Transocean Partners LLC - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 CEO CERTIFICATION - Transocean Partners LLC	exhibit32_1.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - Transocean Partners LLC	exhibit31_1.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - Transocean Partners LLC	exhibit31_2.htm
EX-32.2 - EXHIBIT 32.2 CFO CERTIFICATION - Transocean Partners LLC	exhibit32_2.htm
10-Q - FORM 10-Q 3Q2014 - Transocean Partners LLC	form10_q3q2014.pdf
EXCEL - IDEA: XBRL DOCUMENT - Transocean Partners LLC	Financial_Report.xls

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

______________________________

FORM 10-Q

(Mark one)

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

For the quarterly period ended September 30, 2014

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

For the transition period from _____ to _____

______________________________

Commission file number 001-36584

TRANSOCEAN PARTNERS LLC

(Exact name of registrant as specified in its charter)

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

Deepwater House Kingswells Causeway Prime Four Business Park Aberdeen, Scotland, United Kingdom	AB15 8PU
(Address of principal executive offices)	(Zip Code)

+44 (1224) 945-100
(Registrant’s telephone number, including area code)

______________________________

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

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

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer (do not check if a smaller reporting company) þ Smaller reporting company ¨

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

As of October 28, 2014, 41,379,310 common units and 27,586,207 subordinated units were outstanding.

TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

INDEX TO FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 2014

		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	14
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 4.	Controls and Procedures	23

PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	24
Item 1A.	Risk Factors	24
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	24
Item 4.	Mine Safety Disclosures	24
Item 6.	Exhibits	25

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 September 30,				Nine months ended September 30,
	2014		2013		2014		2013

Operating revenues
Contract drilling revenues	$	134	$	145	$	422	$	389
Other revenues		2		2		7		7
		136		147		429		396
Costs and expenses
Operating and maintenance		56		62		186		181
Depreciation		16		16		49		49
General and administrative		4		2		10		7
		76		80		245		237

Operating income		60		67		184		159
Interest income		1		—		2		1
Income before income tax expense		61		67		186		160
Income tax expense		4		7		16		17

Net income		57	$	60		170	$	143
Net income attributable to Predecessor		22				135
Net income subsequent to initial public offering		35				35
Net income attributable to noncontrolling interest		18				18
Net income attributable to controlling interest	$	17			$	17

Earnings per unit - basic and diluted
Earnings per common unit	$	0.24			$	0.24
Earnings per subordinated unit	$	0.24			$	0.24

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

See accompanying notes.

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except unit data)

(Unaudited)

	September 30, 2014			December 31, 2013

Assets
Cash and cash equivalents	$	49		$	—
Accounts receivable		92			103
Accounts receivable from affiliates		11			—
Materials and supplies, net		42			34
Deferred income taxes, net		10			15
Prepaid assets		9			7
Total current assets		213			159

Property and equipment		2,294			2,309
Less accumulated depreciation		(318	)		(271	)
Property and equipment, net		1,976			2,038
Goodwill		356			213
Deferred income taxes, net		18			29
Other assets		25			29
Total assets	$	2,588		$	2,468

Liabilities and equity
Accounts payable to affiliates	$	57		$	—
Debt due to affiliates within one year		43			—
Deferred revenues		21			37
Total current liabilities		121			37

Long-term tax liability		—			13
Deferred revenues		17			30
Drilling contract intangible liability		32			44
Total long-term liabilities		49			87

Commitments and contingencies

Common units, 41,379,310 authorized, issued and outstanding at September 30, 2014		837			—
Subordinated units, 27,586,207 authorized, issued and outstanding at September 30, 2014		560			—
Total members’ equity		1,397			—
Net investment		—			2,344
Noncontrolling interest		1,021			—
Total equity		2,418			2,344
Total liabilities and equity	$	2,588		$	2,468

See accompanying notes.

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

(Unaudited)

	Nine months ended September 30,
	2014			2013

Common units
Balance, beginning of period	$	—		$	—
Allocation of net investment		824			—
Net income attributable to controlling interest		10			—
Distribution payable for working capital adjustment		(4	)		—
Contribution for parent payment of dual-activity patent royalties		2			—
Contribution for parent indemnification of lost revenues		5			—
Balance, end of period	$	837		$	—

Subordinated units
Balance, beginning of period	$	—		$	—
Allocation of net investment		550			—
Net income attributable to controlling interest		7			—
Distribution payable for working capital adjustment		(2	)		—
Contribution for parent payment of dual-activity patent royalties		1			—
Contribution for parent indemnification of lost revenues		4			—
Balance, end of period	$	560		$	—

Total members’ equity
Balance, beginning of period	$	—		$	—
Allocation of net investment		1,374			—
Net income attributable to controlling interest		17			—
Distribution payable for working capital adjustment		(6	)		—
Contribution for parent payment of dual-activity patent royalties		3			—
Contribution for parent indemnification of lost revenues		9			—
Balance, end of period	$	1,397		$	—

Net investment
Balance, beginning of period	$	2,344		$	2,388
Net income attributable to the Predecessor		135			143
Distributions to the Predecessor parent, net		(102	)		(164	)
Effect of formation transactions		(1,003	)		—
Allocation of net investment		(1,374	)		—
Balance, end of period	$	—		$	2,367

Noncontrolling interest
Balance, beginning of period	$	—		$	—
Effect of formation transactions		1,003			—
Net income attributable to noncontrolling interest		18			—
Balance, end of period	$	1,021		$	—

Total equity
Balance, beginning of period	$	2,344		$	2,388
Net income attributable to the Predecessor		135			143
Net income subsequent to initial public offering		35			—
Distributions to Predecessor parent, net		(102	)		(164	)
Distribution payable for working capital adjustment		(6	)		—
Contribution for parent payment of dual-activity patent royalties		3			—
Contribution for parent indemnification of lost revenues		9			—
Balance, end of period	$	2,418		$	2,367

See accompanying notes.

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013

Cash flows from operating activities
Net income	$	57		$	60		$	170		$	143
Adjustments to reconcile to net cash provided by operating activities
Amortization of drilling contract intangibles		(4	)		(4	)		(12	)		(13	)
Depreciation		16			16			49			49
Patent royalties expense		3			—			3			—
Deferred income taxes		5			4			16			11
Other, net		(1	)		—			(1	)		—
Changes in deferred revenues, net		(9	)		(9	)		(29	)		(28	)
Changes in deferred costs, net		(3	)		1			(4	)		3
Changes in operating assets and liabilities
Decrease in accounts receivable, net		36			3			21			13
Increase in materials and supplies, net		(2	)		(3	)		(8	)		(9	)
(Increase) decrease in prepaid assets, net		1			3			(3	)		(3	)
Decrease in balances due to affiliates, net		(62	)		—			(62	)		—
Increase in income tax liability, net		—			1			1			1
Net cash provided by operating activities		37			72			141			167

Cash flows from investing activities
Capital expenditures		—			(1	)		(2	)		(2	)
Net cash used in investing activities		—			(1	)		(2	)		(2	)

Cash flows from financing activities
Proceeds from working capital note payable to affiliate		43			—			43			—
Distributions to the Predecessor parent, net		(39	)		(71	)		(141	)		(165	)
Contributions resulting from formation transactions		8			—			8			—
Net cash provided by (used in) financing activities		12			(71	)		(90	)		(165	)

Net increase in cash and cash equivalents		49			—			49			—
Cash and cash equivalents at beginning of period		—			—			—			—
Cash and cash equivalents at end of period	$	49		$	—		$	49		$	—

See accompanying notes.

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Nature of 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” or “Parent”), 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 the Parent that gave effect to certain formation transactions, including the Parent’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”). The Parent 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. The Parent holds the remaining 21.3 million common units and 27.6 million subordinated units, which collectively represented a 70.8 percent limited liability company interest. As a result of the offering, the Parent received net cash proceeds of $416 million, net of $27 million for underwriting discounts and commissions and other offering costs.

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

Note 2—Significant Accounting Policies

Presentation—For periods prior to August 5, 2014, the condensed combined financial information of the Predecessor was derived from Transocean’s accounting records. The condensed combined financial information reflects the combined results of operations, financial position and cash flows of the Predecessor Business as if such operations and assets had been combined for all periods presented. All transactions among the Predecessor Business within the Predecessor have been eliminated.

Transocean uses a centralized approach to treasury services to perform cash management for the operations of its affiliates. 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. The Predecessor had no bank accounts, and Transocean did not allocate its cash and cash equivalents to the Predecessor. Accordingly, the Predecessor’s transfers of cash to and from Transocean’s treasury were presented as net distributions to Parent on our condensed consolidated statements of equity and in our financing activities on our condensed consolidated statements of cash flows. The Predecessor’s results of operations do not include any interest expense for intercompany cash advances from Transocean, since Transocean did not historically allocate interest expense for intercompany advances to the Predecessor.

For the periods following August 5, 2014, the condensed consolidated financial statements reflect our consolidated results of operations, financial position and cash flows, which we have prepared as follows:

Our condensed consolidated statements of operations for the three and nine months ended September 30, 2014 consists of the consolidated results of operations of Transocean Partners for the period from August 5, 2014 through September 30, 2014 and the combined results of operations of the Predecessor for the beginning of the respective period through August 4, 2014. Our condensed consolidated statements of operations for the three and nine months ended September 30, 2013 consists entirely of the combined results of operations of the Predecessor.

§	Our condensed consolidated balance sheet at September 30, 2014 consists of the consolidated balances of Transocean Partners. Our condensed consolidated balance sheet at December 31, 2013 consists of the combined balances of the Predecessor.

Our condensed consolidated statements of cash flows for the three and nine months ended September 30, 2014 consists of the consolidated cash flows of Transocean Partners for the period from August 5, 2014 through September 30, 2014 and the combined cash flows of the Predecessor for the beginning of the respective period through August 4, 2014. Our condensed consolidated statements of cash flows for the three and nine months ended September 30, 2013 consists entirely of the combined cash flows of the Predecessor.

Our condensed consolidated statements of equity for the nine months ended September 30, 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 condensed consolidated statements of equity for the nine months ended September 30, 2013 consists entirely of the combined activity of the Predecessor.

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 have prepared the accompanying unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”) for interim financial information and with the instructions to 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 U.S. GAAP for complete financial statements. The condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. Such adjustments are considered to be of a normal recurring nature unless otherwise noted. Operating results for the three and nine months ended September 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014 or for any future period. The accompanying condensed consolidated financial statements and notes thereto should be read in conjunction with the Predecessor’s audited combined financial statements and notes thereto as of December 31, 2013 and 2012 and for each of the two years in the period ended December 31, 2013.

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Accounting estimates—To prepare financial statements in accordance with U.S. GAAP, 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.

Allocated indirect and overhead costs—The Predecessor’s combined results of operations included 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.

In the three and nine months ended September 30, 2014, the Predecessor recognized such allocated operating and maintenance costs of $2 million and $14 million, respectively, including $1 million and $11 million, respectively, for personnel costs. In the three and nine months ended September 30, 2014, the Predecessor recognized such allocated general and administrative costs of less than $1 million and $6 million, respectively, including less than $1 million and $4 million, respectively, for personnel costs.

In the three and nine months ended September 30, 2013, the Predecessor recognized such allocated operating and maintenance costs of $7 million and $22 million, respectively, including $6 million and $17 million, respectively, for personnel costs. In the three and nine months ended September 30, 2013, the Predecessor recognized such allocated general and administrative costs of $2 million and $7 million, respectively, including $1 million and $4 million, respectively, for personnel costs.

Cash and cash equivalents—Cash equivalents are highly liquid debt instruments with original maturities of three months or less that may include 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 record long-term accounts receivable at their present value and recognize interest income using the effective interest method through the date of payment. At September 30, 2014 and December 31, 2013, the aggregate carrying amount of the long-term accounts receivable was $12 million and $22 million, respectively, recorded in other assets, which had weighted average effective interest rates of 11 percent and 10 percent, respectively.

Subsequent events—We evaluate subsequent events through the time of our filing on the date we issue the financial statements. See Note 12—Subsequent Events.

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 a material effect on our condensed consolidated balance sheets or the disclosures contained in the notes to condensed consolidated financial statements.

- 6 -

Recently issued accounting standards

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.

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 will be treated as a corporation for U.S. federal income tax purposes. Certain of our controlled affiliates are subject to taxation in the jurisdictions in which they are organized, conduct business or own assets. For this purpose, “controlled affiliates” include the RigCos.

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. Our 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.

Our 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.

In the nine months ended September 30, 2014 and 2013, our annual effective tax rate was 8.6 percent and the Predecessor’s annual effective tax rate was 10.7 percent, respectively. For the nine months ended September 30, 2014, this rate was based on income before income taxes for each period after adjusting for various discrete items, including certain adjustments of less than $1 million to prior period tax expense.

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

	September 30, 2014		December 31, 2013
Unrecognized tax benefits, excluding interest and penalties	$	—	$	12
Interest and penalties		—		1
Unrecognized tax benefits, including interest and penalties	$	—	$	13

The Predecessor’s unrecognized tax benefits balance at December 31, 2013 arose in legal entities that were not transferred to us in the formation transactions.

In the year ending December 31, 2014, it is reasonably possible that the existing liabilities for unrecognized tax benefits could increase or decrease primarily due to the progression of open audits. However, we cannot reasonably estimate a range of potential changes in the Predecessor’s 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.

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

	Three months ended September 30,				Nine months ended September 30,
	2014		2013		2014		2013
Numerator for earnings per unit
Net income attributable to controlling interest	$	17	$	—	$	17	$	—
Net income available to common unitholders	$	10	$	—	$	10	$	—
Net income available to subordinated unitholders	$	7	$	—	$	7	$	—

Denominator for earnings per unit
Weighted-average common units outstanding		41		—		41		—
Weighted-average subordinated units outstanding		28		—		28		—

Earnings per unit
Earnings per common unit	$	0.24	$	—	$	0.24	$	—
Earnings per subordinated unit	$	0.24	$	—	$	0.24	$	—

See Note 12-Subsequent Events.

Note 6—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 and, as of such date, evaluated the allocated goodwill for impairment. 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 September 30, 2014, the carrying amount of our goodwill was $356 million.

Prior to August 5, 2014, Transocean allocated to the Predecessor a portion of the carrying amount of its goodwill based on the estimated fair value of the Predecessor’s net property and equipment relative to the estimated fair value of the 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.

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 agreement. Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default. At September 30, 2014, based on our leverage ratio on that date, the revolving credit facility margin was 1.625 percent. At September 30, 2014, we had no borrowings outstanding and $300 million available borrowing capacity under the Five-Year Revolving Credit Facility.

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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 September 30, 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 September 30, 2014, the outstanding principal amount under the working capital note payable was $43 million. At September 30, 2014, we estimated that the working capital exceeded the original estimate by approximately $6 million, and we recognized a liability for such amount, recorded in accounts payable to affiliates, with a corresponding reduction to members’ equity.

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.

Note 8—Commitments and Contingencies

Retained risk—Our fleet is covered under Transocean’s hull and machinery and excess liability insurance program, which is comprised of commercial market and captive insurance policies, and Transocean allocated to us the premium costs attributable to our fleet. Transocean renews the commercial and captive policies under its insurance program annually on May 1. At September 30, 2014, our drilling units had the insured value of approximately $2.0 billion under this program. Transocean does not generally carry, and we do not maintain, insurance coverage for loss of revenues. Through its wholly owned captive insurance company, Transocean generally retains the risk 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.

Hull and machinery coverage—Transocean had hull and machinery insurance for physical damage to its drilling rigs, which included coverage for our fleet, for which it allocated to us the respective premium costs. We retained the risk for the deductibles, noted below, relating to physical damage insurance coverage for our fleet. At September 30, 2014, under its hull and machinery program, Transocean generally maintained a $125 million per occurrence deductible, limited to a maximum of $200 million per policy period. Of such $125 million per occurrence deductible, Transocean retained the risk of $115 million in excess of $10 million through its wholly owned captive insurance company, and we retained the risk of the $10 million per occurrence deductible. Subject to the same shared deductible, we also had coverage for an amount equal to 50 percent of a rig’s insured value for combined costs incurred to mitigate damage to a rig and wreck removal. Any excess wreck removal costs were generally covered to the extent of Transocean’s remaining excess liability coverage.

Excess liability coverage—Transocean had excess liability coverage insurance, which included coverage for our fleet, for which it allocated to us the respective premium costs. At September 30, 2014, Transocean carried $700 million of commercial market excess liability coverage, excluding deductibles and Transocean’s primary $50 million self-insured retention, noted below, which generally covered offshore risks such as personal injury, third-party property claims, and third-party non-crew claims, including wreck removal and pollution. Through its wholly owned captive insurance company, Transocean retained the risk of the primary $50 million excess liability coverage. We were covered under Transocean’s primary $50 million captive insurance placement noted above, and Transocean allocated to us the respective premium costs. The excess liability coverage had 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. We and Transocean generally retained the risk for any liability losses in excess of $750 million.

Other insurance coverage—Transocean carries additional insurance, which included coverage for our drilling fleet, and Transocean allocated to us the respective premium costs. At September 30, 2014, Transocean carried $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.

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 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 September 30, 2014, we had no assets subject to liens or other encumbrances.

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Note 9—Related Party Transactions

Formation agreements

Contribution agreement—On July 29, 2014, we entered into a contribution agreement with the Parent that gave effect to certain of the formation transactions, including the Parent’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, the Parent retained the obligation for the payment of the quarterly royalty fees under the dual-activity license agreement through the patent expiration. In the three and nine months ended September 30, 2014, we recognized patent expense of $3 million for fees paid by the Parent on our behalf with a corresponding entry to members’ equity (see “—Other agreements—dual activity license agreements”).

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. The Parent holds the remaining 49 percent noncontrolling interest in each of the RigCos. In connection with the formation transactions, we and the Parent 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, 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 three and nine months ended September 30, 2014, we recognized costs of $14 million, recorded in operating and maintenance 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 three and nine months ended September 30, 2014, we recognized costs of less than $1 million, recorded in operating and maintenance 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 third 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 three and nine months ended September 30, 2014, we recognized costs of $16 million, recorded in operating and maintenance costs and expenses, and $2 million, recorded in general and administrative costs and expenses, for services under the master services agreement. In the three and nine months ended September 30, 2014, we acquired $7 million of materials and supplies purchased through the procurement services of Transocean Offshore Deepwater Drilling Inc. (“TODDI”). In the three and nine months ended September 30, 2014, we recognized insurance costs of $2 million, recorded in operating and maintenance costs and expenses.

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Former master services agreements—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 three and nine months ended September 30, 2014, the Predecessor recognized costs of $5 million and $24 million, respectively, recorded in operating and maintenance costs and expenses, for such services and assistance. In the three and nine months ended September 30, 2013, the Predecessor recognized costs of $9 million and $26 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 three and nine months ended September 30, 2014, the Predecessor paid $5 million and $27 million, respectively, settled through its net investment, for materials and supplies purchased through TODDI’s procurement services. In the three and nine months ended September 30, 2013, the Predecessor paid $11 million and $28 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 three and nine months ended September 30, 2014, the Predecessor recognized allocated insurance costs of $2 million and $8 million, respectively, recorded in operating and maintenance costs and expenses. In the three and nine months ended September 30, 2013, the Predecessor recognized allocated insurance costs of $4 million and $10 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 three and nine months ended September 30, 2014, the Predecessor recognized costs of $9 million and $57 million, respectively, recorded in operating and maintenance costs and expenses, for such personnel costs. In the three and nine months ended September 30, 2013, the Predecessor recognized costs of $24 million and $70 million, respectively, recorded in operating and maintenance costs and expenses, for such personnel costs. In the three and nine months ended September 30, 2014, the Predecessor recognized costs of less than $1 million and $2 million, respectively, recorded in operating and maintenance costs and expenses, for the proportion of the benefit costs that covered the personnel supporting the Predecessor’s operations. In the three and nine months ended September 30, 2013, the Predecessor recognized costs of $2 million and $7 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, the Parent and we entered into an omnibus agreement (the “Omnibus Agreement”) with certain Transocean affiliates. 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 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, the Parent 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. 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.

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.

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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 three and nine months ended September 30, 2014, we submitted an indemnification claim for $9 million associated with lost revenues, and we recognized a receivable from affiliate with a corresponding entry to members’ equity.

Dual-activity license agreements—All three of our drilling units are equipped with Transocean’s patented dual-activity technology. Dual-activity technology employs structures, equipment and techniques using two drilling stations within a dual derrick to perform drilling tasks. Dual-activity technology allows our rigs to perform simultaneous drilling tasks in a parallel rather than sequential manner and reduces critical path activity, improving efficiency in both exploration and development drilling. The Predecessor entered into license agreements with TODDI for the use of the patented technology through the expiration of the patents in May 2016. Under the license agreements, the Predecessor paid to TODDI an aggregate original license cost of $20 million, recorded in other assets. In the three and nine months ended September 30, 2014, the Predecessor recognized amortization of the license costs of less than $1 million and $2 million, respectively, recorded in operating and maintenance costs and expenses. In the three and nine months ended September 30, 2013, the Predecessor recognized amortization of the license costs of less than $1 million and $2 million, respectively, recorded in operating and maintenance costs and expenses. At September 30, 2014 and December 31, 2013, the carrying amount of the deferred license cost was $5 million and $7 million, respectively.

Under the license agreements, the Predecessor also paid to TODDI quarterly royalty fees of between 3 percent and 5 percent of revenues. In the three and nine months ended September 30, 2014, the Predecessor recognized royalty fees of $2 million and $16 million, respectively, recorded in operating and maintenance costs and expenses. In the three and nine months ended September 30, 2013, the Predecessor recognized royalty fees of $5 million and $14 million, respectively, recorded in operating and maintenance costs and expenses. Under the contribution agreement, the Parent retained the obligation for the payment of the quarterly royalty fees (see “—Formation agreements—contribution agreement”).

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.

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TRANSOCEAN PARTNERS LLC AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 10—Supplemental Cash Flow Information

Additional cash flow information was as follows (in millions):

	Nine months ended September 30,
	2014			2013
Non-cash investing and financing activities
Predecessor’s capital transfers to affiliates (a)	$	(23	)	$	—
Predecessor’s capital transfers from affiliates (b)		10			1
Contribution for parent payment of dual-activity patent royalties (c)		3			—
Contribution for parent indemnification of lost revenues (d)		9			—
Distribution payable for working capital adjustment (e)		(6	)		—

_______________________________________________

(a)

In the nine months ended September 30, 2014, the Predecessor transferred to the Parent’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.

(b)

In the nine months ended September 30, 2014 and 2013, the Parent transferred to the Predecessor certain equipment with an aggregate net carrying amount of $10 million and $1 million, respectively, primarily all of which was to Development Driller III, and the Predecessor recorded the non-cash investing activity with a corresponding entry to its net investment.

(c)	In the nine months ended September 30, 2014, in connection with Transocean’s payment of $3 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.

(d)	In the nine months ended September 30, 2014, we submitted an indemnification claim for $9 million associated with lost revenues, and we recognized a receivable from affiliate with a corresponding increase to members’ equity.

(e)

Within 60 days after the formation transactions, under the assignment and bill of sale agreements, we agreed to pay to or receive from a Transocean affiliate the amount by which our pro rata share of actual working capital at the time of the acquisition exceeds or falls below such estimated net working capital at the time of the acquisition. At September 30, 2014, we estimated that the working capital exceeded the original estimate by approximately $6 million, and we recognized a liability for such amount, recorded in accounts payable to affiliates, with a corresponding reduction to members’ equity. See Note 7—Credit Agreements.

Note 11—Financial Instruments

The carrying amounts and fair values of our financial instruments were as follows:

	September 30, 2014				December 31, 2013
	Carrying amount		Fair value		Carrying amount		Fair value
Cash and cash equivalents	$	49	$	49	$	—	$	—
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 September 30, 2014, the aggregate carrying amount of our cash equivalents was $43 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.

Note 12—Subsequent Events

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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 Securities Act of 1933, as amended, and Section 21E of the 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:

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

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

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

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

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

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

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

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

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

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

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

§	our ability to leverage Transocean’s relationship and reputation in the offshore drilling industry;

§	our ability to purchase drilling rigs from Transocean 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 “Risk Factors” included in our prospectus dated July 31, 2014,

§	the adequacy of and access to sources of liquidity,

§	our inability to renew drilling contracts at comparable dayrates,

§	operational performance,

§	the impact of regulatory changes,

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

§	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 United States (“U.S.”) Securities and Exchange Commission (“SEC”), which are available free of charge on the SEC website at www.sec.gov.

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

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Business

Transocean Partners LLC (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean Partners”, “we”, “us”, or “our”) is a growth-oriented limited liability company recently formed by Transocean Ltd. (together with its affiliates, unless the context requires otherwise, “Transocean” or “Parent”) 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 U.S. Gulf of Mexico. We generate revenues through contract drilling services, which involves contracting our mobile offshore drilling fleet, related equipment and work crews on a dayrate basis to drill oil and gas wells.

Upon the completion of our formation transactions and initial public offering on August 5, 2014, we own a 51 percent interest in each of the RigCos. We control each RigCo through our ownership of the majority of its shares or limited liability company interests. The Parent owns the remaining 49 percent noncontrolling interest in each of the RigCos.

The RigCos own the following three drilling rigs:

§	the ultra-deepwater drillship Discoverer Inspiration, which commenced operations in 2010 and is currently under a contract with Chevron through April 2020;

§	the ultra-deepwater drillship Discoverer Clear Leader, which commenced operations in 2009 and is currently under a contract with Chevron through September 2018; and

§	the ultra-deepwater semi-submersible drilling rig Development Driller III, which commenced operations in 2009 and is currently under a contract with BP through November 2016.

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

Our contract drilling services operations are currently concentrated in the U.S. Gulf of Mexico. 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. We consider that 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 rigs are determined by the activities and needs of our customers.

Significant Events

Formation and initial public offering—On July 29, 2014, we entered into a contribution agreement with the Parent and certain of its subsidiaries that gave effect to certain of the formation transactions, including the transfer of 51 percent of the ownership interest in each of the RigCos. 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, the Parent completed the initial public offering of 20.1 million common units, including the 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. In connection with our formation transactions, we entered into certain related party agreements with Transocean affiliates. See Notes to Condensed Consolidated Financial Statements—Note 1—Nature of Business and Note 9—Related Party Transactions.

Working capital notes payable—On July 29, 2014, we entered into agreements with an affiliate of Transocean to establish a working capital note payable in the principal amount of $43 million that is due and payable at maturity on July 28, 2015. See “—Liquidity and capital resources—Sources and uses of liquidity.”

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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 (the “Five-Year Revolving Credit Facility”). See “—Liquidity and capital resources—Sources and uses of liquidity.”

Former credit agreements—On August 5, 2014, we terminated the credit agreements previously entered into with a Transocean affiliate and no borrowings were outstanding under the credit facilities at the time of termination. See “—Liquidity and capital resources—Sources and uses of liquidity.”

Distribution to unitholders— On November 4, 2014, our board of directors approved a distribution of $0.2246 per unit, representing an aggregate cash payment of $15 million to our unitholders, of which $11 million will be paid to the Transocean unitholder. We expect to pay the distribution on November 24, 2014 to unitholders of record as of November 17, 2014. See “—Liquidity and capital resources—Sources and uses of liquidity.”

Outlook

Drilling market—As of October 15, 2014, all three of our high-specification floaters were operating under existing long-term contracts with high-quality, creditworthy customers for an average remaining contract term of approximately 3.8 years. We believe continued exploration successes in the major deepwater offshore provinces and the emerging markets will generate additional demand and support our long-term positive outlook for our high-specification floater fleet.

Although our long-term view of the offshore drilling market remains favorable, particularly for high-specification assets, based upon our customers decisions to delay various exploration and development programs, coupled with the recent significant and rapid decline in commodity prices, we currently expect the pace of executing drilling contracts for the global floater fleet to remain stagnant in the near to mid term, resulting in excess capacity, lower dayrates and idle time for some rigs. Additionally, this excess capacity may result in some lower capability assets in the industry being permanently retired, ultimately reducing the available supply of drilling rigs, all else being equal.

As of October 15, 2014, uncommitted fleet rates for the remainder of 2014 and for 2015, 2016, 2017 and 2018 were as follows:

	2014		2015		2016		2017		2018
Uncommitted fleet rate (a)
Discoverer Inspiration	—	%	—	%	—	%	—	%	—	%
Discoverer Clear Leader	—	%	—	%	—	%	—	%	30	%
Development Driller III	—	%	—	%	10	%	100	%	100	%

_______________________________________________

(a)

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

Fleet status—Discoverer Clear Leader was scheduled to be out of service during the three months ending December 31, 2014 for a period of 18 days for its first scheduled special periodic survey. As of November 1, 2014, we had completed the special periodic survey and commenced returning the rig to service. Transocean has agreed to indemnify us for any lost revenue arising out of the failure to receive an operating dayrate from our customer for Discoverer Clear Leader for the period through the completion of this special periodic survey. As a result of this indemnity, we do not expect that these out of service periods will reduce the amount of our cash available for distribution. See “-Liquidity and capital resources-Sources and uses of liquidity.”

Performance and Other Key Indicators

Contract backlog—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 or other incentive provisions, which are excluded from the amounts presented for contract backlog. The contract backlog for our fleet was as follows:

	October 15, 2014		August 21, 2014		February 18, 2014
Contract backlog	(In millions)
Discoverer Inspiration	$	1,140	$	1,170	$	1,280
Discoverer Clear Leader		830		860		970
Development Driller III		330		360		420
Total fleet contract backlog	$	2,300	$	2,390	$	2,670

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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.

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
	September 30, 2014		June 30, 2014		September 30, 2013
Average daily revenue
Discoverer Inspiration	$	502,900	$	536,700	$	522,400
Discoverer Clear Leader		447,700		510,400		556,500
Development Driller III		461,900		465,800		445,700
Total fleet average daily revenue		470,800		504,300		508,200

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
	September 30, 2014			June 30, 2014			September 30, 2013
Revenue efficiency
Discoverer Inspiration		93	%		99	%		97	%
Discoverer Clear Leader		77	%		87	%		95	%
Development Driller III		98	%		99	%		98	%
Total fleet revenue efficiency		89	%		95	%		97	%

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 for Discoverer Clear Leader decreased in the three months ended September 30, 2014 relative to the three months ended June 30, 2014 due to unplanned downtime primarily associated with blowout preventers and other subsea equipment. Revenue efficiency for Discoverer Clear Leader decreased in the three months ended September 30, 2014 relative to the three months ended September 30, 2013, due to unplanned downtime primarily associated with blowout preventers and other subsea equipment. See “-Liquidity and Capital Resources-Sources and uses of liquidity.”

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
	September 30, 2014			June 30, 2014			September 30, 2013
Rig utilization
Discoverer Inspiration		100	%		100	%		100	%
Discoverer Clear Leader		100	%		100	%		100	%
Development Driller III		100	%		100	%		100	%
Total fleet rig utilization		100	%		100	%		100	%

Our rig utilization rate could decline as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues.

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Operating Results

Three months ended September 30, 2014 compared to three months ended September 30, 2013

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. See also Notes to Condensed Consolidated Financial Statements—Note 2—Significant Accounting Policies—Presentation.

	Three months ended September 30,
	2014			2013			Change			% Change
	(In millions, except day amounts and percentages)

Operating days		276			276			—		n/m
Average daily revenue	$	470,800		$	508,200		$	(37,400	)	(7	)%
Revenue efficiency		89	%		97	%
Rig utilization		100	%		100	%

Contract drilling revenues	$	134		$	145		$	(11	)	(8	)%
Other revenues		2			2			—		n/m
Total revenues		136			147			(11	)	(7	)%
Operating and maintenance expense		(56	)		(62	)		6		10	%
Depreciation expense		(16	)		(16	)		—		n/m
General and administrative expense		(4	)		(2	)		(2	)	(100	)%
Operating income		60			67			(7	)	(10	)%
Interest income		1			—			1		n/m
Income before income tax expense		61			67			(6	)	(9	)%
Income tax expense		(4	)		(7	)		3		43	%
Net income	$	57		$	60		$	(3	)	(5	)%

_______________________________________________

“n/m” means not meaningful

Operating revenues—Contract drilling revenues decreased for the three months ended September 30, 2014 compared to the three months ended September 30, 2013 as follows: (a) approximately $12 million of decreased revenues due to lower revenue efficiency resulting from increased downtime primarily associated with blowout preventers and other subsea equipment on Discoverer Clear Leader and (b) approximately $1 million of increased revenues due to cost escalation provisions.

Costs and expenses—Operating and maintenance costs and expenses decreased for the three months ended September 30, 2014 compared to the three months ended September 30, 2013 as follows: (a) approximately $3 million of decreased personnel costs, (b) approximately $1 million of decreased costs and expenses for between-well maintenance on Discoverer Clear Leader and (c) approximately $1 million of decreased costs and expenses for blowout preventer maintenance on Development Driller III.

Income tax expense—Consistent with the results of operations presented above, the following income tax expense data was based on our tax structure for the period from August 5, 2014 through September 30, 2014 and based on the Predecessor’s tax structure from the beginning of the period through August 4, 2014. For the three months ended September 30, 2014 and 2013, the annual effective tax rates were 7.8 percent and 10.7 percent, respectively, based on income before income taxes. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. For the three months ended September 30, 2014 and 2013, the effect of the various discrete period tax items was a net tax expense of less than $1 million. For the three months ended September 30, 2014 and 2013, the effective tax rates were 7.8 percent and 10.9 percent, respectively, based on income before income taxes, including these discrete tax items.

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Nine months ended September 30, 2014 compared to nine months ended September 30, 2013

The following is an analysis of our operating results. See “—Performance and Other Key Indicators” for a definition of operating days, average daily revenue, revenue efficiency and rig utilization. See also Notes to Condensed Consolidated Financial Statements—Note 2—Significant Accounting Policies—Presentation.

	Nine months ended September 30,
	2014			2013			Change			% Change
	(In millions, except day amounts and percentages)

Operating days		819			819			—		n/m
Average daily revenue	$	500,400		$	458,700		$	41,700		9	%
Revenue efficiency		94	%		88	%
Rig utilization		100	%		100	%

Contract drilling revenues	$	422		$	389		$	33		8	%
Other revenues		7			7			—		n/m
Total revenues		429			396			33		8	%
Operating and maintenance expense		(186	)		(181	)		(5	)	(3	)%
Depreciation expense		(49	)		(49	)		—		n/m
General and administrative expense		(10	)		(7	)		(3	)	(43	)%
Operating income		184			159			25		16	%
Interest income		2			1			1		n/m
Income before income tax expense		186			160			26		16	%
Income tax expense		(16	)		(17	)		1		6	%
Net income	$	170		$	143		$	27		19	%

_______________________________________________

“n/m” means not meaningful

Operating revenues—Contract drilling revenues increased for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 as follows: (a) approximately $24 million of increased revenues due to higher revenue efficiency resulting from reduced downtime associated with blowout preventers and other subsea equipment, primarily on Discoverer Clear Leader and Development Driller III, and (b) approximately $6 million of increased revenues due to cost escalation provisions.

Costs and expenses—Operating and maintenance costs and expenses increased for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013 as follows: (a) approximately $6 million of increased costs and expenses due to blowout preventer recertification costs, (b) approximately $5 million of increased patent royalty expense resulting from increased revenues and (c) approximately $4 million of increased costs and expenses resulting from riser joint overhaul and certification on Development Driller III. Partially offsetting these increases was the following: (a) approximately $9 million of decreased personnel costs, (b) approximately $2 million of decreased costs and expenses for blowout preventer maintenance on Development Driller III and (c) approximately $1 million of decreased indirect costs for shorebased support.

Income tax expense—Consistent with the results of operations presented above, the following income tax expense data was based on our tax structure for the period from August 5, 2014 through September 30, 2014 and based on the Predecessor’s tax structure from the beginning of the period through August 4, 2014. For the nine months ended September 30, 2014 and 2013, the annual effective tax rates were 8.6 percent and 10.7 percent, respectively, based on income before income taxes. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. For the nine months ended September 30, 2014 and 2013, the effect of the various discrete period tax items was a net tax expense of less than $1 million. For the nine months ended September 30, 2014 and 2013, the effective tax rates were 8.8 percent and 10.9 percent, respectively, based on income before income taxes, including these discrete tax items.

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Liquidity and Capital Resources

Sources and uses of cash

The following table summarizes our net cash flows from operating, investing and financing activities for the nine months ended September 30, 2014 and 2013:

	Nine months ended September 30,
	2014			2013			Change
	(In millions)
Cash flows from operating activities
Net cash provided by operating activities	$	141		$	167		$	(26	)
Net cash used in investing activities		(2	)		(2	)		—
Net cash used in financing activities		(90	)		(165	)		75
	$	49		$	—		$	49

Net cash provided by operating activities decreased primarily due to reduced cash from changes in working capital, partially offset by earnings after non-cash adjustments.

Net cash used in financing activities decreased primarily due to proceeds from a working capital note payable to an affiliate and reduced net distributions to the Predecessor parent.

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. We expect to fund our short-term liquidity needs through cash on hand, cash contributions resulting from claims to Transocean for indemnification from lost revenues, borrowings under credit facilities provided by Transocean affiliates, cash generated from operations and debt and equity financings.

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

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

We intend to pay a minimum quarterly distribution of $0.3625 per unit per quarter, which equates to approximately $25 million per quarter, or approximately $100 million per year in the aggregate, based on the number of outstanding common and subordinated units. At October 28, 2014, we had 41.4 million common units and 27.6 million subordinated units outstanding. We do not have a legal obligation to pay this distribution. Please read “Our Cash Distribution Policy and Restrictions on Distributions” in our prospectus dated July 31, 2014 and filed with the SEC on August 1, 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 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, the RigCos’ initial annual estimated maintenance and replacement capital expenditures will be $69 million per year, which is comprised of $50 million for long-term maintenance and society classification surveys and $19 million, including financing costs, for replacing our rigs at the end of their useful lives.

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The estimate of $19 million per year for future rig replacement is 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 limited liability company agreement allows our board of directors to deduct from our operating surplus each quarter estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, in order to reduce disparities in operating surplus caused by fluctuating maintenance and replacement capital expenditures, such as society classification surveys and rig replacement. Our board of directors, with the approval of the conflicts committee, may determine that one or more of our assumptions should be revised, which could cause our board of directors to increase the amount of estimated maintenance and replacement capital expenditures. We may elect to finance some or all of our maintenance and replacement capital expenditures through the issuance of additional common units which could be dilutive to existing unitholders. As our fleet matures and expands, our long-term maintenance expenses will likely increase. Please read “Risk Factors—Risks Inherent in Our Business—We must make substantial capital and operating expenditures to maintain the operating capacity of our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness and to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to execute our growth plan, each of which could negatively affect our financial condition, result of operations and cash flows and reduce distributable cash flow. In addition, each quarter, we are required to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted” and “—If capital expenditures are financed through cash from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished, our financial leverage could increase or our unitholders could be diluted” under “Risk Factors” in our prospectus dated July 31, 2014 and filed with the SEC on August 1, 2014.

Revolving credit facilities—In March 2014, we entered into credit agreements with a Transocean affiliate, establishing credit facilities with an aggregate borrowing capacity of $300 million that were scheduled to expire on March 31, 2017. On August 5, 2014, we terminated these credit agreements with no borrowings outstanding under the credit facilities at the time of termination.

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 plus a margin (the “revolving credit facility margin”), which ranges from 1.625 percent to 2.250 percent based on our leverage ratio, as defined, or (2) the base rate specified in the credit agreement plus the revolving credit facility margin, less one percent per annum. Throughout the term of the Five-Year Revolving Credit Facility, we are required to pay a commitment fee on the daily unused amount of the underlying commitment, which ranges from 0.225 percent to 0.325 percent based on our leverage ratio, as defined. Among other things, the Five-Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The Five-Year Revolving Credit Facility also includes a covenant imposing a maximum debt ratio, as defined in the agreement, with certain adjustments during a specified acquisition period. Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default.

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

The assignment and bill of sale agreements for the acquisition contained 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 October 28, 2014, the estimated working capital adjustment, recorded in accounts payable to affiliates, was $6 million.

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 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 October 28, 2014, we had no assets subject to liens or other encumbrances.

Transocean lost revenues indemnification—Under the omnibus agreement, 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. At September 30, 2014, we had an outstanding indemnification claim for $9 million associated with lost revenues.

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Distribution to unitholders— On November 4, 2014, our board of directors approved a distribution of $0.2246 per unit, representing an aggregate cash payment of $15 million to our unitholders, of which $11 million will be paid to the Transocean unitholder. We expect to pay the distribution on November 24, 2014 to unitholders of record as of November 17, 2014. The approved distribution amount was based on the minimum quarterly distribution for the proportional period from the date of the closing of the initial public offering through September 30, 2014.

Contractual obligations—As of September 30, 2014, with the exception of the $43 million working capital note that we issued in connection with our formation transactions, which is due and payable at maturity on July 28, 2015 (see Notes to Condensed Consolidated Financial Statements—Note 7—Credit Agreements), there have been no material changes from the contractual obligations presented as previously disclosed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our prospectus dated July 31, 2014 and filed with the SEC on August 1, 2014.

Other commercial commitments—As of September 30, 2014, there have been no material changes to the commercial commitments as previously disclosed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our prospectus dated July 31, 2014 and filed with the SEC on August 1, 2014.

Contingencies

Except as noted in this report, including in the Notes to Condensed Consolidated Financial Statements—Note 8—Commitments and Contingencies and in Note 4—Income Taxes, there have been no material changes to those actions, claims and other matters pending as discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies” in our prospectus dated July 31, 2014 and filed with the SEC on August 1, 2014.

Insurance matters

Our fleet is covered under Transocean’s hull and machinery and excess liability insurance program, which is comprised of commercial market and captive insurance policies, and Transocean allocates 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 October 28, 2014, our drilling units had the insured value of approximately $2.0 billion under this program. Above applicable deductibles, Transocean carries an aggregate of $750 million of excess liability limits, which is shared among the rigs in the Transocean fleet, including the rigs in our fleet. See Notes to Condensed Consolidated Financial Statements—Note 8—Commitments and Contingencies.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements. This discussion should be read in conjunction with disclosures included in the notes to our condensed consolidated financial statements related to estimates, contingencies and other accounting policies.

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 materials and supplies obsolescence, property and equipment, goodwill and income taxes. 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 used in the preparation of our condensed consolidated financial statements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” in our prospectus dated July 31, 2014 and filed with the SEC on August 1, 2014. We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. During the nine months ended September 30, 2014, there have been no material changes to the types of judgments, assumptions and estimates upon which our critical accounting estimates are based.

New Accounting Pronouncements

For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our condensed consolidated financial statements, see Notes to Condensed Consolidated Financial Statements—Note 3—New Accounting Pronouncements.

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, 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.

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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

Overview—We have entered into credit agreements and may enter into additional financial instruments, credit agreements or bank credit agreements that may expose it to interest rate risk.

Interest rate risk—At September 30, 2014, we had a working capital note payable to a Transocean affiliate. At October 28, 2014, the aggregate outstanding principal amount of the working capital note was $43 million. The principal amount of the working capital note payable bears interest at a variable rate and exposes us to interest rate risk.

Item 4.

Controls and Procedures

Disclosure controls and procedures—We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined in the Exchange Act, Rules 13a-15 and 15d-15, were effective as of September 30, 2014 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Internal controls over financial reporting—There were no changes to our internal controls during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II.

OTHER INFORMATION

Item 1.

Legal Proceedings

As of September 30, 2014, we were not involved in any lawsuits or other matters that could have a material adverse effect on our consolidated statements of financial position, results of operations or cash flows. For additional information regarding indemnifications provided by Transocean Ltd. and its affiliates for liabilities relating to litigation and other matters attributable to the Predecessor Business, see additional disclosures in our prospectus dated July 31, 2014 and filed with the United States (“U.S.”) Securities and Exchange Commission (“SEC”) on August 1, 2014.

Item 1A.

Risk Factors

There have been no material changes from the risk factors as previously disclosed under “Risk Factors” in our prospectus dated July 31, 2014 and filed with the SEC on August 1, 2014.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

On July 29, 2014, in connection with our initial public offering, Transocean Partners issued (a) to Transocean Partners Holdings Limited (i) 41,379,310 common units and 27,586,207 subordinated units, representing a 60 percent and a 40 percent limited liability company interest in us, respectively, (ii) the non-economic interest, and (iii) all of the incentive distribution rights, which entitle Transocean Partners Holdings Limited to increasing percentages of the cash that we distribute in excess of $0.416875 per unit per quarter, and (b) to an affiliate of Transocean Partners Holdings Limited the 364-Day Working Capital Note Payable of $43 million for cash proceeds of $43 million, all or a portion of which we paid to Transocean Partners Holdings Limited for our pro rata share of certain working capital balances. The foregoing transactions were undertaken in reliance upon the exemption from the registration requirements in Section 4(2) of the Securities Exchange Act of 1934. We believe that exemptions other than the foregoing exemption may exist for these transactions.

On July 31, 2014, our registration statement on Form S-1 (File No. 333-196958), as amended, filed with the SEC in connection with our initial public offering became effective. The offering closed on August 5, 2014, and Transocean Partners Holdings Limited sold to the public 20,125,000 common units at a price of $22.00 per common unit for aggregate gross proceeds of $443 million. Expenses related to the offering were paid by Transocean Partners Holdings Limited. Transocean Partners did not receive any proceeds from the sale of the common units in the offering by Transocean Partners Holdings Limited. The offering was made through an underwriting syndicate led by Morgan Stanley & Co. LLC and Barclays Capital Inc.

Item 4.

Mine Safety Disclosures

Not applicable.

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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 1.1 to Transocean Partners LLC’s registration statement on Form S-1 as amended (Commission File No. 333-196958))

10.1

Omnibus Agreement dated as of August 5, 2014 (incorporated by reference to Exhibit 10.1 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.2

Master Services Agreement dated as of August 5, 2014 (Transocean Offshore Deepwater Drilling Inc.) (incorporated by reference to Exhibit 10.2 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.3

Master Services Agreement dated as of August 5, 2014 (Transocean Partners Holdings Limited) (incorporated by reference to Exhibit 10.3 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.4

Secondment Agreement dated as of August 5, 2014 (incorporated by reference to Exhibit 10.4 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.5

Support Agreement dated as of August 5, 2014 (incorporated by reference to Exhibit 10.5 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.6

Contribution Agreement dated as of July 29, 2014 (incorporated by reference to Exhibit 10.6 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.7

Revolving Credit Facility Agreement, dated as of August 5, 2014, between Transocean Partners LLC, as borrower, and Transocean Financing GmbH, as lender (incorporated by reference to Exhibit 10.7 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.8

364-Day Working Capital Note Payable dated as of July 29, 2014 (incorporated by reference to Exhibit 10.8 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.9

Bill of Sale regarding Transocean RIGP DIN LLC dated as of August 1, 2014 (incorporated by reference to Exhibit 10.9 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.10

Bill of Sale regarding Transocean RIGP DCL LLC dated as of August 1, 2014 (incorporated by reference to Exhibit 10.10 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.11

Bill of Sale regarding Transocean RIGP DD3 LLC dated as of August 1, 2014 (incorporated by reference to Exhibit 10.11 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.12

2014 Long-Term Incentive Plan of Transocean Partners LLC (incorporated by reference to Exhibit 10.12 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.13

Form of Indemnity Agreement (incorporated by reference to Exhibit 10.13 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

10.14

Transocean Partners LLC Executive Severance Policy (incorporated by reference to Exhibit 10.4 to Transocean Partners LLC’s Current Report on Form 8-K (Commission File No. 001-36584) filed on August 5, 2014)

†

31.1

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

†

31.2

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

†

32.1

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

†

32.2

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

†

101.ins

XBRL Instance Document

†

101.sch

XBRL Taxonomy Extension Schema

†

101.cal

XBRL Taxonomy Extension Calculation Linkbase

†

101.def

XBRL Taxonomy Extension Definition Linkbase

†

101.lab

XBRL Taxonomy Extension Label Linkbase

†

101.pre

XBRL Taxonomy Extension Presentation Linkbase

† Filed herewith.

* Compensatory plan or arrangement.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized, on November 10, 2014.

TRANSOCEAN PARTNERS LLC

By: /s/ Garry Taylor______________________________

Garry Taylor

Chief Financial Officer

(Principal Financial Officer and Principal Accounting Officer)

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Attached files

Transocean Partners LLC Reports

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