rigp_Current_Folio

PART I.FINANCIAL INFORMATION

Item 1.Financial Statements

TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per unit data)

(Unaudited)


	Three months ended
	March 31,
	2016		2015

Operating revenues
Contract drilling revenues	$	141	$	136
Other revenues		3		4
		144		140
Costs and expenses
Operating and maintenance		55		58
Depreciation		17		17
General and administrative		6		5
		78		80

Loss on impairment		—		(67)
Operating income (loss)		66		(7)

Other income
Interest income		1		1
Income (loss) before income tax expense		67		(6)
Income tax expense		4		4

Net income (loss)		63		(10)
Net income (loss) attributable to noncontrolling interest		32		(4)
Net income (loss) attributable to controlling interest	$	31	$	(6)

Earnings (loss) per unit—basic
Earnings (loss) per common unit	$	0.45	$	(0.09)
Earnings (loss) per subordinated unit	$	0.45	$	(0.09)

Earnings (loss) per unit—diluted
Earnings (loss) per common unit	$	0.45	$	(0.09)
Earnings (loss) per subordinated unit	$	0.45	$	(0.09)

Weighted-average units outstanding—basic
Common units		41		41
Subordinated units		28		28

Weighted-average units outstanding—diluted
Common units		41		41
Subordinated units		28		28

TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except unit data)

(Unaudited)


	March 31,		December 31,
	2016		2015

Assets
Cash and cash equivalents	$	155	$	159
Accounts receivable		110		115
Accounts receivable from affiliates		1		1
Materials and supplies, net of allowance for obsolescence of $6 at March 31, 2016 and December 31, 2015		40		34
Prepaid assets		4		7
Total current assets		310		316

Property and equipment		2,307		2,296
Less accumulated depreciation		(422)		(401)
Property and equipment, net		1,885		1,895

Deferred income taxes, net		9		10
Other assets		9		10
Total assets	$	2,213	$	2,231

Liabilities and equity
Accounts payable to affiliates	$	53	$	51
Deferred revenues		11		15
Other current liabilities		2		2
Total current liabilities		66		68

Long-term tax liability		4		3
Drilling contract intangible liability		10		14
Other long-term liabilities		1		1
Total long-term liabilities		15		18

Commitments and contingencies

Common units, 40,964,880 and 41,287,810 issued and outstanding at March 31, 2016 and December 31, 2015, respectively		761		757
Subordinated units, 27,586,207 issued and outstanding at March 31, 2016 and December 31, 2015		510		505
Total members’ equity		1,271		1,262

Noncontrolling interest		861		883
Total equity		2,132		2,145
Total liabilities and equity	$	2,213	$	2,231

TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

(Unaudited)


	Three months ended				Three months ended
	March 31,				March 31,
	2016		2015		2016		2015
	Quantity				Amount
Common units
Balance, beginning of period		41.3		41.4		757		847
Net income (loss) attributable to controlling interest		—		—		19		(4)
Contributions for parent payment of patent royalties		—		—		3		3
Distributions of available cash to unitholders		—		—		(15)		(15)
Cancellation of repurchased common units		(0.3)		—		(3)		—
Balance, end of period		41.0		41.4		761		831

Subordinated units
Balance, beginning of period		27.6		27.6		505		564
Net income (loss) attributable to controlling interest		—		—		12		(2)
Contributions for parent payment of patent royalties		—		—		3		2
Distributions of available cash to unitholders		—		—		(10)		(10)
Balance, end of period		27.6		27.6		510		554

Total members’ equity
Balance, beginning of period						1,262		1,411
Net income (loss) attributable to controlling interest						31		(6)
Contributions for parent payment of patent royalties						6		5
Distributions of available cash to unitholders						(25)		(25)
Cancellation of repurchased common units						(3)		—
Balance, end of period						1,271		1,385

Noncontrolling interest
Balance, beginning of period						883		1,040
Net income (loss) attributable to noncontrolling interest						32		(4)
Distributions to holder of noncontrolling interests						(54)		(25)
Balance, end of period						861		1,011

Total equity
Balance, beginning of period						2,145		2,451
Net income (loss)						63		(10)
Contributions for parent payment of patent royalties						6		5
Distributions of available cash to unitholders						(25)		(25)
Distributions to holder of noncontrolling interest						(54)		(25)
Cancellation of repurchased common units						(3)		—
Balance, end of period						2,132		2,396

TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Three months ended
	March 31,
	2016		2015

Cash flows from operating activities
Net income (loss)	$	63	$	(10)
Adjustments to reconcile to net cash provided by operating activities
Amortization of drilling contract intangible		(4)		(4)
Depreciation		17		17
Patent royalties expense		6		5
Loss on impairment		—		67
Deferred income taxes		1		1
Other, net		—		1
Changes in deferred revenues, net		(4)		(5)
Changes in deferred costs, net		1		(2)
Changes in operating assets and liabilities		(2)		51
Net cash provided by operating activities		78		121

Cash flows from investing activities
Payments to affiliates for capital expenditures		—		(3)
Net cash used in investing activities		—		(3)

Cash flows from financing activities
Distributions of available cash to unitholders		(25)		(25)
Distributions to holder of noncontrolling interests		(54)		(25)
Payments to repurchase common units		(3)		—
Contributions for parent indemnification of lost revenues		—		10
Net cash used in financing activities		(82)		(40)

Net increase (decrease) in cash and cash equivalents		(4)		78
Cash and cash equivalents at beginning of period		159		86
Cash and cash equivalents at end of period	$	155	$	164

Note 1—Business

Transocean Partners LLC (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean Partners”, “we”, “us”, or “our”), a Marshall Islands limited liability company, was formed on February 6, 2014 by Transocean Partners Holdings Limited, a Cayman Islands company (the “Transocean Member”) and a wholly owned subsidiary of Transocean Ltd. (together with its affiliates, unless the context requires otherwise, “Transocean”), to own, operate and acquire modern, technologically advanced offshore drilling rigs. At March 31, 2016, the drilling units in our fleet included the ultra‑deepwater drillships Discoverer Inspiration and Discoverer Clear Leader and the ultra‑deepwater semisubmersible Development Driller III, which are located in the United States (“U.S.”) Gulf of Mexico.

We own a 51 percent interest in each of the entities that owns and operates the drilling units in our fleet (each individually, a “RigCo”, and collectively, the “RigCos”). The Transocean Member owns the remaining 49 percent noncontrolling interest in each of the RigCos. At March 31, 2016 and December 31, 2015, the Transocean Member held 21.3 million common units and 27.6 million subordinated units, which collectively represented a 71.2 percent and 70.9 percent, respectively, limited liability company interest in us, and all of our incentive distribution rights. See Note 8—Equity and Note 11—Subsequent Events.

Note 2—Significant Accounting Policies

Presentation—We have prepared our accompanying unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the U.S. for interim financial information and with the instructions to Form 10‑Q and Article 10 of Regulation S‑X of the U.S. Securities and Exchange Commission (“SEC”). Pursuant to such rules and regulations, these financial statements do not include all disclosures required by accounting principles generally accepted in the U.S. for complete financial statements. The condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. Such adjustments are considered to be of a normal recurring nature unless otherwise noted. Operating results for the three months ended March 31, 2016 are not necessarily indicative of the results that may be expected for the year ending December 31, 2016 or for any future period. The accompanying condensed consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto as of December 31, 2015 and 2014 and for each of the three years in the period ended December 31, 2015 included in our annual report on Form 10‑K filed on February 25, 2016.

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

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

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

Subsequent events—We evaluate subsequent events through the time of our filing on the date we issue our financial statements. See Note 11—Subsequent Events.

Note 3—New Accounting Pronouncements

Recently issued accounting standards

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

Stock compensation—Effective no later than our annual report for the year ending December 31, 2016, we will adopt the accounting standards update that allows for simplification of the accounting for share‑based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The update, which permits early adoption, is effective for the annual period ending after December 15, 2016 and for interim and annual periods thereafter. We do not expect that our adoption will have a material effect on our condensed consolidated statements of financial position, operations and cash flows or the notes thereto.

Revenue from contracts with customers—Effective January 1, 2018, we will adopt the accounting standards update that requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The update, which permits early adoption, is effective for interim and annual periods beginning on or after December 15, 2017. We are evaluating the requirements to determine the effect such requirements may have on our condensed consolidated statements of financial position, operations and cash flows and on the disclosures contained in our notes to condensed consolidated financial statements.

Leases—Effective no later than January 1, 2019, we will adopt the accounting standards update that (a) requires lessees to recognize a right–to–use asset and a lease liability for virtually all leases, and (b) updates previous accounting standards for lessors to align certain requirements with the updates to lessee accounting standards and the revenue recognition accounting standards. The update, which permits early adoption, is effective for interim and annual periods beginning on or after December 15, 2018. We are evaluating the requirements to determine the effect such requirements may have on our condensed consolidated statements of financial position, operations and cash flows and on the disclosures contained in our notes to condensed consolidated financial statements.

Note 4—Goodwill Impairment

During the three months ended March 31, 2015, we noted impairment indicators that the fair value of our goodwill could have fallen below its carrying amount. Such impairment indicators included further reduction in the market value of our publicly traded common units and oil and natural gas prices as well as projected reductions in dayrates and utilization. As a result, we performed an interim goodwill impairment test as of March 31, 2015 and determined that the goodwill associated with our reporting unit was impaired. In the three months ended March 31, 2015, we recognized a loss of $67 million associated with the partial impairment of the carrying amount of our goodwill, which had no tax effect, including $34 million attributable to controlling interest ($0.50 per diluted unit) and $33 million attributable to noncontrolling interest. We estimated the implied fair value of the goodwill using a variety of valuation methods, including the income and market approaches. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of our reporting unit, such as future oil and natural gas prices, projected demand for our services, rig availability and dayrates. Subsequent to March 31, 2015, we identified additional indicators that the remaining goodwill associated with our contract drilling services reporting unit may have again fallen below its carrying amount. In the three months ended September 30, 2015, we recognized an incremental loss of $289 million, which had no tax effect, associated with the impairment of our then remaining goodwill.

Note 5—Income Taxes

Tax rate—We are organized as a limited liability company under the laws of The Republic of the Marshall Islands and are a resident in the United Kingdom (“U.K.”) for taxation purposes. We are treated as a corporation for U.S. federal income tax purposes. Certain of our controlled affiliates, including the RigCos, are subject to taxation in the jurisdictions in which they are organized, conduct business or own assets. We calculate our provision for income taxes based on the laws and rates applicable in the jurisdictions in which we operate and earn income. In the three months ended March 31, 2016 and 2015, our estimated annual effective tax rate was 5.4 percent and 6.4 percent, respectively, based on estimated annual income before income taxes, after excluding the loss on impairment.

Note 6—Earnings (Loss) Per Unit

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


	Three months ended March 31,
	2016				2015
	Basic		Diluted		Basic		Diluted
Numerator for earnings (loss) per unit
Net income (loss) attributable to controlling interest	$	31	$	31	$	(6)	$	(6)
Undistributed earnings allocable to participating securities		—		—		—		—
Net income (loss) available to unitholders	$	31	$	31	$	(6)	$	(6)
Net income (loss) available to common unitholders	$	19	$	19	$	(4)	$	(4)
Net income (loss) available to subordinated unitholders	$	12	$	12	$	(2)	$	(2)

Denominator for earnings (loss) per unit – common units
Weighted-average common units outstanding		41		41		41		41
Effect of equity-based awards		—		—		—		—
Weighted-average common units for per unit calculation		41		41		41		41

Denominator for earnings (loss) per unit – subordinated units
Weighted-average subordinated units outstanding		28		28		28		28
Effect of equity-based awards		—		—		—		—
Weighted-average subordinated units for per unit calculation		28		28		28		28

Earnings (loss) per unit
Earnings (loss) per common unit	$	0.45	$	0.45	$	(0.09)	$	(0.09)
Earnings (loss) per subordinated unit	$	0.45	$	0.45	$	(0.09)	$	(0.09)

Cash distributions declared and paid per unit
Common units	$	0.3625	$	0.3625	$	0.3625	$	0.3625
Subordinated units	$	0.3625	$	0.3625	$	0.3625	$	0.3625

In the three months ended March 31, 2016, we excluded from the calculation 20,906 equity-based awards, since the effect would have been anti-dilutive. In the three months ended March 31, 2015, no equity‑based awards were excluded from the calculation.

See Note 8—Equity and Note 11—Subsequent Events.

Note 7—Credit Agreement

Five‑Year Revolving Credit Facility—On August 5, 2014, we entered into a credit agreement, which is scheduled to expire on August 5, 2019, with a Transocean affiliate to establish a committed $300 million five‑year revolving credit facility that allows for uncommitted increases in amounts agreed to by the Transocean affiliate and us (the “Five‑Year Revolving Credit Facility”). We may borrow under the Five‑Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate (“LIBOR”) plus a margin (the “revolving credit facility margin”), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined, or (2) the base rate specified in the credit agreement plus the revolving credit facility margin, less one percent per annum. Throughout the term of the Five‑Year Revolving Credit Facility, we are required to pay a commitment fee on the daily unused amount of the underlying commitment, which ranges from 0.225 percent to 0.325 percent based on our leverage ratio, as defined. Among other things, the Five‑Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all of our assets. The Five‑Year Revolving Credit Facility also includes a covenant imposing a maximum debt ratio, as defined in the credit agreement. Borrowings under the Five‑Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default. At March 31, 2016, based on our leverage ratio on that date, the revolving credit facility margin was 1.625 percent. At March 31, 2016 and December 31, 2015, we had no borrowings outstanding and $300 million available borrowing capacity under the Five‑Year Revolving Credit Facility.

Note 8—Equity

Cash distributions to unitholders—On February 9, 2016, our board of directors approved a distribution of $0.3625 per unit to our unitholders. On February 25, 2016, we made an aggregate cash payment of $25 million to our unitholders of record as of February 22, 2016, including an aggregate cash payment of $18 million to the Transocean Member. On February 9, 2015, our board of directors approved a distribution of $0.3625 per unit to our unitholders. On February 26, 2015, we made an aggregate cash distribution of $25 million to our unitholders of record as of February 20, 2015, including an aggregate cash distribution of $18 million to the Transocean Member. See Note 11—Subsequent Events.

Cash distributions to holder of noncontrolling interests—In the three months ended March 31, 2016 and 2015, we made an aggregate cash distribution of $54 million and $25 million, respectively, to Transocean as holder of noncontrolling interests. See Note 11—Subsequent Events.

Unit repurchase program—On November 4, 2015, we announced that our board of directors approved a unit repurchase program authorizing us to repurchase up to $40 million of our publicly held common units for cancellation. Subject to market conditions, we may repurchase units from time to time in the open market or in privately negotiated transactions. We may suspend or discontinue the program at any time. In the three months ended March 31, 2016, under the unit repurchase program, we repurchased 336,958 of our publicly held common units at an average market price of $8.01 per unit for an aggregate purchase price of $3 million, and such common units were cancelled. See Note 11—Subsequent Events.

Note 9—Related Party Transactions

Master services and support agreements

Secondment agreements—On August 5, 2014, we entered into secondment agreements with certain Transocean affiliates to provide the services of our chief executive officer, rig crews and other personnel. In the three months ended March 31, 2016 and 2015, we recognized costs of $23 million and $24 million, respectively, recorded in operating and maintenance costs and expenses, and $1 million in each period, recorded in general and administrative costs and expenses, for personnel costs under the secondment agreements.

Master services agreements—On August 5, 2014, we entered into master services agreements, which have initial terms of five years, with certain Transocean affiliates, pursuant to which Transocean affiliates provide certain administrative, technical and non‑executive management services to us. We agreed to reimburse Transocean for the cost of all direct labor, materials and expenses incurred in connection with the provision of such 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, and a markup fee under certain circumstances. In the three months ended March 31, 2016 and 2015, we recognized costs of $25 million and $27 million, respectively, recorded in operating and maintenance costs and expenses, and $5 million and $4 million, respectively, recorded in general and administrative costs and expenses, for services under the master services agreements. In the three months ended March 31, 2016 and 2015, we acquired $12 million and $9 million, respectively, of materials and supplies purchased through Transocean’s procurement services. In the three months ended March 31, 2016, we acquired $9 million of equipment from Transocean affiliates, presented as additions to property and equipment with a corresponding increase to accounts payable to affiliates.

Other agreements

Omnibus agreement—On August 5, 2014, we entered into an omnibus agreement with Transocean and certain of its affiliates (the “Omnibus Agreement”). Under the Omnibus Agreement, Transocean granted us a right of first offer for its remaining ownership interests in each of the RigCos should Transocean decide to sell such interests. Transocean also agreed to offer us within five years of the effective date of the Omnibus Agreement, the opportunity to purchase, subject to requisite government and other third‑party consents, not less than a 51 percent interest in any four of the following six ultra‑deepwater drillships: Deepwater Invictus, Deepwater Thalassa, Deepwater Proteus, Deepwater Pontus, Deepwater Poseidon and Deepwater Conqueror. The purchase price for each drillship will be equal to the greater of the fair market value, taking into account the anticipated cash flows under the associated drilling contracts, or the all‑in construction cost, plus transaction costs. Transocean will select which of these drillships it will offer to us, the timing of the offers and whether it will offer us the opportunity to purchase a greater than 51 percent interest in any offered drillship. In addition, Transocean agreed not to acquire, own or operate any new drilling rig or contract for any drilling rig, in each case that was constructed in 2009 or later and is operating under a contract for five or more years (each, a “Five‑Year Drilling Rig”), subject to certain exceptions, without offering us the opportunity to purchase such rig. We also agreed not to acquire, own, operate, or contract for any drilling rig that is not a Five‑Year Drilling Rig, subject to certain exceptions, without first offering the contract to Transocean.

Among other things, Transocean also agreed to indemnify us for any lost revenue, up to $100 million, arising out of the failure to receive an operating dayrate from our customer for Discoverer Clear Leader, for the period commencing on the closing date of our initial public offering through the completion of the rig’s 2014 special periodic survey, which occurred during the three months ended December 31, 2014. In the three months ended March 31, 2015, we received a cash payment of $10 million for such indemnification claims submitted in the year ended December 31, 2014.

Dual‑activity license agreements—All three of our drilling units are equipped with Transocean’s patented dual‑activity technology. Dual‑activity technology employs structures, equipment and techniques using two drilling stations within a dual derrick to perform drilling tasks. Dual‑activity technology allows our rigs to perform simultaneous drilling tasks in a parallel rather than a sequential manner and reduces critical path activity, improving efficiency in both exploration and development drilling.

Under our license agreements with Transocean, we are required to pay quarterly patent royalties of between 3 percent and 5 percent of revenues. The Transocean Member agreed to retain and pay the obligation for the quarterly patent royalties. In the three months ended March 31, 2016 and 2015, we recognized non–cash operating expense for patent royalties of $6 million and $5 million, respectively, recorded in operating and maintenance costs and expenses, representing the patent royalties paid by the Transocean Member on our behalf, with corresponding entries to members’ equity.

Credit agreement—On August 5, 2014, we entered into the Five‑Year Revolving Credit Facility with a Transocean affiliate. See Note 7—Credit Agreement.

Note 10—Financial Instruments

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


	March 31, 2016				December 31, 2015
	Carrying		Fair		Carrying		Fair
	amount		value		amount		value
Cash and cash equivalents	$	155	$	155	$	159	$	159

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

Cash and cash equivalents—The carrying amount of cash and cash equivalents represents the historical cost, plus accrued interest, which approximates fair value because of the short maturities of those instruments. We measured the estimated fair value of our cash equivalents using significant other observable inputs, representative of a Level 2 fair value measurement, including the net asset values of the investments. At March 31, 2016 and December 31, 2015, the aggregate carrying amount of our cash equivalents was $152 million and $153 million, respectively.

Note 11—Subsequent Events

Cash distribution to unitholders—On May 5, 2016, our board of directors approved a distribution of $0.3625 per unit to our unitholders. We expect to pay the aggregate cash distribution of $25 million on May 24, 2016 to our unitholders of record as of May 17, 2016, including an aggregate cash payment of $18 million to the Transocean Member.

Cash distribution to holder of noncontrolling interests—Subsequent to March 31, 2016, we made an aggregate cash distribution of $45 million to Transocean as holder of noncontrolling interests.

Unit repurchase program—Subsequent to March 31, 2016, under the unit repurchase program, we repurchased 49,918 of our publicly held common units at an average market price of $9.71 per unit for an aggregate purchase price of less than $1 million, and such common units were cancelled. As of April 28, 2016, Transocean held a 71.3 percent limited liability company interest in us.

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward‑Looking Information

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

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

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

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

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

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

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

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

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

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

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

our ability to operate safely, efficiently and cost effectively and secure additional long‑term contracts, extend existing contracts and maintain high rig utilization;

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

our ability to leverage our relationship with Transocean Ltd. and its reputation in the offshore drilling industry;

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

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

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

effects of accounting changes and adoption of accounting policies; and

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

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

▪ “anticipates”	▪ “could”	▪ “forecasts”	▪ “might”	▪ “projects”
▪ “believes”	▪ “estimates”	▪ “intends”	▪ “plans”	▪ “scheduled”
▪ “budgets”	▪ “expects”	▪ “may”	▪ “predicts”	▪ “should”

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

those described under “Item 1A. Risk Factors” included in Part I of our annual report on Form 10‑K for the year ended December 31, 2015;

the adequacy of and access to sources of liquidity;

our inability to renew drilling contracts at comparable dayrates;

operational performance;

the impact of regulatory changes;

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

changes in political, social and economic conditions;

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

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

The foregoing risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward‑looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated. All subsequent written and oral forward‑looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward‑looking statements. Each forward‑looking statement speaks only as of the date of the particular statement. We expressly disclaim any obligations or undertaking to release publicly any updates or revisions to any forward‑looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward‑looking statement is based, except as required by law.

Business

Transocean Partners LLC (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean Partners”, “we”, “us”, or “our”) is a growth‑oriented limited liability company formed by Transocean Ltd. (together with its affiliates, unless the context requires otherwise, “Transocean”) to own, operate and acquire modern, technologically advanced offshore drilling rigs. 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. We generate revenues through contract drilling services, which involves contracting our mobile offshore drilling fleet, related equipment and seconded work crews on a dayrate basis to drill oil and gas wells.

We own a 51 percent interest in each of the entities that owns and operates the drilling units in our fleet (each individually, a “RigCo”, and collectively, the “RigCos”). Transocean Partners Holdings Limited (the “Transocean Member”), an indirect wholly owned subsidiary of Transocean Ltd., owns the remaining 49 percent noncontrolling interest in each of the RigCos. We control each RigCo through our ownership of the majority of its shares or limited liability company interests. We are entitled to only 51 percent of the RigCos’ distributions, if any. Our interest in the RigCos represents our only cash‑generating asset. We depend on Transocean affiliates to operate our drilling units, manage our customer relationships, renew existing and obtain new drilling contracts and to perform other administrative support activities. We anticipate growing by acquiring additional drilling rigs and operations indirectly through additional rig‑owning and rig‑operating entities and by acquiring additional equity interests in the RigCos.

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

Significant Events

Cash distributions to unitholders—On May 5, 2016, our board of directors approved a distribution of $0.3625 per unit to our unitholders. We expect to pay the aggregate cash distribution of $25 million on May 24, 2016 to our unitholders of record as of May 17, 2016, including an aggregate cash payment of $18 million to the Transocean Member. On February 9, 2016, our board of directors approved a distribution of $0.3625 per unit to our unitholders. On February 25, 2016, we made an aggregate cash payment of $25 million to our unitholders of record as of February 22, 2016, including an aggregate cash payment of $18 million to the Transocean Member. On February 9, May 4, July 30, and October 29, 2015, our board of directors approved distributions of $0.3625 per unit to our unitholders. On February 26, May 27, August 25, and November 23, 2015, we made an aggregate cash distribution of $100 million to our unitholders of record as of February 20, May 15, August 12, and November 9, 2015, including an aggregate cash distribution of $71 million to the Transocean Member. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Cash distributions to holder of noncontrolling interests—In April 2016, we made an aggregate cash distribution of $45 million to Transocean as holder of noncontrolling interests. In the three months ended March 31, 2016, we made an aggregate cash distribution of $54 million to Transocean as holder of noncontrolling interests. In the year ended December 31, 2015, we made an aggregate cash distribution of $101 million to Transocean as holder of noncontrolling interests. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Unit repurchase program—On November 4, 2015, we announced that our board of directors approved a unit repurchase program authorizing us to repurchase up to $40 million of our publicly held common units for cancellation. Subject to market conditions, we may repurchase units from time to time in the open market or in privately negotiated transactions. We may suspend or discontinue the program at any time. As of April 28, 2016, since the inception of the unit repurchase program, we repurchased 478,376 of our publicly held common units at an average market price of $8.41 per unit for an aggregate purchase price of $4 million. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Outlook

Drilling market—Our long‑term view of the offshore drilling market remains positive, particularly for high‑specification assets; however, the near to medium term remains very challenging. Low commodity pricing due to the current surplus of oil continues to hamper energy spending. Our customers remain focused on maintaining their capital allocation policies, reducing their costs and limiting their spend on exploration and development opportunities in 2016. The risks of project delays, contract renegotiations and contract terminations will continue. As expected, few new contracts have been awarded year to date, and this trend is likely to continue through the remainder of 2016, resulting in falling rig utilization rates exacerbating the negative pressure on rig pricing. Over time, we believe the oversupply of oil will decrease as the current supply and demand imbalance narrows. As spare oil capacity diminishes, we expect upward pressure on commodity pricing with subsequent increased demand for drilling rigs.

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

As of April 21, 2016, uncommitted fleet rates for the remainder of 2016 and for each of the subsequent four years in the period ending December 31, 2020 were as follows:


	2016		2017		2018		2019		2020
Uncommitted fleet rate
Discoverer Inspiration	—	%	—	%	—	%	—	%	78	%
Discoverer Clear Leader	—	%	—	%	10	%	100	%	100	%
Development Driller III	17	%	100	%	100	%	100	%	100	%

Performance and Other Key Indicators

Contract backlog—Contract backlog is defined as the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions. Contract backlog represents the maximum contract drilling revenues that can be earned considering the contractual operating dayrate in effect during the firm contract period and represents the basis for the maximum revenues in our revenue efficiency measurement. To determine maximum revenues for purposes of calculating revenue efficiency, however, we include the revenues earned for mobilization, demobilization and contract preparation, other incentive provisions or cost escalation provisions, which are excluded from the amounts presented for contract backlog. The contract backlog for our fleet was as follows:


	April 21,		February 11,		October 26,
	2016		2016		2015
Contract backlog	(In millions)
Discoverer Inspiration	$	819	$	859	$	923
Discoverer Clear Leader		536		577		640
Development Driller III		91		121		166
Total fleet contract backlog	$	1,446	$	1,557	$	1,729

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

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

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


	Three months ended
	March 31,		December 31,		March 31,
	2016		2015		2015
Average daily revenue
Discoverer Inspiration	$	564,500	$	540,300	$	553,100
Discoverer Clear Leader	$	484,400	$	599,300	$	561,800
Development Driller III	$	463,800	$	449,900	$	471,000
Total fleet average daily revenue	$	504,200	$	529,800	$	526,900

Our average daily revenue fluctuates primarily due to our revenue efficiency.

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


	Three months ended
	March 31,		December 31,		March 31,
	2016		2015		2015
Revenue efficiency
Discoverer Inspiration	97	%	92	%	99	%
Discoverer Clear Leader	83	%	103	%	95	%
Development Driller III	100	%	97	%	100	%
Total fleet revenue efficiency	93	%	98	%	98	%

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

Revenue efficiency decreased in the three months ended March 31, 2016 relative to the three months ended December 31, 2015 and March 31, 2015 due to unpaid downtime for subsea equipment repairs on Discoverer Clear Leader.

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


	Three months ended
	March 31,		December 31,		March 31,
	2016		2015		2015
Rig utilization
Discoverer Inspiration	100	%	100	%	80	%
Discoverer Clear Leader	100	%	100	%	100	%
Development Driller III	100	%	100	%	100	%
Total fleet average utilization	100	%	100	%	93	%

Our rig utilization rate declines as a result of unplanned out‑of‑service shipyard periods. The rig utilization rate may also decline as a result of idle rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.

Operating Results

Three months ended March 31, 2016 compared to the three months ended March 31, 2015

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


	Three months ended
	March 31,
	2016			2015			Change		% Change
	(In millions, except day amounts and percentages)

Operating days		273			252			21	n/m
Average daily revenue	$	504,200		$	526,900		$	(22,700)	(4)	%
Revenue efficiency		93	%		98	%
Rig utilization		100	%		93	%

Contract drilling revenues	$	141		$	136		$	5	4	%
Other revenues		3			4			(1)	(25)	%
		144			140			4	3	%
Operating and maintenance expense		(55)			(58)			3	(5)	%
Depreciation expense		(17)			(17)			—	—	%
General and administrative expense		(6)			(5)			(1)	20	%
Loss on impairment		—			(67)			67	n/m
Operating income		66			(7)			73	n/m
Interest income		1			1			—	-	%
Income (loss) before income tax expense		67			(6)			73	n/m
Income tax expense		(4)			(4)			—	—	%
Net income (loss)	$	63		$	(10)		$	73	n/m

“n/m” means not meaningful.

Operating revenues—Contract drilling revenues increased for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 primarily due to the following: (a) approximately $7 million of increased revenues for Discoverer Inspiration resulting from an increase in contractual dayrate and (b) approximately $9 million of increased revenues for Discoverer Inspiration resulting from improved utilization because of shipyard time in the prior‑year period and the absence of such shipyard time in the current‑year period. These increases were partially offset by the following: (a) approximately $8 million of decreased revenues for Discoverer Clear Leader and Discoverer Inspiration resulting from reduced revenue efficiency and (b) approximately $3 million of decreased revenues for all three rigs resulting from the recognition of pre‑operating revenues.

Costs and expenses—Operating and maintenance expense decreased for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 primarily due to the following: (a) approximately $1 million of decreased operating and maintenance expense for all three rigs primarily resulting from reduced personnel costs and (b) approximately $1 million of decreased operating and maintenance expense for all three rigs primarily resulting from reduced maintenance costs.

Loss on impairment—During the three months ended March 31, 2015, as a result of an interim impairment test, we recognized a loss on the impairment of the carrying amount of our goodwill.

Income tax expense—For the three months ended March 31, 2016 and 2015, our annual effective tax rate was 5.4 percent and 6.4 percent, respectively, based on income (loss) before income taxes after excluding the loss on impairment. We treat the tax effect of settlements of prior‑year tax liabilities and changes in prior‑year tax estimates as discrete period tax expenses or benefits. For the three months ended March 31, 2016 and 2015, the effect of the discrete period tax items was a net tax expense of less than $1 million and benefit of less than $1 million, respectively. For the three months ended March 31, 2016 and 2015, our effective tax rate was 5.8 percent and (55.7) percent, respectively, based on income (loss) before income taxes, including these discrete tax items.

Liquidity and Capital Resources

Sources and uses of cash

Transocean uses a centralized approach to treasury services to perform cash management for the operations of its affiliates. Under the master services agreements with Transocean, Transocean provides its treasury services to manage our cash and cash equivalents.

The following table summarizes our net cash flows from operating, investing and financing activities and our cash and cash equivalents for the three months ended March 31, 2016 and 2015:


	Three months ended
	March 31,
	2016		2015		Change
	(In millions)
Cash flows from operating activities
Net cash provided by operating activities	$	78	$	121	$	(43)
Net cash used in investing activities		—		(3)		3
Net cash used in financing activities		(82)		(40)		(42)
	$	(4)	$	78	$	(82)

Net cash provided by operating activities decreased for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 primarily due to changes in working capital.

Net cash used in investing activities decreased for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 due to a decrease in capital expenditures.

Net cash used in financing activities increased for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 primarily due to the following: (a) increased distributions to the holder of noncontrolling interests and (b) payments to repurchase common units with no comparable cash flows in the prior year period and (c) proceeds from affiliates for indemnification of lost revenues with no comparable cash flows in the current year period.

Sources and uses of liquidity

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

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under credit facilities provided by Transocean affiliates or commercial banks and issuances of debt and equity securities. Generally, our long‑term sources of funds will be cash from operations, long‑term bank borrowings and other debt and equity financings. Because we will distribute all of our available cash, after deducting estimated maintenance, net of replacement capital expenditures, we expect to fund acquisitions and capital expenditures for expansion by relying on external financing sources, including bank borrowings and the issuance of debt and equity securities.

Our access to debt and equity markets may be limited due to a variety of events, including, among others, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry. Our ability to access such markets may be restricted at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions. An economic downturn could have an impact on Transocean, which is the lender in our revolving credit facility, or on our customers, causing them to fail to meet their obligations to us.

We intend to pay and we expect to have sufficient ability to pay a minimum quarterly distribution of $0.3625 per unit per quarter, equivalent to $25 million per quarter, or approximately $99 million per year in the aggregate, based on the number of outstanding common and subordinated units. At April 28, 2016, we had 40.9 million common units and 27.6 million subordinated units outstanding. We do not have a legal obligation to pay this distribution, and the amount declared by our board of directors may vary from this minimum quarterly distribution depending on expectations for future transactions and activities in which we may engage.

On February 9, May 4, July 30 and October 29, 2015, our board of directors approved distributions of $0.3625 per unit to our unitholders. On February 26, May 27, August 25 and November 23, 2015, we made an aggregate cash distribution of $100 million to our

unitholders of record as of February 20, May 15, August 12 and November 9, 2015, including an aggregate cash distribution of $71 million to the Transocean Member.

Unit repurchase program—On November 4, 2015, we announced that our board of directors approved a unit repurchase program authorizing us to repurchase up to $40 million of our publicly held common units for cancellation. Subject to market conditions, we may repurchase units from time to time in the open market or in privately negotiated transactions. We may suspend or discontinue the program at any time. As of April 28, 2016, since the inception of the unit repurchase program, we repurchased 478,376 of our publicly held common units at an average market price of $8.41 per unit for an aggregate purchase price of $4 million.

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

Revolving credit facility—On August 5, 2014, we entered into a credit agreement, which is scheduled to expire on August 5, 2019, with a Transocean affiliate to establish a committed $300 million five‑year revolving credit facility that allows for uncommitted increases in amounts agreed to by Transocean and us. We may borrow under the Five‑Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate (“LIBOR”) plus a margin (the “revolving credit facility margin”), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined, or (2) the base rate specified in the credit agreement plus the revolving credit facility margin, less one percent per annum. Throughout the term of the Five‑Year Revolving Credit Facility, we are required to pay a commitment fee on the daily unused amount of the underlying commitment, which ranges from 0.225 percent to 0.325 percent based on our leverage ratio, as defined. Among other things, the Five‑Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all of our assets. The Five‑Year Revolving Credit Facility also includes a covenant imposing a maximum debt ratio, as defined in the agreement, with certain adjustments during a specified acquisition period. Borrowings under the Five‑Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default. At April 28, 2016, we had no borrowings outstanding and $300 million of available borrowing capacity under the Five‑Year Revolving Credit Facility.

Lost revenues indemnification—Under the Omnibus Agreement, Transocean agreed to indemnify us for any lost revenues, up to $100 million, arising out of the failure to receive an operating dayrate from our customer for Discoverer Clear Leader, for the period commencing on the closing date of our initial public offering through the completion of the rig’s 2014 special periodic survey. In the three months ended March 31, 2015, we received a cash payment of $10 million for such indemnification claims submitted in the year ended December 31, 2014.

Estimated maintenance and replacement capital expenditures—Subject to the approval by the board of directors of each of the RigCos, each RigCo will transfer its available cash to its equityholders, including the Transocean Member, as holder of noncontrolling interests, each quarter. In determining the amount of cash available for transfer, the board of directors of each of the RigCos and our board of directors determine the amount of cash reserves to set aside, including reserves for future maintenance and replacement capital expenditures, working capital and other matters. Because of the substantial capital expenditures the RigCos are required to make to maintain their fleets, we estimate the average annual maintenance and replacement capital expenditures to be $69 million per year, including $50 million for long‑term maintenance and classification society surveys and $19 million for replacing the rigs at the end of their useful lives.

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

The following table presents reconciliations of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net income (loss) for each period presented:


	Three months ended March 31,
	2016		2015
Net income (loss)	$	63	$	(10)
Plus:
Income tax expense		4		4
Interest income, net of interest expense		(1)		(1)
Depreciation expense		17		17
EBITDA		83		10
Plus:
Recognition of prior certification costs and license fees		1		1
Recognition of non-cash patent royalty expense		6		5
Loss on impairment of goodwill		—		67
Less:
Recognition of drilling contract intangible		4		4
Recognition of pre-operating revenues		4		7
Adjusted EBIDTA		82		72
Plus:
Planned out-of-service operating and maintenance expense		1		2
Cash proceeds from pre-operating revenues associated with long-term receivables		4		6
Less:
Estimated maintenance and replacement capital expenditures		17		16
Cash interest income, net		—		(1)
Cash income taxes		1		1
Distributable Cash Flow		69		64
Distributable Cash Flow attributable to noncontrolling interest		35		32
Distributable Cash Flow attributable to controlling interest	$	34	$	32

The following table presents a reconciliation of EBITDA, Adjusted EBITDA and Distributable Cash Flow to net cash provided by operating activities for each period presented:


	Three months ended March 31,
	2016		2015
Net cash provided by operating activities	$	78	$	121
Plus:
Changes in operating assets and liabilities, net		2		(51)
Changes in deferred revenues, net		4		5
Changes in deferred costs, net		(1)		2
Interest income, net of interest expense		(1)		(1)
Income tax expense, current		3		3
Recognition of drilling contract intangible		4		4
Recognition of non-cash patent royalty expense		(6)		(5)
Loss on impairment of goodwill		—		(67)
Other, net		—		(1)
EBITDA		83		10
Plus:
Recognition of prior certification costs and license fees		1		1
Recognition of non-cash patent royalty expense		6		5
Loss on impairment of goodwill		—		67
Less:
Recognition of drilling contract intangible		4		4
Recognition of pre-operating revenues		4		7
Adjusted EBIDTA		82		72
Plus:
Planned out-of-service operating and maintenance expense		1		2
Cash proceeds from pre-operating revenues associated with long-term receivables		4		6
Less:
Estimated maintenance and replacement capital expenditures		17		16
Cash interest income, net		—		(1)
Cash income taxes		1		1
Distributable Cash Flow		69		64
Distributable Cash Flow attributable to noncontrolling interest		35		32
Distributable Cash Flow attributable to controlling interest	$	34	$	32

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements. This discussion should be read in conjunction with disclosures included in the notes to our condensed consolidated financial statements related to estimates, contingencies and other accounting policies. Significant accounting policies are discussed in Note 2 to our condensed consolidated financial statements in this quarterly report on Form 10‑Q and in Note 2 to our consolidated financial statements in our annual report on Form 10‑K for the year ended December 31, 2015.

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

For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our annual report on Form 10‑K for the year ended December 31, 2015. We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. During the three months ended March 31, 2016, there have been no material changes to the types of judgments, assumptions and estimates upon which our critical accounting estimates are based.

New Accounting Pronouncements

For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated financial statements, see Notes to Condensed Consolidated Financial Statements—Note 3—New Accounting Pronouncements in this quarterly report on Form 10–Q and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10–K for the year ended December 31, 2015.

Jumpstart Our Business Startups Act of 2012

We qualify as an emerging growth company, as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). As an emerging growth company, we may, for up to five years after the date of our initial public offering, take advantage of specified exemptions from reporting and other regulatory requirements that are otherwise applicable generally to public companies, including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes‑Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, exemptions from the requirements of holding advisory say‑on‑pay votes on executive compensation and shareholder advisory votes on golden parachute compensation. In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. An emerging growth company can, therefore, delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have elected to take advantage of all of the applicable JOBS Act exemptions, including the exemption provided by Section 107 of the JOBS Act, as described above. This election to take advantage of the extended transition period for complying with new or revised financial accounting standards is irrevocable. Accordingly, the information that we provide you may be different than what you may receive from other public companies in which you hold equity interests.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

Credit risk—We are exposed to credit risk associated with having only two customers. As of March 31, 2016, there have been no material changes to the quantitative and qualitative disclosures about market risk as previously disclosed under “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our annual report on Form 10‑K for the year ended December 31, 2015.

PART II.OTHER INFORMATION

Item 1.Legal Proceedings

As of March 31, 2016, we were not involved in any lawsuits or other matters that could have a material adverse effect on our condensed consolidated statements of financial position, results of operations or cash flows.

Item 1A.Risk Factors

There have been no material changes to the risk factors as previously disclosed in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2015.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities


				Total	Maximum Number
				Number of Units	(or Approximate Dollar Value)
	Total Number	Average		Purchased as Part	of Units that May Yet Be Purchased
	of Units	Price Paid		of Publicly Announced	Under the Plans or Programs
Period	Purchased (a)	Per Unit		Plans or Programs (b)	(in millions)
January 2016	130,338	$	7.59	130,338	$	38.2
February 2016	117,413		7.95	116,564		37.2
March 2016	90,056		8.69	90,056		36.5
Total	337,807	$	8.01	336,958	$	36.5

(a)Total number of shares purchased in the three months ended March 31, 2016 consisted of 849 shares withheld by us through a broker arrangement and limited to statutory tax in satisfaction of withholding taxes due upon the vesting of restricted shares granted to our employees under our Incentive Plan.

(b)On November 4, 2015, we announced that our board of directors approved a unit repurchase program authorizing us to repurchase up to $40 million of our publicly held common units for cancellation. Subject to market conditions, we may repurchase units from time to time in the open market or in privately negotiated transactions. We may suspend or discontinue the program at any time. As of April 28, 2016, since inception of the unit repurchase program, we repurchased 478,376 of our publicly held common units at an average market price of $8.41 per unit for an aggregate purchase price of $4 million, and such common units were cancelled. See “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources and uses of liquidity.”

Item 4.Mine Safety Disclosures

Not applicable.

Item 6.Exhibits

(a)Exhibits

The following exhibits are filed in connection with this Report:


Number		Description
	3.1	Second Amended and Restated Limited Liability Company Agreement of Transocean Partners LLC, dated as of July 29, 2014 (incorporated by reference to Exhibit 3.1 to Transocean Partners LLC’s Current Report on Form 8‑K (Commission File No. 001‑36584) filed on August 5, 2014)
	3.2	Certificate of Formation of Transocean Partners LLC, dated February 6, 2014 (incorporated by reference to Exhibit 3.1 to Transocean Partners LLC’s registration statement on Form S‑1 as amended (Commission File No. 333‑196958))
†	31.1	CEO and CFO Certification Pursuant to Section 302 of the Sarbanes‑Oxley Act of 2002
†	32.1	CEO and CFO Certification Pursuant to Section 906 of the Sarbanes‑Oxley Act of 2002
†	101	The following materials from the Company’s Quarterly Report on Form 10‑Q for the quarter ended March 31, 2016 formatted in Extensible Business Reporting Language (XBRL): (i) the Condensed Consolidated Statements of Operations, (ii) the Condensed Consolidated Balance Sheets, (iii) the Condensed Consolidated Statements of Equity, (iv) the Condensed Consolidated Statements of Cash Flows and (v) related notes


†				Filed herewith.


Republic of the Marshall Islands	66-0818288
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

40 George Street London, England, United Kingdom	W1U 7DW
(Address of principal executive offices)	(Zip Code)


+44 (20) 3675-8410
(Registrant’s telephone number, including area code)

	TRANSOCEAN PARTNERS LLC
	By:	/s/ Kathleen S. McAllister
		Kathleen S. McAllister
		President, Chief Executive Officer and Chief Financial Officer
		(Principal Executive Officer and Principal Financial Officer)

6
		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Statements of Operations	1
	Condensed Consolidated Balance Sheets	2
	Condensed Consolidated Statements of Equity	3
	Condensed Consolidated Statements of Cash Flows	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	10
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	19
Item 4.	Controls and Procedures	20

PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	21
Item 4.	Mine Safety Disclosures	21
Item 6.	Exhibits	21