June 30,				June 30,		Change		June 30,				Change
	2015		2014		2015	2014	%		2015		2014		%

Jackups	64	%	76	%	1,989	2,492	(20	)%	$	123,556	$	113,125	9	%
Floaters (3)	83	%	78	%	455	637	(29	)%	257,764		283,221		(9	)%
Total (4)	67	%	76	%	2,444	3,129	(22	)%	$	148,537	$	147,752	1	%


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


(2)	Information reflects the number of days that our rigs were operating under contract. The rigs retained or sold by Noble contributed 182 operating days for the three months ended June 30, 2014.


(3)	Average rig utilization calculation reflects 182 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 June 30, 2014.


(4)	Amounts exclude the Paragon FPSO1.

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Operating Results

The following table sets forth our operating results for the three months ended June 30, 2015 and 2014.



	Three Months Ended
	June 30,				Change
(Dollars in thousands)	2015		2014		$			%

Operating Revenues
Contract drilling services	$	363,089	$	462,334	$	(99,245	)	(21	)%
Labor contract drilling services	7,206		8,146		(940		)	(12	)%
Reimbursables/Other (1)	22,949		8,477		14,472			171	%
	393,244		478,957		(85,713		)	(18	)%
Operating costs and expenses:
Contract drilling services	$	196,969	$	222,317	$	(25,348	)	(11	)%
Labor contract drilling services	5,681		6,223		(542		)	(9	)%
Reimbursables (1)	18,678		5,224		13,454			258	%
Depreciation and amortization	94,673		112,536		(17,863		)	(16	)%
General and administrative	13,737		12,683		1,054			8	%
Loss on impairment	1,701		—		1,701			**
Loss on disposal of assets, net	4,078		—		4,078			**
	335,517		358,983		(23,466		)	(7	)%
Operating Income (2)	$	57,727	$	119,974	$	(62,247	)	(52	)%


**	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 $42 million and $30 million, respectively, for the three months ended June 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 $108 million. This decrease was only slightly offset by a 1% increase in average dayrates which increased revenues by $9 million.

The decrease in contract drilling services revenues was attributable to both our floaters and jackups which experienced $63 million and $36 million decrease, respectively, in revenues in the Current Quarter as compared to the Comparable Quarter.

The decrease in floater revenues of $63 million in the Current Quarter was driven by a 29% decrease in operating days coupled with a 9% decrease in average dayrates which resulted in a $52 million and a $11 million decrease in revenues, respectively, from the Comparable Quarter.

The decrease in both average dayrates and operating days for our floaters was primarily due to the Noble Driller, which was retained by Noble after the Separation. Also, the Paragon DPDS1 was uncontracted for all of the Current Quarter but experienced full utilization in Brazil during the Comparable Quarter.

The $36 million decrease in jackup revenues in the Current Quarter was driven by a 20% decrease in jackup operating days which resulted in a $57 million decrease in revenues. This decline was partially offset by a 9% increase in average dayrates which positively impacted revenues by $21 million from the Comparable Quarter.

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The decrease in jackup operating days was due to our rigs in Mexico, including the Paragon M821, the Paragon M823, the Paragon M531, and the Paragon L1114, which were uncontracted for all of the Current Quarter but experienced close to 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. In January 2015, we sold the Paragon M822 which worked 39 days in the Comparable Quarter. The remaining decrease in operating days is due to the Paragon L784 currently in the Middle East, the Paragon L785 currently in Southeast Asia, the Paragon M826 currently in West Africa, and the Paragon C20052 and Paragon B391 both currently in the North Sea 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 182 additional operating days in the Current Quarter due to the Prospector 1 and Prospector 5 operating in the North Sea and 156 additional operating days in the Current Quarter due to the Paragon L782 and the Paragon M825 operating in West Africa.

The increase in average dayrates for our jackups resulted from the addition of contracts for the Prospector 1, the Prospector 5 and other contracts entered into during the second half of 2014 in the shallow water market, particularly for our rigs in the North Sea and West Africa.

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 two high-specification jackups added as a result of the Prospector acquisition.

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 $14 million increase in reimbursable revenues and the related $13 million increase in reimbursable costs in the Current Quarter from the Comparable Quarter were primarily due to transition support services we have provided, on a cost-plus basis, to Noble’s remaining Brazil operations. We will continue to provide both rig-based and shore-based support services to Noble through the term of Noble’s existing rig contract and pursuant to the transition service agreement for Brazil (See Note 13 — “Commitments and Contingencies” for additional detail).

Depreciation and Amortization — The $18 million decrease in depreciation and amortization in the Current Quarter was primarily attributable to lower depreciation in the Current Quarter 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 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 higher than the Comparable Quarter due to costs associated with our operating as a standalone public company.

Loss on Impairment — We have entered into negotiations to sell the Paragon MSS3, Paragon B153, and Paragon DPDS4. During the three months ended June 30, 2015, we recognized a total impairment loss of $2 million with respect to the Paragon MSS3 and the Paragon B153. We do not expect an impairment loss on the Paragon DPDS4. We estimated the fair value of these units using significant other observable inputs, representative of Level 2 fair value measurements, based on indicative market values for the drilling units.

Loss on disposal of assets, net — Loss on disposal of assets, net during the Current Quarter was primarily attributable to the sale and disposal of drill pipe to an unrelated third party.

Other Expenses

Income tax provision — Our income tax provision decreased $41 million in the Current Quarter compared to the Comparable Quarter, primarily due to a $88 million decrease in pre-tax book income and underlying changes in the profitability mix of our operations in various jurisdictions, including current year projected losses in certain jurisdictions and certain favorable discrete tax items in the Current Quarter.

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For the Six Months Ended June 30, 2015 and 2014

Our results of operations for the six months ended June 30, 2015 consist entirely of the consolidated results of Paragon while our results of operations for the six months ended June 30, 2014 consist entirely of the combined results of our Predecessor. The results for the six months ended June 30, 2015 also include the results of Prospector.

Net income for six months ended June 30, 2015 was $108 million, or $1.19 per diluted share, on operating revenues of $824 million, compared to net income for six months ended June 30, 2014 of $220 million, or $2.59 per diluted share, on operating revenues of $994 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 six months ended June 30, 2015 (the “Current Period”) and for the six months ended June 30, 2014 (the “Comparable Period”):



	Average Rig Utilization (1)				Operating Days (2)				Average Dayrates
	Six Months Ended				Six Months Ended				Six Months Ended
	June 30,				June 30,		Change		June 30,				Change
	2015		2014		2015	2014	%		2015		2014		%

Jackups	68	%	80	%	4,164	5,193	(20	)%	$	125,168	$	112,717	11	%
Floaters (3)	83	%	78	%	905	1,267	(29	)%	267,110		291,184		(8	)%
Total (4)	70	%	79	%	5,069	6,460	(22	)%	$	150,511	$	147,718	2	%


(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 431 operating days for the six months ended June 30, 2015.


(3)	Average rig utilization calculation reflects 362 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 six months ended June 30, 2015.


(4)	Amounts exclude the Paragon FPSO1.

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Operating Results

The following table sets forth our operating results for the six months ended June 30, 2015 and 2014.



	Six Months Ended
	June 30,					Change
(Dollars in thousands)	2015			2014		$			%

Operating Revenues
Contract drilling services	$	762,908		$	954,297	$	(191,389	)	(20	)%
Labor contract drilling services	14,371			16,357		(1,986		)	(12	)%
Reimbursables/Other (1)	46,613			22,893		23,720			104	%
	823,892			993,547		(169,655		)	(17	)%
Operating costs and expenses:
Contract drilling services	$	422,074		$	448,780	$	(26,706	)	(6	)%
Labor contract drilling services	11,294			12,436		(1,142		)	(9	)%
Reimbursables (1)	38,656			15,850		22,806			144	%
Depreciation and amortization	184,748			223,120		(38,372		)	(17	)%
General and administrative	29,101			25,928		3,173			12	%
Loss on impairment	1,701			—		1,701			**
Gain on disposal of assets, net	(12,717		)	—		(12,717		)	**
Gain on repurchase of long-term debt	(4,345		)	—		(4,345		)	**
	670,512			726,114		(55,602		)	(8	)%
Operating Income (2)	$	153,380		$	267,433	$	(114,053	)	(43	)%


**	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 $101 million and $62 million, respectively, for the six months ended June 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 $221 million. This decrease was partially offset by a 2% increase in average dayrates which increased revenues by $30 million.

The decrease in contract drilling services revenues was attributable to both our floaters and jackups which experienced a$127 million and $64 million decrease, respectively, in revenues in the Current Period as compared to the Comparable Period.

The decrease in floater revenues of $127 million in the Current Period was driven by a 29% decrease in operating days coupled with a 8% decrease in average dayrates which resulted in a $105 million and a $22 million decrease in revenues, respectively, from the Comparable Period.

The decrease in both average dayrates and operating days for our floaters was primarily due to the Noble Driller, which was retained by Noble after the Separation. Also, the Paragon DPDS1 was uncontracted for all of the Current Period but experienced full utilization in Brazil during the Comparable Period.

The $64 million decrease in jackup revenues in the Current Period was driven by a 20% decrease in jackup operating days which resulted in a $116 million decrease in revenues. This decline was partially offset by a 11% increase in average dayrates which positively impacted revenues by $52 million from the Comparable Period.

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The decrease in jackup operating days was due to our rigs in Mexico, including the Paragon M821, the Paragon M823, the Paragon M531, and the Paragon L1114, which were uncontracted for all 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 due to the Paragon L784 currently in the Middle East, the Paragon M826 currently in West Africa, and the Paragon C20052 currently in the North Sea 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 362 additional operating days in the Current Period due to the Prospector 1 and Prospector 5 operating in the North Sea and 220 additional operating days in the Current Period due to the Paragon L782 and the Paragon M825 operating in West 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 two high-specification jackups 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.

Reimbursables Operating Revenues and Costs and Expenses —The $24 million increase in reimbursable revenues and the related $23 million increase in reimbursable costs in the Current Period from the Comparable Period were primarily due to transition support services we have provided, on a cost-plus basis, to Noble’s remaining Brazil operations. We will continue to provide both rig-based and shore-based support services to Noble through the term of Noble’s existing rig contract and pursuant to the transition service agreement for Brazil (See Note 13 — “Commitments and Contingencies” for additional detail).

Depreciation and Amortization — The $38 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 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 higher than the Comparable Period due to costs associated with our operating as a standalone public company.

Loss on Impairment — We have entered into negotiations to sell the Paragon MSS3, Paragon B153, and Paragon DPDS4. During the six months ended June 30, 2015, we recognized a total impairment loss of $2 million with respect to the Paragon MSS3 and the Paragon B153. We do not expect an impairment loss on the Paragon DPDS4. We estimated the fair value of these units using significant other observable inputs, representative of Level 2 fair value measurements, based on indicative market values for the drilling units.

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.

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.

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Other Expenses

Income tax provision — Our income tax provision decreased $54 million in the Current Period compared to the Comparable Period, primarily due to a $165 million decrease in pre-tax book income and underlying changes in the profitability mix of our operations in various jurisdictions, including current year projected losses in certain jurisdictions and certain favorable discrete tax items in the Current Period.

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LIQUIDITY AND CAPITAL RESOURCES

Overview

The table below sets forth a summary of our cash flow information for the six months ended June 30, 2015 and 2014. Our cash flows for the six months ended June 30, 2015 consist entirely of the consolidated results of Paragon while our cash flows for the six months ended June 30, 2014 consist entirely of the combined results of our Predecessor.



	Six Months Ended
	June 30,
(In thousands)	2015			2014
Cash flows provided by (used in):
Operating activities	$	307,020		$	405,688
Investing activities	(85,971		)	(90,523		)
Financing activities	(165,462		)	(319,058		)

Changes in cash flows from operating activities for the six months ended June 30, 2015 are driven by changes in net income (see discussion of changes in Net Income in “Results of Operations”) and significant collections from our customers in the first half of 2015. Changes in cash flows from investing activities are dependent upon our level of capital expenditures, which varies based on the timing of projects. During the six months ended June 30, 2015, our cash flows from 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 a decrease in restricted cash associated with a requirement on the Prospector Senior Credit Facility, which was repaid in full during the first quarter of 2015. Changes in cash flows from financing activities for the six months ended June 30, 2015 are primarily due our repayment of the Prospector Senior Credit Facility and Prospector Bonds net of activity under our Revolving Credit Facility (as defined 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;


•	repayment of outstanding debt;


•	acquisitions;


•	dividends; and


•	share repurchases.

We currently expect to fund these cash flow needs with cash generated by our operations, available cash balances, borrowings under credit facilities, potential issuances of long-term debt or equity, other financings, or asset sales.

At June 30, 2015, we had a total contract drilling services backlog of approximately $1.6 billion, which includes $567 million with Petrobras. Our backlog as of June 30, 2015 reflects a commitment of 55% of available days for the remainder of 2015 and 26% of available days for 2016. For additional information regarding our backlog, see “Contract Drilling Services Backlog.”

Senior Notes, Term Loan Facility and Revolving Credit Facility

In connection with the Separation, we entered into a senior secured revolving credit agreement, a term loan agreement, and a senior note indenture described below that contain customary covenants relating to, among other things, the incurrence of additional indebtedness, dividends and other restricted payments and mergers, consolidations or the sale of substantially all of our assets. In addition, we have obtained surety lines to provide performance bonds for drilling contracts.

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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 up to $800 million of letters of credit. Issuance of letters of credit under the Revolving Credit Facility would reduce a corresponding amount available for borrowing. As of June 30, 2015, we had $365 million in borrowings outstanding at a weighted-average interest rate of 2.40%, and an aggregate amount of $92 million of letters of credit issued under the Revolving Credit Facility.

In connection with the issuance of the aforementioned debt, we incurred $35 million of issuance costs.

Extinguished Obligations

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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. We expect our primary sources of liquidity in the future will be cash generated from operations, borrowings under our Revolving Credit Facility, 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, to service our outstanding indebtedness, acquisitions and to pay future dividends.

At June 30, 2015, we had $112 million of cash on hand and $343 million of committed financing available under our Revolving Credit Facility, which will expire in 2019. 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, the remaining principal balance outstanding under the Prospector Senior Credit Facility in the amount of $261 million, including accrued interest, was paid in full through the use of cash on hand and borrowings under our Revolving Credit Facility.

At June 30, 2015, we have purchase commitments of $199 million and $400 million currently due in 2015 and 2016, respectively, related to three high specification jackup rigs under construction. In July 2015, we agreed with SWS to an extension of the delivery of the Prospector 6 to the second quarter of 2016. 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 rig, we will lose ownership of that rig, at which time, the associated costs currently capitalized (primarily representing down-payments on these rigs) on our balance sheet will be written off. At June 30, 2015, we had approximately $42 million in capitalized costs associated with these three rigs.

In July 2015, we completed a sale-leaseback transaction for two of our jackup units, Prospector 1 and 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. Pursuant to the terms of the sale-leaseback transaction, we will be required to make an aggregate amount of rental payments equal to approximately $373 million over the course of the five-year lease terms for the two rigs (see Note 17, “Subsequent event”).

Our debt facilities are subject to financial and non-financial covenants. While we currently satisfy our covenants, and we expect to be in compliance for the next twelve months, current market conditions, including any future contract amendments with Petrobras or other customers, may prevent us from maintaining compliance. There are measures within our control to help maintain compliance with these financial and non-financial covenants, such as reducing our operating and capital expenditures or seeking a waiver on the covenants from our lenders; however, there is no assurance that these alternatives would be available. Any corrective measures that we do implement may prove inadequate and, even if effective, could have negative long-term consequences to our business. Prospector has been designated as an unrestricted subsidiary under our Revolving Credit Facility, Term Loan Facility, and Senior Notes. 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 these debt facilities.

We expect that our operating cash flows coupled with our cash on hand and financing available under our revolving credit facility will be sufficient to meet our liquidity needs for at least the next twelve months. Our ability to continue to fund our operations will be affected by general economic, competitive and other factors, including any future contract amendments with Petrobras or other customers, many of which are outside of our control. To the extent current 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.

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Capital Expenditures

Capital expenditures, including capitalized interest, totaled $113 million during the six months ended June 30, 2015 and $111 million during the six months ended June 30, 2014. As of June 30, 2015, we had approximately $37 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.

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 June 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. The extension reduces our 2015 commitments by $201 million and resultantly increases our 2016 commitments by the same amount relating to the final installment payment due upon delivery of the Prospector 6. See “Note 17, Subsequent Events,” for our capital lease obligations resulting from the sale-leaseback transaction subsequent to the balance sheet date.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Allowance for Doubtful Accounts

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accounts was $15 million and $1 million at June 30, 2015 and December 31, 2014, respectively. Bad debt expense of $5 million and $14 million was recorded for the three and six months ended June 30, 2015. No bad debt expense was recorded for the three and six months ended June 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 Income for the three and six months ended June 30, 2015.

NEW ACCOUNTING PRONOUNCEMENTS

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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 Securities and Exchange Commission (“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 June 30, 2015, we had $365 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 $4 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 June 30, 2015, we had $642 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 $484 million at June 30, 2015. Related interest expense for three and six months ended June 30, 2015 was $7 million and $13 million. Holding other variables constant (such as debt levels), a 1% increase in interest rates would increase our annual interest expense by approximately $6 million.

Our Senior Notes bear interest at a fixed interest rate and fair value will fluctuate based on changes in prevailing market interest rates and market perceptions of our credit risk. The fair value of our Senior Notes was approximately $332 million at June 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 June 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 six months ended June 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, 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 June 30, 2015.

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 are currently designing and developing an implementation plan for the new processes and controls 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 second half of 2015.

Changes in Internal Control over Financial Reporting

There were no changes in Paragon’s internal control over financial reporting that occurred during the quarter ended June 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 13 – Commitments and Contingencies” to our 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 June 30, 2015, we were involved in a number of other lawsuits and other matters which have arisen in the ordinary course of business for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated and combined statements of financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of the matters referred to above or of any such other pending or threatened litigation or legal proceedings. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.


ITEM 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 non-cash impairment charges. As of June 30, 2015 we had goodwill of $37 million.

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. 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. 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.

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 Pemex and Petrobras, which accounted for approximately 16% and 23% of our operating revenues for the year ended December 31, 2014,

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respectively, and 12% and 21% of our operating revenues for the six month period ended June 30, 2015, respectively, to continue to be significant customers in 2015. Our contract drilling backlog as of June 30, 2015 includes $567 million, or approximately 36%, and $25 million, or approximately 2%, attributable to contracts with Petrobras and Pemex, respectively, for operations offshore Brazil and Mexico. Our floaters working for Petrobras are under contracts that expire beginning in 2016. Petrobras has announced a program to construct up to 29 newbuild floaters, which may reduce or eliminate its need for our rigs. These new drilling units, if built, would compete with, and could displace, our floaters completing contracts and could have a material adverse effect on our utilization rates, particularly in Brazil. Further, some national oil companies have considered regulations limiting the age of rigs in operation. Such reforms, if adopted, could significantly increase our costs or render some of our rigs ineligible for contracts with such companies.

Our customers may generally terminate our term drilling contracts if a drilling rig is destroyed or lost or if we have to suspend drilling operations for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. In the case of nonperformance and under certain other conditions, our drilling contracts generally allow our customers to terminate without any payment to us. The terms of some of our drilling contracts permit the customer to terminate the contract after specified notice periods by tendering contractually specified termination amounts. These termination payments may not fully compensate us for the loss of a contract. Our drilling contracts with Pemex allow 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 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 a number of competitors. Petrobras has indicated to us that it may contest the term of each of our drilling contracts for the Paragon DPDS2 and Paragon DPDS3 in connection with the length of prior shipyard projects relating to these rigs. As of June 30, 2015, backlog related to these contracts was approximately $493 million. While we continue discussions with Petrobras, we cannot guarantee that such discussions will result in the realization of the backlog related to these contracts.

Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by restricted credit markets and economic downturns. If our customers cancel or are unable to renew some of their contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, if contracts are disputed or suspended for an extended period of time or if a number of our contracts are renegotiated, it could have a material adverse effect on our business, financial condition and results of operations.

Risks Related to our Common Shares

If we cannot meet the continued listing requirements of the New York Stock Exchange (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.”

We have 180 days, or until February 5, 2016, to regain compliance with the NYSE’s 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

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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		August 13, 2015
Randall D. Stilley		Date
President, Chief Executive Officer and Director
(Principal Executive Officer)

/s/ Steven A. Manz		August 13, 2015
Steven A. Manz		Date
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)

/s/ Alejandra Veltmann		August 13, 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).
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.

(In shares)

Employee Plan

Director Plan

Shares available for future awards or grants

Outstanding unvested restricted stock units