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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10‑Q

                          (Mark one)

☑	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended June 30, 2015

OR

For the transition period from _____ to _____

______________________________

Commission file number 001‑36584

TRANSOCEAN PARTNERS LLC

(Exact name of registrant as specified in its charter)

______________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes ☑   No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S‑T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes ☑   No ☐

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

Large accelerated filer ☐    Accelerated filer ☐    Non‑accelerated filer (do not check if a smaller reporting company) ☑    Smaller reporting company ☐

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

As of July 28, 2015, 41,379,310 common units and 27,586,207 subordinated units were outstanding.

 

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

INDEX TO FORM 10‑Q

QUARTER ENDED JUNE 30, 2015

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PART I.

FINANCIAL INFORMATION

Item 1.

Financial Statements

TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)

(Unaudited)

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except unit data)

(Unaudited)

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

(Unaudited)

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

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Note 1—Business

Transocean Partners LLC (together with its subsidiaries and predecessors, unless the context requires otherwise, "Transocean Partners", "we", "us", or "our"), a Marshall Islands limited liability company, was formed on February 6, 2014 by Transocean Partners Holdings Limited, a Cayman Islands company and a wholly owned subsidiary of Transocean Ltd. (together with its affiliates, unless the context requires otherwise, "Transocean"), to own, operate and acquire modern, technologically advanced offshore drilling rigs.  At June 30, 2015, the drilling units in our fleet included the ultra‑deepwater drillships Discoverer Inspiration and Discoverer Clear Leader and the ultra‑deepwater semisubmersible Development Driller III, which are located in the United States ("U.S.") Gulf of Mexico.

On July 29, 2014, we entered into a contribution agreement (the "Contribution Agreement") with Transocean that gave effect to certain formation transactions, including Transocean's transfer of a 51 percent ownership interest in each of the entities that own and operate the drilling units in our fleet (each individually, a "RigCo" and collectively, the "RigCos").  Transocean holds the remaining 49 percent ownership interest in the RigCos.  We completed the formation transactions on August 5, 2014.

On July 31, 2014, we announced the pricing of the initial public offering of our common units representing limited liability company interests, which began trading on the New York Stock Exchange under the ticker symbol "RIGP," for $22.00 per unit.  On August 5, 2014, we completed the initial public offering of 20.1 million common units, which represent a 29.2 percent limited liability company interest in Transocean Partners.  Transocean Partners Holdings Limited (the "Transocean Member") holds the remaining 21.3 million common units and 27.6 million subordinated units, which collectively represent a 70.8 percent limited liability company interest, and all of our incentive distribution rights.  As a result of the offering, the Transocean Member received net cash proceeds of $417 million, net of $26 million for underwriting discounts and commissions and other offering costs.

The Transocean Partners LLC Predecessor (the "Predecessor") represents 100 percent of the combined results of operations, assets and liabilities of the drilling units in the fleet (the "Predecessor Business") prior to completion of the formation transactions and initial public offering on August 5, 2014.

Note 2—Significant Accounting Policies

Presentation—We have prepared our accompanying unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the U.S. for interim financial information and with the instructions to Form 10‑Q and Article 10 of Regulation S‑X of the U.S. Securities and Exchange Commission ("SEC").  Pursuant to such rules and regulations, these financial statements do not include all disclosures required by accounting principles generally accepted in the U.S. for complete financial statements.  The condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods.  Such adjustments are considered to be of a normal recurring nature unless otherwise noted.  Operating results for the three and six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 or for any future period.  The accompanying condensed consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto as of December 31, 2014 and 2013 and for each of the three years in the period ended December 31, 2014 included in our annual report on Form 10‑K filed on February 26, 2015.

For the three and six months ended June 30, 2015, the condensed consolidated financial statements reflect our consolidated results of operations, financial position and cash flows.  We present our assets and liabilities at historical cost because the Predecessor transferred to us such assets and liabilities in formation transactions completed under common control within the Transocean consolidated group.  We present in our condensed consolidated financial statements 100 percent of our consolidated results of operations, assets, liabilities and cash flows, and we present Transocean's partial ownership interest in each of the RigCos as noncontrolling interest.

For the three and six months ended June 30, 2014, the condensed combined financial information of the Predecessor was derived from Transocean's accounting records.  The condensed combined financial information reflects the combined results of operations, financial position and cash flows of the Predecessor Business as if such operations and assets had been combined for the periods presented.  All transactions within the Predecessor have been eliminated.

Transocean uses a centralized approach to treasury services to perform cash management for the operations of its affiliates.  Under the master services agreements, described herein, Transocean provides its treasury services to manage our cash and cash equivalents (see Note 11—Related Party Transactions).  The Predecessor had no bank accounts, and Transocean did not allocate its cash and cash equivalents to the Predecessor.  The Predecessor transferred the cash generated and used by its operations to Transocean, and Transocean funded the Predecessor's operating and investing activities as needed.  Accordingly, we presented the Predecessor's transfers of cash to and from Transocean's treasury as net distributions to the Predecessor's parent on our condensed consolidated statements of equity and in our financing activities on our condensed consolidated statements of cash flows.  The Predecessor's results of operations do not include any interest expense for intercompany cash advances from Transocean, since Transocean did not historically allocate interest expense for intercompany advances to the Predecessor.

 

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Accordingly, we have prepared our condensed consolidated financial statements on the following basis:

§

Our condensed consolidated statements of operations for the three and six months ended June 30, 2015 consist of the consolidated results of operations of Transocean Partners.  Our condensed consolidated statements of operations for the three and six months ended June 30, 2014 consist of the combined results of operations of the Predecessor.

§	Our condensed consolidated balance sheets at June 30, 2015 and December 31, 2014 consist of the consolidated balances of Transocean Partners.

§	Our condensed consolidated statement of equity for the six months ended June 30, 2015 consists of the consolidated activity of Transocean Partners.  Our condensed consolidated statement of equity for the six months ended June 30, 2014 consists of the combined activity of the Predecessor.

§

Our condensed consolidated statements of cash flows for the three and six months ended June 30, 2015 consist of the consolidated cash flows of Transocean Partners.  Our condensed consolidated statements of cash flows for the three and six months ended June 30, 2014 consist of the combined cash flows of the Predecessor.

Accounting estimates—To prepare financial statements in accordance with accounting principles generally accepted in the U.S., we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities.  On an ongoing basis, we evaluate our estimates and assumptions, including those related to our allocated costs and related party transactions, materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes and equity‑based compensation.  We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

Fair value measurements—We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.  Our valuation techniques require inputs that we categorize using a three‑level hierarchy, from highest to lowest level of observable inputs, as follows: (1) significant observable inputs, including unadjusted quoted prices for identical assets or liabilities in active markets ("Level 1"), (2) significant other observable inputs, including direct or indirect market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets ("Level 2") and (3) significant unobservable inputs, including those that require considerable judgment for which there is little or no market data ("Level 3").  When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.

Consolidation—We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes.  We eliminate intercompany transactions and accounts in consolidation.  We apply the equity method of accounting for an investment in an entity if we have the ability to exercise significant influence over the entity that (a) does not meet the variable interest entity criteria or (b) meets the variable interest entity criteria, but for which we are not deemed to be the primary beneficiary.  We apply the cost method of accounting for an investment in an entity if we do not have the ability to exercise significant influence over the unconsolidated entity.  We separately present within equity on our condensed consolidated balance sheets the ownership interests attributable to parties with noncontrolling interests in our consolidated subsidiaries, and we separately present net income attributable to such parties on our condensed consolidated statements of operations.

Allocated indirect and overhead costs—Our results of operations include allocations of costs and expenses based on services performed and products provided by Transocean under master services and support agreements.  In connection with such agreements, Transocean allocates to us costs and expenses related to the services performed and products provided to us under the master services and support agreements.  The allocations require significant judgment and subjectivity in applying estimates and assumptions used to determine the amount of such allocations, including the amount of time, services and resources provided to us relative to that provided to other Transocean affiliates.  Altering the assumptions used in our cost allocation estimates could result in significantly different results.  In the three and six months ended June 30, 2015, costs and expenses allocated to us by Transocean were $35 million and $66 million, respectively, including $30 million and $57 million, respectively, recorded in operating and maintenance costs, and $5 million and $9 million, respectively, recorded in general and administrative costs.  See Note 11—Related Party Transactions.

The combined results of operations for the Predecessor include allocated indirect and overhead costs for certain functions historically performed by Transocean and not previously allocated to the Predecessor Business, including allocations of indirect operating and maintenance costs and expenses for onshore operational support services such as engineering, procurement and logistics and general and administrative costs and expenses related to executive oversight, accounting, treasury, tax, legal, and information technology.  We have applied these allocations based on relative values of net property and equipment and operating and maintenance costs and expenses.  We believe the assumptions underlying the consolidated financial statements, including the assumptions regarding allocation of costs from Transocean, are reasonable.  Nevertheless, the combined results of operations of the Predecessor do not include all of the costs that the Predecessor would have incurred had it been a stand‑alone company during the periods presented and may not reflect the combined results of operations, financial position and cash flows had the Predecessor been a stand‑alone company during the periods presented.  In the three and six months ended June 30, 2014, the Predecessor recognized such allocated operating and maintenance costs of $6 million and $12 million, respectively, including $5 million and $10 million, respectively, for personnel costs.  In the three and six months ended June 30, 2014, the Predecessor recognized such allocated general and administrative costs of $4 million and $6 million, respectively, including $2 million and $4 million, respectively, for personnel costs.

 

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Equity-based compensation—For time‑based awards, we recognize compensation expense on a straight‑line basis through the date the employee is no longer required to provide service to earn the award (the "service period").  For performance‑based awards, we recognize compensation expense on a straight‑line basis for each separately vesting tranche of the award.  We have awarded to our employees and non‑employee directors phantom units, and such phantom units are participating securities.  A phantom unit is a notional unit that has no voting rights and entitles the grantee to receive a common unit upon the vesting.  To measure fair values of granted or modified time‑based phantom units, we use the market price of our units on the grant date or modification date.  To measure fair values of granted or modified performance‑based phantom units, we recognize compensation expense only to the extent the achievement of the performance condition is probable, and we remeasure the fair value of the award at each reporting date until the performance condition has been determined.

We recognize equity‑based compensation expense in the same financial statement line item as cash compensation paid to the respective employees or non‑employee directors.  We recognize cash flows resulting from the tax deduction benefits for awards in excess of recognized compensation costs as financing cash flows.  In the three and six months ended June 30, 2015, equity‑based compensation expense was less than $1 million.  In the three and six months ended June 30, 2015, the income tax benefit on share‑based compensation expense was less than $1 million.  See Note 10—Equity‑Based Compensation.

Accounts receivable—We record long-term accounts receivable at their present value and recognize interest income using the effective interest method through the date of payment.  At June 30, 2015 and December 31, 2014, the aggregate face value of our long‑term accounts receivable was $23 million and $24 million, respectively.  At June 30, 2015, the aggregate carrying amount of our long‑term accounts receivable was $21 million, including $15 million due within one year and $6 million due thereafter, recorded in accounts receivable and other assets, respectively.  At December 31, 2014, the aggregate carrying amount of our long‑term accounts receivable was $22 million, including $12 million due within one year and $10 million due thereafter, recorded in accounts receivable and other assets, respectively.  At June 30, 2015 and December 31, 2014, our long‑term accounts receivable had a weighted average effective interest rate of 11 percent.

Property and equipment—The carrying amounts of our property and equipment, consisting primarily of offshore drilling rigs and related equipment, are based on our estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our rigs.  These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations.  At June 30, 2015, the aggregate carrying amount of our property and equipment represented approximately 74 percent of our total assets.

We compute depreciation using the straight‑line method after allowing for salvage values.  In December 31, 2014, we reduced the salvage values of our drilling units due to existing market conditions.  In the three and six months ended June 30, 2015, this change in estimate resulted in an increase of less than $1 million to depreciation expense.  For the year ending December 31, 2015, we expect this change in estimate to result in an increase of approximately $1 million to depreciation expense.

Reclassifications—We have made certain reclassifications to prior period amounts to conform with the current period's presentation.  Such reclassifications did not have a material effect on our condensed consolidated statement of financial position, results of operations or cash flows.

Subsequent events—We evaluate subsequent events through the time of our filing on the date we issue our financial statements.  See Note 14—Subsequent Events.

Note 3—New Accounting Pronouncements

Recently issued accounting standards

Presentation of financial statements—Effective with our annual report for the period ending December 31, 2016, we will adopt the accounting standards update that requires us to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about our ability to continue as a going concern within one year after the date that the financial statements are issued.  The update is effective for the annual period ending after December 15, 2016 and for interim and annual periods thereafter.  We do not expect that our adoption will have a material effect on the disclosures contained in our notes to condensed consolidated financial statements.

Revenue from contracts with customers—Effective January 1, 2018, we will adopt the accounting standards update that requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The update was originally effective for interim and annual periods beginning on or after December 15, 2016, but has since been approved for a one‑year deferral, effective for interim and annual periods beginning on or after December 15, 2017 and permits adoption as early as the original effective date.  We are evaluating the requirements to determine the effect such requirements may have on our revenue recognition policies.

 

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Note 4—Goodwill Impairment

During the three months ended March 31, 2015, we noted impairment indicators that the fair value of our goodwill could have fallen below its carrying amount.  Such impairment indicators included further reduction in the market value of our units, oil and natural gas prices as well as the projected reductions in dayrates and utilization.  As a result, we performed a goodwill impairment test as of March 31, 2015 and determined that the goodwill associated with our contract drilling services reporting unit was impaired.  In the six months ended June 30, 2015, we recognized a loss of $67 million associated with the impairment of our goodwill, which had no tax effect, and of which $34 million was attributable to controlling interest ($0.49 per diluted unit) and $33 million was attributable to noncontrolling interest.  We estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches.  Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of our contract drilling services reporting unit, such as future oil and natural gas prices, projected demand for our services, rig availability and dayrates.  If we experience increasingly unfavorable changes to actual or anticipated market conditions or to other impairment indicators, any of which could result in the fair value of our reporting unit again falling below its carrying amount, we may be required to recognize additional losses on impairment of goodwill.

Note 5—Income Taxes

Tax rate—We are organized as a limited liability company under the laws of The Republic of the Marshall Islands and are a resident in the United Kingdom ("U.K.") for taxation purposes.  We are treated as a corporation for U.S. federal income tax purposes.  Certain of our controlled affiliates, including the RigCos, are subject to taxation in the jurisdictions in which they are organized, conduct business or own assets.  Our provision for income taxes is computed based on the laws and rates applicable in the jurisdictions in which we operate and earn income.

The Predecessor's income tax provision was based on the tax structure of Transocean Ltd., a holding company and Swiss resident, which is exempt from cantonal and communal income tax in Switzerland, but is subject to Swiss federal income tax.  At the federal level, qualifying net dividend income and net capital gains on the sale of qualifying investments in subsidiaries are exempt from Swiss federal income tax.  Consequently, Transocean Ltd.'s dividends from its subsidiaries and capital gains from sales of investments in its subsidiaries are exempt from Swiss federal income tax.  The Predecessor's provision for income taxes was prepared on a separate return basis with consideration to the laws and rates applicable in the jurisdictions in which the Predecessor's Business operated and earned income.

In the six months ended June 30, 2015 and 2014, our estimated annual effective tax rates were 6.2 percent and 9.1 percent, respectively, based on estimated annual income before income taxes, after excluding the loss on impairment.

Deferred taxes—The valuation allowance for our non‑current deferred tax assets was as follows (in millions):

The increase in the valuation allowance for our non‑current deferred tax assets was primarily related to the current net operating losses generated in the U.K.

Unrecognized tax benefits—The liabilities related to our unrecognized tax benefits, including related interest and penalties that we recognize as a component of income tax expense, were as follows (in millions):

In the year ending December 31, 2015, it is reasonably possible that our existing liabilities for unrecognized tax benefits could increase or decrease primarily due to the progression of open audits, changes in legislation or the expiration of statutes of limitation.  However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties.

Tax returns—The Predecessor's results were reported in federal and local tax returns filed in the U.S. and Switzerland.  With few exceptions, the Predecessor's results are no longer subject to examinations of tax matters for years prior to 2010.

 

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Note 6—Earnings Per Unit

The numerator and denominator used for the computation of basic and diluted per unit earnings were as follows (in millions, except per unit data):

We have not presented earnings per unit calculations for the Predecessor periods since the Predecessor had no units outstanding.  See Note 2—Significant Accounting Policies—Presentation.

Note 7—Credit Agreements

Five‑Year Revolving Credit Facility—On August 5, 2014, we entered into a credit agreement, which is scheduled to expire on August 5, 2019, with a Transocean affiliate to establish a committed $300 million five‑year revolving credit facility that allows for uncommitted increases in amounts agreed to by the Transocean affiliate and us (the "Five‑Year Revolving Credit Facility").  We may borrow under the Five‑Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate ("LIBOR") plus a margin (the "revolving credit facility margin"), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined, or (2) the base rate specified in the credit agreement plus the revolving credit facility margin, less one percent per annum.  Throughout the term of the Five‑Year Revolving Credit Facility, we are required to pay a commitment fee on the daily unused amount of the underlying commitment, which ranges from 0.225 percent to 0.325 percent based on our leverage ratio, as defined.  Among other things, the Five‑Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets.  The Five‑Year Revolving Credit Facility also includes a covenant imposing a maximum debt ratio, as defined in the credit agreement.  Borrowings under the Five‑Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default.  At June 30, 2015, based on our leverage ratio on that date, the revolving credit facility margin was 1.625 percent.  At June 30, 2015 and December 31, 2014, we had no borrowings outstanding and $300 million available borrowing capacity under the Five‑Year Revolving Credit Facility.

Working capital note payable—On July 29, 2014, we entered into agreements with a Transocean affiliate to establish a working capital note payable in the principal amount and for cash proceeds of $43 million that is due and payable at maturity on July 28, 2015.  The working capital note payable bears interest at the adjusted one‑month LIBOR plus a margin (the "working capital note margin"), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined in the Five‑Year Revolving Credit Facility.  The principal amount may be repaid early without penalty, and amounts repaid cannot be reborrowed.  At June 30, 2015, based on our leverage ratio on that date, the working capital note margin was 1.625 percent.  At June 30, 2015 and December 31, 2014, we had borrowings of $43 million outstanding under the working capital note payable.  See Note 14—Subsequent Events.

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Note 8—Contingencies

Retained risk

Overview—Our fleet is covered under Transocean's hull and machinery and excess liability insurance program, which is comprised of commercial market and captive insurance policies, and Transocean allocated to us the premium costs attributable to our fleet.  Transocean renews the commercial and captive policies under its insurance program annually on May 1.  At June 30, 2015, our drilling units had the insured value of approximately $1.95 billion under this program.  We also have coverage 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, through Transocean's captive insurance program.  We do not maintain insurance coverage through Transocean or the commercial market for loss of revenues.

Hull and machinery coverage—Our fleet is covered under Transocean's hull and machinery insurance for physical damage, for which it allocated to us the respective premium costs.  At June 30, 2015, in connection with this physical damage insurance coverage, we retained the risk for our per occurrence deductible of $10 million to $11 million.  Subject to the same deductible, we also had coverage for an amount equal to 50 percent of a rig's insured value for combined costs incurred to mitigate rig damage, wreck or debris removal and collision liability.  For losses in excess to our per occurrence deductible of $10 million to $11 million, Transocean provides insurance coverage for physical damage to our fleet through its wholly owned captive insurance company up to its deductible amounts and through its commercial insurance program beyond such deductible amounts.  In connection with losses for any excess wreck removal costs, we are generally covered to the extent of Transocean's remaining excess liability coverage.

Excess liability coverage—Our fleet is covered under Transocean's excess liability coverage insurance, for which it allocated to us the respective premium costs.  At June 30, 2015, in connection with this excess liability insurance coverage, we retained the risk for a separate $10 million per occurrence deductible on collision liability claims and a separate $5 million per occurrence deductible applicable to crew personal injury claims and other third‑party non‑crew claims.  For losses in excess of our deductible amounts, Transocean provides the primary $50 million of excess liability coverage, through its wholly owned captive insurance company, and for the $700 million excess of the $50 million of coverage through its commercial market excess liability program, 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 share the $750 million of captive and commercial market excess liability coverage with Transocean's entire fleet.  We and Transocean generally retained the risk for any liability losses in excess of $750 million.

Other insurance coverage—Our fleet is covered under Transocean's marine package insurance program, and Transocean allocated to us the respective premium costs.  At June 30, 2015, under this insurance program, we have access to $100 million of additional insurance that generally covered expenses that would otherwise be assumed by the well owner, such as costs to control the well, redrill expenses and pollution from the well.  This additional insurance provided coverage for such expenses under circumstances in which we would have had legal or contractual liability arising from its gross negligence or willful misconduct.

Note 9—Cash Distributions

Cash distributions to unitholders—On May 4, 2015 and February 9, 2015, our board of directors approved distributions of $0.3625 per unit to unitholders.  On February 26, 2015, we made an aggregate cash payment of $25 million to our unitholders of record as of February 20, 2015, including an aggregate cash payment of $18 million to the Transocean Member.  On May 27, 2015, we made an aggregate cash payment of $25 million to our unitholders of record as of May 15, 2015, including an aggregate cash payment of $18 million to the Transocean Member.  See Note 14—Subsequent Events.

Cash distributions to holder of noncontrolling interests—In the three and six months ended June 30, 2015, we paid an aggregate distribution of $30 million and $82 million, respectively, of which $15 million and $40 million, respectively, was paid to Transocean as holder of noncontrolling interests and $15 million and $42 million, respectively, was paid to us and eliminated in consolidation.

Note 10—Equity‑Based Compensation

Effective August 5, 2014, we established a long‑term incentive plan (the "Incentive Compensation Plan") under which awards can be granted in the form of unit options, unit appreciation rights, restricted units, phantom units or deferred units for executives, key employees and non‑employee directors.  Awards that may be granted under the Incentive Compensation Plan include time‑vesting awards ("time‑based awards") and awards that are earned based on the achievement of certain performance criteria ("performance‑based awards") or market factors ("market‑based awards").  The compensation committee of our board of directors determines the terms and conditions of the awards granted under the Incentive Compensation Plan.  As of June 30, 2015, we had 3.4 million units authorized and available to be granted under the Incentive Compensation Plan.

In the six months ended June 30, 2015, we granted to our executive officers, key employees and non-employee directors 60,105 time‑based phantom units with an aggregate grant-date fair value of $1 million, and we granted 19,459 performance‑based phantom units with an aggregate fair value of less than $1 million, measured as of June 30, 2015.

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The time‑based awards to our employees vest in three equal installments beginning approximately one year following the grant date, and the time‑based awards to our non‑employee directors fully vest approximately one year following the grant date.  The performance‑based awards may be earned depending on the achievement of certain performance targets as determined upon completion of the specified period at the determination date.  Thereafter, the performance‑based awards vest in three equal installments beginning approximately one year following the determination date.

Note 11—Related Party Transactions

Master services and support agreements

Secondment agreements—On August 5, 2014, we entered into secondment agreements with certain Transocean affiliates to provide the services of certain executives, including our chief executive officer, rig crews and other personnel.  On June 30, 2015, we amended one of the secondment agreements to add additional parties to the agreement and to add personnel covered by the agreement.  All persons provided to us pursuant to the secondment agreements remain on the payroll and benefit plans of Transocean but are under our day‑to‑day control and management.  We reimburse Transocean for the pro rata gross payroll costs of each seconded employee in proportion to the time allocated to us by the seconded employee, including base pay, any incentive compensation and any benefits costs.  We also reimburse Transocean for any applicable unemployment taxes, social security taxes, workers compensation coverage and severance costs, and any foreign equivalents of such taxes, in the amount allocable to the secondment.  The secondment agreements may be terminated by Transocean or us upon 90 days written notice.  In the three and six months ended June 30, 2015, we recognized costs of $23 million and $47 million, respectively, recorded in operating and maintenance costs and expenses, and $1 million and $2 million, respectively, recorded in general and administrative costs and expenses, for personnel costs under the secondment agreements.

Support agreement—On August 5, 2014, we entered into a support agreement with certain Transocean affiliates to provide the services of certain administrative professionals, including our chief financial officer.  The persons providing such services to us pursuant to the support agreement remain on Transocean's payroll and perform their services on or at Transocean's facilities.  Transocean is solely responsible for all matters pertaining to their employment, compensation and discharge.  Such persons may spend only a portion of their time providing services to us and they may be engaged in other work separate from support services on our behalf.  We reimburse Transocean for the pro rata expenses associated with the compensation and benefits of all persons covered by the support agreement according to the time spent by each person in providing us support services as well as certain direct costs and expenses incurred in offering the services.  The support agreement may be terminated by mutual agreement of Transocean and us.  In the three and six months ended June 30, 2015, we recognized costs of less than $1 million, recorded in general and administrative costs and expenses, for services under the support agreement.

Master services agreements—On August 5, 2014, we entered into master services agreements with certain Transocean affiliates, pursuant to which Transocean affiliates provide certain administrative, technical and non‑executive management services to us.  The agreements have initial terms of five years.  Each month, we reimburse Transocean for the cost of all direct labor, materials and expenses incurred in connection with the provision of these services, plus an allocated portion of Transocean's shared and pooled direct costs, indirect costs and general and administrative costs as determined by Transocean's internal accounting procedures.  In addition, we pay Transocean a fee equal to the greater of (i) five percent of its costs and expenses incurred in connection with providing services to us for the month or, in the case of the provision of capital spares or inventory, a four percent markup on the capital spare or inventory plus a four percent markup on the allocable share of the costs of providing such services and (ii) the markup required by applicable transfer pricing rules.  If Transocean incurs costs and expenses from unaffiliated parties in the course of subcontracting the performance of services, we reimburse Transocean at cost and are not required to pay a service fee, unless required by applicable transfer pricing rules.  Each of the master services agreements may be terminated prior to the end of its term by either Transocean or us within 90 days written notice under certain circumstances.  In the three and six months ended June 30, 2015, we recognized costs of $27 million and $51 million, respectively, recorded in operating and maintenance costs and expenses, and $5 million and $9 million, respectively, recorded in general and administrative costs and expenses, for services under the master services agreements.  In the three and six months ended June 30, 2015, we recognized insurance costs of $3 million and $6 million, respectively, recorded in operating and maintenance costs and expenses.  In the three and six months ended June 30, 2015, we acquired $6 million and $15 million, respectively, of materials and supplies purchased through the procurement services of Transocean Offshore Deepwater Drilling Inc. ("TODDI"), a U.S. company and a wholly owned subsidiary of Transocean.

Former master services agreement—Under the former master services agreement, TODDI and its affiliates charged the Predecessor for crew personnel provided to the Predecessor to operate its drilling rigs.  In the three and six months ended June 30, 2014, the Predecessor recognized costs of $24 million and $48 million, respectively, recorded in operating and maintenance costs and expenses, for such personnel costs.  In the three and six months ended June 30, 2014, the Predecessor recognized costs of $1 million and $2 million, respectively, recorded in operating and maintenance costs and expenses, for the proportion of the benefit costs that covered the personnel supporting the Predecessor's operations.

TODDI also charged the Predecessor obtained services and assistance for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services.  In the three and six months ended June 30, 2014, the Predecessor recognized costs of $11 million and $19 million, respectively, recorded in operating and maintenance costs and expenses, for such services and assistance.

 

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TODDI also administered insurance coverage with and processed claims through Transocean's commercial market and captive insurance policies (see Note 8—Contingencies).  In the three and six months ended June 30, 2014, the Predecessor recognized allocated insurance costs of $3 million and $6 million, respectively, recorded in operating and maintenance costs and expenses.

Additionally, TODDI purchased materials and supplies for the Predecessor's drilling operations through its procurement services.  In the three and six months ended June 30, 2014, the Predecessor paid $9 million and $22 million, respectively, settled through its net investment, for materials and supplies purchased through TODDI's procurement services.

Other agreements

Omnibus agreement—On August 5, 2014, we entered into an omnibus agreement with Transocean and certain of its affiliates (the "Omnibus Agreement").  Under the Omnibus Agreement, Transocean granted 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 within five years of the effective date of the Omnibus Agreement, the opportunity to purchase, subject to requisite government and other third‑party consents, not less than a 51 percent interest in any four of the following six ultra‑deepwater drillships: Deepwater Invictus, Deepwater Thalassa, Deepwater Proteus, Deepwater Pontus, Deepwater Poseidon and Deepwater Conqueror.  The purchase price for each drillship will be 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 drillships 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 drillship.  In addition, Transocean agreed not to acquire, own or operate any new drilling rig or contract for any drilling rig, in each case that was constructed in 2009 or later and is operating under a contract for five or more years ("Five‑Year Drilling Rigs"), subject to certain exceptions, without offering us the opportunity to purchase such rig.  We also agreed not to acquire, own, operate, or contract for any drilling rig that is not a Five‑Year Drilling Rig, subject to certain exceptions, without first offering the contract to Transocean.

Transocean agreed to indemnify us for a period of five years through August 5, 2019 against certain environmental and human health and safety liabilities with respect to the assets contributed or sold to us to the extent arising prior to the time they were contributed or sold to us.  Liabilities resulting from a change in law after the closing of the offering are excluded from the environmental indemnity.  The indemnity coverage provided by Transocean for such environmental and human health and safety liabilities will not exceed the aggregate amount of $10 million.  No claim for indemnification may be made unless the aggregate dollar amount of all claims exceeds $500,000, in which case Transocean is liable for claims only to the extent such aggregate amount exceeds $500,000.

In addition, Transocean agreed to indemnify us against any liabilities arising out of the Macondo well incident occurring prior to our initial public offering and any liabilities, other than taxes, arising from Transocean's or its subsidiaries' failure to comply with the Consent Decree or the EPA Agreement, each as it is defined in the Omnibus Agreement, or any similar decree or agreement.  The indemnity coverage provided by Transocean related to the Macondo well incident, the Consent Decree, the EPA Agreement or any similar decree or agreement is unlimited.  However, these indemnities do not cover or include any amount of consequential damages, including lost profits or revenues.

Transocean also agreed to indemnify us to the full extent of any liabilities related to:

§

certain defects in title to Transocean's assets contributed or sold to the RigCos and any failure to obtain, prior to the time they were contributed, certain consents and permits necessary to conduct, own and operate such assets, which liabilities arise within three years after the closing of the offering;

§	any judicial determination substantially to the effect that the Transocean affiliate that transferred any of our initial assets to us pursuant to the Contribution Agreement did not receive reasonably equivalent value in exchange therefor or was rendered insolvent by such transfer;

§	tax liabilities attributable to the operation of the assets contributed or sold to the RigCos prior to the closing of the offering; and

§

any lost revenue, up to $100 million, arising out of the failure to receive an operating dayrate from Chevron for Discoverer Clear Leader, for the period commencing on the closing date of the offering through the completion of the rig's 2014 special periodic survey, which occurred during the three months ending December 31, 2014.

In the year ended December 31, 2014, we submitted indemnification claims under the Omnibus Agreement for an aggregate amount of $19 million associated with lost revenues.  At December 31, 2014, the indemnification claim receivable was $10 million, which we collected in January 2015.

Dual‑activity license agreements—All three of our drilling units are equipped with Transocean's patented dual‑activity technology.  Dual‑activity technology employs structures, equipment and techniques using two drilling stations within a dual derrick to perform drilling tasks.  Dual‑activity technology allows our rigs to perform simultaneous drilling tasks in a parallel rather than sequential manner and reduces critical path activity, improving efficiency in both exploration and development drilling.  The Predecessor entered into license agreements with TODDI for the use of the patented technology through the expiration of the patents in May 2016.  Under the license agreements, the Predecessor paid to TODDI an aggregate original license cost of $20 million, recorded in other assets.  In the three and six months ended June 30, 2015, we recognized amortization of the license costs of less than $1 million and $1 million, respectively, recorded in operating and maintenance costs and expenses.  In the three and six months ended June 30, 2014, the Predecessor recognized amortization of the license costs of $1 million and $2 million, respectively, recorded in operating and maintenance costs and expenses.  At June 30, 2015 and December 31, 2014, the carrying amount of the deferred license cost was $3 million and $4 million, respectively.

 

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Also, under the license agreements, we are and the Predecessor was required to pay to TODDI quarterly patent royalty fees of between 3 percent and 5 percent of revenues.  Under the Contribution Agreement, Transocean retained the obligation for the payment of the quarterly patent royalty fees.  In the three and six months ended June 30, 2015, we recognized patent royalty expense of $7 million and $12 million, respectively, recorded in operating and maintenance costs and expenses with corresponding entries to members' equity, representing the fees paid by Transocean on our behalf.  In the three and six months ended June 30, 2014, the Predecessor recognized patent royalty expense of $9 million and $14 million, respectively, recorded in operating and maintenance costs and expenses.

Credit agreements—On July 29, 2014, we entered into agreements with a Transocean affiliate to establish a working capital note payable in the principal amount and for cash proceeds of $43 million.  On August 5, 2014, we entered into the Five‑Year Revolving Credit Facility with a Transocean affiliate.  See Note 7—Credit Agreements and Note 14—Subsequent Events.

Note 12—Supplemental Cash Flow Information

In the six months ended June 30, 2014, we transferred to Transocean's other drilling units certain equipment with an aggregate net carrying amount of $21 million, primarily all of which was from Development Driller III, and we recorded the non-cash investing activity with a corresponding entry to the Predecessor's net investment.

Note 13—Financial Instruments

The carrying amounts and fair values of our financial instruments were as follows (in millions):

 

We estimated the fair value of each class of financial instruments, for which estimating fair value is practicable, by applying the following methods and assumptions:

Cash and cash equivalents—The carrying amount of cash and cash equivalents represents the historical cost, plus accrued interest, which approximates fair value because of the short maturities of those instruments.  We measured the estimated fair value of our cash equivalents using significant other observable inputs, representative of a Level 2 fair value measurement, including the net asset values of the investments.  At June 30, 2015 and December 31, 2014, the aggregate carrying amount of our cash equivalents was $174 million and $40 million, respectively.

Working capital note payable to affiliate—The carrying amount of the working capital note payable approximates fair value due to the short term nature of the instrument.  We measured the estimated fair value of our working capital note payable using significant unobservable inputs, representative of a Level 3 fair value measurement, including the credit spreads that would be considered at market for a borrower with our credit ratings.

Note 14—Subsequent Events

Cash distribution to unitholders—On July 30, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  We expect to make an aggregate cash payment of $25 million on August 25, 2015 to our unitholders of record as of August 12, 2015, including an aggregate cash payment of $18 million to the Transocean Member.

Working capital note payable to affiliate—On July 17, 2015, we made a cash payment of $43 million to repay the borrowings outstanding under the working capital note.

 

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Forward‑Looking Information

The statements included in this quarterly report regarding future financial performance and results of operations and other statements that are not historical facts are forward‑looking statements within the meaning of Section 27A of the United States ("U.S.") Securities Act of 1933, as amended, and Section 21E of the U.S. Securities Exchange Act of 1934, as amended (the "Exchange Act").  Forward‑looking statements in this quarterly report 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;

§	forecasts of 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, indemnity provisions, 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 Ltd.'s relationship and reputation in the offshore drilling industry;

§	our ability to purchase drilling rigs from Transocean Ltd. 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.

Forward‑looking statements in this quarterly report are identifiable by use of the following words and other similar expressions:

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

§	those described under "Item 1A. Risk Factors" included in Part I of our annual report on Form 10‑K for the year ended December 31, 2014;

§	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;

§	losses on impairment of goodwill and long‑lived assets;

§	changes in political, social and economic conditions;

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

§	other factors discussed in this quarterly report and in our other filings with the U.S. Securities and Exchange Commission ("SEC"), which are available free of charge on the SEC website at www.sec.gov.

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.  We expressly disclaim any obligations or undertaking to release publicly any updates or revisions to any forward‑looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward‑looking statement is based.

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Business

Transocean Partners LLC (together with its subsidiaries and predecessors, unless the context requires otherwise, "Transocean Partners," "we," "us," or "our") is a growth‑oriented limited liability company formed by Transocean Ltd. (together with its affiliates, unless the context requires otherwise, "Transocean") to own, operate and acquire modern, technologically advanced offshore drilling rigs.  At July 28, 2015, the drilling units in our fleet included the ultra‑deepwater drillships Discoverer Inspiration and Discoverer Clear Leader and the ultra‑deepwater semisubmersible Development Driller III, which are located in the U.S. Gulf of Mexico.  We generate revenues through contract drilling services, which involves contracting our mobile offshore drilling fleet, related equipment and seconded work crews on a dayrate basis to drill oil and gas wells.  We depend on Transocean affiliates to operate our drilling units, manage our customer relationships, renew existing and obtain new drilling contracts and to perform other administrative support activities.

On July 29, 2014, we entered into a contribution agreement with Transocean that gave effect to certain formation transactions, including Transocean's transfer of a 51 percent ownership interest in each of the entities that own and operate the drilling units in our fleet (each individually, a "RigCo", and collectively, the "RigCos").  Transocean holds the remaining 49 percent ownership interest in the RigCos.  We completed the formation transactions on August 5, 2014.

On July 31, 2014, we announced the pricing of the initial public offering of our common units representing limited liability company interests, which began trading on the New York Stock Exchange under the ticker symbol "RIGP," for $22.00 per unit.  On August 5, 2014, we completed the initial public offering of 20.1 million common units, including 2.6 million common units sold pursuant to the exercise in full of the underwriters' option to purchase additional common units, which represented a 29.2 percent limited liability company interest in Transocean Partners.  Transocean Partners Holdings Limited (the "Transocean Member") holds the remaining 21.3 million common units and 27.6 million subordinated units, which collectively represented a 70.8 percent limited liability company interest.  As a result of the offering, the Transocean Member received net cash proceeds of $417 million, net of $26 million for underwriting discounts and commissions and other offering costs.

The Transocean Partners LLC Predecessor (the "Predecessor") represents 100 percent of the combined results of operations, assets and liabilities of the drilling units in the fleet (the "Predecessor Business") prior to completion of the formation transactions and initial public offering on August 5, 2014.  See Notes to Consolidated Financial Statements—Note 2—Significant Accounting Policies—Presentation.

Upon the completion of our formation transactions and initial public offering on August 5, 2014, we own a 51 percent interest in each of the RigCos.  We control each RigCo through our ownership of the majority of its shares or limited liability company interests.  The Transocean Member owns 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 Corporation (together with its affiliates "Chevron") through March 2020;

§	the ultra‑deepwater drillship Discoverer Clear Leader, which commenced operations in 2009 and is currently under a contract with Chevron through October 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 plc (together with its affiliates "BP") through November 2016.

We own a 51 percent interest in each of the RigCos and thus are entitled to only 51 percent of the RigCos' distributions, if any.  Our interest in the RigCos represents our only cash‑generating asset.  We anticipate growing by acquiring additional drilling rigs and increasing our operations indirectly through additional rig‑owning and rig‑operating entities and by acquiring additional equity interests in the RigCos.

Although our contract drilling services operations are currently concentrated in the U.S. Gulf of Mexico, we can provide our services anywhere in the global offshore drilling market.  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.  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 our rigs are determined by the activities and needs of our customers.

Significant Events

Discoverer Inspiration operations—On July 6, 2015, Discoverer Inspiration suffered unplanned operational downtime due to an incident involving the drill string.  The incident caused 18 days out of service, resulting in lost revenues of approximately $11 million.  Additionally, we may be responsible for incremental costs associated with the incident.

Impairment of goodwill—During the three months ended March 31, 2015, we identified indicators that the implied fair value of our goodwill could have fallen below its carrying amount, and as a result of our impairment testing, we recognized a loss of $67 million, which had no tax effect, associated with the impairment of our goodwill.  See "—Operating Results."

Working capital note payable—On July 29, 2014, we entered into agreements with a Transocean affiliate to establish a working capital note payable in the principal amount and for cash proceeds of $43 million that is due and payable at maturity on July 28, 2015.  On July 17, 2015, we made a cash payment of $43 million to repay the borrowings outstanding under the working capital note.

 

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Cash distributions to unitholders—On February 9, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  On February 26, 2015, we made an aggregate cash payment of $25 million to our unitholders of record as of February 20, 2015, including an aggregate cash payment of $18 million to the Transocean Member.

On May 4, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  On May 27, 2015, we made an aggregate cash payment of $25 million to our unitholders of record as of May 15, 2015, including an aggregate cash payment of $18 million to the Transocean Member.

On July 30, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  We expect to make an aggregate cash payment of $25 million on August 25, 2015 to our unitholders of record as of August 12, 2015, including an aggregate cash payment of $18 million to the Transocean Member.

See "—Liquidity and Capital Resources—Sources and uses of liquidity."

Cash distributions to holder of noncontrolling interests—In the three and six months ended June 30, 2015, we paid an aggregate distribution of $30 million and $82 million, respectively, of which $15 million and $40 million, respectively, was paid to Transocean as holder of noncontrolling interests and $15 million and $42 million, respectively, was paid to us and eliminated in consolidation.

See "—Liquidity and Capital Resources—Sources and uses of liquidity."

Outlook

Drilling market—As of July 15, 2015, all three of our high‑specification floaters were operating under existing long‑term contracts with high‑quality, creditworthy customers for an average remaining contract term of approximately 3.1 years, the shortest of which is contracted through November 2016.  We believe continued exploration successes in the major deepwater offshore provinces and the emerging markets will generate additional future demand and support our long‑term positive outlook for our high‑specification floater fleet.

Although our long‑term view of the offshore drilling market remains favorable, particularly for high‑specification assets, we expect the near to medium term to be challenging given weak commodity pricing, coupled with our customers' focus on capital allocation, cost reductions and delays of various exploration and development programs.  The significant and rapid decline in oil and natural gas prices has accelerated the rapid decline in demand for drilling rigs across all asset classes and regions.  As a result of this decline in demand, we currently expect the pace of executing drilling contracts for the global floater fleet to remain stagnant in the near to medium term, giving rise to excess capacity, lower dayrates and idle time for some rigs.  Additionally, this excess capacity may result in some lower capability assets in the industry being permanently retired, ultimately reducing the available supply of drilling rigs, all else being equal.

As of July 15, 2015, uncommitted fleet rates for the remainder of 2015 and for 2016, 2017, 2018 and 2019 were as follows:

            ___________________________________________

(a)

The uncommitted fleet rate is defined as the number of uncommitted days divided by the total number of rig calendar days in the measurement period, expressed as a percentage.  An uncommitted day is defined as a calendar day during which a rig is idle or stacked, is not contracted to a customer and is not committed to a shipyard.

 

 

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Performance and Other Key Indicators

Contract backlog—Contract backlog is defined as the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions.  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, other incentive provisions or cost escalation provisions, which are excluded from the amounts presented for contract backlog.  The contract backlog for our contract drilling services was as follows:

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 because 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.  The actual dayrate we receive may be higher than the contractual rate under certain circumstances, such as when cost escalation provisions are applied.

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.

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 contract drilling services was as follows:

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

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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 contract drilling services were as follows:

 

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.

In the three months ended June 30, 2015, revenues earned by Discoverer Inspiration and Development Driller III each exceeded maximum revenues as a result of achieving certain contractual incentive bonuses.

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 fleet were as follows:

 

Our rig utilization rate declines as a result of idle rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.  We remove rigs from the calculation upon disposal, classification as held for sale or classification as discontinued operations.

 

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Operating Results

Three months ended June 30, 2015 compared to three months ended June 30, 2014

The following is an analysis of our operating results.  See "—Performance and Other Key Indicators" for definitions of operating days, average daily revenue, revenue efficiency and rig utilization.

                                                                ______________________________

                                                      "n/m" means not meaningful.

Operating revenues—Contract drilling revenues increased for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 primarily due to the following: (a) approximately $16 million of increased revenues resulting from an increase in contractual dayrate for Discoverer Clear Leader and Discoverer Inspiration and (b) approximately $5 million of increased revenues resulting from incentive bonus revenues earned for Discoverer Inspiration and Development Driller III with no comparable revenues in the prior year period.  These increases were partially offset by approximately $6 million of decreased revenues resulting from the amortization of pre‑operating revenues for Discoverer Clear Leader and Discoverer Inspiration with no comparable revenues in the current year period.

Costs and expenses—Operating and maintenance costs and expenses decreased for the three months ended June 30, 2015 compared to the three months ended June 30, 2014 primarily due to the following: (a) approximately $4 million of decreased costs and expenses resulting from riser joint inspection and well control recertification costs for Development Driller III with no comparable costs in the current year period, (b) $2 million of decreased costs and expenses resulting from patent royalty costs for Discoverer Clear Leader and Discoverer Inspiration and (c) approximately $2 million of decreased costs and expenses resulting from personnel costs for all three rigs.

Income tax expense—For the three months ended June 30, 2015 and 2014, the annual effective tax rates were 5.8 percent and 9.7 percent, respectively, based on estimated annual income (loss) before income taxes after excluding the loss on impairment.  We also treat the tax effect of settlements of prior year tax liabilities and changes in prior year tax estimates as discrete period tax expenses or benefits.  We also treat the tax effect of settlements of prior year tax liabilities and changes in prior year tax estimates as discrete period tax expenses or benefits.  For the three months ended June 30, 2015 and 2014, the effect of the various discrete period tax items was a net tax benefit of less than $1 million and net tax expense of less than $1 million, respectively.  For the three months ended June 30, 2015 and 2014, the effective tax rates were 5.8 percent and 9.9 percent, respectively, based on income (loss) before income taxes, including these discrete tax items.

 

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Six months ended June 30, 2015 compared to six months ended June 30, 2014

The following is an analysis of our operating results.  See "—Performance and Other Key Indicators" for definitions of operating days, average daily revenue, revenue efficiency and rig utilization.

                                                                                                ______________________________

                                                      "n/m" means not meaningful.

Operating revenues—Contract drilling revenues increased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to the following: (a) approximately $16 million of increased revenues resulting from an increase in contractual dayrate for Discoverer Clear Leader and Discoverer Inspiration and (b) approximately $5 million of increased revenues resulting from incentive bonus revenues earned for Discoverer Inspiration and Development Driller III with no comparable revenues in the prior year period.  These increases were partially offset by the following: (a) approximately $8 million of decreased revenues resulting from the amortization of pre‑operating revenues and (b) approximately $9 million of decreased revenues resulting from planned out‑of‑service period for Discoverer Inspiration associated with its five‑year special periodic survey.

Costs and expenses—Operating and maintenance costs and expenses decreased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to the following: (a) approximately $6 million of decreased costs and expenses resulting from blowout preventer recertification costs and (b) approximately $2 million of decreased costs and expenses resulting from patent royalty costs.

General and administrative costs and expenses increased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 due to increased costs and expenses related to establishing a separate publicly traded limited liability company.

During the six months ended June 30, 2015, we recognized a loss on impairment of our goodwill as a result of a decline in the market value of our units and commodity prices as well as the projected reductions in dayrates and utilization.  If we experience increasingly unfavorable changes to actual or anticipated market conditions or to other impairment indicators, any of which could result in the fair value of our reporting unit again falling below its carrying amount, we may be required to recognize additional losses on impairment of goodwill.

Income tax expense—For the six months ended June 30, 2015 and 2014, the annual effective tax rates were 6.2 percent and 9.1 percent, respectively, based on estimated annual income (loss) before income taxes after excluding the loss on impairment.  We also treat the tax effect of settlements of prior year tax liabilities and changes in prior year tax estimates as discrete period tax expenses or benefits.  For the six months ended June 30, 2015 and 2014, the effect of the various discrete period tax items was a net tax benefit of less than $1 million and net tax expense of less than $1 million, respectively.  For the six months ended June 30, 2015 and 2014, the effective tax rates were 12.0 percent and 9.2 percent, respectively, based on income (loss) before income taxes, including these discrete tax items.

 

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Liquidity and Capital Resources

Sources and uses of cash

Transocean uses a centralized approach to treasury services to perform cash management for the operations of its affiliates.  Under the master services agreements with Transocean, described herein, Transocean provides its treasury services to manage our cash and cash equivalents.  The Predecessor had no bank accounts, and Transocean did not allocate its cash and cash equivalents to the Predecessor.  The Predecessor transferred the cash generated and used by its operations to Transocean, and Transocean funded the Predecessor's operating and investing activities as needed.  Accordingly, the Predecessor's transfers of cash to and from Transocean's treasury were presented as net distributions to the Predecessor's parent on our condensed consolidated statements of equity and in our financing activities on our condensed consolidated 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 six months ended June 30, 2015 and 2014:

Net cash provided by operating activities increased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to increased cash from changes in working capital and earnings after adjusting for non‑cash items.

Net cash used in investing activities increased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to an increase in capital expenditures partially offset by proceeds from affiliates for disposal of assets, which have no comparable cash flows in the prior year period.

Net cash used in financing activities decreased for the six months ended June 30, 2015 compared to the six months ended June 30, 2014 primarily due to the following: (a) distributions to the Predecessor parent, which have no comparable cash flows in the current period, and (b) proceeds from affiliates for indemnification of lost revenues, which have no comparable cash flows in the prior year period.  Partially offsetting the net decrease was the following: (a) distributions of available cash to unitholders and (b) distributions to holder of noncontrolling interests, which have no comparable cash flows in the prior year period.

Sources and uses of liquidity

Overview—We operate in a capital‑intensive industry, and our primary liquidity needs are to finance the purchase of additional drilling rigs and other capital expenditures, fund investments, including the equity portion of investments in drilling rigs, fund working capital, maintain cash reserves against fluctuations in operating cash flows, pay distributions to our unitholders and to repay debt due within one year.  We expect to fund our short‑term liquidity needs through cash on hand, borrowings under credit facilities provided by Transocean affiliates or commercial banks, cash generated from operations and issuance of debt or equity securities.

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facility and issuances of additional debt and equity securities.  Generally, our long‑term sources of funds will be cash from operations, long‑term bank borrowings and other debt and equity financings.  Because we will distribute all of our available cash, after deducting estimated maintenance, net of replacement capital expenditures, we expect to fund acquisitions and capital expenditures for expansion by relying on external financing sources, including bank borrowings and the issuance of debt and equity securities.  We believe our current resources, including the potential borrowings under our credit facilities, are sufficient to meet our working capital requirements for our current business for at least the next year.

Our access to debt and equity markets may be limited due to a variety of events, including, among others, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry.  Our ability to access such markets may be 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.  An economic downturn could have an impact on the lenders, including Transocean, participating in our credit facilities or on our customers, causing them to fail to meet their obligations to us.

We intend to pay a minimum quarterly distribution of $0.3625 per unit per quarter, which equates to approximately $25 million per quarter, or approximately $100 million per year in the aggregate, based on the number of outstanding common and subordinated units.  At July 28, 2015, we had 41.4 million common units and 27.6 million subordinated units outstanding.  We do not have a legal obligation to pay this distribution, and the amount declared by our board of directors may vary from this minimum quarterly distribution depending on expectations for future transactions and activities in which we may engage.

Estimated maintenance and replacement capital expenditures—Subject to the approval by the board of directors of each of the RigCos, each RigCo will transfer its available cash to its equityholders, including the Transocean Member as holder of noncontrolling interests, each quarter.  In determining the amount of cash available for transfer, the board of directors of each of the RigCos and our board of directors determine the amount of cash reserves to set aside, including reserves for future maintenance and replacement capital expenditures, working capital and other matters.  Because of the substantial capital expenditures the RigCos are required to make to maintain their fleets, we have estimated the RigCos' initial annual estimated maintenance and replacement capital expenditures to be $67 million per year, including $48 million for long‑term maintenance and society classification surveys and $19 million for replacing the rigs at the end of their useful lives, including estimated financing costs.

 

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We estimated $19 million per year for future rig replacement based on assumptions regarding the remaining useful life of the RigCos' rigs, a net investment rate applied on reserves, replacement values of the RigCos' rigs based on current market conditions, and the residual value of the rigs.  The actual cost of replacing the rigs in the RigCos' fleet will depend on a number of factors, including prevailing market conditions, drilling contract operating dayrates and the availability and cost of financing at the time of replacement.  Our second amended and restated limited liability company agreement allows our board of directors to deduct from our operating surplus each quarter estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, in order to reduce disparities in operating surplus caused by fluctuating maintenance and replacement capital expenditures, such as society classification surveys and rig replacement.  Our board of directors, with the approval of the conflicts committee, may determine that one or more of our assumptions should be revised, which could cause our board of directors to increase the amount of estimated maintenance and replacement capital expenditures.  We may elect to finance some or all of our maintenance and replacement capital expenditures through the issuance of additional common units, which could be dilutive to existing unitholders.  As our fleet matures and expands, our long‑term maintenance expenses will likely increase.

Revolving credit facility—On August 5, 2014, we entered into a credit agreement, which is scheduled to expire on August 5, 2019, with a Transocean affiliate to establish a committed $300 million five‑year revolving credit facility that allows for uncommitted increases in amounts agreed to by Transocean and us.  We may borrow under the Five‑Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate ("LIBOR") plus a margin (the "revolving credit facility margin"), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined, or (2) the base rate specified in the credit agreement plus the revolving credit facility margin, less one percent per annum.  Throughout the term of the Five‑Year Revolving Credit Facility, we are required to pay a commitment fee on the daily unused amount of the underlying commitment, which ranges from 0.225 percent to 0.325 percent based on our leverage ratio, as defined.  Among other things, the Five‑Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets.  The Five‑Year Revolving Credit Facility also includes a covenant imposing a maximum debt ratio, as defined in the agreement, with certain adjustments during a specified acquisition period.  Borrowings under the Five‑Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default.  At July 28, 2015, we had no borrowings outstanding and $300 million of available borrowing capacity under the Five‑Year Revolving Credit Facility.

Working capital note payable—On July 29, 2014, we entered into agreements with a Transocean affiliate to establish a working capital note payable in the principal amount and for cash proceeds of $43 million that is due and payable at maturity on July 28, 2015.  The working capital note payable bears interest at the adjusted one‑month LIBOR plus a margin (the "working capital note margin"), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined in the Five‑Year Revolving Credit Facility.  The principal amount may be repaid early without penalty, and amounts repaid cannot be reborrowed.  At June 30, 2015, based on our leverage ratio on that date, the working capital note margin was 1.625 percent.  On July 17, 2015, we made a cash payment of $43 million to repay the borrowings outstanding under the working capital note.

Lost revenues indemnification—Under the Omnibus Agreement, Transocean agreed to indemnify us for any lost revenues, up to $100 million, arising out of the failure to receive an operating dayrate from Chevron for Discoverer Clear Leader, for the period commencing on the closing date of our initial public offering through the completion of the rig's 2014 special periodic survey.  In the year ended December 31, 2014, we submitted to Transocean indemnification claims under the Omnibus Agreement for an aggregate amount of $19 million, and we received payment of $9 million of such claims in October 2014.  In January 2015, we received payment of the remaining $10 million of the outstanding indemnification claims.

Cash distributions to unitholders—On February 9, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  On February 26, 2015, we made an aggregate cash payment of $25 million to our unitholders of record as of February 20, 2015, including an aggregate cash payment of $18 million to the Transocean Member.

On May 4, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  On May 27, 2015, we made an aggregate cash payment of $25 million to our unitholders of record as of May 15, 2015, including an aggregate cash payment of $18 million to the Transocean Member.

On July 30, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  We expect to make an aggregate cash payment of $25 million on August 25, 2015 to our unitholders of record as of August 12, 2015, including an aggregate cash payment of $18 million to the Transocean Member.

Cash distributions to holder of noncontrolling interests—In the three and six months ended June 30, 2015, we paid an aggregate distribution of $30 million and $82 million, respectively, of which $15 million and $40 million, respectively, was paid to Transocean as holder of noncontrolling interests and $15 million and $42 million, respectively, was paid to us and eliminated in consolidation.

 

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Contractual obligations—As of June 30, 2015, there have been no material changes to the contractual obligations as previously disclosed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our annual report on Form 10‑K for the year ended December 31, 2014, except as noted below.

 

		For the twelve months ending June 30,
		Total				2016				2017 - 2018				2019 - 2020				Thereafter
		(in millions)
Contractual obligations
Purchase obligations		$	6			$	6			$	—			$	—			$	—

      Other commercial commitments—As of June 30, 2015, there have been no material changes to the commercial commitments as previously disclosed in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our annual report on Form 10‑K for the year ended December 31, 2014.

Contingencies

Insurance matters

Our fleet is covered under Transocean's hull and machinery and excess liability insurance program, which is comprised of commercial market and captive insurance policies, and Transocean allocated to us the premium costs attributable to our fleet.  Transocean renews the commercial and captive policies under its insurance program annually on May 1.  At July 28, 2015, our drilling units had the insured value of approximately $1.95 billion under this program.  We also have coverage 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, through Transocean's captive insurance program.  We do not maintain insurance coverage through Transocean or the commercial market for loss of revenues.

See Notes to Consolidated Financial Statements—Note 8—Contingencies.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements.  This discussion should be read in conjunction with disclosures included in the notes to our condensed consolidated financial statements related to estimates, contingencies and other accounting policies.  Significant accounting policies are discussed in Note 2 to our condensed consolidated financial statements in this quarterly report on Form 10‑Q and in Note 2 to our consolidated financial statements in our annual report on Form 10‑K for the year ended December 31, 2014.

To prepare financial statements, we are required to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures of contingent assets and liabilities.  On an ongoing basis, we evaluate our estimates, including those related to our allocated costs and related party transactions, materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes and equity‑based compensation.  These estimates require significant judgments, assumptions and estimates.  We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates.

For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates" in our annual report on Form 10‑K for the year ended December 31, 2014.  We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors.  During the six months ended June 30, 2015, there have been no material changes to the types of judgments, assumptions and estimates upon which our critical accounting estimates are based.

New Accounting Pronouncements

For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our condensed consolidated financial statements, see Notes to Condensed Consolidated Financial Statements—Note 3—New Accounting Pronouncements in this quarterly report on Form 10‑Q and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in our annual report on Form 10‑K for the year ended December 31, 2014.

We are exposed to credit risk associated with having only two customers, and we are exposed to interest rate risk associated with our working capital note payable to affiliate.  For a discussion of our credit risk and interest rate risk, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in our annual report on Form 10‑K for the year ended December 31, 2014.  There have been no material changes to these previously reported matters during the six months ended June 30, 2015.

 

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Item 4.

Controls and Procedures

Disclosure controls and procedures—We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined in the Exchange Act, Rules 13a‑15 and 15d‑15, were effective as of June 30, 2015 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the U.S. Securities and Exchange Commission's rules and forms.

Internal control over financial reporting—There were no changes to our internal control over financial reporting during the quarter ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II.

OTHER INFORMATION

Item 1.

Legal Proceedings

As of June 30, 2015, we were not involved in any lawsuits or other matters that could have a material adverse effect on our condensed consolidated statements of financial position, results of operations or cash flows.

Item 1A.

Risk Factors

Except as disclosed below, there have been no material changes from the risk factors as previously disclosed in "Item 1A. Risk Factors" in our annual report on Form 10‑K for the year ended December 31, 2014.

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 U.K.  Changes to the income tax treaty in force between the U.S. and the U.K. 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 U.K. could also enact changes to its tax laws or policies or its interpretation or application of the same, 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.  In July 2014, legislation was enacted in the U.K which will substantially increase the taxation of drilling contractors operating in the U.K. sector of the North Sea.  In December, 2014, the U.K. Treasury issued an additional draft legislative proposal that would impose an additional tax on certain aggressive tax planning techniques used by multinational entities to divert profits from the U.K.  The Diverted Profit Tax rule was included in the 2015 Finance Bill and on March 26, 2015, the legislation received Royal Assent with an effective date of April 1, 2015.  As we do not currently 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 a July 2015 decision, the Supreme Court of England and Wales held that members of a Delaware limited liability company were entitled to the profits as they arose, the members would, therefore, be taxable in the U.K. on their allocable share of the profits with double tax relief being given for the U.S. tax paid.  Although the implications of this decision are unclear, and may be dependent on the specific facts and circumstances, including the terms of the specific limited liability company agreement in the litigation, the decision could mean that Delaware limited liability companies may be treated, in some, or possibly all cases, as flow-through entities rather than as corporations for certain U.K. tax purposes.  We are a Marshall Islands limited liability company and Marshall Islands corporate law is very similar to Delaware corporate law.  This, in turn, could potentially impact one of the ways in which we may qualify for benefits under certain tax treaties in future years.  If the case is ultimately applied in a manner adverse to us and we are unable to qualify for treaty benefits based on other means, it could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows in future years.

In addition, in the U.S., a number of legislative and budget proposals have been introduced that would substantially reform the U.S. international tax system.  Any material change in tax laws resulting from these legislative proposals could result in a higher effective tax rate on our worldwide earnings, reducing the cash available for distribution and such changes could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Similarly, the Organisation for Economic Co‑Operation and Development (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.  A number of specific tax reform changes have been recently proposed and are currently being publicly debated.  Some of these proposals would impact transfer pricing, requirements to qualify for tax treaty benefits, and the definition of permanent establishments.  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.

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Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 6.

Exhibits

The following exhibits are filed in connection with this Report:

Number

Description

3.1

Second Amended and Restated Limited Liability Company Agreement of Transocean Partners LLC, dated as of July 29, 2014 (incorporated by reference to Exhibit 3.1 to Transocean Partners LLC's Current Report on Form 8‑K (Commission File No. 001‑36584) filed on August 5, 2014)

3.2

Certificate of Formation of Transocean Partners LLC, dated February 6, 2014 (incorporated by reference to Exhibit 3.1 to Transocean Partners LLC's registration statement on Form S‑1, as amended (Commission File No. 333‑196958))

†   *10.15

Summary of non‑employee Director Compensation Policy

†    10.16

Secondment Agreement First Amendment among GlobalSantaFe Offshore Services Inc., Transocean International Resources, Limited, Transocean Deepwater Inc., Transocean Offshore Deepwater Drilling Inc., and Transocean Partners LLC, Triton RIGP DCL Holdco Limited, Triton RIGP DD3 Holdco Limited, Triton RIGP DIN Holdco Limited, Transocean RIGP DCL LLC, Transocean RIGP DD3 LLC and Transocean RIGP DIN LLC, dated as of June 30, 2015

†

31.1

CEO Certification Pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002

†

31.2

CFO Certification Pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002

†

32.1

CEO Certification Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002

†

32.2

CFO Certification Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002

†

101.ins

XBRL Instance Document

†

101.sch

XBRL Taxonomy Extension Schema

†

101.cal

XBRL Taxonomy Extension Calculation Linkbase

†

101.def

XBRL Taxonomy Extension Definition Linkbase

†

101.lab

XBRL Taxonomy Extension Label Linkbase

†

101.pre

XBRL Taxonomy Extension Presentation Linkbase

                                                            

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SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on August 6, 2015.

TRANSOCEAN PARTNERS LLC

Garry Taylor

Chief Financial Officer

(Principal Financial Officer)