S-1 1 d715676ds1.htm FORM S-1 Form S-1
Table of Contents

As filed with the Securities and Exchange Commission on June 20, 2014

Registration Statement No. 333-            

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Transocean Partners LLC

(Exact name of registrant as specified in its charter)

 

Republic of the Marshall Islands   1381   66-0818288

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification No.)

Transocean Deepwater House

Kingswells Causeway

Prime Four Business Park

Aberdeen, AB15 8PU

Scotland

United Kingdom

+44 1224 654436

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

 

 

Jill S. Greene

Transocean Deepwater House

Kingswells Causeway

Prime Four Business Park

Aberdeen, AB15 8PU

Scotland

United Kingdom

+44 1224 654436

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

Copies to:

 

Gene J. Oshman

Joshua Davidson

Andrew J. Ericksen

Baker Botts L.L.P.

910 Louisiana

Houston, Texas 77002

(713) 229-1234

 

Catherine S. Gallagher

Adorys Velazquez

Vinson & Elkins L.L.P.

2200 Pennsylvania Avenue NW

Suite 500W

Washington, DC 20037

(202) 639-6500

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date 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.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   ¨      Accelerated filer   ¨
Non-accelerated filer   ¨   (Do not check if a smaller reporting company)    Smaller reporting 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 units representing limited partner interests

  $350,000,000   $45,080

 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

 

(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

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, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents

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 it is not soliciting an offer to buy these securities in any state or jurisdiction where the offer or sale is not permitted.

 

PROSPECTUS

Subject To Completion, dated June 20, 2014

LOGO

                     Common Units

Representing Limited Liability Company Interests

 

 

This is the initial public offering of Transocean Partners LLC. Transocean Partners Holdings Limited, or the selling unitholder, is offering              common units representing limited liability company interests in this offering. We will not receive any proceeds from the sale of common units by the selling unitholder. Prior to this offering, there has been no public market for our common units.

We are a Marshall Islands limited liability company formed by an affiliate of Transocean Ltd., or Transocean, a leading international provider of offshore contract drilling services for oil and gas wells. We will be treated as a corporation for U.S. federal income tax purposes. We intend to apply to list the common units on the New York Stock Exchange under the symbol “RIGP.” We are an “emerging growth company,” and we are eligible for reduced reporting requirements. See “Summary—Implications of Being an Emerging Growth Company.”

 

 

Investing in our common units involves a high degree of risk. Before buying any common units, you should carefully read the discussion of material risks of investing in our common units in “Risk Factors” beginning on page 19.

These risks include the following:

 

    We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay the minimum quarterly distribution on our units.

 

    We must make substantial capital and operating expenditures to maintain the operating capacity of our fleet, which will reduce cash available for distribution.

 

    Financing agreements containing operating and financial restrictions and other covenants may restrict our business and financing activities.

 

    We currently derive all of our revenues from two customers, and the loss of either of these customers or a dispute that leads to a loss of a customer could have a material adverse impact on our financial condition, results of operations and cash flows.

 

    Any limitation in the availability or operation of any of our three drilling rigs, or the inability to obtain new and favorable contracts for the drilling rigs upon any termination or expiration, could have a material adverse effect on us.

 

    We depend on affiliates of Transocean to assist us in operating and expanding our business.

 

    Unitholders have limited voting and other rights.

 

    Transocean and its affiliates own a controlling interest in us, have conflicts of interest and may favor their own interests to the detriment of us and our other common unitholders.

 

    You will experience immediate and substantial dilution of $             per common unit.

 

    A change in tax laws, treaties or regulations, or their interpretation, of any country in which we are resident or in which we have operations, or a loss of a major tax dispute or a successful tax challenge to our intercompany pricing policies in certain countries, could have a material adverse impact on our financial condition, results of operations and cash flows.

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.

 

 

      

Per
Common Unit

      

Total

 

Public offering price

       $                       $               

Underwriting discount(1)

       $                       $               

Proceeds to the selling unitholder (before expenses)

       $                       $               

 

(1) Excludes a structuring fee equal to 0.5% of the gross proceeds of this offering payable by the selling unitholder to Morgan Stanley & Co. LLC and Barclays Capital Inc. Please read “Underwriting.”

The selling unitholder has granted the underwriters a 30-day option to purchase up to an additional              common units on the same terms and conditions as set forth above if the underwriters sell more than              common units in this offering.

The underwriters expect to deliver the common units to purchasers on or about                     , 2014 through the book-entry facilities of The Depository Trust Company.

 

 

Morgan Stanley   Barclays

Prospectus dated                     , 2014


Table of Contents

[Cover art to be filed by amendment.]

 

 


Table of Contents

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we, the selling unitholder nor the underwriters have authorized anyone to provide you with additional or different information. If anyone provides you with different or inconsistent information, you should not rely on it. Neither we, the selling unitholder nor the underwriters are making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

 

 

TABLE OF CONTENTS

 

SUMMARY

     1   

Transocean Partners LLC

     1   

Our Relationship with Transocean

     3   

Business Strategies

     4   

Competitive Strengths

     5   

Risk Factors

     5   

Formation Transactions

     7   

Holding Company Structure

     7   

Organizational Structure After the Formation Transactions

     8   

Our Management

     9   

Principal Executive Offices and Internet Address

     9   

Summary of Conflicts of Interest and Duties

     9   

Implications of Being an Emerging Growth Company

     10   

The Offering

     11   

Summary Financial and Operating Data

     16   

Non-GAAP Measures

     17   

RISK FACTORS

     19   

Risks Inherent in Our Business

     19   

Risks Inherent in an Investment in Us

     39   

Tax Risks

     50   

FORWARD-LOOKING STATEMENTS

     53   

USE OF PROCEEDS

     55   

CAPITALIZATION

     56   

DILUTION

     57   

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

     58   

General

     58   

Our Minimum Quarterly Distribution

     60   

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015

     61   

Forecast Assumptions and Considerations

     67   

PROVISIONS OF OUR LIMITED LIABILITY COMPANY AGREEMENT RELATING TO CASH DISTRIBUTIONS

     73   

Distributions of Available Cash

     73   

Operating Surplus and Capital Surplus

     74   

Capital Expenditures

     76   

Subordination Period

     77   

Distributions of Available Cash From Operating Surplus During the Subordination Period

     79   

Distributions of Available Cash From Operating Surplus After the Subordination Period

     79   

Transocean Member Interest

     79   

Incentive Distribution Rights

     79   

Percentage Allocations of Available Cash From Operating Surplus

     80   

Distributions From Capital Surplus

     81   

 

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Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

     81   

Distributions of Cash Upon Liquidation

     82   

SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

     84   

Non-GAAP Measures

     86   

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

     87   

Business

     87   

Our Drilling Contracts

     88   

Performance and Other Key Indicators

     88   

Operating Results

     91   

Liquidity and Capital Resources

     96   

Off-Balance Sheet Arrangements

     99   

Critical Accounting Policies and Estimates

     99   

Contingencies

     103   

Quantitative and Qualitative Disclosures About Market Risk

     104   

INDUSTRY

     105   

Overview

     105   

Global Energy Demand

     107   

Oil Prices

     109   

Upstream Capital Expenditures

     110   

Exploration and Discoveries

     111   

Market Conditions in the Ultra-Deepwater Market

     114   

Supply and Demand for Deepwater Rigs

     115   

Dayrates

     116   

BUSINESS

     118   

Overview

     118   

Our Relationship with Transocean

     119   

Business Strategies

     120   

Competitive Strengths

     121   

Drilling Fleet

     122   

Contract Backlog

     124   

Drilling Contracts

     125   

Seasonality

     127   

Customers

     127   

Competition

     127   

Employees

     127   

Joint Venture, Agency and Sponsorship Relationships

     128   

Insurance

     128   

Environmental Regulation

     128   

Classification

     133   

Properties

     133   

Legal Proceedings

     133   

Taxation of the Company

     133   

MANAGEMENT

     135   

Management of Transocean Partners LLC

     135   

Committees of the Board of Directors

     136   

Board Leadership Structure

     136   

Board Role in Risk Oversight

     137   

The Transocean Member

     137   

Directors and Executive Officers

     137   

Reimbursement of Expenses

     138   

Executive Compensation

     138   

Compensation of Directors

     138   

Long-Term Incentive Plan

     139   

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     140   

SELLING UNITHOLDER

     142   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     143   

Distributions and Payments to the Transocean Member and Its Affiliates

     143   

Agreements Governing the Transactions

     144   

Procedures for Review, Approval and Ratification of Related Person Transactions

     152   

CONFLICTS OF INTEREST AND DUTIES

     153   

Conflicts of Interest

     153   

Duties

     157   

DESCRIPTION OF THE COMMON UNITS

     161   

The Units

     161   

Transfer Agent and Registrar

     161   

Transfer of Common Units

     161   

THE LIMITED LIABILITY COMPANY AGREEMENT

     163   

Organization and Duration

     163   

Purpose

     163   

Cash Distributions

     163   

Capital Contributions

     163   

Voting Rights

     163   

Applicable Law; Forum, Venue and Jurisdiction

     165   

Limited Liability

     166   

Issuance of Additional Interests

     167   

Tax Status

     167   

Amendment of the Limited Liability Company Agreement

     167   

Merger, Sale, Conversion or Other Disposition of Assets

     169   

Special Vote Required for Combinations with Interested Unitholders

     170   

Termination and Dissolution

     171   

Liquidation and Distribution of Proceeds

     171   

Withdrawal or Removal of the Transocean Member

     172   

Transfer of Transocean Member Interest

     173   

Transfer of Ownership Interests in the Transocean Member

     173   

Transfer of Incentive Distribution Rights

     173   

Change of Management Provisions

     174   

Limited Call Right

     174   

Board of Directors

     174   

Meetings; Voting

     176   

Status as Member

     176   

Indemnification

     176   

Reimbursement of Expenses

     177   

Books and Reports

     177   

Right to Inspect Our Books and Records

     177   

Registration Rights

     177   

UNITS ELIGIBLE FOR FUTURE SALE

     178   

Rule 144

     178   

Our Limited Liability Company Agreement and Registration Rights

     178   

Lock-Up Agreements

     179   

Registration Statement on Form S-8

     179   

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

     180   

Treatment as a Corporation

     180   

U.S. Holders

     180   

Non-U.S. Holders

     184   

Medicare Tax

     185   

Information Reporting Regarding Foreign Financial Assets

     185   

Backup Withholding and Information Reporting

     185   

 

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NON-UNITED STATES TAX CONSIDERATIONS

     187   

Marshall Islands Tax Consequences

     187   

United Kingdom Tax Consequences

     187   

UNDERWRITING

     189   

Pricing of the Offering

     192   

Directed Unit Program

     192   

Selling Restrictions

     192   

ENFORCEMENT OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS

     195   

LEGAL MATTERS

     195   

EXPERTS

     195   

WHERE YOU CAN FIND MORE INFORMATION

     196   

INDUSTRY AND MARKET DATA

     196   

INDEX TO FINANCIAL STATEMENTS

     F-1   

APPENDIX A—Form of First Amended and Restated Limited Liability Agreement of Transocean Partners LLC

     A-1   

APPENDIX B—Glossary

     B-1   

 

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SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. It does not contain all of the information that you should consider before investing in the common units. You should carefully read the entire prospectus, including “Risk Factors” and the historical and pro forma financial statements and accompanying notes included elsewhere in this prospectus, before investing in our common units. Unless we otherwise specify, all references to information and data in this prospectus about our business and fleet refer to our business and fleet immediately after the closing of this offering. Unless otherwise indicated, the information in this prospectus assumes (i) an initial public offering price of $         per unit (the midpoint of the price range set forth on the cover of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units. Unless otherwise indicated, all references to “dollars” and “$” in this prospectus are to, and amounts are presented in, U.S. Dollars.

All references in this prospectus to “Transocean Partners,” “we,” “our,” “us,” and “the company” refer to Transocean Partners LLC and its subsidiaries, including the RigCos, unless the context otherwise indicates. We will own a 51 percent interest and Transocean will own a 49 percent noncontrolling interest in each of the entities that own and operate Discoverer Inspiration, Discoverer Clear Leader and Development Driller III. Each of these drilling rigs will be owned by and operated by separate subsidiaries of ours. We refer to the rig-owning and rig-operating company for each drilling rig together as a “RigCo” and collectively for all of our drilling rigs as the “RigCos.” References in this prospectus to our fleet, refer to the drilling rigs in which we hold interests indirectly through the RigCos. Unless otherwise specifically noted, financial results and operating data are shown on a 100 percent basis and are not adjusted to reflect Transocean’s 49 percent noncontrolling interest in the RigCos.

References in this prospectus to “Transocean” refer, depending on the context, to Transocean Ltd. (NYSE: RIG, SIX: RIGN) and/or to any one or more of its direct and indirect subsidiaries, other than us. References in this prospectus to “Transocean Member” refer to the owner of the Transocean Member interest, initially Transocean Partners Holdings Limited, the selling unitholder in this offering and an indirect wholly owned subsidiary of Transocean Ltd. The Transocean Member interest is a non-economic interest in Transocean Partners that includes the right to appoint three members of our board of directors. References in this prospectus to “Chevron” and “BP” refer to the subsidiaries of Chevron Corporation and BP plc, respectively, that are our customers. We have provided definitions for some of the terms we use to describe our business and industry and other terms used in this prospectus in the “Glossary of Terms” beginning on page B-1 of this prospectus.

TRANSOCEAN PARTNERS LLC

We are a growth-oriented limited liability company recently formed by Transocean, one of the world’s largest offshore drilling contractors, to own, operate and acquire modern, technologically advanced offshore drilling rigs. Our initial assets consist of 51 percent interests in the RigCos that own and operate three ultra-deepwater drilling rigs that are currently operating in the U.S. Gulf of Mexico. Transocean owns the remaining 49 percent noncontrolling interest in each of the RigCos. We generate revenue through contract drilling services, which involves contracting our mobile offshore drilling fleet, related equipment and work crews on a dayrate basis to large international energy companies to drill oil and gas wells.

Our drilling rigs currently operate under long-term contracts with Chevron and BP, two leading international energy companies, with an average remaining contract term of approximately 4.2 years as of June 16, 2014. We believe that our drilling contracts will generate stable and reliable cash flows over their term. We intend to use the relationships and expertise of Transocean to re-contract our fleet when the existing contracts expire and identify opportunities to expand our fleet through acquisitions.

 

 

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The following table provides information about the rigs in our initial fleet:

 

    Our
Interest
    Year
Entered
Service
    Water
Depth

(feet)
    Drilling
Depth

(feet)
    Location   Current Contract Terms, Dayrates and Customers

Rig Name

            Start Date(1)   Completion
Date(1)
  Dayrate(2)     Customer

Drillships

                 

Discoverer Inspiration

    51     2010        12,000        40,000      USA
(Gulf of Mexico)
  March 2010

April 2015

  March 2015

April 2020

  $

$

526,000

585,000

  

  

  Chevron

Chevron

Discoverer Clear Leader

    51     2009        12,000        40,000      USA
(Gulf of Mexico)
  August 2009

September 2014

  September 2014

September 2018

  $

$

569,000

590,000

(3) 

  

  Chevron

Chevron

Semisubmersible

                 

Development Driller III

    51     2009        7,500        35,000      USA

(Gulf of Mexico)

  November 2009   November 2016   $ 428,000      BP

 

(1) Contract start and completion dates are estimated. Contracts could be longer in duration because of a provision that allows the customer to finish drilling a well-in-progress and due to other factors not under our control. New contracts do not commence until the prior contract has been completed.

 

(2) Represents the maximum contractual operating dayrate (which could change in the future due to cost escalations), but excludes amortization of drilling contract intangible revenues and certain cash and non-cash pre-operating revenues that terminate at the end of the rigs’ current contracts. For a description of amortizing revenues included in the dayrates presented in this table, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Performance and Other Key Indicators—Contract Backlog.”

 

     The average dayrate actually earned over the term of the contract will reflect various reduced rates received under the contract as a result of time billed according to standby rates, waiting-on-weather rates, maintenance rates or any other similar rates, which are typically less than the contract dayrate. In addition, the amount shown does not reflect incentive programs, which are typically based on the rig’s operating performance against a performance curve. For the three months ended March 31, 2014, average daily revenue was $533,200, $579,700 and $467,200 for Discoverer Inspiration, Discoverer Clear Leader and Development Driller III, respectively, and the revenue efficiency of the rigs in our initial fleet was 98 percent. For the year ended December 31, 2013, average daily revenue was $500,700, $450,500 and $416,100 for Discoverer Inspiration, Discoverer Clear Leader and Development Driller III, respectively, and the revenue efficiency of the rigs in our initial fleet was 86 percent. For additional information about average daily revenue earned and revenue efficiency in historical periods, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Performance and Other Key Indicators.”

 

(3) The dayrate for the remainder of the contract is linked to the standard West Texas Intermediate crude oil price with a floor of $40 per barrel resulting in a contract dayrate of $400,000 and a ceiling of $70 per barrel resulting in a contract dayrate of $500,000, before cost escalation adjustments of $50,000 per day and pre-operating revenues of $19,000 per day.

For the three months ended March 31, 2014, we had operating revenues of $148 million, net income of $63 million and Adjusted EBITDA of $72 million. For the year ended December 31, 2013, we had operating revenues of $526 million, net income of $189 million and Adjusted EBITDA of $221 million. Please read “—Non-GAAP Measures” and “Selected Historical Financial and Operating Data—Non-GAAP Measures” for the definition of the term Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income, the most directly comparable financial measure calculated and presented in accordance with U.S. generally accepted accounting principles, or U.S. GAAP.

 

 

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Our Relationship with Transocean

One of our principal strengths is our relationship with Transocean. Transocean is a leading international provider of offshore contract drilling services for oil and gas wells. As of June 16, 2014, Transocean owned or had partial ownership interests in and operated 77 mobile offshore drilling units, including our initial drilling rigs. As of June 16, 2014, Transocean’s fleet, including the rigs in our fleet, consisted of 46 high-specification floaters (ultra-deepwater, deepwater and harsh environment semisubmersibles and drillships), 21 midwater floaters and 10 high-specification jackups. At such date, Transocean also had nine ultra-deepwater drillships and five high-specification jackups under construction or under contract to be constructed.

We believe that our relationship with Transocean will provide us with access to leading international energy companies, as well as suppliers and other key service providers for our industry. We also believe that Transocean’s operational and managerial expertise will enable us to compete more effectively for contract opportunities than other contract drilling companies similar in size to us.

Under an omnibus agreement to be entered into at the closing of this offering, Transocean will grant us a right of first offer for its remaining ownership interests in each of the RigCos should Transocean decide to sell such interests. Transocean also will be required to offer us the opportunity to purchase not less than a 51 percent interest in four of the six drillships listed below within the five years following the closing of this offering at a purchase price equal to the greater of the fair market value (taking into account the anticipated cash flows under the associated drilling contracts) or the all-in construction cost, plus transaction costs. Transocean will select which of these rigs it will offer to us, the timing of the offers and whether it will offer us the opportunity to purchase a greater than 51 percent interest in any offered rig.

 

    Expected
Construction
Completion
  Water
Depth

(feet)
    Drilling
Depth

(feet)
    Location   Current Contract Term, Dayrate and Customers

Rig Name

          Start Date(1)   Completion
Date(1)
  Dayrate(2)     Customer

Deepwater Invictus

  Q2 2014     12,000        40,000      USA

(Gulf of Mexico)

  Q3 2014   Q2 2017   $ 595,000      BHP Billiton

Deepwater Thalassa

  Q1 2016     12,000        40,000      TBA   Q1 2016   Q4 2025   $ 519,000      Shell

Deepwater Proteus

  Q2 2016     12,000        40,000      TBA   Q2 2016   Q2 2026   $ 519,000      Shell

Deepwater Pontus

  Q1 2017     12,000        40,000      TBA   Q1 2017   Q4 2026   $ 519,000      Shell

Deepwater Poseidon

  Q2 2017     12,000        40,000      TBA   Q2 2017   Q2 2027   $ 519,000      Shell

Deepwater Conqueror

  Q4 2016     12,000        40,000      USA
(Gulf of Mexico)
  Q4 2016   Q4 2021   $ 599,000      Chevron

 

(1) Contract start and completion dates are estimated. Contract start dates depend on delivery by shipyards, testing and customer acceptance. Contracts could be longer in duration because of a provision that allows the customer to finish drilling a well-in-progress and due to other factors not under our control.

 

(2) Represents the maximum contractual operating dayrate. The average dayrate actually earned over the term of the contract will reflect various reduced rates received under the contract as a result of time billed according to standby rates, waiting-on-weather rates, maintenance rates or any other similar rates, which typically are less than the contract dayrate. In addition, the amount shown does not reflect incentive programs, which are typically based on the rig’s operating performance against a performance curve. Each of these drilling rigs is currently under construction and, therefore, has no operating history.

In addition, subject to specified exceptions, Transocean will be required to offer us the opportunity to purchase any drilling rigs that Transocean acquires or contracts to build after the closing date of this offering that are subject to a drilling contract with a remaining term of five years or longer, and any existing drilling rigs in its fleet that entered into service in 2009 or later and are placed under an extension or a new drilling contract with a term of five years or longer. In addition, we generally will agree not to acquire, own, operate or contract for

 

 

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certain drilling rigs operating under drilling contracts of less than five years. Relatively few drilling contracts have a term of five years or greater, particularly in the case of contracts that are not associated with newbuild units. As a result, we expect that Transocean will effectively have a right of first refusal on most drilling contract opportunities. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement.”

The consummation and timing of any acquisitions from Transocean will depend upon, among other things, our ability to obtain any necessary consents, the determination that the acquisition is appropriate for our business at that particular time, our ability to agree on mutually acceptable terms of purchase, including price, and our ability to obtain financing on acceptable terms.

Following this offering, Transocean will retain a significant interest in us through its ownership of common and subordinated units, representing an aggregate          percent limited liability company interest in us, and all of our incentive distribution rights. We believe that Transocean is motivated to facilitate the growth of our distributions per unit, including through future contribution or sales to us of additional rigs and its remaining interests in each of the RigCos. In addition to the drillships discussed above, Transocean has a number of newer rigs that are operating under long-term drilling contracts and rigs under construction. Although Transocean is not obligated to offer these rigs to us, we believe that these rigs would be particularly suitable for future contribution or sale to us.

Business Strategies

Our primary business objectives are to operate and maintain our fleet to generate stable cash flows and increase our quarterly cash distributions per unit over time. We intend to accomplish these objectives by executing the following business strategies:

 

    Grow through strategic acquisitions. We intend to pursue strategic opportunities to grow our company and fleet through acquisitions from Transocean or third parties that will enable us to increase our quarterly distributions per unit. Pursuant to the omnibus agreement, Transocean will be required, under certain circumstances, to offer us the opportunity to purchase its remaining interests in one or more of the RigCos, as well as certain drilling rigs (including a majority ownership interest in four of the ultra-deepwater drillships that are currently under construction and are supported by long-term contracts).

 

    Pursue assets with contracts that help maintain stable cash flows. We are focused on generating and maintaining stable cash flows by pursuing drilling rigs operated under long-term contracts with creditworthy counterparties. We believe that employing our rigs under long-term contracts will improve the stability and predictability of our cash flows and should also contribute to our growth strategy by facilitating our access to debt and equity financing. We also believe that our relationship with Transocean will enhance our ability to compete for contract opportunities.

 

    Conduct safe, efficient and reliable operations. We participate in Transocean’s programs designed to maintain and improve the safety, reliability and efficiency of all our operations, which are vital to our ability to retain and attract our customers. We believe that our relationship with Transocean and our relatively young and high-specification fleet will enable us to operate safely, efficiently and cost effectively. We expect that these factors will enhance our ability to secure additional long-term contracts and extend existing contracts, enabling us to maintain high asset utilization.

 

    Maintain a modern and reliable fleet. We have one of the most capable and technologically advanced fleets in the industry. We plan to invest both in growing our modern and reliable fleet and in continually maintaining the quality and operational integrity of our assets. We believe that investing in high-quality assets with proven and reliable drilling rig technology is an important component in our strategy to provide our customers with safe and reliable operations and services.

 

 

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Competitive Strengths

We believe we are well positioned to execute our business strategies based on the following competitive strengths:

 

    Relationship with Transocean provides industry expertise and facilitates our growth strategy. Transocean specializes in operations in technically demanding regions of the global offshore drilling industry with a particular focus on ultra-deepwater and harsh environment drilling services. Transocean believes its mobile offshore drilling fleet is one of the most versatile fleets in the world, consisting of drillships, semisubmersibles and high-specification jackups used in support of offshore drilling activities and offshore support services on a worldwide basis. We believe that our relationship with Transocean will facilitate our acquisition and growth strategy, provide access to premier customers and suppliers and allow us to capitalize on Transocean’s operational expertise. In addition, we believe that our relationship with Transocean will assist us in securing new contracts for our rigs as we complete our current contracts. We believe Transocean’s history as an efficient and reliable contractor and its operational and management expertise will enhance our ability to obtain new long-term contracts.

 

    Long-term contracts with high-quality customers promote stable cash flows. All of our revenues and associated cash flows are derived from our existing long-term contracts. Our rigs are contracted to high-quality, creditworthy customers for an average remaining contract term of approximately 4.2 years as of June 16, 2014. Our drilling contracts provide for payment on a fixed-dayrate basis for the applicable contract term. We believe these agreements will enhance cash flow dependability and predictability, providing us with the financial stability we need to make cash distributions and obtain financing for future growth.

 

    High-quality, well-maintained, modern and young fleet provides strong operational results. We believe that we have one of the most capable, technologically advanced and efficient fleets in the offshore drilling industry and that we can become a preferred provider of offshore drilling services. Our fleet is comprised of technologically advanced drilling rigs designed to operate in ultra-deepwater environments, as well as in deepwater and midwater environments. All of our rigs were placed into service in 2009 or 2010, with an average age of approximately 4.4 years as of June 16, 2014. In general, customers prefer newer, more technologically advanced rigs. Accordingly, we expect to have relatively low maintenance and replacement capital expenditures, high utilization rates and efficient and reliable operations.

 

    Financial flexibility to execute growth strategy. Upon the closing of this offering, we expect to have an undrawn committed $300 million revolving credit facility with an affiliate of Transocean that allows for uncommitted increases in amounts to be agreed upon by Transocean and us. We expect that our borrowing capacity under this credit facility as well as access to the capital markets and other financing sources will be conducive to the execution of our acquisition strategy and enable us to pursue other expansion opportunities.

 

    Experienced leadership team. Our management team has an average of          years of experience in the energy industry. Our management team has established strong relationships with customers, suppliers and other industry participants, which we believe will be beneficial to us in pursuing our business strategies.

Risk Factors

An investment in our common units involves risks associated with our business, our limited liability company structure and the tax characteristics of our common units, including the risks described below. You should carefully consider these risks and the other risks described in “Risk Factors” beginning on page 19 and the other information in this prospectus before investing in our common units.

 

 

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Risks Inherent in Our Business

 

    We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay the minimum quarterly distribution on our common units and subordinated units.

 

    The assumptions underlying our forecast of cash available for distribution are inherently uncertain and subject to risks and uncertainties that could cause actual results to differ materially from those forecasted.

 

    We must make substantial capital and operating expenditures to maintain the operating capacity of our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness and to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to execute our growth plan, each of which could negatively affect our financial condition, results of operations and cash flows and reduce cash available for distribution.

 

    We currently derive all of our revenues from two customers, and the loss of either of these customers or a dispute that leads to a loss of a customer could have a material adverse impact on our financial condition, results of operations and cash flows.

 

    Any limitation in the availability or operation of any of our three drilling rigs could have a material adverse effect on our business, results of operations and financial condition and could significantly reduce our ability to make distributions to our unitholders.

 

    Our revenues will initially be derived from assets that are operating in the U.S. Gulf of Mexico, making us vulnerable to risks associated with operating in that single geographic area.

 

    We may be unable to renew or obtain new and favorable drilling contracts for rigs whose contracts are expiring or are terminated, which could adversely affect our revenues and profitability.

Risks Inherent in an Investment in Us

 

    Transocean and its affiliates may compete with us, and we are limited in our ability to compete with Transocean. In addition, we generally will agree not to acquire, own operate or contract for certain drilling rigs operating under drilling contracts of less than five years. Relatively few drilling contracts have a term of five years or greater, particularly in the case of contracts that are not associated with newbuild units. As a result, we expect that Transocean will effectively have a right of first refusal on most drilling contract opportunities.

 

    The Transocean Member and its other affiliates own a controlling interest in us and have conflicts of interest and limited duties to us and our common unitholders, and the Transocean Member and its other affiliates may favor their own interests to the detriment of us and our other common unitholders.

 

    Our limited liability company agreement limits the duties that the Transocean Member and our directors and officers may have to our unitholders and restricts the remedies available to unitholders for actions taken by the Transocean Member or our directors and officers.

 

    Holders of our common units have limited voting rights.

 

    There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment in us.

Tax Risks

 

    A change in tax laws, treaties or regulations, or their interpretation, of any country in which we have operations, are incorporated or are resident could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.

 

 

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    A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, reducing our cash available for distribution to you.

Formation Transactions

We were formed on February 6, 2014 as a Marshall Islands limited liability company to own and operate a fleet of offshore drilling rigs.

At or prior to the closing of this offering, the following transactions will occur:

 

    subsidiaries of Transocean that own Discoverer Inspiration, Discoverer Clear Leader and Development Driller III will sell each of these rigs to the Transocean Member in exchange for cash and/or a note;

 

    the Transocean Member will contribute each of Discoverer Inspiration, Discoverer Clear Leader and Development Driller III to its wholly owned holding company subsidiaries, which will further contribute each rig to the respective rig-owning company for that rig, each of which is an indirect wholly owned subsidiary of the Transocean Member;

 

    a subsidiary of Transocean will sell to holding company subsidiaries of the Transocean Member a 100 percent ownership interest in the respective rig-operating companies that operate and hold the drilling contracts for Discoverer Inspiration, Discoverer Clear Leader and Development Driller III in exchange for cash and/or a note;

 

    the Transocean Member will contribute or sell to us a 51 percent ownership interest in each of the holding companies that own the RigCos;

 

    we will issue (a) to the Transocean Member (i)         common units and         subordinated units, representing a 60 percent and a 40 percent limited liability company interest in us, (ii) the non-economic Transocean Member interest, and (iii) all of the incentive distribution rights, which entitle the Transocean Member to increasing percentages of the cash that we distribute in excess of $         per unit per quarter, and (b) to an affiliate of Transocean notes payable of approximately $         million for cash proceeds of $         million and initial working capital;

 

    the Transocean Member will sell         common units to the public, representing a         percent limited liability company interest in us; and

 

    the Transocean Member will grant the underwriters a 30-day option to purchase up to an additional         common units on the same terms and conditions as the         common units sold to the public;

 

    we will enter into the omnibus agreement with Transocean and the Transocean Member;

 

    we will enter into master services agreements with Transocean;

 

    we will enter into support and secondment agreements with Transocean; and

 

    we will enter into a $300 million five-year revolving credit facility, or the Five-Year Revolving Credit Facility, with an affiliate of Transocean.

Holding Company Structure

We are a holding company and will conduct our operations and business through subsidiaries, as is common for publicly traded limited liability companies. Initially, we will conduct all of our operations through the

RigCos. We will own and operate each of the drilling rigs in our initial fleet through separate RigCos. This ownership structure provides us the flexibility to purchase additional interests in individual drilling rigs rather than interests in our entire fleet, if we believe that is the appropriate way to grow our business.

 

 

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Organizational Structure After the Formation Transactions

The following diagram depicts our simplified organizational and ownership structure after giving effect to the offering and related transactions described above.

 

     Number of Units    Percentage Ownership  

Public common units

            

Transocean common units

            

Transocean subordinated units

        40.0
  

 

  

 

 

 

Total

        100.0
  

 

  

 

 

 

 

LOGO

 

 

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Our Management

Our limited liability company agreement provides that our board of directors has authority to oversee and direct our operations, management and policies on an exclusive basis. Our executive officers will manage our day-to-day activities consistent with the policies and procedures adopted by our board of directors. We currently do not employ any of our executive officers and rely on Transocean to provide us with personnel who will perform executive officer services for our benefit pursuant to agreements with Transocean and who will be responsible for our day-to-day management subject to the direction of our board of directors. All references in this prospectus to “our officers” include those personnel of Transocean or its affiliates who perform executive officer functions for our benefit.

We will reimburse Transocean and its affiliates for their reasonable costs and expenses incurred in connection with providing management, administrative, financial and other support services to us. In addition, we will pay Transocean a services fee for providing these services to us. We expect that we will pay approximately $         million in total under the master services agreements and the support or secondment agreements for the twelve months ending September 30, 2015. There is no cap on the amount of fees and cost reimbursements that we may be required to pay pursuant to these agreements. For a more detailed description of these agreements, please read “Management—Directors and Executive Officers” and “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions.”

Principal Executive Offices and Internet Address

Our registered and principal executive offices are located at Transocean Deepwater House, Kingswells Causeway, Prime Four Business Park, Aberdeen, AB15 8PU, Scotland, United Kingdom, and our phone number is                         . Following the completion of this offering, our website will be located at www.            .com. We expect to make our periodic reports and other information filed with or furnished to the U.S. Securities and Exchange Commission, or the SEC, available, free of charge, through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Duties

Our directors have a legal duty to manage us in a manner beneficial to us, subject to the limitations described under “Conflicts of Interest and Duties.” However, several of our directors and all of our officers hold positions with Transocean or its affiliates, resulting in those persons owing legal duties to those entities. As a result of these relationships, conflicts of interest may arise between us and our unaffiliated members on the one hand, and Transocean and its affiliates, including the Transocean Member, on the other hand. The resolution of these conflicts may not be in the best interest of us or our unitholders. In particular:

 

    all of our current executive officers and directors also serve as executive officers or directors of Transocean or its affiliates;

 

    Transocean and its other affiliates may compete with us, subject to the restrictions contained in the omnibus agreement;

 

    we will be restricted in our ability to compete with Transocean, subject to the exceptions contained in the omnibus agreement; and

 

    we have entered into arrangements, and may enter into additional arrangements, with Transocean and certain of its subsidiaries, relating to the purchase of interests in drilling rigs, the provision of certain services to us by Transocean and other matters. In the performance of their obligations under these agreements, Transocean and its subsidiaries are generally held to the standard of care specified in these agreements.

 

 

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For a more detailed description of our management structure, please read “Management—Directors and Executive Officers” and “Certain Relationships and Related Party Transactions.”

Although a majority of our directors will over time be elected by common unitholders, Transocean will likely have substantial influence on decisions made by our board of directors due to its ability to appoint certain of our directors and its significant ownership of our units. Our board of directors will have a conflicts committee composed of independent directors. Our board may, but is not obligated to, seek approval of the conflicts committee for resolutions of conflicts of interest that may arise as a result of the relationships between the Transocean Member and its affiliates, on the one hand, and us and our unaffiliated members, on the other.

For a more detailed description of the conflicts of interest and duties of our directors and officers, please read “Conflicts of Interest and Duties.” For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

Implications of Being an Emerging Growth Company

As a company with less than $1 billion in revenues during our last fiscal year, we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act. As an emerging growth company, we may, for up to five years, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies. These exemptions include:

 

    the presentation of only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in the registration statement of an initial public offering of common equity securities;

 

    exemption from the auditor attestation requirement on the effectiveness of our system of internal controls over financial reporting;

 

    delayed adoption of new or revised financial accounting standards; and

 

    reduced disclosure about our executive compensation arrangements.

We may take advantage of these provisions until we are no longer an emerging growth company, which will occur on the earliest of (1) the last day of the fiscal year following the fifth anniversary of this offering, (2) the last day of the fiscal year in which we have more than $1 billion in annual revenues, (3) last day of the fiscal year in which we have more than $700 million in market value of our common units held by non-affiliates as of the end of our fiscal second quarter or (4) the date on which we issue more than $1 billion of non-convertible debt over a three-year period.

We have elected to take advantage of all of the applicable JOBS Act provisions, including the exemption that allows emerging growth companies to extend the transition period for complying with new or revised financial accounting standards. This election to take advantage of the extended transition period for complying with new or revised financial accounting standards is irrevocable. Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

 

 

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THE OFFERING

 

Common units offered to the public by the selling unitholder

  


             common units.

 

             common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering

                common units and              subordinated units, representing a 60 percent and 40 percent limited liability company interest in us, respectively.

Use of proceeds

   We will not receive any proceeds from the sale of common units by the selling unitholder in this offering. See “Use of Proceeds.”

Cash distributions

  

We intend to make minimum quarterly distributions of $         per common unit ($         per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to Transocean. We refer to this cash as “available cash,” and we define its meaning in our limited liability company agreement and in the glossary of terms attached as Appendix B.

 

We will adjust the minimum quarterly distribution for the period from the closing of the offering through                     , 2014 based on the actual length of the period.

 

In general, we will pay any cash distributions we make each quarter in the following manner:

 

•     first, to the holders of common units, pro rata, until each common unit has received a minimum quarterly distribution of $         plus any arrearages from prior quarters;

 

•     second, to the holders of subordinated units, pro rata, until each subordinated unit has received a minimum quarterly distribution of $         ; and

 

•     third, to all unitholders, pro rata, until each unit has received an aggregate distribution of $         .

 

Within 60 days after the end of each fiscal quarter (beginning with the quarter ending                     , 2014), we will distribute all of our available cash to unitholders of record on the applicable record date. Our ability to pay our minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

 

 

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If cash distributions to our unitholders exceed $         per unit in a quarter, holders of our incentive distribution rights (initially, the Transocean Member)

will receive increasing percentages, up to 50 percent, of the cash we distribute in excess of that amount; provided that for any fiscal quarter in which the application of our distribution formula would result in the holders of the common units receiving, in the aggregate, less than a majority of the aggregate distribution of available cash for such quarter, then the distribution to the holders of the incentive distribution rights will be reduced, pro rata, to the extent necessary to cause the aggregate distribution to the holders of the common units to represent a majority of the aggregate distribution of available cash for such quarter. We refer to these distributions as “incentive distributions.” The amount of available cash may be greater than or less than the aggregate amount of the minimum quarterly distribution to be distributed on all units.

 

We believe, based on the estimates contained in and the assumptions listed under “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015,” that we will have sufficient cash available for distribution to enable us to pay the minimum quarterly distribution of $         on all of our common and subordinated units for the twelve months ending September 30, 2015. However, unanticipated events may occur which could adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast, and such variations may be material.

Subordinated units

   Transocean will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period the subordinated units are entitled to receive the minimum quarterly distribution of $         per unit only after the common units have received the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

 

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Conversion of subordinated units

  

The subordination period generally will end if we have earned and paid at least $         (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit for any three consecutive, non-overlapping four-quarter periods ending on or after                     , 2019, provided there are no arrearages on our common units at that time.

 

The subordination period also will end upon the removal of the Transocean Member other than for cause if no subordinated units or common units held by the Transocean Member or its affiliates are voted in favor of that removal.

 

When the subordination period ends as provided above, all subordinated units will convert into common units on a one-for-one basis, and all common units will no longer be entitled to arrearages.

 

Please read “Provisions of Our Limited Liability Company Agreement Relating to Cash Distributions—Subordination Period.”

Issuance of additional units

   We can issue an unlimited number of additional units, including units that are senior to the common units in rights of distribution, liquidation and voting, on the terms and conditions determined by our board of directors, without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Limited Liability Company Agreement—Issuance of Additional Interests.”

Board of directors

   We will hold a meeting of the members every year to elect one or more members of our board of directors and to vote on any other matters that are properly brought before the meeting. Prior to the closing of this offering, the Transocean Member, in its capacity as the initial holder of the common units, will elect three of the seven members of our board of directors who will serve as initial directors, and such elected directors may elect an additional elected director. Prior to the 2015 annual meeting, the Transocean Member may also appoint additional directors to fill the appointed director positions, provided that the number of elected directors must, immediately after such appointment, exceed the number of appointed directors. At our 2015 annual meeting, the common unitholders will elect four of our directors. The four directors elected by our common unitholders at our 2015 annual meeting initially will serve for one-year terms. Upon the election by the Transocean Member to classify our board of directors, the four directors

 

 

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   elected by our common unitholders will be divided into three classes to be elected by our common unitholders on a staggered basis to serve for three-year terms. Transocean may vote any common units held by it in the election of directors; however, subordinated units will not be voted in the election of directors. Our governance documents require that, at all times, at least a majority of the members of our board of directors be United Kingdom (“U.K.”) tax residents.

Voting rights

  

Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders.

 

You will have no right to elect the Transocean Member on an annual or other continuing basis. The Transocean Member may not be removed except by a vote of the holders of at least 66 23 percent of the outstanding units, including any units owned by the Transocean Member and its affiliates, voting together as a single class. Upon consummation of this offering, Transocean will own          of our common units and all of our subordinated units, representing a          percent limited liability company interest in us. If the underwriters’ option to purchase additional common units is exercised in full, Transocean will own          of our common units and all of our subordinated units, representing a          percent limited liability company interest in us. As a result, you will initially be unable to remove the Transocean Member without Transocean’s consent because Transocean will own sufficient units upon completion of this offering to be able to prevent the Transocean Member’s removal. Please read “The Limited Liability Agreement—Voting Rights.”

Limited call right

   If at any time the Transocean Member and its affiliates own more than 80 percent of the outstanding common units, the Transocean Member has the right, but not the obligation, to purchase all, but not less than all, of the remaining common units at a price equal to the greater of (x) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before the notice of exercise of the call right is first mailed and (y) the highest price paid by the Transocean Member or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. The Transocean Member may assign this right to its affiliates, including us. The Transocean Member is not obligated to obtain a fairness opinion, nor will the unitholders be entitled to dissenter’s rights of appraisal, regarding the value of the common units to be repurchased by the Transocean Member upon the exercise of this limited call right.

 

 

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U.S. federal income tax considerations

   We are organized as a limited liability company that is treated as a corporation for U.S. federal income tax purposes. Consequently, distributions you receive from us will constitute dividends to the extent of our current-year or accumulated earnings and profits (as computed for U.S. federal income tax purposes). The remaining portion of such distributions will be treated first as a non-taxable return of capital to the extent of your tax basis in your common units and thereafter as capital gain. We estimate that if you hold the common units that you purchase in this offering through the period ending December 31, 2016, the distributions you receive, on a cumulative basis, that will constitute dividends for U.S. federal income tax purposes will be less than          percent of the total cash distributions received during that period. Please read “Material U.S. Federal Income Tax Considerations—U.S. Holders—Ratio of Dividend Income to Distributions” for the basis for this estimate. For a discussion of other material U.S. federal income tax consequences that may be relevant to prospective unitholders, please read “Material U.S. Federal Income Tax Considerations.”

Non-U.S. tax considerations

   For a discussion of the material Marshall Islands and U.K. tax consequences that may be relevant to prospective unitholders, please read “Non-United States Tax Considerations.”

Directed unit program

   At our request, the underwriters have reserved for sale, at the initial public offering price, up to          percent of the common units offered hereby for our directors, officers, employees and certain other persons associated with us. The number of common units available for sale to the general public will be reduced to the extent such persons purchase such reserved common units. Any reserved common units which are not so purchased will be offered by the underwriters to the general public on the same terms as the other common units offered hereby. Please read “Underwriting—Directed Unit Program.”

Exchange listing

   We intend to apply to list the common units on the New York Stock Exchange under the symbol “RIGP.”

 

 

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SUMMARY FINANCIAL AND OPERATING DATA

The following table presents, in each case for the periods and as of the dates indicated, summary historical financial and operating data of Transocean Partners LLC Predecessor, which includes the operating results, assets and liabilities of the drilling rigs in our initial fleet. The summary historical financial data of Transocean Partners LLC Predecessor as of and for the years ended December 31, 2013 and 2012 are derived from the audited combined financial statements of Transocean Partners LLC Predecessor, prepared in accordance with U.S. GAAP, which are included elsewhere in this prospectus. The summary historical financial data of Transocean Partners LLC Predecessor as of March 31, 2014 and for the three months ended March 31, 2014 and 2013 are derived from the unaudited condensed combined financial statements of Transocean Partners LLC Predecessor, prepared in accordance with U.S. GAAP, which are included elsewhere in this prospectus.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of Transocean Partners LLC Predecessor and the notes thereto, our unaudited pro forma combined balance sheet and the notes thereto and our forecasted results of operations for the twelve months ending September 30, 2015, in each case included elsewhere in this prospectus.

Our financial position, results of operations and cash flows could differ from those that would have resulted if we operated autonomously or as an entity independent of Transocean in the periods for which historical financial data are presented below, and such data may not be indicative of our future operating results or financial performance.

 

     Three months ended
March 31,
    Years ended
December 31,
 
     2014     2013     2013     2012  
     (In millions, except fleet data)  

Statement of operations data

      

Operating revenues

   $ 148      $ 116      $ 526      $ 569   

Costs and expenses

     79        76        318        293   

Operating income

     69        40        208        276   

Interest income

                   4        3   

Income before income tax expense

     69        40        212        279   

Income tax expense

     6        4        23        24   

Net income

     63        36        189        255   

Balance sheet data (at end of period)

      

Cash and cash equivalents

   $      $      $      $   

Property and equipment, net

     2,005        2,082        2,038        2,098   

Total assets

     2,432        2,506        2,468        2,557   

Total long-term liabilities

     78        117        87        131   

Total net investment

     2,320        2,351        2,344        2,388   

Cash flow data

      

Cash provided by operating activities

   $ 70      $ 73      $ 239      $ 340   

Cash used in investing activities(1)

     (1            (4     (15

Cash used in financing activities

     (69     (73     (235     (325

Fleet data

      

Number of rigs

     3        3        3        3   

Average age of fleet at end of period (in years)

     4.3        3.3        4.1        3.1   

Operating days(2)

     270        270        1,095        1,098   

Average daily revenue(3)

   $ 526,700      $ 403,900      $ 455,800      $ 491,500   

Revenue efficiency(4)

     98     77     86     97

Rig utilization(5)

     100     100     100     99

Other financial data

      

EBITDA(6)

   $ 85      $ 56      $ 274      $ 341   

Adjusted EBITDA(6)

     72        43        221        287   

 

 

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(1) Represents cash used to fund capital expenditures.

 

(2) An operating day is defined as a calendar day during which a rig is contracted to earn a dayrate during the firm contract period after commencement of operations.

 

(3) Average daily revenue is defined as contract drilling revenues earned per operating day. Our average daily revenue fluctuates relative to market conditions and our revenue efficiency. Average daily revenues increased in the three months ended March 31, 2014 relative to the three months ended March 31, 2013 due to an increase in revenue efficiency resulting from lower unplanned downtime and an increase in operating dayrates associated with cost escalation adjustments that reflect increases in our operating costs. Average daily revenues decreased in the year ended December 31, 2013 relative to the year ended December 31, 2012 due to a decrease in revenue efficiency resulting from unplanned downtime. This decrease was slightly offset by an increase in operating dayrates associated with cost escalation adjustments that reflect increases in our operating costs.

 

(4) Revenue efficiency is defined as actual contract drilling revenues for the measurement period divided by the maximum revenue calculated for the measurement period, expressed as a percentage. Maximum revenue is defined as the greatest amount of contract drilling revenues the drilling unit could earn for the measurement period, excluding amounts related to incentive provisions. Our revenue efficiency rate varies due to revenues earned under alternative contractual dayrates, such as a waiting-on-weather rate, repair rate, standby rate, force majeure rate or zero rate, that may apply under certain circumstances. Revenue efficiency increased in the three months ended March 31, 2014 relative to the three months ended March 31, 2013 resulting from lower unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment. Revenue efficiency was lower in the year ended December 31, 2013 relative to the year ended December 31, 2012 due to unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment.

 

(5) Rig utilization is defined as the total number of operating days divided by the total number of rig calendar days in the measurement period, expressed as a percentage. Our rig utilization rate declines as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.

 

(6) Please read “—Non-GAAP Measures” described below for a description and a reconciliation of EBITDA and Adjusted EBITDA to net income, the most directly comparable U.S. GAAP measure.

Non-GAAP Measures

We present our operating results in accordance with U.S. GAAP. We believe that certain financial measures which are not in conformity with U.S. GAAP, or non-GAAP measures, provide users of our financial statements with additional useful information in evaluating our operating performance. We define EBITDA as earnings before interest expense net of interest income, taxes, depreciation and amortization and Adjusted EBITDA as EBITDA adjusted for amortization of prior certification costs and license fees, non-cash recognition of royalty fees, amortization of the drilling contract intangible and amortization of pre-operating revenues. EBITDA and Adjusted EBITDA are used as supplemental financial measures by which management and external users of our financial statements, such as investors and commercial banks, can assess:

 

    our performance from period to period and against the performance of other companies in our industry, without regard to financing methods, historical cost basis or capital structure;

 

    the ability of our assets to generate sufficient cash flow to make distributions to our members;

 

    our ability to incur and service debt and fund capital expenditures; and

 

    the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

 

 

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We believe that the presentation of EBITDA and Adjusted EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The U.S. GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with U.S. GAAP. EBITDA and Adjusted EBITDA excludes some, but not all, items that affect net income and these measures may vary among other companies. Therefore, EBITDA and Adjusted EBITDA, as presented above, may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of net income, the most directly comparable U.S. GAAP financial measure, to EBITDA and Adjusted EBITDA for each of the periods indicated.

 

     Three months ended
March 31,
     Years ended
December 31,
 
         2014              2013              2013             2012      
    

(In millions)

 

Net income

   $ 63       $ 36       $ 189      $ 255   

Plus:

          

Income tax expense

     6         4         23        24   

Interest income(1)

                     (4     (3

Depreciation expense

     16         16         66        65   
  

 

 

    

 

 

    

 

 

   

 

 

 

EBITDA

     85         56         274        341   

Plus:

          

Amortization of prior certification costs and license fees

     1         1         3        3   

Non-cash recognition of royalty fees(2)

                              

Less:

          

Amortization of drilling contract intangible

     4         4         18        19   

Amortization of pre-operating revenues

     10         10         38        38   
  

 

 

    

 

 

    

 

 

   

 

 

 

Adjusted EBITDA

   $ 72       $ 43       $ 221      $ 287   
  

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) Includes interest earned on long-term accounts receivable from our customers. We record long-term accounts receivable at their present value and recognize interest income on the outstanding balance using the effective interest method through the dates of payment.

 

(2) Following this offering, the Transocean Member will retain the obligation for the payment of quarterly patent fees through the patent expiration, and we will recognize a non-cash expense for the fees paid on our behalf.

 

 

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RISK FACTORS

Common units are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition, results of operations and cash flows could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment in us.

Risks Inherent in Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay the minimum quarterly distribution on our common units and subordinated units.

We may not have sufficient cash from operations to pay the minimum quarterly distribution of $         per unit, or $         per unit on an annualized basis, on our common units and subordinated units, which will require us to have available cash of approximately $         million per quarter, or $         million per year, based on the number of common and subordinated units to be outstanding after the completion of this offering. We may not have sufficient available cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which may fluctuate from quarter to quarter based on the risks described in this section, including, among other things:

 

    our ability to re-contract our drilling rigs in their current configuration upon expiration or termination of an existing drilling contract and the dayrates we obtain under such contracts;

 

    the dayrates we obtain under our drilling contracts;

 

    the level of reimbursable revenues and expenses;

 

    the level of our rig operating costs, such as the cost of crews, repairs, maintenance and insurance;

 

    the effect of governmental regulations and maritime self-regulatory organization standards on the conduct of our business;

 

    rig downtime or less than full utilization, which would result in a reduction of revenues under our drilling contracts;

 

    changes in local income tax rates, tax treaties and tax laws;

 

    the timeliness of payments from customers under drilling contracts;

 

    time spent mobilizing drilling rigs to the customer location;

 

    resolution of tax assessments;

 

    currency exchange rate fluctuations and currency controls; and

 

    prevailing global economic and market conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

 

    the level and timing of capital expenditures we make;

 

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    the level of our operating, maintenance and rig and shore-based general and administrative expenses, including reimbursements to the Transocean Member and its affiliates for services provided to us and additional expenses we will incur as a result of being a public company;

 

    our debt service requirements and other liabilities;

 

    fluctuations in our working capital needs;

 

    the cost of acquisitions, if any;

 

    our ability to borrow funds and access capital markets;

 

    restrictions on distributions contained in our debt agreements; and

 

    the amount of cash reserves, including reserves for future maintenance and replacement capital expenditures, working capital and other matters, established by our board of directors.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying our forecast of cash available for distribution are inherently uncertain and are subject to risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecast of operating results and cash flows for the twelve months ending September 30, 2015. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct, which are discussed in “Our Cash Distribution Policy and Restrictions on Distributions.”

Our financial forecast has been prepared by management, and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and operational risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may be unable to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow rather than on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Our ability to grow may be adversely affected by our cash distribution policy.

Our cash distribution policy, which is consistent with our limited liability company agreement, requires us to distribute all of our available cash each quarter. In determining the amount of available cash each quarter, our board of directors will approve the amount of cash reserves to set aside, including reserves for anticipated maintenance and replacement capital expenditures, working capital and other matters. We will also rely upon external financing sources, including commercial borrowings, to fund our capital expenditures. To the extent we do not have sufficient cash reserves or are unable to obtain financing, our cash distribution policy may

 

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significantly impair our ability to meet our financial needs or to grow. Accordingly, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

We must make substantial capital and operating expenditures to maintain the operating capacity of our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness and to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to execute our growth plan, each of which could negatively affect our financial condition, result of operations and cash flows and reduce cash available for distribution. In addition, each quarter we are required to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted.

We must make substantial capital and operating expenditures to maintain and replace, over the long-term, the operating capacity of our fleet. We estimate that maintenance and replacement capital expenditures will average approximately $69 million per year, including amounts for replacing current drilling rigs at the end of their useful lives. Maintenance and replacement capital expenditures include capital expenditures for maintenance (including special classification surveys) and capital expenditures associated with modifying an existing drilling rig, including to upgrade its technology, extending the useful life of existing drilling rigs, acquiring a new drilling rig or otherwise replacing current drilling rigs at the end of their useful lives to the extent these expenditures are incurred to maintain or replace the operating capacity of our fleet. These expenditures could vary significantly from quarter to quarter, and from year to year, and could increase as a result of changes in the following:

 

    the cost of labor and materials;

 

    customer requirements;

 

    fleet size;

 

    the cost of replacement drilling rigs;

 

    the cost of replacement parts for existing drilling rigs;

 

    the geographic location of the drilling rigs;

 

    length of drilling contracts;

 

    governmental regulations and maritime self-regulatory organization and technical standards relating to safety, security or the environment;

 

    compliance with Transocean’s consent decree with the U.S. Department of Justice, or Consent Decree, Transocean’s administrative agreement with the U.S. Environmental Protection Agency, or EPA Agreement, and other governmental agreements; and

 

    industry standards.

Changes in offshore drilling technology, customer requirements for new or upgraded equipment and competition within our industry may require us to make significant capital expenditures in order to maintain our competitiveness. Our competitors may have greater financial and other resources than we have, which may enable them to make technological improvements to existing equipment or replace equipment that becomes obsolete. In addition, changes in governmental regulations, safety or other equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. As a result, we may be required to take our rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. In the future, market conditions may not justify these expenditures or enable us to operate our older rigs profitably during the remainder of their economic lives.

 

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Our limited liability company agreement requires our board of directors to deduct estimated maintenance and replacement capital expenditures, instead of actual maintenance and replacement capital expenditures, from operating surplus each quarter in an effort to reduce fluctuations in operating surplus as a result of variations in actual maintenance and replacement capital expenditures each quarter. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by our conflicts committee at least once a year. In years when estimated maintenance and replacement capital expenditures are higher than actual maintenance and replacement capital expenditures, the amount of available cash will be lower than if actual maintenance and replacement capital expenditures were deducted from operating surplus. If our board of directors underestimates the appropriate level of estimated maintenance and replacement capital expenditures, we may have less available cash in future periods when actual capital expenditures exceed our previous estimates.

If capital expenditures are financed through cash from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished, our financial leverage could increase or our unitholders could be diluted.

In order to maintain our fleet and execute our growth plan, we may require additional capital in the future. If we are unable to fund capital expenditures with cash flow from operations, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities. Our ability to access the capital markets for future offerings may be limited by our financial condition at the time, by changes in laws and regulations (or interpretation thereof) and by adverse market conditions resulting from, among other things, general economic conditions, changes in the offshore drilling industry and contingencies and uncertainties that are beyond our control. Failure to obtain the funds for future capital expenditures could have a material adverse effect on our business, results of operations and financial condition and on our ability to make cash distributions. Even if we are successful in obtaining necessary funds, the terms of any debt financings could limit our ability to pay cash distributions to unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash required to pay the minimum quarterly distribution to unitholders, both of which could have a material adverse effect on our ability to make cash distributions.

We currently derive all our revenues from two customers, and the loss of either of these customers or a dispute that leads to a loss of a customer could have a material adverse impact on our financial condition, results of operations and cash flows.

We currently derive all of our revenues and cash flow from two customers. For the year ended December 31, 2013, Chevron accounted for 67 percent and BP accounted for 33 percent of our total revenues, respectively. All of our drilling contracts have fixed terms, but may be terminated early due to certain events or might nevertheless be lost in the event of unanticipated developments, such as the deterioration in the general business or financial condition of a customer, resulting in its inability to meet its obligations under our contracts. Transocean’s relationship with BP, whose affiliate was the operator of the Macondo well, has been and could continue to be negatively impacted by the Macondo well incident. The loss of any customers, drilling contracts or drilling rigs, or a decline in payments under any of our drilling contracts, could have a material adverse effect on our business, financial condition, results of operations or cash flows and could reduce our cash available for distribution.

In addition, our drilling contracts subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control and may include, among other things, general economic conditions, the condition of the offshore drilling industry, prevailing prices for oil and natural gas, the overall financial condition of the counterparty, the dayrates received and the level of expenses necessary to maintain drilling activities. In addition, in depressed market conditions, our customers may no longer need a drilling rig that is currently under contract or may be able to obtain a comparable drilling rig at a lower dayrate. Should a counterparty fail to honor its obligations under an

 

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agreement with us, we could sustain losses, which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Any limitation in the availability or operation of any of our three drilling rigs could have a material adverse effect on our business, results of operations and financial condition and could significantly reduce our ability to make distributions to our unitholders.

Our fleet currently consists of two drillships and one semi-submersible drilling rig. Our limited number of rigs makes us more susceptible to incremental loss in the event of any downtime with respect to any rig. If any of our drilling rigs is unable to generate revenues as a result of sustained periods of downtime or the expiration or termination of its drilling contracts, and we are unable to recontract such rig, our financial condition, results of operations or cash flows could be materially adversely affected and our cash available for distribution could be reduced.

Our revenues will initially be derived from assets that are operating in the U.S. Gulf of Mexico, making us vulnerable to risks associated with operating in that single geographic area.

Currently, all of our operations are conducted in the U.S. Gulf of Mexico. This concentration could disproportionately expose us to operational and regulatory risk or other adverse developments in this area, including, for example, delays or decreases in the availability of equipment, facilities or services, severe weather, including tropical storms and hurricanes, and changes in the regulatory environment, including a complete moratorium on drilling in the U.S. Gulf of Mexico. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified. Because our fleet is mobile, we may have similar concentration risk in other geographic locations in the future.

We may be unable to renew or obtain new and favorable drilling contracts for rigs whose contracts are expiring or are terminated, which could adversely affect our revenues and profitability.

Our ability to renew expiring drilling contracts or obtain new drilling contracts will depend on the prevailing market conditions at the time. If we are unable to obtain new drilling contracts, if new drilling contracts are entered into at dayrates substantially below the existing dayrates or on terms otherwise less favorable compared to existing contract terms or if our customers request modifications of our drilling rigs in connection with new drilling contracts, our revenues and profitability could be adversely affected.

The offshore drilling market in which we compete experiences fluctuations in the demand for drilling services, as measured by the level of exploration and development expenditures. The existing drilling contracts for our drilling rigs are scheduled to expire from 2016 through 2020. We cannot guarantee that we will be able to obtain drilling contracts for our rigs upon the completion or termination of their current contracts or that there will not be a gap in employment of the rigs between current contracts and subsequent contracts. In particular, if oil and natural gas prices are low, or it is expected that such prices will decrease in the future, at a time when we are seeking to arrange drilling contracts for our rigs, we may be unable to obtain drilling contracts at attractive dayrates or at all. In addition, our customers may require modifications to our drilling rigs in connection with a new drilling contract and, depending on the market conditions at the time we enter into the contract, we may not be reimbursed for some or all of such modifications.

If the dayrates which we receive for the reemployment of our current drilling rigs are less favorable, we will recognize less revenue from their operations. Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts for our drilling rigs at sufficiently high dayrates. We cannot predict the future level of demand for our services or future conditions in the oil and gas industry. If oil and gas companies do not continue to increase exploration, development and production expenditures, we may have difficulty securing drilling contracts, or we may be forced to enter into contracts at unattractive dayrates, which would adversely affect our ability to make distributions to our unitholders.

 

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If we are unable to make acquisitions on economically acceptable terms from Transocean or third parties, our future growth would be limited, and any acquisitions we may make may reduce, rather than increase, our cash flows and ability to make distributions to unitholders.

Our strategy to grow our business and increase distributions to unitholders is dependent in part on our ability to make acquisitions that result in an increase in cash available for distribution per unit. Our growth strategy is based in part on our right of first offer from Transocean’s obligation to offer us the opportunity to purchase four specified drilling rigs or other acquisitions that we expect to make from Transocean. There can be no assurance that such acquisitions will be available to us on an accretive basis, on acceptable terms or at all. Other than this obligation to offer us the opportunity to purchase these four drilling rigs, Transocean has no obligation to make any acquisitions available to us. The consummation and timing of any future acquisitions will depend upon, among other things, whether:

 

    we are able to identify attractive acquisition candidates;

 

    we are able to negotiate acceptable purchase agreements;

 

    we are able to obtain financing for these acquisitions on economically acceptable terms; and

 

    we are outbid by competitors.

We can offer no assurance that we will be able to successfully consummate any future acquisitions, whether from Transocean or any third parties. Any acquisitions that may be available to us may require that we be able to access the debt and equity markets. However, we may be unable to access such markets on attractive terms or at all. If we are unable to make future acquisitions, our future growth and ability to increase distributions will be limited. Furthermore, even if we do consummate acquisitions that we believe will be accretive, they may in fact result in a decrease in cash available for distribution per unit as a result of incorrect assumptions in our evaluation of such acquisitions or unforeseen consequences or other external events beyond our control. Acquisitions involve numerous risks, including difficulties in integrating acquired businesses, inefficiencies and unexpected costs and liabilities.

The continuing effects of the enhanced regulations enacted following the Macondo well incident, the Consent Decree and the EPA Agreement could materially and adversely affect our operations.

New governmental safety and environmental requirements applicable to both deepwater and shallow water operations have been adopted for drilling in the U.S. Gulf of Mexico following the Macondo well incident in the U.S. Gulf of Mexico in 2010. In order to obtain drilling permits, operators must submit applications that demonstrate compliance with the enhanced regulations, which require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. Operators have previously had, and may in the future have, difficulties obtaining drilling permits in the U.S. Gulf of Mexico. In addition, the oil and gas industry has adopted new equipment and operating standards, such as the American Petroleum Institute Standard 53 relating to the installation and testing of well control equipment. These new safety and environmental guidelines and standards and any further new guidelines or standards the U.S. government or industry may issue or any other steps the U.S. government or industry may take, could disrupt or delay operations, increase the cost of operations, increase out-of-service time or reduce the area of operations for drilling rigs in U.S. and non-U.S. offshore areas.

Other governments could take similar actions relating to implementing new safety and environmental regulations in the future. Additionally, some of our customers have elected or may elect to voluntarily comply with some or all of the new inspections, certification requirements and safety and environmental guidelines on rigs operating outside of the U.S. Gulf of Mexico. Additional governmental regulations and requirements concerning licensing, taxation, equipment specifications and training requirements or the voluntary adoption of such requirements or guidelines by our customers could increase the costs of our operations, increase certification and permitting requirements, increase review periods and impose increased liability on offshore operations.

 

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Because we are an affiliate of Transocean, our operations in the waters of the United States are subject to the safety, environmental, reporting, operational and other requirements of the Consent Decree and the EPA Agreement. These requirements are in addition to the regulations applicable to all industry participants and may add additional costs and liabilities and may adversely affect our customers’ perception of us and may place us at a competitive disadvantage to other offshore drillers.

Pursuant to the Consent Decree, Transocean agreed to take specified actions relating to operations in U.S. waters, including, among other things, the design and implementation of, and compliance with, additional systems and procedures; blowout preventer certification and reports; measures to strengthen well control competencies, drilling monitoring, recordkeeping, incident reporting, risk management and oil spill training, exercises and response planning; communication with operators; alarm systems; transparency and responsibility for matters relating to the Consent Decree; and technology innovation, with a first emphasis on more efficient, reliable blowout preventers. The Consent Decree provides for independent auditors for compliance with the Consent Decree and an independent process safety consultant and requires certain plans, reports and submissions be made and be acceptable to the U.S. and also requires certain publicly available filings.

In the EPA Agreement, Transocean agreed to, among other things, continue the implementation of certain programs and systems; comply with certain employment and contracting procedures; engage independent compliance auditors and a process safety consultant; and give reports and notices with respect to various matters.

The continuing effects of the enhanced regulations may also decrease the demand for drilling services, negatively affect dayrates and increase out-of-service time, which could ultimately have a material adverse effect on our revenue and profitability. We are unable to predict the full impact that the continuing effects of the enhanced regulations will have on our operations.

In addition, subject to certain exceptions, the EPA Agreement prohibits us from entering into, extending or engaging in certain business relationships with individuals or entities that are debarred, suspended, proposed for debarment or similarly restricted in the United States. The loss of any of our customers due to such restrictions could, at least in the short term, have a material adverse effect on our financial condition, results of operations and cash flows.

Our growth and our business depend on the level of activity in oil and gas exploration, development and production in offshore areas.

Our growth and our business depend on the level of activity in oil and gas exploration, development and production in offshore areas. Demand for our services depends on oil and natural gas industry activity and expenditure levels that are directly affected by trends in oil and natural gas prices.

Oil and gas prices are extremely volatile and are affected by numerous factors, including the following:

 

    worldwide demand for oil and gas, including economic activity in the U.S. and other large energy-consuming markets;

 

    the ability of the Organization of the Petroleum Exporting Countries, or OPEC, to set and maintain production levels, productive spare capacity and pricing;

 

    the level of production in non-OPEC countries;

 

    the policies of various governments regarding exploration and development of their oil and gas reserves;

 

    advances in exploration, development and production technology;

 

    the discovery rate of new oil and gas reserves;

 

    the rate of decline of existing oil and gas reserves;

 

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    laws and regulations related to environmental matters, including those addressing alternative energy sources and the risks of global climate change;

 

    the development and exploitation of alternative fuels;

 

    the development of new technology to exploit oil and gas reserves, such as shale oil;

 

    accidents, adverse weather conditions, natural disasters and other similar incidents relating to the oil and gas industry; and

 

    the worldwide security and political environment, including uncertainty or instability resulting from an escalation or outbreak of armed hostilities, civil unrest or other crises in the Middle East or Eastern Europe or other geographic areas or acts of terrorism.

Demand for our services is particularly sensitive to the level of exploration, development and production activity of, and the corresponding capital spending by, oil and natural gas companies, including national oil companies. Any prolonged reduction in oil and natural gas prices could depress the immediate levels of exploration, development and production activity. Perceptions of longer-term lower oil and natural gas prices by oil and gas companies could similarly reduce or defer major expenditures given the long-term nature of many large-scale development projects. Lower levels of activity result in a corresponding decline in the demand for our services, which could have a material adverse effect on our revenue and profitability. Oil and gas prices and market expectations of potential changes in these prices significantly affect this level of activity. However, higher near-term commodity prices do not necessarily translate into increased drilling activity since customers’ expectations of longer-term future commodity prices typically drive demand for our rigs. Also, increased competition for customers’ drilling budgets could come from, among other areas, offshore areas where we do not currently operate and land-based energy markets in Africa, Russia, China, the Middle East, the U.S. and elsewhere. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments also affect customers’ drilling campaigns. Worldwide military, political and economic events have contributed to oil and gas price volatility and are likely to do so in the future.

Our current backlog of contract drilling revenue may not be fully realized, which may have a material adverse impact on our financial position, results of operations or cash flows, and will reduce cash available for distributions.

Our contract backlog represents the firm term of the drilling contract multiplied by the maximum contractual operating rate, which may be higher than the actual dayrate we receive or we may receive other dayrates included in the contract such as waiting-on-weather rate, repair rate, standby rate or force majeure rate. The contractual operating dayrate may also be higher than the actual dayrate we receive because of a number of factors, including rig downtime or suspension of operations.

Several factors could cause rig downtime or a suspension of operations, including:

 

    breakdowns of equipment and other unforeseen engineering problems;

 

    work stoppages, including labor strikes;

 

    shortages of material and skilled labor;

 

    surveys by government and maritime authorities;

 

    periodic classification surveys;

 

    severe weather, strong ocean currents or harsh operating conditions; and

 

    force majeure events.

In certain drilling contracts, the dayrate may be reduced to zero or result in customer credit against future dayrate if, for example, repairs extend beyond a stated period of time. Our contract backlog currently includes

 

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signed drilling contracts, although, in some cases, we may include contracts represented by other definitive agreements awaiting contract execution. We may be unable to realize the full amount of our contract backlog due to events beyond our control. Our customers could experience liquidity issues if commodity prices decline to lower levels for an extended period of time. Liquidity issues could lead our customers to go into bankruptcy or could encourage our customers to seek to repudiate, cancel or renegotiate these agreements for various reasons, as described under “Our drilling contracts may be terminated due to a number of events” below. Our inability to realize the full amount of our contract backlog may have a material adverse effect on our financial condition, results of operations or cash flows and could reduce our cash available for distribution.

Our drilling contracts may be terminated due to a number of events.

Drilling contracts with customers may be cancelable at the option of the customer upon payment of an early termination payment. Such payments may not, however, fully compensate us for the loss of the contract. Drilling contracts also customarily provide for either automatic termination or termination at the option of the customer typically without the payment of any termination fee, under various circumstances such as non-performance, as a result of significant downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events. Many of these events are beyond our control. During periods of depressed market conditions, we are subject to an increased risk of our customers seeking to repudiate their contracts, including through claims of non-performance. Our customers’ ability to perform their obligations under their drilling contracts, including their ability to fulfill their indemnity obligations to us, may also be negatively impacted by an economic downturn. Our customers often have significant bargaining leverage over us. If our customers cancel some of our contracts, and we are unable to secure new contracts on a timely basis and on substantially similar terms, or if contracts are suspended for an extended period of time or if a number of our contracts are renegotiated, it could adversely affect our financial condition, results of operations or cash flows and reduce our cash available for distribution. For more information regarding the termination provisions of our drilling contracts, please read “Business—Drilling Contracts.”

Our debt levels may limit our flexibility in obtaining additional financing and paying distributions to unitholders, and we may suffer competitive disadvantages.

Upon completion of this offering and the related transactions, we estimate that our consolidated debt (including indebtedness incurred by the RigCos) will be approximately $             million. Following this offering, we will continue to have the ability to incur additional debt. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.” Our level of debt and other obligations could have significant adverse consequences for our business and future prospects, including the following:

 

    we may be unable to obtain financing on favorable terms or at all in the future for working capital, capital expenditures, acquisitions, debt service requirements, distributions or other purposes;

 

    we may not be able to use operating cash flow in other areas of our business or to make distributions because we must dedicate a substantial portion of these funds to service the debt;

 

    we could become more vulnerable to general adverse economic and industry conditions, including increases in interest rates, particularly if we have substantial indebtedness that bears interest at variable rates;

 

    we may not be able to meet financial ratios or satisfy certain other conditions included in our credit facilities, which could result in our inability to meet requirements for borrowings under our credit facilities or a default under our credit facilities and trigger cross default provisions in our other debt instruments; and

 

    we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our less levered competitors.

 

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We may require a significant amount of cash to service our indebtedness and other obligations. Our ability to generate cash depends on many factors beyond our control.

Our ability to make payments on, or refinance, our indebtedness and to fund our working capital needs and planned capital expenditures will depend on our ability to generate cash in the future. A significant reduction in our operating cash flows, including as a result of changes in general economic conditions, timing of contracts or payments, expiration or termination of drilling contracts, legislative or regulatory conditions, increased competition or other events beyond our control, could increase the need for additional or alternative sources of liquidity and could have a material adverse effect on our financial condition, results of operations, cash flows and ability to service our debt and other obligations.

If we are unable to service our indebtedness or to fund our liquidity needs, we may be forced to adopt an alternative strategy that may include actions such as reducing capital expenditures, reducing distributions, selling assets, restructuring or refinancing indebtedness, seeking additional capital or any combination of the foregoing. If we raise additional funds by issuing additional equity securities, existing unitholders may experience dilution. We cannot assure you that any of these alternative strategies could be affected on satisfactory terms, or at all, or that they would yield sufficient funds to enable us to make required payments on our indebtedness or to fund our other liquidity needs. Reducing or delaying capital expenditures or selling assets could delay future cash flows. In addition, the terms of existing or future debt agreements may restrict us from adopting any of these alternatives.

Our failure to generate sufficient operating cash flow or to achieve any of these alternatives could significantly adversely affect the value of our common units. In addition, if we default in the payment of amounts due on any indebtedness, such default would give rise to an event of default under the agreements governing our indebtedness and could lead to the possible acceleration of amounts due under any of our outstanding indebtedness. In the event of any acceleration, we may not have enough cash to repay our outstanding indebtedness.

Financing agreements, including Transocean’s financing agreements, containing operating and financial restrictions and other covenants may restrict our business and financing activities.

The operating and financial restrictions and covenants in our financing agreements and those of Transocean and any future financing agreements of Transocean or us could adversely affect our ability to finance future operations or capital needs or to engage, expand or pursue our business activities. We will be required to comply with the terms of Transocean’s agreements regarding indebtedness and have agreed to take no actions that would cause Transocean not to be in compliance with such agreements. For example, the indentures governing Transocean’s outstanding senior notes may restrict our ability to create or permit liens on our assets. Transocean may incur liens solely for reasons relating to its business that does not affect or benefit us, and it will have no obligation to take into account the effect of the creation of such liens on us. As such, our ability to incur secured indebtedness will depend in part on Transocean’s financial condition, capital needs and plans. In addition, subject to certain exceptions, the financing agreements may restrict our ability to:

 

    pay distributions to our unitholders;

 

    enter into other financing agreements;

 

    incur additional indebtedness;

 

    create or permit liens on our assets;

 

    sell our drilling rigs or the capital stock of our subsidiaries;

 

    change the nature of our business;

 

    make investments;

 

    change the management and/or ownership of our drilling rigs;

 

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    make capital expenditures; and

 

    compete effectively to the extent our competitors are subject to less onerous restrictions.

Transocean may enter into agreements in the future with different or additional restrictions and covenants that will apply to us.

Our ability to comply with the restrictions and covenants, including financial ratios and tests, contained in any financing agreements of Transocean or us, is dependent on our and/or Transocean’s future performance and may be affected by events beyond our control, including actions by Transocean and prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness or in current or future debt financing agreements, there could be a default under the terms of those agreements. If a default occurs under these agreements, lenders could terminate their commitments to lend and/or accelerate the outstanding loans and declare all amounts borrowed due and payable. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Restrictions in our debt agreements may prevent us from paying distributions.

The payment of principal and interest on our debt will reduce our cash available for distribution. In addition, our financing agreements are expected to contain provisions that, upon the occurrence of certain events, permit lenders to terminate their commitments and/or accelerate the outstanding loans and declare all amounts due and payable, which may prevent us from paying distributions to our unitholders. These events may include, among others:

 

    a failure to pay any principal, interest, fees, expenses or other amounts when due;

 

    a violation of covenants requiring us to maintain certain financial ratios;

 

    a default under any other provision of the financing agreement, as well as a default under any provision of related security documents;

 

    a material breach of any representation or warranty contained in the applicable financing agreement;

 

    a default under other indebtedness;

 

    a failure to comply with a final legal judgment from a court of competent jurisdiction;

 

    a bankruptcy or insolvency event;

 

    a suspension or cessation of our business;

 

    the destruction or abandonment of our assets, or the seizure or appropriation thereof by any governmental, regulatory or other authority if the lenders determine such occurrence could have a material adverse effect on our business or our ability to satisfy our obligations under or otherwise comply with the applicable financing agreement;

 

    the invalidity, unlawfulness or repudiation of any financing agreement or related security document;

 

    an enforcement of any liens or other encumbrances covering our assets; and

 

    the occurrence of certain other events that are likely to have a material adverse effect on our business or our ability to satisfy our obligations under or otherwise comply with the applicable financing agreement.

For more information regarding the Five-Year Revolving Credit Facility, please read “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Liquidity and Capital Resources—Revolving credit facilities.”

 

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The offshore drilling industry is highly competitive and cyclical, with intense price competition.

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which has a dominant market share. Drilling contracts are generally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and the quality and technical capability of services and equipment are also considered.

The offshore contract drilling industry has historically been cyclical and is impacted by oil and gas price levels and volatility. There have been periods of high demand, short rig supply and high dayrates, followed by periods of low demand, excess rig supply and low dayrates. Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply may intensify competition in the industry and result in rigs being idle for long periods of time. In addition, certain competitors have greater financial resources than we do, which may enable them to better withstand periods of low utilization and compete more effectively on the basis of price.

During prior periods of high dayrates and rig utilization rates, industry participants have increased the supply of rigs by ordering the construction of new units. This has historically resulted in an oversupply of rigs and has caused a subsequent decline in dayrates and rig utilization rates, sometimes for extended periods of time. Presently, there are numerous recently constructed high-specification floaters and other drilling units that are capable of competing with our rigs that have entered the global market, and there are more that are under contract for construction. The entry into service of these new units has increased and will continue to increase supply and could curtail a strengthening, or trigger a reduction, in dayrates as rigs are absorbed into the active fleet or lead to accelerated stacking of the existing fleet. A significant number of the newbuild units have not been contracted for work, which may intensify price competition. Any further increase in construction of new units would likely exacerbate the negative impact on dayrates and utilization rates. Lower dayrates and rig utilization rates could adversely affect our revenues, profitability and cash available for distribution.

We depend on affiliates of Transocean to assist us in operating and expanding our business.

Our ability to enter into new drilling contracts and expand our customer and supplier relationships will depend largely on our ability to leverage our relationship with Transocean and its reputation and relationships in the offshore drilling industry. If Transocean suffers material damage to its reputation, relationships or financial condition, it could adversely affect us and limit the benefits we expect to derive from our present and future relationship with Transocean. Among other things, such damage may adversely affect Transocean’s ability to provide services to us and to enter into newbuild, acquisition or sale transactions that may benefit us and may harm our business and prospects, including our ability to:

 

    renew existing drilling contracts upon their expiration;

 

    obtain new drilling contracts;

 

    efficiently and productively carry out our business activities;

 

    acquire additional assets from Transocean;

 

    successfully interact with shipyards;

 

    obtain financing and maintain insurance on commercially acceptable terms;

 

    maintain satisfactory relationships with suppliers, labor and other third parties; or

 

    enforce our contractual rights against Transocean, including indemnification rights.

Such damage and other adverse affects could arise from events beyond our control, including developments relating to the Macondo well incident. In addition, pursuant to the master services agreements and the support and secondment agreements, affiliates of Transocean will provide us with significant operational, administrative, financial and other support services and/or personnel. Our operational success and ability to execute our growth strategy will depend significantly upon the satisfactory performance of these services. Please read “Certain Relationships and Related Party Transactions.”

 

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Our shipyard projects and operations are subject to delays and cost overruns.

Our rigs will undergo shipyard projects from time to time. These shipyard projects are subject to the risks of delay or cost overruns inherent in any such construction project resulting from numerous factors, including the following:

 

    shipyard availability, failures and difficulties;

 

    shortages of equipment, materials or skilled labor;

 

    unscheduled delays in the delivery of ordered materials and equipment;

 

    design and engineering problems, including those relating to the commissioning of newly designed equipment;

 

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

 

    unanticipated actual or purported change orders;

 

    disputes with shipyards and suppliers;

 

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

 

    availability of suppliers to recertify equipment for enhanced regulations;

 

    strikes, labor disputes and work stoppages;

 

    customer acceptance delays;

 

    adverse weather conditions, including damage caused by such conditions;

 

    terrorist acts, war, piracy and civil unrest;

 

    unanticipated cost increases; and

 

    difficulty in obtaining necessary permits or approvals.

These factors may contribute to cost variations and delays in the delivery of our rigs undergoing shipyard projects. Delays in the delivery of these units would result in delay in contract commencement, resulting in a loss of revenue to us, and may also cause customers to terminate or shorten the term of the drilling contract for the rig pursuant to applicable late delivery clauses. In the event of termination of any of these drilling contracts, we may not be able to secure a replacement contract on as favorable terms, if at all.

Our operations also rely on a significant supply of capital and consumable spare parts and equipment to maintain and repair our fleet. We also rely on the supply of ancillary services, including supply boats and helicopters. Shortages in materials, manufacturing defects, delays in the delivery of necessary spare parts, equipment or other materials, or the unavailability of ancillary services could negatively impact our future operations and result in increases in rig downtime and delays in the repair and maintenance of our fleet.

Our business involves numerous operating hazards, and our insurance and indemnities from our customers may not be adequate to cover potential losses from our operations.

Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, craterings, fires, explosions and pollution. Contract drilling requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and other parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. Our offshore fleet is also subject to hazards inherent in marine operations, either while on site or during mobilization, such as capsizing, sinking, grounding, collision, piracy, damage from severe weather and marine life infestations. The U.S. Gulf of Mexico area is subject to hurricanes or other extreme weather conditions on a relatively frequent basis, and our

 

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drilling rigs in this region may be exposed to damage or total loss by these storms, some of which may not be covered by insurance. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel. Some experts believe global climate change could increase the frequency and severity of these extreme weather conditions. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. We customarily provide contract indemnity to our customers for certain claims that could be asserted by us relating to damage to or loss of our equipment, including rigs, and claims that could be asserted by us or our employees relating to personal injury or loss of life.

Damage to the environment could also result from our operations, particularly through spillage of hydrocarbons, fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. We may also be subject to property damage, environmental indemnity and other claims by oil and natural gas companies. There are certain risks associated with the loss of control of a well, such as blowout, cratering, the cost to regain control of or re-drill the well and remediation of associated pollution. Our customers may be unable or unwilling to indemnify us against such risks. In addition, a court may decide that certain indemnities in our current or future drilling contracts are not enforceable. The law generally considers contractual indemnity for criminal fines and penalties to be against public policy, and the enforceability of an indemnity as to other matters may be limited.

Our insurance policies and drilling contracts contain rights to indemnity that may not adequately cover our losses, and we do not have insurance coverage or rights to indemnity for all risks. We participate in Transocean’s insurance program and have two main types of coverage: (1) hull and machinery coverage for physical damage to our property and equipment and (2) excess liability coverage which generally covers offshore risks, such as personal injury, third-party property claims and third-party non-crew claims, including wreck removal and pollution. We will not generally carry commercial market insurance coverage for loss of revenues unless we are contractually required or for losses resulting from physical damage to our fleet caused by named windstorms in the U.S. Gulf of Mexico, including liability for wreck removal costs. Under the hull and machinery coverage for physical damage to our property and equipment, we generally maintain a $125 million per occurrence deductible, limited to a maximum of $200 million per policy period. Of such $125 million per occurrence deductible, Transocean has retained the risk of $115 million in excess of $10 million through Transocean’s wholly-owned captive insurance company. Under the excess liability coverage, we maintain per occurrence deductibles on our rigs that generally range up to $10 million for various third-party liabilities and an additional aggregate annual deductible of $50 million, which is self-insured through Transocean’s wholly-owned captive insurance company. We also retain the risk for any liability in excess of Transocean’s $750 million excess liability coverage. However, pollution and environmental risks generally are not completely insurable. See “Business—Insurance.”

If a significant accident or other event occurs that is not fully covered by our insurance or an enforceable or recoverable indemnity from any agreement, the occurrence could adversely affect our financial condition, results of operations or cash flows. The amount of our insurance may also be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we generally retain the risk for any losses in excess of these limits. We generally do not carry insurance for loss of revenue unless contractually required, and certain other claims may also not be reimbursed by insurance carriers. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain more risk in the future, resulting in higher risk of losses, which could be material. Moreover, we may not be able to maintain adequate insurance in the future at rates that we consider reasonable or be able to obtain insurance against certain risks.

Significant part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.

Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to volatility in the quality, prices and availability

 

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of such items. Certain parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider. Recent industry developments have reduced the number of available suppliers. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenues or increase our operating costs.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues.

Our operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Costs for operating a rig are generally fixed or only semi-variable regardless of the dayrate being earned. In addition, should our rigs incur unplanned downtime while on contract or idle time between drilling contracts, we typically will not reduce the staff on those rigs because we will use the crew to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity the unit is performing and the age and condition of the equipment, and these expenses could increase for short or extended periods as a result of regulatory or customer requirements that raise maintenance standards above historical levels. Contract preparation costs vary based on the scope and length of contract preparation required and the duration of the firm contractual period over which such expenditures are amortized.

Our drilling contracts may not permit us to fully recoup our cost increases in the event of an increase in expenses.

Our drilling contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from these term contracts, our drilling contracts include escalation provisions. These provisions allow us to adjust the dayrates based on certain published indices and our historical costs. These provisions are designed to compensate us for certain cost increases, including wages, insurance and maintenance costs. However, actual cost increases may result from events or conditions that do not cause correlative changes to the applicable indices. Furthermore, certain indices may be outdated at the time of adjustment. In addition, the adjustments are normally performed only periodically. For these reasons, the timing and amount received as a result of the adjustments may differ from the timing and amount of expenditures associated with actual cost increases, which could adversely affect our cash flow and ability to make cash distributions. In addition, certain of our future drilling contracts may not include such provisions, which would further expose our results of operations to the effects of inflation on our expenses.

Failure to recruit and retain key personnel could hurt our operations.

We depend on the continuing efforts of highly skilled personnel to operate and provide technical services and support for our business. Historically, competition for the personnel required for drilling operations has intensified as the number of rigs activated, added to fleets or under construction increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher turnover. We may experience a reduction in the experience level of the personnel involved in our operations as a result of any increased turnover, which could lead to higher downtime and more operating incidents, which in turn could decrease revenues and increase costs. If increased competition for qualified personnel were to intensify in the future, we may experience increases in costs or limits on operations.

 

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Our labor costs and the operating restrictions under which we operate could increase as a result of collective bargaining negotiations and changes in labor laws and regulations.

Legislation has been introduced in the U.S. Congress that could encourage unionization efforts in the U.S., as well as increase the chances that such efforts succeed. Unionization efforts, if successful, new collective bargaining agreements or work stoppages could materially increase our labor costs and operating restrictions.

We have a significant carrying amount of long-lived assets, which is subject to impairment testing, and we could be required to recognize losses on impairment of our long-lived assets.

The carrying amount of our property and equipment was $2.0 billion, representing 82 percent and 83 percent of our total assets at March 31, 2014 and December 31, 2013, respectively. In accordance with our critical accounting policies, we review our property and equipment for impairment when events or changes in circumstances indicate that the aggregate carrying amount of our assets held and used may not be recoverable. Future expectations of lower dayrates or rig utilization rates or changes in market conditions could lead us to believe that the carrying amount of our long-lived assets is unrecoverable. If we determine that the carrying amount is not recoverable, we could be required to recognize losses on impairment of our long-lived asset group, which could adversely affect our financial condition and results of operations.

Any operations outside the United States may involve additional risks.

Although initially all of our operations are expected to be in the U.S. Gulf of Mexico, our drilling units are capable of operating in various regions throughout the world, which may expose us to additional political and other uncertainties, including risks of:

 

    terrorist acts, war, piracy and civil unrest;

 

    seizure, expropriation or nationalization of our equipment;

 

    expropriation or nationalization of our customers’ property;

 

    repudiation or nationalization of contracts;

 

    imposition of trade or immigration barriers;

 

    import-export quotas;

 

    wage and price controls;

 

    changes in law and regulatory requirements, including changes in interpretation and enforcement;

 

    involvement in judicial proceedings in unfavorable jurisdictions;

 

    damage to our equipment or violence directed at our employees, including kidnappings;

 

    complications associated with supplying, repairing and replacing equipment in remote locations;

 

    the inability to move income or capital; and

 

    currency exchange fluctuations.

Non-U.S. contract drilling operations are subject to various laws and regulations in certain countries in which we may operate, including laws and regulations relating to the import and export, equipment and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, and taxation of offshore earnings and earnings of expatriate personnel. Any non-U.S. operations also will be subject to the U.S. Treasury Department’s Office of Foreign Assets Control, or OFAC, and other U.S. laws and regulations governing our international operations. In addition, various state and municipal governments, universities and other investors, including, with respect to state governments, by state retirement systems, have proposed or adopted divestment and other initiatives regarding investments in companies that do business with countries that have been designated as state sponsors of terrorism by the U.S. State Department. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to

 

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criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets. Investors could view any potential violations of OFAC regulations negatively, which could adversely affect our reputation and the market for our common units.

Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries, including local content requirements for participating in tenders for certain drilling contracts. Many governments favor or effectively require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction or require use of a local agent or interest owner. In addition, government action, including initiatives by OPEC, may continue to cause oil or gas price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work by oil companies and may continue to do so.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import and export activities are governed by unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the import and export of certain goods, services and technology and impose related import and export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities, and we are also subject to the U.S. anti-boycott law.

The laws and regulations concerning import and export activity, recordkeeping and reporting, import and export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Ongoing economic challenges may increase some foreign governments’ efforts to enact, enforce, amend or interpret laws and regulations as a method to increase revenue. Shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime.

Our ability to operate worldwide will depend on our ability to obtain the necessary visas and work permits for our personnel to travel in and out of, and to work in, the jurisdictions in which we plan to operate. Governmental actions in some of the jurisdictions in which we plan to operate may make it difficult for us to move our personnel in and out of these jurisdictions by delaying or withholding the approval of these permits. If we are not able to obtain visas and work permits in the future for the employees we will need to operate our rigs on a timely basis, we might not be able to perform our obligations under future drilling contracts, which could allow our customers to cancel such contracts. If our customers cancel future drilling contracts, and we are unable to secure replacement drilling contracts on a timely basis and on substantially similar terms, it may adversely affect our financial condition, results of operations or cash flows.

If any of our drilling rigs fails to maintain its class certification or fails any required survey, that drilling rig would be unable to operate, thereby reducing our revenues and profitability.

Every offshore drilling rig is a registered marine vessel and must be “classed” by a classification society. The classification society certifies that the drilling rig is “in-class,” signifying that such drilling rig has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling rig’s country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake such surveys on application or by official order, acting on behalf of the authorities concerned. If any drilling rig does not maintain its class and/or fails any annual survey or special survey, the drilling rig will be unable to carry on operations and will be unemployable and uninsurable, which could cause us to be in violation of certain covenants in our credit facility. Any such inability to carry on operations or be employed could have a material adverse impact on our financial condition, results of operations or our ability to make distributions to our unitholders.

 

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Interest rate fluctuations could affect our earnings and cash flow.

Our working capital notes payable to affiliates of Transocean have floating interest rates, and in the future, we may have additional debt with floating interest rates. As such, significant movements in interest rates could have an adverse effect on our earnings and cash flow. In order to manage our exposure to interest rate fluctuations, we may use interest rate swaps to effectively fix a part of our floating rate debt obligations. The principal amount covered by interest rate swaps is evaluated and determined based on our debt level, our expectations regarding future interest rates, our contract backlog and our overall financial risk exposure. For more information regarding the revolving credit agreement that we expect to enter into, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facilities.”

Compliance with or breach of environmental laws can be costly, expose us to liability and could limit our operations.

Our business in the offshore drilling industry is affected by laws and regulations relating to the energy industry and the environment, including international conventions and treaties, and regional, national, state and local laws and regulations. The offshore drilling industry depends on demand for services from the oil and gas exploration and production industry, and, accordingly, we are directly affected by the adoption of laws and regulations that, for economic, environmental or other policy reasons, curtail exploration and development drilling for oil and gas. Compliance with such laws, regulations and standards, where applicable, may require us to make significant capital expenditures, such as the installation of costly equipment or operational changes, and may affect the resale values or useful lives of our rigs. We may also incur additional costs in order to comply with other existing and future regulatory obligations, including, but not limited to, costs relating to air emissions, including greenhouse gases, the management of ballast waters, maintenance and inspection, development and implementation of emergency procedures and insurance coverage or other financial assurance of our ability to address pollution incidents. Offshore drilling in certain areas has been curtailed and, in certain cases, prohibited because of concerns over protection of the environment. These costs could have a material adverse effect on our financial condition, results of operations or cash flows. A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations.

To the extent new laws are enacted or other governmental actions are taken that prohibit or restrict offshore drilling or impose additional environmental protection requirements that result in increased costs to the oil and gas industry, in general, or the offshore drilling industry, in particular, our business or prospects could be materially adversely affected. The operation of our drilling rigs will require certain governmental approvals. These governmental approvals may involve public hearings and costly undertakings on our part. We may not obtain such approvals or such approvals may not be obtained in a timely manner. If we fail to timely secure the necessary approvals or permits, our customers may have the right to terminate or seek to renegotiate their drilling contracts to our detriment. The amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas could have a material adverse effect on our business, operating results or financial condition. Compliance with any such new legislation or regulations could have an adverse effect on our statements of operations and cash flows.

As an operator of mobile offshore drilling units in some offshore areas, we may be liable for damages and costs incurred in connection with oil spills or waste disposals related to those operations, and we may also be subject to significant fines in connection with spills. For example, an oil spill could result in significant liability, including fines, penalties and criminal liability and remediation costs for natural resource damages, as well as third-party damages, to the extent that the contractual indemnification provisions in our drilling contracts are not enforceable or are otherwise insufficient, or if our customers are unwilling or unable to contractually indemnify us from these risks. Additionally, we may not be able to obtain such indemnities in our future drilling contracts, and our customers may not have the financial capability to fulfill their contractual obligations to us. Also, these indemnities may be held to be unenforceable in certain jurisdictions, as a result of public policy considerations or

 

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for other reasons. Laws and regulations protecting the environment have become more stringent in recent years, and may in some cases impose strict liability, rendering a person liable for environmental damage without regard to negligence. These laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. The application of these requirements or the adoption of new requirements or measures could have a material adverse effect on our financial condition, results of operations or cash flows. In addition, the Consent Decree and the EPA Agreement add to these regulations, requirements and liabilities.

Worldwide financial and economic conditions could have a material adverse effect on our statement of financial position, results of operations or cash flows.

Worldwide financial and economic conditions could cause our ability to access the capital markets to be severely restricted at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions. Worldwide economic conditions have in the past impacted, and could in the future impact, the lenders participating in our credit facilities and our customers, causing them to fail to meet their obligations to us. A slowdown in economic activity could reduce worldwide demand for energy and result in an extended period of lower oil and natural gas prices. A decline in oil and natural gas prices could reduce demand for our drilling services and have a material adverse effect on our statement of financial position, results of operations or cash flows.

Failure to comply with the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010 could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

The U.S. Foreign Corrupt Practices Act, or FCPA, the U.K. Bribery Act 2010, or Bribery Act, and similar anti-bribery laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments for the purpose of obtaining or retaining business. We may operate in many parts of the world that have experienced corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. If we are found to be liable for violations under the FCPA, the Bribery Act or other similar laws, either due to our acts or omissions or due to the acts or omissions of others, we could suffer from civil and criminal penalties or other sanctions, which could have a material adverse effect on our business, financial condition and results of operations.

Civil penalties under the anti-bribery provisions of the FCPA could range up to $10,000 per violation, with a criminal fine up to the greater of $2 million per violation or twice the gross pecuniary gain to us or twice the gross pecuniary loss to others, if larger. Civil penalties under the accounting provisions of the FCPA can range up to $500,000 per violation and a company that knowingly commits a violation can be fined up to $25 million per violation. In addition, both the SEC and the U.S. Department of Justice could assert that conduct extending over a period of time may constitute multiple violations for purposes of assessing the penalty amounts. Often, dispositions for these types of matters result in modifications to business practices and compliance programs and possibly the appointment of a monitor to review future business and practices with the goal of ensuring compliance with the FCPA.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

Some scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases, or GHGs, and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide.

Legislation to regulate emissions of GHGs has been introduced in the U.S. Congress, and there has been a wide-ranging policy debate, both in the U.S. and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries to meet stringent new standards that may require substantial reductions in carbon emissions. Those reductions could be costly and difficult to

 

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implement. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Doha in 2012.

In the United States, the EPA has undertaken efforts to collect information regarding GHG emissions and their effects. Following a finding by the EPA that certain GHGs represent an endangerment to human health, the EPA finalized motor vehicle GHG emissions standards, the effect of which could reduce demand for motor fuels refined from crude oil. The EPA also issued a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration and Title V programs commencing when the motor vehicle standards took effect on January 2, 2011. Facilities containing petroleum and natural gas systems that emit 25,000 metric tons or more of CO2 equivalent per year are now required to report annual GHG emissions to the EPA. To the extent that our operations are subject to the EPA’s GHG regulations, we may face increased capital and operating costs.

Because our business depends on the level of activity in the offshore oil and gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and gas or limit drilling opportunities. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business.

We may be subject to litigation that, if not resolved in our favor and not sufficiently insured against, could have a material adverse effect on us.

We may in the future be, from time to time, involved in various litigation matters. These matters may include, among other things, contract disputes, personal injury claims, environmental claims or proceedings, asbestos and other toxic tort claims, employment matters, governmental claims for taxes or duties and other litigation that arises in the ordinary course of our business. We cannot predict with certainty the outcome or effect of any claim or other litigation matter, and the ultimate outcome of any litigation or the potential costs to resolve them may have a material adverse effect on us. Insurance may not be applicable or sufficient in all cases, insurers may not remain solvent and policies may not be located. To the extent that one or more pending or future litigation matters is not resolved in our favor and is not covered by insurance, a material adverse effect on our financial results and condition could result.

Public health threats could have a material adverse effect on our operations and our financial results.

Public health threats and other highly communicable diseases, outbreaks of which have already occurred in various parts of the world could adversely impact our operations. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems, or any reduction in the demand for drilling services caused by public health threats in the future, may materially impact operations and adversely affect our financial results.

Our information technology systems are subject to cybersecurity risks and threats.

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

 

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Under the master services agreements and certain other agreements, we will be required to indemnify Transocean for any damages it may incur, and Transocean will not be required to indemnify us for any damages we may incur, in connection with its performance of services for us, except to the extent caused by Transocean’s gross negligence, willful misconduct or fraud.

Pursuant to the master services agreements and certain other agreements, Transocean or its affiliates will provide certain administrative, technical and management services to us and the RigCos. In connection therewith, we will be required to indemnify Transocean for any damages it may incur and Transocean will not be required to indemnify us for any damages we may incur in connection with its performance of these services except to the extent caused by Transocean’s gross negligence, willful misconduct or fraud. In addition, Transocean’s aggregate liability for such gross negligence or willful misconduct is limited to 10 times the annual services fees it receives under the applicable agreement. Our business will be harmed if Transocean and its affiliates fail to perform these services satisfactorily, if they cancel their agreements with us or if they stop providing these services to us. Please read “Certain Relationships and Related Party Transactions.”

Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.

Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services. Insurance premiums could increase and coverage may be unavailable in the future. U.S. government regulations may effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we may wish to operate in the future.

Our drilling contracts do not generally provide indemnification against loss of capital assets or loss revenues resulting from acts of terrorism, piracy or social unrest. We have limited insurance coverage for physical damage losses resulting from risks, such as terrorist acts, piracy, vandalism, sabotage, civil unrest, expropriation and acts of war, for our assets, and we do not carry insurance for loss of revenues resulting from such risks.

Risks Inherent in an Investment in Us

Transocean and its affiliates may compete with us, and we are limited in our ability to compete with Transocean.

Pursuant to the omnibus agreement that we and Transocean will enter into in connection with the closing of this offering, Transocean and its controlled affiliates (other than us, our subsidiaries and any publicly held affiliates of Transocean) generally will agree not to acquire, own, operate or contract for certain drilling rigs operating under drilling contracts of five or more years. In addition, we generally will agree not to acquire, own, operate or contract for certain drilling rigs operating under drilling contracts of less than five years. Relatively few drilling contracts have a term of five years or greater, particularly in the case of contracts that are not associated with newbuild units. As a result, we expect that Transocean will effectively have a right of first refusal on most drilling contract opportunities. Additionally, the omnibus agreement contains significant exceptions that may allow Transocean or any of its controlled affiliates to compete with us, which could harm our business. Furthermore, we have granted to Transocean a right of first offer on any proposed sale of any of our drilling rigs. Transocean has not granted us any such reciprocal right. As a result of these provisions, we will be unable to pursue many new business opportunities without Transocean’s consent. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement.”

 

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Although we control the RigCos, the directors and officers of those companies owe duties to the RigCos and their other owner, Transocean, which may conflict with the interests of us and our unitholders.

Conflicts of interest may arise as a result of the relationships between us and our unitholders, on the one hand, and the RigCos, and their other owner, Transocean, on the other hand. Transocean owns a 49 percent noncontrolling interest in each of the RigCos and a 100 percent ownership interest in the Transocean Member. Our directors have duties to influence, in our role as controlling owner, the decisions made by the RigCos in a manner beneficial to us. At the same time, the directors and officers of the RigCos have a duty to act for the RigCos in a manner beneficial to all of the RigCos’ owners, including Transocean. While we will have influence in our role as controlling owner of the RigCos, the directors and officers of the RigCos will exercise decisions of the RigCos and they will have a duty to act in the best interests of the RigCos. Our board of directors may resolve conflicts of interest between Transocean and us and, to the extent acting in our role as the controlling owner of the RigCos, has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in the best interest of us or our unitholders.

For example, conflicts of interest may arise in the following situations:

 

    the allocation of shared overhead expenses to the RigCos and us;

 

    the interpretation and enforcement of contractual obligations between us and our affiliates (other than the RigCos), on the one hand, and the RigCos, on the other hand;

 

    the determination and timing of the amount of cash to be distributed to the RigCos’ owners and the amount of cash to be reserved for the future conduct of the RigCos’ business;

 

    the decision as to whether the RigCos should make asset or business acquisitions or dispositions, and on what terms;

 

    the determination of the amount and timing of the RigCos’ capital expenditures;

 

    the determination of whether the RigCos should use cash on hand, borrow or issue equity to raise cash to finance maintenance or expansion capital projects, repay indebtedness, meet working capital needs or otherwise; and

 

    any decision we make to engage in business activities independent of, or in competition with, the RigCos.

Unitholders have limited voting rights.

Unlike the holders of common stock in a corporation, holders of common units have only limited voting rights on matters affecting our business. We expect to hold annual meetings of the members to elect one or more members of our board of directors and to vote on any other matters that are properly brought before the meeting. Common unitholders will be entitled to elect only four of the seven members of our board of directors. The Transocean Member in its sole discretion will appoint the remaining three directors and set the terms for which those directors will serve. Initially, all four of our elected directors will be elected at our annual meeting and will serve one-year terms. However, upon the election by the Transocean Member to classify our board of directors, the elected directors will be elected on a staggered basis and will serve for three-year terms. Our limited liability company agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Unitholders will have no right to elect the Transocean Member, and the Transocean Member may not be removed except by a vote of the holders of at least 66 23 percent of the outstanding common and subordinated units, including any units owned by the Transocean Member and its affiliates, voting together as a single class.

 

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The Transocean Member and its other affiliates own a controlling interest in us and have conflicts of interest and limited duties to us and our common unitholders, and the Transocean Member and its other affiliates may favor their own interests to the detriment of us and our other common unitholders.

Following this offering, Transocean will own the Transocean Member interest and a          percent limited liability company interest in us, assuming no exercise of the underwriters’ option to purchase additional common units, and will own and control the Transocean Member. We expect that all of our officers and certain of our directors will be directors and/or officers of Transocean and its affiliates and, as such, they will have fiduciary duties to Transocean that may cause them to pursue business strategies that disproportionately benefit Transocean or which otherwise are not in the best interests of us or our unitholders. Conflicts of interest may arise between Transocean and its affiliates on the one hand, and us and our unitholders on the other hand. As a result of these conflicts, Transocean and its affiliates may favor their own interests over the interests of our unitholders. Please read “—Our limited liability company agreement limits the duties that the Transocean Member and our directors and officers may have to our unitholders and restricts the remedies available to unitholders for actions taken by the Transocean Member or our directors and officers.” In addition to conflicts described elsewhere, these conflicts include, among others, the following situations:

 

    neither our limited liability company agreement nor any other agreement requires the Transocean Member or Transocean or its affiliates to pursue a business strategy that favors us or utilizes our assets, and Transocean’s officers and directors have a fiduciary duty to make decisions in the best interests of the shareholders of Transocean, which may be contrary to our interests;

 

    our limited liability company agreement provides that the Transocean Member may make determinations or take or decline to take actions without regard to our or our unitholders’ interests. Specifically, the Transocean Member may exercise its call right, preemptive rights or registration rights, consent or withhold consent to any merger or consolidation of the company, appoint any appointed directors or vote for the election of any elected director, vote or refrain from voting on amendments to our limited liability company agreement that require a vote of the outstanding units, voluntarily withdraw from the company, transfer (to the extent permitted under our limited liability company agreement) or refrain from transferring its units, the Transocean Member interest or incentive distribution rights or vote upon the dissolution of the company;

 

    the Transocean Member and our directors and officers have restricted their liabilities and duties they may have under the laws of the Marshall Islands, while also restricting the remedies available to our unitholders, and, as a result of purchasing common units, unitholders are treated as having agreed to the modified duties and to certain actions that may be taken by the Transocean Member and our directors and officers, all as set forth in our limited liability company agreement;

 

    the Transocean Member is entitled to reimbursement of all costs incurred by it and its affiliates for our benefit;

 

    our limited liability company agreement does not restrict us from paying the Transocean Member or its affiliates for any services rendered to us on terms that are fair and reasonable or entering into additional contractual arrangements with any of these entities on our behalf;

 

    the Transocean Member may exercise its right to call and purchase our common units if it and its affiliates own more than 80 percent of our common units; and

 

    the Transocean Member is not obligated to obtain a fairness opinion, nor will the unitholders be entitled to dissenter’s rights of appraisal, regarding the value of the common units to be repurchased by it upon the exercise of its limited call right.

Although a majority of our directors will over time be elected by common unitholders, the Transocean Member will likely have substantial influence on decisions made by our board of directors due to its ability to appoint certain of our directors and its significant ownership of our common units. Upon the consummation of this offering, Transocean will own              of our common units, representing              percent of our common units. If the underwriters’ option to purchase additional common units is exercised in full, Transocean will own

 

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             of our common units, representing              percent of our common units. Common unitholders that own 50 percent or more of our common units will have the ability to request that cumulative voting be in effect for the election of elected directors. Therefore, for so long as Transocean owns 50 percent or more of our common units, it will have the ability to request that cumulative voting be in effect for the election of elected directors, which would generally enable Transocean to elect one or more of the elected directors even after it owns less than 50 percent of our common units. Please read “Certain Relationships and Related Party Transactions,” “Conflicts of Interest and Duties” and “The Limited Liability Company Agreement.”

Our officers face conflicts in the allocation of their time to our business.

Our officers are not required to work full-time on our affairs and also perform services for Transocean. These other companies conduct substantial businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of our officers who also provide services to other companies, which could have a material adverse effect on our business, results of operations and financial condition. Please read “Management.”

Our limited liability company agreement limits the duties that the Transocean Member and our directors and officers may have to our unitholders and restricts the remedies available to unitholders for actions taken by the Transocean Member or our directors and officers.

Our limited liability company agreement provides that our board of directors will have the authority to oversee and direct our operations, management and policies on an exclusive basis. The Marshall Islands Limited Liability Company Act of 1996, or the Marshall Islands Act, states that a member or manager’s “duties and liabilities may be expanded or restricted by provisions in a limited liability company agreement.” As permitted by the Marshall Islands Act, our limited liability company agreement contains provisions that restrict the standards to which the Transocean Member and our directors and our officers may otherwise be held by Marshall Islands law. For example, our limited liability company agreement:

 

    provides that the Transocean Member may make determinations or take or decline to take actions without regard to our or our unitholders’ interests. The Transocean Member may consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or our unitholders. Decisions made by the Transocean Member will be made by persons acting only in the interest of its sole owner, Transocean. Specifically, the Transocean Member may, among other things, decide to exercise its call right, preemptive rights or registration rights, consent or withhold consent to any merger or consolidation of the company, appoint any directors or vote for the election of any director, vote or refrain from voting on amendments to our limited liability company agreement that require a vote of the outstanding units, voluntarily withdraw from the company, transfer (to the extent permitted under our limited liability company agreement) or refrain from transferring its units, the Transocean Member interest or incentive distribution rights or vote upon the dissolution of the company;

 

    provides that our directors and officers are entitled to make other decisions in “good faith,” meaning they subjectively believe that the decision is not adverse to the best interests of the company;

 

    generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of our board of directors and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our board of directors may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

 

    provides that neither the Transocean Member nor our officers or our directors will be liable for monetary damages to us, our members or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the Transocean Member, our directors or officers or those other persons engaged in actual fraud or willful misconduct.

 

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Please read “Conflicts of Interest and Duties—Duties.”

Fees and cost reimbursements, which certain affiliates of Transocean will determine for services provided to us and our subsidiaries, will be substantial, will be payable regardless of our profitability and will reduce our cash available for distribution to unitholders.

Pursuant to the master services agreements and the support and secondment agreements, we will pay fees for services provided to us and our subsidiaries by certain affiliates of Transocean, and will reimburse these entities for all expenses they incur on our behalf. These fees and expenses will include all costs and expenses incurred in providing certain management, advisory, technical and administrative services to our subsidiaries. In addition, we will pay Transocean a services fee for providing services to us, other than third-party costs and expenses. We expect the amount of these fees and expenses to be approximately $         million for the twelve months ending September 30, 2015. There is no cap on the amount of fees and cost reimbursements that we and our subsidiaries may be required to pay such affiliates of Transocean pursuant to these agreements. For a description of these agreements, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions.” The fees and expenses payable pursuant to these agreements will be payable without regard to our financial condition or results of operations. The payment of fees to and the reimbursement of expenses of affiliates of Transocean could adversely affect our ability to pay cash distributions to you.

Our limited liability company agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or the Transocean Member or acquiring the company, and even if public unitholders are dissatisfied, they will be unable to remove the Transocean Member without Transocean’s consent, unless Transocean’s ownership interest in us is decreased. The effect of such provisions could diminish the trading price of our common units.

Our limited liability company agreement contains provisions that may have the effect of discouraging a person or group from attempting to remove our current management or the Transocean Member.

 

    The unitholders will be unable initially to remove the Transocean Member without its consent because the Transocean Member and its affiliates will own sufficient units upon completion of this offering to be able to prevent its removal. The vote of the holders of at least 66 23 percent of all outstanding common and subordinated units voting together as a single class is required to remove the Transocean Member. Following the closing of this offering, Transocean will own          percent of the outstanding common and subordinated units, assuming no exercise of the underwriters’ option to purchase additional common units.

 

   

If the Transocean Member is removed without “cause” during the subordination period and units held by the Transocean Member and Transocean are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units, any existing arrearages on the common units will be extinguished, and the Transocean Member will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time. A removal of the Transocean Member under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Any conversion of the Transocean Member interest or incentive distribution rights would be dilutive to existing unitholders. Furthermore, any cash payment in lieu of such conversion could be prohibitively expensive. “Cause” is narrowly defined to mean that with respect to a director or officer, a court of competent jurisdiction has entered a final, non-appealable judgment finding such director or officer liable for intentional fraud or willful misconduct, and with respect to the Transocean Member, the Transocean Member is in breach of the limited liability company agreement or a court of competent jurisdiction has entered a final, non-appealable judgment finding the Transocean Member liable for intentional fraud or willful misconduct against us or our members, in their capacity as such. Cause does not include most cases of charges of

 

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poor business decisions, such as charges of poor management of our business by the directors appointed by the Transocean Member, so the removal of the Transocean Member because of the unitholders’ dissatisfaction with the Transocean Member’s decisions in this regard would most likely result in the termination of the subordination period.

 

    Common unitholders, including the Transocean Member as a holder of common units, will be entitled to elect only four of the seven members of our board of directors. The Transocean Member in its sole discretion will appoint the remaining three directors.

 

    Common unitholders that own 50 percent or more of our common units will have the ability to request that cumulative voting be in effect for the election of elected directors. Following such a request, Transocean would generally be able to elect one or more of the elected directors even after it owns less than 50 percent of our common units.

 

    The Transocean Member can elect to classify our board of directors at any time. Thereafter, the election of the four directors elected by unitholders would be staggered, meaning that the members of only one of three classes of our elected directors will be selected each year. In addition, the directors appointed by the Transocean Member will serve for terms determined by the Transocean Member.

 

    Our limited liability company agreement contains provisions limiting the ability of unitholders to call meetings of unitholders, to nominate directors and to acquire information about our operations as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

    There are no restrictions in our limited liability company agreement on our ability to issue additional equity securities.

 

    Although the Marshall Islands Act does not contain specific provisions regarding “business combinations” between limited companies organized under the laws of the Republic of Marshall Islands and “interested unitholders,” our limited liability company agreement includes provisions that impose additional restrictions on our engaging in a business combination with an interested unitholder for a period of three years after the date of the transaction in which the person became an interested unitholder, subject to certain exceptions. Transocean and certain of its transferees are exempt from these additional restrictions.

The effect of these provisions may be to diminish the price at which the common units will trade.

The control of the Transocean Member may be transferred to a third party without unitholder consent.

The Transocean Member may transfer its Transocean Member interest to a third party without the consent of the unitholders. In addition, our limited liability company agreement does not restrict the ability of the members of the Transocean Member from transferring their respective limited liability company interests in the Transocean Member to a third party.

The incentive distribution rights of the Transocean Member may be transferred to a third party without unitholder consent.

The Transocean Member may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If the Transocean Member transfers its incentive distribution rights to a third party, Transocean will have less incentive to grow our company and increase distributions. A transfer of incentive distribution rights by the Transocean Member could reduce the likelihood of Transocean selling or contributing additional assets to us, which in turn would impact our ability to grow our asset base.

 

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Substantial future sales of our common units in the public market could cause the price of our common units to fall.

We have granted registration rights to Transocean and certain of its affiliates. These unitholders have the right, subject to some conditions, to require us to file registration statements covering any of our common, subordinated or other equity securities owned by them or to include those securities in registration statements that we may file for ourselves or other unitholders. Upon the closing of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, Transocean will own          common units and          subordinated units and all of the incentive distribution rights (through its ownership of the Transocean Member). Following their registration and sale under the applicable registration statement, those securities will become freely tradable. By exercising their registration rights and selling a large number of common units or other securities, these unitholders could cause the price of our common units to decline.

You will experience immediate and substantial dilution of $         per common unit.

The initial public offering price of $         per common unit exceeds pro forma net tangible book value of $         per common unit. Based on the initial public offering price, you will incur immediate and substantial dilution of $         per common unit. This dilution results primarily because the assets contributed by the Transocean Member and its affiliates are recorded at their historical cost, and not their fair value, in accordance with U.S. GAAP. Please read “Dilution.”

We may issue additional equity securities, including securities senior to the common units, without unitholder approval, which would dilute existing unitholder ownership interests.

We may, without the approval of our unitholders, issue an unlimited number of additional units or other equity securities. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

    our unitholders’ proportionate ownership interest in us will decrease;

 

    the amount of cash available for distribution on each unit may decrease;

 

    because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

    the relative voting strength of each previously outstanding unit may be diminished; and

 

    the market price of the common units may decline.

Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.

During the subordination period, which we define elsewhere in this prospectus, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $         per unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units. Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash. See “Provisions of Our Limited Liability Company Agreement Relating to Cash Distributions—Subordination Period,” “—Distributions of Available Cash From Operating Surplus During the Subordination Period” and “—Distributions of Available Cash From Operating Surplus After the Subordination Period.”

 

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In establishing cash reserves, our board of directors may reduce the amount of cash available for distribution to you.

Our limited liability company agreement requires our board of directors to deduct from operating surplus cash reserves that it determines are necessary to fund our future operating expenditures. Our limited liability company agreement also permits our board of directors to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to our members. In addition, our limited liability company agreement requires our board of directors each quarter to deduct from operating surplus estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, which could reduce the amount of available cash for distribution. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by our board of directors at least once a year, provided that any change must be approved by the conflicts committee of our board of directors. These cash reserves will affect the amount of cash available for distribution to unitholders.

The Transocean Member has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time the Transocean Member and its affiliates own more than 80 percent of the common units, the Transocean Member will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price of our common units. The Transocean Member is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of this limited call right. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. For additional information about the limited call right, please read “The Limited Liability Company Agreement—Limited Call Right.”

At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, Transocean, which owns and controls the Transocean Member, will own          percent of our common units. At the end of the subordination period, assuming no additional issuances of common units, no exercise of the underwriters’ option to purchase additional common units and the conversion of our subordinated units into common units, Transocean will own          percent of our common units.

We can borrow money to pay distributions, which would reduce the amount of credit available to operate our business.

Our limited liability company agreement allows us to make working capital borrowings to pay distributions. Accordingly, if we have available borrowing capacity, we can make distributions on all our units even though cash generated by our operations may not be sufficient to pay such distributions. Any working capital borrowings by us to make distributions will reduce the amount of working capital borrowings we can make for operating our business. For more information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

Interest rates on future borrowings under credit facilities and on debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors

 

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who invest in our units, and a rising interest rate environment could have an adverse impact on the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment in us.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only          publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. Unitholders may not be able to resell their common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for our common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

    our quarterly distributions;

 

    our quarterly or annual results or those of other companies in our industry;

 

    announcements by us or our competitors of significant contracts or acquisitions;

 

    changes in accounting standards, policies, guidance, interpretations or principles;

 

    general economic conditions;

 

    the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

    future sales of our common units; and

 

    the other factors described in these “Risk Factors.”

Unitholders may have liability to repay distributions.

Under some circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under the Marshall Islands Act, we generally may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. The Marshall Islands Act provides that for a period of three years from the date of the impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated the Marshall Islands Act will be liable to the limited liability company for the distribution amount. Assignees who become substituted members are liable for the obligations of the assignor to make contributions to the company that are known to the assignee at the time it became a member and for unknown obligations if the liabilities could be determined from the limited liability company agreement. Liabilities to members on account of their limited liability company interest and liabilities that are non-recourse to the company are not counted for purposes of determining whether a distribution is permitted.

We have no history operating as a separate publicly traded company and will incur increased costs as a result of being a publicly traded company.

We have no history operating as a publicly traded company. As a publicly traded company, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the

 

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Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the New York Stock Exchange, or NYSE, require publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly traded company. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a public company.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded company, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

We also expect to incur significant expenses in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

We estimate that we will incur approximately $10 million of incremental external costs per year and additional internal costs associated with being a publicly traded company; however, it is possible that our actual incremental costs of being a publicly traded company will be higher than we currently estimate.

We will be a “controlled company” under the NYSE rules, and as such we are entitled to exemption from certain NYSE corporate governance standards, and you may not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.

After the consummation of this offering, Transocean will continue to control a majority of the voting power of our outstanding common units. As a result, we will be a “controlled company” within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50 percent of the voting power for the election of directors is held by another company or group is a “controlled company” and may elect not to comply with certain NYSE corporate governance requirements, including (1) the requirement that a majority of the board of directors consist of independent directors, (2) the requirement that the nominating committee be composed entirely of independent directors and have a written charter addressing the committee’s purpose and responsibilities, (3) the requirement that the compensation committee be composed entirely of independent directors and have a written charter addressing the committee’s purpose and responsibilities and (4) the requirement of an annual performance evaluation of the nominating and compensation committees. Accordingly, in the future you may not have the same protections afforded to stockholders of companies that are subject to all of the NYSE corporate governance requirements.

We have been organized as a limited liability company under the laws of the Republic of the Marshall Islands, which does not have a well-developed body of limited liability company law.

Our limited liability company affairs are governed by our limited liability company agreement and by the Marshall Islands Act. The provisions of the Marshall Islands Act resemble provisions of the limited liability company laws of a number of states in the United States, most notably Delaware. The Marshall Islands Act also provides that it is to be applied and construed to make it uniform with the laws of the State of Delaware and, so long as it does not conflict with the Marshall Islands Act or decisions of the Marshall Islands courts, the non-statutory law (or case law) of the State of Delaware is adopted as the law of the Marshall Islands. There have been, however, few, if any, court cases in the Marshall Islands interpreting the Marshall Islands Act, in contrast to Delaware, which has a fairly well-developed body of case law interpreting its limited liability company statute. Accordingly, we cannot predict whether Marshall Islands courts would reach the same conclusions as the courts in Delaware. For example, the rights of our unitholders and the duties of the Transocean Member and our

 

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directors and officers under Marshall Islands law are not as clearly established as under judicial precedent in existence in Delaware. As a result, unitholders may have more difficulty in protecting their interests in the face of actions by the Transocean Member and our officers and directors than would unitholders of a similarly organized limited liability company in the United States.

Because we are organized under the laws of the Marshall Islands, it may be difficult to serve us with legal process or enforce judgments against us, our directors or our management.

We are organized under the laws of the Marshall Islands. In addition, the Transocean Member is a Cayman Islands exempted company, and a majority of our directors and some of our officers are or will be non-residents of the United States, and all or a substantial portion of the assets of these non-residents are located outside the United States. As a result, it may be difficult or impossible for unitholders to bring an action against us or against these individuals in the United States if unitholders believe that their rights have been infringed under securities laws or otherwise. Even if unitholders are successful in bringing an action of this kind, the laws of the Marshall Islands and of other jurisdictions may prevent or restrict unitholders from enforcing a judgment against our assets or the assets of the Transocean Member or our directors or officers. For more information regarding the relevant laws of the Marshall Islands, please read “Enforcement of Civil Liabilities Against Foreign Persons.”

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units. Pursuant to the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as we are an emerging growth company and we may 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.

We will be required to disclose material changes made in our internal control over financial reporting on a quarterly basis and we will be required to assess the effectiveness of our controls annually. However, for as long as we are an “emerging growth company” under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. We could be an emerging growth company for up to five years. Please read “Summary—Implications of Being an Emerging Growth Company.” Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded limited liability company. We will prepare our consolidated financial statements in accordance with U.S. GAAP, but our internal controls over financial reporting may not meet all standards applicable to companies with publicly traded securities. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 will require us, among other things, to annually review and report on the effectiveness of our internal control over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2015. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our, or our independent registered public accounting firm’s, future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal controls over financial reporting will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

 

 

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In addition, Section 107 of the JOBS Act also 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. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.

We may take advantage of these reporting exemptions until we are no longer an “emerging growth company.” We cannot predict if investors will find our units less attractive because we will rely on these exemptions. If some investors find our units less attractive as a result, there may be a less active trading market for our units and our trading price may be more volatile.

Tax Risks

In addition to the following risk factors, you should read “Business—Taxation of the Company,” “Material U.S. Federal Income Tax Considerations” and “Non-United States Tax Considerations” for a more complete discussion of the expected material U.S. federal and non-U.S. income tax considerations relating to us and the ownership and disposition of our common units.

A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, reducing our cash available for distribution to you.

Some of our subsidiaries will be subject to tax in the jurisdictions in which they are organized or operate, reducing the amount of cash available for distribution. Our income taxes are based upon the applicable tax laws and tax rates in effect in the countries in which we operate and earn income as well as upon our operating structures in these countries.

In computing our tax obligations in these jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing authorities. We cannot assure you that upon review of these positions the applicable authorities will agree with our positions. If a tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries, or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure, or if we lose a material tax dispute in any country, additional tax could be imposed on our subsidiaries, further reducing the cash available for distribution.

For example, the Internal Revenue Service, or the IRS, has in prior periods challenged the transfer pricing used by Transocean for certain charters of drilling rigs—including our rigs—between its subsidiaries. Transocean has settled all challenges of this item for all years through its 2009 tax year with no material adjustments and it is currently contesting the proposed adjustments for its 2010 and 2011 tax years. However, if the IRS were to prevail in its challenge on this issue for Transocean’s 2010 and 2011 tax years, Transocean’s U.S. federal income tax liability could materially increase.

Our financial projections are based on transfer pricing policies that are substantively consistent with the resolution of this issue in Transocean’s prior tax years. If the IRS were to challenge our transfer pricing for bareboat charter payments and be successful in such a challenge, our U.S. federal income tax liability could increase and there could be a material reduction in our cash available for distribution.

In addition, changes in our operations could result in additional tax being imposed on us or our subsidiaries in jurisdictions in which operations are conducted. Please read “Business—Taxation of the Company.”

 

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A change in tax laws, treaties or regulations, or their interpretation, of any country in which we have operations, are incorporated or are resident could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.

Over time, we are likely to operate in multiple jurisdictions through our subsidiaries. Consequently, we are subject to changes in applicable tax laws, treaties or regulations in the jurisdictions in which we operate, which could include laws or policies directed toward companies organized in jurisdictions with low tax rates. A material change in the tax laws, treaties or regulations, or their interpretation, of any country in which we have significant operations, or in which we are incorporated or resident, could result in a higher effective tax rate on our worldwide earnings, reducing the cash available for distribution. Potential changes include, but are not limited to, the examples described below.

For example, we and certain of our subsidiaries are or will be resident for tax purposes in the United Kingdom. Changes to the income tax treaty in force between the United States and the United Kingdom could result in a higher effective tax rate on our worldwide earnings or require us to incur additional costs, reducing the cash available for distribution.

The United Kingdom could also enact changes to its tax laws or policies that could result in a higher effective tax rate on our worldwide earnings, thereby reducing the cash available for distribution. Such changes might include, but may not be limited to, changes in its taxation of earnings of subsidiaries or branches or withholding tax upon distributions to unitholders. Legislation is currently pending in the United Kingdom which would substantially increase the taxation of drilling contractors operating in the United Kingdom sector of the North Sea. As we will not initially have any operations in the North Sea, this change is not expected to impact us, but other future legislative changes could adversely impact us.

In addition, in the United States, legislative and budget proposals have been introduced that would substantially reform the U.S. international tax system. For example, in November 2013, the U.S. Senate Finance Committee introduced an international tax reform discussion draft that proposed a number of international tax changes, including a proposal that could limit the deduction for intercompany payments in certain circumstances. Any material change in tax laws resulting from this legislative proposal could result in a higher effective tax rate on our worldwide earnings, reducing the cash available for distribution.

Similarly, the Organisation for Economic Co-Operation and Development, or the OECD, issued an action plan in July 2013 that called for member states to take action to prevent “base erosion and profit shifting” in situations where payments are made between affiliates from a jurisdiction with high tax rates to a jurisdiction with lower tax rates. Any material change in tax laws or their interpretation, resulting from the OECD action plan could result in a higher effective tax rate on our worldwide earnings, reducing the cash available for distribution.

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

If we were treated as a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes, U.S. unitholders would be subject to adverse U.S. federal income tax consequences with respect to certain distributions on our common units and the gain, if any, realized on the sale, exchange or other disposition of our common units. We would be treated as a PFIC for any taxable year in which either (i) at least 75 percent of our gross income consists of “passive income” (generally, dividends, interest, gains from the sale or exchange of investment property and certain rents and royalties) or (ii) the average percentage (based on quarterly measurements) of the value of our assets that produce, or are held for the production of, “passive income” is at least 50 percent. For purposes of these tests, we are deemed to own our proportionate share of the assets and to receive directly our proportionate share of the income of any other corporation in which we own, directly or indirectly, at least 25 percent of the value of the stock. In addition, income derived from the performance of services does not constitute “passive income.” If we are treated as a PFIC for any taxable year during a

 

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U.S. unitholder’s holding period in our common units, then such U.S. unitholder could be subject to adverse U.S. federal income tax consequences for that year and all subsequent taxable years in which the U.S. unitholder holds common units, even if we cease to be a PFIC.

Based on our current and projected method of operation, and an opinion of our U.S. counsel, Baker Botts L.L.P., we believe that we will not be a PFIC for our 2014 taxable year, and we expect that we will not be treated as a PFIC for any future taxable year. We have received an opinion of our U.S. counsel in support of this position that concludes that the income our subsidiaries earn from our present drilling contracts should not constitute passive income for purposes of determining whether we are a PFIC. In addition, we have represented to our U.S. counsel that we expect that more than 25 percent of our gross income for our 2014 taxable year and each future year will arise from such drilling contracts or other income our U.S. counsel has opined does not constitute passive income, and more than 50 percent of the average value of our assets for each such year will be held for the production of such non-passive income. Assuming the composition of our income and assets is consistent with these expectations, and assuming the accuracy of other representations we have made to our U.S. counsel for purposes of their opinion, our U.S. counsel is of the opinion that we should not be a PFIC for our 2014 taxable year or any future year.

While we have received an opinion of our U.S. counsel in support of our position, our counsel has advised us that the conclusions in this area are not free from doubt and the U.S. Internal Revenue Service, or IRS, or a court could disagree with this opinion and our position. In addition, although we intend to conduct our affairs in a manner to avoid being classified as a PFIC with respect to each taxable year, we cannot assure you that the nature of our operations will not change in the future and that we will not become a PFIC in any taxable year. Please read “Material U.S. Federal Income Tax Considerations—U.S. Holders—PFIC Status and Significant Tax Consequences” for a more detailed discussion of the U.S. federal income tax consequences to U.S. unitholders if we are treated as a PFIC.

The ratio of dividend income to distributions on our common units is subject to business, economic and other uncertainties as well as tax reporting positions with which the IRS may disagree, which could result in a higher ratio of dividend income to distributions and adversely affect the value of our common units.

We estimate that less than          percent of the total cash distributions made to a purchaser of common units in this offering who owns those units from the date of this offering through December 31, 2016 will constitute dividend income. The remaining portion of the distributions will be treated first as a nontaxable return of capital to the extent of the purchaser’s tax basis in its common units and thereafter as capital gain. These estimates are based on certain assumptions that are subject to business, economic, regulatory, competitive and political uncertainties beyond our control. In addition, these estimates are based on current U.S. federal income tax law and tax reporting positions that we will adopt and with which the IRS could disagree. As a result of these uncertainties, these estimates may be incorrect and the actual percentage of total cash distributions that will constitute dividend income could be higher, and any difference could adversely affect the value of the common units. Please read “Material U.S. Federal Income Tax Considerations—U.S. Holders—Ratio of Dividend Income to Distributions.”

 

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FORWARD-LOOKING STATEMENTS

The statements included in this prospectus regarding future financial performance and results of operations and other future matters are forward-looking statements. Forward-looking statements include, but are not limited to, statements about the following subjects:

 

    forecasts of our ability to make cash distributions on the units and the amount of any borrowings that may be necessary to make such distributions;

 

    our results of operations and cash flow from operations, including revenues, revenue efficiency, costs and expenses;

 

    the offshore drilling market, including the impact of enhanced regulations in the jurisdictions in which we operate, supply and demand, utilization rates, dayrates, customer drilling programs, commodity prices, stacking of rigs, reactivation of rigs, effects of new rigs on the market and effects of declines in commodity prices and a downturn in the global economy or market outlook for our various geographical operating sectors and classes of rigs;

 

    customer drilling contracts, including contract backlog, force majeure provisions, contract commencements, contract extensions, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations;

 

    liquidity and adequacy of cash flows for our obligations, including our ability to meet any future capital expenditure requirements;

 

    debt levels, including impacts of a financial and economic downturn;

 

    expected compliance with financing agreements and the expected effect of restrictive covenants in such agreements;

 

    tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues;

 

    legal and regulatory matters, including results and effects of legal proceedings and governmental audits and assessments, outcomes and effects of internal and governmental investigations, customs and environmental matters;

 

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

 

    incurrence of cost overruns in the maintenance or other work performed on our drilling rigs;

 

    our ability to leverage Transocean’s relationship and reputation in the offshore drilling industry;

 

    our ability to purchase drilling rigs from Transocean in the future;

 

    our ability to make acquisitions that will enable us to increase our quarterly distributions per unit;

 

    insurance matters, including adequacy of insurance, renewal of insurance and insurance proceeds;

 

    effects of accounting changes and adoption of accounting policies; and

 

    investments in recruitment, retention and personnel development initiatives, pension plan and other postretirement benefit plan contributions, the timing of severance pay.

 

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Forward-looking statements included or incorporated by reference in this prospectus supplement and the accompanying prospectus are identifiable by use of the following words and other similar expressions, among others:

 

•     “anticipates”

  

•     “may”

•     “believes”

  

•     “might”

•     “budgets”

  

•     “plans”

•     “could”

  

•     “predicts”

•     “estimates”

  

•     “projects”

•     “expects”

  

•     “scheduled”

•     “forecasts”

  

•     “should”

Such statements are subject to numerous risks, uncertainties and assumptions, including, but not limited to:

 

    those described under “Risk Factors” in this prospectus;

 

    the adequacy of and access to sources of liquidity;

 

    our inability to renew drilling contracts at comparable dayrates;

 

    operational performance;

 

    the impact of regulatory changes;

 

    the cancellation of drilling contracts currently included in our reported contract backlog;

 

    increased political and civil unrest;

 

    the effect and results of litigation, regulatory matters, settlements, audits, assessments and contingencies; and

 

    other factors discussed in this prospectus.

The foregoing risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law.

 

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USE OF PROCEEDS

The common units being offered by this prospectus are solely for the account of the selling unitholder, the Transocean Member, including the common units offered if the underwriters exercise their option to purchase additional common units. We will not receive any proceeds from the sale of common units by the selling unitholder. The Transocean Member will pay all offering expenses, underwriting discounts, the structuring fee, financial advisory fees, selling commissions and brokerage fees, if any, incurred in connection with this offering and any exercise by the underwriters of their option to purchase additional units.

The Transocean Member has granted the underwriters a 30-day option to purchase up to          additional common units. Any exercise of such option will not affect the total number of our common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units outstanding following the completion of this offering.

 

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CAPITALIZATION

The following table sets forth:

 

    our historical cash and cash equivalents and capitalization as of March 31, 2014; and

 

    our as adjusted cash and cash equivalents and capitalization as of March 31, 2014, which reflects the completion of this offering and the other transactions described in the unaudited pro forma combined balance sheet included elsewhere in this prospectus.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical unaudited condensed combined financial statements of Transocean Partners LLC Predecessor and the notes thereto and our unaudited pro forma combined balance sheet and the notes thereto, in each case included elsewhere in this prospectus.

 

     March 31, 2014  
     Historical      As adjusted  
     (In millions)  

Cash and cash equivalents

   $       $ 15   
  

 

 

    

 

 

 

Five-Year Revolving Credit Facility

   $       $   

Working Capital Notes Payable

             144   

Members’ equity

     

Net investment

     2,320           

Common units—public

          

Common units—Transocean Member

          

Subordinated units—Transocean Member

          
  

 

 

    

 

 

 

Total members’ equity

             1,124   

Noncontrolling interest

             1,079   
  

 

 

    

 

 

 

Total equity

     2,320         2,203   
  

 

 

    

 

 

 

Total capitalization

   $ 2,320       $ 2,347   
  

 

 

    

 

 

 

 

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DILUTION

Dilution is the amount by which the offering price will exceed the net tangible book value per common unit after this offering. On a pro forma basis as of                     , 2014, our pro forma net tangible book value would have been $         million, or $         per common unit. This remains unchanged when adjusted for the sale by the Transocean Member of          common units in this offering at an assumed initial public offering price of $         per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

 

Assumed initial public offering price per common unit

   $                

Less: Pro forma net tangible book value per common unit before and after this offering(1)

  
  

 

 

 

Immediate dilution in net tangible book value per common unit to purchasers in this offering

   $     
  

 

 

 

 

(1) Determined by dividing the total number of units (         common units and          subordinated units, assuming no exercise of the underwriters’ option to purchase additional common units) to be issued to the Transocean Member and its affiliates for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities.

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, “Forward-Looking Statements” and “Risk Factors” should be read for information regarding statements that do not relate strictly to historical or current facts and regarding certain risks inherent in our business.

For additional information regarding our historical results of operations, please refer to our historical combined financial statements and accompanying notes included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our limited liability company agreement requires that we distribute all of our available cash quarterly. This requirement forms the basis of our cash distribution policy and reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. Under our current cash distribution policy, we intend to make minimum quarterly distributions on our common and subordinated units of $         per unit, or $         per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to the Transocean Member and its affiliates. However, other than the requirement in our limited liability company agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our board of directors has considerable discretion to determine the amount of our available cash each quarter. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves (including estimated maintenance and replacement capital expenditures) and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay minimum quarterly distributions to our unitholders.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

Although our limited liability company agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or any other rate, and we have no legal obligation to do so. Our cash distribution policy is subject to certain restrictions, as well as the discretion of our board of directors in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

 

    Our cash distribution policy may be subject to restrictions on cash distributions under our revolving credit facility or financing agreements that we may enter into in the future. Such restrictions may prohibit us from making cash distributions while an event of default has occurred and is continuing under such revolving credit facility, notwithstanding our cash distribution policy.

 

   

The amount of cash that we distribute and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our limited liability company agreement. Specifically, our board of directors will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any decision to establish cash reserves made by our board of directors in good faith will be binding on our unitholders. Our limited liability company agreement provides that in order for a determination by our board of directors to be

 

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considered to have been made in good faith, our board of directors must subjectively believe that the determination is not adverse to the best interests of the company.

 

    We will be required to make substantial capital expenditures to maintain and replace our fleet. These expenditures may fluctuate significantly over time, particularly as drilling rigs near the end of their useful lives. In order to minimize these fluctuations, we are required to deduct estimated, as opposed to actual, maintenance and replacement capital expenditures from the amount of cash that we would otherwise have available for distribution to our unitholders. In years when estimated maintenance and replacement capital expenditures are higher than actual maintenance and replacement capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance and replacement capital expenditures were deducted.

 

    Although our limited liability company agreement requires us to distribute all of our available cash, our limited liability company agreement, including provisions requiring us to make cash distributions, may be amended. During the subordination period, our limited liability company agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our board of directors can amend our limited liability company agreement without any unitholder approval. For a description of these limited circumstances, please read “The Limited Liability Company Agreement—Amendment of the Limited Liability Company Agreement—No Unitholder Approval.” After the subordination period has ended, our limited liability company agreement can be amended with the approval of a majority of the outstanding common units, including those held by Transocean. At the closing of this offering, Transocean will own approximately          percent of our common units (or          percent if the underwriters’ option to purchase additional common units is exercised in full) and all of our subordinated units. Please read “The Limited Liability Company Agreement—Amendment of the Limited Liability Company Agreement.”

 

    Under Section 40 of the Marshall Islands Act, we generally may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

    We may lack sufficient cash to pay distributions to our unitholders due to, among other things, changes in our business, including decreases in total operating revenues, decreases in dayrates, the loss of a drilling rig, increases in operating or general and administrative expenses, principal and interest payments on outstanding debt, taxes, working capital requirements, maintenance and replacement capital expenditures or anticipated cash needs. Please read “Risk Factors” for a discussion of these factors.

 

    Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of any future indebtedness, applicable partnership and limited liability company laws and other laws and regulations.

 

    If and to the extent our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

To the extent that our board of directors determines not to distribute the full minimum quarterly distribution on our common units with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid on the common units with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. The subordinated units will not accrue any arrearages. Any shortfall in the payment of the minimum quarterly distribution on the common units with respect to any quarter during the subordination period may decrease the likelihood that our quarterly distribution rate would increase in subsequent quarters. Please read “Provisions of Our Limited Liability Company Agreement Relating to Cash Distributions—Subordination Period.”

 

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Our Ability to Grow Depends on Our Ability to Access External Capital

Our limited liability company agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon our cash reserves and external financing sources, including borrowings under our Five-Year Revolving Credit Facility (under which no amounts will be drawn at the closing of this offering) and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our limited liability company agreement to distribute all of our available cash and our current cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. We anticipate that our revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read “Risk Factors—Risks Inherent in an Investment in Us—Increases in interest rates could adversely impact the price of our common units, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.”

Our Minimum Quarterly Distribution

Upon the consummation of this offering, our limited liability company agreement will provide for a minimum quarterly distribution of $         per unit for each whole quarter, or $         per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.” Quarterly distributions, if any, will be made within 60 days after the end of each calendar quarter to holders of record on or about the first day of each such month. We will not make distributions for the period that begins on                     , 2014 and ends on the day prior to the closing of this offering. We will adjust the amount of our distribution for the period from the completion of this offering through                     , 2014 based on the actual length of the period.

The amount of available cash needed to pay the minimum quarterly distribution on all of our common units and subordinated units, in each case to be outstanding immediately after this offering, for one quarter and on an annualized basis is summarized in the table below:

 

     No Exercise of Underwriters’
Option to Purchase

Additional Common Units
     Full Exercise of Underwriters’
Option to Purchase

Additional Common Units
 
     Aggregate Minimum
Quarterly Distributions
     Aggregate Minimum
Quarterly Distributions
 
(Dollars in thousands)    Number
of Units
   One
Quarter
     Annualized
(Four
Quarters)
     Number
of Units
   One
Quarter
     Annualized
(Four
Quarters)
 

Common units held by public

      $         $            $         $     

Common units held by Transocean

                 

Subordinated units held by Transocean

                 
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

Total

      $                    $                       $                    $                
  

 

  

 

 

    

 

 

    

 

  

 

 

    

 

 

 

 

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The Transocean Member will also hold the incentive distribution rights, which entitle it to increasing percentages, up to an aggregate maximum of 50 percent, of the cash we distribute in excess of $         per unit per quarter; provided that for any fiscal quarter in which the application of our distribution formula would result in the holders of the common units receiving, in the aggregate, less than a majority of the aggregate distribution of available cash for such quarter, then the distribution to the holders of the incentive distribution rights will be reduced, pro rata, to the extent necessary to cause the aggregate distribution to the holders of the common units to represent a majority of the aggregate distribution of available cash for such quarter.

During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read “Provisions of Our Limited Liability Company Agreement Relating to Cash Distributions—Subordination Period.” We cannot guarantee, however, that we will pay distributions on our common units at our minimum quarterly distribution rate or at any other rate in any quarter.

Although holders of our common units may pursue judicial action to enforce provisions of our limited liability company agreement, including those related to requirements to make cash distributions as described above, our limited liability company agreement provides that any determination made by our board of directors must be made in good faith and that any such determination will not be subject to any other standard imposed by the Marshall Islands Act or any other law, rule or regulation or at equity. Our limited liability company agreement provides that, in order for a determination by our board of directors to be made in “good faith,” our board of directors must subjectively believe that the determination is in, or not adverse to, the best interests of our company. In making such determination, our board of directors may take into account the totality of the circumstances or the totality of the relationships between the parties involved, including other relationships or transactions that may be particularly favorable or advantageous to us. Please read “Conflicts of Interest and Duties.”

The provision in our limited liability company agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our limited liability company agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves our board of directors establishes in accordance with our limited liability company agreement and the amount of available cash from working capital borrowings.

The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the limited liability company agreement, or in the event of a distribution of available cash from capital surplus. Please read “Provisions of Our Limited Liability Company Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels.”

In the following section, we present a table consisting of “Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015,” in which we provide our estimated forecast of our ability to generate sufficient cash available for distribution to support the full payment of our annualized minimum quarterly distribution of $         per unit on our common and subordinated units for the twelve months ending September 30, 2015.

Estimated Cash Available for Distribution for the Twelve Months Ending September 30, 2015

We forecast that our estimated cash available for distribution for the twelve months ending September 30, 2015 will be approximately $110 million. This amount would exceed by $         million the amount of cash available for distribution we must generate to support the payment of the minimum quarterly distributions for four quarters on our common and subordinated units, in each case to be outstanding immediately after this

 

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offering, for the twelve months ending September 30, 2015. Actual payments of distributions on the common units and the subordinated units are expected to be approximately $         million for the period between the estimated closing date of this offering (                    , 2014) and the end of the fiscal quarter in which the closing date of this offering occurs, and we anticipate that our cash available for distribution generated during such period will be sufficient to pay 100% of the minimum quarterly distribution on all of our common units and subordinated units with respect to such period. The number of outstanding units on which we have based our estimate does not include any common units that may be issued under the long-term incentive plan that we will adopt prior to the closing of this offering.

Management has prepared the forecast of estimated cash available for distribution for the twelve months ending September 30, 2015, and related assumptions set forth below to substantiate our belief that we will have sufficient cash available for distribution to pay the full minimum quarterly distributions on our common and subordinated units for the twelve months ending September 30, 2015. Please read “—Forecast Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast. This forecast is a forward-looking statement and should be read together with our historical financial statements and accompanying notes included elsewhere in this prospectus, our unaudited pro forma balance sheet and accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient cash available for distribution to pay the full minimum quarterly distributions on our common and subordinated units for the twelve months ending September 30, 2015. However, this information is not fact and should not be relied upon as being necessarily indicative of our future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this registration statement has been prepared by, and is the responsibility of, our management. Neither Ernst & Young LLP nor any other independent accountants have compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, neither Ernst & Young LLP nor any other independent accountants express an opinion or any other form of assurance with respect thereto. The report of Ernst & Young LLP included in this prospectus relates to our historical financial information. Such report does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated cash available for distribution.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the forecast or to update this forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this prospective financial information.

The following table sets forth our calculation of (a) our forecasted cash available for distribution for the twelve months ending September 30, 2015 and (b) Transocean Partners LLC Predecessor’s estimated cash available for distribution for the twelve months ended March 31, 2014 and for the year ended December 31, 2013. Throughout the forecast period, we have assumed that our principal assets will consist solely of our 51 percent controlling interest in each of the RigCos, which will own and operate the drilling rigs in our initial fleet. Unless otherwise noted, the financial information in the table below is presented before Transocean’s 49 percent noncontrolling interest in each of the RigCos. Noncontrolling interest for the historical periods presented in the table below has been calculated as if the noncontrolling interest described herein was in place at January 1, 2013.

 

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TRANSOCEAN PARTNERS LLC

ESTIMATED CASH AVAILABLE FOR DISTRIBUTION

 

    Forecast     Estimated  
    Transocean Partners
LLC
    Transocean Partners
LLC Predecessor
 
    Twelve Months Ending
September 30, 2015
    Twelve Months Ended
March 31, 2014
    Year Ended
December 31, 2013
 
    (In millions, except per unit amounts)  

Operating revenues:

     

Contract drilling revenues(1)(2)

  $ 567      $ 549      $ 517   

Other revenues

    10        9        9   
 

 

 

   

 

 

   

 

 

 

Total operating revenues

    577        558        526   
 

 

 

   

 

 

   

 

 

 

Costs and expenses:

     

Operating and maintenance(3)

    273        245        242   

Depreciation

    61        66        66   

General and administrative(4)

    21        10        10   
 

 

 

   

 

 

   

 

 

 

Total costs and expenses

    355        321        318   
 

 

 

   

 

 

   

 

 

 

Operating income

    222        237        208   

Interest income, net(5)

    1        4        4   
 

 

 

   

 

 

   

 

 

 

Income before income tax expense

    223        241        212   

Income tax expense

    18        25        23   
 

 

 

   

 

 

   

 

 

 

Net income

    205        216        189   

Plus:

     

Income tax expense

    18        25        23   

Interest income, net(5)

    (1     (4     (4

Depreciation expense

    61        66        66   
 

 

 

   

 

 

   

 

 

 

EBITDA(6)

    283        303        274   

Plus:

     

Amortization of prior certification costs and license fees

    4        3        3   

Non-cash recognition of royalty fees(7)

    23                 

Less:

     

Amortization of drilling contract intangible(1)

    15        18        18   

Amortization of pre-operating revenues(2)

    20        38        38   
 

 

 

   

 

 

   

 

 

 

Adjusted EBITDA(6)

    275        250        221   

Plus:

     

Planned out-of-service operating and maintenance expense(3)(8)

    12                 

Cash proceeds from pre-operating revenues associated with long-term receivables(9)

    13        24        23   

Less:

     

Estimated maintenance and replacement capital expenditures(8)

    69        69        69   

Cash interest income, net(5)

    (2     (4     (4

Cash income taxes

    8        5        6   
 

 

 

   

 

 

   

 

 

 

Cash available for distribution before noncontrolling interest

    225        204        173   

Cash available for distribution attributable to noncontrolling interest(4)

    115                 
 

 

 

   

 

 

   

 

 

 

Cash available for distribution by Transocean Partners LLC

  $ 110      $ 204      $ 173   
 

 

 

   

 

 

   

 

 

 

Aggregate minimum quarterly distributions

  $        $        $     

Excess of estimated cash available for distribution over aggregate minimum quarterly distributions

  $        $        $     

Distribution per unit (based on minimum quarterly distribution rate of $         per unit)

  $        $        $     

Distributions to public common unitholders(10)

  $        $        $     

Distributions to Transocean:

     

Common units(10)

  $        $        $     

Subordinated units

  $        $        $     

 

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(1) In our contract drilling revenues, we recognize amortization associated with our intangible liability attributed to the drilling contract for Development Driller III. We amortize drilling contract intangible revenues based on the cash flows projected over the contract period and include such revenues in contract drilling revenues on our combined statements of operations.

 

(2) Includes amortization of pre-operating revenues related to mobilization to initial locations and payments for customer-requested upgrades. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Performance and Other Key Indicators—Contract backlog.”

 

(3) Planned out-of-service operating and maintenance expense includes projected expenses related to a planned 21 day out of service period to conduct the special periodic survey (SPS) for Discoverer Inspiration, which is recognized in operating and maintenance expense, with no comparable activities in the twelve months ended March 31, 2014 and the year ended December 31, 2013.

 

(4) Estimated general and administrative expense includes general and administrative costs allocated by Transocean to our Predecessor. Forecasted general and administrative expense includes an estimated $10 million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded limited liability company, which are not included in the historical column. Cash available for distribution attributable to noncontrolling interest equals more than 49 percent of the cash available for distribution because the incremental general and administrative expenses that we expect to incur as a result of being a publicly traded limited liability company are borne entirely by us and not the RigCos.

 

(5) Includes interest expense resulting from the Transocean working capital notes payable and commitment fees related to our anticipated Five-Year Revolving Credit Facility. Also includes interest earned on long-term accounts receivable from our customers. We record long-term accounts receivable at their present value and recognize interest income on the outstanding balance using the effective interest method through the dates of payment.

 

(6) EBITDA and Adjusted EBITDA are non-GAAP financial measures. We define EBITDA as earnings before interest expense net of interest income, taxes, depreciation and amortization and Adjusted EBITDA as EBITDA adjusted for amortization of prior certification costs and license fees, non-cash recognition of royalty fees, amortization of the drilling contract intangible and amortization of pre-operating revenues. Adjusted EBITDA is used as a supplemental financial measure by management and external users of financial statements, such as investors, to assess our financial and operating performance. EBITDA and Adjusted EBITDA assist our management and investors by increasing the comparability of our performance from period to period and against the performance of other companies in our industry that provide EBITDA and Adjusted EBITDA information. This increased comparability is achieved by excluding the potentially disparate effects between periods or companies of interest, taxes, depreciation, amortization of prior certification costs and license fees, non-cash recognition of royalty fees, amortization of the drilling contract intangible and amortization of pre-operating revenues, which items are affected by various and possibly changing financing methods, capital structure and historical cost basis and which items may significantly affect net income between periods. We believe that including EBITDA and Adjusted EBITDA as financial and operating measures benefits investors in (a) selecting between investing in us and other investment alternatives and (b) monitoring our ongoing financial and operational strength in assessing whether to continue to hold common units.

 

     Neither EBITDA nor Adjusted EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with U.S. GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income and these measures may vary among other companies. Therefore, EBITDA and Adjusted EBITDA as presented above may not be comparable to similarly titled measures of other companies.

 

(7) Following this offering, the Transocean Member will retain the obligation for the payment of quarterly patent fees through the patent expiration, and we will recognize a non-cash expense for the fees paid on our behalf.

 

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(8) Estimated maintenance and replacement capital expenditures includes estimated planned out-of-service maintenance expenses, maintenance capital expenditures (including both in-service and out-of-service capital expenditures) and replacement capital expenditures. Our limited liability company agreement requires that an estimate of the maintenance and replacement capital expenditures necessary to maintain our asset base be subtracted from operating surplus each quarter, as opposed to amounts actually spent. Please read “Risk Factors—Risks Inherent in an Investment in Us—In establishing cash reserves, our board of directors may reduce the amount of cash available for distribution to you.”

 

(9) We record long-term accounts receivable at their present value and recognize interest income using the effective interest method through the date of payment. The cash proceeds from pre-operating revenues associated with long-term receivables represents the component of cash proceeds associated with revenues recognized during the period.

 

(10) Assumes the underwriters’ option to purchase additional common units is not exercised.

Quarterly Forecast Information

The following table presents our forecasted cash available for distribution for the twelve months ending September 30, 2015 on a quarterly basis. Please read “—Forecast Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast.

TRANSOCEAN PARTNERS LLC

ESTIMATED CASH AVAILABLE FOR DISTRIBUTION

 

    Forecast  
    Transocean Partners LLC  
    Three Months Ending        
    December 31,
2014
    March 31,
2015
    June 30,
2015
    September 30,
2015
    Twelve Months Ending
September 30, 2015
 
    (In millions, except per unit amounts)  

Operating revenues:

         

Contract drilling revenues(1)(2)

  $ 144      $ 130      $ 145      $ 148      $ 567   

Other revenues

    2        3        3        2        10   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating revenues

    146        133        148        150        577   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

         

Operating and maintenance(3)

    68        68        69        68        273   

Depreciation

    16        15        15        15        61   

General and administrative(4)

    5        6        5        5        21   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

    89        89        89        88        355   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

    57        44        59        62        222   

Interest income, net(5)

           1                      1   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

    57        45        59        62        223   

Income tax expense

    4        4        5        5        18   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

    53        41        54        57        205   

Plus:

         

Income tax expense

    4        4        5        5        18   

Interest income, net

           (1                   (1

Depreciation expense

    16        15        15        15        61   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA(6)

    73        59        74        77        283   

Plus:

         

Amortization of prior certification costs and license fees

    1        1        1        1        4   

Non-cash recognition of royalty fees(7)

    5        6        6        6        23   

Less:

         

Amortization of drilling contract intangible(1)

    4        4        4        3        15   

Amortization of pre-operating revenue(2)

    7        6        3        4        20   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA(6)

    68        56        74        77        275   

 

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    Forecast  
    Transocean Partners LLC  
    Three Months Ending        
    December 31,
2014
    March 31,
2015
    June 30,
2015
    September 30,
2015
    Twelve Months Ending
September 30, 2015
 
    (In millions, except per unit amounts)  

Plus:

         

Planned out-of-service operating and maintenance expense(3)(8)

    5        5        2               12   

Cash proceeds from pre-operating revenues associated with long-term receivables(9)

    5        4        2        2        13   

Less:

         

Estimated maintenance and replacement capital expenditures(8)

    18        17        17        17        69   

Cash interest income, net(5)

    (1     (1                   (2

Cash income taxes

    2        2        2        2        8   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash available for distribution before noncontrolling interest

    59        47        59        60        225   

Cash available for distribution attributable to noncontrolling interest(4)

    30        24        30        31        115   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Cash available for distribution by Transocean Partners LLC

  $ 29      $ 23      $ 29      $ 29      $ 110   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Aggregate minimum quarterly distributions

  $        $        $        $        $     

Excess (shortfall) of estimated cash available for distribution over aggregate minimum quarterly distribution

  $        $        $        $        $     

Distribution per unit (based on minimum quarterly distribution rate of $         per unit)

  $        $        $        $        $     

Distributions to public common unitholders(10)

  $        $        $        $        $     

Distributions to Transocean:

         

Common units(10)

  $        $        $        $        $     

Subordinated units

  $        $        $        $        $     

 

(1) In our contract drilling revenues, we recognize amortization associated with our intangible liability attributed to the drilling contract for Development Driller III. We amortize drilling contract intangible revenues based on the cash flows projected over the contract period and include such revenues in contract drilling revenues on our combined statements of operations.

 

(2) Includes amortization of pre-operating revenues related to mobilization to initial locations and payments for customer-requested upgrades. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Performance and Other Key Indicators—Contract backlog.”

 

(3) Planned out-of-service operating and maintenance expense includes projected expenses related to a planned 21 day out of service period to conduct the SPS for Discoverer Inspiration, which is recognized in operating and maintenance expense.

 

(4) Forecasted general and administrative expense includes an estimated $10 million in incremental general and administrative expenses that we expect to incur annually as a result of being a publicly traded limited liability company. Cash available for distribution attributable to noncontrolling interest equals more than 49 percent of the cash available for distribution because the incremental general and administrative expenses that we expect to incur as a result of being a publicly traded limited liability company are borne entirely by us and not the RigCos.

 

 

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(5) Includes interest expense resulting from the Transocean working capital notes payable and commitment fees related to our Transocean Five-Year Revolving Credit Facility. Also includes interest earned on long-term accounts receivable from our customers. We record long-term accounts receivable at their present value and recognize interest income on the outstanding balance using the effective interest method through the dates of payment.

 

(6) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please read note 6 to the preceding table for additional information.

 

(7) Following this offering, the Transocean Member will retain the obligation for the payment of quarterly patent fees through the patent expiration, and we will recognize a non-cash expense for the fees paid on our behalf.

 

(8) Estimated maintenance and replacement capital expenditures includes estimated planned out-of-service maintenance expenses, maintenance capital expenditures (including both in-service and out-of-service capital expenditures) and replacement capital expenditures. Our limited liability company agreement requires that an estimate of the maintenance and replacement capital expenditures necessary to maintain our asset base be subtracted from operating surplus each quarter, as opposed to amounts actually spent. Please read “Risk Factors—Risks Inherent in an Investment in Us—In establishing cash reserves, our board of directors may reduce the amount of cash available for distribution to you.”

 

(9) We record long-term accounts receivable at their present value and recognize interest income using the effective interest method through the date of payment. The cash proceeds from pre-operating revenues associated with long-term receivables represents the component of cash proceeds associated with revenues recognized during the period.

 

(10) Assumes the underwriters’ option to purchase additional common units is not exercised.

Forecast Assumptions and Considerations

Basis of Presentation

The accompanying financial forecast and related notes of Transocean Partners LLC present the forecasted results of operations of Transocean Partners LLC for the twelve months ending September 30, 2015, based on the assumption that:

 

    we will own a 51 percent interest in each of the RigCos during the forecast period;

 

    we will issue (a) to the Transocean Member (i)          common units and          subordinated units, representing a 100 percent limited liability company interest in us, (ii) the non-economic Transocean Member interest and (iii) all of the incentive distribution rights, which will entitle the Transocean Member to increasing percentages of the cash we distribute in excess of $         per unit per quarter, and (b) to an affiliate of Transocean notes payable of approximately $         million for cash proceeds of $         million and initial working capital; and

 

    the Transocean Member will sell          common units to the public in this offering, representing a          percent limited liability company interest in us.

Summary of Significant Forecast Assumptions

Contract Drilling Revenues. For the twelve months ending September 30, 2015, we forecast contract drilling revenues of $567 million, compared to contract drilling revenues of $549 million and $517 million for the twelve months ended March 31, 2014 and the year ended December 31, 2013, respectively. Our forecast of contract drilling revenues is based on projected dayrates multiplied by the projected revenue efficiency and the projected total number of operating days under the contract during the twelve months ending September 30, 2015. Forecasted operating revenues assume that all of our drilling rigs are operational, excluding the planned 21 day out of service period for Discoverer Inspiration, throughout the twelve months ending September 30, 2015.

 

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The following table summarizes our projected dayrates and revenue efficiency for the twelve months ending September 30, 2015 as well as dayrates and revenue efficiency for the year ended December 31, 2013.

 

    Location   Current Contract Terms and Dayrates     Projected
Revenue
Efficiency(4)
    Actual 2013
Revenue
Efficiency(4)
 

Rig Name

    Contract Start
Date(1)
  Completion
Date(1)
  Projected
Dayrate(2)
    2013
Dayrate(3)
     

Drillships

             

Discoverer Inspiration

  USA
(Gulf of Mexico)
  March 2010

April 2015

  March 2015

April 2020

  $

$

526,000

585,000

  

  

  $

 

522,000

  

  

    95     93

Discoverer Clear Leader

  USA
(Gulf of Mexico)
  August 2009
September 2014
  September 2014

September 2018

  $

$

569,000

590,000

(5) 

  

  $

 

567,000

  

  

    95     77

Semisubmersible

             

Development Driller III

  USA
(Gulf of Mexico)
  November 2009   November 2016   $ 428,000      $ 424,000        94     90

 

(1) Contract start and completion dates are estimated. Contracts could be longer in duration because of a provision that allows the customer to finish drilling a well-in-progress and due to other factors not under our control. New contracts do not commence until the prior contract has been completed.

 

(2) Represents the maximum contractual operating dayrate, which is subject to change due to cost escalations. The dayrate includes pre-operating revenues of $22,000 per day for the Discoverer Inspiration contract ending in March 2015 and $19,000 per day for the Discoverer Clear Leader contract ending in September 2014 for various customer requested upgrades and equipment. The dayrate excludes amortization of drilling contract intangible revenues as well as all other pre-operating revenues that terminate at the end of the rigs’ current contracts.

The average dayrate actually earned over the term of the contract will reflect various reduced rates received under the contract as a result of time billed according to standby rates, waiting-on-weather rates, maintenance rates or other similar rates, which typically are less than the contract dayrate. In addition, the amount shown does not reflect incentive programs, which are typically based on the rig’s operating performance against a performance curve. During the forecast period, we have assumed that we will not earn any additional revenues under incentive programs, and the projected dayrates do not assume any escalations.

For the three months ended March 31, 2014, average daily revenue was $533,200, $579,700 and $467,200 for Discoverer Inspiration, Discoverer Clear Leader and Development Driller III, respectively, and the revenue efficiency of the rigs in our initial fleet was 98 percent. For the twelve months ended March 31, 2014, average daily revenue was $511,100, $490,100 and $456,800 for Discoverer Inspiration, Discoverer Clear Leader and Development Driller III, respectively, and the revenue efficiency of the rigs in our initial fleet was 91 percent. For the year ended December 31, 2013, average daily revenue was $500,700, $450,500 and $416,100 for Discoverer Inspiration, Discoverer Clear Leader and Development Driller III, respectively, and the revenue efficiency of the rigs in our initial fleet was 86 percent.

 

(3) Revenue efficiency is defined as actual contract drilling revenues for the measurement period divided by the maximum revenue calculated for the measurement period, expressed as a percentage. Maximum revenue is defined as the greatest amount of contract drilling revenues the drilling unit could earn for the measurement period, excluding amounts related to incentive provisions. Our revenue efficiency rate varies due to revenues earned under alternative contractual dayrates, such as a waiting-on-weather rate, repair rate, standby rate, force majeure rate or zero rate, that may apply under certain circumstances.

 

(4) The dayrate for the remainder of the contract is linked to the standard West Texas Intermediate crude oil price with a floor of $40 per barrel resulting in a contract dayrate of $400,000 and a ceiling of $70 per barrel resulting in a contract dayrate of $500,000, before cost escalation adjustments of $50,000 per day and pre-operating revenues of $19,000 per day.

The projected revenue efficiency for each drilling rig is based on Transocean’s past experience with these drilling rigs and similar drilling rigs. We do not forecast the number of days during which the rig will earn standby rates, waiting-on-weather rates, maintenance rates or other similar rates. We do include in our forecast

 

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planned out-of-service days. During the twelve months ending September 30, 2015, we have assumed 21 days during which Discoverer Inspiration will earn no dayrate as it undergoes a planned shipyard for routine maintenance.

Revenue efficiency was lower in the twelve months ended March 31, 2014 and the year ended December 31, 2013 relative to the year ended December 31, 2012 due to unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment for each of the rigs in our initial fleet. Total revenue efficiency of our initial fleet in the years ended December 31, 2012 and 2011 was 97 percent and 93 percent, respectively. Total revenue efficiency of our initial fleet in the three months ended March 31, 2014 and 2013 was 98 percent and 77 percent, respectively. For the years ended December 31, 2012 and 2011, revenue efficiency for Discoverer Inspiration was 98 percent and 91 percent, respectively; for Discoverer Clear Leader was 97 percent and 97 percent, respectively; and for Development Driller III was 97 percent and 89 percent, respectively. The increase in revenue efficiency for Development Driller III in 2012 relative to 2011 was due to less unplanned downtime in 2012 for repairs to the blowout preventer and other subsea equipment.

A one percent change in annual revenue efficiency of our initial fleet would cause a corresponding change in the cash available for distribution attributable to Transocean Partners LLC of approximately $2 million.

Our drilling contracts entitle us to cost escalation in dayrates to compensate us for specific cost increases as reflected in certain publicly available cost indices and certain changes in our actual operating expenses. We have not assumed any cost escalations in our projected dayrates during the forecast period.

In addition to recurring contracted dayrates, we may also receive mobilization and demobilization fees for drilling rigs before and after their drilling assignments, and may also receive reimbursement of costs incurred by us at the customer’s request for additional supplies, personnel and other services not covered by the contracted dayrate. For the purpose of this forecast, we have not included any revenue or costs associated with additional customer requests, and we have not included any new mobilization fees or demobilization fees in the forecast as no drilling rigs are expected to be mobilizing or demobilizing during the twelve months ending September 30, 2015.

In connection with Transocean’s business combination with GlobalSantaFe Corporation in November 2007, Transocean acquired Development Driller III, which had a drilling contract that included fixed dayrates for future contract drilling services that were below the then-existing market dayrates available for similar contracts as of the date of the business combination. Accordingly, Transocean recognized a contract intangible liability, representing the estimated fair value of the drilling contract, which is expected to be completed in November 2016. We amortize drilling contract intangible revenues of $42,000 per day over the remainder of the contract period and include such revenues in contract drilling revenues.

Other Revenues. Our forecast assumes estimated other revenues of $10 million during the twelve months ending September 30, 2015, compared to $9 million in the twelve months ended March 31, 2014 and the year ended December 31, 2013 for our Predecessor. The assumed reimbursable revenues consist primarily of revenues related to customer required services and equipment and other reimbursable costs. Other revenues are primarily offset by related costs.

Operating and Maintenance Expense. We estimate that we will have operating and maintenance expenses of $273 million during the twelve months ending September 30, 2015 compared to $245 million in the twelve months ended March 31, 2014 and $242 million in the year ended December 31, 2013 for our Predecessor. Forecasted operating and maintenance expenses assume that all of our drilling rigs are operational throughout the twelve months ending September 30, 2015. Our forecast also assumes the cost level of operating in the U.S. Gulf of Mexico, where our drilling rigs are expected to be located during the twelve months ending September 30, 2015, is consistent with the cost level for this region during the twelve months ended March 31, 2014 and the year ended December 31, 2013, as adjusted for expected inflation. The forecast takes into account increases in

 

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crewing and other labor related costs driven predominantly by an increase in demand for qualified and experienced officers and crew and inflation.

All three of our drilling units are equipped with Transocean’s patented dual-activity technology. We entered into patent license agreements with Transocean for the use of the patented technology through the expiration of the patents in May 2016. Under the license agreements, we paid to Transocean an aggregate original license cost of $20 million, recorded in other assets. For the twelve months ended March 31, 2014 and the year ended December 31, 2013, our Predecessor’s amortized deferred license costs were $3 million, recorded in operating and maintenance expense. Under the license agreements, we are required to pay to Transocean quarterly royalty fees of between three percent and five percent of revenues. In the twelve months ended March 31, 2014 and the year ended December 31, 2013, our Predecessor paid a total of $19 million for royalty fees and recognized a corresponding expense, recorded in operating and maintenance expense. Following this offering, the Transocean Member will retain the obligation for the payment of the quarterly royalty fees through the patent expiration, and we will recognize a corresponding non-cash expense for the fees paid on our behalf.

Depreciation Expense. We estimate that our depreciation expense will be $61 million for the twelve months ending September 30, 2015 compared to $66 million in the twelve months ended March 31, 2014 and in the year ended December 31, 2013 for our Predecessor. Forecasted depreciation expense assumes that no drilling rigs are purchased or sold during the twelve months ending September 30, 2015. We have accounted for depreciation expense in a manner consistent with the historical presentation in the combined statements of operations of Transocean Partners LLC Predecessor. Drilling rigs and equipment are recorded at historical cost less accumulated depreciation. The cost of a drilling rig less its estimated residual value is depreciated on a straight-line basis over its estimated remaining useful life, which we estimate as of July 1, 2014, to be 30, 31 and 30 years for each of Discoverer Clear Leader, Discoverer Inspiration and Development Driller III, respectively.

General and Administrative Expense. Forecasted general and administrative expenses for the twelve months ending September 30, 2015 are based on the following assumptions:

 

    we will incur approximately $11 million of costs and fees pursuant to the master services agreements that we will enter into with Transocean. These costs and fees are consistent with our Predecessor’s costs and fees of approximately $10 million for such services during the twelve months ended March 31, 2014 and the year ended December 31, 2013. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Master Services Agreements”; and

 

    we will incur approximately $10 million in incremental expenses annually as a result of being a publicly traded limited liability company. These expenses will include costs associated with annual reports to unitholders, tax return preparation, investor relations, registrar and transfer agent fees, audit fees, legal fees, incremental director and officer liability insurance costs and executive and director compensation.

Interest Expense (Income), Net. Estimated interest expense (income), net for the twelve months ending September 30, 2015 consists of interest income of $2 million, net of interest expense of $1 million.

Interest income includes $2 million of interest earned on long-term accounts receivable from our customers. We record long-term accounts receivable at their present value and recognize interest income on the outstanding balance using the effective interest method through the dates of payment. In the twelve months ended March 31, 2014 and the year ended December 31, 2013, our Predecessor recognized $4 million of interest income on long-term accounts receivable from customers.

Interest expense consists primarily of a commitment fee related to our anticipated $300 million undrawn Five-Year Revolving Credit Facility and interest expense resulting from the Transocean working capital notes payable, based on an average outstanding principal amount of $19 million. In the twelve months ended March 31, 2014 and the year ended December 31, 2013, our Predecessor did not have any interest expense.

 

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Income Tax Expense. Forecasted income tax expense is based on the tax laws and applicable rates in the countries where operations are conducted and income is earned. The forecasted tax expense for the twelve months ending September 30, 2015 is primarily comprised of the expected U.S. federal income taxes on the U.S. operations of Discoverer Clear Leader, Discoverer Inspiration and Development Driller III. Rig movement between taxing jurisdictions and their respective operating structures could affect the provision for income tax expense. We have assumed that the drilling rigs will remain in the U.S. Gulf of Mexico throughout the twelve months ending September 30, 2015.

In computing our tax obligations, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing authorities. We cannot assure you that upon review of these positions the applicable authorities will agree with our positions. For example, the IRS has in prior periods challenged the transfer pricing used by Transocean for certain charters of drilling rigs, including our drilling rigs, between its subsidiaries. Transocean has settled all challenges of this item for all years through its 2009 tax year with no material adjustments and it is currently contesting the proposed adjustments for its 2010 and 2011 tax years. In addition, the forecasted income tax expense assumes that our transfer pricing policies for charters of drilling rigs between our subsidiaries will be consistent with Transocean’s transfer pricing policies. However, if the IRS successfully challenged our transfer pricing policies, it could result in a material increase in our U.S. federal income tax expense. Please read “Risk Factors—Tax Risks—A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries could result in a higher tax rate on our worldwide earnings, reducing our cash available for distribution to you” for additional information.

Estimated Maintenance and Replacement Capital Expenditures. Our limited liability company agreement requires our board of directors to deduct from operating surplus each quarter an estimate of the present value of the average quarterly maintenance and replacement capital expenditures to be incurred in the future, as opposed to deducting the actual maintenance and replacement capital expenditures incurred during the reporting period. The intent of this adjustment is to smooth the disparities in operating surplus that would be caused by fluctuating maintenance and replacement capital expenditures, such as major capital expenditures associated with equipment recertifications and special classification surveys and drilling rig replacement, with the objective to deliver a consistent, stable distribution. The actual cost of capital expenditures and the replacement of the drilling rigs in our fleet will depend on the factors that cause such out of service time, including, but not limited to, equipment condition, supplier costs, regulatory and classification requirements, prevailing market conditions for contracting opportunities and the availability and cost of financing for replacement of assets, at the time of replacement. Our board of directors, with the approval of the conflicts committee, may determine that one or more of our reserve assumptions should be revised, which could cause our board of directors to change the amount of estimated maintenance and replacement capital expenditures. We may elect to finance some or all of future maintenance and replacement capital expenditures through the issuance of additional common units which could be dilutive to our existing unitholders. Please read “Risk Factors—Risks Inherent in Our Business—We must make substantial capital and operating expenditures to maintain the operating capacity of our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness and to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to execute our growth plan, each of which could negatively affect our financial condition, result of operations and cash flows and reduce cash available for distribution. In addition, each quarter we are required to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted.”

Our initial annual estimated maintenance and replacement capital expenditures will be $69 million per year. This is attributable to the substantial capital expenditures we are required to make to maintain our fleet over time and the cost to replace our drilling rigs at the end of their useful lives, including financing costs. This estimate is based on a number of assumptions including estimated financing costs, the remaining useful lives of the drilling rigs, estimated out of service costs, drilling rig replacement values based on current market conditions and the residual value of the drilling rigs.

 

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Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending September 30, 2015 is based on the following assumptions related to regulatory, industry and economic factors:

 

    no material nonperformance or credit-related defaults by suppliers, customers or vendors;

 

    no new regulation or any interpretation of existing regulations or governmental action that, in either case, would be materially adverse to our business;

 

    no material accidents, environmental incidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events;

 

    no major adverse change in the markets in which we operate resulting from oil production disruptions, reduced demand for oil or significant changes in the market prices of oil;

 

    no material changes to applicable tax laws, treaties or the interpretation thereof in the markets in which we operate and no material tax disputes; and

 

    no material changes to market, regulatory and overall economic conditions or in prevailing interest rates.

Noncontrolling Interest. The noncontrolling interest reflects the 49 percent noncontrolling interest in each RigCo that is owned by the Transocean Member, as those entities will be controlled and consolidated by us. We have assumed that our and the Transocean Member’s respective ownership interests in the RigCos remains unchanged during the forecast period.

Forecast of Compliance with Debt Covenants. Our ability to make distributions could be affected if we and Transocean do not remain in compliance with the covenants in our respective financing agreements. We have assumed that we and Transocean will be in compliance with all of the covenants in such financing agreements during the forecast period. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a further description of our financing agreements.

 

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PROVISIONS OF OUR LIMITED LIABILITY COMPANY AGREEMENT RELATING TO CASH DISTRIBUTIONS

Distributions of Available Cash

General

Within 60 days after the end of each quarter, beginning with the quarter ending                     , 2014, we will distribute all of our available cash (defined below) to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of this offering through                     , 2014, based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for each fiscal quarter, all cash on hand at the end of that quarter (including our proportionate share of cash on hand of subsidiaries we do not wholly own, including the RigCos):

 

    less, the amount of cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own, including the RigCos) established by our board of directors to:

 

    provide for the proper conduct of our business (including reserves for future capital expenditures and for anticipated future debt service requirements) subsequent to that quarter;

 

    comply with applicable law, any debt instruments or other agreements; and

 

    provide funds for distributions to our unitholders for any one or more of the next four quarters (provided that our board of directors may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from paying the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

 

    plus, all cash on hand on the date of determination of available cash resulting from cash distributions received after the end of such quarter on equity interests in any person other than a subsidiary held by us or any of our subsidiaries, which distributions are paid by such person in respect of operations conducted by such person during such quarter;

 

    plus, if our board of directors so determines, all or any portion of the cash on hand (including our proportionate share of cash on hand of subsidiaries we do not wholly own, including the RigCos) on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

The purpose and effect of the last bullet point above is to allow our board of directors, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our limited liability company agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to members and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

Intent to Distribute the Minimum Quarterly Distribution

We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $         per unit, or $         per unit per year, to the extent we have sufficient cash on hand to pay the distribution after we establish cash reserves and pay fees and expenses, including reimbursements of expenses to the Transocean Member and its affiliates. The amount of available cash from operating surplus needed to pay the minimum quarterly distribution for one quarter on all units outstanding immediately after this offering is approximately $         million. However, there is no guarantee that we will pay

 

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the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

Incentive Distribution Rights

The Transocean Member currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50 percent, of the cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter; provided that for any fiscal quarter in which the application of our distribution formula would result in the holders of the common units receiving, in the aggregate, less than a majority of the aggregate distribution of available cash for such quarter, then the distribution to the holders of the incentive distribution rights will be reduced, pro rata, to the extent necessary to cause the aggregate distribution to the holders of the common units to represent a majority of the aggregate distribution of available cash for such quarter. The maximum distribution of 50 percent does not include any distributions the Transocean Member or its affiliates may receive on common or subordinated units that they own. Please read “—Incentive Distribution Rights” below for additional information.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either being paid from “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Operating Surplus

We define operating surplus as:

 

    $         million (as described below); plus

 

    all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge, currency hedge or interest rate hedge prior to its stipulated settlement or termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge, currency hedge or interest rate hedge; plus

 

    working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

 

    cash distributions on equity interests in any entity other than subsidiaries held by us or any of our subsidiaries received after the end of the quarter but on or before the date of determination of operating surplus for that quarter in respect of operations of such entity and not from sources that would constitute interim capital transactions if paid by us; plus

 

    cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

 

    all of our operating expenditures (as defined below), which includes estimated maintenance and replacement capital expenditures, after the closing of this offering; less

 

    the amount of cash reserves established by our board of directors to provide funds for future operating expenditures; less

 

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    all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve month period with the proceeds of additional working capital borrowings; less

 

    any cash loss realized on dispositions of assets acquired using investment capital expenditures.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) issuances of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements and (iv) capital contributions received.

We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of the Transocean Member and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts, currency hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract, currency hedge contract or commodity hedge contract prior to the stipulated settlement or termination date specified therein will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract, currency hedge contract or commodity hedge contract and amounts paid in connection with the initial purchase of an interest rate hedge contract, currency hedge contract or a commodity hedge contract will be amortized at the life of such interest rate hedge contract, currency hedge contract or commodity hedge contract), maintenance and replacement capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

 

    repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

 

    payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

 

    expansion capital expenditures, investment capital expenditures or actual maintenance and replacement capital expenditures (which are discussed in further detail under “—Capital Expenditures” below);

 

    payment of transaction expenses (including taxes) relating to interim capital transactions;

 

    distributions to our members; or

 

    repurchases of limited liability company interests (excluding repurchases we make to satisfy obligations under employee benefit plans).

 

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Capital Surplus

Capital surplus is defined in our limited liability company agreement as any distribution of available cash in excess of our operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 

    borrowings other than working capital borrowings;

 

    sales of our equity and debt securities;

 

    sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and

 

    capital contributions received.

Characterization of Cash Distributions

Our limited liability company agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our limited liability company agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. Our limited liability company agreement treats a distribution of capital surplus as the repayment of the consideration for the issuance of units, which is as a return of capital. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Maintenance and replacement capital expenditures are those cash expenditures required to maintain, over the long-term, the operating capacity, asset base or operating income of the company. In our limited liability company agreement, we refer to these expenditures as “maintenance capital expenditures.” Examples of maintenance and replacement capital expenditures include expenditures associated with maintenance, modifying an existing drilling rig or acquiring a new drilling rig to the extent such expenditures are incurred to maintain the operating capacity, asset base or operating income of the fleet. Maintenance and replacement capital expenditures will also include interest and related fees (including periodic net payments under related interest rate swap agreements) on debt incurred and distributions on equity issued (including the amount of any incremental distributions made to the holders of our incentive distribution rights) to finance the construction of a capital improvement and paid in respect of the construction period, which we define as the period beginning on the date that we enter into a binding construction contract and ending on the earlier of the date that the capital improvement commences commercial service or the date that the capital improvement is abandoned or disposed of. Debt incurred to pay or equity issued to fund construction period interest payments, and distributions on such equity (including the amount of any incremental distributions made to the holders of our incentive distribution rights), will also be considered maintenance and replacement capital expenditures.

Expansion capital expenditures are cash expenditures incurred to increase, over the long-term, the operating capacity, asset base or operating income of the company. Examples of expansion capital expenditures include expenditures associated with acquiring a new drilling rig or improving an existing drilling rig to the extent those expenditures increase, over the long term, the operating capacity, asset base or operating income of the company.

Investment capital expenditures are those capital expenditures that are neither maintenance and replacement capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of equity securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes.

 

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Capital expenditures that are made in part for maintenance and replacement capital purposes, investment capital purposes and/or expansion capital purposes will be allocated as maintenance and replacement capital expenditures, investment capital expenditures or expansion capital expenditures by our board of directors (with the concurrence of the conflicts committee).

Because maintenance and replacement capital expenditures can be very large and vary significantly in timing, the amount of actual maintenance and replacement capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and available cash for distribution to our unitholders if we subtracted actual maintenance and replacement capital expenditures from operating surplus each quarter. Accordingly, to eliminate the effect on operating surplus of these fluctuations, our limited liability company agreement requires that an amount equal to an estimate of the average quarterly maintenance and replacement capital expenditures necessary to maintain the operating capacity of or the revenue generated by our capital assets over the long-term be subtracted from operating surplus each quarter, as opposed to the actual amounts spent. In our limited liability company agreement, we refer to these estimated maintenance and replacement capital expenditures to be subtracted from operating surplus as “estimated maintenance capital expenditures.” The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by our board of directors at least once a year, provided that any change must be approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance and replacement capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will affect the fleet. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance and replacement capital expenditures, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance and replacement capital expenditures in calculating operating surplus will have the following effects:

 

    it will reduce the risk that actual maintenance and replacement capital expenditures in any one quarter will be large enough to make operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter and subsequent quarters;

 

    it may reduce the need for us to borrow to pay distributions;

 

    it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to the Transocean Member; and

 

    it will reduce the likelihood that a large maintenance and replacement capital expenditure in a period will prevent Transocean from being able to convert some or all of its subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, mitigating the effect of the actual payment of the expenditure on any single period.

Subordination Period

General

Our limited liability company agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $         per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from

 

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prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending                     , 2019, that each of the following tests are met:

 

    aggregate distributions of available cash from operating surplus on the outstanding common units, subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units with respect to each of the three consecutive, non-overlapping four-quarter periods immediately preceding such date equaled or exceeded $             (the annualized minimum quarterly distribution) on all outstanding common units and subordinated units and any other outstanding units that are senior or equal in right of distribution to the subordinated units, in each case in respect of such periods;

 

    the adjusted operating surplus for each of the three consecutive, non-overlapping four-quarter periods immediately preceding such date equaled or exceeded $             (the annualized minimum quarterly distribution) on all of the common units, subordinated units and any other units that are senior or equal in right of distribution to the subordinated units that were outstanding during such periods on a fully diluted weighted average basis; and

 

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration Upon Removal of the Transocean Member

In addition, if the unitholders remove the Transocean Member other than for cause and no units held by the Transocean Member and its affiliates voted in favor of the removal:

 

    the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis;

 

    all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end;

 

    the holders of the incentive distribution rights (initially, the Transocean Member) will have the right to convert their incentive distribution rights into common units or to receive cash in exchange for those interests.

Expiration of the Subordination Period

When the subordination period ends upon satisfaction of the test described above or upon removal of the Transocean Member as described above, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for any period consists of:

 

    operating surplus generated with respect to that period (excluding any amounts attributable to the item described in the first bullet point under the caption “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

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    any net increase in working capital borrowings with respect to that period; less

 

    any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

    any net decrease in working capital borrowings with respect to that period; plus

 

    any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

 

    any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods.

Distributions of Available Cash From Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

    first, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

    second, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

    third, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

    thereafter, in the manner described in “—Incentive Distribution Rights” below.

The preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

Distributions of Available Cash From Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

    first, to all unitholders, pro rata, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

    thereafter, in the manner described in “—Incentive Distribution Rights” below.

The preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

Transocean Member Interest

The Transocean Member owns a transferrable non-economic limited liability company interest in us, which does not entitle it to receive cash distributions. However, the Transocean Member owns common units, subordinated units and incentive distribution rights (as further explained below) in us and may in the future own other equity securities in us and is, or will be, entitled to receive distributions on any such interests.

Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution

 

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levels have been achieved. The Transocean Member will hold the incentive distribution rights following completion of this offering. The incentive distribution rights may be transferred separately from the Transocean Member interest. Any transfer by the Transocean Member of the incentive distribution rights would not change the percentage allocations of quarterly distributions with respect to such rights.

If for any quarter:

 

    we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

    we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders in the following manner:

 

    first, 100 percent to all unitholders, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

 

    second, 85 percent to all unitholders, pro rata, and 15 percent to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

 

    third, 75 percent to all unitholders, pro rata, and 25 percent to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “third target distribution”); and

 

    thereafter, 50 percent to all unitholders, pro rata, and 50 percent to the holders of the incentive distribution rights, pro rata.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The percentage interests set forth above assume that we do not issue additional classes of equity securities. Notwithstanding the foregoing, for any quarter in which the application of the formula above would result in the common unitholders receiving, in the aggregate, less than a majority of the aggregate distribution of available cash for such quarter, then the distribution to the holders of the incentive distribution rights will be reduced, pro rata, to the extent necessary to cause the aggregate distribution to the common unitholders to represent a majority of the aggregate distribution of available cash for such quarter.

Percentage Allocations of Available Cash From Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the unitholders and the holders of the incentive distribution rights in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the holders of the incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume that there are no arrearages on common units.

 

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     Total Quarterly Distribution
Target Amount
   Marginal Percentage
Interest in Distributions
 
        Unitholders     Holders of IDRs  

Minimum Quarterly Distribution

   $               100       

First Target Distribution

   above $                 up to $              100       

Second Target Distribution

   above $                 up to $              85     15

Third Target Distribution

   above $                 up to $              75     25

Thereafter

   above $              50     50

Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

    first, to all unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

 

    second, to the common unitholders, pro rata, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

 

    thereafter, as if such distributions were from operating surplus.

The preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

The limited liability company agreement treats a distribution of capital surplus as the repayment of the consideration for the issuance of the units, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution had to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the Transocean Member to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we reduce the minimum quarterly distribution and the target distribution levels to zero, we will then make all future distributions 50 percent to the holders of units and 50 percent to the holders of the incentive distribution rights (initially, the Transocean Member; provided that for any fiscal quarter in which the application of our distribution formula would result in the holders of the common units receiving, in the aggregate, less than a majority of the aggregate distribution of available cash for such quarter, then the distribution to the holders of the incentive distribution rights shall be reduced, pro rata, to the extent necessary to cause the aggregate distribution to the holders of the common units to represent a majority of the aggregate distribution of available cash for such quarter).

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

 

    the minimum quarterly distribution;

 

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    the target distribution levels;

 

    the initial unit price; and

 

    the arrearages per common unit in payment of the minimum quarterly distribution on the common units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50 percent of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine our subordinated units or subdivide our subordinated units, using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the limited liability company agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will apply the proceeds of liquidation in the manner set forth below.

If, as of the date three trading days prior to the announcement of the proposed liquidation, the average closing price for our common units for the preceding 20 trading days (the “current market price”) is greater than the sum of:

 

    any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; plus

 

    the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation);

then the proceeds of the liquidation will be applied as follows:

 

    first, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the current market price of our common units;

 

    second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the current market price of our common units; and

 

    thereafter, 50 percent to all unitholders, pro rata, 50 percent to holders of incentive distribution rights.

Notwithstanding the foregoing, if the application of the formula above would result in the common unitholders receiving, in the aggregate, less than a majority of the aggregate proceeds of liquidation, then the application of the proceeds of liquidation to the holders of the incentive distribution rights shall be reduced, pro rata, to the extent necessary to cause the aggregate application of the proceeds of liquidation to the common unitholders to represent a majority of the aggregate proceeds of liquidation.

If, as of the date three trading days prior to the announcement of the proposed liquidation, the current market price of our common units is equal to or less than the sum of:

 

    any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; plus

 

    the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation);

 

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then the proceeds of the liquidation will be applied as follows:

 

    first, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation);

 

    second, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

    third, to the subordinated unitholders, until we distribute for each outstanding subordinated unit an amount equal to the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation); and

 

    thereafter, 50 percent to all unitholders, pro rata, 50 percent to holders of incentive distribution rights.

Notwithstanding the foregoing, if the application of the formula above would result in the common unitholders receiving, in the aggregate, less than a majority of the aggregate proceeds of liquidation, then the application of the proceeds of liquidation to the holders of the incentive distribution rights shall be reduced, pro rata, to the extent necessary to cause the aggregate application of the proceeds of liquidation to the common unitholders to represent a majority of the aggregate proceeds of liquidation.

The immediately preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

 

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

The following table presents, in each case for the periods and as of the dates indicated, selected historical financial and operating data of Transocean Partners LLC Predecessor, which includes the operating results, assets and liabilities of the drilling rigs in our initial fleet. The selected historical financial data of Transocean Partners LLC Predecessor as of and for the years ended December 31, 2013 and 2012 are derived from the audited combined financial statements of Transocean Partners LLC Predecessor, prepared in accordance with U.S. GAAP, which are included elsewhere in this prospectus. The summary historical financial data of Transocean Partners LLC Predecessor as of March 31, 2014 and for the three months ended March 31, 2014 and 2013 are derived from the unaudited condensed combined financial statements of Transocean Partners LLC Predecessor, prepared in accordance with U.S. GAAP, which are included elsewhere in this prospectus.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical combined financial statements of Transocean Partners LLC Predecessor and the notes thereto, our unaudited pro forma combined balance sheet and the notes thereto and our forecasted results of operations for the twelve months ending September 30, 2015, in each case included elsewhere in this prospectus.

Our financial position, results of operations and cash flows could differ from those that would have resulted if we operated autonomously or as an entity independent of Transocean in the periods for which historical financial data are presented below, and such data may not be indicative of our future operating results or financial performance.

 

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     Three months ended March 31,     Years ended December 31,  
            2014                   2013                   2013                   2012         
    

(In millions, except fleet data)

 

Statement of operations data

        

Operating revenues

   $ 148      $ 116      $ 526      $ 569   

Costs and expenses

     79        76        318        293   

Operating income

     69        40        208        276   

Interest income

                   4        3   

Income before income tax expense

     69        40        212        279   

Income tax expense

     6        4        23        24   

Net income

     63        36        189        255   

Balance sheet data (at end of period)

        

Cash and cash equivalents

   $      $      $      $   

Property and equipment, net

     2,005        2,082        2,038        2,098   

Total assets

     2,432        2,506        2,468        2,557   

Total long-term liabilities

     78        117        87        131   

Total net investment

     2,320        2,351        2,344        2,388   

Cash flow data

        

Cash provided by operating activities

   $ 70      $ 73      $ 239      $ 340   

Cash used in investing activities(1)

     (1            (4     (15

Cash used in financing activities

     (69     (73     (235     (325

Fleet data

        

Number of rigs

     3        3        3        3   

Average age of fleet at end of period (in years)

     4.3        3.3        4.1        3.1   

Operating days(2)

     270        270        1,095        1,098   

Average daily revenue(3)

   $ 526,700      $ 403,900      $ 455,800      $ 491,500   

Revenue efficiency(4)

     98     77     86     97

Rig utilization(5)

     100     100     100     99

Other financial data

        

EBITDA(6)

   $ 85      $ 56      $ 274      $ 341   

Adjusted EBITDA(6)

     72        43        221        287   

 

(1) Represents cash used to fund capital expenditures.

 

(2) An operating day is defined as a calendar day during which a rig is contracted to earn a dayrate during the firm contract period after commencement of operations.

 

(3) Average daily revenue is defined as contract drilling revenues earned per operating day. Our average daily revenue fluctuates relative to market conditions and our revenue efficiency. Average daily revenues increased in the three months ended March 31, 2014 relative to the three months ended March 31, 2013 due to an increase in revenue efficiency resulting from lower unplanned downtime and an increase in operating dayrates associated with cost escalation adjustments that reflect increases in our operating costs. Average daily revenues decreased in the year ended December 31, 2013 relative to the year ended December 31, 2012 due to a decrease in revenue efficiency resulting from unplanned downtime. This decrease was slightly offset by an increase in operating dayrates associated with cost escalation adjustments that reflect increases in our operating costs.

 

(4)

Revenue efficiency is defined as actual contract drilling revenues for the measurement period divided by the maximum revenue calculated for the measurement period, expressed as a percentage. Maximum revenue is defined as the greatest amount of contract drilling revenues the drilling unit could earn for the measurement period, excluding amounts related to incentive provisions. Our revenue efficiency rate varies due to revenues earned under alternative contractual dayrates, such as a waiting-on-weather rate, repair rate,

 

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  standby rate, force majeure rate or zero rate, that may apply under certain circumstances. Revenue efficiency increased in the three months ended March 31, 2014 relative to the three months ended March 31, 2013 resulting from lower unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment. Revenue efficiency was lower in the year ended December 31, 2013 relative to the year ended December 31, 2012 due to unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment.

 

(5) Rig utilization is defined as the total number of operating days divided by the total number of rig calendar days in the measurement period, expressed as a percentage. Our rig utilization rate declines as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.

 

(6) Please read “—Non-GAAP Measures” below for a reconciliation of EBITDA and Adjusted EBITDA to net income, the most directly comparable U.S. GAAP measure.

Non-GAAP Measures

For a discussion of the non-GAAP financial measures EBITDA and Adjusted EBITDA, please read “Summary—Non-GAAP Financial Measures.” The following table presents a reconciliation of net income, the most directly comparable U.S. GAAP financial measure, to EBITDA and Adjusted EBITDA for each of the periods indicated.

 

     Three months ended
March 31,
     Years ended
December 31,
 
         2014              2013              2013             2012      
    

(In millions)

 

Net income

   $ 63       $ 36       $ 189      $ 255   

Plus:

          

Income tax expense

     6         4         23        24   

Interest income(1)

                     (4     (3

Depreciation expense

     16         16         66        65   
  

 

 

    

 

 

    

 

 

   

 

 

 

EBITDA

     85         56         274        341   

Plus:

          

Amortization of prior certification costs and license fees

     1         1         3        3   

Non-cash recognition of royalty fees(2)

                              

Less:

          

Amortization of drilling contract intangible

     4         4         18        19   

Amortization of pre-operating revenues

     10         10         38        38   
  

 

 

    

 

 

    

 

 

   

 

 

 

Adjusted EBITDA

   $ 72       $ 43       $ 221      $ 287   
  

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) Includes interest earned on long-term accounts receivable from our customers. We record long-term accounts receivable at their present value and recognize interest income on the outstanding balance using the effective interest method through the dates of payment.

 

(2) Following this offering, the Transocean Member will retain the obligation for the payment of quarterly patent fees through the patent expiration, and we will recognize a non-cash expense for the fees paid on our behalf.

 

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

You should read the following discussion of our financial condition and results of operations in conjunction with the historical unaudited condensed combined financial statements and related notes and the audited combined financial statements and related notes of our Predecessor included elsewhere in this prospectus. Among other things, those combined financial statements include more detailed information regarding the basis of presentation for the following information.

This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those discussed below. Factors that could cause or contribute to such differences include, but are not limited to, those identified below and those discussed in the section entitled “Risk Factors” included elsewhere in this prospectus.

The following discussion assumes that our business was operated as a separate entity prior to its inception. The interest in the assets, liabilities and operations of our Predecessor will be acquired in a reorganization under common control and have therefore been recorded at Transocean’s historical values. The unaudited condensed combined financial statements and the audited combined financial statements, the results of which are discussed below, have been carved out of the consolidated financial statements of Transocean, which operated the rigs in our fleet during the periods presented. Transocean’s drilling rigs and other assets, liabilities, revenues and expenses that do not relate to the rigs to be acquired by us are not included in our unaudited condensed combined financial statements and our audited combined financial statements. Our financial position, results of operations and cash flows reflected in our unaudited condensed combined financial statements and our audited combined financial statements include all expenses allocable to our business, but may not be indicative of those that would have been incurred had we operated as a separate public entity for all periods presented or of future results.

The combined net assets and results of operations of 100 percent ownership in each of two ultra-deepwater drillships (Discoverer Inspiration and Discoverer Clear Leader) and one semi-submersible drilling rig (Development Driller III) are collectively referred to as our “Predecessor.”

Business

We are a growth-oriented limited liability company recently formed by Transocean, one of the world’s largest offshore drilling contractors, to own, operate and acquire modern, technologically advanced offshore drilling rigs. Our initial assets consist of a 51 percent interest in three ultra-deepwater drilling rigs that are currently operating in the U.S. Gulf of Mexico. We generate revenue through contract drilling services, which involves contracting our mobile offshore drilling fleet, related equipment and work crews on a dayrate basis to drill oil and gas wells.

The historical results discussed below, and the unaudited condensed combined financial statements and related notes and the audited combined financial statements and related notes of what we refer to as “our Predecessor” included elsewhere in this prospectus, represent 100 percent of the combined results of operations of all three drilling rigs in our initial fleet.

Upon the completion of this offering, we will own a 51 percent interest in each of the RigCos. We will control each RigCo through our ownership of the majority of its shares or limited liability company interests. The Transocean Member will own the remaining 49 percent noncontrolling interest in each of the RigCos.

The RigCos own the following three drilling rigs:

 

    the ultra-deepwater drillship Discoverer Inspiration, which commenced operations in 2010 and is currently under a contract with Chevron through April 2020;

 

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    the ultra-deepwater drillship Discoverer Clear Leader, which commenced operations in 2009 and is currently under a contract with Chevron through September 2018; and

 

    the ultra-deepwater semi-submersible drilling rig Development Driller III, which commenced operations in 2009 and is currently under a contract with BP through November 2016.

As discussed below under “—Operating Results—Items You Should Consider When Evaluating Our Historical Financial Performance and Assessing Our Future Prospects,” upon closing of this offering, we will only own a 51 percent interest in each of the RigCos and thus will be entitled to only 51 percent of the RigCos’ distributions, if any. References in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” to the “RigCos” when used in a historical context refer to Transocean Partners LLC Predecessor, and when used in the present tense or prospectively refers to the RigCos and their subsidiaries.

Upon the closing of this offering, our interest in the RigCos will represent our only cash-generating asset. We anticipate growing by acquiring additional drilling rigs and operations indirectly through additional rig-owning and rig-operating entities and by acquiring additional equity interests in the RigCos.

Our contract drilling services operations are currently concentrated in the U.S. Gulf of Mexico. Although rigs can be moved from one region to another, the cost of moving rigs and the availability of rig-moving vessels may cause the supply and demand balance to fluctuate somewhat between regions. Still, significant variations between regions do not tend to persist long term because of rig mobility. We consider that our fleet operates in a single, global market for the provision of contract drilling services. The location of our rigs and the allocation of resources to operate or upgrade rigs are determined by the activities and needs of our customers.

Our Drilling Contracts

The current contracts to provide offshore drilling services associated with the drilling rigs in our initial fleet were individually negotiated and vary in their terms and provisions. We generally obtain most of our drilling contracts through competitive bidding against other contractors and direct negotiations with operators. Our current drilling contracts provide for payment on a dayrate basis, with higher rates for periods while the drilling unit is operating and lower rates or zero rates for periods of mobilization or when drilling operations are interrupted or restricted by equipment breakdowns, adverse environmental conditions or other conditions some of which are beyond our control. Our current drilling contracts extend over a stated term, but may be longer in duration depending on wells in progress and other factors not under our control.

Our current drilling contracts with customers are cancellable at the option of the customer upon payment of an early termination payment. Such payments, however, may not fully compensate us for the loss of the contract. Our contracts also provide for either automatic termination, or termination at the option of the customer typically without the payment of any termination fee, under various circumstances such as non-performance, in the event of extended downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events. Some of these events are beyond our control. The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional term. Our contracts also include a provision that allows the customer to extend the contract to finish drilling a well-in-progress.

Performance and Other Key Indicators

Contract backlog. Contract backlog represents the maximum contract drilling revenues that can be earned considering the contractual operating dayrate in effect during the firm contract period and represents the basis for the maximum revenues in our revenue efficiency measurement. To determine maximum revenues for purposes of calculating revenue efficiency, however, we include the revenues earned for mobilization, demobilization and contract preparation or other incentive provisions, which are excluded from the amounts presented for contract backlog.

 

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Our contract backlog includes only firm commitments, which are represented by signed drilling contracts. The contractual operating dayrate may be higher than the actual dayrate we ultimately receive or an alternative contractual dayrate, such as a waiting-on-weather rate, repair rate, standby rate or force majeure rate, may apply under certain circumstances. The contractual operating dayrate may also be higher than the actual dayrate we ultimately receive because of a number of factors, including rig downtime or suspension of operations. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.

At June 12, 2014, the contract backlog and current contract terms, dayrates and customers for our initial fleet were as follows:

 

     Total      Remainder
of 2014
     For the years ending December 31,      Thereafter  

Contract Backlog

           2015          2016          2017       
     (in millions)  

Drillships

                 

Discoverer Inspiration

   $ 1,208       $ 106       $ 198       $ 214       $ 210       $ 480   

Discoverer Clear Leader

   $ 900       $ 106       $ 215       $ 212       $ 215       $ 152   

Semi-Submersible

                 

Development Driller III

   $ 384       $ 87       $ 156       $ 141       $       $   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 2,492       $ 299       $ 569       $ 567       $ 425       $ 632   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

     Current Contract Terms, Dayrates and Customers  

Rig Name

   Start Date(1)    Completion Date(1)    Dayrate(2)      Customer  

Drillships

           

Discoverer Inspiration

   March 2010

April 2015

   March 2015

April 2020

   $

$

526,000

585,000

  

  

    

 

Chevron

Chevron

  

  

Discoverer Clear Leader

   August 2009

September 2014

   September 2014

September 2018

   $

$

569,000

590,000

(3) 

  

    

 

Chevron

Chevron

  

  

Semisubmersible

           

Development Driller III

   November 2009    November 2016    $ 428,000         BP   

 

(1) Contract start and completion dates are estimated. Contract start dates depend on delivery by shipyards, testing and customer acceptance. Contracts could be longer in duration depending on wells in progress and other factors not in our control. Completion dates represent our current estimate of the earliest date the contract for each rig is likely to expire. New contracts do not commence until the prior contract has been completed.

 

(2) Represents the maximum contractual operating dayrate, which is subject to change due to cost escalations. The dayrate includes pre-operating revenues of $22,000 per day for the Discoverer Inspiration contract ending in March 2015 and $19,000 per day for the Discoverer Clear Leader contract ending in September 2014 for various customer requested upgrades and equipment. The dayrate excludes amortization of drilling contract intangible revenues as well as all other pre-operating revenues that terminate at the end of the rigs’ current contracts.

The average dayrate actually earned over the term of the contract will reflect various reduced rates received under the contract as a result of time billed according to standby rates, waiting-on-weather rates, maintenance rates or other similar rates, which typically are less than the contract dayrate. In addition, the amount shown does not reflect incentive programs, which are typically based on the rig’s operating performance against a performance curve. Please read “—Average Daily Revenue” and “—Revenue Efficiency” for additional information.

 

(3) The dayrate for the remainder of the contract is linked to the standard West Texas Intermediate crude oil price with a floor of $40 per barrel resulting in a contract dayrate of $400,000 and a ceiling of $70 per barrel resulting in a contract dayrate of $500,000, before cost escalation adjustments of $50,000 per day and pre- operating revenues of $19,000 per day.

 

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The actual amounts of revenues earned and the actual periods during which revenues are earned will differ from the amounts and periods shown in the tables above due to various factors, including shipyard and maintenance projects, unplanned downtime and other factors that result in lower applicable dayrates than the full contractual operating dayrate. Additional factors that could affect the amount and timing of actual revenue to be recognized include customer liquidity issues and contract terminations, which are available to our customers under certain circumstances.

Average daily revenue. Average daily revenue is defined as contract drilling revenues earned per operating day. An operating day is defined as a calendar day during which a rig is contracted to earn a dayrate during the firm contract period after commencement of operations. The average daily revenue for our initial fleet was as follows:

 

Average Daily Revenue

   Three months ended      Years ended December 31,  
   March 31,
2014
     December 31,
2013
     March 31,
2013
           2013                  2012        

Drillships

              

Discoverer Inspiration

   $ 533,200       $ 472,400       $ 490,600       $ 500,700       $ 519,200   

Discoverer Clear Leader

   $ 579,700       $ 407,200       $ 419,100       $ 450,500       $ 527,900   

Semi-Submersible

              

Development Driller III

   $ 467,200       $ 461,500       $ 302,100       $ 416,100       $ 437,000   

Our average daily revenue fluctuates relative to market conditions and our revenue efficiency.

Average daily revenues increased in the three months ended March 31, 2014 relative to the three months ended December 31, 2013 due to an increase in revenue efficiency resulting from lower unplanned downtime and an increase in operating dayrates associated with cost escalation adjustments that reflect increases in our operating costs.

Average daily revenues increased in the three months ended March 31, 2014 relative to the three months ended March 31, 2013 due to an increase in revenue efficiency resulting from lower unplanned downtime and an increase in operating dayrates associated with cost escalation adjustments that reflect increases in our operating costs.

Average daily revenues decreased in the year ended December 31, 2013 relative to the year ended December 31, 2012 due to a decrease in revenue efficiency resulting from unplanned downtime. This decrease was slightly offset by an increase in operating dayrates associated with cost escalation adjustments that reflect increases in our operating costs.

Revenue efficiency. Revenue efficiency is defined as actual contract drilling revenues for the measurement period divided by the maximum revenue calculated for the measurement period, expressed as a percentage. Maximum revenue is defined as the greatest amount of contract drilling revenues the drilling unit could earn for the measurement period, excluding amounts related to incentive provisions. The revenue efficiency rates for our initial fleet were as follows:

 

     Three months ended     Years ended December 31,  

Revenue Efficiency

   March 31,
2014
  December 31,
2013
    March 31,
2013
          2013                 2012        

Drillships

          

Discoverer Inspiration

   98%     87     92     93     98

Discoverer Clear Leader

   98%     69     72     77     97

Semi-Submersible

          

Development Driller III

   98%     98     66     90     97

Our revenue efficiency rate varies due to revenues earned under alternative contractual dayrates, such as a waiting-on-weather rate, repair rate, standby rate, force majeure rate or zero rate, that may apply under certain circumstances.

 

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Revenue efficiency increased in the three months ended March 31, 2014 relative to the three months ended December 31, 2013 resulting from lower unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment particularly with respect to Discoverer Inspiration and Discoverer Clear Leader.

Revenue efficiency increased in the three months ended March 31, 2014 relative to the three months ended March 31, 2013 resulting from lower unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment particularly with respect to Discoverer Clear Leader and Development Driller III.

Revenue efficiency decreased in the year ended December 31, 2013 relative to the year ended December 31, 2012 due to unplanned downtime associated primarily with repairs to blowout preventers and other subsea equipment particularly with respect to Discover Clear Leader.

Rig utilization. Rig utilization is defined as the total number of operating days divided by the total number of rig calendar days in the measurement period, expressed as a percentage. The rig utilization rates for our initial fleet were as follows:

 

Rig Utilization

   Three months ended     Years ended December 31,  
   March 31,
2014
    December 31,
2013
    March 31,
2013
    2013     2012  

Drillships

          

Discoverer Inspiration

     100     100     100     100     98

Discoverer Clear Leader

     100     100     100     100     100

Semi-Submersible

          

Development Driller III

     100     100     100     100     100

Our rig utilization rate declines as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.

Operating Results

Items You Should Consider When Evaluating Our Historical Financial Performance and Assessing Our Future Prospects

You should consider the following facts when evaluating our historical results of operations and assessing our future prospects:

 

    We do not own all of the interests in the RigCos. As a result, our cash flow will not include distributions on the Transocean Member’s interest in the RigCos. Upon the completion of this offering, we will own a 51 percent interest in each RigCo through our ownership of the majority of each RigCo’s shares or limited liability company interests. The Transocean Member will own the remaining 49 percent noncontrolling interest in each RigCo. We and the Transocean Member have entered into governing documents for each of the RigCos that govern the ownership and management of each of the RigCos. Each of the RigCos is managed by its board of directors. Pursuant to such governing documents, we are able to control the election of these boards of directors as the majority interest owner. Subject to the approval of the board of directors of each of the RigCos, each RigCo will transfer its available cash to its equityholders each quarter. In determining the amount of cash available for distribution to us by the RigCos and by us to our unitholders, the board of directors of each of the RigCos and our board of directors must approve the amount of cash reserves to be set aside, including reserves for future maintenance and replacement capital expenditures, working capital and other matters. Distributions by the RigCos to the Transocean Member in respect of its ownership interest in the RigCos will not be included in our cash flow in the future.

 

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    Our historical combined results of operations reflect allocated administrative costs that may not be indicative of future administrative costs. The administrative costs included in the Predecessor’s unaudited condensed combined financial statements and audited combined financial statements have been determined by allocating to us a portion of Transocean’s administrative costs incurred by other entities in the Transocean corporate group. These shared costs are charged to the respective RigCos at cost, or in some cases at cost plus a margin specified in the master services agreements and are allocated based on rig type, with a greater portion of costs charged to the larger drilling rigs compared to the smaller drilling rigs. These allocated costs may not be indicative of our future administrative costs. In connection with this offering, we will enter into master services agreements pursuant to which subsidiaries of Transocean will provide management, administrative, financial and other support services to us, and we will reimburse such subsidiaries of Transocean for costs and expenses incurred in connection with the provision of those services, and pay a service fee, under such agreements.

 

    We will incur additional general and administrative expense as a publicly traded company. We expect we will incur approximately $10 million annually in additional general and administrative expenses as a publicly traded limited liability company that we have not previously incurred, including costs associated with annual reports to unitholders, tax return preparation, investor relations, registrar and transfer agent fees, audit fees, legal fees, incremental director and officer liability insurance costs, directors’ compensation and maintaining our U.K. offices.

 

    We expect to enter into a credit agreement and issue working capital notes payable in connection with this offering. As a result, our operating results will include interest expense for commitment fees and outstanding borrowings. In connection with the offering, we expect to enter into the Five-Year Revolving Credit Facility and this new agreement may not be on the same terms as Transocean’s financing agreements. Our Predecessor currently has no debt and thus has not recognized any interest expense in its combined statements of operations. We will have $             million of working capital notes payable and no borrowings outstanding under our revolving credit facility. Following the completion of this offering, we will have interest expense related to the working capital notes payable and commitment fees. For descriptions of our current financing agreements, please read “—Liquidity and Capital Resources—Revolving credit facilities.”

Factors Affecting Our Results of Operations

We believe the principal factors that will affect our future results of operations include:

 

    the offshore drilling market, including the impact of enhanced regulations in the jurisdictions in which we operate, supply and demand, rig utilization rates, dayrates, customer drilling programs, commodity prices, stacking of rigs, reactivation of rigs, effects of new rigs on the market and effects of declines in commodity prices, which influence the demand for offshore drilling services, and a downturn in the global economy or market outlook for our various geographical operating sectors and classes of rigs;

 

    the terms of our customer drilling contracts, including contract backlog, force majeure provisions, contract commencements, contract extensions, contract terminations, contract option exercises, contract revenues, contract awards and rig mobilizations;

 

    our ability to successfully employ our drilling rigs at economically attractive dayrates as our current contracts are completed or are otherwise terminated;

 

    the number and availability of our drilling rigs, including our ability to purchase the four drilling rigs (or majority interest therein) that Transocean will be required to offer us or any other drilling rigs in the future;

 

    the effective and efficient technical management of our drilling rigs;

 

    accidents, natural disasters, adverse weather, equipment failures or other events outside of our control that, together with shipyard and planned maintenance, will result in downtime;

 

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    our ability to maintain good relationships with our existing customers and to increase the number of customer relationships;

 

    investments in recruitment, retention and personnel development initiatives;

 

    our ability to obtain and maintain major oil and gas company approvals and to satisfy their quality, technical, health, safety and compliance standards;

 

    the effects of regulation, litigation and compliance with the Consent Decree, the EPA Agreement or any similar agreement relating to the Macondo well incident;

 

    debt levels, including impacts of a financial and economic downturn;

 

    the level of any distributions on our common units;

 

    changes in tax laws, treaties or regulations of any country in which we are resident or in which we have operations, or a loss of a major tax dispute or a successful tax challenge to our transfer pricing policies in certain countries;

 

    changes in our ownership interests in the RigCos; and

 

    our access to capital required to acquire additional drilling rigs or equity interests in the RigCos and/or to implement our business strategy.

Please read “Risk Factors” for a discussion of certain risks inherent in our business that will also affect our future results of operations.

Inflation

All of our drilling rigs operate under long-term contracts. As of June 16, 2014, the average remaining contract term was approximately 4.2 years for our drilling rigs. All of these contracts have dayrates that are fixed over the contract term. In order to mitigate the effects of inflation on revenues from long-term contracts, all of our long-term contracts include escalation provisions. These provisions allow us to adjust the dayrates based on certain publicly available cost indices and certain changes in our actual operating expenses. However, because these escalations are normally performed on a periodic basis, the timing and amount awarded as a result of such adjustments may differ from actual cost increases, which could adversely affect the stability of the RigCos and our cash flow and ability to make cash distributions.

 

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Three months ended March 31, 2014 compared to three months ended March 31, 2013

The following is an analysis of our operating results from continuing operations. See “—Performance and Other Key Indicators” for definitions of operating days, average daily revenue, revenue efficiency and rig utilization.

 

     Three months ended
March 31,
             
     2014     2013     Change     % Change  
     (In millions, except day amounts and percentages)  

Operating days

     270        270        —          —  

Average daily revenue

   $ 526,700      $ 403,900      $ 122,800        30

Revenue efficiency

     98     77    

Rig utilization

     100     100    

Contract drilling revenues

   $ 146      $ 114      $ 32        28

Other revenues

     2        2        —          —  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     148        116        32        28

Operating and maintenance expense

     (61     (58     (3     (5 )% 

Depreciation expense

     (16     (16     —          —  

General and administrative expense

     (2     (2     —          —  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     69        40        29        73

Interest income

     —          —          —          —  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

     69        40        29        73

Income tax expense

     (6     (4     (2     (50 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 63      $ 36      $ 27        75
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating revenues. Contract drilling revenues increased for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 primarily due to approximately $29 million of increased revenues due to higher revenue efficiency resulting from reduced downtime associated primarily with repairs to blowout preventers and other subsea equipment in the same period in the prior year and approximately $3 million of increased revenues due to cost escalation provisions.

Costs and expenses. Operating and maintenance costs and expenses increased for the three months ended March 31, 2014 compared to the three months ended March 31, 2013 primarily due to blowout preventer recertification costs recognized in the same period in the current year.

Income tax expense. The following income tax expense data represents the historical of Transocean Partners LLC Predecessor tax structure, which includes the subsidiaries of Transocean that have interests in the drilling rigs in the Company’s initial fleet and the associated rig-operating companies. For the three months ended March 31, 2014 and 2013, our annual effective tax rates were 8.5 percent and 10 percent, respectively, based on income before income taxes. The tax effect of settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. For the three months ended March 31, 2014 and 2013, the effect of the various discrete period tax items was a net tax expense of less than $1 million. For the three months ended March 31, 2014 and 2013, these discrete tax items resulted in effective tax rates of 8.7 percent and 10.8 percent, respectively, on income before income taxes.

 

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Year ended December 31, 2013 compared to year ended December 31, 2012

The following is an analysis of our operating results from continuing operations. See “—Performance and Other Key Indicators” for definitions of operating days, average daily revenue, revenue efficiency and rig utilization.

 

     Years ended December 31,              
           2013                 2012           Change     % Change  
     (In millions, except day amounts and percentages)  

Operating days

     1,095        1,098        3       

Average daily revenue

   $ 455,800      $ 491,500      $ (35,700     (7 )% 

Revenue efficiency

     86     97    

Rig utilization

     100     99    

Contract drilling revenues

   $ 517      $ 558      $ (41     (7 )% 

Other revenues

     9        11        (2     (18 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     526        569        (43     (8 )% 

Operating and maintenance expense

     (242     (219     (23     (11 )% 

Depreciation expense

     (66     (65     (1     (2 )% 

General and administrative expense

     (10     (9     (1     (11 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     208        276        (68     (25 )% 

Interest income

     4        3        1        33
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

     212        279        (67     (24 )% 

Income tax expense

     (23     (24     1        4
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

   $ 189      $ 255      $ (66     (26 )% 
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating revenues. Contract drilling revenues decreased for the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily due to approximately $64 million of decreased revenues due to lower revenue efficiency caused by downtime associated primarily with repairs to blowout preventers and other subsea equipment. This was partially offset by approximately $23 million of increased revenues due to improved contract terms and cost escalation provisions.

Costs and expenses. Operating and maintenance costs and expenses increased for the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily due to the following: (a) approximately $9 million of increased personnel costs, (b) approximately $5 million of increased costs for allocated fleet costs on shared personnel and shared equipment, (c) approximately $4 million of increased costs for required well control system recertification and (d) approximately $4 million of increased costs for between well maintenance on subsea equipment, including the well control system.

Income tax expense. The following income tax expense data represents the historical of Transocean Partners LLC Predecessor tax structure, which includes the subsidiaries of Transocean that have interests in the drilling rigs in the Company’s initial fleet and the associated rig-operating companies. For the years ended December 31, 2013 and 2012, our annual effective tax rates were 10.4 percent and 9.3 percent, respectively, based on income before income taxes. The tax effect of settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. For the years ended December 31, 2013 and 2012, the effect of the various discrete period tax items was a net tax expense of less than $1 million, and a net tax benefit of $2 million, respectively. For the years ended December 31, 2013 and 2012, these discrete tax items resulted in effective tax rates of 10.8 percent and 8.6 percent, respectively, on income before income taxes.

 

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Liquidity and Capital Resources

Sources and uses of cash

Transocean uses a centralized approach to the cash management system for and financing of its operations. The cash generated and used by our operations is transferred to Transocean and Transocean funds our operating and investing activities as needed. We had no bank accounts and the cash and cash equivalents held by Transocean were not allocated to us for any period presented. Accordingly, we have presented the transfers of cash to and from Transocean’s cash management system in our net investment on our unaudited condensed combined balance sheets and our combined balance sheets, and in net distributions to or from Transocean in our financing activities on our unaudited condensed combined statements of cash flows and our audited combined statements of cash flows.

The following table summarizes our net cash flows from operating, investing and financing activities and our cash and cash equivalents for the three months ended March 31, 2014 and 2013:

 

     Three months ended
March 31,
       
         2014             2013         Change  
     (in millions)  

Net cash provided by operating activities

   $ 70      $ 73      $ (3

Net cash used in investing activities

   &nb