Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2015 | Apr. 28, 2015 | |
Entity Registrant Name | Transocean Partners LLC | |
Entity Central Index Key | 1607250 | |
Document Type | 10-Q | |
Document Period End Date | 31-Mar-15 | |
Amendment Flag | FALSE | |
Current Fiscal Year End Date | -19 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Document Fiscal Year Focus | 2015 | |
Document Fiscal Period Focus | Q1 | |
Common units | ||
Entity Common Stock, Shares Outstanding | 41,379,310 | |
Subordinated units | ||
Entity Common Stock, Shares Outstanding | 27,586,207 |
CONDENSED_CONSOLIDATED_STATEME
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) | 3 Months Ended | |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Operating revenues | ||
Contract drilling revenues | $136 | |
Other revenues | 4 | |
Total operating revenues | 140 | |
Costs and expenses | ||
Operating and maintenance | 58 | |
Depreciation | 17 | |
General and administrative | 5 | |
Total costs and expenses | 80 | |
Loss on impairment | -67 | |
Operating income (loss) | -7 | |
Interest income | 1 | |
Income (loss) before income tax expense | -6 | |
Income tax expense | 4 | |
Net income (loss) | -10 | |
Net loss attributable to noncontrolling interest | -4 | |
Net loss attributable to controlling interest | -6 | |
Predecessor Business | ||
Operating revenues | ||
Contract drilling revenues | 146 | |
Other revenues | 2 | |
Total operating revenues | 148 | |
Costs and expenses | ||
Operating and maintenance | 61 | |
Depreciation | 16 | |
General and administrative | 2 | |
Total costs and expenses | 79 | |
Operating income (loss) | 69 | |
Income (loss) before income tax expense | 69 | |
Income tax expense | 6 | |
Net income (loss) | 63 | |
Common units | ||
Costs and expenses | ||
Net loss attributable to controlling interest | -4 | |
Loss per unit | ||
Earnings (loss) per unit, basic | ($0.09) | |
Earnings (loss) per unit, diluted | ($0.09) | |
Weighted-average units outstanding | ||
Weighted average units outstanding -basic (in units) | 41 | |
Weighted-average units outstanding - diluted (in units) | 41 | |
Subordinated units | ||
Costs and expenses | ||
Net loss attributable to controlling interest | ($2) | |
Loss per unit | ||
Earnings (loss) per unit, basic | ($0.09) | |
Earnings (loss) per unit, diluted | ($0.09) | |
Weighted-average units outstanding | ||
Weighted average units outstanding -basic (in units) | 28 | |
Weighted-average units outstanding - diluted (in units) | 28 |
CONDENSED_CONSOLIDATED_BALANCE
CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Assets | ||
Cash and cash equivalents | $164 | $86 |
Accounts receivable | 110 | 112 |
Accounts receivable from affiliates | 8 | 28 |
Materials and supplies, net of allowance for obsolescence of $4 and $3 at March 31, 2015 and December 31, 2014, respectively | 40 | 41 |
Deferred income taxes, net | 7 | 8 |
Prepaid assets | 4 | 6 |
Total current assets | 333 | 281 |
Property and equipment | 2,302 | 2,302 |
Less accumulated depreciation | -353 | -336 |
Property and equipment, net | 1,949 | 1,966 |
Goodwill | 289 | 356 |
Deferred income taxes, net | 6 | 7 |
Other assets | 23 | 22 |
Total assets | 2,600 | 2,632 |
Liabilities and equity | ||
Accounts payable to affiliates | 105 | 76 |
Debt due to affiliates within one year | 43 | 43 |
Deferred revenues | 16 | 18 |
Other current liabilities | 4 | 1 |
Total current liabilities | 168 | 138 |
Long-term tax liability | 1 | 1 |
Deferred revenues | 10 | 13 |
Drilling contract intangible liability | 25 | 29 |
Total long-term liabilities | 36 | 43 |
Commitments and contingencies | ||
Total members' equity | 1,385 | 1,411 |
Noncontrolling interest | 1,011 | 1,040 |
Total equity | 2,396 | 2,451 |
Total liabilities and equity | 2,600 | 2,632 |
Common units | ||
Liabilities and equity | ||
Common units, 41,379,310 authorized, issued and outstanding at March 31, 2015 and December 31, 2014 | 831 | 847 |
Total equity | 831 | 847 |
Subordinated units | ||
Liabilities and equity | ||
Subordinated units, 27,586,207 authorized, issued and outstanding at March 31, 2015 and December 31, 2014 | 554 | 564 |
Total equity | $554 | $564 |
CONDENSED_CONSOLIDATED_BALANCE1
CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, except Share data, unless otherwise specified | ||
CONDENSED CONSOLIDATED BALANCE SHEETS | ||
Materials and supplies, allowance for obsolescence (in dollars) | $4 | $3 |
Common units | ||
Statement | ||
Units authorized | 41,379,310 | 41,379,310 |
Units issued | 41,379,310 | 41,379,310 |
Units outstanding | 41,379,310 | 41,379,310 |
Subordinated units | ||
Statement | ||
Units authorized | 27,586,207 | 27,586,207 |
Units issued | 27,586,207 | 27,586,207 |
Units outstanding | 27,586,207 | 27,586,207 |
CONDENSED_CONSOLIDATED_STATEME1
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (USD $) | Predecessor Business | Predecessor Business | Common units | Subordinated units | Total members' equity | Noncontrolling interest | Total |
In Millions, unless otherwise specified | Net investment | ||||||
Balance, beginning of period at Dec. 31, 2013 | $2,344 | $2,344 | |||||
Increase (Decrease) in Partners' Capital | |||||||
Net income (loss) | 63 | 63 | |||||
Distributions to parent, net | -87 | -87 | |||||
Balance, end of period at Mar. 31, 2014 | 2,320 | 2,320 | |||||
Balance, beginning of period at Dec. 31, 2014 | 847 | 564 | 1,411 | 1,040 | 2,451 | ||
Balance, beginning of period (in shares) at Dec. 31, 2014 | 41 | 28 | |||||
Increase (Decrease) in Partners' Capital | |||||||
Net income (loss) | -10 | ||||||
Net loss attributable to controlling interest | -4 | -2 | -6 | -6 | |||
Contribution for parent payment of dual activity royalties | 3 | 2 | 5 | 5 | |||
Net loss attributable to noncontrolling interest | -4 | 4 | |||||
Distributions to holders of non controlling interest | -25 | -25 | |||||
Distribution of available cash to unitholders | -15 | -10 | -25 | -25 | |||
Balance, end of period at Mar. 31, 2015 | $831 | $554 | $1,385 | $1,011 | $2,396 | ||
Balance, end of period (in shares) at Mar. 31, 2015 | 41 | 28 |
CONDENSED_CONSOLIDATED_STATEME2
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) | 3 Months Ended | |
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 |
Cash flows from operating activities | ||
Net income (loss) | ($10) | |
Adjustments to reconcile to net cash provided by operating activities | ||
Amortization of drilling contract intangibles | -4 | |
Depreciation | 17 | |
Loss on impairment | 67 | |
Patent royalties expense | 5 | |
Deferred income taxes | 1 | |
Other, net | 1 | |
Changes in deferred revenues, net | -5 | |
Changes in deferred costs, net | -2 | |
Changes in operating assets and liabilities | ||
(Increase) decrease in accounts receivable, net | 3 | |
(Increase) decrease in other current assets, net | 4 | |
Increase in current liabilities, net | 2 | |
Increase in balances due to affiliates, net | 40 | |
Increase in income tax liability, net | 2 | |
Net cash provided by operating activities | 121 | |
Cash flows from investing activities | ||
Payments to affiliates for capital expenditures | -3 | |
Net cash used in investing activities | -3 | |
Cash flows from financing activities | ||
Proceeds from affiliates for indemnification | 10 | |
Distribution of available cash to unitholders | -25 | |
Distribution to holder of noncontrolling interests | -25 | |
Net cash used in financing activities | -40 | |
Net increase in cash and cash equivalents | 78 | |
Cash and cash equivalents at beginning of period | 86 | |
Cash and cash equivalents at end of period | 164 | |
Predecessor Business | ||
Cash flows from operating activities | ||
Net income (loss) | 63 | |
Adjustments to reconcile to net cash provided by operating activities | ||
Amortization of drilling contract intangibles | -4 | |
Depreciation | 16 | |
Deferred income taxes | 5 | |
Changes in deferred revenues, net | -10 | |
Changes in deferred costs, net | 1 | |
Changes in operating assets and liabilities | ||
(Increase) decrease in accounts receivable, net | -1 | |
(Increase) decrease in other current assets, net | -1 | |
Increase in income tax liability, net | 1 | |
Net cash provided by operating activities | 70 | |
Cash flows from investing activities | ||
Payments to affiliates for capital expenditures | -1 | |
Net cash used in investing activities | -1 | |
Cash flows from financing activities | ||
Distributions to the parent, net | -69 | |
Net cash used in financing activities | -69 | |
Net increase in cash and cash equivalents | 0 | |
Cash and cash equivalents at beginning of period | 0 | |
Cash and cash equivalents at end of period | $0 |
Business
Business | 3 Months Ended |
Mar. 31, 2015 | |
Business | |
Business | Note 1—Business |
Transocean Partners LLC (together with its subsidiaries and predecessors, unless the contexts 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. The drilling units in our fleet include 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. | |
Significant_Accounting_Policie
Significant Accounting Policies | 3 Months Ended | |||
Mar. 31, 2015 | ||||
Significant Accounting Policies | ||||
Significant Accounting Policies | 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 months ended March 31, 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 months ended March 31, 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 three months ended March 31, 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 all 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, 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 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. | ||||
Accordingly, we have prepared our condensed consolidated financial statements on the following basis: | ||||
· | Our condensed consolidated statement of operations for the three months ended March 31, 2015 consists of the consolidated results of operations of Transocean Partners. Our condensed consolidated statement of operations for the three months ended March 31, 2014 consists of the combined results of operations of the Predecessor. | |||
· | Our condensed consolidated balance sheets at March 31, 2015 and December 31, 2014 consist of the consolidated balances of Transocean Partners. | |||
· | Our condensed consolidated statement of equity for the three months ended March 31, 2015 consists of the consolidated activity of Transocean Partners. Our condensed consolidated statement of equity for the three months ended March 31, 2014 consists of the combined activity of the Predecessor. | |||
· | Our condensed consolidated statement of cash flows for the three months ended March 31, 2015 consists of the consolidated cash flows of Transocean Partners. Our condensed consolidated statement of cash flows for the three months ended March 31, 2014 consists 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 materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes, allocated costs and related party transactions. 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 months ended March 31, 2015, costs and expenses allocated to us by Transocean were $31 million, including $27 million and $4 million, recorded in operating and maintenance costs and general and administrative costs, respectively. 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 months ended March 31, 2014, the Predecessor recognized such allocated operating and maintenance costs of $6 million, including $5 million, for personnel costs. In the three months ended March 31, 2014, the Predecessor recognized such allocated general and administrative costs of $2 million, including $2 million, for personnel costs. | ||||
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”). 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 months ended March 31, 2015, equity-based compensation expense was less than $1 million. In the three months ended March 31, 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 March 31, 2015 and December 31, 2014, the aggregate face value of our long-term accounts receivable was $25 million and $24 million, respectively. At March 31, 2015, the aggregate carrying amount of our long-term accounts receivable was $23 million, including $14 million due within one year and $9 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 March 31, 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 March 31, 2015, the aggregate carrying amount of our property and equipment represented approximately 75 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 months ended March 31, 2015, our change in this estimate resulted in an increase of less than $1 million to depreciation expense. For the year ending December 31, 2015, we expect our change in this 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. | ||||
New_Accounting_Pronouncements
New Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2015 | |
New Accounting Pronouncements | |
New Accounting Pronouncements | 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, 2017, 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 is effective for interim and annual periods beginning on or after December 15, 2016. We are evaluating the requirements to determine the effect such requirements may have on our revenue recognition policies. | |
Goodwill_Impairment
Goodwill Impairment | 3 Months Ended |
Mar. 31, 2015 | |
Goodwill Impairment | |
Goodwill Impairment | 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 as a result, in the three months ended March 31, 2015, we recognized a loss of $67 million associated with the impairment of our goodwill, which had no tax effect. We determined that, of the $67 million estimated loss, $34 million was attributable to controlling interest ($0.50 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. | |
Income_Taxes
Income Taxes | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Income Taxes | ||||||||
Income Taxes | 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. | ||||||||
For the three months ended March 31, 2014, 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 three months ended March 31, 2015 and 2014, our estimated annual effective tax rates were 6.4 percent and 8.5 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): | ||||||||
March 31, | December 31, | |||||||
2015 | 2014 | |||||||
Valuation allowance for non-current deferred tax assets | $ | 3 | $ | 2 | ||||
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): | ||||||||
March 31, | December 31, | |||||||
2015 | 2014 | |||||||
Unrecognized tax benefits, excluding interest and penalties | $ | 1 | $ | 1 | ||||
Interest and penalties | — | — | ||||||
Unrecognized tax benefits, including interest and penalties | $ | 1 | $ | 1 | ||||
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 or the expiration of statutes of limitation. However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties, such as the unresolved nature of various audits. | ||||||||
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. | ||||||||
Earnings_Loss_Per_Unit
Earnings (Loss) Per Unit | 3 Months Ended | |||||||||||||
Mar. 31, 2015 | ||||||||||||||
Earnings (Loss) Per Unit | ||||||||||||||
Earnings (Loss) Per Unit | Note 6—Earnings (Loss) Per Unit | |||||||||||||
The numerator and denominator used for the computation of basic and diluted per unit earnings (loss) were as follows (in millions, except per unit data): | ||||||||||||||
Three months ended March 31, | ||||||||||||||
2015 | 2014 | |||||||||||||
Basic | Diluted | Basic | Diluted | |||||||||||
Numerator for earnings (loss) per share | ||||||||||||||
Net loss attributable to controlling interest | $ | (6 | ) | $ | (6 | ) | $ | — | $ | — | ||||
Undistributed earnings allocable to participating securities | — | — | — | — | ||||||||||
Net loss available to unitholders | $ | (6 | ) | $ | (6 | ) | $ | — | $ | — | ||||
Net loss available to common unitholders | $ | (4 | ) | $ | (4 | ) | — | — | ||||||
Net loss available to subordinated unitholders | $ | (2 | ) | $ | (2 | ) | — | — | ||||||
Denominator for earnings (loss) per share — common units | ||||||||||||||
Weighted-average common units outstanding | 41 | 41 | — | — | ||||||||||
Effect of equity-based awards | — | — | — | — | ||||||||||
Weighted-average common units for per unit calculation | 41 | 41 | — | — | ||||||||||
Denominator for earnings (loss) per share — subordinated units | ||||||||||||||
Weighted-average subordinated units outstanding | 28 | 28 | — | — | ||||||||||
Effect of equity-based awards | — | — | — | — | ||||||||||
Weighted-average subordinated units for per unit calculation | 28 | 28 | — | — | ||||||||||
Earnings (loss) per unit | ||||||||||||||
Loss per common unit | $ | (0.09 | ) | $ | (0.09 | ) | $ | — | $ | — | ||||
Loss per subordinated unit | $ | (0.09 | ) | $ | (0.09 | ) | $ | — | $ | — | ||||
Cash distributions declared and paid per unit | ||||||||||||||
Common units | $ | 0.3625 | $ | 0.3625 | $ | — | $ | — | ||||||
Subordinated units | $ | 0.3625 | $ | 0.3625 | $ | — | $ | — | ||||||
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). | ||||||||||||||
Credit_Agreements
Credit Agreements | 3 Months Ended |
Mar. 31, 2015 | |
Credit Agreements | |
Credit Agreements | 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 March 31, 2015, based on our leverage ratio on that date, the revolving credit facility margin was 1.625 percent. At March 31, 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 March 31, 2015, based on our leverage ratio on that date, the working capital note margin was 1.625 percent. At March 31, 2015 and December 31, 2014, we had borrowings of $43 million outstanding under the working capital note payable. | |
Contingencies
Contingencies | 3 Months Ended |
Mar. 31, 2015 | |
Contingencies | |
Contingencies | Note 8—Contingencies |
Retained risk—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 March 31, 2015, our drilling units had the insured value of approximately $1.965 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 March 31, 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 March 31, 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 March 31, 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. | |
Guarantees, letters of credit and surety bonds—At March 31, 2015 and December 31, 2014, we had no guarantees, letters of credit or surety bonds issued or outstanding. | |
Cash_Distributions
Cash Distributions | 3 Months Ended |
Mar. 31, 2015 | |
Cash Distributions. | |
Cash Distributions | Note 9—Cash Distributions |
Cash distribution to unitholders—On February 9, 2015, our board of directors approved a distribution 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. Of the $25 million distribution, we paid $7 million to our public common unitholders and an aggregate amount of $18 million to the Transocean Member. See Note 14—Subsequent Events. | |
Cash distributions to holder of noncontrolling interests—On January 15, 2015, we declared dividends for an aggregate amount of $52 million. On January 16, 2015, we made an aggregate payment of $25 million to the Transocean Member as holder of noncontrolling interests and the remaining $27 million was eliminated in consolidation. | |
EquityBased_Compensation_Plan
Equity-Based Compensation Plan | 3 Months Ended |
Mar. 31, 2015 | |
Equity-Based Compensation Plan | |
Equity-Based Compensation Plan | 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 March 31, 2015, we had 3.4 million units authorized and available to be granted under the Incentive Compensation Plan. | |
On February 24, 2015, we granted to certain executive officers and key employees 15,746 time-based phantom units, which vest in three equal installments beginning one year following the grant date. A phantom unit is a notional unit that has no voting rights and entitles the grantee to receive a common unit upon the vesting. The total grant-date fair value of the time-based awards was less than $1 million. | |
Related_Party_Transactions
Related Party Transactions | 3 Months Ended | |||
Mar. 31, 2015 | ||||
Related Party Transactions | ||||
Related Party Transactions | 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. 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 months ended March 31, 2015, we recognized costs of $24 million, recorded in operating and maintenance costs and expenses, and $1 million, 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 months ended March 31, 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 months ended March 31, 2015, we recognized costs of $24 million, recorded in operating and maintenance costs and expenses, and $4 million, recorded in general and administrative costs and expenses, for services under the master services agreements. In the three months ended March 31, 2015, we recognized insurance costs of $3 million, recorded in operating and maintenance costs and expenses. In the three months ended March 31, 2015, we acquired $9 million of materials and supplies purchased through the procurement services of Transocean Offshore Deepwater Drilling Inc. (“TODDI”). | ||||
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 months ended March 31, 2014, the Predecessor recognized costs of $24 million, recorded in operating and maintenance costs and expenses, for such personnel costs. In the three months ended March 31, 2014, the Predecessor recognized costs of $1 million, 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 months ended March 31, 2014, the Predecessor recognized costs of $8 million, recorded in operating and maintenance costs and expenses, for such services and assistance. | ||||
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 months ended March 31, 2014, the Predecessor recognized allocated insurance costs of $3 million, 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 months ended March 31, 2014, the Predecessor paid $13 million, 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. At March 31, 2015, there was no outstanding indemnification claim receivable. | ||||
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 months ended March 31, 2015 and 2014, we and the Predecessor recognized amortization of the license costs of $1 million, recorded in operating and maintenance costs and expenses. At March 31, 2015 and December 31, 2014, the carrying amount of the deferred license cost was $3 million and $4 million, respectively. | ||||
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 months ended March 31, 2015 and 2014, we recognized patent royalty expense of $5 million recorded in operating and maintenance costs and expenses. Of the $5 million patent royalty expense recognized in the three months ended March 31, 2015, we recognized a non-cash expense of $5 million with a corresponding entry to members’ equity, representing the fees paid by Transocean on our behalf with a corresponding entry to members’ equity. | ||||
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. | ||||
Supplemental_Cash_Flow_Informa
Supplemental Cash Flow Information | 3 Months Ended |
Mar. 31, 2015 | |
Supplemental Cash Flow Information | |
Supplemental Cash Flow Information | Note 12—Supplemental Cash Flow Information |
In the three months ended March 31, 2014, we transferred to Transocean’s other drilling units certain equipment with an aggregate net carrying amount of $18 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. | |
Financial_Instruments
Financial Instruments | 3 Months Ended | |||||||||||||
Mar. 31, 2015 | ||||||||||||||
Financial Instruments | ||||||||||||||
Financial Instruments | Note 13—Financial Instruments | |||||||||||||
The carrying amounts and fair values of our financial instruments were as follows: | ||||||||||||||
March 31, 2015 | December 31, 2014 | |||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||
amount | value | amount | value | |||||||||||
Cash and cash equivalents | $ | 164 | $ | 164 | $ | 86 | $ | 86 | ||||||
Working capital note payable to affiliate | 43 | 43 | 43 | 43 | ||||||||||
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 March 31, 2015 and December 31, 2014, the aggregate carrying amount of our cash equivalents was $145 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. | ||||||||||||||
Subsequent_Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2015 | |
Subsequent Events. | |
Subsequent Events | Note 14—Subsequent Events |
Cash distribution to unitholders—On May 4, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders. We expect to pay the aggregate cash distribution of $25 million on May 27, 2015 to our unitholders of record as of May 15, 2015, including an aggregate cash payment of $18 million to the Transocean Member. | |
Significant_Accounting_Policie1
Significant Accounting Policies (Policies) | 3 Months Ended | |||
Mar. 31, 2015 | ||||
Significant Accounting Policies | ||||
Presentation | 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 months ended March 31, 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 months ended March 31, 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 three months ended March 31, 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 all 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, 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 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. | ||||
Accordingly, we have prepared our condensed consolidated financial statements on the following basis: | ||||
· | Our condensed consolidated statement of operations for the three months ended March 31, 2015 consists of the consolidated results of operations of Transocean Partners. Our condensed consolidated statement of operations for the three months ended March 31, 2014 consists of the combined results of operations of the Predecessor. | |||
· | Our condensed consolidated balance sheets at March 31, 2015 and December 31, 2014 consist of the consolidated balances of Transocean Partners. | |||
· | Our condensed consolidated statement of equity for the three months ended March 31, 2015 consists of the consolidated activity of Transocean Partners. Our condensed consolidated statement of equity for the three months ended March 31, 2014 consists of the combined activity of the Predecessor. | |||
· | Our condensed consolidated statement of cash flows for the three months ended March 31, 2015 consists of the consolidated cash flows of Transocean Partners. Our condensed consolidated statement of cash flows for the three months ended March 31, 2014 consists of the combined cash flows of the Predecessor. | |||
Accounting estimates | 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 materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes, allocated costs and related party transactions. 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 | 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 | 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 | 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 months ended March 31, 2015, costs and expenses allocated to us by Transocean were $31 million, including $27 million and $4 million, recorded in operating and maintenance costs and general and administrative costs, respectively. 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 months ended March 31, 2014, the Predecessor recognized such allocated operating and maintenance costs of $6 million, including $5 million, for personnel costs. In the three months ended March 31, 2014, the Predecessor recognized such allocated general and administrative costs of $2 million, including $2 million, for personnel costs. | ||||
Equity-based compensation | 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”). 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 months ended March 31, 2015, equity-based compensation expense was less than $1 million. In the three months ended March 31, 2015, the income tax benefit on share-based compensation expense was less than $1 million. See Note 10—Equity-Based Compensation. | ||||
Accounts receivable | 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 March 31, 2015 and December 31, 2014, the aggregate face value of our long-term accounts receivable was $25 million and $24 million, respectively. At March 31, 2015, the aggregate carrying amount of our long-term accounts receivable was $23 million, including $14 million due within one year and $9 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 March 31, 2015 and December 31, 2014, our long-term accounts receivable had a weighted average effective interest rate of 11 percent. | |||
Property and equipment | 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 March 31, 2015, the aggregate carrying amount of our property and equipment represented approximately 75 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 months ended March 31, 2015, our change in this estimate resulted in an increase of less than $1 million to depreciation expense. For the year ending December 31, 2015, we expect our change in this estimate to result in an increase of approximately $1 million to depreciation expense. | ||||
Reclassifications | 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 | 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. | |||
Income_Taxes_Tables
Income Taxes (Tables) | 3 Months Ended | |||||||
Mar. 31, 2015 | ||||||||
Income Taxes | ||||||||
Schedule of valuation allowance | The valuation allowance for our non-current deferred tax assets was as follows (in millions): | |||||||
March 31, | December 31, | |||||||
2015 | 2014 | |||||||
Valuation allowance for non-current deferred tax assets | $ | 3 | $ | 2 | ||||
Schedule of unrecognized tax benefits, including related interest and penalties | 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): | |||||||
March 31, | December 31, | |||||||
2015 | 2014 | |||||||
Unrecognized tax benefits, excluding interest and penalties | $ | 1 | $ | 1 | ||||
Interest and penalties | — | — | ||||||
Unrecognized tax benefits, including interest and penalties | $ | 1 | $ | 1 | ||||
Earnings_Loss_Per_unit_Tables
Earnings (Loss) Per unit (Tables) | 3 Months Ended | |||||||||||||
Mar. 31, 2015 | ||||||||||||||
Earnings (Loss) Per Unit | ||||||||||||||
Schedule of numerator and denominator used for the computation of basic and diluted per unit earnings | ||||||||||||||
The numerator and denominator used for the computation of basic and diluted per unit earnings (loss) were as follows (in millions, except per unit data): | ||||||||||||||
Three months ended March 31, | ||||||||||||||
2015 | 2014 | |||||||||||||
Basic | Diluted | Basic | Diluted | |||||||||||
Numerator for earnings (loss) per share | ||||||||||||||
Net loss attributable to controlling interest | $ | (6 | ) | $ | (6 | ) | $ | — | $ | — | ||||
Undistributed earnings allocable to participating securities | — | — | — | — | ||||||||||
Net loss available to unitholders | $ | (6 | ) | $ | (6 | ) | $ | — | $ | — | ||||
Net loss available to common unitholders | $ | (4 | ) | $ | (4 | ) | — | — | ||||||
Net loss available to subordinated unitholders | $ | (2 | ) | $ | (2 | ) | — | — | ||||||
Denominator for earnings (loss) per share — common units | ||||||||||||||
Weighted-average common units outstanding | 41 | 41 | — | — | ||||||||||
Effect of equity-based awards | — | — | — | — | ||||||||||
Weighted-average common units for per unit calculation | 41 | 41 | — | — | ||||||||||
Denominator for earnings (loss) per share — subordinated units | ||||||||||||||
Weighted-average subordinated units outstanding | 28 | 28 | — | — | ||||||||||
Effect of equity-based awards | — | — | — | — | ||||||||||
Weighted-average subordinated units for per unit calculation | 28 | 28 | — | — | ||||||||||
Earnings (loss) per unit | ||||||||||||||
Loss per common unit | $ | (0.09 | ) | $ | (0.09 | ) | $ | — | $ | — | ||||
Loss per subordinated unit | $ | (0.09 | ) | $ | (0.09 | ) | $ | — | $ | — | ||||
Cash distributions declared and paid per unit | ||||||||||||||
Common units | $ | 0.3625 | $ | 0.3625 | $ | — | $ | — | ||||||
Subordinated units | $ | 0.3625 | $ | 0.3625 | $ | — | $ | — | ||||||
Financial_Instruments_Tables
Financial Instruments (Tables) | 3 Months Ended | |||||||||||||
Mar. 31, 2015 | ||||||||||||||
Financial Instruments | ||||||||||||||
Schedule of carrying amounts and fair values of our financial instruments | March 31, 2015 | December 31, 2014 | ||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||
amount | value | amount | value | |||||||||||
Cash and cash equivalents | $ | 164 | $ | 164 | $ | 86 | $ | 86 | ||||||
Working capital note payable to affiliate | 43 | 43 | 43 | 43 | ||||||||||
Business_Details
Business (Details) (USD $) | 0 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Aug. 05, 2014 | Jul. 31, 2014 | Jul. 29, 2014 |
Offer price of common units (in dollars per share) | $22 | ||
Transocean | |||
Common units offered in initial public offering | 20.1 | ||
Percentage of common units sold in public offering and purchased by underwriters | 29.20% | ||
Common units held by parent | 21.3 | ||
Subordinated units held by parent | 27.6 | ||
Percentage of limited liability company interest held by parent | 70.80% | ||
Net cash proceeds from offering | $417 | ||
Underwriting discounts, commissions and other offering costs | $26 | ||
Rig Cos and subsidiaries | |||
Ownership percentage | 51.00% | ||
Rig Cos and subsidiaries | Transocean | |||
Ownership percentage | 49.00% | ||
Predecessor Business | |||
Percentage of the combined results of operations, assets and liabilities of the Predecessor Business, included in the condensed combined financial statements of the Predecessor | 100.00% |
Significant_Accounting_Policie2
Significant Accounting Policies (Details) (USD $) | 3 Months Ended | 12 Months Ended | 3 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 | Mar. 31, 2014 |
Allocated indirect and overhead costs | |||
Allocated costs and expenses | $31 | ||
Accounts receivable | |||
Face value of long term accounts receivable | 25 | 24 | |
Aggregate carrying amount of long term accounts receivable (Non-Current) | 23 | 22 | |
Weighted average effective interest rates of long term accounts receivable (as a percent) | 11.00% | 11.00% | |
Property and equipment | |||
Property and equipment as a percentage of total assets | 75.00% | ||
Maximum | |||
Equity-based compensation | |||
Equity-based compensation expense | 1 | ||
Income tax benefit on equity-based compensation expense | 1 | ||
Drilling units | Maximum | |||
Property and equipment | |||
Increase in depreciation expense due to adjustment in salvage value | 1 | ||
Increase in depreciation expense in 2015 due to adjustment in salvage value | 1 | ||
Accounts receivable | |||
Accounts receivable | |||
Aggregate carrying amount of long term accounts receivable (Current) | 14 | 12 | |
Other assets | |||
Accounts receivable | |||
Aggregate carrying amount of long term accounts receivable (Non-Current) | 9 | 10 | |
Operating and maintenance costs and expenses | |||
Allocated indirect and overhead costs | |||
Allocated costs and expenses | 27 | ||
General and administrative costs and expenses | |||
Allocated indirect and overhead costs | |||
Allocated costs and expenses | 4 | ||
Predecessor Business | Transocean | |||
Allocated indirect and overhead costs | |||
Allocated operating and maintenance costs | 6 | ||
Allocated personnel costs included in operating and maintenance costs | 5 | ||
Allocated general and administrative costs | 2 | ||
Allocated personnel costs included in general and administrative costs | $2 |
Goodwill_Impairment_Details
Goodwill Impairment (Details) (USD $) | 3 Months Ended |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 |
Goodwill Impairment | |
Estimate of loss on impairment of goodwill | $67 |
Estimate of Loss on impairment of goodwill, tax effect | 0 |
Estimate of loss on impairment of goodwill attributable to controlling interest | 34 |
Estimate of loss on impairment of goodwill per diluted share | $0.50 |
Estimate of loss on impairment of goodwill attributable to noncontrolling interest | $33 |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2015 | Mar. 31, 2014 | Dec. 31, 2014 |
Components of provision (benefit) for income taxes | |||
Annual effective tax rates (as a percent) | 6.40% | ||
Deferred taxes | |||
Valuation allowance for non-current deferred tax assets | $3 | $2 | |
Unrecognized tax benefits | |||
Unrecognized tax benefits, excluding interest and penalties | 1 | 1 | |
Unrecognized tax benefits, including interest and penalties | $1 | $1 | |
Predecessor Business | |||
Components of provision (benefit) for income taxes | |||
Annual effective tax rates (as a percent) | 8.50% |
Earnings_Loss_Per_Unit_Details
Earnings (Loss) Per Unit (Details) (USD $) | 3 Months Ended |
In Millions, except Per Share data, unless otherwise specified | Mar. 31, 2015 |
Numerator for earnings (loss) per unit, basic | |
Net loss attributable to controlling interest | ($6) |
Net loss available to unitholders | -6 |
Net loss available to common unitholders | -4 |
Net loss available to subordinated unitholders | -2 |
Numerator for earnings (loss) per unit, diluted | |
Net loss attributable to controlling interest | -6 |
Net loss available to unitholders | -6 |
Net loss available to common unitholders | -4 |
Net loss available to subordinated unitholders | -2 |
Common units | |
Numerator for earnings (loss) per unit, basic | |
Net loss attributable to controlling interest | -4 |
Denominator for earnings (loss ) per unit, basic | |
Weighted-average units outstanding (in units) | 41 |
Weighted average common units for per unit calculation (in units) | 41 |
Earnings (loss) per unit, basic | |
Earnings (loss) per unit, basic | ($0.09) |
Cash distributions declared and paid per unit | |
Distribution (in dollars per unit) | $0.36 |
Numerator for earnings (loss) per unit, diluted | |
Net loss attributable to controlling interest | -4 |
Denominator for earnings (loss) per unit, diluted | |
Weighted-average units outstanding (in units) | 41 |
Weighted-average units for unit calculation (in units) | 41 |
Earnings (loss) per unit, diluted | |
Earnings (loss) per unit, diluted | ($0.09) |
Cash distributions declared and paid per unit | |
Distribution (in dollars per unit) | $0.36 |
Subordinated units | |
Numerator for earnings (loss) per unit, basic | |
Net loss attributable to controlling interest | -2 |
Denominator for earnings (loss ) per unit, basic | |
Weighted-average units outstanding (in units) | 28 |
Weighted average common units for per unit calculation (in units) | 28 |
Earnings (loss) per unit, basic | |
Earnings (loss) per unit, basic | ($0.09) |
Cash distributions declared and paid per unit | |
Distribution (in dollars per unit) | $0.36 |
Numerator for earnings (loss) per unit, diluted | |
Net loss attributable to controlling interest | ($2) |
Denominator for earnings (loss) per unit, diluted | |
Weighted-average units outstanding (in units) | 28 |
Weighted-average units for unit calculation (in units) | 28 |
Earnings (loss) per unit, diluted | |
Earnings (loss) per unit, diluted | ($0.09) |
Cash distributions declared and paid per unit | |
Distribution (in dollars per unit) | $0.36 |
Credit_Agreements_Details
Credit Agreements (Details) (USD $) | 0 Months Ended | |||
In Millions, unless otherwise specified | Mar. 31, 2015 | Aug. 05, 2014 | Jul. 29, 2014 | Dec. 31, 2014 |
Credit Agreements | ||||
Accounts payable to affiliates | $105 | $76 | ||
Five Year Revolving Credit Facility | ||||
Credit Agreements | ||||
Aggregate borrowing capacity | 300 | |||
Credit facility term | 5 years | |||
Basis spread on variable rate (as a percent) | 1.63% | |||
Credit facility amount outstanding | 0 | 0 | ||
Available borrowing capacity | 300 | 300 | ||
Five Year Revolving Credit Facility | Minimum | ||||
Credit Agreements | ||||
Percentage of commitment fees | 0.23% | |||
Five Year Revolving Credit Facility | Maximum | ||||
Credit Agreements | ||||
Percentage of commitment fees | 0.33% | |||
Five Year Revolving Credit Facility | LIBOR | Minimum | ||||
Credit Agreements | ||||
Basis spread on variable rate (as a percent) | 1.63% | |||
Five Year Revolving Credit Facility | LIBOR | Maximum | ||||
Credit Agreements | ||||
Basis spread on variable rate (as a percent) | 2.25% | |||
Five Year Revolving Credit Facility | Base rate | ||||
Credit Agreements | ||||
Percentage reduction to the calculated variable rate | 1.00% | |||
Working capital notes payable | ||||
Credit Agreements | ||||
Face amount of debt | 43 | |||
Outstanding principal amount | $43 | $43 | ||
Working capital notes payable | LIBOR | ||||
Credit Agreements | ||||
Basis spread on variable rate (as a percent) | 1.63% | |||
Working capital notes payable | LIBOR | Minimum | ||||
Credit Agreements | ||||
Basis spread on variable rate (as a percent) | 1.63% | |||
Working capital notes payable | LIBOR | Maximum | ||||
Credit Agreements | ||||
Basis spread on variable rate (as a percent) | 2.25% |
Contingencies_Details
Contingencies (Details) (USD $) | 3 Months Ended | 12 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2015 | Dec. 31, 2014 |
Commitments and Contingencies | ||
Guarantees outstanding | $0 | $0 |
Letters of credit outstanding | 0 | 0 |
Surety bonds outstanding | 0 | 0 |
Retained risk | ||
Commitments and Contingencies | ||
Aggregate insured value of drilling rig fleet | 1,965 | |
Retained risk | Transocean | ||
Commitments and Contingencies | ||
Maximum percentage of asset insured value covered by damage mitigation insurance | 50.00% | |
Commercial market excess liability coverage | 700 | |
Per occurrence deductible on excess liability for which risk is retained by wholly-owned insurance company | 50 | |
Per occurrence deductible on collision liability claims | 10 | |
Per occurrence deductible on crew personal injury and other third-party non-crew claims | 5 | |
Liability loss excess amount for commercial market excess liability coverage | 750 | |
Additional insurance that covers expenses that would otherwise be assumed by the well owner | 100 | |
Minimum | Retained risk | ||
Commitments and Contingencies | ||
Per occurrence insurance deductible on hull and machinery | 10 | |
Maximum | Retained risk | ||
Commitments and Contingencies | ||
Per occurrence insurance deductible on hull and machinery | $11 |
Cash_Distributions_Details
Cash Distributions (Details) (USD $) | 0 Months Ended | 3 Months Ended | 0 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Jan. 16, 2015 | Jan. 15, 2015 | Mar. 31, 2015 | Feb. 26, 2015 | Feb. 09, 2015 |
Distribution to unitholders | $25 | ||||
Approved distribution to unitholders | 52 | ||||
Distribution to unitholders paid and eliminated | 27 | ||||
Transocean | |||||
Distribution to unitholders | 25 | 18 | |||
Unitholders | |||||
Distribution (in dollars per unit) | $0.36 | ||||
Distribution to unitholders | 25 | ||||
Public common unitholders | |||||
Distribution to unitholders | $7 |
EquityBased_Compensation_Plan_
Equity-Based Compensation Plan (Details) (USD $) | 0 Months Ended | |
In Millions, except Share data, unless otherwise specified | Feb. 24, 2015 | Mar. 31, 2015 |
Phantom units | ||
Equity-Based Compensation Plan | ||
Number of phantom units granted | 15,746 | |
Number of equal installments vesting | 3 | |
Period from grant after which vesting begins | 1 year | |
Incentive Compensation Plan | ||
Equity-Based Compensation Plan | ||
Numbers of units authorized | 3,400,000 | |
Maximum | Phantom units | ||
Equity-Based Compensation Plan | ||
Total grant date fair value | 1 |
Related_Party_Transactions_Det
Related Party Transactions (Details) (USD $) | 3 Months Ended | 12 Months Ended | 0 Months Ended | 3 Months Ended | |
Mar. 31, 2015 | Dec. 31, 2014 | Aug. 05, 2014 | Mar. 31, 2014 | Jul. 29, 2014 | |
item | |||||
Related Party Transactions | |||||
Indemnification claim for lost revenues | $19,000,000 | ||||
Proceeds from affiliates for indemnification | 10,000,000 | ||||
Accounts receivable from affiliates | 8,000,000 | 28,000,000 | |||
Number of drilling units equipped with patented dual activity technology | 3 | ||||
Number of drilling stations to employ structures, equipment and techniques of dual-activity technology | 2 | ||||
Five Year Revolving Credit Facility | |||||
Related Party Transactions | |||||
Aggregate borrowing capacity | 300,000,000 | ||||
Credit facility term | 5 years | ||||
Working capital notes payable | |||||
Related Party Transactions | |||||
Face amount of debt | 43,000,000 | ||||
Secondment agreements | |||||
Related Party Transactions | |||||
Notice period for termination of agreement | 90 days | ||||
Support agreement | General and administrative costs and expenses | Maximum | |||||
Related Party Transactions | |||||
Cost and expenses | 1,000,000 | ||||
Master services agreements | |||||
Related Party Transactions | |||||
Notice period for termination of agreement | 90 days | ||||
Term of agreement | 5 years | ||||
Percentage of costs and expenses incurred in connection with provision of services considered for payment of fees | 5.00% | ||||
Percentage markup on costs incurred in connection with capital spare or inventory considered for payment of fees | 4.00% | ||||
Percentage markup of allocable share of costs in connection with provision of services for capital spares or inventory added for payment of fees | 4.00% | ||||
Omnibus Agreement | |||||
Related Party Transactions | |||||
Period after effective date of agreement for purchase of interest in drillship | 5 years | ||||
Minimum percentage of interest to be offered for purchase of drillships | 51.00% | ||||
Number of ultra deepwater drillships in which interest is required to be offered | 4 | ||||
Number of ultra deepwater drillships available for offer to purchase interest | 6 | ||||
Services for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services | Master services agreements | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Cost and expenses | 24,000,000 | ||||
Services for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services | Master services agreements | General and administrative costs and expenses | |||||
Related Party Transactions | |||||
Cost and expenses | 4,000,000 | ||||
Insurance costs allocated to drilling rigs | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Cost and expenses | 3,000,000 | ||||
Personnel costs | Secondment agreements | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Cost and expenses | 24,000,000 | ||||
Personnel costs | Secondment agreements | General and administrative costs and expenses | |||||
Related Party Transactions | |||||
Cost and expenses | 1,000,000 | ||||
TODDI | Payment for materials and supplies settled through net investment | Master services agreements | |||||
Related Party Transactions | |||||
Cost and expenses | 9,000,000 | ||||
TODDI | License agreements | |||||
Related Party Transactions | |||||
Deferred license cost | 3,000,000 | 4,000,000 | |||
TODDI | License agreements | Maximum | |||||
Related Party Transactions | |||||
Amortized license cost | 1,000,000 | ||||
TODDI | Royalty fees | |||||
Related Party Transactions | |||||
Cost and expenses | 5,000,000 | ||||
Non-cash expense with a corresponding entry to members' equity | 5,000,000 | ||||
Transocean | |||||
Related Party Transactions | |||||
Accounts receivable from affiliates | 0 | 10,000,000 | |||
Transocean | Omnibus Agreement | |||||
Related Party Transactions | |||||
Period of indemnification | 5 years | ||||
Maximum amount of lost revenue arising out of the failure to receive an operating dayrate from Chevron for Discoverer Clear Leader | 100,000,000 | ||||
Transocean | Omnibus Agreement | Minimum | |||||
Related Party Transactions | |||||
Aggregate amount of indemnification for which Transocean is liable for claims | 500,000 | ||||
Transocean | Omnibus Agreement | Maximum | |||||
Related Party Transactions | |||||
Aggregate amount of indemnity coverage provided by Transocean for such environmental and human health and safety liabilities | 10,000,000 | ||||
Transocean affiliate | Five Year Revolving Credit Facility | |||||
Related Party Transactions | |||||
Credit facility term | 5 years | ||||
Transocean affiliate | Working capital notes payable | |||||
Related Party Transactions | |||||
Face amount of debt | 43,000,000 | ||||
Rig Cos and subsidiaries | |||||
Related Party Transactions | |||||
Ownership percentage | 51.00% | ||||
Rig Cos and subsidiaries | Transocean | |||||
Related Party Transactions | |||||
Ownership percentage | 49.00% | ||||
Rig Cos and subsidiaries | Transocean | Omnibus Agreement | |||||
Related Party Transactions | |||||
Period within which after the closing of offering Transocean agreed to indemnify for certain defects | 3 years | ||||
Predecessor Business | Insurance costs allocated to drilling rigs | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Cost and expenses | 3,000,000 | ||||
Predecessor Business | Personnel costs | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Cost and expenses | 24,000,000 | ||||
Predecessor Business | Personnel benefit costs | |||||
Related Party Transactions | |||||
Cost and expenses | 1,000,000 | ||||
Predecessor Business | TODDI | Services for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services | |||||
Related Party Transactions | |||||
Cost and expenses | 8,000,000 | ||||
Predecessor Business | TODDI | Payment for materials and supplies settled through net investment | |||||
Related Party Transactions | |||||
Cost and expenses | 13,000,000 | ||||
Predecessor Business | TODDI | License agreements | |||||
Related Party Transactions | |||||
Original license cost | 20,000,000 | ||||
Predecessor Business | TODDI | License agreements | Minimum | |||||
Related Party Transactions | |||||
Percentage of quarterly royalty fees paid under license agreement | 3.00% | ||||
Predecessor Business | TODDI | License agreements | Maximum | |||||
Related Party Transactions | |||||
Percentage of quarterly royalty fees paid under license agreement | 5.00% | ||||
Predecessor Business | TODDI | Royalty fees | |||||
Related Party Transactions | |||||
Cost and expenses | $5,000,000 |
Supplemental_Cash_Flow_Informa1
Supplemental Cash Flow Information (Details) (USD $) | 3 Months Ended |
In Millions, unless otherwise specified | Mar. 31, 2014 |
Supplemental Cash Flow Information | |
Aggregate value of drilling unit equipment transferred to parent - primarily from Development Driller III | $18 |
Financial_Instruments_Details
Financial Instruments (Details) (USD $) | Mar. 31, 2015 | Dec. 31, 2014 |
In Millions, unless otherwise specified | ||
Financial Instruments | ||
Carrying amount of cash equivalents | $145 | $40 |
Carrying amount | ||
Financial Instruments | ||
Cash and cash equivalents | 164 | 86 |
Working capital note payable to affiliate | 43 | 43 |
Fair value | ||
Financial Instruments | ||
Cash and cash equivalents | 164 | 86 |
Working capital note payable to affiliate | $43 | $43 |
Subsequent_Events_Details
Subsequent Events (Details) (USD $) | 0 Months Ended | 3 Months Ended | 0 Months Ended | ||
In Millions, except Per Share data, unless otherwise specified | Jan. 15, 2015 | Mar. 31, 2015 | 4-May-15 | Feb. 26, 2015 | Jan. 16, 2015 |
Subsequent Events | |||||
Approved distribution to unitholders | $52 | ||||
Distribution to unitholders | 25 | ||||
Subsequent Events | |||||
Subsequent Events | |||||
Distribution (in dollars per unit) | $0.36 | ||||
Approved distribution to unitholders | 25 | ||||
Transocean | |||||
Subsequent Events | |||||
Distribution to unitholders | 18 | 25 | |||
Transocean | Subsequent Events | |||||
Subsequent Events | |||||
Distribution to unitholders | $18 |