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PARAGON OFFSHORE PLC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion of financial condition and results of operations pertain to the Noble Standard-Spec Business (the "Predecessor"), which comprised the entire standard specification drilling fleet and related operations of Noble Corporation plc ("Noble"). The Separation (as defined below) included the transfer to Paragon Offshore plc (together with its subsidiaries, "Paragon," the "Company," "we," "us" or "our") of the Predecessor, except for six standard specification drilling units, three of which were retained by Noble and three of which were sold by Noble prior to the Separation. Paragon will consolidate the historical financial results of the Predecessor in its consolidated financial statements for all periods prior to the Spin-Off (as defined below). The following discussion should be read in conjunction with the Predecessor's historical combined financial statements and related notes contained in this Quarterly Report on Form 10-Q and our combined financial statements and notes thereto included in our registration statement on Form-10 information statement. 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. All statements other than statements of historical facts included in this report 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, completion, delivery dates and acceptance of our newbuild rigs, 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, results of joint ventures, 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 are forward-looking statements. 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, risks associated with the ability to consummate future restructurings, operations outside the U.S., actions by regulatory authorities, customers, joint venture partners, 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, violations of anti-corruption laws, 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 this quarterly report on Form 10-Q, Part I, Item 1A. "Risk Factors" of our registration statement on Form 10 as filed with the SEC on July 14, 2014 and in our other filings with 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. Separation from Noble On June 30, 2014, Paragon Offshore Limited was an indirect wholly owned subsidiary of Noble incorporated under the laws of England and Wales. On July 17, 2014, Paragon Offshore Limited re-registered under the Companies Act 2006 as a public limited company under the name of Paragon Offshore plc. Subsequent to June 30, 2014, Noble transferred to us the assets and liabilities (the "Separation") constituting most of Noble's standard specification drilling units and related assets, liabilities and business. On August 1, 2014, Noble made a pro rata distribution to its shareholders of all of our issued and outstanding ordinary shares (the "Distribution" and, collectively with the Separation, the "Spin-Off"). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned. Noble owned 84.8 million ordinary shares of Paragon as of July 23, 2014, Noble's record date for the Distribution. We will consolidate the historical financial results of the Predecessor in our consolidated financial statements for all periods prior to the Spin-Off. 19-------------------------------------------------------------------------------- Table of Contents 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 might be in the future as a standalone public company as a result of the matters discussed below: Centralized Support Functions Our Predecessor's historical combined financial statements include expense allocations for certain support functions that were provided on a centralized basis within Noble, including, but not limited to, general corporate expenses related to communications, corporate administration, finance, legal, information technology, human resources, compliance, and employee benefits and incentives. These allocated costs are not necessarily indicative of the costs that we would incur in the future as a standalone public company. Following the spin-off, Noble will continue to provide us with some of the services related to these functions on a transitional basis pursuant to a transition services agreement relating to our business, and we expect to incur other costs to replace the services and resources that will not be provided by Noble. Please read Paragon Offshore plc Spin-off transaction within the "Commitments and Contingencies" footnote to the "Predecessor Combined Financial Statements" for additional information on such transition services agreement. During the period that Noble will provide services to us pursuant to such transition services agreement, we expect to incur higher costs for certain services than the allocated costs included in our Predecessor's historical combined financial statements as we will incur additional expenses to continue staffing our organization to perform such functions internally in addition to the amounts we will pay Noble for such services. Taxes Income Taxes The operations of our business have been included in the consolidated U.S. federal income tax return and certain foreign 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. These amounts are not necessarily indicative of what our income tax provisions and related deferred tax assets and liabilities will be in the future following the completion of the Spin-Off. We entered into a tax sharing agreement with Noble on July 31, 2014 that will govern 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 other matters regarding taxes. Our effective tax rate will be higher subsequent to the Separation primarily for the following reasons. First, prior to the Spin-Off, Noble restructured certain aspects of our business to effect the Separation. This restructuring resulted in significant tax inefficiencies for our business and operations, including our inability to deduct interest expense with respect to borrowings under the Term Loan Facility and Senior Notes and ownership of certain of our assets in structures subject to higher tax rates than prior to the restructuring. Second, in July 2014, legislation was enacted by the U.K. government that will restrict deductions on certain intercompany transactions, such as those relating to the bareboat charter agreements used in connection with our U.K. continental shelf operations. These bareboat charter agreements are common within the offshore drilling industry. The legislation, enacted in July 2014 and effective retroactively to April 1, 2014, will result in an increase in our income taxes in the U.K. We estimate that the retroactive impact of this change will result in an increase of approximately $6.0 - $8.0 million in income tax expense for the period from April 1, 2014 through June 30, 2014. In addition, we expect that the new legislation will increase the effective tax rate on our consolidated operations beginning in the third quarter of 2014. We are actively reviewing our overall structure to better align it with our business objectives as a standalone company. Other Contingencies 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 $118.0 million, of which $36.0 million is subject to indemnity by Noble. Petrobras has also notified us that if Petrobras is ultimately assessed and must pay such withholding taxes, it will seek reimbursement from us. We believe that we are contractually indemnified by Petrobras for these amounts and dispute any basis for Petrobras to obtain such reimbursement. We have notified Petrobras of our position. We will, if necessary, vigorously defend our rights. If we were required to pay such reimbursement, however, the amount of such reimbursement could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. See Note 7 "Commitments and Contingencies" to our "Combined Financial Statements" included in Item 1 of Part I of this Quarterly Report on Form 10-Q. 20 -------------------------------------------------------------------------------- Table of Contents Compensation and Benefit Plan Matters During the periods presented in the historical combined financial statements of our Predecessor, most of our emp1oyees were eligible to participate in various Noble benefit programs. Our Predecessor's historical combined financial statements include an allocation of the costs of such employee benefit plans. These costs were allocated based on our employee population for each of the periods presented. The allocated costs included in our Predecessor's historical combined financial statements could differ from amounts that would have been incurred by us if we operated on a stand-alone basis and are not necessarily indicative of costs to be incurred in the future. We have instituted competitive compensation policies and programs, as well as carried over several plans as a standalone public company, the expense for which may differ from the compensation expense allocated by Noble in our Predecessor's historical combined financial statements. Public Company Expenses As a result of the Spin-Off, we became subject to the reporting requirements of the Exchange Act and the Sarbanes Oxley Act. We are required to establish procedures and practices as a standalone public company in order to comply with our obligations under those laws and the related rules and regulations. As a result, we expect to incur approximately $8 million of additional costs annually, for functions including external and internal audit, investor relations, share administration and regulatory compliance. The amount of these expenses will exceed the amount historically allocated to us from Noble for these types of expenses. Overview The business environment for offshore drillers during the first six months of 2014 has been challenging. While the price of Brent crude oil, a key factor in determining customer activity levels, remained generally steady throughout the period, there has been a decrease in contractual activity. Many offshore drilling industry analysts project a decrease in the rate of global offshore exploration and development spending relative to previous years. In addition, according to RigLogix, as of August 27, 2014, 136 jackup drilling rigs were under construction or on order, which could negatively impact the contracting environment as these rigs enter the market. While we believe the short-term outlook has downside risks, we continue to have confidence in the long-term fundamentals for the industry. These fundamental factors include stable crude oil prices, strong exploration results, geographic expansion of offshore drilling activities, a growing backlog of multi-year field development programs and greater access by our customers to promising offshore regions, as evidenced by energy reform legislation in Mexico that could potentially lead to an increase in drilling activity in Mexican waters. During the recent period of high utilization and high dayrates, industry participants have increased the supply of drilling rigs by building new drilling rigs. Historically, this has often resulted in an oversupply of drilling rigs and has caused a subsequent decline in utilization and dayrates when new drilling rigs have entered the market, which has sometimes continued for extended periods of time. The increase in supply created by the number and types of rigs being built, as well as changes in our competitors' drilling rig fleets, could intensify price competition and require higher capital investment to keep our rigs competitive. A number of customers are drilling more wells that require rigs with higher specification than many of our rigs. Our proforma contract drilling backlog as of June 30, 2014 was down by approximately 20% as compared to March 31, 2014, due to the industry wide decrease in the contractual activity. 21 -------------------------------------------------------------------------------- Table of Contents Paragon 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, 2014, the amount of our pro forma contract drilling services backlog and the percent of available operating days committed for the periods indicated: For the Years Ending December 31 Total 2014* 2015 2016 2017 2018 (dollars in millions) Floaters (1) $ 1,101 $ 292 $ 443 $ 255 $ 111 $ - Jackups (2) 1,170 561 508 99 2 - Total(3)(4) $ 2,271 $ 853 $ 951 $ 354 $ 113 $ - Percent of available days committed (5) 70 % 35 % 10 % 2 % 0 % * Represents a six-month period beginning July 1, 2014. (1) Our drilling contracts with Petrobras provide an opportunity for us to earn performance bonuses based on reaching targets for downtime experienced for our rigs operating offshore Brazil, for which we have included in our backlog an amount equal to 50% of potential performance bonuses for such rigs, or $64 million. (2) Pemex has the ability to cancel its drilling contracts on 30 days or less notice without Pemex's making an early termination payment. At June 30, 2014, we had ten rigs contracted to Pemex, and our backlog included approximately $308 million related to such contracts. (3) Some of our drilling contracts provide the customer with certain early termination rights. (4) Excludes approximately $136 million of total backlog related to two jackups and one floater that will be retained by Noble. (5) Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period, or committed days, by the product of the total number of our rigs, including cold-stacked rigs, and the number of calendar days in such period. Committed days do not include the days that a rig is stacked or the days that a rig is expected to be out of service for significant overhaul repairs or maintenance. Our pro forma 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, 2014, our pro forma contract drilling services backlog did not include any letters of intent. We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts. The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the pro forma backlog amounts and pro forma 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 pro forma backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our pro forma backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. In addition, we generally do not expect to re-contract our floaters, which accounted for 48% of our pro forma backlog at June 30, 2014, until late in their contract terms. Due to the higher dayrates earned by our floaters, until these rigs are re-contracted, our total pro forma backlog is expected to decline. 22-------------------------------------------------------------------------------- Table of Contents Results of Operations As part of Noble, our Predecessor has not operated on a standalone basis. When the term "we" or "our" is used in the following discussion, the reference is to the historical operations of our Predecessor, which includes rigs retained by Noble or sold by Noble prior to the Distribution. For the Three Months Ended June 30, 2014 and 2013 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, 2014 (the "Current Quarter") and for the three months ended June 30, 2013 (the "Comparable Quarter"): Average Rig Operating Average Utilization (1) Days (2) Dayrates 2014 2013 2014 2013 % Change 2014 2013 % Change (dollars in thousands) Jackups 76 % 91 % 2,492 3,048 -18 % $ 113,125 $ 102,550 10 % Floaters 78 % 62 % 637 506 26 % 283,221 260,151 9 % Total 75 % 80 % 3,129 3,554 -12 % $ 147,752 $ 124,990 18 % (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, excluding newbuild rigs under construction. (2) Information reflects the number of days that our rigs were operating under contract. The following table sets forth the operating results of our Predecessor for the three months ended June 30, 2014 and 2013: Change 2014 2013 $ % (dollars in thousands) (unaudited) Operating Revenues Contract drilling services $ 462,334 $ 444,208 $ 18,126 4 % Labor contract drilling services 8,146 8,902 (756 ) -8 % Reimbursables/Other (1) 8,477 11,835 (3,358 ) -28 % 478,957 464,945 14,012 3 % Operating costs and expenses: Contract drilling services 222,317 226,281 (3,964 ) -2 % Labor contract drilling services 6,223 6,033 190 3 % Reimbursables (1) 5,224 9,053 (3,829 ) -42 % Depreciation and amortization 112,536 101,897 10,639 10 % General and Administrative 12,683 15,538 (2,855 ) -18 % 358,983 358,802 181 0 % Operating Income (2) $ 119,974 $ 106,143 $ 13,831 13 % (1) We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. (2) The rigs retained and sold by Noble represent revenues of $42.4 and $54.0 million for the three months ended June 30, 2014 and 2013 respectively. The expenses for these same periods are $29.7 and $36.4 million respectively. 23 -------------------------------------------------------------------------------- Table of Contents Contract Drilling Services Operating Revenues-Changes in contract drilling services revenues for the Current Quarter as compared to the Comparable Quarter were driven by an increase in average dayrates, partially offset by a decrease in operating days. The 18 percent increase in average dayrates increased revenue by $71 million but the 12% decrease in operating days decreased revenue by $53 million. The increase in contract drilling services revenues was driven by our floaters, which generated approximately $49 million more revenue in the Current Quarter. The increase in revenue from our floaters was partially offset by a $31 million decrease in revenue from our jackups. The increase in floater revenues in the Current Quarter was driven by a 26 percent increase in operating days coupled with a 9 percent increase in average dayrates which resulted in a $34 million and a $15 million increase in revenues, respectively, from the comparable quarter. The increase in both average dayrates and operating days was the result of the Noble Roger Easonreturning to full operations during the Current Quarter after receiving a reduced rate while in the shipyard to undergo its reliability upgrade project during the Comparable Quarter. The increase in average dayrates was also driven by the Noble Driller, which received higher day rates, but was retained by Noble after the Separation. The decrease in jackup revenues in the Current Quarter was driven by an 18 percent decrease in operating days, which was offset by a 10 percent increase in jackup average dayrates resulting in a $57 million decrease and $26 million increase in revenues, respectively from the Comparable Quarter. The increase in average dayrates resulted from improved market conditions in the global shallow water market. The decrease in operating days was driven by the Noble Gus Androes, Noble Gene Rosser, Noble Charlie Yester and Noble David Tinsley, which were off contract in the Current Quarter but experienced full utilization during the Comparable Quarter, coupled with increased shipyard time on the Noble Percy Johns and Noble Ed Noble during the Current Quarter. Additionally, the Noble Lewis Dugger, which was sold in July 2013, was fully utilized during the Comparable Quarter. Contract Drilling Services Operating Costs and Expenses-Contract drilling services operating costs and expenses remained consistent in the Current Quarter as compared to the Comparable Quarter. Labor Contract Drilling Services Operating Revenues and Costs and Expenses-The decline in revenues associated with our Canadian labor contract drilling services were primarily related to fluctuations in foreign currency exchange rates. Expenses associated with our labor contract drilling services remained relatively constant. Depreciation and Amortization-The $11 million increase in depreciation and amortization in the Current Quarter from the Comparable Quarter was primarily attributable to completion of the Noble Roger Eason shipyard upgrade which was completed during the fourth quarter of 2013 and the rig went back into service in 2013. General and Administrative-The decrease in general and administrative expenses of our Predecessor related to the sales of the Noble Lewis Dugger (July 2013), Noble Lester Pettus (January 2014), and Noble Joe Alford (January 2014), which affected the various inputs used for the allocation of costs to our Predecessor in the Current Quarter as compared to the Comparable Quarter. Other Expenses Income tax provision-Income tax expense for the Predecessor for the Current Quarter remained consistent with the Comparable Quarter as the impact on income tax expense resulting from the increase in revenues was offset by the geographic mix of earnings in more tax efficient jurisdictions. 24-------------------------------------------------------------------------------- Table of Contents For the Six Months Ended June 30, 2014 and 2013 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, 2014 (the "Current Period") and for the six months ended June 30, 2013 (the "Comparable Period"): Average Rig Operating Average Utilization (1) Days (2) Dayrates 2014 2013 2014 2013 % Change 2014 2013 % Change (dollars in thousands) Jackups 80 % 91 % 5,193 6,106 -15 % $ 112,717 $ 100,136 13 % Floaters 78 % 65 % 1,267 1,058 20 % 291,184 251,596 16 % Total 77 % 81 % 6,460 7,164 -10 % $ 147,718 $ 122,508 21 % (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, excluding newbuild rigs under construction. (2) Information reflects the number of days that our rigs were operating under contract. The following table sets forth the operating results for our Predecessor for the six months ended June 30, 2014 and 2013: Change 2014 2013 $ % (dollars in thousands) (unaudited) Operating Revenues Contract drilling services $ 954,297 $ 877,619 $ 76,678 9 % Labor contract drilling services 16,357 17,684 (1,327 ) -8 % Reimbursables/Other (1) 22,893 23,712 (819 ) -3 % 993,547 919,015 74,532 8 % Operating costs and expenses: Contract drilling services 448,780 451,124 (2,344 ) -1 % Labor contract drilling services 12,436 11,746 690 6 % Reimbursables (1) 15,850 17,597 (1,747 ) -10 % Depreciation and amortization 223,120 200,601 22,519 11 % General and Administrative 25,928 31,003 (5,075 ) -16 % Gain on contract settlements / extinguishments - (1,800 ) 1,800 726,114 710,271 15,843 2 % Operating Income (2) $ 267,433 $ 208,744 $ 58,689 28 % (1) We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows. (2) The rigs retained and sold by Noble represent revenues of $100.9 and $103.2 million for the six months ended June 30, 2014 and 2013 respectively. The expenses for these same periods are $61.1 and $69.7 million respectively. Contract Drilling Services Operating Revenues-Changes in contract drilling services revenues for the Current Period as compared to the Comparable Period were driven by an increase in average dayrates, partially offset by a decrease in operating days. The 21 percent increase in average dayrates increased revenue by $163 million but the 10% decrease in operating days decreased revenue by $86 million. The increase in contract drilling services revenues was driven by our floaters, which generated approximately $103 million more revenue in the Current Period. The increase in revenue from our floaters was partially offset by a $26 million decrease in revenue from our jackups. 25-------------------------------------------------------------------------------- Table of Contents The increase in floater revenues in the Current Period was driven by a 20 percent increase in operating days coupled with a 16 percent increase in average dayrates which resulted in a $53 million and a $50 million increase in revenues, respectively, from the Comparable Period. The increase in both average dayrates and operating days was the result of the Noble Roger Eason returning to full operations during the Current Period, after receiving a reduced rate while in the shipyard to undergo its reliability upgrade project during the Comparable Period. The increase in average dayrates was also driven by the Noble Driller, which received a higher dayrate after starting a new contract but was retained by Noble after the Separation. The 15 percent decrease in jackup operating days resulted in a $91 million decrease in revenues, offset by a 13 percent increase in jackup average dayrates resulted in a $65 million increase in revenues, resulting in a $26 million decrease in revenues from the Comparable Period. The increase in average dayrates resulted from improved market conditions in the global shallow water market. The decrease in operating days was driven by the Noble Gus Androes, Noble Gene Rosser, and Noble Charlie Yester, which were off contract in the Current Period but experienced full utilization during the Comparable Period, coupled with increased shipyard time on the Noble Percy Johns and Noble Ed Noble during the Current Period. Additionally, the Noble Lewis Dugger, which was sold in July 2013, was fully utilized during the Comparable Period. Contract Drilling Services Operating Costs and Expenses-Contract drilling services operating costs and expenses remained consistent in the Current Quarter as compared to the Comparable Quarter. Labor Contract Drilling Services Operating Revenues and Costs and Expenses-The decline in revenues associated with our Canadian labor contract drilling services were primarily related to fluctuations in foreign currency exchange rates. Expenses associated with our labor contract drilling services remained relatively constant. Depreciation and Amortization-The $22 million increase in depreciation and amortization in the Current Period was primarily attributable to completion of the Noble Roger Eason shipyard upgrade. This upgrade was completed during the fourth quarter of 2013 and the rig went back into service in 2013. General and Administrative-The decrease in general and administrative expenses of our Predecessor related to the sales of the Noble Lewis Dugger (July 2013), Noble Lester Pettus (January 2014), and Noble Joe Alford (January 2014), which affected the various inputs used for the allocation of costs to our Predecessor in the Current Quarter as compared to the Comparable Quarter. Other Expenses Income tax provision-Income tax expense for the Predecessor for the Current Period remained consistent with the Comparable Period as the impact on income tax expense resulting from the increase in revenues was offset by the geographic mix of earnings in more tax efficient jurisdictions. Liquidity and Capital Resources In connection with the Separation, we have entered into a revolving credit agreement, a term loan agreement and a senior note indenture 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. We expect our primary sources of liquidity in the future will be cash generated from operations, our revolving credit facility and any future financing arrangements, if necessary. Our principal uses of liquidity will be to fund our working capital and capital expenditures, including major projects, upgrades and replacements to drilling equipment, to service our outstanding indebtedness and to pay future dividends. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for Noble. As part of such program, Noble periodically swept all available cash from our operating accounts until June 30, 2014. Prior to the Distribution, Noble delivered to us $40 million in cash to increase our working capital. After June 30, 2014, we have been solely responsible for the provision of funds to finance our working capital and other cash requirements. We believe our liquidity will be sufficient to fund our operations for at least the next 12 months. Our ability to continue to fund these items may be affected by general economic, competitive and other factors, many of which are outside of our control. 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 expenditures, sell assets, refrain from paying or reduce the amount of any dividends, obtain additional debt or equity or refinance all or a portion of our debt. 26 -------------------------------------------------------------------------------- Table of Contents Financial Resources and Liquidity Predecessor The table below sets forth our Predecessor's summary cash flow information for the six months ended June 30, 2014 and 2013: Six Months Ended June 30, 2014 2013 (unaudited) (dollars in thousands) Cash flows provided by (used in): Operating activities $ 405,688 $ 285,995 Investing activities (90,523 ) (221,390 ) Financing activities (319,058 ) (89,191 ) Changes in cash flows from operating activities from period to period are primarily driven by changes in net income. Changes in cash flows from investing activities are dependent upon our Predecessor's level of capital expenditures which vary based on the timing of projects, while changes in cash flows from financing activities from period to period are based on activity under Noble's commercial paper program and credit facilities and investments to and from Parent. Paragon 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; • dividends; • reduction of outstanding debt; • share repurchases; and • acquisitions. We currently expect to fund these cash flow needs with cash generated by our operations, cash on hand, borrowings under future credit facilities, potential issuances of long-term debt, or asset sales. At June 30, 2014, we had a total pro forma contract drilling services backlog of approximately $2.3 billion. Our pro forma backlog as of June 30, 2014 reflects a commitment of 70 percent of available days for the remainder of 2014 and 35 percent of available days for 2015. For additional information regarding our pro forma backlog, see "Pro Forma Contract Drilling Services Backlog." Capital Expenditures Our primary use of available liquidity during 2014 is for capital expenditures. Capital expenditures, including maintenance, rig reactivations, major projects and upgrades to our fleet, totaled $111 million during the six months ended June 30, 2014 and $216 million during the six months ended June 30, 2013. Capital expenditures considered necessary to sustain the capabilities of the fleet were $43 million for the six months ended June 30, 2014. Capital expenditures for the six months ended June 30, 2013 included $110 million related to upgrade projects on drillships in Brazil, which we completed in 2013. As of June 30, 2014, we had approximately $102 million in capital commitments related to ongoing major projects, upgrades and replacements to drilling equipment, all of which we expect to spend within the next twelve months. Capital commitments include all open purchase orders issued to vendors to procure capital equipment. 27 -------------------------------------------------------------------------------- Table of Contents 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 from time to time. 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. New Accounting Pronouncements In April 2014, the FASB issued Accounting Standards Update ("ASU") No. 2014-08, which amends FASB Accounting Standards Codification ("ASC") Topic 205, "Presentation of Financial Statements" and ASC Topic 360, "Property, Plant, and Equipment." This ASU alters the definition of a discontinued operation to cover only asset disposals that are a strategic shift with a major effect on an entity's operations and finances, and calls for more extensive disclosures about a discontinued operation's assets, liabilities, income and expenses. The guidance is effective for all disposals, or classifications as held-for-sale, of components of an entity that occur within annual periods beginning on or after December 15, 2014. We are still evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures. In May 2014, the FASB issued ASU No. 2014-09, which amends ASC Topic 606, "Revenue from Contracts with Customers." The amendments in this ASU are intended to provide a more robust framework for addressing revenue issues, improve comparability of revenue recognition practices and improve disclosure requirements. The amendments in this accounting standard update are effective for interim and annual reporting periods beginning after December 15, 2016. We are still evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures. In June 2014, the FASB issued ASU No. 2014-12, which amends ASC Topic 718, "Compensation-Stock Compensation." The guidance requires that a performance target that affects vesting and that could be achieved after the requisite service period be treated as a performance condition and should not be reflected in the estimate of the grant-date fair value of the award. The guidance is effective for annual periods beginning after December 15, 2015. The guidance can be applied prospectively for all awards granted or modified after the effective date or retrospectively to all awards with performance targets outstanding as of the beginning of the earliest annual period presented in the financial statements and to all new or modified awards thereafter. We are still evaluating what impact, if any, the adoption of this guidance will have on our financial condition, results of operations, cash flows or financial disclosures. 28-------------------------------------------------------------------------------- Table of Contents PARAGON OFFSHORE PLC UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS On June 30, 2014, Paragon Offshore Limited was an indirect wholly owned subsidiary of Noble Corporation plc ("Noble") incorporated under the laws of England and Wales. On July 17, 2014, Paragon Offshore Limited re-registered under the Companies Act 2006 as a public limited company under the name of Paragon Offshore plc (together with its subsidiaries, "Paragon," the "Company," "we," "us" or "our"). Subsequent to June 30, 2014, Noble transferred to us the assets and liabilities (the "Separation") constituting most of Noble's standard specification drilling units and related assets, liabilities and business. On August 1, 2014, Noble made a pro rata distribution to its shareholders of all of our issued and outstanding ordinary shares (the "Distribution" and, collectively with the Separation, the "Spin-Off"). In connection with the Distribution, Noble shareholders received one ordinary share of Paragon for every three ordinary shares of Noble owned. Noble owned 84.8 million ordinary shares of Paragon as of July 23, 2014, Noble's record date for the Distribution. The historical financial information contained in this report relates to periods that ended prior to the Spin-Off. Consequently, the unaudited combined financial statements and related discussion of financial condition and results of operations contained in this report pertain to the Noble Standard-Spec Business (the "Predecessor"), which comprised the entire standard specification drilling fleet and related operations of Noble. The Separation included the transfer to us of the Predecessor, except for six standard specification drilling units, three of which were retained by Noble and three of which were sold by Noble prior to the Separation (collectively, the "Excluded Assets"). We will consolidate the historical financial results of the Predecessor in our consolidated financial statements for all periods prior to the Spin-Off. We are a pure-play global provider of standard specification offshore drilling rigs and includes 34 jackups and eight floaters (five drillships and three semisubmersibles), and one floating production storage and offloading unit ("FPSO"). We refer to our semisubmersibles and drillships collectively as "floaters." We also operate the Hibernia platform offshore of Canada. Our primary business is to contract our drilling rigs, related equipment and work crews to conduct oil and gas drilling and workover operations for our exploration and production customers on a dayrate basis around the world. Set forth below are our unaudited pro forma combined balance sheet as of June 30, 2014 and our unaudited pro forma combined statements of operations for the six months ended June 30, 2014 and 2013. Our unaudited pro forma combined financial data have been derived by adjusting the historical combined financial statements of our Predecessor. At the Separation, our fleet consisted of 34 jackups, five drillships, three semisubmersibles and one floating production storage and offloading unit, as well as the Hibernia platform operations. The following unaudited pro forma combined financial information sets forth: a) the historical financial information of our Predecessor as of June 30, 2014 and for the six months ended June 30, 2014 and 2013, as derived from the unaudited combined financial statements of our Predecessor; and b) the unaudited pro forma combined financial statements of Paragon assuming a) the transfer of our Predecessor (less the Excluded Assets) to us in exchange for our shares and intercompany indebtedness in an aggregate principal amount of approximately $1.7 billion and b) repayment of the intercompany indebtedness to Noble using the proceeds from the $1.7 billion of indebtedness under the Term Loan Facility and the Debt Securities from unaffiliated third-parties and lenders. The pro forma adjustments applied in the unaudited pro forma combined financial statements are based upon currently available information and certain estimates and assumptions, and actual results may differ from the pro forma adjustments. However, we believe that these estimates and assumptions provide a reasonable basis for presenting the significant effects of the contemplated transactions and that the pro forma adjustments are factually supportable and give appropriate effect to those estimates and assumptions. 29-------------------------------------------------------------------------------- Table of Contents As a result of the Distribution, we became subject to the reporting requirements of the Securities Exchange Act of 1934 and the Sarbanes-Oxley Act. We are required to establish procedures and practices as a standalone public company in order to comply with our obligations under those laws and the related rules and regulations. As a result, we expect to incur approximately $8 million of incremental annual expenses related to being a public company, including internal and external audit, investor relations, share administration and regulatory compliance costs. The amount of these expenses will exceed the amount historically allocated to us from Noble for these types of expenses. No pro forma adjustments have been made for these incremental public company expenses. The unaudited pro forma combined financial statements are presented for comparative purposes only and may not necessarily be indicative of what our actual financial position or results of operations would have been as of, and for, the period presented, nor does it purport to represent our future financial position or results of operations. You should read our unaudited pro forma combined financial statements and the accompanying notes in conjunction with our Predecessor combined financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q for our fiscal quarter ended June 30, 2014 and the financial and other information appearing elsewhere in this report. 30-------------------------------------------------------------------------------- Table of Contents PARAGON OFFSHORE PLC UNAUDITED PRO FORMA COMBINED BALANCE SHEET AS OF JUNE 30, 2014 (In thousands) Excluded or disposed Paragon Predecessor standard-spec Pre-financing Financing Separation Offshore Historical assets subtotal Adjustments adjustments Pro Forma Note 1 Note 2 Note 3 ASSETS Current assets Cash and cash equivalents $ 32,688 $ - $ 32,688 $ - $ 40,000 $ 72,688 Accounts receivable 364,244 (40,965 ) 323,279 - - 323,279 Prepaid and other current assets 57,886 (3,680 ) 54,206 - 55,315 109,521 Total current assets 454,818 (44,645 ) 410,173 - 95,315 505,488 Property and equipment, at cost 6,171,698 (686,748 ) 5,484,950 - - 5,484,950 Accumulated depreciation (2,809,195 ) 207,974 (2,601,221 ) - - (2,601,221 ) Property and equipment, net 3,362,503 (478,774 ) 2,883,729 - - 2,883,729 Other assets 72,837 (15,405 ) 57,432 33,223 4,807 95,462 Total assets $ 3,890,158 $ (538,824 ) $ 3,351,334 $ 33,223 $ 100,122 $ 3,484,679 LIABILITIES AND EQUITY Current liabilities Accounts payable $ 123,249 $ (6,911 ) $ 116,338 $ - $ - $ 116,338 Accrued payroll and related costs 54,186 (4,947 ) 49,239 - - 49,239 Other current liabilities 35,547 - 35,547 - 80,226 115,773 Total current liabilities 212,982 (11,858 ) 201,124 - 80,226 281,350 Long-term debt 2,268,613 - 2,268,613 (541,863 ) - 1,726,750 Deferred income taxes 97,063 - 97,063 - (18,107 ) 78,956 Other liabilities 82,792 - 82,792 - 23,826 106,618 Total liabilities 2,661,450 (11,858 ) 2,649,592 (541,863 ) 85,945 2,193,674 Commitments and contingencies Shareholders' equity Shares - - - - 848 848 Additional paid-in capital - - - - 1,330,120 1,330,120 Net parent investment 1,228,687 (526,966 ) 701,721 575,086 (1,276,807 ) - Accumulated other comprehensive loss 21 - 21 - (39,984 ) (39,963 ) Total equity 1,228,708 (526,966 ) 701,742 575,086 14,177 1,291,005 Total liabilities and equity $ 3,890,158 $ (538,824 ) $ 3,351,334 $ 33,223 $ 100,122 $ 3,484,679 See accompanying notes to the unaudited pro forma combined financial statements. 31 -------------------------------------------------------------------------------- Table of Contents |