Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Feb. 16, 2016 | Jun. 30, 2015 | |
Document and Entity Information | |||
Entity Registrant Name | Transocean Partners LLC | ||
Entity Central Index Key | 1,607,250 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2015 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Public Float | $ 278 | ||
Entity Common Stock, Shares Outstanding | 41,076,208 | ||
Document Fiscal Year Focus | 2,015 | ||
Document Fiscal Period Focus | FY |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating revenues | |||
Contract drilling revenues | $ 564 | $ 557 | |
Other revenues | 16 | 10 | |
Total operating revenues | 580 | 567 | |
Costs and expenses | |||
Operating and maintenance | 245 | 248 | |
Depreciation | 68 | 66 | |
General and administrative | 24 | 20 | |
Total costs and expenses | 337 | 334 | |
Loss on impairment | (356) | ||
Loss on disposal of assets, net | (1) | ||
Operating income (loss) | (114) | 233 | |
Interest income | 2 | 3 | |
Interest expense | (1) | (1) | |
Income (loss) before income tax expense | (113) | 235 | |
Income tax expense | 14 | 20 | |
Net income (loss) | (127) | 215 | |
Net income attributable to Predecessor | 135 | ||
Net income (loss) subsequent to initial public offering | (127) | 80 | |
Net income (loss) attributable to noncontrolling interest | (56) | 44 | |
Net income (loss) attributable to controlling interest | (71) | 36 | |
Predecessor Business | |||
Costs and expenses | |||
Income tax expense | $ 23 | ||
Net income (loss) | 189 | ||
Predecessor Business | |||
Operating revenues | |||
Contract drilling revenues | 517 | ||
Other revenues | 9 | ||
Total operating revenues | 526 | ||
Costs and expenses | |||
Operating and maintenance | 242 | ||
Depreciation | 66 | ||
General and administrative | 10 | ||
Total costs and expenses | 318 | ||
Operating income (loss) | 208 | ||
Interest income | 4 | ||
Income (loss) before income tax expense | 212 | ||
Income tax expense | 23 | ||
Net income (loss) | $ 189 | ||
Common units | |||
Costs and expenses | |||
Net income (loss) attributable to controlling interest | $ (43) | $ 22 | |
Earnings (loss) per unit—basic | |||
Earnings (loss) per unit—basic | $ (1.02) | $ 0.52 | |
Earnings (loss) per unit—diluted | |||
Earnings (loss) per unit—diluted | $ (1.02) | $ 0.52 | |
Weighted‑average units outstanding—basic | |||
Weighted-average units outstanding—basic (in units) | 41 | 41 | |
Weighted‑average units outstanding—diluted | |||
Weighted-average units outstanding—diluted (in units) | 41 | 41 | |
Subordinated units | |||
Costs and expenses | |||
Net income (loss) attributable to controlling interest | $ (28) | $ 14 | |
Earnings (loss) per unit—basic | |||
Earnings (loss) per unit—basic | $ (1.02) | $ 0.52 | |
Earnings (loss) per unit—diluted | |||
Earnings (loss) per unit—diluted | $ (1.02) | $ 0.52 | |
Weighted‑average units outstanding—basic | |||
Weighted-average units outstanding—basic (in units) | 28 | 28 | |
Weighted‑average units outstanding—diluted | |||
Weighted-average units outstanding—diluted (in units) | 28 | 28 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Assets | ||
Cash and cash equivalents | $ 159 | $ 86 |
Accounts receivable | 115 | 112 |
Accounts receivable from affiliates | 1 | 28 |
Materials and supplies, net | 34 | 41 |
Prepaid assets | 7 | 6 |
Total current assets | 316 | 273 |
Property and equipment | 2,296 | 2,302 |
Less accumulated depreciation | (401) | (336) |
Property and equipment, net | 1,895 | 1,966 |
Goodwill | 356 | |
Deferred income taxes, net | 10 | 15 |
Other assets | 10 | 22 |
Total assets | 2,231 | 2,632 |
Liabilities and equity | ||
Accounts payable to affiliates | 51 | 76 |
Debt due to affiliates within one year | 43 | |
Deferred revenues | 15 | 18 |
Other current liabilities | 2 | 1 |
Total current liabilities | 68 | 138 |
Long-term tax liability | 3 | 1 |
Deferred revenues | 13 | |
Drilling contract intangible liability | 14 | 29 |
Other long-term liabilities | 1 | |
Total long-term liabilities | $ 18 | $ 43 |
Commitments and contingencies | ||
Total members' equity | $ 1,262 | $ 1,411 |
Noncontrolling interest | 883 | 1,040 |
Total equity | 2,145 | 2,451 |
Total liabilities and equity | 2,231 | 2,632 |
Common units | ||
Liabilities and equity | ||
Common units, 41,287,810 and 41,379,310 authorized, issued and outstanding at December 31, 2015 and 2014, respectively | 757 | 847 |
Total equity | 757 | 847 |
Subordinated units | ||
Liabilities and equity | ||
Subordinated units, 27,586,207 issued and outstanding at December 31, 2015 and 2014, respectively | 505 | 564 |
Total equity | $ 505 | $ 564 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2015 | Dec. 31, 2014 |
Common units | ||
Units issued | 41,287,810 | 41,379,310 |
Units outstanding | 41,287,810 | 41,379,310 |
Subordinated units | ||
Units issued | 27,586,207 | 27,586,207 |
Units outstanding | 27,586,207 | 27,586,207 |
CONSOLIDATED STATEMENTS OF EQUI
CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Millions, $ in Millions | Common units | Subordinated units | Total members' equity | Net investment | Noncontrolling interest | Total |
Balance, beginning of period (Predecessor Business) at Dec. 31, 2012 | $ 2,388 | $ 2,388 | ||||
Increase (Decrease) in Partners' Capital | ||||||
Effect of formation transactions | Predecessor Business | $ 0 | $ 0 | ||||
Effect of formation transactions | 0 | 0 | ||||
Net income attributable to the Predecessor | Predecessor Business | 189 | 189 | ||||
Distributions to the Predecessor parent, net | Predecessor Business | (233) | (233) | ||||
Balance, end of period (Predecessor Business) at Dec. 31, 2013 | 2,344 | 2,344 | ||||
Balance, end of period at Dec. 31, 2013 | 2,344 | 2,344 | ||||
Increase (Decrease) in Partners' Capital | ||||||
Effect of formation transactions | $ 821 | $ 547 | $ 1,368 | (2,364) | $ 996 | |
Effect of formation transactions (in shares) | 41 | 28 | ||||
Net income (loss) attributable to controlling interest | $ 22 | $ 14 | 36 | 36 | ||
Net income (loss) subsequent to initial public offering | 80 | |||||
Net income attributable to the Predecessor | 135 | 135 | ||||
Contributions for parent payment of patent royalties | 4 | 3 | 7 | 7 | ||
Contributions for parent indemnification of lost revenues | 11 | 8 | 19 | 19 | ||
Distributions of available cash to unitholders | (9) | (6) | (15) | (15) | ||
Distributions to the Predecessor parent, net | $ (115) | (115) | ||||
Net income (loss) attributable to noncontrolling interest | 44 | (44) | ||||
Distributions for working capital adjustment | (2) | (2) | (4) | (4) | ||
Balance, end of period at Dec. 31, 2014 | $ 847 | $ 564 | 1,411 | 1,040 | 2,451 | |
Balance, end of period (in shares) at Dec. 31, 2014 | 41 | 28 | ||||
Increase (Decrease) in Partners' Capital | ||||||
Effect of formation transactions | $ 0 | $ 0 | ||||
Effect of formation transactions (in shares) | 0 | 0 | ||||
Net income (loss) attributable to controlling interest | $ (43) | $ (28) | (71) | (71) | ||
Net income (loss) subsequent to initial public offering | (127) | |||||
Contributions for parent payment of patent royalties | 14 | 9 | 23 | 23 | ||
Distributions of available cash to unitholders | (60) | (40) | (100) | (100) | ||
Distributions to holder of non controlling interests | (101) | (101) | ||||
Net income (loss) attributable to noncontrolling interest | (56) | 56 | ||||
Cancellation of repurchased common units | (1) | (1) | (1) | |||
Balance, end of period at Dec. 31, 2015 | $ 757 | $ 505 | $ 1,262 | $ 883 | $ 2,145 | |
Balance, end of period (in shares) at Dec. 31, 2015 | 41 | 28 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Cash flows from operating activities | |||
Net income (loss) | $ (127) | $ 215 | |
Adjustments to reconcile to net cash provided by operating activities | |||
Amortization of drilling contract intangible | (15) | (15) | |
Depreciation | 68 | 66 | |
Patent royalties expense | 23 | 7 | |
Loss on impairment | 356 | ||
Deferred income taxes | 5 | 18 | |
Other, net | 2 | ||
Changes in deferred revenues, net | (16) | (36) | |
Changes in deferred costs, net | 2 | (4) | |
Changes in operating assets and liabilities | |||
Decrease in accounts receivable, net | 9 | 4 | |
(Increase) decrease in other current assets, net | 5 | (8) | |
Increase in current liabilities | 1 | ||
Increase (decrease) in balances due to affiliates, net | (2) | (60) | |
Increase in income tax liability, net | 1 | 3 | |
Net cash provided by operating activities | 312 | 190 | |
Cash flows from investing activities | |||
Payments to affiliates for capital expenditures | (16) | (3) | |
Proceeds from affiliates for disposal of assets, net | 12 | ||
Net cash used in investing activities | (4) | (3) | |
Cash flows from financing activities | |||
Proceeds from working capital note payable to affiliate | 43 | ||
Repayment of working capital note payable to affiliate | (43) | ||
Contributions resulting from formation transactions | 8 | ||
Contributions for parent indemnification of lost revenues | 10 | 9 | |
Distributions of available cash to unitholders | (100) | (15) | |
Distributions to holder of noncontrolling interests | (101) | ||
Distributions to the Predecessor parent, net | (141) | ||
Distributions to affiliate for working capital adjustment | (5) | ||
Payments to repurchase common units | (1) | ||
Net cash used in financing activities | (235) | (101) | |
Net increase in cash and cash equivalents | 73 | 86 | |
Cash and cash equivalents at beginning of period | 86 | ||
Cash and cash equivalents at end of period | $ 159 | $ 86 | |
Predecessor Business | |||
Cash flows from operating activities | |||
Net income (loss) | $ 189 | ||
Adjustments to reconcile to net cash provided by operating activities | |||
Amortization of drilling contract intangible | (18) | ||
Depreciation | 66 | ||
Deferred income taxes | 15 | ||
Other, net | 1 | ||
Changes in deferred revenues, net | (29) | ||
Changes in deferred costs, net | 4 | ||
Changes in operating assets and liabilities | |||
Decrease in accounts receivable, net | 22 | ||
(Increase) decrease in other current assets, net | (13) | ||
Increase in income tax liability, net | 2 | ||
Net cash provided by operating activities | 239 | ||
Cash flows from investing activities | |||
Payments to affiliates for capital expenditures | (4) | ||
Net cash used in investing activities | (4) | ||
Cash flows from financing activities | |||
Distributions to the Predecessor parent, net | (235) | ||
Net cash used in financing activities | $ (235) |
Business
Business | 12 Months Ended |
Dec. 31, 2015 | |
Business | |
Business | Note 1—Busines s Transocean Partners LLC (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean Partners”, “we”, “us”, or “our”), a Marshall Islands limited liability company, was formed on February 6, 2014 by Transocean Partners Holdings Limited, a Cayman Islands company (the “Transocean Member”) and a wholly owned subsidiary of Transocean Ltd. (together with its affiliates, unless the context requires otherwise, “Transocean”), to own, operate and acquire modern, technologically advanced offshore drilling rigs. At December 31, 2015, the drilling units in our fleet included the ultra ‑deepwater drillships Discoverer Inspiration and Discoverer Clear Leader and the ultra ‑deepwater semisubmersible Development Driller III , which are located in the United States (“U.S.”) Gulf of Mexico. We own a 51 percent interest in each of the entities that owns and operates the drilling units in our fleet (each individually, a “RigCo”, and collectively, the “RigCos”). The Transocean Member owns the remaining 49 percent noncontrolling interest in each of the RigCos. On August 5, 2014, we completed the initial public offering of 20.1 million common units, which trade on the New York Stock Exchange under the symbol “RIGP.” The Transocean Member holds the remaining 21.3 million common units and 27.6 million subordinated units, which collectively represented a 70.8 percent limited l iability company interest in us at the time of our initial public offering, and all of our incentive distribution rights (see Note 10—Unit Repurchase Program and Note 18—Subsequent Events). As a result of the offering, the Transocean Member received net cash proceeds of $417 million, after deducting approximately $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 Policies
Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2015 | |
Significant Accounting Policies | |
Significant Accounting Policies | Note 2—Significant Accounting Policies Presentation —For periods prior to August 5, 2014, the combined financial information of the Predecessor was derived from Transocean’s accounting records. The 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 among the Predecessor Business within the Predecessor have been eliminated. For the periods following August 5, 2014, the consolidated financial statements reflect our consolidated results of operations, financial position and cash flows. We have presented 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 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. Transocean uses a centralized approach to treasury services to perform cash management for the operations of its affiliates. Under the Master Services Agreement, Transocean provides its treasury services to manage our cash and cash equivalents. The Predecessor had no bank accounts, and Transocean did not allocate its cash and cash equivalents to the Predecessor. The Predecessor transferred the cash generated and used by its operations to Transocean, and Transocean funded the Predecessor’s operating and investing activities as needed. Accordingly, the Predecessor’s transfers of cash to and from Transocean’s treasury were presented as net distributions to the Predecessor’s parent on our consolidated statements of equity and in our financing activities on our 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 consolidated financial statements on the following basis: § Our consolidated statement of operations for the year ended December 31, 2015 consists of the consolidated results of operations of Transocean Partners. Our consolidated statement of operations for the year ended December 31, 2014 consists of the consolidated results of operations of Transocean Partners for the period from August 5, 2014 through December 31, 2014 and the combined results of operations of the Predecessor for the beginning of the period through August 4, 2014. Our consolidated statement of operations for the year ended December 31, 2013 consists entirely of the combined results of operations of the Predecessor. § Our consolidated balance sheets at December 31, 2015 and 2014 consist of the consolidated balances of Transocean Partners. § Our consolidated statement of equity for the year ended December 31, 2015 consists of the consolidated activity of Transocean Partners. Our consolidated statement of equity for the year ended December 31, 2014 consists of the consolidated activity of Transocean Partners during and following the formation on August 5, 2014 and the combined activity of the Predecessor through August 4, 2014. Our consolidated statement of equity for the year ended December 31, 2013 consists entirely of the combined activity of the Predecessor. § Our consolidated statement of cash flows for the year ended December 31, 2015 consists of the consolidated cash flows of Transocean Partners. Our consolidated statement of cash flows for the year ended December 31, 2014 consists of the consolidated cash flows of Transocean Partners for the period from August 5, 2014 through December 31, 2014 and the combined cash flows of the Predecessor for the beginning of the respective period through August 4, 2014. Our consolidated statement of cash flows for the year ended December 31, 2013 consists entirely of the combined cash flows of the Predecessor. Accounting estimates —To prepare financial statements in accordance with accounting principles generally accepted in the U.S., we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates and assumptions, including those related to our allocated costs and related party transactions, materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes and equity ‑based compensation. We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates. Fair value measurements —We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability. Our valuation techniques require inputs that we categorize using a three ‑level hierarchy, from highest to lowest level of observable inputs, as follows: (1) significant observable inputs, including unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) significant other observable inputs, including direct or indirect market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) significant unobservable inputs, including those that require considerable judgment for which there is little or no market data (“Level 3”). When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable. Consolidation —We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes. We eliminate intercompany transactions and accounts in consolidation. We separately present within equity on our 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 consolidated statements of operations. Operating revenues and expenses —We recognize operating revenues as they are realized and earned and can be reasonably measured, based on contractual dayrates, and when collectability is reasonably assured. In connection with drilling contracts, we may receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to rigs. We defer the revenues earned and incremental costs incurred that are directly related to contract preparation and mobilization and recognize such revenues and costs over the primary contract term of the drilling project using the straight ‑line method. We amortize, in operating and maintenance costs and expenses, the fees related to contract preparation and mobilization on a straight ‑line basis over the estimated firm period of drilling, which is consistent with the general pace of activity, level of services being provided and dayrates being earned over the life of the contract. For contractual daily rate contracts, we recognize the losses for loss contracts as such losses are incurred. We recognize the costs of relocating drilling units without contracts as such costs are incurred. Upon completion of drilling contracts, we recognize in earnings any demobilization fees received and expenses incurred. We defer capital upgrade revenues received and recognize such revenues over the primary contract term of the drilling project. We depreciate the actual costs incurred for the capital upgrade on a straight ‑line basis over the estimated useful life of the asset. We defer the periodic survey and drydock costs incurred in connection with obtaining regulatory certification to operate our rigs and well control systems on an ongoing basis, and we recognize such costs over the period until expiration of certification using the straight ‑line method. We defer costs associated with the license fee that we paid for the use of Transocean’s patented dual ‑activity and recognize such amortized costs using the straight ‑line method through the license and patent expiration in May 2016 (see Note 12—Related Party Transactions). Included in our contract drilling revenues, we recognize amortization associated with our drilling contract intangible liability attributed to the drilling contract for Development Driller III . We amortize drilling contract intangible revenues based on the cash flows projected over the contract period and include such revenues in contract drilling revenues on our consolidated statements of operations. See Note 5—Goodwill and Intangible Liability. Our other revenues represent those derived from customer reimbursable revenues. We recognize customer reimbursable revenues as we bill our customers for reimbursement of costs associated with certain equipment, materials and supplies, subcontracted services, employee bonuses and other expenditures, resulting in little or no net effect on operating income since such recognition is concurrent with the recognition of the respective reimbursable costs in operating and maintenance expense. 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 service 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 service 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 years ended December 31, 2015 and 2014, costs and expenses allocated to us by Transocean were $146 million and $62 million, respectively (see Note 12—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 years ended December 31, 2014 and 2013, the Predecessor recognized such allocated operating and maintenance costs of $14 million and $28 million, respectively, including $11 million and $21 million, respectively, for personnel costs. In the years ended December 31, 2014 and 2013, we recognized such allocated general and administrative costs of $6 million and $10 million, respectively, including $4 million and $6 million, respectively, for personnel costs. Equity-based compensation —For service awards, we recognize compensation expense on a straight ‑line basis over the service period through the date the employee is no longer required to provide service to earn the award. For performance awards, we recognize compensation expense on a straight ‑line basis fo r each separately vesting portion of the award as if the award was in substance, multiple awards . We have awarded to our employees and non ‑employee directors phantom units, and such phantom units are participating securities. A phantom unit is a notional unit that has no voting rights and entitles the grantee to receive a common unit upon the vesting. To measure fair values of granted or modified phantom units, we use the market price of our units on the grant date or modification date. To measure fair values of performance awards, 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 year ended December 31, 2015, equity ‑based compensation expense was less than $1 million, which had no tax impact. In the years ended December 31, 2014 and 2013 , we had no equity ‑based awards outstanding. See Note 11—Equity ‑Based Compensation. Income taxes —We provide for income taxes based upon the tax laws and rates in effect in the countries in which operations are conducted and income is earned. We recognize deferred tax assets and liabilities for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the applicable jurisdictional tax rates in effect at year end. We record a valuation allowance for deferred tax assets when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We also record a valuation allowance for deferred tax assets resulting from net operating losses incurred during the year in certain jurisdictions and for other deferred tax assets where, in our opinion, it is more likely than not that the financial statement benefit of these losses will not be realized. Additionally, we record a valuation allowance for foreign tax credit carryforwards , if applicable, to reflect the possible expiration of these benefits prior to their utilization. We maintain liabilities for estimated tax exposures in our jurisdictions of operation, and we recognize the provisions and benefits resulting from changes to those liabilities in our income tax expense or benefit along with related interest and penalties. Tax exposure items may include potential challenges to qualification for treaty benefits, intercompany pricing, disposition transactions, and withholding tax rates and their applicability. These tax exposures are resolved primarily through the settlement of audits within these tax jurisdictions or by judicial means, but can also be affected by changes in applicable tax law or other factors, which could cause us to revise past estimates. The U.S. Internal Revenue Service (the “IRS”) has previously challenged and is currently challenging Transocean’s transfer pricing relating to certain bareboat charters. If the IRS successfully challenged our transfer pricing policies, it could result in a material increase in our U.S. federal income tax expense. See Note 5—Income Taxes. Earnings per unit —We apply the two ‑class method of calculating earnings per unit for our participating securities, including our common units, subordinated units and our incentive distribution rights. Under our limited liability company agreement, we established a cash distribution policy that requires the distribution of our available cash, which is determined by our board of directors (see Note 9—Cash Distributions). To calculate the earnings per unit for our common and subordinated unitholders, we allocate our net income or loss attributable to controlling interest for the quarterly or annual period in proportion to the respective ownership interest or, if the application of our cash distribution policy results in disproportionate distribution, in accordance with such policy. We present earnings per unit regardless of whether such earnings would or could be distributed under the terms of our limited liability company agreement. Accordingly, the reported earnings per unit is not indicative of potential cash distributions that may be made based on historical or future earnings. See Note 6—Earnings Per Unit. Cash and cash equivalents —We consider cash equivalents to include highly liquid debt instruments with original maturities of three months or less, such as time deposits with commercial banks that have high credit ratings, U.S. Treasury and government securities, Eurodollar time deposits, certificates of deposit and commercial paper. We may also invest excess funds in no ‑load, open ‑ended, management investment trusts. Such management trusts invest exclusively in high ‑quality money market instruments. Accounts receivable —We earn our revenues by providing our drilling services to international oil companies. We evaluate the credit quality of our customers on an ongoing basis, and we do not generally require collateral or other security to support customer receivables. We establish an allowance for doubtful accounts on a case ‑by ‑case basis, considering changes in the financial position of a customer, when we believe the required payment of specific amounts owed to us is unlikely to occur. At December 31, 2015 and 2014, we had no allowance for doubtful accounts. 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 December 31, 2015 and 2014, the aggre gate face value of such accounts receivable was $15 million and $24 million, respectively. At December 31, 2015, the aggregate carr ying amount of such accounts receivable was $15 million, recorded in accounts receivable. At December 31, 2014, the aggregate carrying amount of such accounts receivable was $22 million, including $12 million and $10 million, respectively, recorded in accounts receivable and other assets, respectively. At December 31, 2015 and 2014, our long ‑term accounts receivable had a weighted average effective interest rate of 11 percent. Materials and supplies —We record materials and supplies at their average cost less an allowance for obsolescence. We estimate the allowance for obsolescence based on historical experience and expectations for future use of the materials and supplies. At December 31, 2015 and 2014, the allowance for obsolescence was $6 million and $3 million, respectively. 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 December 31, 2015, the aggregate carrying amount of our property and equipment represented approximately 85 percent of our total assets. We capitalize expenditures for newbuilds, renewals, replacements and improvements, including capitalized interest, if applicable, and we recognize the expense for maintenance and repair costs as incurred. Upon sale or other disposition of an asset, we recognize a net gain or loss on disposal of the asset, which is measured as the difference between the net carrying amount of the asset and the net proceeds received. We compute depreciation using the straight ‑line method after allowing for salvage values. As of December 31, 2014, we reduced the salvage values of our drilling units due to existing market conditions. For the year ended December 31, 2015, this change in estimate resulted in an increase of approximately $1 million to depreciation expense. The estimated original useful life of each of our drilling units is 35 years. We reevaluate the remaining useful lives and salvage values of our rigs when certain events occur that directly impact the useful lives and salvage values of the rigs, including changes in operating condition, functional capability and market and economic factors. When evaluating the remaining useful lives of rigs, we also consider major capital upgrades required to perform certain contracts and the long ‑term impact of those upgrades on future marketability. Long ‑lived asset impairment —We review the aggregate carrying amount of our long ‑lived assets, principally property and equipment, for potential impairment when events occur or circumstances change that indicate that the aggregate carrying amount of the drilling units and related equipment in our asset group may not be recoverable. We determine recoverability by evaluating the aggregate estimated undiscounted future net cash flows based on projected dayrates and utilization of our drilling units. When an impairment of our assets is indicated, we measure the impairment as the amount by which the aggregate carrying amount of the drilling units and related equipment in our asset group exceeds the aggregate estimated fair value. We measure the fair value of our drilling units and related equipment by applying a variety of valuation methods, incorporating a combination of income and market approaches, using projected discounted cash flows and estimates of the exchange price that would be received for the assets in the principal or most advantageous market for the assets in an orderly transaction between market participants as of the measurement date. Goodwill impairment —Prior to the full impairment of our goodwill, we conducted impairment testing annually as of October 1 and more frequently, on an interim basis, when an event occured or circumstances changed that indicated that the fair value of our reporting unit may have declined below its carrying value. We tested goodwill at the reporting unit level, which is defined as an operating segment or one level below an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. We determined that we had a single reporting unit for this purpose. We estimate the fair value of our reporting unit using projected discounted cash flows, publicly traded company multiples and acquisition multiples. To develop the projected cash flows associated with our reporting unit, which are based on estimated future dayrates and rig utilization, we consider key factors that include assumptions regarding future commodity prices, credit market conditions and the effect these factors may have on our contract drilling operations and the capital expenditure budgets of our customers. We discount the projected cash flows using a long ‑term, risk ‑adjusted weighted ‑average cost of capital, which is based on our estimate of the investment returns that market participants would require for each of our reporting units. We derive publicly traded company multiples for companies with operations similar to our reporting units using observable information related to shares traded on stock exchanges and, when available, observable information related to recent acquisitions. If the reporting unit’s carrying amount exceeds its fair value, we consider goodwill impaired and perform a second step to measure the amount of the impairment loss, if any. In the year ended December 31, 2015, as a result of interim goodwill tests, we recognized an aggregate loss of $356 million, which had no tax effect, associated with the full impairment of the carrying amount of our goodwill, of which $ 182 million ($ 2.62 per diluted unit) was attributable to controlling interest and $174 million was attributable to noncontrolling interest. In the years ended December 31, 2014 and 2013, as a result of our annual impairment testing, we concluded that our goodwill was not impaired. See Note 4—Goodwill and Intangible Liability. Contingencies —We perform assessments of our contingencies on an ongoing basis to evaluate the appropriateness of our liabilities and disclosures for such contingencies. We establish liabilities for estimated loss contingencies when we believe a loss is probable and the amount of the probable loss can be reasonably estimated. We recognize corresponding assets for those loss contingencies that we believe are probable of being recovered through insurance. Once established, we adjust the carrying amount of a contingent liability upon the occurrence of a recognizable event when facts and circumstances change, altering our previous assumptions with respect to the likelihood or amount of loss. We recognize expense for legal costs as they are incurred, and we recognize a corresponding asset for such legal costs only if we expect such legal costs to be recovered through insurance. Net investment —Net investment on our consolidated balance sheets represents Transocean’s historical investment in the Predecessor, the Predecessor’s accumulated earnings and the net effect of cash transactions and allocations between Transocean and the Predecessor. Reclassifications —We have made certain reclassifications, such as those related to our adoption of updates to accounting standards for income taxes, which did not have an effect on net income, to prior period amounts to conform with the current year’s presentation. These reclassifications did not have a material effect on our 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 18—Subsequent Events. |
New Accounting Pronouncements
New Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2015 | |
New Accounting Pronouncements | |
New Accounting Pronouncements | Note 3—New Accounting Pronouncements Recently adopted accounting standards Income taxes —Effective December 31, 2015, we elected to early adopt, on a retrospective basis, the accounting standards update that requires deferred tax liabilities and assets to be classified as noncurrent in a classified statement of financial position. The update is effective for interim and annual periods beginning after December 15, 2016 and early adoption is permitted. We elected to apply the accounting standards update to the prior year on a retrospective basis for comparability purposes. At December 31, 2014 , as a result of our adoption, we reclassified $8 million of deferred income taxes to noncurrent assets from current assets on our consolidated balance sheet. Recently issued accounting standards Presentation of financial statements —Effective with our annual report for the year 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 consolidated financial statements. Revenue from contracts with customers —Effective January 1, 2018, we will adopt the accounting standards update that requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The update was originally effective for interim and annual periods beginning on or after December 15, 2016, but has since been approved for a one ‑year deferral, effective for interim and annual periods beginning on or after December 15, 2017, and permits adoption as early as the original effective date. We are evaluating the requirements to determine the effect such requirements may have on our revenue recognition policies. |
Goodwill and Intangible Liabili
Goodwill and Intangible Liability | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Liability | |
Goodwill and Intangible Liability | Note 4—Goodwill and Intangible Liability 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 publicly traded common units and oil and natural gas prices as well as projected reductions in dayrates and utilization. As a result, we performed an interim goodwill impairment test as of March 31, 2015 and determined that the goodwill associated with our reporting unit was impaired. During the three months ended September 30, 2015, we noted impairment indicators that the fair value of our goodwill could have, again, fallen below its carrying amount. Such impairment indicators included further reduction in the market value of our publicly traded common units and oil and natural gas prices as well as projected reductions in dayrates and utilization. As a result, we performed an interim goodwill impairment test as of September 30, 2015 and determined that the remaining goodwill associated with our reporting unit was fully impaired. In the year ended December 31, 2015, we recognized an aggregate loss of $356 million associated with the full impairment of the carrying amount of our goodwill, which had no tax effect, and of which $182 million was attributable to controlling interest ( $2.6 2 per diluted unit) and $174 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 reporting unit, such as future oil and natural gas prices, projected demand for our services, rig availability and dayrates. As a result of our goodwill impairment tests in the years ended December 31, 2014 and 2013, we concluded that our goodwill was not impaired. Origination —As of the closing of the formation transactions on August 5, 2014, Transocean allocated to us $356 million of goodwill based on the estimated fair value of our reporting unit relative to the estimated fair value of Transocean’s reporting unit immediately prior to the allocation. Transocean estimated the fair value of our reporting unit using a variety of valuation methods, including the income and market approaches, by applying significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of our reporting unit, such as future oil and gas prices, projected demand for our services, rig availability and dayrates. At December 31, 2014, the carrying amount of our goodwill was $356 million. Prior to August 5, 2014, Transocean allocated to the Predecessor a portion of the carrying amount of its goodwill based on the estimated fair value of the Predecessor’s net property and equipment relative to the estimated fair value of Transocean’s reporting unit, including the Predecessor’s net property and equipment. The goodwill allocated to the Predecessor as of January 1, 2012, the measurement date for this purpose, was $213 million. Transocean estimated the fair value of the Predecessor’s net property and equipment using a variety of valuation methods, including the income and market approaches, by applying significant unobservable inputs, representative of Level 3 fair value measurement, including assumptions related to the future performance of our reporting unit, such as future oil and gas prices, projected demand for our services, rig availability and dayrates. Intangible liability Transocean acquired Development Driller III in connection with a business combination in November 2007. At the time of the business combination, the drilling contract under which the rig is currently operating included fixed dayrates for contract drilling services that were below the then ‑existing market dayrates available for similar contracts as of the date of the business combination. Accordingly, Transocean recognized a contract intangible liability, representing the estimated fair value of the Development Driller III drilling contract, which is expected to be completed in November 2016. The Predecessor transferred to us the historical carrying amount of the intangible liability. The gross carrying amounts of our drilling contract intangible liability and accumulated amortization were as follows (in millions): Year ended December 31, 2015 Year ended December 31, 2014 Gross Net Gross Net carrying Accumulated carrying carrying Accumulated carrying amount amortization amount amount amortization amount Drilling contract intangible liability Balance, beginning of period $ $ $ $ $ $ Amortization — — Balance, end of period $ $ $ $ $ $ We expect the remaining net carrying amount of our drilling contract intangible liability to be fully amortized in the year ending December 31, 2016. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 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. The Republic of the Marshall Islands —Because we and our controlled affiliates do not conduct business or operations in The Republic of the Marshall Islands, neither we nor our controlled affiliates will be subject to income, capital gains, profits or other taxation under current Marshall Islands law. As a result, any distributions from our controlled affiliates are not subject to Marshall Islands taxation. United Kingdom —We are a resident of the U.K. for taxation purposes. We expect that any distributions from our controlled affiliates generally will be exempt from taxation in the U.K. under the applicable exemption for distributions from subsidiaries. United States —We have elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to U.S. federal income tax to the extent we earn income from U.S. sources or income that is treated as effectively connected with the conduct of a trade or business in the U.S. We have controlled affiliates that conduct drilling operations in the U.S. Gulf of Mexico that are subject to taxation by the U.S. on their net income. Cayman Islands —The Cayman Islands will not impose any income, capital gains, profits, withholding or other taxation on us, our controlled affiliates or on any distributions we or they may make. Effective upon completion of the formation transactions, our provision for income taxes are computed based on the laws and rates applicable in the jurisdictions in which we operate and earn income. 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. 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. Our provision for income taxes was prepared on a separate return basis with consideration to the tax laws and rates applicable in the jurisdictions in which we operated and earned income. In the years ended December 31, 2015, 2014 and 2013, our annual effective tax rate was 6.2 percent, 8.5 percent and 10.7 percent, respectively. The components of our provision for income taxes were as follows (in millions): Years ended December 31, 2015 2014 2013 Current tax expense $ $ $ Deferred tax expense Income tax expense $ $ $ The following is a reconciliation of the differences between the income tax expense computed at (a) the Marshall Islands holding company federal statutory rate of zero percent in the years ended December 31, 2015 and 2014 and (b) the Swiss holding company federal statutory rate of 7.83 percent for the Predecessor in the year ended December 31, 2013 and the reported provision for income taxes (in millions): Years ended December 31, 2015 2014 2013 Income tax expense at the respective federal statutory rate $ — $ — $ Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate Changes in unrecognized tax benefits, net Changes in valuation allowance — Other, net — — Income tax expense $ $ $ Deferred taxes — The significant components of our deferred tax assets were as follows (in millions): December 31, 2015 2014 Deferred tax assets Net operating loss carryforwards $ $ Accrued payroll costs not currently deductible — Deferred revenues and drilling contract intangible Valuation allowance Other Total deferred tax assets Deferred tax liabilities Total deferred tax liabilities — — Net deferred tax assets $ $ The Predecessor’s income tax provision is based on the applicable rates in the jurisdictions in which the Predecessor’s business operated and earned income. We believe our consolidated statements of financial position, results of operation and cash flows are materially correct as presented. At December 31, 2015, the tax effect of our U.K. net operating losses, which do not expire, was $4 million. The valuation allowance for our deferred tax assets was as follows (in millions): December 31, 2015 2014 Valuation allowance for deferred tax assets $ $ Unrecognized tax benefits — The changes to our liabilities related to unrecognized tax benefits, excluding interest and penalties that we recognize as a component of income tax expense, were as follows (in millions): Years ended December 31, 2015 2014 2013 Balance, beginning of period $ $ $ Additions for current year tax positions Reductions for prior year tax positions — — Settlements — — — Balance, end of period $ $ $ A portion of the reductions for prior year tax positions reported in the year ended December 31, 2014 resulted from unrecognized tax benefits that originated in legal entities that were not transferred to us in the formation transactions. 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): December 31, 2015 2014 Unrecognized tax benefits, excluding interest and penalties $ $ Interest and penalties — — Unrecognized tax benefits, including interest and penalties $ $ In the years ended December 31, 2015, 2014 and 2013 , we recognized interest and penalties of less than $1 million, recognized as a component of income tax expense, associated with the unrecognized tax benefits. As of December 31, 2015, if recognized, $3 million of the unrecognized tax benefits would favorably impact the effective tax rate. In the year ending December 31, 2016, it is reasonably possible that the existing liabilities for unrecognized tax benefits could increase or decrease, primarily due to the progression of open audits. 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 were no longer subject to examinations of tax matters for years prior to 2010. |
Earnings Per Unit
Earnings Per Unit | 12 Months Ended |
Dec. 31, 2015 | |
Earnings Per Unit | |
Earnings Per Unit | Note 6—Earnings per unit The numerator and denominator used for the computation of basic and diluted per unit earnings, were as follows (in millions, except per unit data): Years ended December 31, 2015 2014 2013 Basic Diluted Numerator for earnings (loss) per unit Net income (loss) attributable to controlling interest $ $ $ $ — Undistributed earnings allocable to participating securities — — — — Net income (loss) available to unitholders $ $ $ $ — Net income (loss) available to common unitholders $ $ $ $ — Net income (loss) available to subordinated unitholders $ $ $ $ — Denominator for earnings (loss) per unit – common units Weighted-average common units outstanding — Effect of equity-based awards — — — — Weighted-average common units for per unit calculation — Denominator for earnings (loss) per unit – subordinated units Weighted-average subordinated units outstanding — Effect of equity-based awards — — — — Weighted-average subordinated units for per unit calculation — Earnings (loss) per unit Earnings (loss) per common unit $ $ $ $ — Earnings (loss) per subordinated unit $ $ $ $ — Cash distributions declared and paid per unit Common units $ $ $ $ — Subordinated units $ $ $ $ — Earnings per unit calculations relate only to the periods subsequent to our initial public offering since the Predecessor had no units outstanding. In the year ended December 31, 2015, we excluded from the calculation 16,474 equity-based awards since the effect would have been anti-dilutive. In the year ended December 31, 2014, our basic and dilutive earnings per unit were the same because we had no potentially dilutive units outstanding. See Note 9—Cash Distributions and Note 18—Subsequent Events. |
Credit Agreements
Credit Agreements | 12 Months Ended |
Dec. 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 of our 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 December 31, 2015, based on our leverage ratio on that date, the revolving credit facility marg in was 1.625 percent. At December 31, 2015, we had no borrowings outstanding and $300 million available borrowing capacity under the Five ‑Year Revolving Credit Facility. Working capital note payable and customer receivables guaranty agreements —On July 29, 2014, we entered into agreements with a Transocean affiliate to establish a working capital note payable in the principal amount of $43 million that was due and payable at maturity on July 28, 2015. At December 31, 2014, we had borrowings of $43 million outstanding under the working capital note payable. On July 17, 2015, we made a cash payment of $43 million to repay the borrowings outstanding under the working capital note payable. We used the proceeds from the 364 ‑day working capital note as partial consideration for contributed working capital associated with our acquisition of interests in the RigCos. In connection with the acquisition, Transocean agreed to guarantee the payment of any receivables held by the RigCos at the closing of the acquisition. In addition, the assignment and bill of sale agreements for the acquisition contain a true ‑up mechanism whereby we agreed to pay Transocean for the amount by which our pro rata share of actual net working capital, as determined within 60 days after the acquisition, exceeded our pro rata share of estimated net working capital at the time of the acquisition, and Transocean agreed to pay us if such actual net working capital was less than such estimated net working capital. Subsequent to our formation, we determined that the working capital exceeded the original estimate by $4 million, and in December 2014, we made a cash payment to Transocean in satisfaction of our obligation. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2015 | |
Commitments and Contingencies | |
Commitments and Contingencies | Note 8—Commitments and Contingencies Purchase obligations —At December 31, 2015, the aggregate future payments required under our purchase obligations for equipment, which are due in the year e nding December 31, 2016, were $12 million. 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 December 31, 2015, our drilling units had the insured value of approximately $ 1.95 billion under this program. Additionally, we maintain various other commercial lines of insurance covering the business. 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. 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 of 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. 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. Guarantees, letters of credit and surety bonds —At Dece mber 31, 2015 and 2014, we had no guarantees, letters of credit or surety bonds issued or outstanding. |
Cash Distributions
Cash Distributions | 12 Months Ended |
Dec. 31, 2015 | |
Cash Distributions. | |
Cash Distributions | Note 9—Cash Distributions Cash distribution policy —Under our cash distribution policy, we intend to make minimum quarterly distributions on our common and subordinated units of $0.3625 per unit, equivalent to $1.45 per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including the payment of expenses to the Transocean Member and its affiliates. However, other than the requirement in our limited liability company agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our board of directors has considerable discretion to determine the amount of our available cash each quarter. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves, including estimated maintenance and replacement capital expenditures, (ii) cash on hand on the date of determination resulting from cash distributions received after the end of such quarter from equity interests in any person other than a subsidiary in respect of operations conducted by such person during the quarter and (iii) if our board of directors so determines, cash on hand on the date of determination resulting from working capital borrowings made after the end of the quarter. If we do not generate sufficient available cash from our operations, we may, but are under no obligation to, borrow funds to pay minimum quarterly distributions to our unitholders. For any quarter during the subordination period, which extends through the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending June 30, 2019, we will make distributions of our available cash from operating surplus among the unitholders and the holders of the incentive distribution rights in the following manner: § first , 100 percent to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; § second , 100 percent to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; § third , 100 percent to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and § thereafter , in the manner further described below. The percentage interests set forth below assume that there are no arrearages on common units. Marginal percentage interest in distributions (a) Holders of incentive Total quarterly distribution distribution target amount (a) Unitholders rights Minimum quarterly distribution $ 0.362500 % — First target distribution Above $ 0.362500 up to $ 0.416875 % — Second target distribution Above $ 0.416875 up to $ 0.453125 % % Third target distribution Above $ 0.453125 up to $ 0.543750 % % Thereafter Above $ 0.543750 % % (a) The marginal percentage interest in distributions represents the percentage interests of the unitholders and holders of incentive distribution rights in any available cash from operations surplus that we distribute up to and including the corresponding total quarterly distribution amount, until the available cash from operating surplus reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the holders of incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. At December 31, 2015, the Transocean Member held 21.3 million common units and 27.6 million subordinated units, which collectively represented a 70.9 percent limited liability company interest, and all of our incentive distribution rights. Cash distributions to unitholders —On February 9, May 4, July 30 and October 29, 2015, our board of directors approved distributions of $0.3625 per unit to our unitholders. On February 26, May 27, August 25 and November 23, 2015, we made an aggregate cash distribution of $100 million to our unitholders of record as of February 20, May 15, August 12 and November 9, 2015, including an aggregate cash distribution of $7 1 million to the Transocean Member. On November 4, 2014, our board of directors approved a distribution of $0.2246 per unit to our unitholders based on the minimum quarterly distribution for the proportional period from the date of the closing of the initial public offering through September 30, 2014. On November 24, 2014, we made an aggregate cash payment of $15 million to our unitholders of record as of November 17, 2014, including an aggregate cash payment of $11 million to the Transocean Member. See Note 18 —Subsequent Events. Cash distributions to holder of noncontrolling interests —In the year ended December 31, 2015, we paid an aggregate cash distribution of $ 101 million to Transocean as holder of noncontrolling interests. In the year ended December 31, 2014, we did not make any such distributio ns to Transocean. See Note 18 —Subsequent Events. |
Unit Repurchase Program
Unit Repurchase Program | 12 Months Ended |
Dec. 31, 2015 | |
Unit Repurchase Program | |
Unit Repurchase Program | Note 10—Unit Repurchase Program Unit repurchase program —On November 4, 2015, we announced that our board of directors approved a unit repurchase program authorizing us to repurchase up to $40 million of our publicly held common units. Subject to market conditions, we may repurchase units from time to time in the open market or in privately negotiated transactions. We may suspend or discontinue the program at any time. The common units repurchased under this program will be cancelled. In the year ended December 31, 2015, under the unit repurchase program, we re purchased 91,500 of our publicly held common units at an average market price of $9.20 per unit for an aggregate purchase price of $1 million, and such common units were cancelled. See Note 18—Subsequent Events. |
Equity-Based Compensation Plan
Equity-Based Compensation Plan | 12 Months Ended |
Dec. 31, 2015 | |
Equity-Based Compensation Plan | |
Equity-Based Compensation Plan | Note 11—Equity ‑Based Compensation Plan 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 executive officers, key employees and non ‑employee directors. Awards may be granted as service awards that are earned over a defined service period or as performance awards that are earned based on the achievement of certain performance criteria or market factors. The compensation committee of our board of directors determines the terms and conditions of the awards granted under the Incentive Compensation Plan. As of December 31, 2015, we had 3.4 million units authorized and available to be granted under the Incentive Compensation Plan. The service awards to our employees vest in three equal annual installments beginning approximately one year following the grant date, and the service awards to our non ‑employee directors fully vest approximately one year following the grant date. The performance awards may be earned depending on the achievement of certain performance targets as determined upon completion of the specified period at the determination date. Thereafter, the performance awards vest in three equal annual installments beginning approximately one year following the determination date. In the year ended December 31, 2015, we granted to our executive officers, key employees and non ‑employee directors 60,105 service awards in the form of phantom units with a weighted average grant ‑date fair value of $ 14.78 per unit and an aggregate grant ‑date fair value of less than $ 1 million. In the year ended December 31, 2015, we granted to our chief executive officer 19,459 performance awards in the form of phantom units with a weighted average fair value of $ 8.83 per unit and an aggregate fair value of less than $ 1 million, measured as of December 31, 2015. The actual number of performance awards expected to vest will be determined in February 2016. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2015 | |
Related Party Transactions | |
Related Party Transactions | Note 12—Related Party Transactions Formation agreements Contribution agreement —On July 29, 2014, we entered into a contribution agreement (the “Contribution Agreement”) with Transocean that gave effect to certain of the formation transactions, including Transocean’s transfer to us of a 51 percent ownership interest in each of the RigCos. In connection with the formation transactions under the Contribution Agreement, Transocean retained the obligation for the payment of the quarterly royalty fees under the dual ‑activity license agreement through the patent expiration (see “—Other agreements—Dual ‑activity license agreements”). Transocean retains a significant interest in us through its ownership of common and subordinated units, representing an aggregate 70.9 percent limited liability company interest in us as of December 31, 2015, and all of our incentive distribution rights. Transocean also holds the non ‑economic interest in us that includes the right to appoint three of the seven members of our board of directors. Under our limited liability company agreement, common unitholders that own 50 percent or more of our common units have the ability to request that cumulative voting be in effect for the election of elected directors. Cumulative voting is an irrevocable election that allows for the unitholder to allocate its votes cumulatively, rather than proportionally. Therefore, for so long as Transocean owns 50 percent or more of our common units, it will have the ability to request that cumulative voting be in effect for the election of elected directors, which would enable Transocean to elect one or more of the elected directors even after it owns less than 50 percent of our common units. As a result, if cumulative voting was in effect, Transocean would have the ability to fill the majority of positions on our board, by appointment or election, as long as it retains at least 20 percent of our common units. The directors appointed by Transocean may designate a member of the board of directors to be the chairman of the board of directors. Specific rights of the Transocean Member are designated in our limited liability company agreement. Governing documents —Upon completion of the formation transactions, we own a 51 percent ownership interest in each of the RigCos and control their operations and activities. Transocean holds the remaining 49 percent noncontrolling interest in each of the RigCos. In connection with the formation transactions, we and certain Transocean affiliates entered into governing documents for each of the RigCos that govern the ownership and management of each of the RigCos. Each of the RigCos is managed by its board of directors. Pursuant to such governing documents, we are able to control the election of these boards of directors as the majority interest owner. Subject to certain prerequisites under applicable law and the approval of the board of directors of each of the RigCos, each RigCo intends to transfer its available cash to its equityholders each quarter. Approval of the conflicts committee of our board of directors is required to amend the RigCos’ governing documents. Master services and support agreements Secondment agreements —On August 5, 2014, we entered into secondment agreements with certain Transocean affiliates to provide the services of certain executives, including our chief executive officer, rig crews and other personnel. On June 30, 2015, we amended one of the secondment agreements to add additional parties to the agreement and to add personnel covered by the agreement. All persons provided to us pursuant to the secondment agreements remain on the payroll and benefit plans of Transocean but are under our day ‑to ‑day control and management. We reimburse Transocean for the pro rata gross payroll costs of each seconded employee in proportion to the time allocated to us by the seconded employee, including base pay, any incentive compensation and any benefits costs. We also reimburse Transocean for any applicable unemployment taxes, social security taxes, workers compensation coverage and severance costs, and any foreign equivalents of such taxes, in the amount allocable to the secondment. The secondment agreements may be terminated by Transocean or us upon 90 days written notice. In the years ended December 31, 2015 and 2014, we recognized costs of $ 91 million and $ 38 million, respectively, recorded in operating and maintenance costs and expenses, and $ 4 million and $2 million, respectively, recorded in general and administrative costs and expenses, for personnel costs under the secondment agreements. Support agreement —On August 5, 2014, we entered into a support agreement with certain Transocean affiliates to provide the services of certain administrative professionals, including our chief financial officer. The persons providing such services to us pursuant to the support agreement continue to participate in Transocean’s compensation and benefits plans 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 years ended December 31, 2015 and 2014, 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 under certain circumstances prior to the end of its term by either Transocean or us within 90 days written notice. In the years ended December 31, 2015 and 2014, we recognized costs of $ 116 million and $46 million, respectively, recorded in operating and maintenance costs and expenses, and $ 19 million and $11 million, respectively, recorded in general and administrative costs and expenses, for services under the master services agreements. In the years ended December 31, 2015 and 2014, we recognized insurance costs of $ 11 million and $5 million, respectively, recorded in operating and maintenance costs and expenses. In the years ended December 31, 2015 and 2014, we acquired $ 26 million and $ 13 million, respectively, of materials and supplies purchased through Transocean’s procurement services. Former master services agreement —Under the former master services agreement, Transocean Offshore Deepwater Drilling Inc., a U.S. company and a wholly owned subsidiary of Transocean (“TODDI”), and its affiliates charged the Predecessor for crew personnel provided to the Predecessor to operate its drilling rigs. In the years ended December 31, 2014 and 2013, the Predecessor recognized costs of $60 million and $100 million, respectively, recorded in operating and maintenance costs and expenses, for such crew personnel costs. TODDI charged the Predecessor for performing and assisting with certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services. In the years ended December 31, 2014 and 2013, the Predecessor recognized costs of $25 million and $35 million, respectively, recorded in operating and maintenance costs and expenses, and $8 million and $10 million, respectively, recorded in general and administrative costs and expenses, for such services and assistance. TODDI charged the Predecessor for administering insurance coverage and processing claims through Transocean’s commercial market and captive insurance policies (see Note 8—Commitments and Contingencies). In the years ended December 31, 2014 and 2013, the Predecessor recognized insurance costs of $7 million and $13 million, respectively, recorded in operating and maintenance costs and expenses. Additionally, TODDI charged the Predecessor for materials and supplies for the Predecessor’s drilling operations that were acquired through Transocean’s procurement services. In the years ended December 31, 2014 and 2013, the Predecessor acquired $20 million and $38 million, respectively, settled through its net investment, for such materials and supplies. 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 agreed 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 (each, a “Five ‑Year Drilling Rig”), 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 such contribution or sale 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 our initial public 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 our initial public 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 our initial public offering through the completion of the rig’s 2014 special periodic survey, which occurred during the three months ended December 31, 2014. In the year ended December 31, 2014, we submitted indemnification claims under the Omnibus Agreement for an aggregate amount of $19 million associated with lost revenues. At December 31, 2014, the indemnification claim receivable was $10 million, which we collected in January 2015. Dual ‑activity license agreements —All three of our drilling units are equipped with Transocean’s patented dual ‑activity technology. Dual ‑activity technology employs structures, equipment and techniques using two drilling stations within a dual derrick to perform drilling tasks. Dual ‑activity technology allows our rigs to perform simultaneous drilling tasks in a parallel rather than a 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. In the years ended December 31, 2015, 2014 and 2013, we and the Predecessor recognized amortization of the license costs of $ 3 million, $2 million and $3 million, respectively, recorded in operating and maintenance costs and expenses. At December 31, 2015 and 2014, the carrying amount of the deferred license cost was $ 1 million and $4 million, respectively, recorded in other assets. 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 agreed to retain and pay the obligation for the quarterly patent royalty fees. In the years ended December 31, 2015 and 2014, we recognized patent royalty expense of $ 23 million and $7 million, respectively, recorded in operating and maintenance costs and expenses, representing the fees paid by Transocean on our behalf, with corresponding entries to members’ equity. In the years ended December 31, 2014 and 2013, the Predecessor recognized patent royalty expense of $23 million and $19 million, respectively, recorded in operating and maintenance costs and expenses. Credit agreements —On July 29, 2014, we entered into agreements with a Transocean affiliate to establish a working capital note payable in the principal amount of $43 million, which we repaid on July 17, 2015. 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 Informat
Supplemental Cash Flow Information | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information | |
Supplemental Cash Flow Information | Note 13—Supplemental Cash Flow Information Additional cash flow information was as follows (in millions): Years ended December 31, 2015 2014 2013 Certain cash operating activities Cash payments for interest $ $ — $ — Cash payments for income taxes — Non - cash investing and financing activities Capital additions, accrued at end of period (a) $ — $ $ Property and equipment transferred to the Predecessor from affiliates (b) — Property and equipment transferred from the Predecessor to affiliates (c) — — Contributions for parent payment of patent royalties (d) — Contribution for parent indemnification of lost revenues (e) — — (a) These amounts represent additions to property and equipment for which we had accrued a corresponding liability in accounts payable to affiliates at the end of the period. (b) In the years ended December 31, 2014 and 2013, Transocean transferred to the Predecessor certain equipment with an aggregate net carrying amount of $ 10 million and $1 million, respectively, primarily all of which was to Development Driller III , and the Predecessor recorded the non ‑cash investing activity with a corresponding increase to its net investment. (c) In the year ended December 31, 2014, the Predecessor transferred to Transocean’s other drilling units certain equipment with an aggregate net carrying amount of $23 million, primarily all of which was from Development Driller III , and the Predecessor recorded the non ‑cash investing activity with a corresponding reduction to its net investment. (d) In the years ended December 31, 2015 and 2014, in connection with Transocean’s payment of royalty fees under our dual ‑activity license agreements with a Transocean affiliate, we recognized non ‑cash operating costs of $ 23 million and $7 million, respectively, with a corresponding increase to members’ equity. (e) In the year ended December 31, 2014, we submitted to Transocean indemnification claims associated with lost revenues in the aggregate amount of $19 million, and we recognized a receivable from affiliate with a corresponding increase to members’ equity. At December 31, 2014, the unpaid balance was $ 10 million, recorded in accounts receivable from affiliates . |
Financial Instruments
Financial Instruments | 12 Months Ended |
Dec. 31, 2015 | |
Financial Instruments | |
Financial Instruments | Note 14—Financial Instruments The carrying amounts and fair values of our financial instruments were as follows (in millions): December 31, 2015 December 31, 2014 Carrying Fair Carrying Fair amount value amount value Cash and cash equivalents $ $ $ $ Working capital note payable to affiliate — — 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 December 31, 2015 and 2014, the aggregate carrying amount of our cash equivalents was $ 153 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 the 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. |
Risk Concentration
Risk Concentration | 12 Months Ended |
Dec. 31, 2015 | |
Risk Concentration | |
Risk Concentration | Note 15—Risk Concentration Credit risk —Financial instruments that potentially subject us to concentrations of credit risk are primarily trade receivables. We earn all of our revenues by providing our drilling services to two international oil companies and conduct all of our operations in the U.S. Gulf of Mexico. We are not aware of any significant credit risks related to our customer base and do not generally require collateral or other security to support customer receivables. |
Operating Segments, Geographic
Operating Segments, Geographic Analysis and Major Customers | 12 Months Ended |
Dec. 31, 2015 | |
Operating Segments, Geographic Analysis and Major Customers | |
Operating Segments, Geographic Analysis and Major Customers | Note 16—Operating Segments, Geographic Analysis and Major Customers Operating segments —We operate in a single market for the provision of contract drilling services to our customers. The location of our rigs and the allocation of our resources to build or upgrade rigs are determined by the activities and needs of our customers. Geographic analysis —For the years ended December 31, 2015, 2014 and 2013, we earned 100 percent of our consolidated operating revenues in the U.S. Gulf of Mexico. At December 31, 2015 and 2014, 100 percent of our assets were in the U.S. Gulf of Mexico. Major customers —For the years ended December 31, 2015, 2014 and 2013, Chevron Corporation and BP plc, each together with its affiliates, accounted for approximately 67 percent and 33 percent, respectively, of our consolidated operating revenues. |
Quarterly Results (unaudited)
Quarterly Results (unaudited) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Results (unaudited) | |
Quarterly Results (unaudited) | Note 17—Quarterly Results (unaudited) Our consolidated statements of operations for the quarterly periods in the year ended December 31, 2015 consist entirely of our consolidated results. Our consolidated statements of operations for the quarterly periods in the year ended December 31, 2014 consist of the consolidated results of operations of Transocean Partners for the period from August 5, 2014 through December 31, 2014 and the combined results of operations of the Predecessor for the period from January 1, 2014 through August 4, 2014. See Note 2—Significant Accounting Policies ‑Presen tation. Three months ended March 31, June 30, September 30, December 31, (In millions, except per share data) 2015 Operating revenues $ $ $ $ Operating income (loss) (a) Net income (loss) (a) Net income (loss) attributable to controlling interest (a) Per unit earnings - basic and diluted Common units $ $ $ $ Subordinated units $ $ $ $ Weighted-average units outstanding Common units Subordinated units 2014 Operating revenues $ $ $ $ Operating income Net income Net income attributable to controlling interest (b) (b) Per unit earnings - basic and diluted Common units $ (b) $ (b) $ $ Subordinated units $ (b) $ (b) $ $ Weighted ‑ average units outstanding Common units (b) (b) Subordinated units (b) (b) (a) First quarter and third quarter included a loss of $67 million and $289 million, respectively, associated with the impairment of the remaining balance of our goodwill of which $34 million and $148 million, respectively, was attributable to controlling interest. See Note 4—Goodwill and Intangible Liability. (b) Amounts associated with the Predecessor period, and, therefore, not applicable. See Note 2—Significant Accounting Policies . |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2015 | |
Subsequent Events. | |
Subsequent Events | Note 18—Subsequent Events Cash distribution to unitholders —On February 9, 2016, 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 February 25, 2016 to unitholders of record as of February 22, 2016, including an aggregate cash payment of $18 million to the Transocean Member. Cash distributions to holder of noncontrolling interests —Subsequent to December 31, 2015, we paid an aggregate cash distribution of $54 million to Transocean as holder of noncontrolling interests. Unit repurchase program —Subsequent to Dec ember 31, 2015, under the unit repurchase program, we repurchased 215,467 of our publicly held common units at an average market price of $7.74 per share for an aggregate purchase price of $2 million, and such common units were cancelled. As of February 16 , 2016, Transocean held a 71.1 percent limited liability company interest in us. |
Significant Accounting Polici25
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2015 | |
Significant Accounting Policies | |
Presentation | Presentation —For periods prior to August 5, 2014, the combined financial information of the Predecessor was derived from Transocean’s accounting records. The 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 among the Predecessor Business within the Predecessor have been eliminated. For the periods following August 5, 2014, the consolidated financial statements reflect our consolidated results of operations, financial position and cash flows. We have presented 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 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. Transocean uses a centralized approach to treasury services to perform cash management for the operations of its affiliates. Under the Master Services Agreement, Transocean provides its treasury services to manage our cash and cash equivalents. The Predecessor had no bank accounts, and Transocean did not allocate its cash and cash equivalents to the Predecessor. The Predecessor transferred the cash generated and used by its operations to Transocean, and Transocean funded the Predecessor’s operating and investing activities as needed. Accordingly, the Predecessor’s transfers of cash to and from Transocean’s treasury were presented as net distributions to the Predecessor’s parent on our consolidated statements of equity and in our financing activities on our 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 consolidated financial statements on the following basis: § Our consolidated statement of operations for the year ended December 31, 2015 consists of the consolidated results of operations of Transocean Partners. Our consolidated statement of operations for the year ended December 31, 2014 consists of the consolidated results of operations of Transocean Partners for the period from August 5, 2014 through December 31, 2014 and the combined results of operations of the Predecessor for the beginning of the period through August 4, 2014. Our consolidated statement of operations for the year ended December 31, 2013 consists entirely of the combined results of operations of the Predecessor. § Our consolidated balance sheets at December 31, 2015 and 2014 consist of the consolidated balances of Transocean Partners. § Our consolidated statement of equity for the year ended December 31, 2015 consists of the consolidated activity of Transocean Partners. Our consolidated statement of equity for the year ended December 31, 2014 consists of the consolidated activity of Transocean Partners during and following the formation on August 5, 2014 and the combined activity of the Predecessor through August 4, 2014. Our consolidated statement of equity for the year ended December 31, 2013 consists entirely of the combined activity of the Predecessor. Our consolidated statement of cash flows for the year ended December 31, 2015 consists of the consolidated cash flows of Transocean Partners. Our consolidated statement of cash flows for the year ended December 31, 2014 consists of the consolidated cash flows of Transocean Partners for the period from August 5, 2014 through December 31, 2014 and the combined cash flows of the Predecessor for the beginning of the respective period through August 4, 2014. Our consolidated statement of cash flows for the year ended December 31, 2013 consists entirely 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 allocated costs and related party transactions, materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes and equity ‑based compensation. We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates. |
Fair value measurements | 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 separately present within equity on our 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 consolidated statements of operations. |
Operating revenues and expenses | Operating revenues and expenses —We recognize operating revenues as they are realized and earned and can be reasonably measured, based on contractual dayrates, and when collectability is reasonably assured. In connection with drilling contracts, we may receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to rigs. We defer the revenues earned and incremental costs incurred that are directly related to contract preparation and mobilization and recognize such revenues and costs over the primary contract term of the drilling project using the straight ‑line method. We amortize, in operating and maintenance costs and expenses, the fees related to contract preparation and mobilization on a straight ‑line basis over the estimated firm period of drilling, which is consistent with the general pace of activity, level of services being provided and dayrates being earned over the life of the contract. For contractual daily rate contracts, we recognize the losses for loss contracts as such losses are incurred. We recognize the costs of relocating drilling units without contracts as such costs are incurred. Upon completion of drilling contracts, we recognize in earnings any demobilization fees received and expenses incurred. We defer capital upgrade revenues received and recognize such revenues over the primary contract term of the drilling project. We depreciate the actual costs incurred for the capital upgrade on a straight ‑line basis over the estimated useful life of the asset. We defer the periodic survey and drydock costs incurred in connection with obtaining regulatory certification to operate our rigs and well control systems on an ongoing basis, and we recognize such costs over the period until expiration of certification using the straight ‑line method. We defer costs associated with the license fee that we paid for the use of Transocean’s patented dual ‑activity and recognize such amortized costs using the straight ‑line method through the license and patent expiration in May 2016 (see Note 12—Related Party Transactions). Included in our contract drilling revenues, we recognize amortization associated with our drilling contract intangible liability attributed to the drilling contract for Development Driller III . We amortize drilling contract intangible revenues based on the cash flows projected over the contract period and include such revenues in contract drilling revenues on our consolidated statements of operations. See Note 5—Goodwill and Intangible Liability. Our other revenues represent those derived from customer reimbursable revenues. We recognize customer reimbursable revenues as we bill our customers for reimbursement of costs associated with certain equipment, materials and supplies, subcontracted services, employee bonuses and other expenditures, resulting in little or no net effect on operating income since such recognition is concurrent with the recognition of the respective reimbursable costs in operating and maintenance expense. |
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 service 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 service 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 years ended December 31, 2015 and 2014, costs and expenses allocated to us by Transocean were $146 million and $62 million, respectively (see Note 12—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 years ended December 31, 2014 and 2013, the Predecessor recognized such allocated operating and maintenance costs of $14 million and $28 million, respectively, including $11 million and $21 million, respectively, for personnel costs. In the years ended December 31, 2014 and 2013, we recognized such allocated general and administrative costs of $6 million and $10 million, respectively, including $4 million and $6 million, respectively, for personnel costs. |
Equity-based compensation | Equity-based compensation —For service awards, we recognize compensation expense on a straight ‑line basis over the service period through the date the employee is no longer required to provide service to earn the award. For performance awards, we recognize compensation expense on a straight ‑line basis fo r each separately vesting portion of the award as if the award was in substance, multiple awards . We have awarded to our employees and non ‑employee directors phantom units, and such phantom units are participating securities. A phantom unit is a notional unit that has no voting rights and entitles the grantee to receive a common unit upon the vesting. To measure fair values of granted or modified phantom units, we use the market price of our units on the grant date or modification date. To measure fair values of performance awards, 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 year ended December 31, 2015, equity ‑based compensation expense was less than $1 million, which had no tax impact. In the years ended December 31, 2014 and 2013 , we had no equity ‑based awards outstanding. See Note 11—Equity ‑Based Compensation. |
Income taxes | Income taxes —We provide for income taxes based upon the tax laws and rates in effect in the countries in which operations are conducted and income is earned. We recognize deferred tax assets and liabilities for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the applicable jurisdictional tax rates in effect at year end. We record a valuation allowance for deferred tax assets when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We also record a valuation allowance for deferred tax assets resulting from net operating losses incurred during the year in certain jurisdictions and for other deferred tax assets where, in our opinion, it is more likely than not that the financial statement benefit of these losses will not be realized. Additionally, we record a valuation allowance for foreign tax credit carryforwards , if applicable, to reflect the possible expiration of these benefits prior to their utilization. We maintain liabilities for estimated tax exposures in our jurisdictions of operation, and we recognize the provisions and benefits resulting from changes to those liabilities in our income tax expense or benefit along with related interest and penalties. Tax exposure items may include potential challenges to qualification for treaty benefits, intercompany pricing, disposition transactions, and withholding tax rates and their applicability. These tax exposures are resolved primarily through the settlement of audits within these tax jurisdictions or by judicial means, but can also be affected by changes in applicable tax law or other factors, which could cause us to revise past estimates. The U.S. Internal Revenue Service (the “IRS”) has previously challenged and is currently challenging Transocean’s transfer pricing relating to certain bareboat charters. If the IRS successfully challenged our transfer pricing policies, it could result in a material increase in our U.S. federal income tax expense. See Note 5—Income Taxes. |
Earnings per unit | Earnings per unit —We apply the two ‑class method of calculating earnings per unit for our participating securities, including our common units, subordinated units and our incentive distribution rights. Under our limited liability company agreement, we established a cash distribution policy that requires the distribution of our available cash, which is determined by our board of directors (see Note 9—Cash Distributions). To calculate the earnings per unit for our common and subordinated unitholders, we allocate our net income or loss attributable to controlling interest for the quarterly or annual period in proportion to the respective ownership interest or, if the application of our cash distribution policy results in disproportionate distribution, in accordance with such policy. We present earnings per unit regardless of whether such earnings would or could be distributed under the terms of our limited liability company agreement. Accordingly, the reported earnings per unit is not indicative of potential cash distributions that may be made based on historical or future earnings. See Note 6—Earnings Per Unit. |
Cash and cash equivalents | Cash and cash equivalents —We consider cash equivalents to include highly liquid debt instruments with original maturities of three months or less, such as time deposits with commercial banks that have high credit ratings, U.S. Treasury and government securities, Eurodollar time deposits, certificates of deposit and commercial paper. We may also invest excess funds in no ‑load, open ‑ended, management investment trusts. Such management trusts invest exclusively in high ‑quality money market instruments. |
Accounts receivable | Accounts receivable —We earn our revenues by providing our drilling services to international oil companies. We evaluate the credit quality of our customers on an ongoing basis, and we do not generally require collateral or other security to support customer receivables. We establish an allowance for doubtful accounts on a case ‑by ‑case basis, considering changes in the financial position of a customer, when we believe the required payment of specific amounts owed to us is unlikely to occur. At December 31, 2015 and 2014, we had no allowance for doubtful accounts. 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 December 31, 2015 and 2014, the aggre gate face value of such accounts receivable was $15 million and $24 million, respectively. At December 31, 2015, the aggregate carr ying amount of such accounts receivable was $15 million, recorded in accounts receivable. At December 31, 2014, the aggregate carrying amount of such accounts receivable was $22 million, including $12 million and $10 million, respectively, recorded in accounts receivable and other assets, respectively. At December 31, 2015 and 2014, our long ‑term accounts receivable had a weighted average effective interest rate of 11 percent. |
Materials and supplies | Materials and supplies —We record materials and supplies at their average cost less an allowance for obsolescence. We estimate the allowance for obsolescence based on historical experience and expectations for future use of the materials and supplies. At December 31, 2015 and 2014, the allowance for obsolescence was $6 million and $3 million, respectively. |
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 December 31, 2015, the aggregate carrying amount of our property and equipment represented approximately 85 percent of our total assets. We capitalize expenditures for newbuilds, renewals, replacements and improvements, including capitalized interest, if applicable, and we recognize the expense for maintenance and repair costs as incurred. Upon sale or other disposition of an asset, we recognize a net gain or loss on disposal of the asset, which is measured as the difference between the net carrying amount of the asset and the net proceeds received. We compute depreciation using the straight ‑line method after allowing for salvage values. As of December 31, 2014, we reduced the salvage values of our drilling units due to existing market conditions. For the year ended December 31, 2015, this change in estimate resulted in an increase of approximately $1 million to depreciation expense. The estimated original useful life of each of our drilling units is 35 years. We reevaluate the remaining useful lives and salvage values of our rigs when certain events occur that directly impact the useful lives and salvage values of the rigs, including changes in operating condition, functional capability and market and economic factors. When evaluating the remaining useful lives of rigs, we also consider major capital upgrades required to perform certain contracts and the long ‑term impact of those upgrades on future marketability. |
Long-lived asset impairment | Long ‑lived asset impairment —We review the aggregate carrying amount of our long ‑lived assets, principally property and equipment, for potential impairment when events occur or circumstances change that indicate that the aggregate carrying amount of the drilling units and related equipment in our asset group may not be recoverable. We determine recoverability by evaluating the aggregate estimated undiscounted future net cash flows based on projected dayrates and utilization of our drilling units. When an impairment of our assets is indicated, we measure the impairment as the amount by which the aggregate carrying amount of the drilling units and related equipment in our asset group exceeds the aggregate estimated fair value. We measure the fair value of our drilling units and related equipment by applying a variety of valuation methods, incorporating a combination of income and market approaches, using projected discounted cash flows and estimates of the exchange price that would be received for the assets in the principal or most advantageous market for the assets in an orderly transaction between market participants as of the measurement date. |
Goodwill impairment | Goodwill impairment —Prior to the full impairment of our goodwill, we conducted impairment testing annually as of October 1 and more frequently, on an interim basis, when an event occured or circumstances changed that indicated that the fair value of our reporting unit may have declined below its carrying value. We tested goodwill at the reporting unit level, which is defined as an operating segment or one level below an operating segment that constitutes a business for which financial information is available and is regularly reviewed by management. We determined that we had a single reporting unit for this purpose. We estimate the fair value of our reporting unit using projected discounted cash flows, publicly traded company multiples and acquisition multiples. To develop the projected cash flows associated with our reporting unit, which are based on estimated future dayrates and rig utilization, we consider key factors that include assumptions regarding future commodity prices, credit market conditions and the effect these factors may have on our contract drilling operations and the capital expenditure budgets of our customers. We discount the projected cash flows using a long ‑term, risk ‑adjusted weighted ‑average cost of capital, which is based on our estimate of the investment returns that market participants would require for each of our reporting units. We derive publicly traded company multiples for companies with operations similar to our reporting units using observable information related to shares traded on stock exchanges and, when available, observable information related to recent acquisitions. If the reporting unit’s carrying amount exceeds its fair value, we consider goodwill impaired and perform a second step to measure the amount of the impairment loss, if any. |
Contingencies | Contingencies —We perform assessments of our contingencies on an ongoing basis to evaluate the appropriateness of our liabilities and disclosures for such contingencies. We establish liabilities for estimated loss contingencies when we believe a loss is probable and the amount of the probable loss can be reasonably estimated. We recognize corresponding assets for those loss contingencies that we believe are probable of being recovered through insurance. Once established, we adjust the carrying amount of a contingent liability upon the occurrence of a recognizable event when facts and circumstances change, altering our previous assumptions with respect to the likelihood or amount of loss. We recognize expense for legal costs as they are incurred, and we recognize a corresponding asset for such legal costs only if we expect such legal costs to be recovered through insurance. |
Net Investment | Net investment —Net investment on our consolidated balance sheets represents Transocean’s historical investment in the Predecessor, the Predecessor’s accumulated earnings and the net effect of cash transactions and allocations between Transocean and the Predecessor. |
Reclassifications | Reclassifications —We have made certain reclassifications, such as those related to our adoption of updates to accounting standards for income taxes, which did not have an effect on net income, to prior period amounts to conform with the current year’s presentation. These reclassifications did not have a material effect on our 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 18—Subsequent Events. |
Goodwill and Intangible Liabi26
Goodwill and Intangible Liability (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Goodwill and Intangible Liability | |
Schedule of carrying amounts of intangible liabilities and accumulated amortization and impairment | The gross carrying amounts of our drilling contract intangible liability and accumulated amortization were as follows (in millions): Year ended December 31, 2015 Year ended December 31, 2014 Gross Net Gross Net carrying Accumulated carrying carrying Accumulated carrying amount amortization amount amount amortization amount Drilling contract intangible liability Balance, beginning of period $ $ $ $ $ $ Amortization — — Balance, end of period $ $ $ $ $ $ |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Income Taxes | |
Schedule of components of provision for income taxes | The components of our provision for income taxes were as follows (in millions): Years ended December 31, 2015 2014 2013 Current tax expense $ $ $ Deferred tax expense Income tax expense $ $ $ |
Schedule of reconciliation of income taxes | The following is a reconciliation of the differences between the income tax expense computed at (a) the Marshall Islands holding company federal statutory rate of zero percent in the years ended December 31, 2015 and 2014 and (b) the Swiss holding company federal statutory rate of 7.83 percent for the Predecessor in the year ended December 31, 2013 and the reported provision for income taxes (in millions): Years ended December 31, 2015 2014 2013 Income tax expense at the respective federal statutory rate $ — $ — $ Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate Changes in unrecognized tax benefits, net Changes in valuation allowance — Other, net — — Income tax expense $ $ $ |
Schedule of deferred income taxes | The significant components of our deferred tax assets were as follows (in millions): December 31, 2015 2014 Deferred tax assets Net operating loss carryforwards $ $ Accrued payroll costs not currently deductible — Deferred revenues and drilling contract intangible Valuation allowance Other Total deferred tax assets Deferred tax liabilities Total deferred tax liabilities — — Net deferred tax assets $ $ |
Schedule of valuation allowance | The valuation allowance for our deferred tax assets was as follows (in millions): December 31, 2015 2014 Valuation allowance for deferred tax assets $ $ |
Schedule of changes to liabilities related to unrecognized tax benefits | The changes to our liabilities related to unrecognized tax benefits, excluding interest and penalties that we recognize as a component of income tax expense, were as follows (in millions): Years ended December 31, 2015 2014 2013 Balance, beginning of period $ $ $ Additions for current year tax positions Reductions for prior year tax positions — — Settlements — — — Balance, end of period $ $ $ |
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): December 31, 2015 2014 Unrecognized tax benefits, excluding interest and penalties $ $ Interest and penalties — — Unrecognized tax benefits, including interest and penalties $ $ |
Earnings Per Unit (Tables)
Earnings Per Unit (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Earnings 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, were as follows (in millions, except per unit data): Years ended December 31, 2015 2014 2013 Basic Diluted Numerator for earnings (loss) per unit Net income (loss) attributable to controlling interest $ $ $ $ — Undistributed earnings allocable to participating securities — — — — Net income (loss) available to unitholders $ $ $ $ — Net income (loss) available to common unitholders $ $ $ $ — Net income (loss) available to subordinated unitholders $ $ $ $ — Denominator for earnings (loss) per unit – common units Weighted-average common units outstanding — Effect of equity-based awards — — — — Weighted-average common units for per unit calculation — Denominator for earnings (loss) per unit – subordinated units Weighted-average subordinated units outstanding — Effect of equity-based awards — — — — Weighted-average subordinated units for per unit calculation — Earnings (loss) per unit Earnings (loss) per common unit $ $ $ $ — Earnings (loss) per subordinated unit $ $ $ $ — Cash distributions declared and paid per unit Common units $ $ $ $ — Subordinated units $ $ $ $ — |
Cash Distributions (Tables)
Cash Distributions (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Cash Distributions. | |
Schedule of percentage interests | Marginal percentage interest in distributions (a) Holders of incentive Total quarterly distribution distribution target amount (a) Unitholders rights Minimum quarterly distribution $ 0.362500 % — First target distribution Above $ 0.362500 up to $ 0.416875 % — Second target distribution Above $ 0.416875 up to $ 0.453125 % % Third target distribution Above $ 0.453125 up to $ 0.543750 % % Thereafter Above $ 0.543750 % % (a) The marginal percentage interest in distributions represents the percentage interests of the unitholders and holders of incentive distribution rights in any available cash from operations surplus that we distribute up to and including the corresponding total quarterly distribution amount, until the available cash from operating surplus reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the holders of incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. |
Supplemental Cash Flow Inform30
Supplemental Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Supplemental Cash Flow Information | |
Schedule of additional cash flow information | Additional cash flow information was as follows (in millions): Years ended December 31, 2015 2014 2013 Certain cash operating activities Cash payments for interest $ $ — $ — Cash payments for income taxes — Non - cash investing and financing activities Capital additions, accrued at end of period (a) $ — $ $ Property and equipment transferred to the Predecessor from affiliates (b) — Property and equipment transferred from the Predecessor to affiliates (c) — — Contributions for parent payment of patent royalties (d) — Contribution for parent indemnification of lost revenues (e) — — (a) These amounts represent additions to property and equipment for which we had accrued a corresponding liability in accounts payable to affiliates at the end of the period. (b) In the years ended December 31, 2014 and 2013, Transocean transferred to the Predecessor certain equipment with an aggregate net carrying amount of $ 10 million and $1 million, respectively, primarily all of which was to Development Driller III , and the Predecessor recorded the non ‑cash investing activity with a corresponding increase to its net investment. (c) In the year ended December 31, 2014, the Predecessor transferred to Transocean’s other drilling units certain equipment with an aggregate net carrying amount of $23 million, primarily all of which was from Development Driller III , and the Predecessor recorded the non ‑cash investing activity with a corresponding reduction to its net investment. (d) In the years ended December 31, 2015 and 2014, in connection with Transocean’s payment of royalty fees under our dual ‑activity license agreements with a Transocean affiliate, we recognized non ‑cash operating costs of $ 23 million and $7 million, respectively, with a corresponding increase to members’ equity. In the year ended December 31, 2014, we submitted to Transocean indemnification claims associated with lost revenues in the aggregate amount of $19 million, and we recognized a receivable from affiliate with a corresponding increase to members’ equity. At December 31, 2014, the unpaid balance was $ 10 million, recorded in accounts receivable from affiliates |
Financial Instruments (Tables)
Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Financial Instruments | |
Schedule of carrying amounts and fair values of our financial instruments | The carrying amounts and fair values of our financial instruments were as follows (in millions): December 31, 2015 December 31, 2014 Carrying Fair Carrying Fair amount value amount value Cash and cash equivalents $ $ $ $ Working capital note payable to affiliate — — |
Quarterly Results (unaudited) (
Quarterly Results (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2015 | |
Quarterly Results (unaudited) | |
Schedule of Quarterly Financial Data (Unaudited) | Three months ended March 31, June 30, September 30, December 31, (In millions, except per share data) 2015 Operating revenues $ $ $ $ Operating income (loss) (a) Net income (loss) (a) Net income (loss) attributable to controlling interest (a) Per unit earnings - basic and diluted Common units $ $ $ $ Subordinated units $ $ $ $ Weighted-average units outstanding Common units Subordinated units 2014 Operating revenues $ $ $ $ Operating income Net income Net income attributable to controlling interest (b) (b) Per unit earnings - basic and diluted Common units $ (b) $ (b) $ $ Subordinated units $ (b) $ (b) $ $ Weighted ‑ average units outstanding Common units (b) (b) Subordinated units (b) (b) (a) First quarter and third quarter included a loss of $67 million and $289 million, respectively, associated with the impairment of the remaining balance of our goodwill of which $34 million and $148 million, respectively, was attributable to controlling interest. See Note 4—Goodwill and Intangible Liability. Amounts associated with the Predecessor period, and, therefore, not applicable. See Note 2—Significant Accounting Policies |
Business (Details)
Business (Details) - USD ($) shares in Millions, $ in Millions | Aug. 05, 2014 | Dec. 31, 2015 | Jul. 29, 2014 |
Transocean | |||
Common units offered in initial public offering | 20.1 | ||
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% | 70.90% | |
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 Polici34
Significant Accounting Policies (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |||
Sep. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Significant Accounting Policies | |||||
Percentage of the consolidated results of operations, assets, liabilities, and cash flows, including noncontrolling interests | 100.00% | ||||
Equity-based compensation | |||||
Income tax benefit on equity-based compensation expense | $ 0 | ||||
Equity-based awards outstanding | 0 | ||||
Accounts receivable | |||||
Allowance for doubtful accounts | 0 | $ 0 | |||
Face value of long term accounts receivable | 15 | 24 | |||
Aggregate carrying amount of long term accounts receivable (Non-Current) | $ 22 | ||||
Weighted average effective interest rates of long term accounts receivable (as a percent) | 11.00% | ||||
Materials and supplies | |||||
Allowance for obsolescence on materials and supplies | $ 6 | $ 3 | |||
Property and equipment | |||||
Property and equipment as a percentage of total assets | 85.00% | ||||
Goodwill impairment | |||||
Loss on impairment of goodwill | $ 289 | $ 67 | $ 356 | ||
Loss on impairment of goodwill, tax effect | 0 | ||||
Loss on impairment of goodwill attributable to controlling interest | $ 148 | $ 34 | $ 182 | ||
Loss on impairment of goodwill per diluted share (in dollars per share) | $ 2.62 | ||||
Loss on impairment of goodwill attributable to noncontrolling interest | $ 174 | ||||
Maximum | |||||
Equity-based compensation | |||||
Equity-based compensation expense | 1 | ||||
Transocean | |||||
Allocated indirect and overhead costs | |||||
Allocated costs and expenses | 146 | 62 | |||
Drilling units | |||||
Property and equipment | |||||
Increase in depreciation expense due to adjustment in salvage value | $ 1 | ||||
Estimated original useful lives | 35 years | ||||
Accounts receivable | |||||
Accounts receivable | |||||
Aggregate carrying amount of long-term accounts receivable | $ 15 | 12 | |||
Other assets | |||||
Accounts receivable | |||||
Aggregate carrying amount of long-term accounts receivable | 10 | ||||
Predecessor Business | |||||
Equity-based compensation | |||||
Equity-based awards outstanding | 0 | ||||
Predecessor Business | Transocean | |||||
Allocated indirect and overhead costs | |||||
Allocated operating and maintenance costs | 14 | $ 28 | |||
Allocated personnel costs included in operating and maintenance costs | 11 | 21 | |||
Allocated general and administrative costs | 6 | 10 | |||
Allocated personnel costs included in general and administrative costs | $ 4 | $ 6 |
New Accounting Pronouncements (
New Accounting Pronouncements (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
New accounting pronouncement | ||
Deferred income taxes, net, noncurrent assets | $ 10 | $ 15 |
New accounting pronouncement, early adoption, effect | ASU-Classification of deferred taxes | ||
New accounting pronouncement | ||
Deferred income taxes, net, noncurrent assets | 8 | |
Deferred income taxes, net, current assets | $ (8) |
Goodwill and Intangible Liabi36
Goodwill and Intangible Liability (Impairment) (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2015 | |
Goodwill Impairment | |||
Loss on impairment of goodwill | $ 289 | $ 67 | $ 356 |
Loss on impairment of goodwill, tax effect | 0 | ||
Loss on impairment of goodwill attributable to controlling interest | $ 148 | $ 34 | $ 182 |
Loss on impairment of goodwill per diluted share | $ 2.62 | ||
Loss on impairment of goodwill attributable to noncontrolling interest | $ 174 |
Goodwill and Intangible Liabi37
Goodwill and Intangible Liability (Origination) (Details) - USD ($) $ in Millions | Dec. 31, 2014 | Aug. 05, 2014 | Jan. 01, 2012 |
Goodwill | |||
Goodwill | $ 356 | ||
Transocean | |||
Goodwill | |||
Allocated goodwill | $ 356 | ||
Transocean | Predecessor Business | |||
Goodwill | |||
Allocated goodwill | $ 213 |
Goodwill and Intangible Liabi38
Goodwill and Intangible Liability (Intangibles) (Details) - Drilling contract intangible liabilities - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Change in gross carrying amounts of drilling contract intangible liabilities | ||
Gross carrying amount at the beginning of the period | $ 126 | $ 126 |
Gross carrying amount at the end of the period | 126 | 126 |
Changes in accumulated amortization of definite-lived intangible liabilities | ||
Accumulated amortization at the beginning of the period | (97) | (82) |
Amortization | (15) | (15) |
Accumulated amortization at the end of the period | (112) | (97) |
Changes in net carrying amount of definite-lived intangible liabilities | ||
Net carrying amount at the beginning of the year | 29 | 44 |
Amortization | (15) | (15) |
Net carrying amount at the end of the year | $ 14 | $ 29 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Components of provision (benefit) for income taxes | |||
Annual effective tax rates (as a percent) | 6.20% | 8.50% | 10.70% |
Current tax expense | $ 9 | $ 2 | |
Deferred tax expense | 5 | 18 | |
Income tax expense | $ 14 | $ 20 | |
Reconciliation of the differences between the income tax expense computed at the holding company statutory rate and the reported provision for income taxes | |||
Statutory rate | 0.00% | 0.00% | |
Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate | $ 11 | $ 15 | |
Changes in unrecognized tax benefits, net | 2 | 3 | |
Changes in valuation allowance | 2 | 2 | |
Other, net | (1) | ||
Income tax expense | 14 | 20 | |
Deferred tax assets | |||
Net operating loss carryforwards | 4 | 2 | |
Accrued payroll costs not currently deductible | 1 | ||
Deferred revenues and drilling contract intangible | 5 | 12 | |
Valuation allowance | (4) | (2) | |
Other | 4 | 3 | |
Total deferred tax assets | 10 | 15 | |
Net deferred tax assets | 10 | 15 | |
Reconciliation of unrecognized tax benefits, excluding interest and penalties | |||
Balance, beginning of period | 1 | 12 | |
Additions for current year tax positions | 2 | 1 | |
Reductions for prior year tax positions | (12) | ||
Balance, end of period | 3 | 1 | $ 12 |
Unrecognized tax benefits | |||
Unrecognized tax benefits, excluding interest and penalties | 3 | 1 | |
Unrecognized tax benefits, including interest and penalties | 3 | 1 | |
Unrecognized tax benefits would favorably impact the effective tax rate | 3 | ||
Non-current deferred tax assets | |||
Deferred tax assets | |||
Valuation allowance | (4) | (2) | |
Maximum | |||
Unrecognized tax benefits | |||
Interest and penalties related to unrecognized tax benefits recognized as a component of income tax expense | $ 1 | 1 | |
Predecessor Business | |||
Components of provision (benefit) for income taxes | |||
Current tax expense | 8 | ||
Deferred tax expense | 15 | ||
Income tax expense | $ 23 | ||
Reconciliation of the differences between the income tax expense computed at the holding company statutory rate and the reported provision for income taxes | |||
Statutory rate | 7.83% | ||
Income tax expense at the respective federal statutory rate | $ 17 | ||
Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate | 4 | ||
Changes in unrecognized tax benefits, net | 2 | ||
Income tax expense | 23 | ||
Reconciliation of unrecognized tax benefits, excluding interest and penalties | |||
Balance, beginning of period | $ 12 | 11 | |
Additions for current year tax positions | 1 | ||
Balance, end of period | 12 | ||
Predecessor Business | Maximum | |||
Unrecognized tax benefits | |||
Interest and penalties related to unrecognized tax benefits recognized as a component of income tax expense | $ 1 |
Earnings Per Unit (Details)
Earnings Per Unit (Details) - USD ($) $ / shares in Units, $ in Millions | Nov. 04, 2014 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Numerator for earnings (loss) per unit, basic | |||||||||
Net income (loss) attributable to controlling interest | $ 34 | $ (134) | $ 35 | $ (6) | $ 19 | $ 17 | $ (71) | $ 36 | |
Net income (loss) available to unitholders | (71) | 36 | |||||||
Denominator for earnings (loss) per unit, basic | |||||||||
Distribution (in dollars per unit) | $ 0.2246 | ||||||||
Numerator for earnings (loss) per unit, diluted | |||||||||
Net income (loss) attributable to controlling interest | $ 34 | $ (134) | $ 35 | $ (6) | $ 19 | $ 17 | (71) | 36 | |
Net income (loss) available to unitholders | $ (71) | $ 36 | |||||||
Denominator for earnings (loss) per unit, diluted | |||||||||
Distribution (in dollars per unit) | $ 0.2246 | ||||||||
Share-based awards | |||||||||
Denominator for earnings (loss) per unit, diluted | |||||||||
Share-based awards excluded from earnings per unit calculation (in shares) | 16,474 | 0 | |||||||
Common units | |||||||||
Numerator for earnings (loss) per unit, basic | |||||||||
Net income (loss) attributable to controlling interest | $ (43) | $ 22 | |||||||
Net income (loss) available to common unitholders | $ (43) | $ 22 | |||||||
Denominator for earnings (loss) per unit, basic | |||||||||
Weighted average units outstanding (in units) | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | |
Weighted-average common units for per unit calculation (in units) | 41,000,000 | 41,000,000 | |||||||
Earnings (loss) per unit—basic | $ (1.02) | $ 0.52 | |||||||
Distribution (in dollars per unit) | $ 1.4500 | $ 0.2246 | |||||||
Numerator for earnings (loss) per unit, diluted | |||||||||
Net income (loss) attributable to controlling interest | $ (43) | $ 22 | |||||||
Net income (loss) available to common unitholders | $ (43) | $ 22 | |||||||
Denominator for earnings (loss) per unit, diluted | |||||||||
Weighted average units outstanding (in units) | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | 41,000,000 | |
Weighted-average common units for per unit calculation (in units) | 41,000,000 | 41,000,000 | |||||||
Earnings (loss) per unit—diluted | $ (1.02) | $ 0.52 | |||||||
Distribution (in dollars per unit) | $ 1.4500 | 0.2246 | |||||||
Earnings (loss) per unit | |||||||||
Earnings per unit - basic and diluted (in dollars per share) | $ 0.49 | $ (1.94) | $ 0.51 | $ (0.09) | $ 0.28 | $ 0.24 | $ 0.52 | ||
Subordinated units | |||||||||
Numerator for earnings (loss) per unit, basic | |||||||||
Net income (loss) attributable to controlling interest | $ (28) | $ 14 | |||||||
Net income (loss) available to subordinated unitholders | $ (28) | $ 14 | |||||||
Denominator for earnings (loss) per unit, basic | |||||||||
Weighted average units outstanding (in units) | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | |
Weighted-average common units for per unit calculation (in units) | 28,000,000 | 28,000,000 | |||||||
Earnings (loss) per unit—basic | $ (1.02) | $ 0.52 | |||||||
Distribution (in dollars per unit) | $ 1.4500 | $ 0.2246 | |||||||
Numerator for earnings (loss) per unit, diluted | |||||||||
Net income (loss) attributable to controlling interest | $ (28) | $ 14 | |||||||
Net income (loss) available to subordinated unitholders | $ (28) | $ 14 | |||||||
Denominator for earnings (loss) per unit, diluted | |||||||||
Weighted average units outstanding (in units) | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | 28,000,000 | |
Weighted-average common units for per unit calculation (in units) | 28,000,000 | 28,000,000 | |||||||
Earnings (loss) per unit—diluted | $ (1.02) | $ 0.52 | |||||||
Distribution (in dollars per unit) | $ 1.4500 | 0.2246 | |||||||
Earnings (loss) per unit | |||||||||
Earnings per unit - basic and diluted (in dollars per share) | $ 0.49 | $ (1.94) | $ 0.51 | $ (0.09) | $ 0.28 | $ 0.24 | $ 0.52 |
Credit Agreements (Details)
Credit Agreements (Details) - USD ($) $ in Millions | Jul. 17, 2015 | Aug. 05, 2014 | Jul. 29, 2014 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Credit Agreements | ||||||
Repayment of working capital note payable | $ 43 | |||||
Disbursement to affiliates for working capital adjustment | $ 5 | |||||
Rig Cos and subsidiaries | ||||||
Credit Agreements | ||||||
Period after acquisition to determine pro rata share of actual net working capital | 60 days | |||||
Five Year Revolving Credit Facility | ||||||
Credit Agreements | ||||||
Aggregate borrowing capacity | $ 300 | |||||
Credit facility term | 5 years | |||||
Basis spread on variable rate (as a percent) | 1.625% | |||||
Credit facility amount outstanding | $ 0 | |||||
Available borrowing capacity | $ 300 | |||||
Five Year Revolving Credit Facility | Minimum | ||||||
Credit Agreements | ||||||
Percentage of commitment fees | 0.225% | |||||
Five Year Revolving Credit Facility | Maximum | ||||||
Credit Agreements | ||||||
Percentage of commitment fees | 0.325% | |||||
Five Year Revolving Credit Facility | LIBOR | Minimum | ||||||
Credit Agreements | ||||||
Basis spread on variable rate (as a percent) | 1.625% | |||||
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 | ||||||
Credit facility term | 364 days | |||||
Face amount of debt | $ 43 | |||||
Outstanding principal amount | $ 43 | $ 43 | ||||
Repayment of working capital note payable | $ 43 | |||||
Disbursement to affiliates for working capital adjustment | $ 4 |
Commitments and Contingencies (
Commitments and Contingencies (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Dec. 31, 2014 | |
Commitments and Contingencies | ||
Future payments required under our purchase obligations | $ 12 | |
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 | $ 1,950 | |
Retained risk | Transocean | ||
Commitments and Contingencies | ||
Maximum percentage of asset insured value covered by damage mitigation insurance | 50.00% | |
Per occurrence deductible on collision liability claims | $ 10 | |
Per occurrence deductible on crew personal injury and other third-party non-crew claims | 5 | |
Commercial market excess liability coverage | 700 | |
Per occurrence deductible on excess liability for which risk is retained by wholly-owned insurance company | 50 | |
Liability loss excess amount for commercial market excess liability coverage | 750 | |
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 ($) $ / shares in Units, shares in Millions, $ in Millions | Oct. 29, 2015 | Jul. 30, 2015 | May. 04, 2015 | Feb. 09, 2015 | Nov. 24, 2014 | Nov. 04, 2014 | Aug. 05, 2014 | Dec. 31, 2015 | Dec. 31, 2014 |
Minimum quarterly distribution (in dollars per share) | $ 0.3625 | ||||||||
Minimum quarterly distribution annualized (in dollars pers share) | $ 1.45 | ||||||||
Distribution (in dollars per unit) | $ 0.2246 | ||||||||
Distribution to unitholders | $ 100 | $ 15 | |||||||
Distributions to holder of noncontrolling interests | $ 101 | ||||||||
First | |||||||||
Percentage of distribution of the quarterly distribution | 100.00% | ||||||||
Second | |||||||||
Percentage of distribution of the quarterly distribution | 100.00% | ||||||||
Third | |||||||||
Percentage of distribution of the quarterly distribution | 100.00% | ||||||||
Transocean | |||||||||
Unit holds | 21.3 | ||||||||
Unit holds | 27.6 | ||||||||
Percentage of interest holding | 70.90% | ||||||||
Distribution to unitholders | $ 11 | $ 71 | |||||||
Minimum quarterly distribution | |||||||||
Minimum quarterly distribution (in dollars per share) | $ 0.362500 | ||||||||
First target distribution | |||||||||
Quarterly distribution target amount (in dollars pers share) | 0.362500 | ||||||||
Maximum quarterly distribution target amount (in dollars pers share) | 0.416875 | ||||||||
Second target distribution | |||||||||
Quarterly distribution target amount (in dollars pers share) | 0.416875 | ||||||||
Maximum quarterly distribution target amount (in dollars pers share) | 0.453125 | ||||||||
Third target distribution | |||||||||
Quarterly distribution target amount (in dollars pers share) | 0.453125 | ||||||||
Maximum quarterly distribution target amount (in dollars pers share) | 0.543750 | ||||||||
Thereafter | |||||||||
Quarterly distribution target amount (in dollars pers share) | $ 0.543750 | ||||||||
Unitholders | |||||||||
Distribution (in dollars per unit) | $ 0.3625 | $ 0.3625 | $ 0.3625 | $ 0.3625 | |||||
Distribution to unitholders | $ 15 | $ 100 | |||||||
Unitholders | Minimum quarterly distribution | |||||||||
Marginal percentage interest in distribution | 100.00% | ||||||||
Unitholders | First target distribution | |||||||||
Marginal percentage interest in distribution | 100.00% | ||||||||
Unitholders | Second target distribution | |||||||||
Marginal percentage interest in distribution | 85.00% | ||||||||
Unitholders | Third target distribution | |||||||||
Marginal percentage interest in distribution | 75.00% | ||||||||
Unitholders | Thereafter | |||||||||
Marginal percentage interest in distribution | 50.00% | ||||||||
Holders of incentive distribution rights | Second target distribution | |||||||||
Marginal percentage interest in distribution | 15.00% | ||||||||
Holders of incentive distribution rights | Third target distribution | |||||||||
Marginal percentage interest in distribution | 25.00% | ||||||||
Holders of incentive distribution rights | Thereafter | |||||||||
Marginal percentage interest in distribution | 50.00% | ||||||||
Common units | Transocean | |||||||||
Unit holds | 21.3 | ||||||||
Subordinated units | Transocean | |||||||||
Unit holds | 27.6 | ||||||||
Noncontrolling interest | Transocean | |||||||||
Distributions to holder of noncontrolling interests | $ 101 |
Unit Repurchase Program (Detail
Unit Repurchase Program (Details) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2015 | Nov. 04, 2015 | |
Cancellation of repurchased common units | $ 1 | |
Unit repurchase program | ||
Authorized repurchase amount | $ 40 | |
Cancellation of repurchased common units (in units) | 91,500 | |
Units repurchased amount (in dollars per unit) | $ 9.20 | |
Cancellation of repurchased common units | $ 1 |
Equity-Based Compensation Plan
Equity-Based Compensation Plan (Details) $ / shares in Units, $ in Millions | Dec. 31, 2015USD ($)installmentshares | Dec. 31, 2015installment$ / sharesshares |
Time-Based phantom units | ||
Equity-Based Compensation | ||
Number of phantom units granted | 60,105 | |
Weighted average grant date fair value (in dollars per unit) | $ / shares | $ 14.78 | |
Total grant date fair value | $ | $ 1 | |
Performance-based phantom units | ||
Equity-Based Compensation | ||
Number of equal installments vesting | installment | 3 | 3 |
Period from grant after which vesting begins | 1 year | |
Employees | Time-Based phantom units | ||
Equity-Based Compensation | ||
Number of equal installments vesting | installment | 3 | 3 |
Period from grant after which vesting begins | 1 year | |
Non Employee Directors | Time-Based phantom units | ||
Equity-Based Compensation | ||
Vesting period | 1 year | |
Chief Executive Officer | Performance-based phantom units | ||
Equity-Based Compensation | ||
Number of phantom units granted | 19,459 | |
Weighted average grant date fair value (in dollars per unit) | $ / shares | $ 8.83 | |
Incentive Compensation | ||
Equity-Based Compensation | ||
Numbers of units authorized | 3,400,000 | 3,400,000 |
Maximum | Chief Executive Officer | Performance-based phantom units | ||
Equity-Based Compensation | ||
Total grant date fair value | $ | $ 1 |
Related Party Transactions (Det
Related Party Transactions (Details) | Aug. 05, 2014USD ($)item | Jul. 29, 2014USD ($) | Dec. 31, 2015USD ($)itemdirector | Dec. 31, 2014USD ($) | Dec. 31, 2013USD ($) |
Related Party Transactions | |||||
Number of members of board of directors | director | 7 | ||||
Percentage of ownership to request cumulative voting | 50.00% | ||||
Indemnification claim for lost revenues | $ 10,000,000 | ||||
Accounts receivable from affiliates | $ 1,000,000 | 28,000,000 | |||
Number of drilling units equipped with patented dual activity technology | item | 3 | ||||
Number of drilling stations to employ structures, equipment and techniques of dual-activity technology | item | 2 | ||||
Five Year Revolving Credit Facility | |||||
Related Party Transactions | |||||
Credit facility term | 5 years | ||||
Working capital notes payable | |||||
Related Party Transactions | |||||
Face amount of debt | $ 43,000,000 | ||||
Credit facility term | 364 days | ||||
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 | |||||
Operating and maintenance costs and expenses | $ 1,000,000 | 1,000,000 | |||
Master services agreements | |||||
Related Party Transactions | |||||
Notice period for termination of agreement | 90 days | ||||
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 | |||||
Term of agreement | 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 | item | 4 | ||||
Number of ultra deepwater drillships available for offer to purchase interest | item | 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 | |||||
Operating and maintenance costs and expenses | 116,000,000 | 46,000,000 | |||
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 | |||||
Operating and maintenance costs and expenses | 19,000,000 | 11,000,000 | |||
Payment for materials and supplies settled through net investment | Master services agreements | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 26,000,000 | 13,000,000 | |||
Insurance costs allocated to drilling rigs | Master services agreements | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 11,000,000 | 5,000,000 | |||
Personnel costs | Secondment agreements | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 91,000,000 | 38,000,000 | |||
Personnel costs | Secondment agreements | General and administrative costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 4,000,000 | 2,000,000 | |||
TODDI | License agreements | |||||
Related Party Transactions | |||||
Original license cost | 20,000,000 | ||||
Deferred license cost | 1,000,000 | 4,000,000 | |||
TODDI | License agreements | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Amortized license cost | 3,000,000 | 2,000,000 | $ 3,000,000 | ||
TODDI | Royalty fees | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | $ 23,000,000 | 7,000,000 | |||
Transocean | |||||
Related Party Transactions | |||||
Percentage of limited liability company interest held by parent | 70.80% | 70.90% | |||
Percentage of interest holding | 70.90% | ||||
Number of Members of board of directors Transocean can appoint | director | 3 | ||||
Minimum number of directors that Transocean can appoint after electing cumulative voting. | director | 1 | ||||
Percentage of ownership that would enable Transocean to appoint majority of the board of directors | 20.00% | ||||
Transocean | Omnibus Agreement | |||||
Related Party Transactions | |||||
Period of indemnification | 5 years | ||||
Aggregate amount of indemnity coverage provided by Transocean for such environmental and human health and safety liabilities | $ 10,000,000 | ||||
Maximum amount of lost revenue arising out of the failure to receive an operating dayrate from Chevron for Discoverer Clear Leader | 100,000,000 | ||||
Indemnification claim for lost revenues | 19,000,000 | ||||
Accounts receivable from affiliates | 10,000,000 | ||||
Transocean | Omnibus Agreement | Minimum | |||||
Related Party Transactions | |||||
Aggregate amount of indemnification for which Transocean is liable for claims | $ 500,000 | ||||
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 | TODDI | Services for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 25,000,000 | 35,000,000 | |||
Predecessor Business | TODDI | Services for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services | General and administrative costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 8,000,000 | 10,000,000 | |||
Predecessor Business | TODDI | Payment for materials and supplies settled through net investment | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 20,000,000 | 38,000,000 | |||
Predecessor Business | TODDI | Insurance costs allocated to drilling rigs | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 7,000,000 | 13,000,000 | |||
Predecessor Business | TODDI | Personnel costs | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | 60,000,000 | 100,000,000 | |||
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 | Operating and maintenance costs and expenses | |||||
Related Party Transactions | |||||
Operating and maintenance costs and expenses | $ 23,000,000 | $ 19,000,000 |
Supplemental Cash Flow Inform47
Supplemental Cash Flow Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Certain cash operating activities | |||
Cash payments for interest | $ 1 | ||
Cash payments for income taxes | 9 | ||
Non‑cash investing and financing activities | |||
Capital additions, accrued at end of period | $ 6 | ||
Contributions for parent payment of patent royalties | $ 23 | 7 | |
Contribution for parent indemnification of lost revenues | 10 | ||
Contribution for parent indemnification of lost revenues | 19 | ||
Predecessor Business | |||
Certain cash operating activities | |||
Cash payments for income taxes | $ 6 | ||
Non‑cash investing and financing activities | |||
Capital additions, accrued at end of period | 1 | ||
Transocean | Predecessor Business | |||
Non‑cash investing and financing activities | |||
Property and equipment transferred to the Predecessor from affiliates | 10 | $ 1 | |
Property and equipment transferred from the Predecessor to affiliates | $ (23) |
Financial Instruments (Details)
Financial Instruments (Details) - USD ($) $ in Millions | Dec. 31, 2015 | Dec. 31, 2014 |
Financial Instruments | ||
Carrying amount of cash equivalents | $ 153 | $ 40 |
Carrying amount | ||
Financial Instruments | ||
Cash and cash equivalents | 159 | 86 |
Working capital note payable to affiliate | 43 | |
Fair value | ||
Financial Instruments | ||
Cash and cash equivalents | $ 159 | 86 |
Working capital note payable to affiliate | $ 43 |
Operating Segments, Geographi49
Operating Segments, Geographic Analysis and Major Customers (Details) | 12 Months Ended | ||
Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | |
Operating revenue | Customer concentration | Chevron Corporation | |||
Operating Segments, Geographic Analysis and Major Customers | |||
Percentage of concentration | 67.00% | 67.00% | 67.00% |
Operating revenue | Customer concentration | BP plc | |||
Operating Segments, Geographic Analysis and Major Customers | |||
Percentage of concentration | 33.00% | 33.00% | 33.00% |
U.S. Gulf Of Mexico | Operating revenue | Geographic concentration | |||
Operating Segments, Geographic Analysis and Major Customers | |||
Percentage of concentration | 100.00% | 100.00% | 100.00% |
U.S. Gulf Of Mexico | Assets | Geographic concentration | |||
Operating Segments, Geographic Analysis and Major Customers | |||
Percentage of concentration | 100.00% | 100.00% |
Quarterly Results (unaudited)50
Quarterly Results (unaudited) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2014 | |
Operating revenues | $ 154 | $ 125 | $ 161 | $ 140 | $ 138 | $ 136 | $ 145 | $ 148 | $ 580 | $ 567 |
Operating income (loss) | 76 | (260) | 77 | (7) | 49 | 60 | 55 | 69 | (114) | 233 |
Net income (loss) | 71 | (261) | 73 | (10) | 45 | 57 | $ 50 | $ 63 | (127) | 215 |
Net income (loss) attributable to controlling interest | $ 34 | (134) | $ 35 | (6) | $ 19 | $ 17 | (71) | 36 | ||
Weighted‑average units outstanding—basic | ||||||||||
Loss on impairment of goodwill | 289 | 67 | 356 | |||||||
Loss on impairment of goodwill attributable to controlling interest | $ 148 | $ 34 | 182 | |||||||
Common units | ||||||||||
Net income (loss) attributable to controlling interest | $ (43) | $ 22 | ||||||||
Per unit earnings | ||||||||||
Earnings per unit - basic and diluted (in dollars per share) | $ 0.49 | $ (1.94) | $ 0.51 | $ (0.09) | $ 0.28 | $ 0.24 | $ 0.52 | |||
Weighted‑average units outstanding—basic | ||||||||||
Weighted average units outstanding (in units) | 41 | 41 | 41 | 41 | 41 | 41 | 41 | 41 | ||
Subordinated units | ||||||||||
Net income (loss) attributable to controlling interest | $ (28) | $ 14 | ||||||||
Per unit earnings | ||||||||||
Earnings per unit - basic and diluted (in dollars per share) | $ 0.49 | $ (1.94) | $ 0.51 | $ (0.09) | $ 0.28 | $ 0.24 | $ 0.52 | |||
Weighted‑average units outstanding—basic | ||||||||||
Weighted average units outstanding (in units) | 28 | 28 | 28 | 28 | 28 | 28 | 28 | 28 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions | Feb. 25, 2016 | Feb. 16, 2016 | Feb. 09, 2016 | Nov. 24, 2014 | Nov. 04, 2014 | Aug. 05, 2014 | Mar. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Subsequent Events | |||||||||
Distribution (in dollars per unit) | $ 0.2246 | ||||||||
Distribution to unitholders | $ 100 | $ 15 | |||||||
Cancellation of repurchased common units | $ 1 | ||||||||
Common units | |||||||||
Subsequent Events | |||||||||
Distribution (in dollars per unit) | $ 1.4500 | $ 0.2246 | |||||||
Cancellation of repurchased common units | $ 1 | ||||||||
Unit repurchase program | |||||||||
Subsequent Events | |||||||||
Cancellation of repurchased common units (in units) | 91,500 | ||||||||
Units repurchased amount (in dollars per unit) | $ 9.20 | ||||||||
Cancellation of repurchased common units | $ 1 | ||||||||
Subsequent Events | |||||||||
Subsequent Events | |||||||||
Distribution (in dollars per unit) | $ 0.3625 | ||||||||
Approved distribution to unitholders | $ 25 | ||||||||
Subsequent Events | Unit repurchase program | |||||||||
Subsequent Events | |||||||||
Units repurchased amount (in dollars per unit) | $ 7.74 | ||||||||
Cancellation of repurchased common units | $ 2 | ||||||||
Subsequent Events | Unit repurchase program | Common units | |||||||||
Subsequent Events | |||||||||
Cancellation of repurchased common units (in units) | 215,467 | ||||||||
Transocean | |||||||||
Subsequent Events | |||||||||
Distribution to unitholders | $ 11 | $ 71 | |||||||
Percentage of limited liability company interest held by parent | 70.80% | 70.90% | |||||||
Transocean | Subsequent Events | |||||||||
Subsequent Events | |||||||||
Approved distribution to unitholders | $ 18 | ||||||||
Distribution to unitholders | $ 54 | ||||||||
Percentage of limited liability company interest held by parent | 71.10% |