F-1 1 d338176df1.htm FORM F-1 Form F-1
Table of Contents

As filed with the Securities and Exchange Commission on January 7, 2013.

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form F-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

QGOG Constellation S.A.

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Luxembourg   1381   Not Applicable
(State or Other Jurisdiction of
Incorporation or Organization)
  (Primary Standard Industrial
Classification Code Number)
 

(I.R.S. Employer

Identification No.)

QGOG Constellation S.A.

40, avenue Monterey, L-2163

Luxembourg

+352 20 20 2401

(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

 

 

Puglisi & Associates

850 Library Avenue, Suite 204

Newark, Delaware 19711

(302) 738-6680

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Donald Baker, Esq.

Mark Bagnall, Esq.

White & Case LLP

1155 Avenue of the Americas

New York, NY 10036

Tel: (212) 819-8200

Fax: (212) 354-8113

 

Andrew B. Jánszky, Esq.

Tobias Stirnberg, Esq.

Milbank, Tweed, Hadley & McCloy LLP

One Chase Manhattan Plaza

New York, NY 10005

Tel: (212) 530-5000

Fax: (212) 530-5219

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after effectiveness of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

The Registrant is an emerging growth company, as defined in Section 2(a) of the Securities Act. This registration statement complies with the requirements that apply to an issuer that is an emerging growth company.

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

 

Proposed

Maximum
Aggregate
Offering Price(1)(2)

  Amount of
Registration Fee

Common shares, no par value

  $500,000,000   $68,200

 

 

(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.
(2) Includes shares to be sold upon exercise of the underwriters’ option. See “Underwriting.”

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a) may determine.

 

 

 


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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and is not a solicitation of an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

SUBJECT TO COMPLETION, DATED JANUARY 7, 2013

             Shares

 

LOGO

QGOG Constellation S.A.

Common Shares

$        per common share

 

 

This is an initial public offering of our common shares. We are offering              common shares.

Prior to this offering, there has been no public market for our common shares. We expect the initial public offering price of our common shares to be between $         and $         per share. After the pricing of this offering, we expect that our common shares will trade on the New York Stock Exchange under the symbol “QGOG”.

We have granted the underwriters an option to purchase a maximum of              additional common shares from us, at the public offering price, less the underwriting discount, for 30 days after the date of this prospectus.

We are an emerging growth company, as defined in Section 2(a) of the Securities Act and, as such, may elect to comply with certain reduced U.S. public company reporting requirements.

 

 

Investing in our common shares involves risks. See “Risk Factors” beginning on page 15 of this prospectus.

 

     Price to Public      Underwriting
Discounts and
Commissions(*)
     Net Proceeds
to Us
 

Public Offering Price per Common Share

   $                    $                    $                

Underwriting Discount

   $                    $                    $                

Proceeds, before expenses, to us

   $                    $                    $                

 

(*) See “Underwriting” for further information.

Delivery of our common shares will be made on or about                     , 2013.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

 

J.P. Morgan   BofA Merrill Lynch   Itaú BBA   Credit Suisse   Bradesco BBI

The date of this prospectus is                    , 2013


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[Cover Artwork to Come]


Table of Contents

TABLE OF CONTENTS

 

     Page  

PRESENTATION OF FINANCIAL AND OTHER INFORMATION

     ii   

PROSPECTUS SUMMARY

     1   

THE OFFERING

     11   

SUMMARY FINANCIAL AND OTHER DATA

     13   

RISK FACTORS

     15   

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

     30   

USE OF PROCEEDS

     32   

DIVIDEND POLICY

     33   

CAPITALIZATION

     34   

DILUTION

     35   

SELECTED FINANCIAL AND OTHER DATA

     37   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     39   

INDUSTRY

     74   

BUSINESS

     87   

MANAGEMENT

     111   

PRINCIPAL SHAREHOLDERS

     118   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     121   

DESCRIPTION OF CAPITAL STOCK

     125   

SHARES ELIGIBLE FOR FUTURE SALE

     131   

TAXATION

     132   

UNDERWRITING

     141   

LEGAL MATTERS

     148   

EXPERTS

     149   

ENFORCEABILITY OF CIVIL LIABILITIES

     150   

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     152   

INDEX TO FINANCIAL STATEMENTS

     F-1   

 

 

The terms “our company,” “the issuer,” “we,” “our” or “us,” as used herein, refer to QGOG Constellation S.A. and its consolidated subsidiaries unless otherwise stated or indicated by context. The term “Constellation,” as used herein, refers to Constellation Overseas Ltd. unless otherwise stated or indicated by context.

Neither we nor the underwriters have authorized anyone to provide you with additional information or information different from that contained in this prospectus or in any free writing prospectus prepared by us or on our behalf. When you make a decision about whether to invest in our common shares, you should not rely upon any information other than the information in this prospectus and any free writing prospectus prepared by us or on our behalf. Neither the delivery of this prospectus nor the sale of our common shares means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or solicitation of an offer to buy our common shares in any circumstances under which such offer or solicitation is unlawful.

For investors outside the United States: neither we nor any of the underwriters have done anything that would permit the offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. You are required to inform yourselves about and to observe any restrictions relating to this offering and the distribution of this prospectus outside of the United States.

 

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PRESENTATION OF FINANCIAL AND OTHER INFORMATION

General

We are a holding company organized under the laws of Luxembourg. We completed our corporate reorganization in August 2012. As part of our corporate reorganization, each shareholder of Constellation contributed its shares in Constellation to us in exchange for our issuance of our common shares to them in the same proportion that each such shareholder held in Constellation. Following this contribution, these shareholders transferred their common shares in us to our current shareholders, which in turn are controlled by the former shareholders of Constellation. See “Principal Shareholders” for further information. The contribution of the outstanding capital stock of Constellation to us was accounted for at its historical cost as this entity is under common management and control with us. As a result, we own all of the outstanding capital stock of Constellation.

For the purpose of this prospectus, we have included the following financial statements (included elsewhere in this prospectus):

 

   

our unaudited condensed consolidated interim financial information as of September 30, 2012 and for the three and nine-month periods ended September 30, 2012 and 2011; and

 

   

our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011.

Our financial statements have been prepared in accordance with International Financial Reporting Standards, or IFRS, as issued by the International Accounting Standards Board, or IASB. The functional currency of the issuer and most of its subsidiaries is the U.S. dollar. Our combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011 have been audited by our independent auditors, as set forth in their report included elsewhere in this prospectus.

Our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011 are derived from the combination of (1) the financial statements of Constellation for the corresponding periods, utilizing historical results of operations, assets and liabilities and (2) the historical financial information of QGOG Constellation as of December 31, 2011 and for the period from August 30, 2011 (the date of our incorporation) to December 31, 2011. These combined financial statements have been prepared considering that we and Constellation were under common management and control. Our audited combined financial statements as of December 31, 2011 and 2010, and for each of the three years ended December 31, 2011, have been restated to correct an error in our accounting policy related to the recognition of mobilization revenues and costs. As a result, we defer mobilization revenues and costs over the period that we charter and we provide operation services, which is consistent with the general pace of activity, level of services we provide, and dayrates we earn over the life of the related contract. For a discussion of this restatement and its related effects, see note 31 to our audited combined financial statements included elsewhere in this prospectus.

All references herein to “U.S. dollars,” “dollars” or “$” are to U.S. dollars. All references to the “real,” “reais” or “R$” are to the Brazilian real, the official currency of Brazil. All references to “€” are to the Euro.

Market Share and Other Information

The information on the market and the competitive position in our operating market used throughout this prospectus, including market forecasts, was obtained from market research, publicly available information and industry publications. We have made these statements on the basis of information from third-party sources that we believe are reliable, such as the following:

 

   

the Fearnley Proctor Group, or Fearnley;

 

   

the Brazilian National Agency of Water Transport (Agência Nacional de Transportes Aquaviários), or ANTAQ;

 

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the Central Bank of Brazil (Banco Central do Brasil), or the Central Bank;

 

   

the Brazilian Institute of Geography and Statistics (Instituto Brasileiro de Geografia e Estatística), or the IBGE;

 

   

the International Monetary Fund, or the IMF;

 

   

Organization of the Petroleum Exporting Countries, or OPEC;

 

   

the Getulio Vargas Foundation (Fundação Getulio Vargas), or the FGV;

 

   

the Brazilian National Agency for Oil and Gas (Agência Nacional de Petróleo, Gás Natural, e Biocombustíveis), or the ANP;

 

   

Petróleo Brasileiro S.A.—Petrobras, or Petrobras;

 

   

the Brazilian National Environment Council (Conselho Nacional do Meio Ambiente), or the CONAMA;

 

   

the BP Statistical Review of World Energy; and

 

   

the World Bank.

The industry publications and surveys and forecasts from which we have derived this information generally state that the information contained therein has been obtained from sources believed to be reliable, and we are not aware of any misstatements regarding our market, industry or similar data presented herein. However, we have not independently verified such third party information. In addition, some data is also based on our good faith estimates and our management’s understanding of industry conditions. This data involves risks and uncertainties and is subject to change based on various factors, including those discussed under the headings “Special Note Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus.

Backlog

Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding any potential rig performance bonuses, which we have assumed will be paid to the maximum extent provided for in the respective contracts. Our calculation also assumes 100% uptime of our drilling rigs for the contract period; however, the amount of actual revenue earned and the actual periods during which revenues are earned may be different from the amounts and periods shown in the tables below due to various factors, including, but not limited to, stoppages for maintenance or upgrades, unplanned downtime, the learning curve related to commencement of operations of additional drilling units, weather conditions and other factors that may result in applicable dayrates lower than the full contractual operating dayrate. Contract drilling backlog includes revenues for mobilization and demobilization on a cash basis and assumes no contract extensions. However, our offshore rigs benefit from contracts that may be renewed for a period equivalent to the original contract term (subject to mutual consent of the parties), with the exception of our Alaskan Star and Atlantic Star rigs. Nevertheless, all of our contracts are subject to renewal through negotiation among the parties. In addition, in August 2012, we entered into the charter and corresponding service contracts of Urca, Bracuhy and Mangaratiba rigs, which have a 15-year term, renewable for an additional five-year period.

Our FPSO backlog is calculated for each FPSO by multiplying our percentage interest in the FPSO by the contracted operating dayrate by the firm contract period, in each case with respect to such FPSO. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated.

As of September 30, 2012, we maintained a backlog of $10.9 billion for contract drilling and FPSO services. This backlog included: (1) an aggregate amount of $3,624.0 million from charter and service contracts (including management fees) that our special purpose companies (owned together with Sete Brasil S.A., or Sete Brasil) and

 

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Queiroz Galvão Óleo e Gás S.A., or QGOG, respectively, entered into in August 2012 (relating to our 15% interest in these special purpose companies, each of which owns an ultra-deepwater semi-submersible rig: Urca, Bracuhy and Mangaratiba); (2) $1,907.7 million from the Amaralina Star and Laguna Star drillships in which we have a 55% interest, but with respect to which we will receive 100% of the charter and services revenues until the repayment in full of loans we have made to Alperton Capital Ltd., or Alperton (with a maximum term of 12 years) to fund its related equity contributions; and (3) $1,108.8 million from our 25.5% interest in a joint venture with SBM Holding Inc. S.A., or SBM Holding, related to our investment in FPSO Cidade de Ilhabela (assuming we exercise the option to increase our existing 12.75% interest by an additional 12.75% by 2014).

Rounding

We have made rounding adjustments to certain figures and percentages included in this prospectus. Accordingly, numerical figures presented as totals in some tables may not be an exact arithmetic aggregation of the figures that precede them.

Certain Definitions and Conventions

Definitions

Unless the context otherwise requires, in this prospectus references to:

 

   

“bbl” are to barrels;

 

   

“bblpd” are to barrels per day;

 

   

“boe” are to barrels of oil equivalent; one million boe is equivalent to approximately 5.35 billion cubic feet of natural gas, according to the conversion table from the 2012 BP Statistical Review of World Energy;

 

   

“boepd” are to barrels of oil equivalent per day;

 

   

“BOP” are to blowout preventers;

 

   

“CAGR” are to compounded annual growth rate;

 

   

“charters” are to the various contractual arrangements for the hiring of a unit covering both the rental of the unit itself, as provided under a charter contract, and the services required to operate the vessel, which are usually agreed upon under a separate service agreement;

 

   

“dayrates” are to daily fees earned by a unit, including, among others, the charter fees earned under a charter contract and the service fees earned under a service agreement;

 

   

“deepwater” are to water depths of approximately 3,000 feet to 7,499 feet;

 

   

“delivery date” are to (1) the date our offshore or onshore rig commenced or is expected to commence operations for the customer, (2) the date on which we acquired the offshore rig operating under an existing contract or (3) the date a FPSO produces or is expected to produce oil;

 

   

“drilling contracts” are to charter and service agreements entered into with customers.

 

   

“downtime” are to periods in which we do not earn a dayrate because there has been an interruption in activity due to, among other reasons, an operational mistake or equipment malfunction;

 

   

“DP” are to dynamically-positioned;

 

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“E&P” are to exploration and production of hydrocarbons;

 

   

“FPSO” are to a floating production storage and offloading unit, a type of floating tank system used by the offshore oil and gas industry and designed to take all of the oil or gas produced from nearby platforms or templates, process it, and store it until the oil or gas can be offloaded onto a tanker or transported through a pipeline;

 

   

“foot” or “feet” are to a unit of length equal to 12 inches or 0.3048 of a meter;

 

   

“HP” are to horsepower;

 

   

“learning curve” are to the period during which an operator becomes more familiar with the equipment and progressively reduces downtime until a point is reached when there is no significant improvement;

 

   

“midwater” are to water depths up to and including approximately 2,999 feet;

 

   

“pre-salt” are to areas more than 13,120 feet below the seabed, under layers of rock and salt;

 

   

“QG S.A.” are to Queiroz Galvão S.A., the Brazilian holding company for the Queiroz Galvão Group;

 

   

“Queiroz Galvão Group” are to the Brazilian conglomerate with activities in heavy construction, energy, oil and gas, infrastructure, real estate, agriculture and steel. We are part of the Queiroz Galvão Group as the ultimate beneficial owners of our company from the Queiroz Galvão family are also the ultimate beneficial owners of QG S.A., the holding company for the Queiroz Galvão Group;

 

   

“Sete Brasil” are to a Brazilian investment company focused on offshore drilling assets, which is majority owned by certain Brazilian pension funds and Banco Bradesco, Banco Santander and Banco BTG Pactual;

 

   

“SS” are to semi-submersible, a specialized rig design;

 

   

“stacking” are to maintaining an offshore rig in a yard, shipyard or sheltered waters until it is awarded a new assignment;

 

   

“stacking period” are to the period in which stacking occurs;

 

   

“ultra-deepwater” are to water depths of approximately 7,500 feet or more;

 

   

“uptime” are to periods in which we earn a dayrate; and

 

   

“VFD” are to variable frequency drive.

Implications of Being an Emerging Growth Company

In April 2012, the Jumpstart Our Business Startups Act, or the JOBS Act, was signed into law in the United States. The JOBS Act contains provisions that, among other things, relax certain U.S. reporting requirements for “emerging growth companies,” including certain requirements relating to accounting standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, unlike other U.S. public companies, we will not be required to (1) provide an independent auditor’s attestation report on the effectiveness of our internal controls over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act, (2) comply with any new requirements that may be adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory independent audit firm rotation or a supplement to the independent auditor’s report in which the independent auditor would be required to provide additional information about its audit and our financial statements or (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012 unless the SEC determines otherwise.

 

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Although we will not be required to provide an independent auditor’s attestation report for so long as we are an emerging growth company, we are currently in the process of implementing the necessary internal controls and expect to have established such policies and procedures to provide this attestation report in our second annual report filed with the SEC.

Section 102 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our decision to opt out of the extended transition period is irrevocable.

We may remain an emerging growth company for up to five years, although if during that five-year period (1) our annual gross revenue exceeds $1.0 billion during any fiscal year, (2) the aggregate amount of debt securities we issue during any three-year period exceeds $1.0 billion or (3) the market value of our common stock that is held by non-affiliates exceeds $700 million as of June 30 of any year, we would cease to be an emerging growth company as of the following December 31.

 

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PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. This summary does not contain all the information that you should consider before deciding to invest in our common shares. You should read the entire prospectus carefully, including the information presented under “Risk Factors” and our combined financial statements and notes to our combined financial statements, before making an investment decision.

Overview

We are a market leading Brazilian-controlled provider of offshore oil and gas contract drilling and FPSO services in Brazil. We are also one of the ten largest drilling companies globally, as measured by ultra-deepwater and deepwater drilling rigs in operation. We believe that our size and over 30 years of continuous operating experience in this industry provides us a competitive advantage in the Brazilian oil and gas market. In particular, we believe we are well positioned to benefit from the expected increase in ultra-deepwater drilling activity in Brazil, a market segment driven primarily by the recent discoveries of vast potential oil and gas reserves in the pre-salt layer offshore Brazil. We own and hold ownership interests in a fleet of state-of-the-art offshore and onshore drilling rigs and FPSOs, including nine ultra-deepwater rigs in operation or under construction. In 2011, we recorded net operating revenues of $586.3 million, a 2009-2011 annual net operating revenue CAGR of 93.5% and an EBITDA margin of 36.1%. For the nine-month period ended September 30, 2012, we recorded net operating revenues of $575.9 million and an EBITDA margin of 56.5%. We plan to continue our growth strategy through investments in additional premium ultra-deepwater drilling units and FPSOs. We are part of the Queiroz Galvão Group, which through QG S.A., the group’s Brazilian holding company, is one of the largest Brazilian conglomerates with $3.4 billion in consolidated gross revenues in 2011 and with a proven track record in heavy construction, energy, oil and gas, infrastructure, real estate, agriculture and steel. We have successfully capitalized on our market-leading position and industry expertise to accumulate a contract backlog of $10.9 billion as of September 30, 2012, a 136.6% increase from our contract backlog as of December 31, 2008.

We have a strong, long-term relationship with Petrobras, one of the world’s largest integrated oil and gas companies, which has been our principal client since we commenced operations in 1981. We believe that our long-term track record in Brazil and our relationship with Petrobras, together with our premium drilling assets, investments in FPSOs and affiliation with the Queiroz Galvão Group, will allow us to capture a significant share of the growing offshore services opportunity in Brazil.

Our Assets

Our assets consist of nine ultra-deepwater drilling rigs in (including one drillship under construction with Samsung Heavy Industries Co., Ltd., or Samsung, and three ultra-deepwater drilling rigs recently awarded by Petrobras to our strategic partner Sete Brasil), one deepwater drilling rig, two midwater drilling rigs, investments in four FPSOs and nine onshore drilling rigs. Our services subsidiary QGOG will be the sole operator of the rigs owned in partnership with Sete Brasil and will receive 100% of the services revenues from these rigs.

Offshore Drilling Rigs

Our offshore drilling assets are currently contracted to Petrobras under long-term contracts. The following table sets forth additional information with respect to each of our offshore drilling assets.

 

Rig

   %
Interest
    Type    Water
Depth (ft)
     Delivery Date    Dayrate
($/day) (7)
     Contract
Expiration
Date (8)

Ultra-deepwater (1):

                

Alpha Star

     100   DP; SS      9,000       July 2011      431,513       July 2017

Lone Star

     100   DP; SS      7,900       April 2011      349,212       March 2018

Gold Star

     100   DP; SS      9,000       February 2010      354,788       February 2015

Amaralina Star (2)

     55   DP drillship      10,000       September 2012      422,572       September 2018

Laguna Star (2)

     55   DP drillship      10,000       November 2012      422,572       November 2018

Urca (3)

     15   DP; SS      10,000       July 2016      566,757       July 2031

 

 

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Bracuhy (3)

     15   DP; SS      10,000       January 2018     571,135       January 2033

Mangaratiba (3)

     15   DP; SS      10,000       May 2019     575,544       May 2034

Deepwater:

               

Olinda Star

     100   Moored; SS      3,600       August 2009(4)     292,297       August 2014

Midwater:

               

Alaskan Star

     100   Moored; SS      1,700       December 2010(5)     304,063       November 2016

Atlantic Star

     100   Moored; SS      2,000       February 2011(6)     292,368       July 2018

 

(1) We, through one of our subsidiaries, have also entered into a contract with Samsung to design, construct, build, complete and deliver an ultra-deepwater drillship. See “Business—Backlog and Drilling Contracts—Samsung Letter of Intent.”
(2) We hold a 55% interest in these drillships through a strategic partnership with Alperton. We will receive 100% of the charter and services revenues from these drillships until the repayment in full of loans we have made to Alperton (with a maximum term of 12 years) to fund its related equity contributions. See “Business—Shareholder and Joint Venture Agreements—Shareholders Agreements Related to Amaralina Star and Laguna Star.”
(3) In connection with our strategic partnership with Sete Brasil, on August 3, 2012, we entered into three shareholders’ agreements and corresponding share purchase agreements pursuant to which we acquired a 15% equity interest in three special purpose companies, each one owning a semi-submersible rig. See “Business—Shareholder and Joint Venture Agreements.” In addition, we will be the sole operator and will receive 100% of the services revenues. The charter and service contracts in connection with our partnership with Sete Brasil were signed on August 3, 2012.
(4) Olinda Star underwent an upgrade with total cost of $275.2 million, which was concluded in August 2009.
(5) We acquired the Alaskan Star in 1994 while it was an operational rig. The Alaskan Star underwent upgrades with total cost of $132.4 million, including the last upgrade concluded in December 2010.
(6) We acquired the Atlantic Star in 1997 while it was an operational rig. Atlantic Star underwent upgrades with total cost of $116.3 million, including the last upgrade concluded in February 2011.
(7) Dayrates as of September 30, 2012. The dayrates reflect 100% of the charter and corresponding service contract dayrates and include the applicable performance bonus under each offshore charter and corresponding service contract. We are eligible for (i) an up to 10% performance bonus with respect to each of our Alpha Star, Amaralina Star, Laguna Star and Olinda Star units, (ii) an up to 15% performance bonus with respect to each of our Urca, Bracuhy, Mangaratiba, Lone Star, Alaskan Star and Atlantic Star units and (iii) no performance bonus with respect to our Gold Star rig. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Principal Factors Affecting our Results of Operations—Revenue per Asset, Utilization, Uptime and Dayrates of Our Drilling Rigs.”
(8) Our offshore rigs benefit from contracts that may be renewed for a period equivalent to the original contract term (subject to mutual consent of the parties), with the exception of our Alaskan Star and Atlantic Star rigs. Nevertheless, all of our contracts are subject to renewal through negotiation among the parties. In addition, in August 2012, we entered into the charter and corresponding service contracts of Urca, Bracuhy and Mangaratiba rigs, which have a 15-year term, renewable for an additional five-year period.

FPSOs

We have entered into strategic partnerships for our investments in FPSOs with SBM Holding, Mitsubishi Corporation, or Mitsubishi, BW Offshore do Brasil Ltda., or BWO, Nippon Yusen Kabushiki Kaisha, or NYK, and Itochu Corporation, or Itochu, to benefit from the increased demand for FPSOs. These FPSOs are currently chartered to Petrobras. The following table sets forth additional information about the FPSOs:

 

FPSO

   Status    % Interest   Daily
Production
Capacity
(bbl/day)
     Storage
Capacity
(bbl)
     Expected
Delivery Date
  Charter
Expiration
Date
   Total
Contract
Amount (in
millions of $)
(4)
 

Capixaba

   Operating    20%     100,000         1,600,000       May 2006(1)   May 2022      1,774.9   

Cidade de Paraty

   Construction    20%     120,000         2,300,000       May 2013   April 2033      4,254.2   

Cidade de Ilhabela

   Construction    12.75%(2)     150,000         2,400,000       September 2014   August 2034      5,220.5   

P-63 (Papa Terra) (3)

   Construction    —       140,000         2,200,000       July 2013   June 2016      89.1   

 

(1) The FPSO Capixaba was built in May 2006, and we subsequently entered into a partnership with SBM to acquire our interest in this FPSO.
(2) We currently own an equity interest of 12.75% with an option to increase our interest to 25.5% after first oil production.
(3) We own a 40% participation in the operating contract, but not an ownership interest in the asset. The term of the operating contract is 50 months. Petrobras owns this FPSO and no charter agreement exists.
(4) Except in the case of P-63, for which the total contract amount refers to 100% of the amounts to be paid under the service contract, total contract amount refers to 100% of the amounts to be paid under both the charter and corresponding services contract.

 

 

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Onshore Drilling Rigs

The following table sets forth additional information about our onshore drilling assets, which are all owned entirely by us, and we currently contract to Petrobras, OGX Petróleo e Gás Participações S.A., or OGX, and HRT O&G Exploração e Produção Ltda., or HRT:

 

Onshore Rig

   Type    Drilling Depth
Capacity (ft)
     Customer    Contract Expiration
Date

QG-I

   1600HP      16,500       OGX    February 2013(1)

QG-II

   1600HP      16,500       Petrobras    January 2014

QG-III

   Heli-portable; 1200HP      11,500       Petrobras    April 2014

QG-IV

   Heli-portable; 550HP      9,800       Petrobras    April 2014

QG-V

   Heli-portable; 1600HP      14,800       Petrobras    April 2015

QG-VI

   2000HP      23,000       Petrobras    June 2014

QG-VII

   2000HP      23,000       Petrobras    June 2014

QG-VIII

   Heli-portable; 1600HP      14,800       HRT    April 2015

QG-IX

   Heli-portable; 1600HP      14,800       HRT    April 2015

 

(1) On December 19, 2012, we signed a contract with Shell to provide onshore drilling services in the São Francisco Basin, Brazil, using the onshore rig QG-I. We expect to begin providing these services during the second half of 2013, after the expiration of our current contract for the QG-I rig with OGX.

Market conditions in the Brazilian oil and gas sector

According to the 2012 BP Statistical Review of World Energy, Brazil’s oil and gas reserves are among the fastest growing in the world. Proven oil reserves in Brazil have grown from 4.8 billion barrels at the end of 1991 to 15.1 billion barrels at the end of 2011. During the same period, proven natural gas reserves in Brazil grew from 4.0 trillion cubic feet to 16.0 trillion cubic feet. The Campos and Santos Basins account for the majority of the growth in these reserves in recent years. The Campos Basin covers approximately 100,000 km2 (24.7 million acres) and currently accounts for nearly 86% of Brazil’s oil production and 80% of Petrobras’ proven crude oil reserves in Brazil. The Santos Basin is located in the southeastern region off the Brazilian coast, covering an area of approximately 350,000 km2 (86.5 million acres) and is currently considered the most promising exploration and production area in Brazil, due to recent discoveries in the pre-salt layer. As disclosed by Petrobras, the Lula Field (formerly known as the Tupi Field), recently discovered in this basin, contains an estimated recoverable volume of 6.5 billion boe of reserves, and there are significant volumes in other relevant discoveries in other fields in the same basin, such as the Guará, Carioca and Jupiter Fields.

While pre-salt activity currently comprises only 5% of Brazil’s total current production, it is projected by Petrobras to increase to over 47% by 2020. The anticipated development of the pre-salt offshore fields contributes largely to the growth prospects of the Brazilian oil and gas industry. From 2006 to 2011, 50% of new discoveries globally were in deepwater, and of those, 63% were in Brazil according to Petrobras.

In June 2012, Petrobras disclosed its five-year investment plan, which provides for an aggregate of $237 billion in capital expenditures from 2012 through 2016, up from an aggregate of $174 billion in capital expenditures in its 2009-2014 investment plan. Approximately $142 billion (or 60%) of these capital expenditures are budgeted for E&P projects, with $132 billion to be spent in Brazil which has led to an increase in demand for our services, which we expect will continue in the coming years. Petrobras expects its total production to more than double from the current 2.6 million boepd to an estimated 5.7 million boepd in 2020.

Our competitive strengths

We believe the following strengths have contributed to our success and differentiate us from our competitors:

Strong competence in ultra-deepwater drilling in Brazil. We have a long track record of operating drilling rigs for the exploration of oil and gas in Brazilian waters. In the ultra-deepwater segment, we currently operate a modern fleet of five drilling rigs which drilled ten wells in 2010 and 2011. Our fleet of ultra-deepwater drilling rigs is one of the largest Brazilian owned ultra-deepwater fleets in the industry. Ultra-deepwater drilling is inherently more complex and operationally challenging than drilling in shallower water depths. We are one of a small group of Brazilian contract drillers with commercial scale and demonstrated ultra-deepwater drilling competence. Our deepwater contract drilling operations achieved 94% average uptime in 2011, and we expect to improve our performance in 2012 following the learning curve of our deepwater rigs. After the initial learning curve period of 12 to 24 months, we expect to achieve average uptime for our ultra-deepwater rigs that is consistent with the performance our deepwater rig achieved in 2011.

 

 

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Premium fleet of offshore drilling rigs. We have a modern fleet of drilling rigs constructed by many of the world’s leading shipyards, including Samsung and Keppel FELS. Our existing ultra-deepwater semi-submersible rigs have the capability to operate in water depths ranging from 7,900 to 9,000 feet and drill to a total well depth of 30,000 feet. In addition, we have two drillships in operation (Amaralina Star and Laguna Star), each of which is capable of drilling in water depths of up to 10,000 feet and drill to a total well depth of 40,000 feet. We have regularly upgraded our drilling rigs to incorporate technological advances that increase the efficiency of our operations. As of the date of this prospectus, all of our offshore drilling rigs were either less than three years old or had major upgrades within the last three years.

Strong relationship with Petrobras. We have maintained a strong and long-standing relationship with Petrobras having performed continuous drilling services for the company since 1981. Our extensive knowledge and experience in the Brazilian drilling market is the principal basis of our strong relationship. All of our operating offshore drilling rigs, all of the FPSOs in which we have invested and six of our onshore drilling rigs are currently contracted to Petrobras. In addition, most of our senior executives have more than 30 years of experience working with Petrobras. We believe we are well positioned to continue as a strategic service provider to Petrobras by renewing our current charter and service contracts and entering into new charter and service contracts with Petrobras. We further believe that the Queiroz Galvão Group’s long, close business relationship with Petrobras in a number of areas, including heavy construction and E&P, strengthens our business prospects in the oil and gas industry.

Financial ability to execute growth plan. We enter into long-term charter contracts with respect to all of our offshore drilling rigs and FPSOs. Our contract profile provides significant revenue visibility which enables ongoing access to various sources of capital. Typically, we fund the majority of our investments in new offshore assets through project financing in the bank and capital markets. Our long-term contracts, our significant experience with obtaining financing, even under distressed markets, and our regular dialogue with international banks, lenders and investors increase our ability to obtain capital to fund additions to our fleet of offshore assets.

High safety standards and strong track record. In addition to our focus on operational performance and drilling efficiency, we operate with the highest Quality, Health, Safety and Environment, or QHSE, standards. All of our drilling operations are certified by ISO 9001:2008, ISO14001:2004 and OHSAS18001:2007 standards, which were renewed in November 2011. Although not mandatory in our line of business, our adoption of these standards is a testament to our commitment to QHSE.

Highly skilled employees with low turnover. We employ skilled personnel to operate and provide technical services to, and support for, our rigs. As of September 30, 2012, we had a total of 2,370 employees. We enjoy low turnover levels among the crew and key officers of our drilling units, which is an important factor in achieving high levels of uptime of our rigs and which is especially critical in the skilled-personnel labor market in Brazil. We employ an ongoing, robust training program for all of our employees, which promotes, among other factors, superior safety practices. We use this program to develop talent organically and to regularly promote people from within our company to more senior positions. We also take advantage of our onshore rigs to train our personnel for work on our more complex offshore drilling rigs.

Highly experienced management team backed by a strong shareholder group. Our management team is comprised of highly trained executives, most with more than 30 years of experience in the Brazilian and global oil and gas sector. Our executives have in-depth knowledge of drilling and FPSO operations, including project bidding, procurement, overseeing construction and upgrades of drilling rigs and the efficient, safe and profitable operation of our assets. Moreover, prior to joining us, many of our key executives worked at Petrobras and other international oil and gas companies, as well as leading global services companies.

Our controlling shareholders are members of the Queiroz Galvão family, which controls the Queiroz Galvão Group. In 2011, the consolidated gross revenue of the Queiroz Galvão Group was $3.4 billion. We believe that the Queiroz Galvão Group’s recognized financial strength, geographic diversity and successful business track record in a wide spectrum of industries, represent key competitive advantages for our development and growth.

 

 

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In June 2010, Capital International Private Equity Funds, or CIPEF, a global emerging markets private equity program managed by Capital International, Inc., or Capital, acquired an equity interest of 19.5% in Constellation (which, after the completion of the first stage of our corporate reorganization, resulted in CIPEF holding an equivalent equity interest in our capital stock). Capital is currently represented on our Board of Directors and has contributed to our adoption of best corporate governance practices and financial management tools. Through a CIPEF fund, the Oil & Gas Group of the International Finance Corporation, a unit of the World Bank Group, invested $100 million in a co-investment vehicle for our company organized by CIPEF and as a result, is one of our indirect shareholders.

Our growth strategies

We have consistently grown in accordance with our growth strategy. Our net operating revenues increased by 69.1% to $586.3 million in 2011 from $346.8 million in 2010. Our net operating revenues increased 38.7% to $575.9 million for the nine-month period ended September 30, 2012 from $415.3 million for the nine-month period ended September 30, 2011. Furthermore, we have increased our backlog to $10.9 billion as of September 30, 2012 from $4.6 billion as of December 31, 2008, an increase of 136.6%. Our backlog of $10.9 billion as of September 30, 2012 represents 14.6 times our net operating revenues for the 12-month period ended September 30, 2012.

We intend to pursue the following strategies:

Capitalize on our market-leading position in the Brazilian ultra-deepwater drilling and FPSO sectors. As a recognized Brazilian market leader, we intend to capitalize on our strong market position in Brazil and close relationship with Petrobras to continue to grow our ultra-deepwater and FPSO operations. For example, we entered into a partnership with Sete Brasil through which we own a 15% equity interest in and will operate three ultra-deepwater drilling rigs that will be built at the BrasFELS Shipyard, a subsidiary of Keppel FELS Ltd., the shipyard with a strong track record in Brazil. These three rigs are expected to commence operations in 2016, 2018 and 2019, respectively, and we will operate these units for Petrobras. We have also entered into a partnership with SBM Holding and Mitsubishi through which we have a right of first refusal to participate in future FPSO projects contracted by them with Petrobras in Brazil. We intend to further develop our FPSO partnerships in Brazil through the co-ownership and operation of additional FPSO units.

Significantly expand our business by investing in state-of-the-art ultra-deepwater drilling rigs. We have planned up to $5.1 billion of investments, $3.1 billion of which are related to already existing commitments, principally in new ultra-deepwater drilling rigs and FPSOs through 2015 to take advantage of Petrobras’ significant capital expenditure plan and expand our dominant position in Brazil. We are focused on using and investing in new and proven technologies that have the potential to maximize efficiency, reduce environmental impact and enhance safety. We expect that all rigs we procure will be constructed under fixed-price contracts with top-rated shipyards.

We are also exploring strategic acquisitions of drilling assets, or investments in contract drilling companies, on an opportunistic basis, that we expect could enhance our growth, create value for our shareholders and increase our global market share. We believe that our extensive knowledge of the Brazilian oil and gas market, particularly in ultra-deepwater operations, will be critical in the pursuit of these opportunities either in Brazil or outside Brazil.

Through these organic and strategic growth initiatives, we plan to double the number of our ultra-deepwater fleet by 2020.

Strengthen our relationship with Petrobras and other companies. Our longstanding and strong relationship with Petrobras positions us well to capitalize on the expected growth in the Brazilian and global oil and gas markets. We intend to continue to work to strengthen our relationship with Petrobras to develop additional offshore and onshore drilling projects. In addition, we will continue to strengthen our relationships with international companies and other Brazilian companies in an effort to opportunistically pursue other offshore and onshore projects.

Seek revenue visibility through financially attractive long-term contracts. We believe that our focus on long-term contracts reduces our exposure to market risks and provides access to stable and reliable revenues. The average length of charter contracts in Brazil is longer than in other markets. Our focus on long-term contracts for

 

 

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exploration and development projects in deep and ultra-deepwater continues to strengthen our relationship with Petrobras, which values reliability and superior service. We believe that our long-term contracts will increase our ability to raise capital for the acquisition of additional drilling and FPSO units as well as to fund other growth opportunities. In addition, given the expected growth in demand for offshore drilling rigs globally and in Brazil, we intend to seek to negotiate higher dayrates upon the expiration of our current charter contracts. We plan to achieve this by seeking contracts that require the most technologically advanced rigs, which are needed for more complex ultra-deepwater and deepwater drilling services. Furthermore, certain of our current charter and service contracts permit their renewal subject to our and our counterparty’s consent, and, based on our successful history of contract renewals at higher rates we expect to be able to successfully negotiate the renewal of these contracts on market terms.

Focus on high operational performance and QHSE standards. We intend to maintain our strong focus on the continued high quality performance and safety of our operations. Our management team is dedicated to the superior performance of our assets by hiring and retaining highly-skilled employees and training current employees. We maintain high QHSE standards by maintaining our certifications in ISO 9001:2008, ISO14001:2004 and OHSAS18001:2007 standards and focusing on investing in state-of-the-art technology and performing planned maintenance on our drilling units. In addition, we are committed to continuing to provide safety training to maintain the quality of service to our clients expect from us, including low downtime for our rigs.

Risk Factors

Investing in our common shares involves risks. You should carefully consider the risks described in “Risk Factors” before making a decision to invest in our common shares. If any of these risks actually were to occur, our business, financial condition and results of operations would likely be materially adversely affected, the trading price of our common shares would likely decline and you may lose all or part of your investment. The following is a summary of some of the principal risks we face:

 

   

Currently, we derive nearly all of our revenue from Petrobras. The loss of Petrobras as our customer, or a reduction of our revenue from Petrobras, could have a material adverse impact on us;

 

   

Our customers may seek to renegotiate or terminate certain of our drilling contracts if we experience excessive delivery and acceptance delays for our assets, downtime, operational difficulties or safety-related issues, or in case of non-compliance with our obligations set forth in our drilling contracts, which would materially adversely affect our ability to realize our backlog of contract revenue;

 

   

If we are unable to renew or obtain new and favorable contracts to replace contracts for rigs that expire or are terminated, our revenue and profitability would be materially and adversely affected;

 

   

The vast majority of our contracts with our customers are long-term dayrate contracts. Increases in our operating costs, which fluctuate, including based on certain events outside our control, could materially adversely affect our profitability;

 

   

Rig and FPSO upgrade, refurbishment, repair and construction projects are subject to risks, including delays and cost overruns, which could have a material adverse impact on our available cash resources and results of operations;

 

   

We are a holding company that depends on dividend distributions from our operating subsidiaries, and we have a substantial amount of indebtedness, which could restrict our financing and operating flexibility;

 

   

We have a business plan that contemplates significant growth, which requires substantial additional capital, and we may be unable to execute our growth strategy or obtain needed capital or financing on satisfactory terms, or at all;

 

   

The ownership and operation of rigs and FPSO units involves numerous operating hazards, and the insurance we purchase may not cover all of our losses and may not be renewed on favorable terms, including reasonable prices. Accidents may subject us to civil, property, environmental and other damage claims, including by Petrobras, federal, state or municipal governmental entities in Brazil, and third parties;

 

 

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We have a limited number of potential customers;

 

   

Certain of our partnerships or joint ventures may not succeed due to several factors;

 

   

A substantial or extended decline in expenditures by oil and gas companies due to a decline or volatility in oil and gas prices may reduce long-term demand for our services and adversely affect our ability to successfully negotiate the renewal terms of our current charter and service contracts over the long-term or enter into new charter or service contracts upon termination of our current contracts;

 

   

Global ultra-deepwater rig and FPSO demand is highly dependent on Petrobras’ development plan for offshore drilling in Brazil;

 

   

Our industry is highly competitive and cyclical, with potential intense price competition and oversupply of drilling equipment;

 

   

We depend on a limited number of key suppliers and vendors to provide equipment that we need to operate our business and any failure by our key suppliers and vendors to supply necessary equipment on a timely basis or at all, could materially adversely affect us;

 

   

We have a limited operating history in the ultra-deepwater sector, which makes it more difficult to accurately forecast our future results and may make it difficult for investors to evaluate our business and our future prospects, both of which will increase the risk of your investment in our common shares;

 

   

Our failure to maintain or renew all necessary authorizations and certifications required for the operation of our rigs, and changes in current licensing regimes may have a material adverse effect on our operations; and

 

   

Complex and stringent environmental laws and regulations may increase our exposure to environmental and other liabilities, may increase our exposure to environmental and other liabilities, and may increase operating costs and adversely affect the operation of our rigs.

Corporate Reorganization

Our offshore drilling assets are owned by special purpose companies that we own and control. We also own and control other special purpose companies that are party to our offshore charter agreements with Petrobras. In addition, we own 100% of the outstanding preferred shares and 49% of the outstanding common shares of QGOG, which is party to all of our services agreements and the charter agreements for all our onshore drilling rigs. The remaining 51% of QGOG’s voting capital stock is owned by QG S.A. In connection with the shareholders’ agreement, we, through our subsidiary QGOG Participações S.A., or QGOGPar, also entered into a call option agreement to purchase the remaining 51% of QGOG’s common shares.

We are controlled by a holding company, Queiroz Galvão Oil & Gas International S.à.r.l., or Queiroz Galvão Oil & Gas, owned by the Queiroz Galvão family, which owns approximately 80.5% of our outstanding equity, with the remaining 19.5% owned indirectly by private equity funds managed by CIPEF. See “Principal Shareholders.”

We recently completed our corporate reorganization. As a result, we indirectly own all of the oil and gas contract drilling assets and interests in FPSO assets through five wholly-owned sub-holding companies:

 

   

QGOG Star GmbH, an entity organized under the laws of Switzerland on May 2, 2012, which wholly-owns Constellation. Constellation will continue to wholly-own, directly and indirectly, the entities which own the drilling rigs.

 

 

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Arazi S.à.r.l., or Arazi, an entity organized under the laws of Luxembourg on May 12, 2011, which owns our equity interest in FPSO Capixaba, FPSO Cidade de Ilhabela and FPSO Cidade de Paraty.

 

   

Constellation Netherlands B.V., an entity organized under the laws of the Netherlands on April 3, 2012, which will indirectly wholly-own certain of the entities that are party to our offshore charter agreements with Petrobras.

 

   

Angra Participações B.V., or Angra, an entity organized under the laws of the Netherlands on May 11, 2012, which holds a 15% equity interest in three special purpose companies, each of which owns an ultra-deepwater semi-submersible rig (Urca, Bracuhy and Mangaratiba) in a strategic partnership with Sete Brasil.

 

   

Centaurus S.à.r.l., or Centaurus, an entity organized under the laws of Luxembourg on July 27, 2007, which directly wholly-owns Eiffel Ridge Group C.V., an entity that is party to the Lone Star and Gold Star charter agreements with Petrobras.

 

 

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The following chart sets forth our expected corporate structure after giving effect to the contemplated issuance and sale of common shares in this offering, assuming no exercise of the underwriters’ over-allotment option:

 

LOGO

 

(1) The Queiroz Galvão family holds approximately 80.5% of our common shares. See “Principal Shareholders” for further information.
(2) CIPEF Constellation Coinvestment Fund L.P. and CIPEF V Constellation Holding L.P. (each a Delaware entity). See “Principal Shareholders” for further information.
(3) Constellation Coinvestment Fund S.à.r.l. (wholly-owned by CIPEF Constellation Coinvestment Fund L.P.) and Constellation Holdings S.à.r.l. (wholly-owned by CIPEF V Constellation Holding L.P.)
(4) Issuer.
(5) Constellation Services S.A. (BVI), Lone Star Offshore Ltd. (BVI), Gold Star Equities Ltd. (BVI), Alpha Star Equities Ltd. (BVI), Olinda Star Ltd. (BVI), Snover Intl. Inc. (BVI), Hopelake Services Ltd. (BVI), Lancaster Projects Corp. (BVI), Laguna Star Ltd. (BVI), Amaralina Star Ltd. (BVI), Alaskan Star Ltd. (BVI), Star International Drilling Limited (Cayman Islands), Alaskan & Atlantic & Cooperatief U.A. (the Netherlands), Alaskan &Atlantic Rigs B.V. (The Netherlands), Atlantic/Alaskan Rigs Ltd. (BVI), Manisa Serviços de Petróleo Ltda (Brazil), Laguna Cooperatief U.A. (The Netherlands), Amaralina Cooperatief U.A. (The Netherlands), Keam Holdings C.V. (The Netherlands), Tarsus Serviços de Petróleo Ltda (Brazil) and Tenfield Management Corp. (BVI).
(6) London Tower C.V. (The Netherlands), Positive Investment Management B.V. (The Netherlands), Positive Investments (The Netherlands), London Tower Management B.V. (The Netherlands), Palase Management B.V. (The Netherlands), Palase C.V. (The Netherlands), Podocarpus Management B.V. (The Netherlands) and Podocarpus C.V. (The Netherlands). Palase C.V. (The Netherlands) is majority-owned by Amaralina Cooperatief U.A. (The Netherlands) and Podocarpus C.V. (The Netherlands) is majority-owned by Laguna Cooperatief U.A. (The Netherlands). Both Amaralina Cooperatief U.A. (The Netherlands) and Laguna Cooperatief U.A. (The Netherlands) are indirectly owned by Constellation.
(7) QGOGPar holds 49% and 100% of the common shares and preferred shares, respectively, of QGOG.
(8) QG S.A. holds 51% of the common shares of QGOG.

 

 

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(9) QGOGPar holds a call option to purchase the remaining 51% of QGOG’s common shares from QG S.A., which effectively gives QGOGPar control over QGOG.
(10) Arazi holds our equity interests in FPSOs.
(11) Angra holds a 15% equity interest in three special purpose companies, each of which will own an ultra-deepwater semi-submersible rig (Urca, Bracuhy and Mangaratiba) in a strategic partnership with Sete Brasil.
(12) Centaurus directly wholly owns Becrux B.V. (The Netherlands). Becrux B.V. (The Netherlands) owns a 0.001% equity interest in Eiffel Ridge Group C.V. (The Netherlands), an entity that is party to the Lone Star and Gold Star charter agreements with Petrobras. The remaining 99.999% equity interest in Eiffel Ridge Group C.V. is directly owned by Centaurus.

Recent Developments

Onshore drilling contract signed with Shell

On December 19, 2012, we signed a contract with Shell to provide onshore drilling services in the São Francisco Basin, Brazil, using the onshore rig QG-I. We expect to begin providing these services during the second half of 2013, after the expiration of our current contract for the QG-I rig with OGX.

Short-term loans pre-payment

On December 14, 2012 we prepaid $350.1 million of our short-term debt with Banco Bradesco S.A., and on December 13, 2012 we prepaid $151.9 million of our short-term debt with Banco Itaú BBA S.A., in each case, using a portion of the net proceeds from our 6.250% senior notes due 2019 described below. We intend to repay our short-term debt with Banco do Brasil S.A. in full ($123.2 million) upon its final maturity on August 30, 2013.

Laguna Star Drillship

We commenced operations of the Laguna Star drillship on November 20, 2012.

Samsung Construction Contract

On November 14, 2012, we, through one of our subsidiaries, exercised an option to enter into a contract with Samsung to design, construct, build, complete and deliver an ultra-deepwater drillship. According to the payment schedule, we paid 10% of the contract price as a first installment, 20% of the contract as a second installment is due in October 2013 and 70% of the contract price upon delivery, subject to the terms and conditions of the construction contract. We expect that Samsung will deliver this ultra-deepwater drillship by December 2014. The total contract price is $586.4 million. See “Business—Backlog and Drilling Contracts—Samsung Letter of Intent.”

6.250% Senior Notes due 2019

On November 9, 2012, we issued $700.0 million aggregate principal amount of 6.250% senior notes due 2019. The notes are fully and unconditionally guaranteed on a senior basis by Constellation. We have used $502.0 million of the net proceeds of the offering, or $683.3 million, to repay outstanding short-term debt and intend to use the remaining net proceeds to repay other outstanding short-term debt and for general corporate purposes. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments” and “Capitalization.”

Corporate information

We were incorporated as a société anonyme under the laws of Luxembourg on August 30, 2011. Our principal executive offices are located at 40, avenue Monterey, L-2163 Luxembourg. Our telephone number is +352 20 20 2401.

 

 

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THE OFFERING

The following is a brief summary of the terms of this offering. For a more complete description of our common shares, see “Description of Capital Stock” in this prospectus.

 

Issuer

QGOG Constellation S.A.

 

Primary Offering

We are offering             common shares.

 

Offering Price Range

Between $         and $         per share.

 

Option to Purchase Additional Common Shares

We have granted the underwriters the right to purchase             additional common shares within 30 days from the date of this prospectus.

 

Use of Proceeds

We estimate that we will receive net proceeds (based on the midpoint of the range set forth on the cover page of this prospectus), after deducting the underwriters’ discounts and commissions and estimated expenses incurred in connection with this offering, of $         million. If the underwriters exercise their option to purchase additional common shares in full, we estimate that the net proceeds will be approximately $         million.

 

  We intend to use the net proceeds from this offering (1) to make down payments for two ultra-deepwater drillships, one of which is subject to the exercise of an option pursuant to a letter of intent we have executed with Samsung (as described in “Business—Backlog and Drilling Contracts—Samsung Letter of Intent”), (2) to make capital expenditures and related expenses for certain existing projects and (3) to make capital expenditures and investments related to expected new projects, including new opportunities involving the purchase of assets, and/or equity interests in, drilling and/or production service companies, and related expenses in connection therewith and for general corporate purposes, including the payment of an IPO completion bonus to certain of our employees (as described in “Management—Compensation—IPO Completion Bonus”). See “Use of Proceeds.”

 

Share Capital Before and After Offering

The issued and outstanding share capital consists of             common shares as of the date of this prospectus. Immediately after this offering, we will have common shares issued and outstanding, assuming no exercise of the underwriters’ option to purchase additional common shares. If the underwriters exercise their option to purchase additional common shares in full, we will have             common shares issued and outstanding.

 

Voting Rights

Holders of our common shares are entitled to one vote per common share in all shareholders’ meetings. See “Description of Capital Stock—Voting Rights.”

 

Dividends

We have not paid a dividend on our common shares, in cash or otherwise, and we do not intend to do so in the near future. Any future determination relating to our dividend policy will be made by our Board of Directors and will depend on a number of factors, including our earnings, capital requirements, contractual restrictions, financial condition and future prospects, together with any other factors that our Board of Directors may deem relevant. See “Dividend Policy.”

 

Lock-up Agreements

We have agreed with the underwriters, subject to certain exceptions, not to sell or dispose of any common shares or securities convertible into or exchangeable or exercisable for any common shares during the period commencing on the date of this prospectus until 180 days after the completion of this offering. Members of our Board of Directors, our executive officers and our shareholders have agreed to similar lock-up provisions, subject to certain exceptions. See “Underwriting.”

 

 

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Listing

We intend to apply to list our common shares on the New York Stock Exchange under the symbol “QGOG.”

 

Risk Factors

Investing in our common shares involves a significant degree of risk. See “Risk Factors” beginning on page 15 of this prospectus and the other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in our common shares.

Unless otherwise indicated, all information contained in this prospectus assumes no exercise of the option granted to the underwriters to purchase additional securities.

 

 

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SUMMARY FINANCIAL AND OTHER DATA

The following tables set forth our summary financial and other data. You should read the following summary financial and other data in conjunction with “Presentation of Financial and Other Information”. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this prospectus. Historical results are not indicative of the results to be expected in the future. Our financial statements have been prepared in accordance with IFRS as issued by the IASB. The summary statement of operations for the nine-month periods ended September 30, 2012 and 2011 and for the three years ended December 31, 2011 and the summary statement of financial position data as of September 30, 2012 and December 31, 2011 and 2010, are derived from:

 

   

our unaudited condensed consolidated interim financial information as of September 30, 2012 and for the three and nine-month periods ended September 30, 2012 and 2011; and

 

   

our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011.

The audited combined financial statements as of December 31, 2011 and 2010, and for each of the three years ended December 31, 2011 have been restated as described in the “Presentation of Financial and Other Information” section.

Our results for the nine-month period ended September 30, 2012 are not necessarily indicative of the results to be expected for the year ending December 31, 2012.

 

     For the nine–month period
ended September 30,

(unaudited)
    For the year ended December 31,  
         2012             2011             2011             2010             2009      
     (in millions of $, except per share data)  

Statement of Operations Data:

  

Net operating revenue

     575.9        415.3        586.3        346.8        156.6   

Costs of services

     (342.5     (314.5     (466.1     (264.5     (141.2
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

     233.5        100.9        120.2        82.3        15.4   

General and administrative expenses

     (31.5     (22.1     (29.8     (24.7     (20.0

Other operating income (expenses), net

     1.8        (10.5     (11.3     (34.3     (15.9
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating profit (loss)

     203.8        68.2        79.1        23.3        (20.5

Financial costs, net

     (94.2     (92.7     (118.5     (76.3     (32.0

Share of results of joint ventures

     2.4        0.5        1.0        6.2        6.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before taxes

     112.0        (23.9     (38.4     (46.8     (45.6

Taxes

     (0.7     (0.7     (5.1     1.5        0.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) for the period

     111.3        (24.7     (43.5     (45.3     (44.7
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net earnings (loss) per common share (1):

          

Basic

     2.00        (0.44     (0.71     (0.81     (0.80

Diluted

     2.00        (0.44     (0.71     (0.81     (0.80

Weighted average common shares outstanding (thousands of common shares):

          

Basic

     55,632        55,632        55,632        55,632        55,632   

Diluted

     55,632        55,632        55,632        55,632        55,632   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Net income per share as attributed to the company excludes income/losses attributed to non-controlling interests.

 

 

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The following table sets forth a reconciliation of our EBITDA to net income (loss) for each of the periods and years presented:

 

     For the nine–month  period
ended September 30, (unaudited)
    For the year ended December 31,  
         2012             2011             2011             2010             2009      
     (in millions of $)  

Other Financial Information:

  

Net income (loss) for the period/year

     111.3        (24.7     (43.5     (45.3     (44.7

(+) Financial costs, net

     94.2        92.7        118.5        76.3        32.0   

(+) Taxes

     0.7        0.7        5.1        (1.5     (0.9

(+) Depreciation

     119.4        92.5        131.3        90.6        49.5   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA (1)(2)

     325.6        161.2        211.4        120.1        35.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA margin (%)(3)

     56.5     38.8     36.1     34.6     22.9

 

(1) EBITDA was adversely impacted by provisions related to penalties due to late delivery of rigs of $10.7 million for the nine-month period ended September 30, 2011 and $10.8 million, $35.0 million and $17.3 million for the years ended December 2011, 2010 and 2009, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Year Ended December 31, 2011 Compared with Year Ended December 31, 2010—Other Operating Expenses, Net” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Year Ended December 31, 2010 Compared with Year Ended December 31, 2009—Other Operating Expenses, Net.”
(2) EBITDA is a non-GAAP measure prepared by us. EBITDA consists of: net income, plus financial costs, net, taxes and depreciation. EBITDA is not a measure defined under IFRS, should not be considered in isolation, does not represent cash flow for the periods indicated and should not be regarded as an alternative to cash flow or net income, or as an indicator of operational performance or liquidity. EBITDA does not have a standardized meaning, and different companies may use different EBITDA definitions. Therefore our definition of EBITDA may not be comparable to the definitions used by other companies. We use EBITDA to analyze our operational and financial performance, as well as a basis for administrative decisions. The use of EBITDA as an indicator of our profitability has limitations because it does not account for certain costs in connection with our business, such as financial costs, net, taxes, depreciation, capital expenses and other related expenses.
(3) EBITDA margin is a non-GAAP measure prepared by us. EBITDA margin is calculated by dividing EBITDA by net operating revenue for the applicable period.

 

     As of September  30,
(unaudited)
     As of December 31,  
     2012      2011      2010      2009  
     (in millions of $)  

Statement of Financial Position:

  

Cash and cash equivalents

     276.7         188.9         84.3         63.1   

Short-term investments

     116.1         138.7         8.5         36.1   

Restricted cash

     17.9         26.3         29.6         —     

Total assets

     5,132.8         4,734.1         3,678.5         2,912.5   

Total loans and financings

     3,336.2         2,440.5         2,006.3         1,716.6   

Total liabilities

     3,895.2         3,611.7         2,451.5         2,049.6   

Shareholders’ equity

     1,237.6         1,122.4         1,227.0         862.9   

 

 

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RISK FACTORS

This initial public offering and an investment in our common shares involve a significant degree of risk. You should consider carefully the risks described below and all other information contained in this prospectus, before you decide to invest in our common shares. If any of the following risks were to occur, our business, financial condition and results of operations we would likely be materially adversely affected. In that event, the trading price of our common shares would likely decline and you might lose all or part of your investment.

For purposes of this section, the indication that a risk, uncertainty or problem may or will have a “material adverse effect on us” or that we may experience a “material adverse effect” means that the risk, uncertainty or problem could have a material adverse effect on our business, financial condition or results of operations and/or the market price of our common shares, except as otherwise indicated or as the context may otherwise require. You should view similar expressions in this section as having a similar meaning.

Risks Related to our Company

Currently, we derive nearly all of our revenue from Petrobras. The loss of Petrobras as our customer, or a reduction of our revenue from Petrobras, could have a material adverse impact on us.

During each of the nine-month period ended September 30, 2012, and the year ended December 31, 2011, our gross revenue from Petrobras represented approximately 94% and 93% of our total gross revenue, respectively. Most of our existing rigs, including six onshore rigs, six semi-submersible rigs, two drillships and one FPSO in which we have an investment, are chartered to Petrobras. In addition, we currently have three FPSOs (in which we have invested) under construction, and two drillships in operation for which we have entered into long-term charter agreements with Petrobras. Our results of operations would be materially adversely affected if Petrobras were to terminate its contracts with us, fail to renew its existing contracts with us or refuse to award new contracts to us, as there are only a limited number of potential customers that are available to replace Petrobras. Petrobras is the largest E&P company in Brazil, so if it were to take any of these actions, we may be unable to enter into new charter agreements for our rigs and the FPSOs in which we have invested on similar terms or on a timely basis, if at all, which would have a material adverse effect on us.

Our customers may seek to renegotiate or terminate certain of our drilling contracts if we experience excessive delivery and acceptance delays for our assets, downtime, operational difficulties or safety-related issues, or in case of non-compliance with our obligations set forth in the drilling contracts, which would materially adversely affect our ability to realize our backlog of contract revenue.

Our contracts with our customers permit them to terminate or seek to renegotiate their contracts, or seek to impose penalties, if we experience (1) delays in delivering a contracted rig, (2) any failure of a contracted rig to pass initial acceptance testing within the period specified in the contract, (3) downtime or operational problems that exceed permissible levels under our contracts, (4) specified safety-related issues, or (5) any failure to comply with other obligations set forth in such contracts. The damages we suffer and the expenses we may incur from any of these events are not always fully payable or reimbursable by the shipyards constructing the units. Furthermore, certain of our contracts include termination provisions in the event of our poor performance, our bankruptcy or other events, with little prior notice and without reimbursement to us or any early termination payment. Early termination of a contract may result in a rig being idle for an extended period of time. If our customers were to cancel any of our contracts, and we are unable to secure a replacement contract on substantially similar terms, or at all, our revenue and profitability could be materially adversely affected.

As of September 30, 2012, our contract backlog was approximately $10.9 billion. This backlog included: (1) an aggregate amount of $3,624.0 million from charter and service contracts (including management fees) that our special purpose companies (owned together with Sete Brasil S.A., or Sete Brasil) and Queiroz Galvão Óleo e Gás S.A., or QGOG, respectively, entered into in August 2012 (relating to our 15% interest in these special purpose companies, each of which owns an ultra-deepwater semi-submersible rig: Urca, Bracuhy and Mangaratiba); (2) $1,907.7 million from the Amaralina Star and Laguna Star drillships in which we have a 55% interest, but with respect to which we will receive 100% of the charter and services revenues until the repayment in full of loans we have made to Alperton (with a maximum term of 12 years) to fund its related equity contributions; and (3) $1,108.8 million from our 25.5% interest in a joint venture with SBM related to our investment in FPSO Cidade de Ilhabela (assuming we exercise the option to increase our existing 12.75% interest by an additional 12.75% by 2014).

 

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If we are unable to renew or obtain new and favorable contracts to replace contracts for rigs that expire or are terminated, our revenue and profitability would be materially and adversely affected.

Our existing drilling and our FPSO contracts are scheduled to expire between 2012 and 2034. Our ability to renew these contracts or obtain new contracts on similar terms and conditions will depend on market conditions at the time of their scheduled expiration or termination. We may be unable to renew our contracts that expire or obtain new contracts for these rigs, and the dayrates under any new or renewed contracts may be substantially lower than the dayrates in existing contracts, which could materially and adversely affect us.

The vast majority of our contracts with our customers are long-term dayrate contracts. Increases in our operating costs, which fluctuate, including based on certain events outside our control, could materially adversely affect our profitability.

In periods of rising demand for rigs, drilling contractors generally prefer to enter into well-to-well or other shorter term contracts that allow the contractor to profit from increasing dayrates, while customers with established long term drilling programs typically prefer longer term contracts in order to maintain dayrates at a consistent level. Conversely, in periods of decreasing demand for offshore drilling rigs, drilling contractors generally prefer longer term contracts to preserve dayrates and avoid idle periods, while customers generally prefer well-to-well or shorter term contracts that allow the customers to benefit from the decreasing dayrates. We expect, based on our contracted backlog, that the great majority of our revenues for the foreseeable future will come from long-term contracts, so we may be unable to fully benefit from increasing dayrates in an improving market, which could adversely affect our profitability.

In general, our operating costs increase as the business environment for drilling services improves and demand for oilfield equipment and skilled labor increases. In addition, the costs of materials, parts and equipment maintenance fluctuate depending on the type of activity and the age and condition of the equipment. While many of our contracts include escalation provisions that allow us to increase the dayrate based on the consumer price index as published by the United States Bureau of Labor Statistics, the timing and amount we earn from these higher dayrates may differ or be delayed from our actual higher operating costs. Additionally, we may incur expenses relating to preparation for drilling operations under a new contract. If our rigs are idle between assignments, the opportunity to reduce the size of our crews on these rigs may be limited as our crews may be engaged in preparing the rig for a new assignment. When a rig faces longer idle periods, reductions in operating costs also may take time as our crew may be required to prepare the idle rig for stacking and for maintenance in the stacking period. Our increased operating costs and financial expenses have resulted in our operating at a net loss in recent fiscal years, and there can be no assurance that we will operate at a net profit in any future periods. Given our high percentage of long-term dayrate contracts with limited cost escalation provisions, we may not be able to recoup increased operating costs, which may adversely affect our margins and profitability.

Rig and FPSO upgrade, refurbishment, repair and construction projects are subject to risks, including delays and cost overruns, which could have a material adverse impact on our available cash resources and results of operations.

We have a total of six operational semi-submersible rigs and two operational drillships. In addition, we have investments in partnerships that are converting three additional units into FPSOs. We have expended, and will continue to expend, significant amounts on the construction or conversion of these rigs. In addition, we make significant upgrades, refurbishments and repairs to our fleet from time to time. In 2012, we have budgeted approximately $1.5 billion for the construction, refurbishment and upgrading of our other rigs, including amounts we are responsible to pay to our partners in connection with the three FPSO units under construction. We may also decide to procure the construction of additional rigs from time to time. While we generally enter into fixed price EPC contracts for the construction or refurbishment of our vessels, these projects remain subject to risks of delays or cost overruns, including costs or delays resulting from factors such as:

 

   

failure or delay of third-party equipment vendors or service providers;

 

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

 

   

shortage of shipyard capacity globally and in Brazil;

 

   

shipyard availability or disputes with shipyards;

 

   

financial and other difficulties at shipyards and other suppliers;

 

   

work stoppages; and

 

   

impact of new governmental regulations, among others.

Significant cost overruns or delays for these or other reasons could materially adversely affect our financial condition and results of operations. The damages we suffer and the expenses we incur from any of these events are not always fully reimbursable by the shipyards constructing the units. Additionally, our actual capital expenditures for rig upgrade, refurbishment and construction projects could materially exceed our budgeted capital expenditures.

We are a holding company that depends on dividend distributions from our operating subsidiaries, and we have a substantial amount of indebtedness, which could restrict our financing and operating flexibility.

As of September 30, 2012, our total aggregate outstanding consolidated indebtedness was $3,336.2 million. Our existing level of indebtedness and the requirements and limitations imposed by our debt instruments could materially adversely affect us. In particular, our loans incurred by the special purpose companies that own our rigs to finance their construction or refurbishment are secured by the rigs and related assets, including accounts into which the amounts payable under our charter and services agreements are required to be paid. We are a holding company that depends on dividend distributions from our operating subsidiaries. The terms of most of our debt instruments restrict the ability of our project subsidiaries, to pay dividends, incur additional debt, grant additional liens, sell or dispose of assets and enter into certain acquisitions, mergers and consolidations, except with the prior consent of the respective creditors. Furthermore, some of our debt instruments include financial covenants that require us and/or our subsidiaries to maintain compliance with certain specified financial ratios. The terms of the credit agreement for our Alpha Star semi-submersible drilling rig and our Amaralina Star and Laguna Star drillships provide that if the charter or service agreements for these units are not renewed or replaced on terms reasonably satisfactory to the lenders, a cash sweep will be implemented on the eighteenth month prior to the maturity of the respective loans.

The occurrence of a payment event of default or acceleration under any of our debt instruments may trigger events of defaults or cross-defaults under our other debt instruments. We may be unable to incur additional debt in an amount necessary to finance our capital expenditure needs, which could materially and adversely affect us.

If we are unable to meet our debt service obligations or comply with our debt covenants, we could be forced to renegotiate or refinance our indebtedness, sell assets or seek to raise additional equity capital, which could restrict our financing and operating flexibility.

We have a business plan that contemplates significant growth, which requires substantial additional capital, and we may be unable to execute our growth strategy or obtain needed capital or financing on satisfactory terms, or at all.

Our industry is capital intensive, and we expect to significantly grow in the coming years, with substantial capital expenditures in the construction of rigs and investments in FPSOs. We have budgeted capital expenditures of up to $5.1 billion until 2015, $3.1 billion of which are related to existing commitments for the acquisition of rigs, investments in FPSOs and an option for the acquisition of two ultra-deepwater drillships as well as our maintenance expenditures and currently existing construction and refurbishment projects, and $2.0 billion of which is planned for additional investment opportunities in our business, which may not be realized. We intend to finance our ongoing

 

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and future capital expenditures with cash flow from our operations, the proceeds from this and future equity offerings and additional debt financings. If, for example, our current substantial amount of indebtedness impairs our ability to obtain debt financing on favorable terms or at all, or if the cash generated by our operations, when taken together with available debt financing, is insufficient to meet our capital expenditure requirements, our results of operations and financial condition would be materially adversely affected. In addition, if our capital expenditure requirements are higher than we have budgeted, our results of operations and financial condition could be materially adversely affected.

The ownership and operation of rigs and FPSO units involves numerous operating hazards, and the insurance we purchase may not cover all of our losses and may not be renewed on favorable terms, including reasonable premiums. Accidents may subject us to civil, property, environmental and other damage claims, including by Petrobras, federal, state or municipal governmental entities in Brazil, and third parties.

Although we follow industry best practices, our oil and gas service operations, particularly our rigs and FPSOs in which we hold investments, are subject to hazards inherent to drilling and FPSO activities and operation of oil and gas wells, such as: fires; explosions; pressures and irregularities in formations; blowouts and surface cratering; uncontrollable flows of underground gas, oil and formation water; natural disasters, such as adverse weather conditions, pipe or cement failures, casing collapses and, lost or damaged oilfield drilling and service tools; and environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases and oil. The occurrence of any of these events could result in the suspension of our drilling or FPSO operations, severe damage to, or destruction of our rigs, injury or death to our personnel and environmental damage and resulting containment and clean-up costs, in addition to administrative and criminal penalties. We are also subject to personal injury and other claims by the crews of our rigs as a result of both marine and drilling operations. We may also be subject to potentially unlimited civil, property, environmental and other damage claims by Petrobras, federal, state or municipal governmental entities and authorities in Brazil, and affected third parties.

We currently have insurance for our rigs covering their hulls and machinery, liability in connection with certain environmental damage and removal of wrecks or debris and third parties liabilities, in amounts that our management deems appropriate. See “Business—Insurance.” All of our dynamically positioned rigs have business interruption insurance, and we intend to seek to acquire business interruption insurance for our drillships.

However, there can be no assurance that insurance we currently have, or insurance we seek to acquire, will be available to us on favorable terms, at reasonable prices or at all, that the amounts of such insurance will be sufficient to cover the related losses, including after taking into account loss deductibles on such insurance, or that the insurers will not dispute their obligations under the policies for any applicable losses.

In addition, at the time of any renewal of the insurance on our rigs, the coverage available to us may be significantly less than our existing coverage and the premiums we are required to pay may be substantially higher than those under our existing policies.

Any of these risks could have a material adverse effect on us and our ability to conduct our operations.

We have a limited number of potential customers.

The E&P market in Brazil is dominated by Petrobras, and the number of other oil and gas E&P companies in the market is limited. Further, mergers among oil and gas E&P companies have reduced, and may from time to time further reduce the number of available customers. In addition, as a result of recently adopted rules, Petrobras will be the sole operator in the Brazilian pre-salt areas under a production sharing regime, further limiting the number of customers available for our units. A reduced number of potential customers could increase the ability of remaining potential customers to achieve favorable pricing terms, which would adversely materially affect us.

Certain of our partnerships or joint ventures may not succeed due to several factors.

Our strategy includes significant growth, including through joint ventures, partnerships and co-investments with various entities, including Sete Brasil, SBM and others. The risks related to our partnerships and joint ventures

 

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include, among others: (1) difficulty in maintaining a good relationship with our partners and joint ventures (current and future); (2) financial or operational difficulties of our partners or joint ventures, which difficulties may result in delay or cancellation of joint venture projects or additional investments; and (3) divergence of financial, commercial or strategic interests between us and our partners or joint ventures. The occurrence of these risks may adversely affect the estimated results of our partnerships or joint ventures, may reduce our expected backlog, or may result in the need for additional investments or the loss of investments we have made (or may make in the future) in these partnerships or joint ventures.

We may be subject to conflicts of interest in future transactions with related parties.

We expect to capitalize on synergies with other companies in the Queiroz Galvão Group during the design, development, construction and utilization of our rigs. We also may enter into charter and services agreements with Queiroz Galvão Exploração e Produção S.A., or QGEP, our affiliate that is involved in oil and gas E&P operations in Brazil, and QUIP S.A., or QUIP, our construction services affiliate currently involved in the construction of the FPSO P-63. For instance, in the future, we may enter into agreements for the construction of drillships with a shipyard in which an affiliate of our company owns a substantial equity stake. Although we have no obligation to enter into transactions with related parties, and if we do enter into any such transactions we will do so under terms negotiated on an arm’s length basis, conflicts of interests may arise from our relationship with other companies in the Queiroz Galvão Group and our controlling shareholders, which may adversely affect, interrupt or alter our relationship with other companies in the Queiroz Galvão Group and materially adversely affect our results of operations.

QG S.A. currently holds 51% of QGOG’s voting capital stock, which may give rise to additional conflicts of interests with our public shareholders. See “Certain Relationships and Related Party Transactions—Shareholders’ Agreement.”

Risks Relating to Our Industry

A substantial or extended decline in expenditures by oil and gas companies due to a decline or volatility in oil and gas prices may reduce long-term demand for our services.

Oil and gas prices and market expectations regarding potential changes in these prices significantly affect the level of exploration, development and production activity by oil and gas companies. Oil and gas are commodities, and therefore, their prices are subject to wide fluctuations in response to changes in supply and demand. Historically, the markets for oil and gas have been volatile. According to Bloomberg, the monthly average of West Texas Intermediate (40° API) oil prices over the three-year period ended June 30, 2012, have ranged from record high levels in April 2011 of approximately $113.93 per barrel to low levels of approximately $59.52 per barrel in July 2009, with similar volatility in gas prices. These markets will likely continue to be volatile in the future.

The prices that oil and gas producers receive for their production and the levels of their production depend on numerous factors beyond their control, including, but not limited to:

 

   

political and economic conditions, including embargoes and wars;

 

   

the global demand for oil and gas;

 

   

the cost of exploring for, developing, producing and delivering oil and gas;

 

   

the policies of the Brazilian government regarding exploration and development of their oil and gas reserves;

 

   

advances in exploration, development and production technology;

 

   

Brazilian tax and royalty policies; and

 

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the development and availability of alternative fuels.

Any prolonged reduction in oil and gas prices may reduce the levels of exploration, development and production activity. Moreover, even during periods of high commodity prices, our customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditures for E&P for a variety of reasons, including their lack of success in exploration efforts. If these or other factors were to reduce the level of exploration, production and development of oil and gas, it could cause our revenue and margins to decline, decrease dayrates and reduce utilization of our rigs and limit our future growth prospects. A significant decrease in dayrates or the utilization of our rigs could materially reduce our revenue and profitability.

A reduction in long-term demand for our services may materially adversely affect our ability to successfully negotiate the renewal terms of our current charter and service contracts or enter into new charter or service contracts upon termination of our current contracts.

Our charter and service agreements are long-term contracts, subject to renewal upon our and our counterparty’s consent. As a result, the long-term profitability of our operations and our ability to successfully negotiate the renewal terms of our drilling contracts depends upon long-term conditions in the oil and gas industry and, specifically, the level of exploration, development and production activity by oil and gas E&P companies. This is particularly relevant to us as an oil and gas contract drilling company, because we make significant investments in and incur significant amounts of indebtedness related to our operating units, and therefore, we depend on the efficient utilization of these assets. Any prolonged reduction in long-term-demand for our services or reduction in the level of exploration, development and production activity of oil and gas, may adversely affect our ability to successfully negotiate the renewal terms of our charter and service contracts over the long-term or enter into new charter or service contracts upon termination of our contracts, which could result in a significant decrease in the utilization of our rigs and materially reduce our revenue and profitability.

Global ultra-deepwater rig and FPSO demand is highly dependent on Petrobras’ development plan for offshore drilling in Brazil.

Petrobras has announced a multi-billion dollar drilling program over the next several years to develop recently discovered oil fields. As a result, we expect Brazil to be a major source of demand growth in the industry. However, Petrobras may not spend the sums outlined in its business plan within the next several years or at all. This is particularly relevant to us as an oil and gas contract drilling company, because we make significant investments in and incur significant amounts of indebtedness related to our operating units, and therefore, we depend on the efficient utilization of these assets. In addition, the extraction of oil and gas from the Brazilian oil fields may be more costly than currently estimated, and the volume and quality of oil and gas reserves may be lower than estimated. Furthermore, Petrobras may not be able to obtain the necessary financing for its E&P program due to budget pressures, higher interest rates, adverse credit or equity markets and other factors. Lower oil prices or lower-than-expected production may also prompt Petrobras to curtail its drilling program. Any substantial reduction in Petrobras’ proposed offshore drilling or FPSO program would reduce demand for offshore drilling or FPSO services worldwide, which may materially erode dayrates and/or utilization rates for our semi-submersible rigs, drillships and FPSO units in which we have investments, which could have a material adverse effect on us.

Our industry is highly competitive and cyclical, with potential intense price competition and oversupply of drilling equipment.

The contract drilling industry is highly competitive with numerous international and domestic industry participants. Drilling contracts are generally awarded on a competitive bid basis. Intense price competition is often the primary factor in the bidding process, although safety records, competency, rig availability and location are also considered in determining which qualified contractor is awarded a contract. Demand for contract drilling and related services is influenced by a number of factors, including current and expected prices of oil and gas and expenditures of oil and gas companies for E&P activities. In addition, demand for drilling services remains dependent on a variety of political and economic factors beyond our control, including the level of costs for Brazilian offshore oilfield and construction services, the discovery of new oil and gas reserves in Brazil, the cost of non-conventional hydrocarbons in Brazil and Brazilian regulatory restrictions on offshore drilling. We believe that

 

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the market for drilling contracts will continue to be highly competitive. Our competition includes international companies and Brazilian-controlled companies. Certain of our competitors have more diverse fleets and may have greater financial resources than we do, which may enable them to compete more effective on the basis of price and have more capacity to build new rigs or acquire existing rigs.

Our competition includes international companies and Brazilian-controlled companies. In addition, the contract drilling business is subject to cyclical variations. In particular, the offshore service industry has been highly cyclical, with periods of high demand, limited rig supply and high dayrates, often followed by periods of low demand, excess rig supply and low dayrates. Periods of low demand and excess rig supply intensify the competition in the industry and often result in rigs, particularly lower specification rigs, being idle for long periods of time. Prolonged periods of low utilization and reduced dayrates could result in our having to recognize impairment charges on certain of our rigs if future cash flow estimates, based upon information available to our management at any time, indicates that we may be unable to recover the carrying value of these rigs. If we are unable to compete successfully for future drilling contracts or adequately manage the cyclical nature of our business, it would have a material adverse effect on our margins and our results of operations.

Moreover, demand and contract prices customers are willing to pay for our rigs are affected by the total supply of comparable rigs available for service in Brazil. During prior periods of high utilization and dayrates, industry participants have increased the supply of rigs by ordering the construction of new rigs. Historically, this has created an oversupply of drilling rigs and has caused a decline in utilization and dayrates when these rigs enter the market, sometimes for extended periods of time until such rigs have been absorbed into the active fleet. The entry into service of newly constructed, upgraded or reactivated rigs will increase supply and could reduce, or curtail a strengthening of, dayrates in the affected markets as rigs are absorbed into the active fleet. Any additional increase in construction of new drilling rigs may negatively affect our utilization and dayrates. In addition, the construction of high specification rigs, as well as changes in our competitors’ drilling rig fleets, could require us to make material additional capital investments to keep our rig fleet competitive.

We depend on a limited number of key suppliers and vendors to provide equipment that we need to operate our business, and any failure by our key suppliers and vendors to supply necessary equipment on a timely basis or at all, could materially adversely affect us.

We depend upon a limited number of key suppliers and vendors to provide us with equipment and other services necessary for the construction and operation of our rigs and FPSOs in which we have invested. Although we contract with most of our suppliers and vendors at fixed prices and require them to pay delivery delay penalties, our suppliers may, among other things, extend delivery times, raise contract prices and limit supply due to their own shortages and business requirements. If our suppliers or vendors were to fail to provide equipment or service to us on a timely basis, we could experience disruptions in our operations, which could have a material adverse effect on our revenue and results of operations, and we may be unable to satisfy the requirements contained in our drilling contracts, which could subject us to fines or cancellation of these agreements.

Consolidation among key suppliers and vendors could limit our ability to obtain equipment and services on terms favorable to us. In the last decade, the overall number of suppliers and vendors in this sector has decreased, resulting in fewer alternatives to obtain important equipment and services. Increases in costs or lack of availability of equipment could result in our inability to enter into new EPC contracts for new rigs, or the stoppage of certain our rigs for a prolonged period of time, which could have a material adverse effect on us.

We have a limited operating history in the ultra-deepwater sector, which makes it more difficult to accurately forecast our future results and may make it difficult for investors to evaluate our business and our future prospects, both of which will increase the risk of your investment in our common shares.

Our growth strategy is principally based on our growth in the ultra-deepwater and FPSO markets. Our assets consist of three ultra-deepwater drilling rigs, the Alpha Star, Lone Star and Gold Star, which commenced operations in July 2011, April 2011 and February 2010, respectively. Because of our and the industry’s limited operating history, we lack historical financial and operational data with respect to these ultra-deepwater drilling rigs and FPSOs in which we have invested, making it more difficult for an investor to evaluate our business, forecast our future revenues and other operating results and assess the merits and risks of an investment in our common shares.

 

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This lack of information will increase the risk of your investment in our common shares. These risks and difficulties include uncertainties resulting from having had a relatively limited time period in which to implement our business strategies. If we are not able to successfully meet these challenges, our growth strategy, financial condition, results of operations, cash flows and the price of our common shares could be materially adversely affected.

Failure to employ a sufficient number of skilled workers or an increase in labor costs could materially adversely affect us.

Maintaining low turnover levels among the crew and key officers of our rigs is an important factor in maintaining the level of uptime of our rigs. We must employ skilled personnel to operate and provide technical services to, and support for, our rigs. Shortages of qualified personnel result in higher wages and difficulties in maintaining staffing levels, particularly as a result of the increase in the level of activity in the oil and gas sector in Brazil and the growth of the Brazilian economy generally, which have resulted in more rigs operating in, and under construction to operate in, our area of operations. Due to the anticipated introduction of a number of new rigs and units in the Brazilian market, we expect increased competition for qualified crew and other personnel, and our rigs may lose personnel due to competition for skilled labor from other drilling rig operators.

Turnover among the crew and officers of our rigs also may increase for reasons that are beyond our control. Shortages of qualified personnel to operate our rigs or our inability to obtain and retain qualified personnel could also materially adversely affect the quality and timeliness of the operations of our rigs. Competition for skilled personnel could materially impact our business by limiting or affecting the quality and safety of our operations or increasing our operating costs, which may have a material adverse effect on us.

Changes to, the revocation of, adverse interpretation of, or exclusion from Brazilian tax regimes and international treaties to which we and our clients are currently subject may negatively impact us.

Amounts paid to us by Petrobras and our other clients in Brazil for chartering our offshore units are currently not subject to any Brazilian withholding income tax.

Petrobras is currently involved in a dispute with the Brazilian federal tax authorities regarding whether oil and gas rigs, semi-submersible rigs, drillships and FPSOs are considered “vessels” for purposes of benefiting from a zero percent withholding income tax rate. Brazilian tax authorities have claimed that, for the zero percent withholding income tax rate to be applicable to a vessel, the vessel must be used to transport people or goods. If this interpretation were to prevail, charter payments payable to us would not benefit from the zero percent withholding income tax rate, and instead would be subject to a withholding income tax rate of 15%.

In 2009, a trial court decided that the zero percent withholding income tax rate was applicable to oil rigs, but the Brazilian federal tax authorities appealed this decision, and this appeal is pending.

Petrobras recently announced that is involved in another dispute with the Brazilian Federal Tax authorities regarding payments to companies located in favorable tax jurisdictions for chartering offshore units. In November 2012, a lower judicial court decided that any payments made to favorable tax jurisdictions (including chartering payments) are subject to a withholding income tax rate of 25%, not applying the zero percent withholding income tax rate. Petrobras informed the market that they will appeal from this decision. Although our subsidiaries that are parties to our charter agreements are not located in favorable tax jurisdictions, some of them were located in favorable tax jurisdictions within the statute of limitations period.

In any such cases, although the terms of our charter contracts require Petrobras and our other clients to gross-up any payments to us for tax increases, Petrobras and our other clients could attempt to resist the application of this provision and attempt to not gross-up their payments to us, or not gross-up these payments in full. As a principle, new tax regulations are applied post-issuance of law.

However, with respect to the interpretation of tax rules already in force, Brazilian authorities may try to assess withholding tax related to facts that occurred within the statute of limitations period. If the Brazilian federal tax authorities were to prevail, or if the withholding income tax rate were to increase or the law were to change, our profitability may be materially impaired, and we could be materially adversely affected.

 

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Furthermore, we provide services under interrelated charter and services agreements, as described under “Business—Backlog and Drilling Contracts.” We receive the charter payments outside Brazil, and these payments are not subject to Brazilian income tax, while we receive payments under the services agreements in Brazil, which payments are subject to Brazilian taxes. The Brazilian tax authorities from time to time have questioned other market participants as to whether the contractual split applied to charter and service revenues in these agreements is appropriate. If Brazilian tax authorities were to disapprove of our contractual revenue split, we may be required to pay additional taxes on amounts that may be required to be allocated to service revenues, which could have a material adverse effect on us.

Our results of operations are directly affected by the special customs regime for exportation and importation of goods related to the exploration and production of oil and gas (Regime Aduaneiro Especial de Exportação e Importação de bens destinados à exploração e à produção de petróleo e gás natural), or REPETRO, a Brazilian tax incentive program that allows the use of a special customs arrangement for our importation of goods and equipment for the term of any concession agreement if we use the goods or equipment for the research and development of petroleum and natural gas. The REPETRO system benefits equipment imported—listed by the Federal Revenue Office—under a temporary admission regime, granting full suspension of federal import taxes. This suspension may be applied until December 31, 2020. Moreover, Brazilian States are allowed to reduce the assessment basis of the value-added tax on goods and services (Imposto Sobre Operações Relativas à Circulação de Mercadorias e Sobre Prestações de Serviços de Transporte Interestadual e Intermunicipal e de Comunicação), or ICMS, triggered by the import of assets under REPETRO (temporary admission regime) for use in oil and gas production facilities, resulting in a tax burden equivalent to 7.5% (non-cumulative basis) or 3% (cumulative basis). Brazilian States are also authorized to exempt or reduce the ICMS calculation basis (burden equivalent to 1.5% under a cumulative basis) for application in oil exploration facilities. For a more detailed description of the REPETRO regime, see “Business—Brazilian Regulatory Framework—REPETRO.” Our current charter contracts protect us from changes in the REPETRO regime, but any termination or modification of this tax incentive program could, in the future, have a material adverse effect on us.

In accordance with our proposed corporate reorganization, our future effective tax rates are based on tax laws, treaties and regulations, both in Brazil and internationally (especially Brazilian, Dutch, Switzerland and Luxembourg tax treaties). Such tax laws and regulations are frequently challenged and are subject to interpretation. Due to our corporate and operational structure, if we or our clients lose a relevant tax dispute or if there is a material change in the interpretation of such treaties or regulations, or in case any tax authority disregards our fiscal residency in any jurisdiction, our revenue and/or our tax rate could increase substantially and, consequently, our financial results could be materially adversely affected.

Our failure to maintain or renew all necessary authorizations and certifications required for the operation of our rigs, and changes in current licensing regimes may have a material adverse effect on our operations.

The operation of our rigs requires several authorizations from Brazilian government agencies, including the Brazilian Institute of Environment and Renewable Resources (Instituto Brasileiro do Meio Ambiente e dos Recursos Naturais Renováveis), or IBAMA, ANTAQ and the Brazilian Port and Coast Division (Diretoria de Portos e Costas), or DPC. Obtaining and maintaining necessary authorizations and certifications is a complex, time-consuming process, and we cannot guarantee that we will be able to obtain or maintain all authorizations required for the continued operation of each of our rigs. Our failure to obtain, maintain or renew any such required authorizations or any disputes in connection with any such authorizations, could result in the suspension or termination of the operation of certain of our rigs or the imposition of material fines, penalties or other liabilities, which could have a material adverse effect on our results of operations. In addition, as a result of a decision by the ANP, Petrobras or any other charterer of our rigs may require that we maintain additional quality and safety certifications, or meet certain additional quality and safety targets, during the term of a relevant charter agreement. Our failure to obtain and maintain these certifications or to otherwise meet these targets may result in the early termination of the affected charter agreements or in our failure to be eligible to enter into additional charters which could have a material adverse effect on our revenues and results of operations.

 

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In addition, certain of our drilling contracts require that we comply with applicable international standards, including the International Marine Organization’s Code for the Construction and Equipment of Mobile Offshore Drilling Units. We and our drilling rigs are also subject to laws and regulations governing maritime and drilling operations in Brazil and the technical requirements of third parties, including classification societies and insurers. These laws, regulations and technical requirements include provisions for the protection of the environment, natural resources and human health and safety and also require the payment of taxes, the maintenance of classifications, and the maintenance of various permits and licenses. These laws, regulations and technical requirements may require us to incur significant expenditures, and breaches may result in fines and penalties, which may be material. We will be responsible for bearing any increased costs required to maintain compliance with any such laws, regulations or other requirements.

Changes in local content policies may adversely affect our business.

The local content policy in Brazil has historically required that for E&P companies in Brazil, approximately at least 70% of their investments in capital goods must be contracted with local service providers and producers. Although once voluntary, compliance with minimum local content requirements has become part of the qualifying criteria in assessing bids for exploration blocks at ANP auctions. In fact, from and after the seventh ANP bidding round for concessions of oil and gas blocks, concessions have included minimum local content requirements for a list of items both during the exploration and the production phase. Since 2007, compliance with minimum local content requirements is required to be verified by means of certificates. In effect, as of the issuance of Rulings 36/2007–39/2007, ANP applies a certification system for compliance of minimum local content requirements, applicable to concession agreements granted before and after the seventh bidding round. Recent discoveries of oil and gas in the pre-salt area have led to debates among governmental authorities, investors, the press and the Brazilian public about the need to make changes to the regulatory framework of the oil and gas sector. It is not yet possible to determine to what extent these changes will affect the current system of exploration concessions granted by ANP and consequently, the potential adverse effect on our activities. Further to domestic local content policies, our business significantly depends on the local content policies adopted by participants in the oil and gas sectors, especially Petrobras.

Complex and stringent environmental laws and regulations may increase our exposure to environmental and other liabilities, may increase our operating costs and adversely affect the operation of our rigs.

The operation of our rigs is subject to Brazilian environmental laws, regulations and standards at the federal, state and local levels. Compliance with these laws, regulations and standards may require installation of additional costly equipment, increased staffing, and higher operating expenses. Violation of these laws, regulations and standards may result in administrative and criminal penalties for us, such as fines, suspension or interruption of our operations, and prohibitions or restrictions on participation in future charter bids sponsored by government-controlled entities, among other sanctions. As some Brazilian environmental laws impose strict and unlimited civil liability for remediation of damages in connection with spills and releases of oil and hazardous substances, we could be subject to liability even if we were not negligent or at fault. These laws and regulations may expose us to liability for the conduct of, or conditions caused by, others, including charterers or third-party agents. To the extent that we are subject to environmental liabilities, the payment of any such liabilities or the costs that we may incur to remedy environmental pollution could have a material adverse effect on our operations and financial condition.

The laws, regulations and technical requirements governing maritime and drilling operations in Brazil have become increasingly complex, more stringently enforced and more expensive to comply with, and this trend is likely to continue. In addition, as a result of the 2010 major oil spill in the Gulf of Mexico, significant concerns regarding the safety of offshore oil drilling have been raised. In addition, the November 2011 oil spill in the Frade field offshore Brazil has led to the severe regulatory fines being imposed and criminal charges being filed against Chevron and Transocean and certain of their executives. Amendments to existing laws and regulations or changes in the application or the creation of new laws, regulations and technical standards may be highly restrictive and impose significantly increased costs on the operation of our business, or otherwise materially adversely impact our operating results or future prospects.

 

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Risks Relating to Brazil

The Brazilian government has exercised, and continues to exercise, significant influence over the Brazilian economy. This influence, as well as Brazilian political and economic conditions, could adversely impact our business, results of operations and financial condition.

All of our operations and customers are located in Brazil. Accordingly, our financial condition and results of operations are substantially dependent on Brazil’s economy. The Brazilian government frequently intervenes in the Brazilian economy and occasionally makes significant changes in policies and regulations. The Brazilian government’s actions to control inflation and other regulations and policies have in the past involved, among other measures, increases in interest rates, changes in tax policies, price controls, currency devaluations, capital controls, limits on imports and other actions. We have no control over, and cannot predict the measures or policies that the Brazilian government may adopt in the future. Our business, results of operations and financial condition may be adversely affected by changes in public policies at the federal, state and municipal levels, related to taxes, currency exchange control, as well as other factors, such as:

 

   

applicable regulations and increase fines for any violations of law applied by the Brazilian government, including through the ANP, as well as state and local governments;

 

   

expansion or contraction of the Brazilian economy, as measured by the variation of Brazil’s gross domestic product;

 

   

interest rates;

 

   

currency depreciation and other fluctuations in exchange rates;

 

   

inflation rates;

 

   

liquidity of domestic capital and financial markets;

 

   

fiscal policy and the applicable tax regime;

 

   

social and political instability;

 

   

energy shortages; and

 

   

other diplomatic, political, social and economic developments in or affecting Brazil.

These and other future developments in the Brazilian economy and governmental policies may materially adversely affect us.

If Brazil were to experience higher inflation, our margins and our ability to access the international financial markets may be reduced. Government measures to curb inflation may have material adverse effects on the Brazilian economy and on us.

Brazil has in the past experienced extremely high rates of inflation, which led its government to pursue monetary policies that have contributed to one of the highest real interest rates in the world. Since the introduction of the Real Plan in 1994, the annual rate of inflation in Brazil has decreased significantly, as measured by the National Broad Consumer Price Index (Índice Nacional de Preços ao Consumidor Amplo), or IPCA. Inflation measured by the IPCA index was 4.3%, 5.9% and 6.5% in the years ended December 31, 2009, 2010 and 2011, respectively. Inflation and the Brazilian government’s inflation containment measures, principally through monetary policies, have had and may have significant effects on the Brazilian economy and our business. Tight monetary policies with high interest rates may restrict Brazil’s growth and the availability of credit. Conversely, more lenient policies and lower interest rates may trigger higher inflation, with the consequent reaction of sudden and significant interest rate increases, which could have a material adverse effect on the Brazilian economic growth and us.

 

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If Brazil were to experience high inflation in the future, our operating costs may increase and our operating and net margins may decrease. Inflationary pressures may also curtail our ability to access the international financial markets and may lead to further government intervention in the economy, including the introduction of government policies that may adversely affect the overall performance of the Brazilian economy. In addition, most of our operating costs are denominated in reais and incurred in Brazil, which therefore exposes us to the effects of inflation in Brazil, which may adversely affect us.

Political, economic and social developments and the perception of risk in other countries, especially emerging market countries, may adversely affect the market value of our securities.

The market for securities issued by a company that is significantly exposed to the Brazilian market and economy, such as us, may be influenced, to varying degrees, by economic and market conditions in other countries, especially other Latin American and other emerging market countries. Although economic conditions are different in each country, the reaction of investors to developments in one country may cause the capital markets in other countries to fluctuate. Adverse economic conditions in other countries have at times resulted in significant outflows of funds from Brazil including, for example, in economic crises in Greece, Spain, Portugal, Ireland and Italy. The Brazilian economy also is affected by international economic and market conditions generally. These factors could materially adversely affect the market value of our securities and impede our ability to access the international capital markets and finance our operations in the future on terms acceptable to us or at all.

Exchange rate instability may adversely affect our financial condition and expected results of operations.

The Brazilian currency has during the past decades experienced frequent and substantial variations in relation to the U.S. dollar and other foreign currencies. Between 2000 and 2002, the real depreciated significantly against the U.S. dollar, reaching an exchange rate of R$3.53 per $1.00 at the end of 2002. Between 2003 and mid-2008, the real appreciated significantly against the U.S. dollar due to the stabilization of the macroeconomic environment and a strong increase in foreign investment in Brazil, with the exchange rate reaching R$1.56 per $1.00 in August 2008. As a result of the crisis in the global financial markets since mid-2008, the real depreciated 31.9% against the U.S. dollar over the course of 2008 and reached R$2.34 per $1.00 on December 31, 2008. The exchange rate as of December 31, 2011 and September 30, 2012 was R$1.88 and R$2.03, respectively, per $1.00. If the real appreciates significantly against the U.S. dollar, our results of operations may be adversely affected.

Risks Relating to the Offering and an Investment in Our Common Shares

The price of our common shares after the offering may be volatile.

The trading price of our common shares could fluctuate significantly as a result of various factors, including:

 

   

actual or anticipated fluctuations in our quarterly and annual results, including when compared to levels that may be projected by securities analysts;

 

   

mergers and strategic alliances in the offshore contract drilling industry in Brazil and generally;

 

   

market conditions in the offshore contract drilling industry and general economic conditions in Brazil and generally;

 

   

changes in government regulations;

 

   

changes in our dividend policy;

 

   

announcements concerning us or our competitors;

 

   

any lack of coverage of our company by securities analysts after this offering;

 

   

terrorist acts;

 

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future issuances of our common shares or other securities;

 

   

sales of substantial amounts of our common shares or the perception that such sales could occur;

 

   

investors’ perception of us and the offshore contract drilling industry in Brazil and generally;

 

   

the general state of the securities market; and

 

   

other developments affecting our business, our industry or our competitors.

Operating and financial results of companies in the offshore contract drilling industry have been unpredictable and volatile. Securities markets worldwide are experiencing significant price and volume fluctuations. This market volatility, as well as general economic, market or political conditions, could reduce the market price of our common shares despite our operating performance. Consequently, you may not be able to sell any common shares at prices that are at least equal to the purchase price established for this offering.

You may face difficulties in serving process on or enforcing judgments against us, our affiliates and our directors and officers.

We are incorporated under the laws of Luxembourg, and all of the current members of our board of directors, our executive officers and some of the experts named in this prospectus reside in Brazil or elsewhere outside the United States. The majority of our assets are located outside the United States. Upon the consummation of this offering, only one member of our Board of Directors will be a resident of the United States. As a result, it may be difficult for investors to effect service of process upon us or these persons within the United States or other jurisdictions outside Luxembourg or Brazil or to enforce against us or these other persons judgments obtained in the United States or other jurisdictions outside Luxembourg or Brazil. In addition, because substantially all of our assets and all of our directors and officers reside outside the United States, any judgment obtained in the United States against us or any of our directors or officers may not be collectible within the United States. Because (1) there is uncertainty as to whether the courts of Luxembourg would enforce judgments of U.S. courts for civil liabilities based upon the U.S. federal securities laws, and (2) judgments of U.S. courts for civil liabilities based upon the U.S. federal securities laws may only be enforced in Brazil if certain conditions are met, holders may face greater difficulties in protecting their interests in the case of actions by us or our board of directors or executive officers than would shareholders of a U.S. corporation. See “Enforceability of Civil Liabilities.”

Our controlling shareholder has the ability to direct our business and affairs and its interests could conflict with yours.

Our controlling shareholder has the power to, among other things, elect a majority of our directors and determine the outcome of any action requiring shareholder approval, including transactions with related parties, corporate reorganizations and the timing and payment of any future dividends. Our controlling shareholder may have an interest in pursuing acquisitions, dispositions, financings or similar transactions that could conflict with your interest as a holder of our common shares. For a description of our ownership structure, see “Principal Shareholders.”

We are exempt from some of the corporate governance requirements of the New York Stock Exchange.

We are a foreign private issuer, as defined by the SEC for purposes of the Securities Exchange Act of 1934, or the Exchange Act. As a result, for so long as we remain a foreign private issuer, we will be exempt from, and you will not be provided with the benefits of, some of the corporate governance requirements of the New York Stock Exchange, or the NYSE. We are permitted to follow the practice of companies incorporated in Luxembourg that are not listed on any European stock exchange in lieu of the provisions of the NYSE’s corporate governance rules, except that:

 

   

we are required to have an audit committee that satisfies the requirements of Rule 10A-3 under the Exchange Act;

 

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we are required to disclose any significant ways in which our corporate governance practices differ from those followed by U.S. domestic companies under NYSE listing standards;

 

   

our chief executive officer is obligated to promptly notify the NYSE in writing after any of our executive officers becomes aware of any non-compliance with any applicable provisions of the NYSE corporate governance rules; and

 

   

we must submit an executed written affirmation annually to the NYSE. In addition, we must submit an interim written affirmation as and when required by the interim written affirmation form specified by the NYSE.

The standards applicable to us are considerably different than the standards applied to U.S. domestic issuers with shares listed on the NYSE. We intend to rely on the following exemptions as a foreign private issuer listed on the NYSE:

 

   

a majority of our Board of Directors will not be independent;

 

   

we do not have a compensation committee or a nominating or corporate governance committee of our Board of Directors as of the date of this offering;

 

   

we will not hold at least one executive session of solely independent members of our Board of Directors each year; and

 

   

we will not adopt corporate governance guidelines.

As a result, you will not be provided with the benefits of certain corporate governance requirements of the NYSE, which may adversely affect the market price of our common shares.

There is no guarantee that an active and liquid public market will develop for you to resell our common shares.

In connection with this offering, we will apply to list our common shares on the NYSE, subject to official notice of issuance. We cannot assure you that an active and liquid public market for our common shares will develop as a result of their listing on the NYSE. If an active public market for our common shares does not develop on the NYSE following the completion of this offering, the market price and liquidity of our common shares may be materially and adversely affected. The initial public offering price for our common shares will be determined by negotiation between us and the underwriters based upon several factors, and the trading price of our common shares after this offering may decline below the initial public offering price. As a result, investors may experience a significant decrease in the market price of our common shares.

We are an “emerging growth company,” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common shares less attractive to investors.

We are an “emerging growth company,” as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. We cannot predict if investors will find our common shares less attractive because we will rely on these exemptions. If some investors find our common shares less attractive as a result, there may be a less active trading market for our common shares, and our share price may be more volatile.

 

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Future sales of our common shares could lower the share price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional common shares in subsequent offerings. We may also issue additional common shares or convertible securities. After the completion of this offering, we will have              outstanding common shares, including              shares that we are selling in this offering (assuming no exercise of the underwriters’ option to purchase additional common shares).

Following the completion of this offering, Queiroz Galvão Oil & Gas, Constellation Holdings S.à.r.l. and Constellation Coinvestment Fund S.à.r.l. will own             ,              and              common shares, or approximately     %,     % and     % respectively, of our total outstanding common shares, respectively, and certain of our officers and directors will own              common shares, or approximately     % of our outstanding common shares, all of which are restricted from immediate resale under the U.S. federal securities laws and are subject to lock-up agreements between such parties and the underwriters described in “Underwriting,” but may be sold into the market in the future.

We cannot predict the size of future issuances of our common shares or the effect, if any, that future issuances and sales of our common shares will have on their market price. Sales of substantial amounts of our common shares, or the perception that such sales could occur, may adversely affect the market prices of our common shares.

We may not be able to make distributions without subjecting you to Luxembourg withholding tax.

Any dividends paid by us will be subject to a Luxembourg withholding tax at a rate of 15% for the year ending 2012 (17.65% if the withholding tax is not deducted from the dividend paid to the shareholder), subject to the exceptions provided by Luxembourg tax law or by double tax treaties entered into by the Grand Duchy of Luxembourg and the country of tax residency of our shareholders. For more details, please refer to the summary under “Taxation—Certain Luxembourg Tax Considerations for Holders of Common Shares—Tax Regime Applicable to Distributions—Reduction of Luxembourg Withholding Tax.” The withholding tax must be withheld from the gross distribution and paid to the Luxembourg tax authorities.

U.S. tax authorities could treat us as a “passive foreign investment company,” which could have adverse U.S. federal income tax consequences to U.S. shareholders.

A non-U.S. corporation will be treated as a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes if either (1) at least 75% of its gross income for any taxable year consists of certain types of “passive income” or (2) at least 50% of the average value of the corporation’s assets for any taxable year produce or are held for the production of “passive income.” For purposes of these tests, “passive income” includes dividends, interest and gains from the sale or exchange of investment property and rents and royalties other than certain rents and royalties which are received from unrelated parties in connection with the active conduct of a trade or business, but does not include income derived from the performance of services.

U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC, and the gain, if any, they derive from the sale or other disposition of their interests in the PFIC. We believe that we will not be a PFIC for the current taxable year or for any future taxable year. Based on our operations described herein, all or a substantial portion of our income from our drilling contracts should not be treated as passive income, and thus all or a substantial portion of the assets that we will own and operate in connection with the production of that income should not constitute passive assets, for purposes of determining whether we are a PFIC. However, this involves a facts and circumstances analysis and it is possible that the U.S. Internal Revenue Service would not agree with this conclusion. Please read “Taxation—United States Federal Income Taxation—Passive Foreign Investment Company Considerations.”

 

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

We make forward-looking statements in this prospectus that are subject to risks and uncertainties. These forward-looking statements include information about possible or assumed future results of our business, financial condition, results of operations, liquidity, plans and objectives. In some cases, you can identify forward-looking statements by terminology such as “believe,” “may,” “estimate,” “continue,” “anticipate,” “intend,” “should,” “plan,” “expect,” “predict,” “potential,” or the negative corollary of these terms or other similar expressions. The statements we make regarding the following subject matters are forward-looking by their nature:

All statements related to our future financial condition contained in this prospectus, including business strategy, budgets, cost projections, and management plans and goals for future operations, are “forward-looking statements.” These statements can be identified by the use of expressions such as “may,” “will,” “could,” “expect,” “intend,” “believe,” “plan,” “anticipate,” “estimate,” or “continue,” or the negative forms thereof, or similar terms. Although we believe that the expectations reflected in these forward-looking statements are reasonable, no assurance can be provided with respect to these statements. Because these statements are subject to risks and uncertainties, actual results may differ materially and adversely from those expressed or implied by such forward-looking statements. Factors that could cause actual results to differ materially and adversely from those contemplated in such forward-looking statements include but are not limited to:

 

   

our strategy, including the expansion and growth of our operations and our ability to make future investments on attractive terms;

 

   

expected useful lives of our rigs and FPSOs in which we have invested;

 

   

future capital expenditures and refurbishment costs;

 

   

our inability to secure financing on attractive terms;

 

   

our inability to maintain operating expenses at adequate and profitable levels;

 

   

delay in, payments by, or disputes with Petrobras or other customers under our charter or services agreements;

 

   

our inability to comply with, maintain, renew or extend the charter and services agreements with Petrobras or our other customers;

 

   

our inability to charter our units upon termination of our charter and services agreements at profitable dayrates.

 

   

our inability to respond to new technological requirements in the areas in which we operate;

 

   

the occurrence of any accident involving our rigs and FPSOs and other units in the industry;

 

   

if any of our partnerships and joint ventures do not succeed;

 

   

changes in governmental regulations that affect us or our customers and the interpretations of those regulations;

 

   

increased competition in the drilling and FPSO market;

 

   

general economic, political and business conditions in Brazil and globally;

 

   

the development of alternative sources of fuel and energy; and

 

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the other factors referred to under the caption “Risk Factors” and otherwise in this prospectus.

Some of these factors are analyzed in greater detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors.” The forward-looking statements contained herein are valid only as of the date they were made, and therefore, potential investors should not unduly rely on such forward-looking statements. These warnings should be taken into account in connection with any forward-looking statement, oral or written, that we may make in the future. We assume no obligation to update publicly or to revise any such forward-looking statements after we distribute this prospectus, for the purpose of reflecting subsequent events or developments or the occurrence of unexpected events. Because of these uncertainties, you should not make any investment decision based on these estimates and forward-looking statements.

 

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USE OF PROCEEDS

We estimate that our net proceeds from this offering, after deducting the underwriting discount and estimated offering expenses, will be approximately $        million (or approximately $        million if the underwriters exercise their option to purchase additional common shares in full), assuming the shares are offered at $        per share, the mid-point of the estimated offering price range set forth on the cover page of this prospectus. A $1.00 increase (decrease) in the assumed initial public offering price of $        per share would increase (decrease) the net proceeds to us from this offering by approximately $        million, assuming the number of common shares offered by us as set forth on the cover page of this prospectus remains the same and after deducting the underwriting discounts and commissions.

We intend to use the net proceeds from this offering (1) to make down payments for two ultra-deepwater drillships, one of which is subject to the exercise of an option pursuant to a letter of intent we have executed with Samsung (as described in “Business—Backlog and Drilling Contracts—Samsung Letter of Intent”), (2) to make capital expenditures and related expenses for certain existing projects and (3) to make capital expenditures and investments related to expected new projects, including new opportunities involving the purchase of assets, and/or equity interests in, drilling and/or production service companies, and related expenses in connection therewith and for general corporate purposes, including the payment of an IPO completion bonus to certain of our employees (as described in “Management—Compensation—IPO Completion Bonus”). Specifically, we expect to allocate the net proceeds as follows:

 

Allocation

   Percentage     Estimated net proceeds
(in millions of $) (1)

Down payments for two ultra-deepwater drillships

           

Capital expenditures for certain existing projects

           

Capital expenditures for new projects and general corporate purposes

           
  

 

 

   

 

Total

     100.0  
  

 

 

   

 

 

(1) Assuming the underwriters do not exercise their option to purchase additional common shares.

 

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DIVIDEND POLICY

We have not paid a dividend on our common shares, in cash or otherwise, and we do not intend to do so in the near future. Any future determination relating to our dividend policy will be made by our Board of Directors and will depend on a number of factors, including our earnings, capital requirements, contractual restrictions, financial condition and future prospects, together with any other factors that our Board of Directors may deem relevant.

 

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CAPITALIZATION

The following table sets forth our total capitalization as of September 30, 2012, as follows:

 

   

on an actual basis;

 

   

on an as adjusted basis to give effect to (1) the issuance of our 6.250% senior notes due 2019 in an aggregate principal amount of $700.0 million in November 2012, the net proceeds of which were $683.2 million and (2) the application of $502.0 million of the net proceeds to repay short-term debt in December 2012; and

 

   

on an as further adjusted basis to give effect to the issuance and sale of $        of our common shares pursuant to this prospectus at an assumed price of $        , after deduction of commissions and expenses we must pay in connection with this offering.

You should read this information in conjunction with our financial statements and the related notes appearing elsewhere in this prospectus, the “Use of Proceeds” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections and other financial information contained in this prospectus.

 

     As of September 30, 2012
     Actual     As Adjusted     As Further
Adjusted
     (in millions of $)

Short-term debt (1)

     1,070.7        574.4     

Long-term debt

     2,265.5        2,948.8     
  

 

 

   

 

 

   

 

Total debt

     3,336.2        3,523.2     
  

 

 

   

 

 

   

 

Common shares, $1.00 par value; 55,632,446 shares issued and fully paid on an actual basis

     55.6        55.6     

Share premium

     470.5        470.5     

Other reserves

     (5.0     (5.0  

Retained earnings

     740.8        740.8     

Equity attributable to the owners of our company

     1,261.9        1,261.9     
  

 

 

   

 

 

   

 

Non-controlling interest

     (24.3     (24.3  
  

 

 

   

 

 

   

 

Total shareholders’ equity

     1,237.6        1,237.6     
  

 

 

   

 

 

   

 

Total capitalization (2)

     4,573.8        4,760.8     
  

 

 

   

 

 

   

 

 

(1) We used a portion of the net proceeds of our 6.250% senior notes due 2019 to repay short-term debt of $502.0 million in December 2012, which had a balance of $496.3 million as of September 30, 2012. We intend to use an additional portion of the net proceeds of these 6.250% senior notes due 2019 to repay our short-term debt with Banco do Brasil S.A. in full ($123.2 million as of September 30,2012), upon its final maturity on August 30, 2013.
(2) Total capitalization is short-term debt plus long-term debt plus total shareholders’ equity.

 

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DILUTION

If you invest in our common shares in this offering, your ownership interest will be immediately diluted to the extent of the difference between the initial public offering price per share and the net tangible book value per common share after this offering. Our net tangible book value as of September 30, 2012, was $1,237.6 million, corresponding to a net tangible book value of $         per common share (as adjusted to reflect a stock split of         -to-         approved by our Board of Directors on                     , 2012). Net tangible book value per share represents our total tangible assets reduced by the amount of our total liabilities, divided by the total number of our common shares outstanding after giving effect to this offering.

After giving effect to the sale of our common shares at an assumed initial public offering price of $         per share (the midpoint of the initial public offering price range set forth on the cover page of this prospectus) and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us, our as adjusted net tangible book value as of September 30, 2012, would have been approximately $         per common share. This amount represents an immediate increase in net tangible book value of $         per common share to our existing shareholders and an immediate dilution in net tangible book value of approximately $         per common share to new investors purchasing common shares in this offering. We determine dilution by subtracting the as adjusted net tangible book value per share after this offering from the amount of cash that a new investor paid for a common share.

The following table illustrates this dilution:

 

Assumed initial public offering price per share

   $         $     

Net tangible book value per share as of September 30, 2012

   $                    $                

Increase per share attributable to this offering

   $         $     

Pro forma net tangible book value per share after this offering

   $         $     

Dilution per share to new investors

   $         $     

A $1.00 increase (decrease) in the assumed initial public offering price of $         per share (the midpoint of the range set forth on the cover page of this prospectus), would increase (decrease) our consolidated net tangible book value after this offering by $         and the dilution per share to new investors by $        , in each case assuming the number of shares offered, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

If the underwriters exercise their option to purchase additional common shares in full in this offering, the as adjusted net tangible book value after this offering would be $         per share, the increase in net tangible book value per share to existing shareholders would be $        , and the dilution per share to new investors would be $         per share, in each case assuming an initial public offering price of $         per share (the midpoint of the initial public offering price range set forth on the cover page of this prospectus).

The following table summarizes, as of September 30, 2012, the differences between the number of shares purchased from us, the total consideration paid to us in cash and the average price per share that existing shareholders and new investors paid. The calculation below is based on an assumed initial public offering price of $        per share (the midpoint of the initial public offering price range set forth on the cover page of this prospectus) before deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

 

     Shares Purchased     Total Consideration     Average  Price
Per Share
 
      Number    Percent     Amount      Percent    

Existing shareholders

               $                             $                

New investors

                          
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

Total

        100        100  
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

 

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If the underwriters exercise their option to purchase additional common shares in full:

 

   

the percentage of common shares held by existing shareholders will decrease to approximately     % of the total number of common shares outstanding after this offering; and

 

   

the number of common shares held by new investors will increase to         , or approximately     % of the total number of common shares outstanding after this offering.

 

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SELECTED FINANCIAL AND OTHER DATA

The following tables set forth our selected financial and other data. You should read the following selected financial and other data in conjunction with “Presentation of Financial and Other Information,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included elsewhere in this prospectus. Historical results are not indicative of the results to be expected in the future. Our financial statements have been prepared in accordance with IFRS as issued by the IASB. The summary statement of operations for the nine-month periods ended September 30, 2012 and 2011 and for the three years ended December 31, 2011 and the summary statement of financial position data as of September 30, 2012 and December 31, 2011 and 2010, are derived from:

 

   

our unaudited condensed consolidated interim financial information as of September 30, 2012 and for the three and nine-month periods ended September 30, 2012 and 2011; and

 

   

our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011.

The audited combined financial statements as of December 31, 2011 and 2010, and for each of the three years ended December 31, 2011 have been restated as described in the “Presentation of Financial and Other Information” section.

Our results for the nine-month period ended September 30, 2012 are not necessarily indicative of the results to be expected for the year ending December 31, 2012.

 

     For the nine-month period
ended September 30,

(unaudited)
    For the year ended December 31,  
         2012             2011             2011             2010             2009      
     (in millions of $, except per share data)  

Statement of Operations Data:

          

Net operating revenue

     575.9        415.3        586.3        346.8        156.6   

Costs of services

     (342.5     (314.5     (466.1     (264.5     (141.2
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross profit

     233.5        100.9        120.2        82.3        15.4   

General and administrative expenses

     (31.5     (22.1     (29.8     (24.7     (20.0

Other operating income (expenses), net

     1.8        (10.5     (11.3     (34.3     (15.9
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating profit (loss)

     203.8        68.2        79.1        23.3        (20.5

Financial costs, net

     (94.2     (92.7     (118.5     (76.3     (32.0

Share of results of joint ventures

     2.4        0.5        1.0        6.2        6.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before taxes

     112.0        (23.9     (38.4     (46.8     (45.6

Taxes

     (0.7     (0.7     (5.1     1.5        0.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) for the period

     111.3        (24.7     (43.5     (45.3     (44.7
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net earnings (loss) per common share (1):

          

Basic

     2.00        (0.44     (0.71     (0.81     (0.80

Diluted

     2.00        (0.44     (0.71     (0.81     (0.80

Weighted average common shares outstanding (thousands of common shares):

          

Basic

     55,632        55,632        55,632        55,632        55,632   

Diluted

     55,632        55,632        55,632        55,632        55,632   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) Net income per share as attributed to the company excludes income/losses attributed to non-controlling interests.

 

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The following table sets forth a reconciliation of our EBITDA to net income (loss) for each of the periods and years presented:

 

     For the nine–month period
ended September 30,

(unaudited)
    For the year ended December 31,  
         2012             2011             2011             2010             2009      
     (in millions of $)  

Other Financial Information:

          

Net income (loss) for the period/year

     111.3        (24.7     (43.5     (45.3     (44.7

(+) Financial costs, net

     94.2        92.7        118.5        76.3        32.0   

(+) Taxes

     0.7        0.7        5.1        (1.5     (0.9

(+) Depreciation

     119.4        92.5        131.3        90.6        49.5   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA (1)(2)

     325.6        161.2        211.4        120.1        35.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA margin (%) (3)

     56.5     38.8     36.1     34.6     22.9

 

(1) EBITDA was adversely impacted by provisions related to penalties due to late delivery of rigs of $10.7 million for the nine-month period ended September 30, 2011 and $10.8 million, $35.0 million and $17.3 million for the years ended December 2011, 2010 and 2009, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Year Ended December 31, 2011 Compared with Year Ended December 31, 2010—Other Operating Expenses, Net” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Year Ended December 31, 2010 Compared with Year Ended December 31, 2009—Other Operating Expenses, Net.”
(2) EBITDA is a non-GAAP measure prepared by us. EBITDA consists of: net income, plus financial costs, net, taxes and depreciation. EBITDA is not a measure defined under IFRS, should not be considered in isolation, does not represent cash flow for the periods indicated and should not be regarded as an alternative to cash flow or net income, or as an indicator of operational performance or liquidity. EBITDA does not have a standardized meaning, and different companies may use different EBITDA definitions. Therefore our definition of EBITDA may not be comparable to the definitions used by other companies. We use EBITDA to analyze our operational and financial performance, as well as a basis for administrative decisions. The use of EBITDA as an indicator of our profitability has limitations because it does not account for certain costs in connection with our business, such as financial costs, net, taxes, depreciation, capital expenses and other related expenses.
(3) EBITDA margin is a non-GAAP measure prepared by us. EBITDA margin is calculated by dividing EBITDA by net operating revenue for the applicable period.

 

     As of September  30,
(unaudited)
     As of December 31,  
     2012      2011      2010      2009  
     (in millions of $)  

Statement of Financial Position:

           

Cash and cash equivalents

     276.7         188.9         84.3         63.1   

Short-term investments

     116.1         138.7         8.5         36.1   

Restricted cash

     17.9         26.3         29.6         —     

Total assets

     5,132.8         4,734.1         3,678.5         2,912.5   

Total loans and financings

     3,336.2         2,440.5         2,006.3         1,716.6   

Total liabilities

     3,895.2         3,611.7         2,451.5         2,049.6   

Shareholders’ equity

     1,237.6         1,122.4         1,227.0         862.9   

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated interim financial information as of September 30, 2012 and for the nine-month periods ended September 30, 2012 and 2011, our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011, included in this prospectus, as well as with the information presented under “Presentation of Financial and Other Information” and “Selected Financial and Other Data.”

The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in these estimates and forward-looking statements as a result of various factors, including, without limitation, those set forth in “Special Note Regarding Forward-Looking Statements” and “Risk Factors.”

Overview

We are a market leading Brazilian-controlled provider of offshore oil and gas contract drilling and FPSO services in Brazil. We are also one of the ten largest drilling companies globally, as measured by ultra-deepwater and deepwater drilling rigs in operation. We believe that our size and over 30 years of continuous operating experience in this industry provides us a competitive advantage in the Brazilian oil and gas market. In particular, we believe we are well positioned to benefit from the expected increase in ultra-deepwater drilling activity in Brazil, a market segment driven primarily by the recent discoveries of vast potential oil and gas reserves in the pre-salt layer offshore Brazil. We own and hold ownership interests in a fleet of state-of-the-art offshore and onshore drilling rigs and FPSOs, including nine ultra-deepwater rigs in operation or under construction. In 2011, we recorded net operating revenues of $586.3 million, a 2009-2011 annual net operating revenue CAGR of 93.5% and an EBITDA margin of 36.1%. For the nine-month period ended September 30, 2012, we recorded net operating revenues of $575.9 million and an EBITDA margin of 56.5%. We plan to continue our growth strategy through investments in additional premium ultra-deepwater drilling units and FPSOs. We are part of the Queiroz Galvão Group, which through QG S.A., the group’s Brazilian holding company, is one of the largest Brazilian conglomerates with $3.4 billion in consolidated gross revenues in 2011 and with a proven track record in heavy construction, energy, oil and gas, infrastructure, real estate, agriculture and steel. We have successfully capitalized on our market-leading position and industry expertise to accumulate a contract backlog of $10.9 billion as of September 30, 2012, a 136.6% increase from our contract backlog as of December 31, 2008.

Our results of operations for the nine-month periods ended September 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009 were influenced, and our results of operations will continue to be influenced, by a variety of factors, including:

 

   

the expansion or contraction of the global fleet of offshore drilling rigs and FPSO units, which affects the supply of drilling rigs and FPSO units available for contract work and the prevailing dayrates that we are able to negotiate in our contracts;

 

   

the levels of exploration and development spending of Petrobras and other E&P players worldwide;

 

   

additions to our fleet of drilling rigs, increasing our net operating revenue, operating expenses and financial expenses;

 

   

upgrades to our fleet of drilling rigs;

 

   

our ability to enter into long-term charter agreements for our drilling rigs, generating a backlog of committed net operating revenue for our company;

 

   

the uptime, utilization and dayrates of our drilling rigs, which are the primary determinants of our net operating revenue; and

 

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the results of operations of those companies in which we have equity investments, a pro rata portion of which is included in our results of operations under the equity method.

Our financial condition and liquidity are influenced by a variety of factors, including:

 

   

our ability to generate cash flows from our operations;

 

   

our ability to borrow funds from financial institutions and to sell our debt securities in the international capital markets; and

 

   

our capital expenditure requirements, primarily consisting of construction of new offshore drilling rigs, maintenance of our existing drilling rigs, equity contributions to joint ventures and investments in our operations.

Financial Presentation and Accounting Policies

Presentation of Financial Statements

We are a holding company organized under the laws of Luxembourg. We completed our corporate reorganization in August 2012. As part of our corporate reorganization, each shareholder of Constellation contributed its shares in Constellation to us in exchange for our issuance of our common shares to them in the same proportion that each such shareholder held in Constellation. Following this contribution, these shareholders transferred their common shares in us to our current shareholders, which in turn are controlled by the former shareholders of Constellation. See “Principal Shareholders” for further information. The contribution of the outstanding capital stock of Constellation to us was accounted for at its historical cost as this entity is under common management and control with us. As a result, we own all of the outstanding capital stock of Constellation.

For the purpose of this prospectus, we have included the following financial statements (included elsewhere in this prospectus):

 

   

our unaudited condensed consolidated interim financial information as of September 30, 2012 and for the three and nine-month periods ended September 30, 2012 and 2011; and

 

   

our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011.

Our financial statements have been prepared in accordance with IFRS as issued by the IASB. The functional currency of the issuer and most of its subsidiaries is the U.S. dollar. Our combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011 have been audited by our independent auditors, as set forth in their report included elsewhere in this prospectus. Our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011 have been restated to correct an error in our accounting policy related to the recognition of mobilization revenues and costs. As a result, we defer mobilization revenues and costs over the period that we charter and we provide operation services, which is consistent with the general pace of activity, the level of services we provide and dayrates we earn over the life of the related contract. For a discussion of this restatement and its related effects, see note 31 to our audited combined financial statements included elsewhere in this prospectus. Management’s Discussion and Analysis of Financial Condition and Results of Operations has been revised for the effects of the restatement.

Our unaudited condensed consolidated interim financial information as of September 30, 2012 and for the nine-month periods ended September 30, 2012 and 2011, and our audited combined financial statements as of December 31, 2011 and 2010 and for each of the three years ended December 31, 2011 are derived from the combination of (1) the financial statements of Constellation for the corresponding periods, utilizing historical results of operations, assets and liabilities and (2) the historical financial information of QGOG Constellation as of and for the nine-month period ended September 30, 2012, and as of December 31, 2011 and for the period from August 30, 2011 (the date of our incorporation) to December 31, 2011. These combined financial statements have been prepared considering that we and Constellation were under common management and control.

 

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New and Revised Financial Accounting Standards

We qualify as an “emerging growth company” pursuant to the provisions of the JOBS Act, enacted on April 5, 2012. Section 102 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Our decision to opt out of the extended transition period is irrevocable.

Critical Accounting Policies and Estimates

The preparation of our financial statements and related disclosures in accordance with IFRS requires our management to make estimates, judgments and assumptions that affect the amounts reported in our financial statements and accompanying notes.

Our management must judge and develop estimates for the carrying values of assets and liabilities which are not easily obtainable from other sources. The estimates and associated assumptions are based on historical experience and other factors considered relevant. Actual results could differ from those estimates.

We continually review these estimates and underlying assumptions. We recognize the effects of revisions to accounting estimates are recognized in the period that estimates are revised if the revision affects only that period, or also in later periods if the revision affects both current and future periods.

Our management has concluded that the most significant judgments and estimates considered during the preparation of our financial statements are the following:

Financial Instruments

Our main financial instruments include cash and cash equivalents, short-term investments, restricted cash, trade and other receivables, receivables from related parties, trade and other payables, payables to related parties, loans and financings and derivative financial instruments.

Our financial assets and liabilities are initially recognized at their fair value plus the costs directly attributable to their purchase or issue. Subsequent to initial recognition, our financial non-derivative assets and liabilities are measured as of each balance sheet date according to their classification, which is defined upon initial recognition based on the purposes for which they were acquired or issued, as described below:

 

   

Financial assets measured at fair value through profit or loss: these include financial assets acquired for sale (acquired primarily to be sold in the short term or settled against to loan or financing), or designated upon initial recognition at fair value through profit and loss. Interest, monetary and exchange variation and variations arising from fair value measurement, are recognized in profit or loss as financial revenues or expenses, when incurred. For the years presented, we have cash equivalents, short-term investments and restricted cash in this category; and

 

   

Loans and receivables: these include non-derivative financial assets with fixed or determinable payments that are not quoted on an active market which, after initial recognition are measured based on their amortized cost under the effective interest rate method. The interest, monetary and exchange variation, less losses in recoverable value, when applicable, are recognized in profit or loss as financial revenues or expenses, when incurred. For the years presented, we have bank deposits, trade receivables, receivables from related parties and other assets in this category.

 

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Our non-derivative financial liabilities, which are not normally traded prior to maturity, are not measured at fair value. After initial recognition they are measured on the amortized cost based on the effective interest rate method. The interest, monetary and exchange variation, when applicable, are recognized in profit or loss when incurred. We have loans and financings, trade accounts payable, payables to related parties and other liabilities, which are classified in this category.

We have no forward contracts, option, swaptions (swaps with non-exercise options), flexible options, derivatives embedded in other products or exotic derivatives. We do not conduct derivative transactions for speculative purposes, thus reaffirming our commitment to our policy of conservative management of cash.

Our management believes that the carrying amounts of our remaining financial instruments are not significantly different from their fair value as it considers that interest rates on these instruments are not significantly different from market rates.

Derivative financial instruments

We enter into derivative financial instruments, including interest rate swaps, to manage our exposure to interest rate risk. Our derivatives are measured at fair value at inception and at the end of each reporting period. The resulting gain or loss is recognized in profit or loss immediately unless the derivative is designated and effective as a hedging instrument, in which event the timing of the recognition in profit or loss depends on the nature of the hedge relationship.

A derivative with a positive fair value is recognized as a financial asset; a derivative with a negative fair value is recognized as a financial liability. A derivative is presented as a non-current asset or a non-current liability if the remaining maturity of the instrument is more than 12 months and it is not expected to be realized or settled within 12 months.

Hedge accounting

We designate certain derivative instruments used to protect against interest risks as cash flow hedges.

At the inception of the hedge relationship, we document the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking the hedge transactions. Furthermore, at the inception of the hedge and on an ongoing basis, we document whether the hedging instrument is effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk.

The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized in other comprehensive loss. The gain or loss relating to the ineffective portion is recognized immediately in profit or loss, and is included in the other financial gains and losses line item.

Amounts previously recognized in other comprehensive loss and accumulated in equity are reclassified to profit or loss in the periods when the hedged item is recognized in profit or loss, in the same line of the consolidated statement of operations as the recognized hedged item. However, when the hedged forecast transaction results in the recognition of a non-financial asset or a non-financial liability, the gains and losses previously recognized in other comprehensive loss and accumulated in equity are transferred from equity and included in the initial measurement of the cost of the non-financial asset or non-financial liability.

Hedge accounting is discontinued when we revoke the hedging relationship, when the hedging instrument expires or is sold, terminated, or exercised, or when it no longer qualifies for hedge accounting. Any gain or loss recognized in other comprehensive loss and accumulated in equity at that time remains in equity and is recognized when the forecast transaction is ultimately recognized in profit or loss. When a forecast transaction is no longer expected to occur, the gain or loss accumulated in equity is recognized immediately in profit or loss.

Provisions for Claims and Other Obligations

Claims against us, including known but unascertained claims, are recognized as a liability and/or are disclosed in notes to our financial statements, unless the likelihood of loss is considered as remote by our internal and external legal counsel.

 

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The accounting for claims and other obligations as a liability on our financial position is made when the loss amount can be reliably estimated. Due to their nature, claims and other similar obligations will be settled when one or more future events occur. Normally, the occurrence or non-occurrence of these events does not depend on our performance. This prevents accurate estimates as to the precise date on which these events will occur. The assessment of these liabilities is subject to varying degrees of legal uncertainty and interpretation and requires significant estimates and judgments by our management on the result of future events.

Useful Lives of Property, Plant and Equipment

All property, plant and equipment is carried at cost less accumulated depreciation. Property, plant and equipment consist primarily of offshore and onshore drilling rigs and related equipment. Equipment under construction is built by a third-party shipyard and the related cost is recognized at cost based on actual costs incurred in the construction of the equipment.

The carrying value of property, plant and equipment is based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our rigs. These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations. We compute depreciation using the straight-line method. At the end of each year, we review the estimated useful lives of our drilling units.

Impairment of Property, Plant and Equipment

Assets that are subject to depreciation are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Determining whether property, plant and equipment is impaired requires an estimation of the value in use of the related asset or cash-generating unit. The value used requires us to estimate future cash flows expected to arise from the related asset or cash-generating unit and the related discount rate in order to calculate the present value. We have not recognized any impairment of losses on long-lived assets.

Investments in Joint Ventures

For investments in joint ventures, we apply the equity method of accounting. Under the equity method of accounting, an investment is initially recognized at cost and adjusted thereafter to recognize our share of the profit or loss and other income of these joint ventures. When our share of losses of a joint venture exceeds our interest in such joint venture, we discontinue recognizing our share of any further losses. Additional losses are recognized only to the extent that we have incurred legal or contractual obligations or made payments on behalf of the joint ventures.

When we enter into transactions with a joint venture, we eliminate the profit and loss resulting from such transaction to the extent of our participation in the joint venture.

Outcome of Contract Negotiations

During the normal course of business, our subsidiaries enter into contracts with third parties causing such subsidiary to assume obligations under the contract. In the event of any contractual dispute, our management is required to exercise judgment in considering uncertainty in the outcome of negotiations, which may have a material impact on the assets and liabilities of our company.

 

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For additional information regarding our significant accounting policies, see notes 3 and 4 to our audited combined financial statements. For information regarding recent accounting standards, see note 2 to our audited combined financial statements.

Principal Factors Affecting Our Results of Operations

Additions and Upgrades to Our Fleet of Drilling Rigs

Offshore Drilling Rigs

Our business strategy focuses on the expansion of our ultra-deepwater drilling capacity. We have expanded our offshore drilling capabilities in recent years through the construction of new rigs, and we plan to continue pursuing opportunities to expand and upgrade our fleet to achieve greater technological capability, which should increase our operational efficiencies.

Since December 31, 2008, we have commenced operations of the following drilling rigs (dayrates are shown as of September 30, 2012 considering a real/$ exchange rate of R$2.0306 to $1.00):

 

   

Alpha Star in July 2011, currently under contract at a dayrate of $431,513;

 

   

Lone Star in April 2011, currently under contract at a dayrate of $349,211;

 

   

Gold Star in February 2010, currently under contract at a dayrate of $354,788;

 

   

Olinda Star in August 2009, currently under contract at a dayrate of $292,297;

 

   

Amaralina Star in September 2012, currently under contract at a dayrate of $422,572; and

 

   

Laguna Star in November 2012, currently under contract at a dayrate of $422,572.

In addition, we completed upgrades of (1) Atlantic Star in February 2011, currently under contract at a dayrate of $292,368 as of September 30, 2012, and (2) Alaskan Star in December 2010, currently under contract at a dayrate of $304,063 as of September 30, 2012.

The commencement of operations of these units has also significantly increased our net operating revenue, operating expenses and financial expenses (as financial charges relating to the project financing of these units are no longer capitalized after the commencement of their operation).

Penalties may be applied by our customers on a one-time basis for each contract when we deliver and commence operation of a drilling rig after its contracted delivery date. We expense penalties based on our best estimate of the date of delivery of the unit and considering the likelihood of the customer applying contractual penalties.

Gold Star and Alpha Star were delivered five months and nine months ahead of schedule, respectively. Lone Star and Olinda Star were delivered with delays, for which penalties were due. To reduce the penalties for Lone Star, we agreed with Petrobras to deliver the Gold Star rig in substitution of the Lone Star rig. However, we also incurred penalties under the Gold Star drilling contract given the delays in delivery of the Lone Star rig (which was delivered in place of the Gold Star Rig).

Amaralina Star was delivered after its contracted delivery date, and Laguna Star will be delivered after its contracted delivery date. We were aware of these delays prior to entering into these contracts, and the seller adjusted the purchase price for these assets as a result. During the nine-month period ended September 30, 2011, we recorded penalties related to the delays in delivery of these drillships. Amaralina Star commenced operations in September 2012 and Laguna Star commenced operations in November 2012.

 

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Onshore Drilling Rigs

We are also focused on the expansion of our onshore drilling capacity through agreements for construction of new units. In April 2011, we commenced operations of our QG-V, QG-VIII and QG-IX rigs with average contracted dayrates of approximately $40,651 based on the real/$ exchange rate as of September 30, 2012 of R$2.0306 to $1.00.

Our Backlog

We maintain a backlog of $10.9 billion for contract drilling and FPSO services. Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding any potential rig performance bonuses, which we have assumed will be paid to the maximum extent provided for in the respective contracts. Our calculation also assumes 100% uptime of our drilling rigs for the contract period; however, the amount of actual revenue earned and the actual periods during which revenues are earned may be different from the amounts and periods shown in the tables below due to various factors, including, but not limited to, stoppages for maintenance or upgrades, unplanned downtime, the learning curve related to commencement of operations of additional drilling units, weather conditions and other factors that may result in applicable dayrates lower than the full contractual operating dayrate. Contract drilling backlog includes revenues for mobilization and demobilization on a cash basis and assumes no contract extensions. However, our offshore rigs benefit from contracts that may be renewed for a period equivalent to the original contract term (subject to mutual consent of the parties), with the exception of our Alaskan Star and Atlantic Star rigs. Nevertheless, all of our contracts are subject to renewal through negotiation among the parties. In addition, in August 2012, we entered into the charter and corresponding service contracts of Urca, Bracuhy and Mangaratiba rigs, which have a 15-year term, renewable for an additional five-year period.

Our FPSO backlog is calculated for each FPSO by multiplying our percentage interest in the FPSO by the contracted operating dayrate by the firm contract period, in each case with respect to such FPSO. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated.

The following table sets forth as of September 30, 2012 the amount of our contract drilling and FPSO services backlog related to contracted existing and new projects for the periods indicated.

 

     2012      2013      2014      2015      2016      2017–2034      Total     %  
     (in millions of $) (1)  

Ultra-deepwater (2)

     215.7         722.9         722.9         609.1         639.7         4,385.2         7,295.7        67.0

Deepwater

     26.9         106.7         62.6         —           —           —           196.1        1.8

Midwater

     54.9         217.7         217.7         217.7         203.4         165.5         1,076.8        9.9

FPSOs (3)

     5.2         68.4         127.1         120.3         112.3         1,668.2         2,101.5        19.3

Onshore

     30.3         108.6         66.2         17.2         —           —           222.2        2.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

     333.0         1,224.3         1,196.5         964.2         955.4         6,218.9         10,892.3 (4)      100.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) Amounts denominated in reais have been converted to U.S. dollars at the selling rate as reported by the Central Bank as of September 30, 2012 for reais into U.S. dollars of R$2.0306 to $1.00.
(2) This includes (i) an aggregate amount of $3,624.0 million from charter and service contracts (including management fees) that our special purpose companies (owned together with Sete Brasil) and Queiroz Galvão Óleo e Gás S.A., or QGOG, respectively, entered into in August 2012 (relating to our 15% interest in these special purpose companies, each of which owns an ultra-deepwater semi-submersible rig: Urca, Bracuhy and Mangaratiba) and (ii) $1,907.7 million from the Amaralina Star and Laguna Star drillships in which we have a 55% interest, but with respect to which we will receive 100% of the charter and services revenues until the repayment in full of loans we have made to Alperton (with a maximum term of 12 years) to fund its related equity contributions.
(3) This represents only our portion of contracts in proportion to our ownership interest in FPSOs, which includes $1,108.8 million from our 25.5% interest in a joint venture with SBM related to our investment in FPSO Cidade de Ilhabela (assuming we exercise the option to increase our existing interest by an additional 12.75% by 2014).
(4) Our total backlog includes any potential rig performance bonuses that we may earn under our charter and services agreements in an aggregate amount of $959.4 million.

 

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Revenue per Asset, Utilization, Uptime and Dayrates of Our Drilling Rigs

The most significant variables affecting the net operating revenue from our drilling rigs in operation are utilization days, dayrate, uptime and performance bonus payments. Payments under our charter and service agreements are calculated by multiplying the applicable dayrate for each drilling rig by the uptime for the period for which such payment is being calculated. In addition, we are entitled to receive performance bonus payments.

A waiting and moving rate equal to 90% of the dayrate for any drilling rig (other than our Alaskan Star, Atlantic Star, Urca, Bracuhy and Mangaratiba drilling rigs, which earn a waiting and moving rate equal to 95% of the dayrate for such rigs) will be applied in situations of total stoppage of operations of such rig attributable to adverse weather or when we are awaiting orders or other action with respect to such rig from Petrobras or the applicable charterer of such rig. Our drilling rigs are subject to reduced dayrates in the event we are unable to operate due to force majeure events as defined in the applicable charter and service agreements. See “Business—Backlog and Drilling Contracts.”

As stated above, our offshore drilling contracts (other than our drilling contracts for Gold Star) provide for additional remuneration through a bonus structure (which varies by contract) that rewards us for the efficient operation of our drilling rigs, which is measured by the availability of the respective rig. Bonuses are calculated as a percentage of dayrates and are assessed and paid monthly in arrears, are determined on an accrual basis, and are linked to uptime of our rigs. We are eligible for (i) an up to 10% performance bonus with respect to each of our Alpha Star, Amaralina Star, Laguna Star and Olinda Star units, (ii) an up to 15% performance bonus with respect to each of our Urca, Bracuhy, Mangaratiba, Lone Star, Alaskan Star and Atlantic Star units and (iii) no performance bonus with respect to our Gold Star rig. In the event that a drilling rig operates with less than 90% availability, we are not entitled to receive a performance bonus.

The following tables set forth the revenue per asset type, utilization days, uptime and actual average dayrates and average daily revenue for our drilling fleet for the periods presented:

 

     For the nine-month
period ended
September 30,
     %
 Change 
     For the year ended December 31,      % Change  
         2012              2011          2012/
2011
         2011              2010              2009          2011/
2010
     2010/
2009
 
     (in millions of $)             (in millions of $)                

Net revenue per asset type:

              

Ultra-deepwater

     275.3         166.1         65.7         240.8         100.2         —           140.3         —     

Deepwater

     71.0         68.4         3.8         89.3         85.9         22.5         4.0         281.8   

Midwater

     140.7         104.9         34.1         150.8         91.8         70.2         64.3         30.8   

Onshore rigs

     87.0         75.9         14.6         105.4         67.6         60.2         55.9         12.3   

Other

     1.9         —           —           —           1.3         3.7         —           (64.9
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     575.9         415.3         38.7         586.3         346.8         156.6         69.1         121.5   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

     For the nine-month
period ended
September 30,
     %
 Change 
     For the year ended December 31,      % Change  
         2012              2011          2012/
2011
         2011              2010              2009          2011/
2010
     2010/
2009
 
     (in days)             (in days)                

Utilization days (1):

              

Ultra-deepwater

     834         536         55.6         813         321         —           153.3         —     

Deepwater

     274         273         0.4         365         365         151         —           141.7   

Midwater

     548         504         8.7         688         472         730         45.8         (35.3

Onshore rigs

     2,466         2,142         15.1         2,970         2,004         2,030         48.2         (1.3
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     4,122         3,455         19.3         4,836         3,162         2,911         52.9         8.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Utilization days are derived by multiplying the number of rigs by the days under contract, excluding upgrade periods. Except for certain of our onshore rigs, our rigs are currently under long-term contracts.

 

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     For the nine-month period ended
September 30,
     For the year ended December 31,  
     2012      2011      2011      2010     2009  

Units in operation:

             

Ultra-deepwater

     4         3         3         1        —     

Deepwater

     1         1         1         1        1   

Midwater

     2         2         2         1 (1)      2   

Onshore rigs

     9         9         9         6        6   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

     16         15         15         9        9   
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) Atlantic Star rig was under upgrade during December 2010.

 

     For the nine-month
period ended
September 30,
     %
Change
    For the year ended
December 31,
     % Change  
         2012              2011          2012/
2011
    2011      2010      2009      2011/
2010
     2010/
2009
 
     (in thousands of $)            (in thousands of $)         

Average contract dayrate (including performance bonus) (1):

          

Ultra-deepwater

     382.3         372.3         2.7        388.5         357.8         —           8.6         —     

Deepwater

     296.8         296.8         —          296.4         292.2         288.2         1.4         1.4   

Midwater

     299.2         224.5         33.3        243.8         198.1         96.8         23.1         104.6   

Onshore rigs

     35.9         38.5         (6.8     39.4         37.2         34.9         5.9         6.6   

 

(1) Contract dayrates denominated in reais have been converted to U.S. dollars for the respective period presented at the average selling rate as reported by the Central Bank for reais into U.S. dollars of R$1.9200 to $1.00 during the nine-month period ended September 30, 2012, R$1.6332 to $1.00 during the nine-month period ended September 30, 2011, R$1.6749 to $1.00 during the year ended December 31, 2011, R$1.7601 to $1.00 during the year ended December 31, 2010 and R$1.9976 to $1.00 during the year ended December 31, 2009.

 

     For the nine-month period
ended September 30,
     For the year ended December 31,  
     2012     2011      2011      2010      2009  
     (%)      (%)  

Uptime (1):

     

Ultra-deepwater

     90        91         84         89         —     

Deepwater

     97        96         94         92         61   

Midwater

     91 (2)      89         90         98         98   

Onshore rigs

     99        99         99         99         99   

 

(1) Uptime is derived by dividing (i) the number of days the rigs effectively earned a contractual dayrate by (ii) utilization days.
(2) Includes nine days of uptime that was compensated at lower dayrates.

The nine-month period ended September 30, 2012 showed an improvement in average ultra-deepwater uptime when compared to the full year average for 2011, which reflected the learning curve related to our rigs. During the nine-month period ended September 30, 2012, the uptime of our ultra-deepwater rigs was also affected by the 28-day downtime of our Gold Star rig in January, which was caused by equipment failure, which has been subsequently repaired. Uptime of our ultra-deepwater rigs for 2011 was adversely impacted by the commencement of operations of two new rigs and the commencement of operations of one rig in 2010 (learning curve).

During the nine-month period ended September 30, 2012, the combined average uptime of our midwater rigs improved to 91% year-over-year, primarily reflecting the return of the Atlantic Star and Alaskan Star drilling rigs from their upgrades in February 2011 and December 2010, respectively. Uptime for the Alaskan Star rig was adversely affected by a minor break-out fire in March, which was immediately controlled without any injuries or material damage. In the first quarter of 2012, the rig had 14 days’ downtime due to unexpected events, including the break-out fire. Uptime on the Atlantic Star rig was adversely affected by 25 days’ downtime due to equipment failure, 15 of which occurred in June and 10 in July, when the rig returned to normal operating conditions. This was the first time this particular equipment failure was experienced and it is not expected to reoccur.

 

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The following tables set forth the uptime for the three-month periods ended March 31, 2012, June 30, 2012 and September 30, 2012:

 

     For the three-month
period ended March 31,
2012
     For the three-month
period ended June 30,
2012
     For the three-month
period ended
September 30, 2012
 
     (%)      (%)      (%)  

Uptime:

        

Ultra-deepwater

     78         94         98   

Deepwater

     97         95         98   

Midwater

     88         90         94   

Onshore rigs

     99         99         99   

Results of Operations of Joint Ventures

We have investments in several joint ventures, and as part of the execution of our business strategy we expect to make additional investments in joint ventures. We currently have:

 

   

a 20% equity interest in two joint ventures with SBM, FPSO Capixaba Venture S.A., or Capixaba Venture, which owns FPSO Capixaba, and SBM Espírito do Mar Inc., or Espírito do Mar, which operates FPSO Capixaba;

 

   

a 20% equity interest in a joint venture with SBM and certain other parties to convert, own and operate FPSO Cidade de Paraty, which is expected to start production in May 2013; and

 

   

a 12.75% equity interest in a joint venture with SBM and certain other parties to convert, own and operate FPSO Cidade de Ilhabela, which is expected to start production in the third quarter of 2014, with an option to increase our participation to 25.5% after first oil production. See “Business—Our Fleet and Investments—FPSOs—FPSO Cidade de Ilhabela.”

We account for these investments under the equity method. We also expect to account for our equity interests in our strategic partnership with Sete Brasil under the equity method. Consequently, our results of operations are subject to fluctuations that depend on the results of these joint ventures. We share control over the operations and policies of these joint ventures. Pursuant to our business plan, we may acquire majority interests in special purpose companies that own FPSOs and we intend to control the operations and policies of those joint ventures.

In addition, we have a 40% interest in a consortium with BWO to operate FPSO P-63 (Papa Terra) (which is wholly owned by Petrobras) for three years commencing in mid-2013 that, if classified as a joint operation, we will account for based on our percentage interest in the related assets, liabilities, revenues and expenses.

Global Demand for Oil and Effect of Oil Prices on Demand for Drilling Services

Demand for drilling rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region. Such spending fluctuations result from a variety of economic and political factors, including:

 

   

worldwide demand for oil and gas;

 

   

regional and global economic conditions;

 

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political, social and legislative environments in major oil-producing countries;

 

   

the policies of various governments, including the Brazilian government, regarding access to their oil and gas reserves;

 

   

the ability of OPEC to set and maintain production levels and pricing and the level of production of non-OPEC countries;

 

   

the development of alternative sources of fuel and energy;

 

   

technological advancements that impact the methods for or cost of oil and gas exploration and development; and

 

   

the impact that these and other events, whether caused by economic conditions, international or national climate change regulations or other factors, may have on the current and expected prices of oil and gas.

Historically, oil and gas prices and market expectations of potential changes in these prices have significantly affected the level of drilling activity worldwide. Generally, higher oil and gas prices, or our customers’ expectations of higher prices, result in greater exploration and development spending by oil and gas companies, and lower oil and gas prices result in reduced exploration and development spending by oil and gas companies.

In 2012, the global offshore drilling market dynamics continued displaying signs of strength with an increase in tender activity (the process in which E&P companies solicit bids from offshore contract drillers for the provision of drilling units, crews and related services which typically concludes with a contract award to the winning bidder) as well as a tightening supply stemming from increasing exploration activity in the Gulf of Mexico, and the rise to prominence of frontier markets such as West Africa and Australia. These improving dynamics have led to increased utilization, increased dayrates, and longer tenor fixtures across all asset classes. Additionally, there has been a significant increase in offshore drilling activity in Brazil. From 2006 to 2011, the number of offshore oil and gas wells drilled has increased by 11% per year, resulting in a total of 1,083 wells drilled over this time period. Further, a significant level of this actively has been targeted to exploit the pre-salt opportunity in ultra-deepwater. The exploration and production of ultra-deepwater blocks is a more complex activity than onshore or shallow water drilling, and consequently, it requires more sophisticated assets. Petrobras has announced plans to seek approximately 95 ultra-deepwater and deepwater units by 2020, from a current fleet of 55 ultra-deepwater and deepwater units. We believe both the short-term and long-term outlook for the Brazilian ultra-deepwater and deepwater market continues to improve.

Planned Investments in the Brazilian Offshore Oil and Gas Market

Although we have previously provided drilling services to various companies, including major oil companies, for the nine-month period ended September 30, 2012, and the year ended December 31, 2011, Petrobras represented approximately 94% and 93% of our gross revenue, respectively. Most of our existing rigs, including our six semi-submersible rigs and six of our nine onshore rigs, are chartered to Petrobras. In addition, we have two drillships in operation (Amaralina Star and Laguna Star), both of which are chartered to Petrobras.

In 2009, Petrobras announced its detailed four-year investment plan, with an estimate of $174 billion projected in capital expenditures through 2013. The plan included $105 billion for E&P, encompassing a tender for 28 rigs to be delivered by 2017. The latest Petrobras plan, released in June 2012, projects investments of $237 billion from 2012-2016. Approximately $142 billion (or 60% of the total planned investments) will be allocated to E&P projects, with $132 billion allocated for projects in Brazil. As a result, offshore activity in Brazil is expected to grow significantly in the coming years, with over 1,000 wells anticipated to be drilled by Petrobras by 2016.

 

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Tax Benefits

We benefit from REPETRO and a number of tax treaties in force in the jurisdictions in which we and our subsidiaries are incorporated. See “Risk Factors—Risks Relating to Our Industry—Changes to, the revocation of, adverse interpretation of, or exclusion from Brazilian tax regimes and international treaties to which we and our clients are currently subject may negatively impact us” and “Business—Brazilian Regulatory Framework—REPETRO.”

Recent Developments

On November 9, 2012, we issued $700.0 million aggregate principal amount of 6.250% senior notes due 2019. The notes are fully and unconditionally guaranteed on a senior basis by Constellation. In addition, we established an interest reserve account in favor of the collateral agent, which was fully funded in an amount sufficient to provide for the payment of the next two succeeding interest payments. Interest on the notes is payable semi-annually and these notes mature in November 2019. We have used $502.0 million of the net proceeds of the offering, or $683.3 million, to repay outstanding short-term debt and intend to use the remaining net proceeds to repay other outstanding short-term debt and for general corporate purposes. See “Capitalization.”

On December 14, 2012 we prepaid $350.1 million of our short-term debt with Banco Bradesco S.A. and on December 13, 2012 we prepaid $151.9 million of our short-term debt with Banco Itaú BBA S.A., in each case, using a portion of the net proceeds from our 6.250% Senior Notes due 2019 described above. We intend to repay our short-term debt with Banco do Brasil S.A. in full ($123.2 million) upon its final maturity, on August 30, 2013.

On November 14, 2012, we, through one of our subsidiaries, exercised an option to enter into a contract with Samsung to design, construct, build, complete and deliver an ultra-deepwater drillship. According to the payment schedule, we paid 10% of the contract price as a first installment, 20% of the contract as a second installment is due in October 2013 and 70% of the contract price upon delivery, subject to the terms and conditions of the construction contract. We expect that Samsung will deliver this ultra-deepwater drillship by December 2014. The total contract price is $586.4 million. See “Business—Backlog and Drilling Contracts—Samsung Letter of Intent.”

For a discussion of other material transactions we entered into, and other material developments affecting our company since September 30, 2012, see “Summary—Recent Developments.”

Results of Operations

The following discussion of our results of operations is based on our financial statements prepared in accordance with IFRS as adopted by the IASB. In the following discussion, references to increases or decreases in any period are made by comparison with the corresponding prior period, except as the context otherwise indicates.

Principal Components of Our Results of Operations

Net Operating Revenue

Our net operating revenue is comprised of revenue from charter and service contracts and mobilization.

Our charter dayrates are denominated and payable in U.S. dollars. Our dayrates under the services agreements are denominated and payable in Brazilian reais, based on the exchange rate for U.S. dollars determined pursuant to the terms of the services agreements. In our offshore drilling contracts, our charter dayrates typically comprise 90% of our total dayrate and our service dayrates typically comprise the remaining 10% of our total dayrate, except with respect to the Lone Star, in which our charter dayrates comprise 60% of the total dayrate and our service dayrates comprise 40%. Our charter and services agreements may permit increases in the dayrates based on a variety of factors, including inflation, machinery and equipment indexes, oil and gas industry indexes, and exchange rate variations.

Net operating revenue is measured at the fair value of the consideration received or receivable. In addition, net operating revenue is determined on an accrual basis according to the contracted dayrates, the uptime and the number of operating days during the financial period. The dayrates for our drilling rigs are set for the entire term of the charter and services agreements and payments are based on uptime; however, a waiting and moving rate equal to 90% or 95% (depending on the contract) of the applicable dayrate applies for certain periods when a drilling rig is available but not in operation.

As is customary in the offshore drilling market, there is a learning curve period for new units during which the unit is not fully utilized. This learning curve typically requires periods of downtime to make operational corrections and therefore, limits our ability to receive maximum revenue during the first 12 to 24 operating months.

 

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Our net operating revenue from our service agreements is presented net of certain federal and municipal taxes. Importantly, the Programa de Integração Social, or PIS (a federal value-added tax), and Contribuição para o Financiamento da Seguridade Social, or COFINS (a federal value-added tax) are deducted from our gross revenue at rates of 1.65% and 7.6%, respectively. In addition, an Imposto sobre Serviços de Qualquer Natureza is assessed on our gross revenue from services at rates ranging from 2% to 5%. Revenue from our charter agreements for our offshore rigs is not subject to any taxes on revenue.

Costs of Services

Our costs of services consist primarily: (1) salaries and payroll expenses of the rig crews and supervisors; (2) depreciation; and (3) materials, maintenance (including repair services) and insurance. The following table sets forth our cost of services for the nine-month periods ended September 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009.

 

     For the nine-month
period ended
September 30,

(unaudited)
     %
Change
    For the year ended
December 31,
     % Change  
         2012              2011          2012/
2011
    2011      2010      2009      2011/
2010
     2010/
2009
 
     (in millions of $)            (in millions of $)         

Payroll, charges and benefits

     128.6         118.2         8.7        165.0         81.0         49.8         103.6         62.6   

Depreciation

     118.5         91.5         29.5        130.1         89.5         48.6         45.3         84.2   

Materials

     30.4         36.3         (16.2     72.8         42.9         18.2         69.4         136.4   

Maintenance

     26.6         28.9         (7.8     39.2         27.0         12.9         45.2         109.1   

Insurance

     9.7         7.5         29.7        11.1         7.0         3.8         58.9         82.5   

Other (1)

     28.7         32.1         (10.6     47.9         17.1         7.9         183.2         115.7   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total cost of services

     342.5         314.5         8.9        466.1         264.5         141.2         76.3         87.3   
  

 

 

    

 

 

    

 

 

   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Composed mainly of costs for communication, transportation, information technology, taxes, legal advisors, auditors and advisory services.

Salaries and payroll expenses include expenses for the crew that operates a rig, supervisors that directly support the operation of the rig and salaries, charges, benefits and costs related to training. Most of our payroll expenses are payable in reais, matching the currency of payment under our services agreements.

Depreciation costs are based on the costs of our drilling rigs, which are depreciated linearly over their respective useful economic lives. See note 10 to our unaudited condensed consolidated interim financial information for further details on the useful economic lives of our rigs. Drilling equipment is recorded at the lower of its acquisition cost or its market value. Our costs related to materials, maintenance and repair services (payable principally in U.S. dollars) include the costs of drilling equipment and supplies.

When we commence operations of a unit, we typically have higher costs as a percent of our net operating revenue of the unit because we begin incurring full operating expenses. In contrast, our net operating revenue is driven by efficiency rates achieved during the learning curve period.

General and Administrative Expenses

Our general and administrative expenses consist of office expenses as well as the remuneration and compensation of directors and administrative employees, legal and auditing fees, rent expense related to office space and other miscellaneous expenses.

 

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Financial costs, net

Our financial costs, net consists of interest on loans and financings, derivatives expenses, financial expenses with related parties, interest and monetary variations and other financial costs, net of financial income, including, interest on cash investments, income on loan receivables and other financial income.

Taxes

We are organized in Luxembourg and most of our subsidiaries are organized in the British Virgin Islands and the Cayman Islands, which jurisdictions do not charge income taxes. We have subsidiaries organized in the Netherlands, where a tax on our reportable income is imposed, but none of our Netherlands subsidiaries reported taxable income during the nine-month period ended September 30, 2012, or during 2011, 2010 or 2009, and we do not expect to recognize taxable income in the Netherlands during future periods. Certain of our subsidiaries are organized in Brazil and are subject to corporate statutory income tax and social contribution tax at a composite rate of 34%.

Effects of Foreign Exchange Variations on Our Results of Operations

Although our net operating revenues are primarily driven by the expansion of our fleet of drilling rigs, dayrates, the availability of certain of our drilling rigs and mobilization, our net operating revenue is also affected by fluctuations in the real-U.S. dollar exchange rate to the extent that revenue under our service agreements denominated in reais. In addition, our payroll, charges and benefits expenses as well as certain general and administrative expenses are also affected by fluctuations in the real-U.S. dollar exchange rate to the extent that these expenses are denominated in reais.

We measure the effect of foreign exchange variations on our results of operations derived from QGOG and denominated in reais by assuming that the exchange rate in the prior period remains the same between periods of comparison and all other factors affecting our results of operations are also otherwise unaffected.

The 17.6% depreciation of the average daily selling rate of the real against the U.S. dollar, as reported by the Central Bank, during the nine-month period ended September 30, 2012 compared to the nine-month period ended September 30, 2011 resulted in:

 

   

a 6.7% decrease in revenue in U.S. dollars from our service contracts that were in force during the nine-month period ended September 30, 2012 compared to the corresponding period of 2011; and

 

   

a 19.4% decrease in payroll, charges and benefits costs and expenses in U.S. dollars during the nine-month period ended September 30, 2012 compared to the corresponding period of 2011.

Conversely, the 4.8% and 11.9% appreciation of the average daily selling rate of the real against the U.S. dollar, as reported by the Central Bank, during 2011 compared to 2010 and during 2010 compared to 2009, respectively, resulted in:

 

   

a 2.5% increase in revenue in U.S. dollars from QGOG’s contracts that were in force during 2011 when compared to 2010 and a 7.6% increase during 2010 when compared to 2009; and

 

   

a 7.9% increase in payroll, charges and benefits costs and expenses in U.S. dollars during 2011 when compared to 2010 and an 18.4% increase during 2010 when compared to 2009.

Revenue denominated in reais generated under our service agreements tends to provide a natural hedge against a portion of our payroll, charges and benefits expenses and general and administrative expenses denominated in reais, but they do not fully match them. Fluctuations in the real against the U.S. dollar have not had a material

 

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impact on our overall operating results or our net income. Therefore, we do not enter into hedging arrangements with respect to our exposure to the residual foreign exchange rate risk, as we do not believe that this risk to our business is material. See “—Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Exchange Rate Risk.”

EBITDA

EBITDA is a non-GAAP measure prepared by us. EBITDA consists of: net income, plus financial costs, net, taxes and depreciation. EBITDA is not a measure defined under IFRS, should not be considered in isolation, does not represent cash flow for the periods indicated and should not be regarded as an alternative to cash flow or net income, or as an indicator of operational performance or liquidity. EBITDA does not have a standardized meaning, and different companies may use different EBITDA definitions. Therefore our definition of EBITDA may not be comparable to the definitions used by other companies. We use EBITDA to analyze our operational and financial performance, as well as a basis for administrative decisions. The use of EBITDA as an indicator of our profitability has limitations because it does not account for certain costs in connection with our business, such as financial costs, net, taxes, depreciation, capital expenses and other related expenses.

The following table sets forth a reconciliation of our EBITDA to net income (loss) for each of the periods and years presented:

 

     For the nine–month period
ended September 30,

(unaudited)
    For the year ended December 31,  
         2012             2011                 2011             2010             2009          
     (in millions of $)  

Other Financial Information:

  

Net income (loss) for the period/year

     111.3        (24.7     (43.5     (45.3     (44.7

(+) Financial costs, net

     94.2        92.7        118.5        76.3        32.0   

(+) Taxes

     0.7        0.7        5.1        (1.5     (0.9

(+) Depreciation

     119.4        92.5        131.3        90.6        49.5   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA (1)(2)

     325.6        161.2        211.4        120.1        35.9   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA margin (%) (3)

     56.5     38.8     36.1     34.6     22.9

 

(1) EBITDA was adversely impacted by provisions related to penalties due to late delivery of rigs of $10.7 million for the nine-month period ended September 30, 2011 and $10.8 million, $35.0 million and $17.3 million for the years ended December 2011, 2010 and 2009. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Year Ended December 31, 2011 Compared with Year Ended December 31, 2010—Other Operating Expenses, Net” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Year Ended December 31, 2010 Compared with Year Ended December 31, 2009—Other Operating Expenses, Net.”
(2) EBITDA is a non-GAAP measure prepared by us. EBITDA consists of: net income, plus financial costs, net, taxes and depreciation. EBITDA is not a measure defined under IFRS, should not be considered in isolation, does not represent cash flow for the periods indicated and should not be regarded as an alternative to cash flow or net income, or as an indicator of operational performance or liquidity. EBITDA does not have a standardized meaning, and different companies may use different EBITDA definitions. Therefore our definition of EBITDA may not be comparable to the definitions used by other companies. We use EBITDA to analyze our operational and financial performance, as well as a basis for administrative decisions. The use of EBITDA as an indicator of our profitability has limitations because it does not account for certain costs in connection with our business, such as financial costs, net, taxes, depreciation, capital expenses and other related expenses.
(3) EBITDA margin is a non-GAAP measure prepared by us. EBITDA margin is calculated by dividing EBITDA by net operating revenue for the applicable period.

 

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Nine-Month Period Ended September 30, 2012 Compared with Nine-Month Period Ended September 30, 2011

The following table sets forth unaudited condensed consolidated interim financial information for the nine-month periods ended September 30, 2012 and 2011.

 

    

For the nine-month period ended September 30,

(unaudited)

 
         2012             2011             % Change      
     (in millions of $)        

Net operating revenue

     575.9        415.3        38.7   

Costs of services

     (342.5     (314.5     8.9   

Gross profit

     233.5        100.9        131.4   

General and administrative expenses

     (31.5     (22.1     42.4   

Other operating income (expenses), net

     1.8        (10.5     n.m.   

Operating profit

     203.8        68.2        198.7   

Financial costs, net

     (94.2     (92.7     1.6   

Share of results of joint ventures

     2.4        0.5        363.7   

Income (loss) before taxes

     112.0        (23.9     n.m.   

Taxes

     (0.7     (0.7     (4.8

Net income (Loss)

     111.3        (24.7     n.m.   

 

n.m.: not meaningful.

Net Operating Revenue

Net operating revenue increased by $160.6 million, or 38.7%, during the nine-month period ended September 30, 2012 compared to the corresponding period in 2011, primarily as a result of:

 

   

the commencement of operations of our Alpha Star rig in July 2011, contributing an $89.9 million increase to net operating revenue during the nine-month period ended September 30, 2012;

 

   

the $39.6 million increase in the contribution to net operating revenue of our Atlantic Star rig due to (1) the increased dayrate for this unit beginning in July 2011 as a result of a renegotiated contract, and (2) the increased availability of this unit during the nine-month period ended September 30, 2012 compared to the nine-month period ended September, 2011. During the nine-month period ended September 30, 2011, our Atlantic Star rig was unavailable for 42 days while undergoing an upgrade;

 

   

the commencement of operations of our Lone Star rig in April 2011, which contributed a $25.6 million increase to net operating revenue during the nine-month period ended September 30, 2012; and

 

   

the commencement of operations of our QG-V, QG-VIII and QG-IX rigs in April 2011, contributing an aggregate increase of $12.5 million to our net operating revenue during the nine-month period ended September 30, 2012.

The positive effects of these factors were partially offset by the 17.6% depreciation of the average daily selling rate of the real against the U.S. dollar during the nine-month period ended September 30, 2012, compared with the corresponding period in 2011, which resulted in our net operating revenue being $28.0 million less than it would have been had there been no change in the average daily selling rate between these periods and all other factors affecting our net operating revenue were otherwise unaffected.

Costs of Services

Costs of services increased by $28.0 million, or 8.9%, during the nine-month period ended September 30, 2012 compared to the corresponding period in 2011. The following table sets forth the components of our cost of services for the nine-month periods ended September 30, 2012 and 2011.

 

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     For the nine-month period ended
September 30,

(unaudited)
        
         2012              2011          % Change  
     (in millions of $)  

Payroll, charges and benefits

     128.6         118.2         8.7   

Depreciation

     118.5         91.5         29.5   

Materials

     30.4         36.3         (16.2

Maintenance

     26.6         28.9         (7.8

Insurance

     9.7         7.5         29.7   

Other (1)

     28.7         32.1         (10.6
  

 

 

    

 

 

    

 

 

 

Total cost of services

     342.5         314.5         8.9   
  

 

 

    

 

 

    

 

 

 

 

(1) Comprised mainly of costs for communication, transportation, information technology, taxes, legal advisors, auditors and advisory services.

Our costs of services increased primarily as a result of:

 

   

the increase in payroll, charges and benefits to $128.6 million, or a 8.7% increase, during the nine-month period ended September 30, 2012 from $118.2 million during the corresponding period in 2011, principally due to (1) payroll, charges and benefits costs incurred for the crews of our Alpha Star, Lone Star, QG-V, QG-VIII and QG-IX rigs, following the commencement of operations of these rigs in the second and third quarters of 2011 and (2) payroll, charges and benefits costs incurred for the crew of Atlantic Star for the full nine-month period ended September 30, 2012 compared to only 230 days in the nine-month period ended September 30, 2011 following the completion of the upgrade of this rig in February 2011. These effects were partially compensated by the 17.6% depreciation of the average daily selling rate of the real against the U.S. dollar during the nine-month period ended September 30, 2012, compared with the corresponding period in 2011, which resulted in these costs being $22.1 million lower than they would have been had there been no change to the average daily selling rate between these periods and all other factors affecting our payroll, charges and benefits costs were otherwise unaffected; and

 

   

a 29.5% increase in depreciation to $118.5 million during the nine-month period ended September 30, 2012 from $91.5 million during the corresponding period in 2011, principally due to depreciation incurred following the commencement of operations of our Alpha Star, Lone Star, QG-V, QG-VIII and QG-IX rigs.

The effect of these factors was partially offset by (1) a 16.2% decrease in materials costs to $30.4 million during the nine-month period ended September 30, 2012 from $36.3 million during the corresponding period in 2011, mainly due to 17.6% depreciation of the average daily selling rate of the real against the U.S. dollar during the nine-month period ended September 30, 2012, compared with the corresponding period in 2011, which resulted in these material costs being $3.8 million lower than they would have been had there been no change to the average daily selling rate between these periods and all other factors affecting our payroll, charges and benefits costs were otherwise unaffected; and (2) a 10.6% decrease in other costs to $28.7 million during the nine-month period ended September 30, 2012 from $32.1 million during the corresponding period in 2011, mainly due to taxes in connection with the commencement of operations of certain onshore rigs in April, 2011.

As a result, our gross profit increased by $132.6 million, or 131.4%, during the nine-month period ended September 30, 2012 compared to the corresponding period in 2011. Gross margin (gross profit as a percentage of net operating revenue) increased to 40.5% during the nine-month period ended September 30, 2012 from 24.3% during the corresponding period in 2011.

 

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General and Administrative Expenses

General and administrative expenses increased by $9.4 million, or 42.4%, during the nine-month period ended September 30, 2012 compared to the corresponding period in 2011, primarily as a result of:

 

   

a 42.8% increase in payroll, charges and benefits expenses to $18.3 million during the nine-month period ended September 30, 2012 from $12.8 million during the corresponding period in 2011, principally due to an increase in our administrative headcount to support the expansion of our operations, annual inflation readjustments of our salaries and expenses related to our corporate reorganization and enhanced corporate governance. The increase in payroll, charges and benefits expenses were partially ameliorated by the 17.6% depreciation of the average daily selling rate of the real against the U.S. dollar during the nine-month period ended September 30, 2012, compared with the corresponding period in 2011, which resulted in these expenses being $3.3 million lower than they would have been had there been no change in the average daily selling rate between these periods and all other factors affecting our payroll, charges and benefits expenses were otherwise unaffected; and

 

   

a 47.5% increase in other expenses to $12.3 million during the nine-month period ended September 30, 2012 from $8.3 million during the corresponding period in 2011, principally due to an increase in expenses for consultants, legal and financial advisers and auditors in connection with our corporate reorganization. General and administrative expenses as a percentage of net operating revenue increased to 5.5% during the nine-month period ended September 30, 2012 from 5.3% during the corresponding period in 2011.

Other Operating Income (Expenses), Net

Our other net operating income (expenses), net was $1.8 million during the nine-month period ended September 30, 2012 compared to other net operating expenses, net, of $10.5 million during the corresponding period in 2011, primarily as a result of contractual penalties for delays in our deliveries of our Amaralina Star and Laguna Star rigs in the aggregate amount of $8.5 million during the nine-month period ended September 30, 2011. We did not incur any similar penalties during the nine-month period ended September 30, 2012.

Operating Profit

As a result of the foregoing, our operating profit increased by 198.7% to $203.8 million during the nine-month period ended September 30, 2012 compared to $68.2 million for the corresponding period in 2011. As a percentage of net operating revenue, our operating profit increased to 35.4% during the nine-month period ended September 30, 2012 from 16.4% in the corresponding period in 2011.

Financial Costs, Net

The net financial costs increased by $1.5 million, or 1.6%, during the nine-month period ended September 30, 2012 compared to the corresponding period in 2011, as a result of a 3.3% increase in financial costs to $101.0 million in the nine-month period ended September 30, 2012 from $97.8 million during the corresponding period in 2011 and a 34.7% increase in financial income to $6.8 million in the nine-month period ended September 30, 2012 from $5.0 million during the corresponding period in 2011.

Financial Income

Financial income increased to $6.8 million during the nine-month period ended September 30, 2012 from $5.0 million during the corresponding period in 2011, primarily as a result of an increase in interest income from cash investments.

Financial Costs

Financial costs increased by 3.3% to $101.0 million during the nine-month period ended September 30, 2012 from $97.8 million during the corresponding period in 2011, principally due to a 92.0% increase in financial charges on loans and financings to $59.0 million during the nine-month period ended September 30, 2012 from $30.8 million during the corresponding period in 2011, primarily as a result of (a) our recognition during the nine-month period ended September 30, 2012 of $7.0 million of interest expense related to our financing of our Alpha Star and Lone Star rigs and for other projects that we had capitalized prior to the commencement of operation of these units, (b) $12.2 million related to the secured project bond we issued in July 2011 and (c) our recognition during the nine-month period ended September 30, 2012 of $10.4 million of interest expense related to short-term loans. Interest expense for the nine-month period ended September 30, 2012 as a percentage of total indebtedness as of September 30, 2012 was 1.8%.

 

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Share of Results of Joint Ventures

Our share of results of joint ventures was $2.4 million during the nine-month period ended September 30, 2012 compared to $0.5 million during the corresponding period in 2011.

Taxes

Our tax expense was $0.7 million during the nine-month period ended September 30, 2012, the same as during the corresponding period in 2011.

Net Income for the Period

Our net income was $111.3 million, or 19.3% of our net operating revenue, during the nine-month period ended September 30, 2012 compared to a net loss of $24.7 million during the corresponding period in 2011.

Year Ended December 31, 2011 Compared with Year Ended December 31, 2010

The following table sets forth combined financial information for the years ended December 31, 2011 and 2010.

 

     For the year ended December 31,        
         2011             2010         % Change  
     (in millions of $)        

Net operating revenue

     586.3        346.8        69.1   

Costs of services

     (466.1     (264.5     76.3   
  

 

 

   

 

 

   

Gross profit

     120.2        82.3        46.0   

General and administrative expenses

     (29.8     (24.7     20.6   

Other operating expenses, net

     (11.3     (34.3     (67.0
  

 

 

   

 

 

   

Operating profit

     79.1        23.3        238.7   

Financial costs, net

     (118.5     (76.3     55.3   

Share of results of joint ventures

     1.0        6.2        (83.4
  

 

 

   

 

 

   

Loss before taxes

     (38.4     (46.8     (18.0

Taxes

     (5.1     1.5        n.m.   
  

 

 

   

 

 

   

Loss for the year

     (43.5     (45.3     (4.0
  

 

 

   

 

 

   

 

n.m.: not meaningful.

Net Operating Revenue

Net operating revenue increased by $239.5 million, or 69.1%, during 2011, primarily as a result of:

 

   

the commencement of operations of our Alpha Star rig in July 2011, contributing a $58.6 million increase to net operating revenue during 2011;

 

   

the commencement of operations of our Lone Star rig in April 2011, contributing a $66.5 million increase to net operating revenue during 2011;

 

   

the commencement of operations of our QG-V, QG-VIII and QG-IX rigs in April 2011, contributing an aggregate increase of $27.9 million to net operating revenue during 2011;

 

   

the $29.9 million increase in the contribution to net operating revenue of Atlantic Star due to (1) the increased dayrate for this unit effective in July 2011 as a result of a renegotiated contract, and (2) the increased uptime of this unit in 2011. During 2010, Atlantic Star was unavailable for 183 days while undergoing an upgrade, while it was unavailable due to this upgrade for only 42 days in 2011;

 

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the $29.1 million increase in the contribution to net operating revenue of Alaskan Star due to the increased uptime of this unit in 2011. During 2010, Alaskan Star was unavailable for 155 days while undergoing an upgrade, which was completed in December 2010; and

 

   

the 4.8% appreciation of the average daily selling rate of the real against the U.S. dollar from 2010 to 2011, which resulted in our net operating revenue being $8.6 million greater than it would have been had there been no change in the average daily selling rate between these years and all other factors affecting our net operating revenue were otherwise unaffected.

Costs of Services

Costs of services increased by $201.6 million, or 76.3%, during 2011. The following table sets forth the components of our cost of services for the years ended December 31, 2011 and 2010.

 

     For the year ended December 31,         
         2011              2010          % Change  
     (in millions of $)  

Payroll, charges and benefits

     165.0         81.0         103.6   

Depreciation

     130.1         89.5         45.3   

Materials

     72.8         42.9         69.4   

Maintenance

     39.2         27.0         45.2   

Insurance

     11.1         7.0         58.9   

Other (1)

     47.9         17.1         183.2   
  

 

 

    

 

 

    

Total cost of services

     466.1         264.5         76.3   
  

 

 

    

 

 

    

 

(1) Comprised mainly of costs for communication, transportation, information technology, of income taxes, legal advisors, auditors and advisory services.

Our costs of services increased primarily as a result of:

 

   

a 103.6% increase in payroll, charges and benefits costs to $165.0 million during 2011 from $81.0 million during 2010, principally due to (1) our recognition in 2011 of personnel costs related to the crews of Alpha Star, Lone Star, QG-V, QG-VIII and QG-IX in 2011, following the commencement of operations of these rigs and (2) the effects of the 4.8% appreciation of the average daily selling rate of the real against the U.S. dollar from 2010 to 2011, which resulted in these costs being $6.9 million greater than they would have been had there been no change to the average daily selling rate between these years and all other factors affecting our payroll, charges and benefits expenses were otherwise unaffected;

 

   

a 45.3% increase in depreciation costs to $130.1 million during 2011 from $89.5 million during 2010, principally due to additional depreciation incurred following the commencement of operations of Alpha Star, Lone Star, QG-V, QG-VIII and QG-IX;

 

   

a 183.2% increase in other expenses to $47.9 million in 2011 from $17.1 million in 2010 mainly due to tax provisions and other taxes in connection with the commencement of operations of onshore rigs; and

 

   

a 69.4% increase in materials costs to $72.8 million during 2011 from $42.9 million during 2010, principally due to an increase in our materials requirements as a result of the commencement of operations of Alpha Star, Lone Star, QG-V, QG-VIII and QG-IX.

As a result, gross profit increased by $37.9 million, or 46.0%, during 2011. Gross margin (gross profit as a percentage of net operating revenue) declined slightly to 20.5% during 2011 from 23.7% during 2010 due to the learning curve of our operations, and the associated effect of the learning curve for Alpha Star on our margins.

 

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General and Administrative Expenses

General and administrative expenses increased by $5.1 million, or 20.6%, during 2011, primarily as a result of a 38.4% increase in payroll, charges and benefits expenses to $18.0 million during 2011 from $13.0 million during 2010, principally due to (1) an increase in headcount resulting from the expansion of our operations, other expenses related to our corporate reorganization and the improvement of our corporate governance due to new requirements deriving from the terms of our private placement and our project financings and (2) the effects of the 4.8% appreciation of the average daily selling rate of the real against the U.S. dollar from 2010 to 2011, which resulted in these expenses being $0.6 million greater than they would have been had there been no change in the average daily selling rate between these years and all other factors affecting our payroll, charges and benefits expenses were otherwise unaffected. General and administrative expenses as a percentage of net operating revenue declined to 5.1% during 2011 from 7.1% during 2010.

Other Operating Expenses, Net

Other operating expenses, net, declined by $23.0 million, or 67.0%, during 2011, primarily as a result of a 69.1% decline in penalties to $10.8 million during 2011 from $35.0 million during 2010. The 2011 penalties included contractual penalties for delays in the delivery of Lone Star, Amaralina Star and Laguna Star. The 2010 penalties included contractual penalties for delays in the delivery of Olinda Star, Lone Star and Gold Star.

Operating Profit

As a result of the foregoing, our operating profit increased by 238.7% to $79.1 million during 2011 from $23.3 million in 2010. As a percentage of net operating revenue, operating profit increased to 13.5% in 2011 from 6.7% in 2010.

Financial Costs, Net

Financial costs, net, increased by $42.2 million, or 55.3%, during 2011, as a result of a 52.6% increase in financial costs to $121.9 million in 2011 from $79.9 million in 2010 and a 4.1% decrease in financial income to $3.4 million in 2011 from $3.6 million in 2010.

Financial Income

Financial income declined to $3.4 million during 2011 from $3.6 million during 2010, primarily as a result of a 66.7% decrease in non-cash gains from exchange rate variations to $0.5 million during 2011 from $1.5 million during 2010, the effects of which were partially offset by an increase in financial income from related parties to $0.6 million during 2011 from $0.2 million during 2010.

Financial Costs

Financial costs increased by 52.6% to $121.9 million during 2011 from $79.9 million during 2010, principally due to (1) a 132.0% increase in financial charges on loans and financings to $60.0 million during 2011 from $25.9 million during 2010, primarily as a result of (a) our recognition in 2011 of interest expenses related to the financing of Alpha Star and Lone Star in 2011, which we had capitalized prior to the commencement of operation of these units and (b) our recognition of interest expense related to the financing of Gold Star for the full year in 2011 compared to 11 months during 2010, which we had capitalized during the remaining one month of 2010, and (2) a 154.7% increase in financial expenses from related parties to $16.0 million during 2011 from $6.3 million during 2010, primarily as a result of our paying fees to QG S.A. as consideration for its guarantee of certain of our debt obligations for the full year 2011 compared to six months of 2010. See “Certain Relationships and Related Party Transactions.” Interest expense as a percentage of total indebtedness outstanding as of the end of the year increased to 2.5% during 2011 from 1.3% during 2010.

Share of Results of Joint Ventures

Share of results of joint ventures declined by $5.2 million, or 83.4%, during 2011 as a result of the effects of the upgrade of FPSO Capixaba (and the reduced uptime during the upgrade) and of the financing of this upgrade in 2010, which resulted in Capixaba Venture recognizing increased depreciation costs and financial charges. In addition, the renegotiation of the existing FPSO Capixaba contract led to an extended contract term and a slightly lower dayrate beginning in June 2010.

 

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Taxes

Our tax expense was $5.1 million during 2011 compared to a deferred tax of $1.5 million during 2010 due to the higher taxable income of QGOG in 2011.

Loss for the Year

Loss declined to $43.5 million, or 7.4% of net operating revenue, during 2011 from $45.3 million, or 13.1% of net operating revenue, during 2010.

Year Ended December 31, 2010 Compared with Year Ended December 31, 2009

The following table sets forth combined financial information for the years ended December 31, 2010 and 2009.

 

     For the year ended December 31,        
         2010             2009         % Change  
     (in millions of $)        

Net operating revenue

     346.8        156.6        121.5   

Cost of services

     (264.5     (141.2     87.3   
  

 

 

   

 

 

   

Gross profit

     82.3        15.4        435.5   

General and administrative expenses

     (24.7     (20.0     23.7   

Other operating expenses, net

     (34.3     (15.9     115.7   
  

 

 

   

 

 

   

Operating profit (loss)

     23.3        (20.5     n.m.   

Financial costs, net

     (76.3     (32.0     138.8   

Share of results of joint ventures

     6.2        6.9        (9.1
  

 

 

   

 

 

   

Loss before taxes

     (46.8     (45.6     2.6   

Taxes

     1.5        0.9        54.2   
  

 

 

   

 

 

   

Loss for the year

     (45.3     (44.7     1.5   
  

 

 

   

 

 

   

 

n.m.: not meaningful.

Net Operating Revenue

Net operating revenue increased by $190.2 million, or 121.5%, during 2010, primarily as a result of:

 

   

the commencement of operations of Gold Star in February 2010, contributing a $100.2 million increase to net operating revenue during 2010;

 

   

the commencement of operations of Olinda Star in August 2009, contributing an $85.9 million increase to net operating revenue during 2010 compared to $22.5 million during the five months that Olinda Star was operational in 2009;

 

   

the $32.2 million increase in net operating revenue of Alaskan Star due to the increased dayrate for this unit beginning in December 2009, the effects of which were partially offset by this unit being unavailable during its upgrade for 155 days during 2010; and

 

   

the 11.9% appreciation of the average daily selling rate of the real against the U.S. dollar from 2009 to 2010, which resulted in our net operating revenue being $11.9 million greater than it would have been had there been no change in the average daily selling rate between these years and all other factors affecting our net operating revenue were otherwise unaffected.

 

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Costs of Services

Costs of services increased by $123.3 million, or 87.3%, during 2010. The following table sets forth the components of our cost of services for the years ended December 31, 2010 and 2009.

 

     For the year ended December 31,         
         2010              2009          % Change  
     (in millions of $)  

Payroll, charges and benefits

     81.0         49.8         62.6   

Depreciation

     89.5         48.6         84.2   

Materials

     42.9         18.2         136.4   

Maintenance

     27.0         12.9         109.1   

Insurance

     7.0         3.8         82.5   

Other (1)

     17.1         7.9         115.7   
  

 

 

    

 

 

    

Total cost of services

     264.5         141.2         87.3   
  

 

 

    

 

 

    

 

(1) Comprised mainly of costs for communication, transportation, information technology, legal advisors, auditors and advisory services.

Our costs of services increased primarily as a result of:

 

   

a 84.2% increase in depreciation to $89.5 million during 2010 from $48.6 million during 2009, principally due to depreciation incurred following the commencement of operations of Gold Star and the effect of a full year of operations of Olinda Star in 2010;

 

   

a 62.6% increase in payroll, charges and benefits costs to $81.0 million during 2010 from $49.8 million during 2009, principally due to (1) our recognition in 2010 of personnel costs related to the crew of Gold Star that commenced operating in February 2010 and an increase in headcount as a result of our expansion of the base in Macaé (which we have since closed), in the State of Rio de Janeiro to support our growing fleet of offshore rigs and (2) the effects of the 11.9% appreciation of the average daily selling rate of the real against the U.S. dollar from 2009 to 2010, which resulted in these costs being $9.9 million greater than they would have been had there been no change in the average daily selling rate between these periods and all other factors affecting our payroll, charges and benefits costs were otherwise unaffected;

 

   

a 136.4% increase in materials costs to $42.9 million during 2010 from $18.2 million during 2009, principally due to costs related to materials necessary for commencement of operations of Gold Star and the expansion of our base in Macaé; and

 

   

a 109.1% increase in maintenance costs to $27.0 million during 2010 from $12.9 million during 2009, principally due to (1) the commencement of operations of Gold Star and mobilization costs and (2) the effects of the 11.9% appreciation of the average daily selling rate of the real against the U.S. dollar from 2009 to 2010, which resulted in these costs being $2.8 million greater than they would have been had there been no change in the average daily selling rate between these periods and all other factors affecting our maintenance costs were otherwise unaffected.

As a result, gross profit increased by $66.9 million, or 435.5%, during 2010. Gross margin increased to 23.7% during 2010 from 9.8% during 2009.

General and Administrative Expenses

General and administrative expenses increased by $4.7 million, or 23.7%, during 2010, primarily as a result of:

 

   

a 41.2% increase in communication, transportation, information technology and consulting services to $10.7 million during 2010 from $7.5 million during 2009; and

 

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a 12.4% increase in payroll, charges and benefits expenses to $13.0 million during 2010 from $11.5 million during 2009, principally due to (1) an increase in headcount at our headquarters resulting from personnel, required to support our addition at operating rigs and (2) the effects of the 11.9% appreciation of the average daily selling rate of the real against the U.S. dollar from 2009 to 2010, which resulted in these expenses being $1.4 million greater than they would have been had there been no change in the average daily selling rate between these periods and all other factors affecting our payroll, charges and benefits expenses were otherwise unaffected.

Other Operating Expenses, Net

Other operating expenses, net, increased by $18.4 million, or 115.7%, during 2010, principally as a result of a 102.3% increase in penalties to $35.0 million in 2010 from $17.3 million during 2009, primarily due to the imposition of penalties in 2010 under charter agreements as a result of delays in the delivery of Olinda Star, Lone Star and Gold Star compared to the imposition of penalties in 2009 under charter agreements as a result of delays in the delivery of Olinda Star and Gold Star.

Operating Profit (Loss)

As a result of the foregoing, our operating profit was $23.3 million during 2010 compared to an operating loss of $20.5 million in 2009. As a percentage of net operating revenue, operating profit was 6.7% in 2010 compared to operating loss of 13.1% in 2009.

Financial Costs, Net

Financial costs, net, increased by $44.3 million, or 138.8%, during 2010 as a result of a 131.1% increase in financial expenses, the effects of which were partially offset by a 37.0% increase in financial income.

Financial Income

Financial income increased by 37.0% to $3.6 million during 2010 from $2.6 million during 2009, primarily as a result of a 102.9% increase in non-cash gains from exchange rate variations to $1.5 million during 2010 from $0.7 million during 2009.

Financial Costs

Financial costs increased by 131.1% to $79.9 million during 2010 from $34.6 million during 2009, principally due to (1) a $40.0 million increase in non-cash derivatives expenses to $41.2 million during 2010 from $1.2 million during 2009, primarily as a result of (a) the increase in the nominal amount of our derivatives, which we use to hedge our exposure to floating interest rates under many of our debt obligations, in connection with the incurrence of indebtedness under our financing arrangements for our drilling rigs and (b) the mark-to-market effects of our debt obligations of $11.9 million and (2) $6.3 million of financial expenses from related parties recorded during 2010, primarily as a result of our agreement in July 2010 to pay fees to QG S.A. as consideration for its guarantee of certain of our debt obligations. The effects of these factors was partially offset by our recording a $0.3 million gain from exchange rate variations in 2010 compared to a $6.8 million loss from exchange rate variations in 2009 related to the effects of the depreciation of the real on the reimbursement in reais of certain expenses incurred by QGOG during the period between the date of incurrence of these expenses and the date of their reimbursement. Interest expense as a percentage of total indebtedness outstanding as of the end of the year decreased to 1.3% during 2010 from 1.4% during 2009.

Share of Results of Joint Ventures

Share of results of joint ventures declined by $0.7 million, or 9.1%, during 2010, as a result of the 33.1% decline in the net income recorded by SBM Espírito do Mar during 2010, the effects of which were partially offset by an increase in the share of results of Capixaba Venture to $1.7 million during 2010 from $0.1 million during 2009. The 9.1% decline in net income recorded by SBM Espírito do Mar was primarily due to the renegotiation of the existing FPSO Capixaba contract, which led to an extended contract term and a slightly lower dayrate beginning in June 2010.

 

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Taxes

Our deferred tax was $1.5 million during 2010 compared to $0.9 million during 2009.

Loss for the Year

Loss increased by 1.5% to $45.3 million, or 13.1% of net operating revenue, during 2010 from $44.7 million, or 28.5% of net operating revenue, during 2009.

Liquidity and Capital Resources

We operate in a capital intensive industry. Our principal cash requirements consist of the following:

 

   

capital expenditures related to investments in operations, construction of new offshore rigs, and maintenance and upgrades of our existing drilling rigs;

 

   

servicing our indebtedness;

 

   

equity contributions to joint ventures; and

 

   

working capital requirements.

Our principal sources of liquidity consist of the following:

 

   

cash flows from operating activities;

 

   

short-term and long-term loans and financings; and

 

   

capital contributions and shareholder contributions.

During the nine-month period ended September 30, 2012 and the year ended December 31, 2011, we used our cash flow generated by operations primarily for investing activities, to service our outstanding debt obligations and for working capital requirements. As of September 30, 2012, we recorded consolidated cash and cash equivalents and short-term investments of $276.7 million and $116.1 million, respectively. As of September 30, 2012, we had a negative working capital of $576.0 million, mainly related to short-term debt in the amount of $619.5 million. In November 2012, the Company issued $700.0 million aggregate principal amount of 6.250% senior notes due 2019 on November 9, 2012. We used $502.0 million of the net proceeds of the offering to repay short-term debt and intend to use the remaining net proceeds to reduce our negative working capital by repaying a portion of our short-term debt. For more information, see “Summary—Recent Developments.”

As the indirect parent company of our operating subsidiaries, we are not a direct party to any charter agreements and are therefore dependent on receiving dividends from our subsidiaries. Distribution of surplus cash held in our subsidiaries that own our drilling rigs and are borrowers under the financing agreements related thereto may be restricted under such financing agreements. We do not believe these restrictions will prevent us and other non-borrowing subsidiaries from meeting our respective liquidity needs.

We believe, based on our current business plan, that the net proceeds of this offering, our cash and cash equivalents on hand, our cash generated by operations and available under our existing credit facilities will be adequate to meet all of our capital expenditure requirements and liquidity needs in the near term. We may require additional capital to meet our longer term financing and future growth requirements.

 

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Cash Flows

The following table sets forth our cash flows for the periods presented.

 

     For the nine-month
period ended September 30,

(unaudited)
    For the year ended December 31,  
           2012                 2011               2011             2010             2009      
     (in millions of $)  

Cash flows provided used in operating activities:

          

Net income (loss) for the period

     111.3        (24.7     (43.5     (45.3     (44.7

Adjustments to reconcile net income (loss) to net cash used in operating activities

     207.3        193.6        260.7        192.5        89.2   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income after adjustments to reconcile net income (loss) to net cash used in operating activities

     318.6        168.9        217.2        147.2        44.5   

Decrease (increase) in working capital related to operating activities

     (41.0     (73.5     (99.3     (67.8     (53.8
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash flows provided by (used in) operating activities

     277.7        95.4        117.9        79.4        (9.3

Cash flows used in investing activities

     (1,006.9     (259.5     (277.8     (799.9     (391.1

Cash flows provided by financing activities

     816.1        467.6        262.4        739.3        367.7   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Increase (decrease) in cash and cash equivalents

     86.8        303.5        102.5        18.8        (32.7
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash Flows Provided by (Used in) Operating Activities

During the nine-month period ended September 30, 2012, operating activities provided net cash of $277.7 million and during the nine-month period ended September 30, 2011, operating activities provided net cash of $95.4 million. During the years ended December 31, 2011 and 2010, operating activities provided net cash of $117.9 million and $79.4 million, respectively, and during the year ended December 31, 2009, operating activities used net cash of $9.3 million.

Net cash provided by operating activities increased by $182.2 million during the nine-month period ended September 30, 2012 compared to the corresponding period in 2011. This increase was due to an increase in our cash generated from net income after adjustments to reconcile net income to net cash used in operating activities of $149.7 million compared to the corresponding period in 2011. Our cash generated from net income after adjustments to reconcile net income to net cash used in operating activities increased mainly due to commencement of operations of our Alpha Star, Lone Star, QG-V, QG-VIII and QG- IX rigs, and the increased dayrate for Atlantic Star beginning in July 2011. During the nine-month period ended September 30, 2012, the increase in our working capital was $41.0 million, compared to an increase of $73.5 million in our working capital in the corresponding period in 2011. This decrease was primarily a result of a $20.8 million decrease in short-term investments as of September 30, 2012 compared to a $48.1 million increase in these investments during the corresponding period in 2011, and was partially offset by a $63.5 million increase in trade and other receivables during the nine-month period ended September 30, 2012 compared to a $21.5 million decrease in trade and other receivables during the corresponding period in 2011.

Net cash provided by operating activities increased by $38.5 million during the year ended December 31, 2011 compared to the year ended December 31, 2010. In the year ended December 31, 2011, our cash generated from net loss after adjustments to reconcile net loss to net cash used in operating activities was $217.2 million, an increase of $70.0 million compared to the year ended December 31, 2010. This increase was mainly due to the commencement of operations of the Alpha Star, Lone Star, QG-V, QG-VIII and QG- IX, the increased dayrate for Atlantic Star beginning in July 2011 and the increased availability of Atlantic Star in 2011. This increase in net cash provided by operating activities was partially offset by an increase in working capital of $99.3 million in the year ended December 31, 2011 compared to an increase in working capital of $67.8 million in the year ended December 31, 2010, primarily as a result of a $131.8 million increase in short-term investments during 2011 compared to a $27.6 million decrease in such investments during 2010.

Net cash provided by operating activities increased by $88.7 million during the year ended December 31, 2010, compared to the year ended December 31, 2009. In the year ended December 31, 2010, our cash generated from net loss after adjustments to reconcile net loss to net cash used in operating activities was $147.2 million, an increase of $102.7 million compared to the year ended December 31, 2009. This increase was mainly due to the commencement of operations of Gold Star and Olinda Star, and the increased dayrate for Alaskan Star beginning in December 2009. This increase in net cash provided by operating activities was partially offset by an increase in

 

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working capital of $67.8 million in the year ended December 31, 2010 compared to an increase in working capital of $53.8 million in the year ended December 31, 2009, primarily as a result of (1) a $29.6 million increase in restricted cash as of December 31, 2010 and (2) a $49.9 million increase of trade and other receivables during the year ended December 31, 2010, primarily due to reimbursements charged to Petrobras in 2010 and received in 2011, compared to a $30.7 million increase in trade and other receivables during 2009.

Cash Flows Used in Investing Activities

Investing activities used net cash of $1,006.9 million during the nine-month period ended September 30, 2012, $259.5 million during the nine-month period ended September 30, 2011, $277.8 million during the year ended December 31, 2011, $799.9 million during the year ended December 31, 2010 and $391.2 million during the year ended December 31, 2009.

During the nine-month period ended September 30, 2012, investing activities for which we used cash, primarily consisted of (1) loans to related parties of $156.8 million, principally for our portion of milestone payments relating to the construction of FPSO Cidade de Ilhabela, FPSO Cidade de Paraty, and loans made to Alperton to finance its portion of disbursements for the construction of the Amaralina Star and Laguna Star and (2) capital expenditures of $938.2 million in property, plant and equipment, including $930.6 million related to the construction of the Amaralina Star and Laguna Star rigs. These factors were partially offset by proceeds from related parties of $91.5 million related to payments in respect of loans made to Alperton to finance its portion of disbursements for the construction of Amaralina Star and Laguna Star.

During the nine-month period ended September 30, 2011, investing activities for which we used cash primarily consisted of (1) capital expenditures of $197.7 million in property, plant and equipment, including $108.8 million related to our Alpha Star rig, $19.6 million related to our Lone Star rig, and $22.0 million related to our Atlantic Star rig and (2) loans to related parties of $62.3 million, principally for our portion of milestone payments relating to the construction of FPSO Cidade de Paraty.

During the year ended December 31, 2011, investing activities for which we used cash primarily consisted of (1) capital expenditures of $230.2 million in property, plant and equipment, including $119.3 million related to Alpha Star, $23.6 million related to Atlantic Star, $22.7 million related to Amaralina Star and Laguna Star, and $19.6 million related to Lone Star and (2) loans to related parties of $48.3 million, principally due to $31.0 million in milestone payments relating to the construction of FPSO Cidade de Paraty and FPSO Cidade de Ilhabela and $17.3 million related to loans made to Alperton to finance its portion of disbursements for the construction of Amaralina Star and Laguna Star.

During the year ended December 31, 2010, investing activities for which we used cash primarily consisted of (1) capital expenditures of $485.1 million in property, plant and equipment, including $249.6 million related to Alpha Star, $67.0 million related to Alaskan Star and $82.3 million related to Lone Star, (2) advances to suppliers of $212.6 million, primarily consisting of advances to the shipyard that was constructing Amaralina Star and Laguna Star, and (3) proceeds to related parties, primarily consisting of $95.7 million in loans to Alperton to finance its portion of disbursements for the construction of Amaralina Star and Laguna Star.

During the year ended December 31, 2009, investing activities for which we used cash primarily consisted of capital expenditures of $394.3 million in property, plant and equipment, including $165.3 million related to Alpha Star, $107.7 million related to Gold Star, $68.4 million related to Olinda Star and $38.1 million related to Lone Star.

Cash Flows Provided by (Used in) Financing Activities

Financing activities provided net cash of $816.1 million during the nine-month period ended September 30, 2012, and provided net cash of $467.6 million during the nine-month period ended September 30, 2011, $262.4 million during the year ended December 31, 2011, $739.3 million during the year ended December 31, 2010, and $367.7 million during the year ended December 31, 2009.

 

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During the nine-month period ended September 30, 2012, our principal sources of borrowed funds consisted of proceeds, net of transaction costs, of $868.4 million under our Amaralina Star and Laguna Star project loan facility and $262.0 million under a short-term loan made to Constellation. During the nine-month period ended September, 2012, we used cash (1) to make scheduled amortization payments under our loans and financings and repayment of a short-term loan made to Constellation, in an aggregate amount of $275.0 million, (2) to make scheduled interest payments under our loans and financings in an aggregate amount of $51.1 million and (3) to make cash payments of $37.1 million in respect of interest rate swap agreements. Amaralina Star Ltd. and Laguna Star Ltd. also made amortization payments in an aggregate amount of $91.5 million in respect of loans from Alperton to finance its portion of the construction of Amaralina Star and Laguna Star.

During the nine-month period ended September 30, 2011, our principal sources of borrowed funds consisted of proceeds, net of transaction costs, of $685.2 million, from our issuance of 5.25% Senior Secured Notes due 2018, $575.0 million disbursed under our Alpha Star project loan facility, and $313.0 million under short-term loans to Constellation. During the nine-month period ended September 30, 2011, we used cash (1) to prepay all amounts outstanding under our Atlantic Star and Alaskan Star project loan facilities, a bridge loan to finance the construction of Alpha Star, short-term loans made to Constellation, as well as to make scheduled amortization payments under our other loans and financings, in an aggregate amount of $1,137.5 million, (2) to make scheduled interest payments under our loans and financings in an aggregate amount of $50.3 million, and (3) to make payments of $47.2 million in respect of interest rate swap agreements.

During the year ended December 31, 2011, our principal sources of borrowed funds consisted of proceeds of $685.2 million, net of transaction costs, from our issuance of 5.25% Senior Secured Notes due 2018 and $575.0 million disbursed under our Alpha Star project loan facility. During the year ended December 31, 2011, we used cash to prepay all amounts outstanding under our Atlantic Star and Alaskan Star project loan facilities, a bridge loan to finance the construction of Alpha Star, a term loan credit agreement and a revolving credit agreement, as well as to make scheduled amortization payments under our other credit agreements. Interest and derivatives paid totaled $130.3 million. Amaralina Star Ltd. and Laguna Star Ltd. also received loans in the year ended December 31, 2011 from related parties of $17.3 million due to contributions received from Alperton to finance its portion of the construction of Amaralina Star and Laguna Star. See “Certain Relationships and Related Party Transactions.”

During the year ended December 31, 2010, we received cash as a result of a capital increase by Constellation in which CIPEF Constellation Coinvestment Fund L.P. and CIPEF V Constellation Holding L.P. purchased 5,081,050 and 5,788,859 common shares of Constellation, respectively, for an aggregate purchase price of $420.7 million, net of $9.3 million of expenses directly related to this capital increase. During the year ended December 31, 2010, our principal sources of borrowed funds consisted of $260.0 million disbursed under our Alpha Star project loan facility and $133.0 million disbursed under our Atlantic Star project loan facility. During the year ended December 31, 2010, we used cash to make scheduled amortization payments under our credit agreements. Interest and derivatives paid totaled $89.2 million. Amaralina Star Ltd. and Laguna Star Ltd. also received loans in 2010 from related parties of $95.7 million due to contributions received from Alperton to finance its portion of the construction of Amaralina Star and Laguna Star. See “Certain Relationships and Related Party Transactions.”

During the year ended December 31, 2009, our principal sources of borrowed funds consisted of $160.6 million under the Alaskan Star project loan facility and $127.8 million disbursed under our Lone Star and Gold Star project loan facilities, $87.0 million disbursed under our Atlantic Star project loan facility and $107.5 million disbursed under a bridge loan. During the year ended December 31, 2009, we used cash to refinance all amounts outstanding under our Atlantic Star facility, as well as to make scheduled amortization payments under our other credit agreements. Interest and derivatives paid totaled $35.1 million.

Capital Expenditures

We have incurred capital expenditures in the last three years in order to construct, upgrade and maintain our rigs. For the nine-month periods ended September 30, 2012 and 2011 and the years ended December 31, 2011, 2010 and 2009, we recorded capital expenditures of $267.9 million, $679.1 million, $910.0 million, $608.8 million and $618.8 million, respectively, in connection with the construction and upgrading of our rigs.

 

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Except for our portion of the capital expenditures for the Sete Brasil rigs and the rigs ordered pursuant to a construction contract entered into with Samsung, our current projects are fully funded. We expect to finance our future capital expenditures for new projects through either project financing or issuances in the capital markets. The table below sets forth our expected capital expenditures for existing and future projects through 2015.

 

     2012(2)      2013      2014      2015      Total  
     (in millions of $)  

Existing Projects

     1,212         316         114         158         1,800   

Two ultra-deepwater drillships (1)

     115         281         449         395         1,240   

Expected New Projects

     —           409         671         959         2,039   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total (3)

     1,327         1,006         1,234         1,512         5,079   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) In connection with the letter of intent signed with Samsung for two ultra-deepwater drillships. On November 14, 2012, we exercised the option on one of these drillships. See “Business—Backlog and Drilling Contracts—Samsung Letter of Intent.”
(2) Includes expected capital expenditures for existing and future projects for the full year 2012.
(3) Includes pro rata portion of budgeted capital expenditures of $1,814 million for projects in which we have or expect to have a minority participation and in which we currently have a minority participation, including our participation in FPSOs under construction and in three ultra-deepwater rigs in strategic partnership with Sete Brasil. We expect to finance approximately 75% to 85% of this amount with debt. See “Business—Our Fleet and Investments—FPSOs.”

Contractual Obligations

The following table summarizes our significant contractual obligations and commitments as of December 31, 2011:

 

     Payments Due by Period  
     Less than One
Year
     One to Three
Years
     Three to Five
Years
     More than Five
Years