Transocean Partners (RIGP) 10-K 26 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2014	Feb. 17, 2015
Entity Registrant Name	Transocean Partners LLC
Entity Central Index Key	1607250
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$0
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Common units
Entity Common Stock, Shares Outstanding			41,379,310
Subordinated units
Entity Common Stock, Shares Outstanding			27,586,207

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenues
Contract drilling revenues	$557
Other revenues	10
Total operating revenues	567
Costs and expenses
Operating and maintenance	248
Depreciation	66
General and administrative	20
Total costs and expenses	334
Operating income	233
Other income (expense), net
Interest income	3
Interest expense	-1
Other income (expense), net	2
Income before income tax expense	235
Income tax expense	20
Net income	215
Net income attributable to Predecessor	135
Net income subsequent to initial public offering	80
Net income attributable to noncontrolling interest	44
Net income attributable to controlling interest	36
Common units
Other income (expense), net
Net income attributable to controlling interest	22
Earnings per unit - basic and diluted
Earnings per unit - basic and diluted (in dollars per share)	$0.52
Weighted-average units outstanding
Weighted-average units outstanding (in shares)	41
Subordinated units
Other income (expense), net
Net income attributable to controlling interest	14
Earnings per unit - basic and diluted
Earnings per unit - basic and diluted (in dollars per share)	$0.52
Weighted-average units outstanding
Weighted-average units outstanding (in shares)	28
Predecessor Business
Operating revenues
Contract drilling revenues		517	558
Other revenues		9	11
Total operating revenues		526	569
Costs and expenses
Operating and maintenance		242	219
Depreciation		66	65
General and administrative		10	9
Total costs and expenses		318	293
Operating income		208	276
Other income (expense), net
Interest income		4	3
Other income (expense), net		4	3
Income before income tax expense		212	279
Income tax expense		23	24
Net income		$189	$255

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Assets
Cash and cash equivalents	$86
Accounts receivable	112
Accounts receivable from affiliates	28
Materials and supplies, net	41
Deferred income taxes, net	8
Prepaid assets	6
Total current assets	281
Property and equipment	2,302
Less accumulated depreciation	-336
Property and equipment, net	1,966
Goodwill	356
Deferred income taxes, net	7
Other assets	22
Total assets	2,632
Liabilities and equity
Accounts payable to affiliates	76
Debt due to affiliates within one year	43
Deferred revenues	18
Other current liabilities	1
Total current liabilities	138
Long-term tax liability	1
Deferred revenues	13
Drilling contract intangible liability	29
Total long-term liabilities	43
Commitments and contingencies
Total members' equity	1,411
Noncontrolling interest	1,040
Total equity	2,451	2,344
Total liabilities and equity	2,632
Common units
Liabilities and equity
Common units, 41,379,310 authorized, issued and outstanding at December 31, 2014	847
Total equity	847
Subordinated units
Liabilities and equity
Subordinated units, 27,586,207 authorized, issued and outstanding at December 31, 2014	564
Total equity	564
Predecessor Business
Assets
Accounts receivable		103
Materials and supplies, net		34
Deferred income taxes, net		15
Prepaid assets		7
Total current assets		159
Property and equipment		2,309
Less accumulated depreciation		-271
Property and equipment, net		2,038
Goodwill		213
Deferred income taxes, net		29
Other assets		29
Total assets		2,468
Liabilities and equity
Deferred revenues		37
Total current liabilities		37
Long-term tax liability		13
Deferred revenues		30
Drilling contract intangible liability		44
Total long-term liabilities		87
Commitments and contingencies
Net investment		2,344
Total equity		2,344
Total liabilities and equity		$2,468

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical)	Dec. 31, 2014
Common units
Units authorized	41,379,310
Units issued	41,379,310
Units outstanding	41,379,310
Subordinated units
Units authorized	27,586,207
Units issued	27,586,207
Units outstanding	27,586,207

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (USD $)	Predecessor Business	Predecessor Business	Common units	Subordinated units	Total members' equity	Net investment	Noncontrolling interest	Total
In Millions, unless otherwise specified	Net investment
Balance, beginning of period at Dec. 31, 2011	$2,443	$2,443
Increase (Decrease) in Partners' Capital
Net income		255
Net income attributable to Predecessor	255	255
Distributions to the Predecessor parent, net	-310	-310
Balance, end of period at Dec. 31, 2012	2,388	2,388
Increase (Decrease) in Partners' Capital
Net income		189
Net income attributable to Predecessor	189	189
Distributions to the Predecessor parent, net	-233	-233
Balance, end of period at Dec. 31, 2013	2,344	2,344				2,344		2,344
Increase (Decrease) in Partners' Capital
Net income								215
Net income attributable to controlling interest			22	14	36			36
Net income attributable to Predecessor						135		135
Net income subsequent to initial public offering								80
Effect of formation transaction						-996	996
Allocation of net investment			821	547	1,368	-1,368
Contribution for parent payment of dual activity patent royalties			4	3	7			7
Contribution for parent indemnification of lost revenues			11	8	19			19
Net income attributable to noncontrolling interest							44	44
Distributions to the Predecessor parent, net						-115		-115
Distribution of available cash to unitholders			-9	-6	-15			-15
Distribution for working capital adjustment			-2	-2	-4			-4
Balance, end of period at Dec. 31, 2014			$847	$564	$1,411		$1,040	$2,451

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income	$215
Adjustments to reconcile to net cash provided by operating activities
Amortization of drilling contract intangible	-15
Depreciation	66
Patent royalties expense	7
Deferred income taxes	18
Changes in deferred revenues, net	-36
Changes in deferred costs, net	-4
Changes in operating assets and liabilities
Decrease in accounts receivable, net	4
Increase in materials and supplies, net	-8
Decrease in balances due to affiliates, net	-60
Increase in income tax liability, net	3
Net cash provided by operating activities	190
Cash flows from investing activities
Capital expenditures	-3
Net cash used in investing activities	-3
Cash flows from financing activities
Proceeds from working capital note payable to affiliate	43
Proceeds from affiliates for indemnification	9
Contributions resulting from formation transactions	8
Disbursement to affiliates for working capital adjustment	-5
Distribution of available cash to unitholders	-15
Distributions to the Predecessor parent, net	-141
Net cash used in financing activities	-101
Net increase in cash and cash equivalents	86
Cash and cash equivalents at end of period	86
Predecessor Business
Cash flows from operating activities
Net income		189	255
Adjustments to reconcile to net cash provided by operating activities
Amortization of drilling contract intangible		-18	-19
Depreciation		66	65
Deferred income taxes		15	21
Other, net		1	1
Changes in deferred revenues, net		-29	-38
Changes in deferred costs, net		4	3
Changes in operating assets and liabilities
Decrease in accounts receivable, net		22	55
Increase in materials and supplies, net		-13	-5
Increase in income tax liability, net		2	2
Net cash provided by operating activities		239	340
Cash flows from investing activities
Capital expenditures		-4	-15
Net cash used in investing activities		-4	-15
Cash flows from financing activities
Distributions to the Predecessor parent, net		-235	-325
Net cash used in financing activities		($235)	($325)

Business

Business	12 Months Ended
	Dec. 31, 2014
Business
Nature of Business
	Note 1—Business
	Transocean Partners LLC (“Transocean Partners”, “we”, “us”, or “our”), a Marshall Islands limited liability company, was formed on February 6, 2014, by Transocean Partners Holdings Limited, a wholly owned subsidiary of Transocean Ltd. (together with its affiliates, unless the context requires otherwise, “Transocean”), to own, operate and acquire modern, technologically advanced offshore drilling rigs.  The drilling units in our fleet include the ultra-deepwater drillships Discoverer Inspiration and Discoverer Clear Leader and the ultra-deepwater semisubmersible Development Driller III, which are located in the United States (“U.S.”) Gulf of Mexico.
	On July 29, 2014, we entered into a contribution agreement with Transocean that gave effect to certain formation transactions, including Transocean’s transfer of a 51 percent ownership interest in each of the entities that own and operate the drilling units in our fleet (each individually, a “RigCo”, and collectively, the “RigCos”).  Transocean holds the remaining 49 percent ownership interest in the RigCos.  We completed the formation transactions on August 5, 2014.
	On July 31, 2014, we announced the pricing of the initial public offering of our common units representing limited liability company interests, which began trading on the New York Stock Exchange under the ticker symbol “RIGP,” for $22.00 per unit.  On August 5, 2014, we completed the initial public offering of 20.1 million common units, including 2.6 million common units sold pursuant to the exercise in full of the underwriters’ option to purchase additional common units, which represented a 29.2 percent limited liability company interest in Transocean Partners.  Transocean Partners Holdings Limited (the “Transocean Member”) holds the remaining 21.3 million common units and 27.6 million subordinated units, which collectively represented a 70.8 percent limited liability company interest, and all of our incentive distribution rights.  As a result of the offering, the Transocean Member received net cash proceeds of $417 million, net of $26 million for underwriting discounts and commissions and other offering costs.
	The Transocean Partners LLC Predecessor (the “Predecessor”) represents 100 percent of the combined results of operations, assets and liabilities of the drilling units in the fleet (the “Predecessor Business”) prior to completion of the formation transactions and initial public offering on August 5, 2014.

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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 the 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, 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 statements of operations for the years ended December 31, 2013 and 2012 consist entirely of the combined results of operations of the Predecessor.
		·	Our consolidated balance sheet at December 31, 2014 consists of the consolidated balances of Transocean Partners.  Our consolidated balance sheet at December 31, 2013 consists of the combined balances of the Predecessor.
		·	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 statements of equity for the years ended December 31, 2013 and 2012 consist entirely of the combined activity of the Predecessor.
		·	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 statements of cash flows for the years ended December 31, 2013 and 2012 consist 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 materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes, allocated costs and related party transactions.  We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources.  Actual results could differ from such estimates.
	Fair value measurements—We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.  Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) significant observable inputs, including unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) significant other observable inputs, including direct or indirect market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) significant unobservable inputs, including those that require considerable judgment for which there is little or no market data (“Level 3”).  When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.
	Consolidation—We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes.  We eliminate intercompany transactions and accounts in consolidation.  We apply the equity method of accounting for an investment in an entity if we have the ability to exercise significant influence over the entity that (a) does not meet the variable interest entity criteria or (b) meets the variable interest entity criteria, but for which we are not deemed to be the primary beneficiary.  We apply the cost method of accounting for an investment in an entity if we do not have the ability to exercise significant influence over the unconsolidated entity.  We separately present within equity on our 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 11—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 year ended December 31, 2014, costs and expenses allocated to us by Transocean were $19 million (see Note 11—Related Party Transactions).
	The combined results of operations for the Predecessor include allocated indirect and overhead costs for certain functions historically performed by Transocean and not previously allocated to the Predecessor Business, including allocations of indirect operating and maintenance costs and expenses for onshore operational support services such as engineering, procurement and logistics and general and administrative costs and expenses related to executive oversight, accounting, treasury, tax, legal, and information technology.  We have applied these allocations based on relative values of net property and equipment and operating and maintenance costs and expenses.  We believe the assumptions underlying the consolidated financial statements, including the assumptions regarding allocation of costs from Transocean, are reasonable.  Nevertheless, the combined results of operations of the Predecessor do not include all of the costs that the Predecessor would have incurred had it been a stand-alone company during the periods presented and may not reflect the combined results of operations, financial position and cash flows had the Predecessor been a stand-alone company during the periods presented.  In the years ended December 31, 2014, 2013 and 2012, the Predecessor recognized such allocated operating and maintenance costs of $14 million, $28 million and $22 million, respectively, including $11 million, $21 million and $17 million, respectively, for personnel costs.  In the years ended December 31, 2014, 2013 and 2012, we recognized such allocated general and administrative costs of $6 million, $10 million and $9 million, respectively, including $4 million, $6 million and $6 million, respectively, for personnel costs.
	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 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 4—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 5—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 derive a majority of our revenues from 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, 2014 and 2013, 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, 2014 and 2013, the aggregate face value of our long-term accounts receivable was $24 million and $50 million, respectively.  At December 31, 2014, the aggregate carrying amount of our long-term accounts receivable was $22 million, including $12 million and $10 million, recorded in accounts receivable and other assets, respectively.  At December 31, 2013, the aggregate carrying amount of our long-term accounts receivable was $45 million, including $23 million and $22 million, respectively, recorded in accounts receivable and other assets, respectively.  At December 31, 2014 and 2013, our long-term accounts receivable had weighted average effective interest rates of 11 percent and 10 percent, respectively.
	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, 2014 and 2013, the allowance for obsolescence was $3 million and $2 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, 2014, the aggregate carrying amount of our property and equipment represented approximately 75 percent of our total assets.
	We compute depreciation using the straight-line method after allowing for salvage values.  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.
	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—We conduct impairment testing for our goodwill annually as of October 1 and more frequently, on an interim basis, when an event occurs or circumstances change that indicate that the fair value of a reporting unit may have declined below its carrying value.  We test 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 have determined that we have a single reporting unit for this purpose.  Before testing goodwill, we consider whether or not to first assess qualitative factors to determine whether the existence of events or circumstances lead to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether the two-step impairment test is required.  If, as the result of our qualitative assessment, we determine that the two-step impairment test is required, or, alternatively, if we elect to forgo the qualitative assessment, we test goodwill for impairment by comparing the carrying amount of the reporting unit, including goodwill, to the fair value of the reporting unit.
	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 years ended December 31, 2014 and 2013, as a result of our annual impairment testing, we concluded that our goodwill was not impaired.
	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, 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 17—Subsequent Events.

New_Accounting_Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 2014
New Accounting Pronouncements
New Accounting Pronouncements
	Note 3—New Accounting Pronouncements
	Recently adopted accounting standards
	Income taxes—Effective January 1, 2014, we adopted the accounting standards update that requires an unrecognized tax benefit to be presented in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward if net settlement is required or expected.  The update is effective for interim and annual periods beginning on or after December 15, 2013.  Our adoption did not have an effect on our consolidated balance sheets or the disclosures contained in our notes to consolidated financial statements.
	Recently issued accounting standards
	Presentation of financial statements—Effective with our annual report for the period ending December 31, 2016, we will adopt the accounting standards update that requires us to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about our ability to continue as a going concern within one year after the date that the financial statements are issued.  The update is effective for the annual period ending after December 15, 2016 and for annual periods and interim 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, 2017, we will adopt the accounting standards update that requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.  The update is effective for interim and annual periods beginning on or after December 15, 2016.  We are evaluating the requirements to determine the effect such requirements may have on our revenue recognition policies.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Taxes
Income Taxes
	Note 4—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.  The components of our provision for income taxes were as follows (in millions):
		Years ended December 31,
		2014			2013		2012
	Current tax expense	$	2		$	8	$	3
	Deferred tax expense	18			15		21
	Income tax expense	$	20		$	23	$	24
	We considered the earnings of the Predecessor to be indefinitely reinvested.  As such, we have not provided for taxes on these unremitted earnings.  If there were to be a distribution of these unremitted earnings, such distribution would be subject to withholding taxes in the U.S.
	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 for us in the year ended December 31, 2014 or (b) the Swiss holding company federal statutory rate of 7.83 percent for the Predecessor in the years ended December 31, 2013 and 2012 and the reported provision for income taxes (in millions):
		Years ended December 31,
		2014			2013		2012
	Income tax expense at the respective federal statutory rate	$	—		$	17	$	22
	Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate	15			4		—
	Changes in unrecognized tax benefits, net	3			2		2
	Changes in valuation allowance	2			—		—
	Income tax expense	$	20		$	23	$	24
	Deferred taxes—The significant components of our deferred tax assets were as follows (in millions):
		December 31,
		2014			2013
	Deferred tax assets
	Net operating loss carryforwards	$	2		$	—
	Deferred revenues and drilling contract intangible	12			39
	Valuation allowance	(2		)	—
	Other	3			5
	Total deferred tax assets	15			44
	Deferred tax liabilities
	Total deferred tax liabilities	—			—
	Net deferred tax assets	$	15		$	44
	During the three months ended December 31, 2014, we adjusted the deferred tax asset related to our drilling contract intangible to correct an error related to the remeasurement and contribution of such deferred tax asset in connection with our formation transactions.  As a result of the correction, we recorded a reduction of $11 million to the deferred tax asset with a corresponding entry to total equity.
	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, 2014, the tax effect of our U.K. net operating losses, which does not expire, was $2 million.
	The valuation allowance for our non-current deferred tax assets was as follows (in millions):
		December 31,
		2014			2013
	Valuation allowance for non-current deferred tax assets	$	2		$	—
	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,
		2014			2013		2012
	Balance, beginning of period	$	12		$	11	$	9
	Additions for current year tax positions	1			1		4
	Reductions for prior year tax positions	(12		)	—		—
	Settlements	—			—		(2		)
	Balance, end of period	$	1		$	12	$	11
	The Predecessor’s unrecognized tax benefits balance at December 31, 2013, originated in legal entities that were not transferred to us in the formation transactions which is reported as part of the reduction for prior year tax positions.
	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,
		2014			2013
	Unrecognized tax benefits, excluding interest and penalties	$	1		$	12
	Interest and penalties	—			1
	Unrecognized tax benefits, including interest and penalties	$	1		$	13
	In the year ended December 31, 2013, we recognized interest and penalties of less than $1 million associated with the unrecognized tax benefits and recorded as a component of income tax expense.  As of December 31, 2014, if recognized, $1 million of the unrecognized tax benefits would favorably impact the effective tax rate.
	It is reasonably possible that the existing liabilities for unrecognized tax benefits could increase or decrease in the year ending December 31, 2015, 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, 2014
Earnings per unit
Earnings per unit
	Note 5—Earnings per unit
	Our basic and diluted earnings per unit were the same because we did not have any potentially dilutive units outstanding for the periods presented.  The numerator and denominator used for the computation of basic and diluted per unit earnings, were as follows (in millions, except per share data):
		Years ended December 31,
		2014		2013		2012
	Numerator for earnings per unit
	Net income attributable to controlling interest	$	36	$	—	$	—
	Net income available to common unitholders	$	22	$	—	$	—
	Net income available to subordinated unitholders	$	14	$	—	$	—
	Denominator for earnings per unit
	Weighted-average common units outstanding	41		—		—
	Weighted-average subordinated units outstanding	28		—		—
	Earnings per unit
	Earnings per common unit	$	0.52	$	—	$	—
	Earnings per subordinated unit	$	0.52	$	—	$	—
	Cash distributions declared and paid per unit
	Common units	$	0.2246	$	—	$	—
	Subordinated units	$	0.2246	$	—	$	—
	We have not presented earnings per unit calculations for the Predecessor periods, since the Predecessor had no units outstanding (see Note 2 —Significant Accounting Policies—Presentation).
	See Note 9—Cash Distributions and Note 17—Subsequent Events.

Goodwill_and_Intangible_Liabil

Goodwill and Intangible Liability	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Liability
Goodwill and Intangible Liability
	Note 6—Goodwill and Intangible Liability
	Goodwill—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 commodity prices, projected demand for our services, rig availability and dayrates.  At December 31, 2014, the carrying amount of our goodwill was $356 million.
	During the three months ended December 31, 2014, we observed a rapid and significant decline in the market value of our stock, the market value of Transocean’s stock, prices of oil and natural gas and the actual and projected declines in dayrates and utilization, and we considered these indicators that the fair value of our goodwill could have fallen below its carrying amount, and as a result, we performed an interim goodwill impairment test.  Although we determined that our goodwill was not impaired as of December 31, 2014, we concluded that our reporting unit was at risk of failing the first step of our goodwill impairment test, as the reporting unit’s estimated fair value exceeded its carrying amount by less than 5 percent.  If the market value of our stock declines below its previous 52-week low or if we experience increasingly unfavorable changes to actual or anticipated market conditions, or to other impairment indicators, any of which may result in the fair value of our reporting unit falling below its carrying amount, we may be required to recognize losses on impairment of goodwill in the near future.
	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 commodity prices, projected demand for our services, rig availability and dayrates.  At December 31, 2013, the Predecessor’s goodwill was $213 million.
	Intangible liability—In connection with Transocean’s business combination with GlobalSantaFe Corporation in November 2007, Transocean acquired Development Driller III, which had a drilling contract that included fixed dayrates for future contract drilling services that were below the then-existing market dayrates available for similar contracts as of the date of the business combination.  Accordingly, Transocean recognized a contract intangible liability, representing the estimated fair value of the 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, 2014								Year ended December 31, 2013
		Gross		Accumulated			Net			Gross		Accumulated			Net
		carrying		amortization			carrying			carrying		amortization			carrying
		amount					amount			amount					amount
	Drilling contract intangible liabilities
	Balance, beginning of period	$	126	$	(82	)	$	44		$	126	$	(64	)	$	62
	Amortization	—		(15		)	(15		)	—		(18		)	(18		)
	Balance, end of period	$	126	$	(97	)	$	29		$	126	$	(82	)	$	44
	At December 31, 2014, the estimated future amortization of our drilling contract intangible liabilities was as follows (in millions):
		Drilling
		contract
		intangible
		liabilities
	Years ending December 31,
	2015	$	15
	2016	14
	Total intangible liabilities	$	29

Credit_Agreements

Credit Agreements	12 Months Ended
	Dec. 31, 2014
Credit Agreements
Credit Agreements
	Note 7—Credit Agreements
	Five-Year Revolving Credit Facility—On August 5, 2014, we entered into a credit agreement, which is scheduled to expire on August 5, 2019, with a Transocean affiliate to establish a committed $300 million five-year revolving credit facility that allows for uncommitted increases in amounts agreed to by the Transocean affiliate and us (the “Five-Year Revolving Credit Facility”).  We may borrow under the Five-Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate (“LIBOR”) plus a margin (the “revolving credit facility margin”), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined, or (2) the base rate specified in the credit agreement plus the revolving credit facility margin, less one percent per annum.  Throughout the term of the Five-Year Revolving Credit Facility, we are required to pay a commitment fee on the daily unused amount of the underlying commitment, which ranges from 0.225 percent to 0.325 percent based on our leverage ratio, as defined.  Among other things, the Five-Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets.  The Five-Year Revolving Credit Facility also includes a covenant imposing a maximum debt ratio, as defined in the credit agreement.  Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default.  At December 31, 2014, based on our leverage ratio on that date, the revolving credit facility margin was 1.625 percent.  At December 31, 2014, we had no borrowings outstanding and $300 million available borrowing capacity under the Five-Year Revolving Credit Facility.
	Working capital note payable 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 and for cash proceeds of $43 million that is due and payable at maturity on July 28, 2015.  The working capital note payable bears interest at the adjusted one-month LIBOR plus a margin (the “working capital note margin”), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined in the Five-Year Revolving Credit Facility.  The principal amount may be repaid early without penalty, and amounts repaid cannot be reborrowed.  At December 31, 2014, based on our leverage ratio on that date, the working capital note margin was 1.625 percent.
	The proceeds from the 364-day working capital note were used as partial consideration for contributed working capital in connection with the 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 contains a true-up mechanism whereby we will pay Transocean for the amount by which our pro rata share of actual net working capital, as determined within 60 days after the acquisition, exceeds our pro rata share of estimated net working capital at the time of the acquisition, and Transocean will pay us if such actual net working capital is less than such estimated net working capital.  At December 31, 2014, the outstanding principal amount under the working capital note payable was $43 million.  Subsequent to our formation, we determined that the working capital exceeded the original estimate by $4 million, and in the three months ended December 31, 2014, we made a cash payment in satisfaction of our obligation.
	Former credit agreements—In March 2014, we entered into credit agreements with a Transocean affiliate establishing three credit facilities with an aggregate borrowing capacity of $300 million that was scheduled to expire on March 31, 2017.  On August 5, 2014, we terminated the credit agreements.  No borrowings were outstanding under the credit facilities at the time of termination.

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies
Commitments and Contingencies
	Note 8—Commitments and Contingencies
	Purchase obligations—At December 31, 2014, the aggregate future payments required under our purchase obligations for equipment, which are due in the year ending December 31, 2015, were $23 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, 2014, our drilling units had the insured value of approximately $2.0 billion under this program.  We also have coverage for losses resulting from physical damage to our fleet caused by named windstorms in the U.S. Gulf of Mexico, including liability for wreck removal costs, through Transocean’s captive insurance program.  We do not maintain insurance coverage through Transocean or the commercial market for loss of revenues.
	Hull and machinery coverage—Our fleet is covered under Transocean’s hull and machinery insurance for physical damage, for which it allocated to us the respective premium costs.  In connection with this physical damage insurance coverage, we retained the risk for our per occurrence deductible of $10 million to $11 million.  Subject to the same deductible, we also had coverage for an amount equal to 50 percent of a rig’s insured value for combined costs incurred to mitigate rig damage, wreck or debris removal and collision liability.  For losses in excess to our per occurrence deductible of $10 million to $11 million, Transocean provides insurance coverage for physical damage to our fleet through its wholly owned captive insurance company up to its deductible amounts and through its commercial insurance program beyond such deductible amounts.  In connection with losses for any excess wreck removal costs, we are generally covered to the extent of Transocean’s remaining excess liability coverage.
	Excess liability coverage—Our fleet is covered under Transocean’s excess liability coverage insurance, for which it allocated to us the respective premium costs.  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 to our deductible amounts, Transocean provides the primary $50 million of excess liability coverage, through its wholly owned captive insurance company, and for the $700 million excess of the $50 million of coverage through its commercial market excess liability program, which generally covers offshore risks such as personal injury, third-party property claims, and third-party non-crew claims, including wreck removal and pollution.  We share the $750 million of captive and commercial market excess liability coverage with Transocean’s entire fleet.  We and Transocean generally retained the risk for any liability losses in excess of $750 million.
	Other insurance coverage—Our fleet is covered under Transocean’s marine package insurance program, and Transocean allocated to us the respective premium costs.  Under this insurance program, we have access to $100 million of additional insurance that generally covered expenses that would otherwise be assumed by the well owner, such as costs to control the well, redrill expenses and pollution from the well.  This additional insurance provided coverage for such expenses under circumstances in which we would have had legal or contractual liability arising from its gross negligence or willful misconduct.
	Guarantees, letters of credit and surety bonds—At December 31, 2014 and 2013, we had no guarantees, letters of credit or surety bonds issued or outstanding.
	Encumbered assets—Transocean had a $900 million three-year secured revolving credit facility established under a bank credit agreement dated October 25, 2012, that was scheduled to expire on October 25, 2015 (the “Transocean Three-Year Secured Revolving Credit Facility”).  Transocean’s borrowings under the Transocean Three-Year Secured Revolving Credit Facility were secured by three of its ultra-deepwater floaters, including its interests in the ultra-deepwater drillship Discoverer Inspiration.  At December 31, 2013, Transocean had no borrowings outstanding under the Transocean Three-Year Secured Revolving Credit Facility.  At December 31, 2013, the aggregate carrying amount of the ultra-deepwater drillship Discoverer Inspiration was $706 million.  On June 30, 2014, Transocean terminated the Transocean Three-Year Secured Revolving Credit Facility and the related security agreement with respect to the ultra-deepwater drillship Discoverer Inspiration.  At December 31, 2014, we had no assets subject to liens or other encumbrances.

Cash_Distributions

Cash Distributions	12 Months Ended
	Dec. 31, 2014
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)
			Total quarterly		Unitholders		Holders of
			distribution target amount (a)				incentive
							distribution rights
	Minimum quarterly distribution		$0.36		100	%	—
	First target distribution		Above $0.3625 up to $0.416875		100	%	—
	Second target distribution		Above $0.416875 up to $0.453125		85	%	15	%
	Third target distribution		Above $0.453125 up to $0.543750		75	%	25	%
	Thereafter		Above $0.543750		50	%	50	%
		(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.
	The Transocean Member holds 21.3 million common units and 27.6 million subordinated units, which collectively represents a 70.8 percent limited liability company interest, and all of our incentive distribution rights.
	Cash distribution to unitholders—On November 4, 2014, our board of directors approved a distribution of $0.2246 per unit to unitholders.  On November 24, 2014, we made an aggregate cash payment of $15 million to our unitholders of record as of November 17, 2014.  Of the $15 million distribution, we paid $5 million, $4 million and $6 million to our public common unitholders, our Transocean common unitholder and our Transocean subordinated unitholder, respectively.  See Note 17—Subsequent Events.

EquityBased_Compensation_Plan

Equity-Based Compensation Plan	12 Months Ended
	Dec. 31, 2014
Equity-Based Compensation Plan
Equity-Based Compensation Plan
	Note 10—Equity-Based Compensation Plan
	Effective August 5, 2014, we established a long-term incentive plan (the “Incentive Compensation Plan”) for executives, key employees and non-employee directors under which awards can be granted in the form of unit options, unit appreciation rights, restricted units, or deferred units.  Awards that may be granted under the Incentive Compensation Plan include time-vesting awards (“time-based awards”) and awards that are earned based on the achievement of certain performance criteria (“performance-based awards”) or market factors (“market-based awards”).  Our executive 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, 2014, we had no unit-based awards granted, and we had 3.4 million units authorized and available to be granted under the Incentive Compensation Plan.  See Note 17—Subsequent Events.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions
Related Party Transactions
	Note 11—Related Party Transactions
	Formation agreements
	Contribution agreement—On July 29, 2014, we entered into a 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 70.8 percent limited liability company interest in us, 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 appoint the majority of our board 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 executives, including our chief executive officer, rig crews and other personnel.  All persons provided to us pursuant to the secondment agreements will remain on the payroll and benefit plans of Transocean but will be under our day-to-day control and management.  We will 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 will 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.  Transocean will invoice us quarterly for amounts payable under the secondment agreements.  The secondment agreements may be terminated by Transocean or us upon 90 days written notice.  In the year ended December 31, 2014, we recognized costs of $38 million, recorded in operating and maintenance costs and expenses, and $2 million, recorded in general and administrative costs and expenses, for personnel costs under the secondment agreements.
	Support agreement—On August 5, 2014, we entered into a support agreement with certain Transocean affiliates to provide the services of certain administrative professionals, including our chief financial officer.  The persons providing such services to us pursuant to the support agreement will remain on Transocean’s payroll and will perform their services on or at Transocean’s facilities.  Transocean will be 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 will 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 year ended December 31, 2014, we recognized costs of less than $1 million, recorded in operating and maintenance costs and expenses, and 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 will provide certain administrative, technical and non-executive management services to us.  Transocean affiliates will also provide insurance coverage to us commensurate with that provided to the Predecessor.  The agreements have initial terms of five years.  Each month, we will 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 will 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 must reimburse Transocean at cost and is not required to pay a service fee, unless required by applicable transfer pricing rules.  Amounts payable under the master services agreements must be paid within 30 days after Transocean submits to us invoices for such fees, costs and expenses.  Each of the master services agreements may be terminated prior to the end of its term by either Transocean or us within 90 days written notice under certain circumstances.  In the year ended December 31, 2014, we recognized costs of $46 million, recorded in operating and maintenance costs and expenses, and $11 million, recorded in general and administrative costs and expenses, for services under the master services agreement.  In the year ended December 31, 2014, we acquired $13 million of materials and supplies purchased through the procurement services of Transocean Offshore Deepwater Drilling Inc. (“TODDI”).  In the year ended December 31, 2014, we recognized insurance costs of $5 million, recorded in operating and maintenance costs and expenses.
	Former master services agreement—Under the former master services agreement with TODDI, the Predecessor obtained services and assistance for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services.  In the years ended December 31, 2014, 2013 and 2012, the Predecessor recognized costs of $24 million, $35 million and $28 million, respectively, recorded in operating and maintenance costs and expenses, for such services and assistance.
	Under the former master services agreement, TODDI purchased materials and supplies for the Predecessor’s drilling operations through its procurement services.  In the years ended December 31, 2014, 2013 and 2012, the Predecessor paid $27 million, $38 million and $29 million, respectively, settled through its net investment, for materials and supplies purchased through TODDI’s procurement services.
	Also under the former master services agreement, TODDI administered insurance coverage with and processed claims through Transocean’s commercial market and captive insurance policies (see Note 8—Commitments and Contingencies).  In the years ended December 31, 2014, 2013 and 2012, the Predecessor recognized allocated insurance costs of $8 million, $13 million and $14 million, respectively, recorded in operating and maintenance costs and expenses.
	TODDI and its affiliates charged the Predecessor under the former master services agreement for crew personnel provided to the Predecessor to operate its drilling rigs.  In the years ended December 31, 2014, 2013 and 2012, the Predecessor recognized costs of $57 million, $91 million and $81 million, respectively, recorded in operating and maintenance costs and expenses, for such personnel costs.  In the years ended December 31, 2014, 2013 and 2012, the Predecessor recognized costs of $2 million, $9 million and $8 million, respectively, recorded in operating and maintenance costs and expenses, for the proportion of the benefit costs that covered the personnel supporting the Predecessor’s operations.
	Other agreements
	Omnibus agreement—On August 5, 2014, we entered into an omnibus agreement with Transocean and certain of its affiliates (the “Omnibus Agreement”).  Under the Omnibus Agreement, Transocean granted us a right of first offer for its remaining ownership interests in each of the RigCos should Transocean decide to sell such interests.  Transocean also will be required to offer us within five years of the effective date of the Omnibus Agreement, the opportunity to purchase, subject to requisite government and other third-party consents, not less than a 51 percent interest in any four of the following six ultra-deepwater drillships: Deepwater Invictus,  Deepwater Thalassa,  Deepwater Proteus,  Deepwater Pontus,  Deepwater Poseidon and Deepwater Conqueror.  The purchase price for each drillship will be equal to the greater of the fair market value, taking into account the anticipated cash flows under the associated drilling contracts, or the all-in construction cost, plus transaction costs.  Transocean will select which of these drillships it will offer to us, the timing of the offers and whether it will offer us the opportunity to purchase a greater than 51 percent interest in any offered drillship.  In addition, Transocean agreed not to acquire, own or operate any new drilling rig or contract for any drilling rig, in each case that was constructed in 2009 or later and is operating under a contract for five or more years (“Five-Year Drilling Rigs”), subject to certain exceptions, without offering us the opportunity to purchase such rig.  We also agreed not to acquire, own, operate, or contract for any drilling rig that is not a Five-Year Drilling Rig, subject to certain exceptions, without first offering the contract to Transocean.
	Transocean agreed to indemnify us for a period of five years through August 5, 2019 against certain environmental and human health and safety liabilities with respect to the assets contributed or sold to us to the extent arising prior to the time they were contributed or sold to us.  Liabilities resulting from a change in law after the closing of the offering are excluded from the environmental indemnity.  The indemnity coverage provided by Transocean for such environmental and human health and safety liabilities will not exceed the aggregate amount of $10 million.  No claim for indemnification may be made unless the aggregate dollar amount of all claims exceeds $500,000, in which case Transocean is liable for claims only to the extent such aggregate amount exceeds $500,000.
	In addition, Transocean agreed to indemnify us against any liabilities arising out of the Macondo well incident occurring prior to our initial public offering and any liabilities, other than taxes, arising from Transocean’s or its subsidiaries’ failure to comply with the Consent Decree or the EPA Agreement, each as it is defined in the Omnibus Agreement, or any similar decree or agreement.  The indemnity coverage provided by Transocean related to the Macondo well incident, the Consent Decree, the EPA Agreement or any similar decree or agreement is unlimited.  However, these indemnities do not cover or include any amount of consequential damages, including lost profits or revenues.
	Transocean also agreed to indemnify us to the full extent of any liabilities related to:
		·	certain defects in title to Transocean’s assets contributed or sold to the RigCos and any failure to obtain, prior to the time they were contributed, certain consents and permits necessary to conduct, own and operate such assets, which liabilities arise within three years after the closing of the offering;
		·	any judicial determination substantially to the effect that the Transocean affiliate that transferred any of our initial assets to us pursuant to the contribution agreement did not receive reasonably equivalent value in exchange therefor or was rendered insolvent by such transfer;
		·	tax liabilities attributable to the operation of the assets contributed or sold to the RigCos prior to the closing of the offering; and
		·	any lost revenue, up to $100 million, arising out of the failure to receive an operating dayrate from Chevron for Discoverer Clear Leader, for the period commencing on the closing date of the offering through the completion of the rig’s 2014 special periodic survey, which is expected to occur during the three months ending December 31, 2014.
	In the year ended December 31, 2014, we submitted indemnification claims for an aggregate amount of $19 million associated with lost revenues, and we recognized a receivable from affiliate with a corresponding entry to members’ equity.  In October 2014, we received from Transocean a cash payment of $9 million.  At December 31, 2014, the outstanding indemnification claim receivable was $10 million, recorded in receivables from affiliates.
	Dual-activity license agreements—All three of our drilling units are equipped with Transocean’s patented dual-activity technology.  Dual-activity technology employs structures, equipment and techniques using two drilling stations within a dual derrick to perform drilling tasks.  Dual-activity technology allows our rigs to perform simultaneous drilling tasks in a parallel rather than sequential manner and reduces critical path activity, improving efficiency in both exploration and development drilling.  The Predecessor entered into license agreements with TODDI for the use of the patented technology through the expiration of the patents in May 2016.  Under the license agreements, the Predecessor paid to TODDI an aggregate original license cost of $20 million, recorded in other assets.  In the years ended December 31, 2014, 2013 and 2012, we and the Predecessor recognized amortization of the license costs of $2 million, $3 million and $3 million, respectively, recorded in operating and maintenance costs and expenses.  At December 31, 2014 and 2013, the carrying amount of the deferred license cost was $4 million and $7 million, respectively.
	Also, under the license agreements, we are and the Predecessor was required to pay to TODDI quarterly patent royalty fees of between 3 percent and 5 percent of revenues.  Under the contribution agreement, Transocean retained the obligation for the payment of the quarterly patent royalty fees (see “—Formation agreements—Contribution agreement”).  In the years ended December 31, 2014, 2013 and 2012, we recognized patent royalty expense of $23 million, $19 million and $21 million, respectively, recorded in operating and maintenance costs and expenses.  Of the $23 million patent royalty expense recognized in the year ended December 31, 2014, we recognized a non-cash expense of $7 million with a corresponding entry to members’ equity, representing the fees paid by Transocean on our behalf with a corresponding entry to members’ equity.
	Credit agreements—In March 2014, we entered into credit agreements with TODDI, establishing three credit facilities with an aggregate borrowing capacity of $300 million, and effective as of August 5, 2014, we terminated these credit agreements.  On July 29, 2014, we entered into agreements with a Transocean affiliate to establish a working capital note payable in the principal amount and for cash proceeds of $43 million.  On August 5, 2014, we entered into the Five-Year Revolving Credit Facility with a Transocean affiliate.  See Note 7—Credit Agreements.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information
Supplemental Cash Flow Information
	Note 12—Supplemental Cash Flow Information
	Additional cash flow information was as follows (in millions):
			Years ended December 31,
			2014			2013		2012
	Certain cash operating activities
	Cash payments for income taxes		$	—		$	6	$	1
	Non-cash investing and financing activities
	Capital additions, accrued at end of period (a)		$	6		$	1	$	—
	Property and equipment transferred to the Predecessor from affiliates (b)		10			1		21
	Property and equipment transferred from the Predecessor to affiliates (c)		(23		)	—		—
	Contribution for parent payment of dual-activity patent royalties (d)		7			—		—
	Contribution for parent indemnification of lost revenues (e)		10			—		—
		(a)		These amounts represent additions to property and equipment for which we had accrued a corresponding liability at the end of the period.
		(b)		In the years ended December 31, 2014, 2013 and 2012, Transocean transferred to the Predecessor certain equipment, primarily all of which was to Development Driller III, and the Predecessor recorded the non-cash investing activity with a corresponding entry 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 entry to its net investment.
		(d)		In the year ended December 31, 2014, in connection with Transocean’s payment of $7 million of royalty fees under our dual-activity license agreements with a Transocean affiliate, we recognized non-cash operating expense with a corresponding increase to members’ equity.
		(e)		In the year ended December 31, 2014, we submitted indemnification claims associated with lost revenues for an aggregate amount of $19 million, representing a capital contribution recognized in 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, 2014
Financial Instruments
Financial Instruments
	Note 13—Financial Instruments
	The carrying amounts and fair values of our financial instruments were as follows:
		December 31, 2014				December 31, 2013
		Carrying		Fair		Carrying		Fair
		amount		value		amount		value
	Cash and cash equivalents	$	86	$	86	$	—	$	—
	Working capital note payable to affiliate	43		43		—		—
	We estimated the fair value of each class of financial instruments, for which estimating fair value is practicable, by applying the following methods and assumptions:
	Cash and cash equivalents—The carrying amount of cash and cash equivalents represents the historical cost, plus accrued interest, which approximates fair value because of the short maturities of those investments.  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, 2014, the aggregate carrying amount of our cash equivalents was $40 million.
	Working capital note payable to affiliate—The carrying amount of the working capital note payable approximates fair value due to the short term nature of the instrument.  We measured the estimated fair value of our working capital note payable using significant unobservable inputs, representative of a Level 3, fair value measurement, including the credit spreads that would be considered at market for a borrower with our credit ratings.

Risk_Concentration

Risk Concentration	12 Months Ended
	Dec. 31, 2014
Risk Concentration
Risk Concentration
	Note 14—Risk Concentration
	Credit risk—Financial instruments that potentially subject us to concentrations of credit risk are primarily trade receivables.  We derive all of our revenues from 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, 2014
Operating Segments, Geographic Analysis and Major Customers
Operating Segments, Geographic Analysis and Major Customers
	Note 15—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, 2014, 2013 and 2012, we earned 100 percent of our consolidated operating revenues in the U.S. Gulf of Mexico.  At December 31, 2014 and 2013, 100 percent of our assets were in the U.S. Gulf of Mexico.
	Major customers—For the year ended December 31, 2014, Chevron Corporation and BP plc accounted for approximately 67 percent and 33 percent, respectively, of our consolidated operating revenues.  For the year ended December 31, 2013, Chevron Corporation and BP plc accounted for approximately 67 percent and 33 percent, respectively, of our combined operating revenues.  For the year ended December 31, 2012, Chevron Corporation and BP plc accounted for approximately 68 percent and 32 percent, respectively, of our combined operating revenues.

Quarterly_Results_unaudited

Quarterly Results (unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Results (unaudited)
Quarterly Results (unaudited)
	Note 16—Quarterly Results (unaudited)
	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 respective period through August 4, 2014.  Our consolidated statements of operations for the year ended December 31, 2013 consist entirely of the combined results of operations of the Predecessor.  See Note 2—Significant Accounting Policies-Presentation.
			Three months ended
			March 31,			June 30,			September 30,		December 31,
			(In millions, except per share data)
	2014
	Operating revenues		$	148		$	145		$	136	$	138
	Operating income		69			55			60		49
	Net income		63			50			57		45
	Net income attributable to controlling interest		(a		)	(a		)	17		19
	Per unit earnings - basic and diluted
	Common units		$	(a	)	$	(a	)	$	0.24	$	0.28
	Subordinated units		$	(a	)	$	(a	)	$	0.24	$	0.28
	Weighted-average units outstanding
	Common units		(a		)	(a		)	41		41
	Subordinated units		(a		)	(a		)	28		28
	2013
	Operating revenues		$	116		$	133		$	147	$	130
	Operating income		40			52			67		49
	Net income		36			47			60		46
		(a)		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, 2014
Subsequent Events.
Subsequent Events
	Note 17—Subsequent Events
	Distribution to unitholders—On February 9, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders.  We expect to pay the aggregate cash distribution of $25 million on February 26, 2015 to unitholders of record as of February 20, 2015, including an aggregate cash payment of $18 million to the Transocean unitholder.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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 the 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, 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 statements of operations for the years ended December 31, 2013 and 2012 consist entirely of the combined results of operations of the Predecessor.
		·	Our consolidated balance sheet at December 31, 2014 consists of the consolidated balances of Transocean Partners.  Our consolidated balance sheet at December 31, 2013 consists of the combined balances of the Predecessor.
		·	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 statements of equity for the years ended December 31, 2013 and 2012 consist entirely of the combined activity of the Predecessor.
		·	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 statements of cash flows for the years ended December 31, 2013 and 2012 consist 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 materials and supplies obsolescence, property and equipment, goodwill and drilling contract intangible liability, income taxes, allocated costs and related party transactions.  We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources.  Actual results could differ from such estimates.
Fair value measurements
	Fair value measurements—We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.  Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) significant observable inputs, including unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) significant other observable inputs, including direct or indirect market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) significant unobservable inputs, including those that require considerable judgment for which there is little or no market data (“Level 3”).  When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.
Consolidation
	Consolidation—We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes.  We eliminate intercompany transactions and accounts in consolidation.  We apply the equity method of accounting for an investment in an entity if we have the ability to exercise significant influence over the entity that (a) does not meet the variable interest entity criteria or (b) meets the variable interest entity criteria, but for which we are not deemed to be the primary beneficiary.  We apply the cost method of accounting for an investment in an entity if we do not have the ability to exercise significant influence over the unconsolidated entity.  We separately present within equity on our 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 11—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 year ended December 31, 2014, costs and expenses allocated to us by Transocean were $19 million (see Note 11—Related Party Transactions).
	The combined results of operations for the Predecessor include allocated indirect and overhead costs for certain functions historically performed by Transocean and not previously allocated to the Predecessor Business, including allocations of indirect operating and maintenance costs and expenses for onshore operational support services such as engineering, procurement and logistics and general and administrative costs and expenses related to executive oversight, accounting, treasury, tax, legal, and information technology.  We have applied these allocations based on relative values of net property and equipment and operating and maintenance costs and expenses.  We believe the assumptions underlying the consolidated financial statements, including the assumptions regarding allocation of costs from Transocean, are reasonable.  Nevertheless, the combined results of operations of the Predecessor do not include all of the costs that the Predecessor would have incurred had it been a stand-alone company during the periods presented and may not reflect the combined results of operations, financial position and cash flows had the Predecessor been a stand-alone company during the periods presented.  In the years ended December 31, 2014, 2013 and 2012, the Predecessor recognized such allocated operating and maintenance costs of $14 million, $28 million and $22 million, respectively, including $11 million, $21 million and $17 million, respectively, for personnel costs.  In the years ended December 31, 2014, 2013 and 2012, we recognized such allocated general and administrative costs of $6 million, $10 million and $9 million, respectively, including $4 million, $6 million and $6 million, respectively, for personnel costs.
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 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 4—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 5—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 derive a majority of our revenues from 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, 2014 and 2013, 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, 2014 and 2013, the aggregate face value of our long-term accounts receivable was $24 million and $50 million, respectively.  At December 31, 2014, the aggregate carrying amount of our long-term accounts receivable was $22 million, including $12 million and $10 million, recorded in accounts receivable and other assets, respectively.  At December 31, 2013, the aggregate carrying amount of our long-term accounts receivable was $45 million, including $23 million and $22 million, respectively, recorded in accounts receivable and other assets, respectively.  At December 31, 2014 and 2013, our long-term accounts receivable had weighted average effective interest rates of 11 percent and 10 percent, respectively.
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, 2014 and 2013, the allowance for obsolescence was $3 million and $2 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, 2014, the aggregate carrying amount of our property and equipment represented approximately 75 percent of our total assets.
	We compute depreciation using the straight-line method after allowing for salvage values.  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.
	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—We conduct impairment testing for our goodwill annually as of October 1 and more frequently, on an interim basis, when an event occurs or circumstances change that indicate that the fair value of a reporting unit may have declined below its carrying value.  We test 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 have determined that we have a single reporting unit for this purpose.  Before testing goodwill, we consider whether or not to first assess qualitative factors to determine whether the existence of events or circumstances lead to a determination that it is more likely than not that the fair value of a reporting unit is less than its carrying amount and whether the two-step impairment test is required.  If, as the result of our qualitative assessment, we determine that the two-step impairment test is required, or, alternatively, if we elect to forgo the qualitative assessment, we test goodwill for impairment by comparing the carrying amount of the reporting unit, including goodwill, to the fair value of the reporting unit.
	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 years ended December 31, 2014 and 2013, as a result of our annual impairment testing, we concluded that our goodwill was not impaired.
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, 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 17—Subsequent Events.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013		2012
	Current tax expense	$	2		$	8	$	3
	Deferred tax expense	18			15		21
	Income tax expense	$	20		$	23	$	24
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 for us in the year ended December 31, 2014 or (b) the Swiss holding company federal statutory rate of 7.83 percent for the Predecessor in the years ended December 31, 2013 and 2012 and the reported provision for income taxes (in millions):
		Years ended December 31,
		2014			2013		2012
	Income tax expense at the respective federal statutory rate	$	—		$	17	$	22
	Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate	15			4		—
	Changes in unrecognized tax benefits, net	3			2		2
	Changes in valuation allowance	2			—		—
	Income tax expense	$	20		$	23	$	24
Schedule of deferred income taxes	The significant components of our deferred tax assets were as follows (in millions):
		December 31,
		2014			2013
	Deferred tax assets
	Net operating loss carryforwards	$	2		$	—
	Deferred revenues and drilling contract intangible	12			39
	Valuation allowance	(2		)	—
	Other	3			5
	Total deferred tax assets	15			44
	Deferred tax liabilities
	Total deferred tax liabilities	—			—
	Net deferred tax assets	$	15		$	44
Schedule of valuation allowance	The valuation allowance for our non-current deferred tax assets was as follows (in millions):
		December 31,
		2014			2013
	Valuation allowance for non-current deferred tax assets	$	2		$	—
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,
		2014			2013		2012
	Balance, beginning of period	$	12		$	11	$	9
	Additions for current year tax positions	1			1		4
	Reductions for prior year tax positions	(12		)	—		—
	Settlements	—			—		(2		)
	Balance, end of period	$	1		$	12	$	11
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,
		2014			2013
	Unrecognized tax benefits, excluding interest and penalties	$	1		$	12
	Interest and penalties	—			1
	Unrecognized tax benefits, including interest and penalties	$	1		$	13

Earnings_per_unit_Tables

Earnings per unit (Tables)	12 Months Ended
	Dec. 31, 2014
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 share data):
		Years ended December 31,
		2014		2013		2012
	Numerator for earnings per unit
	Net income attributable to controlling interest	$	36	$	—	$	—
	Net income available to common unitholders	$	22	$	—	$	—
	Net income available to subordinated unitholders	$	14	$	—	$	—
	Denominator for earnings per unit
	Weighted-average common units outstanding	41		—		—
	Weighted-average subordinated units outstanding	28		—		—
	Earnings per unit
	Earnings per common unit	$	0.52	$	—	$	—
	Earnings per subordinated unit	$	0.52	$	—	$	—
	Cash distributions declared and paid per unit
	Common units	$	0.2246	$	—	$	—
	Subordinated units	$	0.2246	$	—	$	—

Goodwill_and_Intangible_Liabil1

Goodwill and Intangible Liability (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014								Year ended December 31, 2013
		Gross		Accumulated			Net			Gross		Accumulated			Net
		carrying		amortization			carrying			carrying		amortization			carrying
		amount					amount			amount					amount
	Drilling contract intangible liabilities
	Balance, beginning of period	$	126	$	(82	)	$	44		$	126	$	(64	)	$	62
	Amortization	—		(15		)	(15		)	—		(18		)	(18		)
	Balance, end of period	$	126	$	(97	)	$	29		$	126	$	(82	)	$	44
Schedule of estimated future amortization of drilling contract intangible liabilities	At December 31, 2014, the estimated future amortization of our drilling contract intangible liabilities was as follows (in millions):
		Drilling
		contract
		intangible
		liabilities
	Years ending December 31,
	2015	$	15
	2016	14
	Total intangible liabilities	$	29

Cash_Distributions1

Cash Distributions	12 Months Ended
	Dec. 31, 2014
Cash Distributions.
Schedule of percentage interests
					Marginal percentage
					interest in distributions (a)
			Total quarterly		Unitholders		Holders of
			distribution target amount (a)				incentive
							distribution rights
	Minimum quarterly distribution		$0.36		100	%	—
	First target distribution		Above $0.3625 up to $0.416875		100	%	—
	Second target distribution		Above $0.416875 up to $0.453125		85	%	15	%
	Third target distribution		Above $0.453125 up to $0.543750		75	%	25	%
	Thereafter		Above $0.543750		50	%	50	%
		(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_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information
Schedule of additional cash flow information	Additional cash flow information was as follows (in millions):
			Years ended December 31,
			2014			2013		2012
	Certain cash operating activities
	Cash payments for income taxes		$	—		$	6	$	1
	Non-cash investing and financing activities
	Capital additions, accrued at end of period (a)		$	6		$	1	$	—
	Property and equipment transferred to the Predecessor from affiliates (b)		10			1		21
	Property and equipment transferred from the Predecessor to affiliates (c)		(23		)	—		—
	Contribution for parent payment of dual-activity patent royalties (d)		7			—		—
	Contribution for parent indemnification of lost revenues (e)		10			—		—
		(a)		These amounts represent additions to property and equipment for which we had accrued a corresponding liability at the end of the period.
		(b)		In the years ended December 31, 2014, 2013 and 2012, Transocean transferred to the Predecessor certain equipment, primarily all of which was to Development Driller III, and the Predecessor recorded the non-cash investing activity with a corresponding entry 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 entry to its net investment.
		(d)		In the year ended December 31, 2014, in connection with Transocean’s payment of $7 million of royalty fees under our dual-activity license agreements with a Transocean affiliate, we recognized non-cash operating expense with a corresponding increase to members’ equity.
		(e)		In the year ended December 31, 2014, we submitted indemnification claims associated with lost revenues for an aggregate amount of $19 million, representing a capital contribution recognized in 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, 2014
Financial Instruments
Schedule of carrying amounts and fair values of our financial instruments
		December 31, 2014				December 31, 2013
		Carrying		Fair		Carrying		Fair
		amount		value		amount		value
	Cash and cash equivalents	$	86	$	86	$	—	$	—
	Working capital note payable to affiliate	43		43		—		—

Quarterly_Results_unaudited_Ta

Quarterly Results (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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)
	2014
	Operating revenues		$	148		$	145		$	136	$	138
	Operating income		69			55			60		49
	Net income		63			50			57		45
	Net income attributable to controlling interest		(a		)	(a		)	17		19
	Per unit earnings - basic and diluted
	Common units		$	(a	)	$	(a	)	$	0.24	$	0.28
	Subordinated units		$	(a	)	$	(a	)	$	0.24	$	0.28
	Weighted-average units outstanding
	Common units		(a		)	(a		)	41		41
	Subordinated units		(a		)	(a		)	28		28
	2013
	Operating revenues		$	116		$	133		$	147	$	130
	Operating income		40			52			67		49
	Net income		36			47			60		46
		(a)		Amounts associated with the Predecessor period, and, therefore, not applicable.  See Note 2—Significant Accounting Policies.

Nature_of_Business_Details

Nature of Business (Details) (USD $)	0 Months Ended
In Millions, except Per Share data, unless otherwise specified	Aug. 05, 2014	Jul. 31, 2014	Jul. 29, 2014
Offer price of common units (in dollars per share)		$22
Transocean
Common units offered in initial public offering	20.1
Common units purchased by underwriters upon exercise of option	2.6
Percentage of common units sold in public offering and purchased by underwriters	29.20%
Common units held by parent	21.3
Subordinated units held by parent	27.6
Percentage of limited liability company interest held by parent	70.80%
Net cash proceeds from offering	$417
Underwriting discounts, commissions and other offering costs	$26
Rig Cos and subsidiaries
Ownership percentage			51.00%
Rig Cos and subsidiaries | Transocean
Ownership percentage			49.00%
Predecessor Business
Percentage of the combined results of operations, assets and liabilities of the Predecessor Business, included in the condensed combined financial statements of the Predecessor	100.00%

Significant_Accounting_Policie2

Significant Accounting Policies (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounts receivable
Allowance for doubtful accounts	$0
Face value of long term accounts receivable	24
Aggregate carrying amount of long term accounts receivable	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	3
Property and equipment
Property and equipment as a percentage of total assets	75.00%
Estimated original useful lives	35 years
Accounts receivable
Accounts receivable
Aggregate carrying amount of long-term accounts receivable	12	23
Other assets
Accounts receivable
Aggregate carrying amount of long-term accounts receivable	10	22
Predecessor Business
Accounts receivable
Allowance for doubtful accounts		0
Face value of long term accounts receivable		50
Aggregate carrying amount of long term accounts receivable		45
Weighted average effective interest rates of long term accounts receivable (as a percent)		10.00%
Materials and supplies
Allowance for obsolescence on materials and supplies		2
Predecessor Business | Transocean
Allocated indirect and overhead costs
Allocated costs and expenses	19
Allocated operating and maintenance costs	14	28	22
Allocated personnel costs included in operating and maintenance costs	11	21	17
Allocated general and administrative costs	6	10	9
Allocated personnel costs included in general and administrative costs	$4	$6	$6

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Components of provision (benefit) for income taxes
Current tax expense		$2
Deferred tax expense		18
Income tax expense		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%
Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate		15
Changes in unrecognized tax benefits, net		3
Changes in valuation allowance		2
Income tax expense		20
Deferred tax assets
Net operating loss carryforwards	2	2
Deferred revenues and drilling contract intangible	12	12
Valuation allowance	-2	-2
Other	3	3
Total deferred tax assets	15	15
Net deferred tax assets	15	15
Deferred tax asset adjustment related to drilling contract intangible related to the remeasurement and contribution of such deferred tax asset in connection with formation	11
Reconciliation of unrecognized tax benefits, excluding interest and penalties
Balance, beginning of period		12
Additions for current year tax positions		1
Reductions for prior year tax positions		-12
Balance, end of period	1	1
Unrecognized tax benefits
Unrecognized tax benefits, excluding interest and penalties	1	1
Unrecognized tax benefits, including interest and penalties	1	1
Unrecognized tax benefits would favorably impact the effective tax rate	1	1
Non-current deferred tax assets
Deferred tax assets
Valuation allowance	-2	-2
Predecessor Business
Components of provision (benefit) for income taxes
Current tax expense			8	3
Deferred tax expense			15	21
Income tax expense			23	24
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%	7.83%
Income tax expense at the respective federal statutory rate			17	22
Taxes on earnings subject to rates different than the Marshall Islands federal statutory rate			4
Changes in unrecognized tax benefits, net			2	2
Income tax expense			23	24
Deferred tax assets
Deferred revenues and drilling contract intangible			39
Other			5
Total deferred tax assets			44
Net deferred tax assets			44
Reconciliation of unrecognized tax benefits, excluding interest and penalties
Balance, beginning of period			11	9
Additions for current year tax positions			1	4
Settlements				-2
Balance, end of period			12	11
Unrecognized tax benefits
Unrecognized tax benefits, excluding interest and penalties			12
Interest and penalties			1
Unrecognized tax benefits, including interest and penalties			13
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 $)	0 Months Ended	3 Months Ended		12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Nov. 04, 2014	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014
Numerator for earnings per unit
Net income attributable to controlling interest		$19	$17	$36
Net income available to common unitholders				22
Net income available to subordinated unitholders				14
Cash distributions declared and paid per unit
Distribution (in dollars per share)	$0.22
Common units
Numerator for earnings per unit
Net income attributable to controlling interest				22
Denominator for earnings per unit
Weighted average units outstanding (in units)		41	41	41
Earnings per unit
Earnings per unit (in dollars per unit)		$0.28	$0.24	$0.52
Cash distributions declared and paid per unit
Distribution (in dollars per share)				$0.22
Subordinated units
Numerator for earnings per unit
Net income attributable to controlling interest				$14
Denominator for earnings per unit
Weighted average units outstanding (in units)		28	28	28
Earnings per unit
Earnings per unit (in dollars per unit)		$0.28	$0.24	$0.52
Cash distributions declared and paid per unit
Distribution (in dollars per share)				$0.22

Goodwill_and_Intangible_Liabil2

Goodwill and Intangible Liability (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Aug. 05, 2014	Jan. 01, 2012
In Millions, unless otherwise specified
Goodwill
Goodwill	$356
Predecessor Business
Goodwill
Goodwill		213
Transocean
Goodwill
Allocated goodwill			356
Transocean | Predecessor Business
Goodwill
Allocated goodwill				$213

Goodwill_and_Intangible_Liabil3

Goodwill and Intangible Liability (Details 2) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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
Accumulated amortization at the end of the period	-97	-82
Changes in net carrying amount of definite-lived intangible liabilities
Net carrying amount at the beginning of the year	29	44
Amortization	-15
Net carrying amount at the end of the year	29	44
Predecessor Business
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		-82	-64
Amortization		-18
Accumulated amortization at the end of the period		-82	-64
Changes in net carrying amount of definite-lived intangible liabilities
Net carrying amount at the beginning of the year		44	62
Amortization		-18
Net carrying amount at the end of the year		$44	$62

Goodwill_and_Intangible_Liabil4

Goodwill and Intangible Liability (Details 3) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Future amortization of our intangible liabilities
2015	$15
2016	14
Total intangible liabilities	29	44
Predecessor Business
Future amortization of our intangible liabilities
Total intangible liabilities		$44	$62

Credit_Agreements_Details

Credit Agreements (Details) (USD $)	0 Months Ended			1 Months Ended
In Millions, unless otherwise specified	Jul. 29, 2014	Dec. 31, 2014	Aug. 05, 2014	Mar. 31, 2014
				item
Credit Agreements
Accounts payable to affiliates		$76
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)		1.63%
Credit facility amount outstanding		0
Available borrowing capacity		300
Five Year Revolving Credit Facility | Minimum
Credit Agreements
Percentage of commitment fees			0.23%
Five Year Revolving Credit Facility | Maximum
Credit Agreements
Percentage of commitment fees			0.33%
Five Year Revolving Credit Facility | LIBOR | Minimum
Credit Agreements
Basis spread on variable rate (as a percent)			1.63%
Five Year Revolving Credit Facility | LIBOR | Maximum
Credit Agreements
Basis spread on variable rate (as a percent)			2.25%
Five Year Revolving Credit Facility | Base rate
Credit Agreements
Percentage reduction to the calculated variable rate			1.00%
Working capital notes payable
Credit Agreements
Credit facility term	364 days
Face amount of debt	43
Outstanding principal amount		43
Accounts payable to affiliates		4
Working capital notes payable | LIBOR
Credit Agreements
Basis spread on variable rate (as a percent)		1.63%
Working capital notes payable | LIBOR | Minimum
Credit Agreements
Basis spread on variable rate (as a percent)	1.63%
Working capital notes payable | LIBOR | Maximum
Credit Agreements
Basis spread on variable rate (as a percent)	2.25%
TODDI | Credit facilities
Credit Agreements
Aggregate borrowing capacity				300
Credit facility amount outstanding			$0
Number of credit facilities				3

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	12 Months Ended	0 Months Ended
	Dec. 31, 2014	Oct. 25, 2012	Dec. 31, 2013
		item
Commitments and Contingencies
Future payments required under our purchase obligations	$23,000,000
Guarantees outstanding	0
Letters of credit outstanding	0
Surety bonds outstanding	0
Retained risk
Commitments and Contingencies
Aggregate insured value of drilling rig fleet	2,000,000,000
Retained risk | Transocean
Commitments and Contingencies
Maximum percentage of asset insured value covered by damage mitigation insurance	50.00%
Commercial market excess liability coverage	700,000,000
Per occurrence deductible on excess liability for which risk is retained by wholly-owned insurance company	50,000,000
Per occurrence deductible on collision liability claims	10,000,000
Per occurrence deductible on crew personal injury and other third-party non-crew claims	5,000,000
Liability loss excess amount for commercial market excess liability coverage	750,000,000
Additional insurance that covers expenses that would otherwise be assumed by the well owner	100,000,000
Predecessor Business
Commitments and Contingencies
Aggregate carrying amount assets pledged			706,000,000
Predecessor Business | Transocean | Transocean Three-Year Secured Revolving Credit Facility
Commitments and Contingencies
Borrowing capacity, maximum		900,000,000
Credit facility term		3 years
Number of assets held as collateral		3
Credit facility amount outstanding			0
Minimum | Retained risk
Commitments and Contingencies
Per occurrence insurance deductible on hull and machinery	10,000,000
Maximum | Retained risk
Commitments and Contingencies
Per occurrence insurance deductible on hull and machinery	$11,000,000

Cash_Distributions_Details

Cash Distributions (Details) (USD $)	0 Months Ended		12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Nov. 24, 2014	Nov. 04, 2014	Dec. 31, 2014
Minimum quarterly distribution (in dollars per share)			$0.36
Minimum quarterly distribution annualized (in dollars pers share)			$1.45
Distribution (in dollars per share)		$0.22
Distribution to unitholders	$15		$15
First
Percentage of distribution of the quarterly distribution			100
Second
Percentage of distribution of the quarterly distribution			100
Third
Percentage of distribution of the quarterly distribution			100
Transocean
Percentage of interest holding			70.80%
Minimum quarterly distribution
Minimum quarterly distribution (in dollars per share)			$0.36
First target distribution
Quarterly distribution target amount (in dollars pers share)			$0.36
Maximum quarterly distribution target amount (in dollars pers share)			$0.42
Second target distribution
Quarterly distribution target amount (in dollars pers share)			$0.42
Maximum quarterly distribution target amount (in dollars pers share)			$0.45
Third target distribution
Quarterly distribution target amount (in dollars pers share)			$0.45
Maximum quarterly distribution target amount (in dollars pers share)			$0.54
Thereafter
Quarterly distribution target amount (in dollars pers share)			$0.54
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
Distribution to unitholders	4
Subordinated units | Transocean
Unit holds			27.6
Distribution to unitholders	6
Public common unitholders
Distribution to unitholders	$5

UnitBased_Compensation_Plan_De

Unit-Based Compensation Plan (Details) (Incentive Compensation Plan)	Dec. 31, 2014
Incentive Compensation Plan
Unit-Based Compensation Plan
Unit-based awards granted as of reporting date	0
Numbers of units authorized	3.4
Number of units available to be granted	3.4

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended	0 Months Ended		1 Months Ended		12 Months Ended
	Dec. 31, 2014	Aug. 05, 2014	Jul. 29, 2014	Mar. 31, 2014	Oct. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	item			item
	director
Related Party Transactions
Number of members of board of directors	7
Percentage of ownership to request cumulative voting	50.00%
Indemnification claim for lost revenues	$10,000,000
Proceeds from affiliates for indemnification	9,000,000
Accounts receivable from affiliates	28,000,000
Number of drilling units equipped with patented dual activity technology	3
Number of drilling stations to employ structures, equipment and techniques of dual-activity technology	2
Five Year Revolving Credit Facility
Related Party Transactions
Aggregate borrowing capacity		300,000,000
Credit facility term		5 years
Working capital notes payable
Related Party Transactions
Face amount of debt			43,000,000
Credit facility term			364 days
Secondment agreements
Related Party Transactions
Notice period for termination of agreement		90 days
Secondment agreements | General and administrative costs and expenses | Maximum
Related Party Transactions
Operating and maintenance costs and expenses	2,000,000
Support agreement | Operating and maintenance costs and expenses | Maximum
Related Party Transactions
Operating and maintenance costs and expenses	1,000,000
Support agreement | General and administrative costs and expenses | Maximum
Related Party Transactions
Operating and maintenance costs and expenses	1,000,000
Master services agreements
Related Party Transactions
Notice period for termination of agreement		90 days
Term of agreement		5 years
Percentage of costs and expenses incurred in connection with provision of services considered for payment of fees		5.00%
Percentage markup on costs incurred in connection with capital spare or inventory considered for payment of fees		4.00%
Percentage markup of allocable share of costs in connection with provision of services for capital spares or inventory added for payment of fees		4.00%
Period for payment of fees after receipt of invoice		30 days
Omnibus Agreement
Related Party Transactions
Period after effective date of agreement for purchase of interest in drillship		5 years
Minimum percentage of interest to be offered for purchase of drillships		51.00%
Number of ultra deepwater drillships in which interest is required to be offered		4
Number of ultra deepwater drillships available for offer to purchase interest		6
Services for certain activities, including accounting, legal, finance, marketing, tax, treasury, insurance, global procurement and technical services | Master services agreements | Operating and maintenance costs and expenses
Related Party Transactions
Operating and maintenance costs and expenses	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	11,000,000
Personnel costs | Secondment agreements | Operating and maintenance costs and expenses
Related Party Transactions
Operating and maintenance costs and expenses	38,000,000
TODDI | Payment for materials and supplies settled through net investment | Master services agreements
Related Party Transactions
Operating and maintenance costs and expenses	13,000,000
TODDI | Insurance costs allocated to drilling rigs | Operating and maintenance costs and expenses
Related Party Transactions
Operating and maintenance costs and expenses	5,000,000
TODDI | License agreements
Related Party Transactions
Deferred license cost	4,000,000
TODDI | Royalty fees
Related Party Transactions
Non-cash expense with a corresponding entry to members' equity	7,000,000
TODDI | Credit facilities
Related Party Transactions
Number of credit facilities				3
Aggregate borrowing capacity				300,000,000
Transocean
Related Party Transactions
Percentage of limited liability company interest held by parent		70.80%
Indemnification claim for lost revenues	19,000,000
Proceeds from affiliates for indemnification					9,000,000
Accounts receivable from affiliates	10,000,000
Transocean | Omnibus Agreement
Related Party Transactions
Period of indemnification		5 years
Maximum amount of lost revenue arising out of the failure to receive an operating dayrate from Chevron for Discoverer Clear Leader		100,000,000
Transocean | Omnibus Agreement | Minimum
Related Party Transactions
Aggregate amount of indemnification for which Transocean is liable for claims		500,000
Transocean | Omnibus Agreement | Maximum
Related Party Transactions
Aggregate amount of indemnity coverage provided by Transocean for such environmental and human health and safety liabilities		10,000,000
Transocean affiliate | Five Year Revolving Credit Facility
Related Party Transactions
Credit facility term		5 years
Transocean affiliate | Working capital notes payable
Related Party Transactions
Face amount of debt			43,000,000
Transocean
Related Party Transactions
Percentage of limited liability company interest held by parent	70.80%
Number of Members of board of directors Transocean can appoint	3
Minimum number of directors that Transocean can appoint after electing cumulative voting.	1
Percentage of ownership that would enable Transocean to appoint majority of the board of directors	20.00%
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	24,000,000					35,000,000	28,000,000
Predecessor Business | TODDI | Payment for materials and supplies settled through net investment
Related Party Transactions
Operating and maintenance costs and expenses	27,000,000					38,000,000	29,000,000
Predecessor Business | TODDI | Insurance costs allocated to drilling rigs | Operating and maintenance costs and expenses
Related Party Transactions
Operating and maintenance costs and expenses	8,000,000					13,000,000	14,000,000
Predecessor Business | TODDI | Personnel costs | Operating and maintenance costs and expenses
Related Party Transactions
Operating and maintenance costs and expenses	57,000,000					91,000,000	81,000,000
Predecessor Business | TODDI | Personnel benefit costs | Operating and maintenance costs and expenses
Related Party Transactions
Operating and maintenance costs and expenses	2,000,000					9,000,000	8,000,000
Predecessor Business | TODDI | License agreements
Related Party Transactions
Original license cost	20,000,000
Deferred license cost						7,000,000
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 | License agreements | Operating and maintenance costs and expenses
Related Party Transactions
Amortized license cost	2,000,000					3,000,000	3,000,000
Predecessor Business | TODDI | Royalty fees
Related Party Transactions
Operating and maintenance costs and expenses	$23,000,000					$19,000,000	$21,000,000

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Certain cash operating activities
Capital additions, accrued at end of period	$6
Contribution for parent payment of dual-activity patent royalties	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	1
Capital additions, accrued at end of period		1
Property and equipment transferred to the Predecessor from affiliates	10	1	21
Property and equipment transferred from the Predecessor to affiliates	-23
Aggregate value of drilling unit equipment transferred to parent	$23

Financial_Instruments_Details

Financial Instruments (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Financial Instruments
Carrying amount of cash equivalents	$40
Carrying amount
Financial Instruments
Cash and cash equivalents	86
Working capital note payable to affiliate	43
Fair value
Financial Instruments
Cash and cash equivalents	86
Working capital note payable to affiliate	$43

Operating_Segments_Geographic_1

Operating Segments, Geographic Analysis and Major Customers (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating revenue | Customer concentration | Chevron Corporation
Operating Segments, Geographic Analysis and Major Customers
Percentage of concentration	67.00%
Operating revenue | Customer concentration | BP plc
Operating Segments, Geographic Analysis and Major Customers
Percentage of concentration	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%
Predecessor Business | Operating revenue | Customer concentration | Chevron Corporation
Operating Segments, Geographic Analysis and Major Customers
Percentage of concentration		67.00%	68.00%
Predecessor Business | Operating revenue | Customer concentration | BP plc
Operating Segments, Geographic Analysis and Major Customers
Percentage of concentration		33.00%	32.00%

Quarterly_Results_unaudited_De

Quarterly Results (unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014
Operating revenues	$138	$136	$145	$148	$130	$147	$133	$116	$567
Operating income	49	60	55	69	49	67	52	40	233
Net income	45	57	50	63	46	60	47	36	215
Net income attributable to controlling interest	19	17							36
Common units
Net income attributable to controlling interest									22
Earnings per unit - basic and diluted
Earnings per unit - basic and diluted (in dollars per share)	$0.28	$0.24							$0.52
Weighted-average units outstanding
Weighted-average units outstanding (in shares)	41	41							41
Subordinated units
Net income attributable to controlling interest									$14
Earnings per unit - basic and diluted
Earnings per unit - basic and diluted (in dollars per share)	$0.28	$0.24							$0.52
Weighted-average units outstanding
Weighted-average units outstanding (in shares)	28	28							28

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	0 Months Ended		12 Months Ended	0 Months Ended
In Millions, except Per Share data, unless otherwise specified	Nov. 24, 2014	Nov. 04, 2014	Dec. 31, 2014	Feb. 26, 2015	Feb. 09, 2015	Feb. 20, 2015
Subsequent Events
Distribution (in dollars per share)		$0.22
Distribution to unitholders	$15		$15
Subsequent Events
Subsequent Events
Distribution (in dollars per share)					$0.36
Approved distribution to unitholders				25
Subsequent Events | Transocean
Subsequent Events
Distribution to unitholders						$18