Edgar Filing: Transocean Ltd.

form10_q1q2015.htm

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 March 31, 2015

¨ 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 000-53533

TRANSOCEAN LTD.

(Exact name of registrant as specified in its charter)

Zug, Switzerland	98-0599916
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

10 Chemin de Blandonnet Vernier, Switzerland	1214
(Address of principal executive offices)	(Zip Code)

+41 (22) 930-9000
(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 þ No ¨

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 þ Accelerated filer ¨ Non-accelerated filer (do not check if a smaller reporting company) ¨ 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 April 28, 2015, 363,350,739 shares were outstanding.

TRANSOCEAN LTD. AND SUBSIDIARIES

INDEX TO FORM 10-Q

QUARTER ENDED MARCH 31, 2015

		Page
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Condensed Consolidated Statements of Operations	1
	Condensed Consolidated Statements of Comprehensive Income	2
	Condensed Consolidated Balance Sheets	3
	Condensed Consolidated Statements of Equity	4
	Condensed Consolidated Statements of Cash Flows	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	48
Item 4.	Controls and Procedures	48

PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 4.	Mine Safety Disclosures	50
Item 6.	Exhibits	51

Index

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share data)

(Unaudited)

	Three months ended March 31,
	2015			2014
Operating revenues
Contract drilling revenues	$	2,000		$	2,292
Other revenues		43			47
		2,043			2,339
Costs and expenses
Operating and maintenance		1,084			1,269
Depreciation		291			273
General and administrative		46			57
		1,421			1,599
Loss on impairment		(936	)		(65	)
Loss on disposal of assets, net		(7	)		(3	)
Operating income (loss)		(321	)		672

Other income (expense), net
Interest income		6			10
Interest expense, net of amounts capitalized		(116	)		(126	)
Other, net		47			(2	)
		(63	)		(118	)
Income (loss) from continuing operations before income tax expense		(384	)		554
Income tax expense		83			80
Income (loss) from continuing operations		(467	)		474
Loss from discontinued operations, net of tax		(2	)		(8	)

Net income (loss)		(469	)		466
Net income attributable to noncontrolling interest		14			10
Net income (loss) attributable to controlling interest	$	(483	)	$	456

Earnings (loss) per share-basic
Earnings (loss) from continuing operations	$	(1.32	)	$	1.27
Loss from discontinued operations		(0.01	)		(0.02	)
Earnings (loss) per share	$	(1.33	)	$	1.25

Earnings (loss) per share-diluted
Earnings (loss) from continuing operations	$	(1.32	)	$	1.27
Loss from discontinued operations		(0.01	)		(0.02	)
Earnings (loss) per share	$	(1.33	)	$	1.25

Weighted-average shares outstanding
Basic		363			361
Diluted		363			361

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

(Unaudited)

	Three months ended March 31,
	2015			2014

Net income (loss)	$	(469	)	$	466
Net income attributable to noncontrolling interest		14			10
Net income (loss) attributable to controlling interest		(483	)		456

Other comprehensive loss before reclassifications
Components of net periodic benefit costs		(13	)		(5	)

Reclassifications to net income
Components of net periodic benefit costs		5			6
(Gain) loss on derivative instruments		—			(2	)

Other comprehensive income (loss) before income taxes		(8	)		(1	)
Income taxes related to other comprehensive loss		(2	)		—

Other comprehensive loss		(10	)		(1	)
Other comprehensive income attributable to noncontrolling interest		—			—
Other comprehensive loss attributable to controlling interest		(10	)		(1	)

Total comprehensive income (loss)		(479	)		465
Total comprehensive income attributable to noncontrolling interest		14			10
Total comprehensive income (loss) attributable to controlling interest	$	(493	)	$	455

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

(Unaudited)

	March 31, 2015			December 31, 2014

Assets
Cash and cash equivalents	$	2,682		$	2,635
Accounts receivable, net of allowance for doubtful accounts of $14 at March 31, 2015 and December 31, 2014		1,964			2,120
Materials and supplies, net of allowance for obsolescence of $112 and $109 at March 31, 2015 and December 31, 2014, respectively		807			818
Assets held for sale		23			25
Deferred income taxes, net		157			161
Other current assets		210			242
Total current assets		5,843			6,001

Property and equipment		26,740			28,516
Less accumulated depreciation		(6,174	)		(6,978	)
Property and equipment, net		20,566			21,538
Other assets		696			874
Total assets	$	27,105		$	28,413

Liabilities and equity
Accounts payable	$	619		$	784
Accrued income taxes		217			131
Debt due within one year		1,024			1,033
Other current liabilities		1,313			1,822
Total current liabilities		3,173			3,770

Long-term debt		8,996			9,059
Deferred income taxes, net		152			237
Other long-term liabilities		1,263			1,354
Total long-term liabilities		10,411			10,650

Commitments and contingencies
Redeemable noncontrolling interest		11			11

Shares, CHF 15.00 par value, 396,260,487 authorized, 167,617,649 conditionally authorized, 373,830,649 issued at March 31, 2015 and December 31, 2014 and 363,346,369 and 362,279,530 outstanding at March 31, 2015 and December 31, 2014, respectively		5,183			5,169
Additional paid-in capital		5,806			5,797
Treasury shares, at cost, 2,863,267 held at March 31, 2015 and December 31, 2014		(240	)		(240	)
Retained earnings		2,866			3,349
Accumulated other comprehensive loss		(414	)		(404	)
Total controlling interest shareholders’ equity		13,201			13,671
Noncontrolling interest		309			311
Total equity		13,510			13,982
Total liabilities and equity	$	27,105		$	28,413

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

(Unaudited)

	Three months ended March 31,				Three months ended March 31,
	2015		2014		2015			2014
	Quantity				Amount
Shares
Balance, beginning of period		362		361	$	5,169		$	5,147
Issuance of shares under share-based compensation plans		1		1		14			17
Balance, end of period		363		362	$	5,183		$	5,164
Additional paid-in capital
Balance, beginning of period					$	5,797		$	6,784
Share-based compensation						19			28
Issuance of shares under share-based compensation plans						(15	)		(16	)
Allocated capital for sale of noncontrolling interest						9			—
Other, net						(4	)		(4	)
Balance, end of period					$	5,806		$	6,792
Treasury shares, at cost
Balance, beginning of period					$	(240	)	$	(240	)
Balance, end of period					$	(240	)	$	(240	)
Retained earnings
Balance, beginning of period					$	3,349		$	5,262
Net income (loss) attributable to controlling interest						(483	)		456
Balance, end of period					$	2,866		$	5,718
Accumulated other comprehensive loss
Balance, beginning of period					$	(404	)	$	(262	)
Other comprehensive loss attributable to controlling interest						(10	)		(1	)
Balance, end of period					$	(414	)	$	(263	)
Total controlling interest shareholders’ equity
Balance, beginning of period					$	13,671		$	16,691
Total comprehensive income (loss) attributable to controlling interest						(493	)		455
Share-based compensation						19			28
Issuance of shares under share-based compensation plans						(1	)		1
Allocated capital for sale of noncontrolling interest						9			—
Other, net						(4	)		(4	)
Balance, end of period					$	13,201		$	17,171
Noncontrolling interest
Balance, beginning of period					$	311		$	(6	)
Total comprehensive income attributable to noncontrolling interest						14			10
Allocated capital for sale of noncontrolling interest						(9	)		—
Distributions to holders of noncontrolling interest						(7	)		—
Balance, end of period					$	309		$	4
Total equity
Balance, beginning of period					$	13,982		$	16,685
Total comprehensive income (loss)						(479	)		465
Share-based compensation						19			28
Issuance of shares under share-based compensation plans						(1	)		1
Distributions to holders of noncontrolling interest						(7	)		—
Other, net						(4	)		(4	)
Balance, end of period					$	13,510		$	17,175

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Three months ended March 31,
	2015			2014
Cash flows from operating activities
Net income (loss)	$	(469	)	$	466
Adjustments to reconcile to net cash provided by operating activities:
Amortization of drilling contract intangibles		(4	)		(4	)
Depreciation		291			273
Share-based compensation expense		19			28
Loss on impairment		936			65
Loss on disposal of assets, net		7			3
Loss on disposal of assets in discontinued operations, net		—			10
Deferred income taxes		(98	)		(15	)
Other, net		12			12
Changes in deferred revenue, net		(39	)		(26	)
Changes in deferred costs, net		57			38
Changes in operating assets and liabilities		(186	)		(714	)
Net cash provided by operating activities		526			136

Cash flows from investing activities
Capital expenditures		(201	)		(1,131	)
Proceeds from disposal of assets, net		7			91
Proceeds from disposal of assets in discontinued operations, net		2			14
Other, net		—			(12	)
Net cash used in investing activities		(192	)		(1,038	)

Cash flows from financing activities
Repayments of debt		(63	)		(237	)
Proceeds from restricted cash investments		57			107
Deposits to restricted cash investments		—			(20	)
Distribution of qualifying additional paid-in capital		(272	)		(202	)
Distribution to holders of noncontrolling interest		(7	)		—
Other, net		(2	)		(2	)
Net cash used in financing activities		(287	)		(354	)

Net increase (decrease) in cash and cash equivalents		47			(1,256	)
Cash and cash equivalents at beginning of period		2,635			3,243
Cash and cash equivalents at end of period	$	2,682		$	1,987

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Business

Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean,” the “Company,” “we,” “us” or “our”) is a leading international provider of offshore contract drilling services for oil and gas wells. We specialize in technically demanding sectors of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. Our mobile offshore drilling fleet is considered one of the most versatile fleets in the world. We contract our drilling rigs, related equipment and work crews predominantly on a dayrate basis to drill oil and gas wells. At March 31, 2015, we owned or had partial ownership interests in and operated 66 mobile offshore drilling units associated with our continuing operations. At March 31, 2015, our fleet consisted of 42 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 14 Midwater Floaters, and 10 High-Specification Jackups. At March 31, 2015, we also had seven Ultra-Deepwater drillships and five High-Specification Jackups under construction or under contract to be constructed. See Note 9—Drilling Fleet.

On August 5, 2014, we completed an initial public offering to sell a noncontrolling interest in Transocean Partners LLC (“Transocean Partners”), a Marshall Islands limited liability company, which was formed on February 6, 2014, by Transocean Partners Holdings Limited, a Cayman Islands company and our wholly owned subsidiary, to own, operate and acquire modern, technologically advanced offshore drilling rigs. See Note 15—Noncontrolling Interest.

Note 2—Significant Accounting Policies

Presentation—We have prepared our accompanying unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the U.S. for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the U.S. Securities and Exchange Commission (“SEC”). Pursuant to such rules and regulations, these financial statements do not include all disclosures required by accounting principles generally accepted in the U.S. for complete financial statements. The condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. Such adjustments are considered to be of a normal recurring nature unless otherwise noted. Operating results for the three months ended March 31, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015 or for any future period. The accompanying condensed consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto as of December 31, 2014 and 2013 and for each of the three years in the period ended December 31, 2014 included in our annual report on Form 10-K filed on February 26, 2015.

Accounting estimates—To prepare financial statements in accordance with accounting principles generally accepted in the U.S., we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates and assumptions, including those related to our allowance for doubtful accounts, materials and supplies obsolescence, assets held for sale, property and equipment, investments, income taxes, contingencies, share-based compensation, defined benefit pension plans and other postretirement benefits. We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results could differ from such estimates.

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

Consolidation—We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes. We eliminate intercompany transactions and accounts in consolidation. We apply the equity method of accounting for an investment in an entity if we have the ability to exercise significant influence over the entity that (a) does not meet the variable interest entity criteria or (b) meets the variable interest entity criteria, but for which we are not deemed to be the primary beneficiary. We apply the cost method of accounting for an investment in an entity if we do not have the ability to exercise significant influence over the unconsolidated entity. We separately present within equity on our condensed consolidated balance sheets the ownership interests attributable to parties with noncontrolling interests in our consolidated subsidiaries, and we separately present net income attributable to such parties on our condensed consolidated statements of operations. See Note 4—Variable Interest Entities and Note 15—Noncontrolling Interest.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Property and equipment—The carrying amounts of our property and equipment, consisting primarily of offshore drilling rigs and related equipment, are based on our estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values of our rigs. These estimates, assumptions and judgments reflect both historical experience and expectations regarding future industry conditions and operations. At March 31, 2015, the aggregate carrying amount of our property and equipment represented approximately 76 percent of our total assets.

We compute depreciation using the straight-line method after allowing for salvage values. In December 2014, we reduced the salvage values of certain drilling units due to existing market conditions. In the three months ended March 31, 2015, this change in estimate resulted in increased depreciation expense of $30 million ($28 million, or $0.08 per diluted share, net of tax). For the year ending December 31, 2015, we expect this change in estimate to result in increased depreciation expense of approximately $76 million ($73 million, net of tax).

Share-based compensation—In the three months ended March 31, 2015 and 2014, we recognized share-based compensation expense of $19 million and $28 million, respectively.

Capitalized interest—We capitalize interest costs for qualifying construction and upgrade projects. In the three months ended March 31, 2015 and 2014, we capitalized interest costs on construction work in progress of $26 million and $34 million, respectively.

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

Subsequent events—We evaluate subsequent events through the time of our filing on the date we issue our financial statements. See Note 18—Subsequent Events.

Note 3—New Accounting Pronouncements

Recently adopted accounting standards

Presentation of financial statements—Effective January 1, 2015, we adopted the accounting standards update that changes the criteria for reporting discontinued operations. The update expands the disclosures for discontinued operations and requires new disclosures related to the disposal of individually significant components of an entity that do not qualify for discontinued operations. The update is effective for interim and annual periods beginning on or after December 15, 2014 and does not apply to components, such as our discontinued operations, that have been evaluated and reported as discontinued operations under previous guidance. Our adoption did not have an effect on our condensed consolidated financial statements or the disclosures contained in our notes to condensed consolidated financial statements.

Recently issued accounting standards

Interest—Effective January 1, 2016, we will adopt the accounting standards update that requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The update is effective for interim and annual periods beginning after December 15, 2015. We do not expect that our adoption will have a material effect on our condensed consolidated balance sheets or the disclosures contained in our notes to condensed consolidated financial statements.

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

Revenue from contracts with customers—Effective January 1, 2017, we will adopt the accounting standards update that requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The update is effective for interim and annual periods beginning on or after December 15, 2016. We are evaluating the requirements to determine the effect such requirements may have on our revenue recognition policies.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 4—Variable Interest Entities

Consolidated variable interest entities—Angola Deepwater Drilling Company Limited (“ADDCL”), a consolidated Cayman Islands company, and Transocean Drilling Services Offshore Inc. (“TDSOI”), a consolidated British Virgin Islands company, are variable interest entities for which we are the primary beneficiary. Accordingly, we consolidate the operating results, assets and liabilities of ADDCL and TDSOI. The carrying amounts associated with our consolidated variable interest entities, after eliminating the effect of intercompany transactions, were as follows (in millions):

	March 31, 2015		December 31, 2014
Assets	$	1,257	$	1,257
Liabilities		65		74
Net carrying amount	$	1,192	$	1,183

Note 5—Impairments

Assets held and used—During the three months ended March 31, 2015, we identified indicators that the asset groups in our contract drilling services reporting unit may not be recoverable. Such indicators included a reduction in the number of new contract opportunities, recent low dayrate fixtures and contract terminations. Our Deepwater Floater asset group, in particular, has seen further declines in projected dayrates and utilization partly caused by more technologically advanced drilling units aggressively competing with less capable drilling units. As a result of our testing, we determined that the carrying amount of the Deepwater Floater asset group was impaired. In the three months ended March 31, 2015, we recognized a loss of $507 million ($481 million, or $1.34 per diluted share, net of tax) associated with the impairment of these long-lived assets. We measured the fair value of the asset group by applying a combination of income and cost approaches, using projected discounted cash flows and estimates of the exchange price that would be received for the assets in the principal or most advantageous market for the assets in an orderly transaction between market participants as of the measurement date. Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of our contract drilling services reporting unit, such as future commodity prices, projected demand for our services, rig availability and dayrates. If we experience increasingly unfavorable changes to actual or anticipated dayrates or other impairment indicators, or if we are unable to secure new or extended contracts for our active units or the reactivation of any of our stacked units, we may be required to recognize additional losses in future periods as a result of impairments of the carrying amount of one or more of our asset groups.

Assets held for sale—In the three months ended March 31, 2015, we recognized an aggregate loss of $429 million ($393 million, or $1.07 per diluted share, net of tax), associated with the impairment of the Ultra-Deepwater Floater Deepwater Expedition, the Deepwater Floaters Sedco 707 and Transocean Rather and the Midwater Floaters GSF Aleutian Key, GSF Arctic III and Transocean Legend, along with related equipment, which were classified as assets held for sale at the time of impairment. We measured the impairment of the drilling units and related equipment as the amount by which the carrying amount exceeded the estimated fair value less costs to sell. We estimated the fair value of the assets using significant other observable inputs, representative of Level 2 fair value measurements, including indicative market values for the drilling units and related equipment to be sold for scrap value.

In the three months ended March 31, 2014, we recognized an aggregate loss of $65 million ($0.19 per diluted share), which had no tax effect, associated with the impairment of the Midwater Floater Sedneth 701 and the High-Specification Jackup GSF Magellan, along with related equipment, which were classified as assets held for sale at the time of impairment. We measured the impairments of the drilling units and related equipment as the amount by which the carrying amount exceeded the estimated fair value less costs to sell. We estimated the fair value of the assets using significant other observable inputs, representative of Level 2 fair value measurements, including indicative market values for comparable drilling units or a binding sale and purchase agreement for the drilling units and related equipment.

If we commit to plans to sell additional rigs for scrap value, we may be required to recognize additional losses in future periods associated with the impairment of such assets. See Note 18—Subsequent Events.

Note 6—Income Taxes

Tax rate—Transocean Ltd., a holding company and Swiss resident, 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. expects dividends from its subsidiaries and capital gains from sales of investments in its subsidiaries to be exempt from Swiss federal income tax.

Our provision for income taxes is based on the tax laws and rates applicable in the jurisdictions in which we operate and earn income. The relationship between our provision for or benefit from income taxes and our income or loss before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues rather than income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures. Generally, our annual marginal tax rate is lower than our annual effective tax rate. In the three months ended March 31, 2015 and 2014, our estimated annual effective tax rates were 25.8 percent and 15.1 percent, respectively, based on estimated annual income from continuing operations before income taxes, after excluding certain items, such as losses on impairment and gains and losses on certain asset disposals. 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.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

In December 2014, the U.K. Treasury released a draft proposal that would impose tax on groups that use certain tax planning techniques that are perceived as diverting profits from the U.K. The Diverted Profit Tax rule was included in the 2015 Finance Bill and on March 26, 2015, the legislation received Royal Assent with an effective date of April 1, 2015. The change in the law did not affect our existing annual income tax rate or deferred tax balances.

Deferred taxes—The valuation allowance for our non-current deferred tax assets was as follows (in millions):

			March 31, 2015				December 31, 2014
Valuation allowance for non-current deferred tax assets		$	395			$	340

The increase in the valuation allowance for our non-current deferred tax assets was primarily related to the current net operating losses generated in Norway and the U.K. carryforward deductions related to charter payments.

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

		March 31, 2015		December 31, 2014
Unrecognized tax benefits, excluding interest and penalties	$	271	$	265
Interest and penalties		120		120
Unrecognized tax benefits, including interest and penalties	$	391	$	385

In the year ending December 31, 2015, it is reasonably possible that our existing liabilities for unrecognized tax benefits may increase or decrease primarily due to the progression of open audits or the expiration of statutes of limitation. However, we cannot reasonably estimate a range of potential changes in our existing liabilities for unrecognized tax benefits due to various uncertainties, such as the unresolved nature of various audits.

Tax returns—We file federal and local tax returns in several jurisdictions throughout the world. With few exceptions, we are no longer subject to examinations of our U.S. and non-U.S. tax matters for years prior to 2010.

Our tax returns in the major jurisdictions in which we operate, other than the U.S., Norway and Brazil, which are mentioned below, are generally subject to examination for periods ranging from three to six years. We have agreed to extensions beyond the statute of limitations in two major jurisdictions for up to 20 years. Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments. We are defending our tax positions in those jurisdictions. While we cannot predict or provide assurance as to the timing or the outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated statement of financial position or results of operations, although it may have a material adverse effect on our consolidated statement of cash flows.

U.S. tax investigations—In January 2014, we received a draft assessment from the U.S. tax authorities related to our 2010 and 2011 U.S. federal income tax returns. The significant issue raised in the assessment relates to transfer pricing for certain charters of drilling rigs between our subsidiaries. This issue, if successfully challenged, would result in net adjustments of approximately $290 million of additional taxes, excluding interest and penalties. We believe our U.S. federal income tax returns are materially correct as filed, and we intend to continue to vigorously defend against all such claims to the contrary. An unfavorable outcome on these adjustments could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. Furthermore, if the authorities were to continue to pursue these positions with respect to subsequent years and were successful in such assertions, our effective tax rate on worldwide earnings with respect to years following 2011 could increase substantially, and could have a material adverse effect on our consolidated results of operations or cash flows.

Norway tax investigations and trial—Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 1999, 2001 and 2002 as well as the actions of certain employees of our former external tax advisors on these transactions. The authorities issued tax assessments as follows: (a) NOK 684 million, equivalent to approximately $85 million, plus interest, related to the migration of our subsidiary that was previously subject to tax in Norway, (b) NOK 412 million, equivalent to approximately $51 million, plus interest, related to a 2001 dividend payment and (c) NOK 43 million, equivalent to approximately $5 million, plus interest, related to certain foreign exchange deductions and dividend withholding tax. In November 2012, the Norwegian district court in Oslo heard the civil tax case regarding the disputed tax assessment of NOK 684 million related to the migration of our subsidiary. On March 1, 2013, the Norwegian district court in Oslo overturned the initial civil tax assessment and ruled in our favor, and the tax authorities filed an appeal. On June 26, 2014, the Norwegian district court in Oslo ruled that our subsidiary was liable for the civil tax assessment of NOK 412 million, equivalent to approximately $51 million, but waived all penalties and interest. On September 12, 2014, we filed an appeal. We intend to take all other appropriate action to continue to support our position that our Norwegian tax returns are materially correct as filed.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

In June 2011, the Norwegian authorities issued criminal indictments against two of our subsidiaries alleging misleading or incomplete disclosures in Norwegian tax returns for the years 1999 through 2002, as well as inaccuracies in Norwegian statutory financial statements for the years ended December 31, 1996 through 2001. Two employees of our former external tax advisors were also issued criminal indictments with respect to the disclosures in our tax returns, and our former external Norwegian tax attorney was issued criminal indictments related to certain of our restructuring transactions and the 2001 dividend payment. In January 2012, the Norwegian authorities supplemented the previously issued criminal indictments by issuing a financial claim of NOK 1.8 billion, equivalent to approximately $223 million, jointly and severally, against our two subsidiaries, the two external tax advisors and the external tax attorney. In February 2012, the authorities dropped the previously existing civil tax claim related to a certain restructuring transaction. In April 2012, the Norwegian tax authorities supplemented the previously issued criminal indictments against our two subsidiaries by extending a criminal indictment against a third subsidiary, alleging misleading or incomplete disclosures in Norwegian tax returns for the years 2001 and 2002. The criminal trial commenced in December 2012. In May 2013, the Norwegian authorities dropped the financial claim of NOK 1.8 billion against one of our subsidiaries and the criminal case related to the migration case of another subsidiary. The criminal trial proceedings ended in September 2013. The Norwegian authorities subsequently suggested, if we were found guilty, that the court assess criminal penalties of NOK 230 million, equivalent to approximately $29 million, against three of our subsidiaries in addition to any civil tax penalties and the financial claim.

On July 2, 2014, the Norwegian district court in Oslo acquitted our three subsidiaries, two external tax attorneys and an external tax advisor of all criminal charges related to the disclosures in our Norwegian tax returns for the years 1999 through 2002 and statutory financial statements for the years ended December 31, 1996 through 2001. On July 16, 2014, the Norwegian authorities dropped the financial claim of NOK 1.8 billion, equivalent to approximately $223 million, against two of our subsidiaries, fully closing this matter, and on the same date, filed an appeal with respect to the following charges: (a) disclosures in our Norwegian tax returns related to a dividend payment in 2001, (b) disclosures in our Norwegian tax returns related to an intercompany rig sale in 1999 and (c) certain inaccuracies in Norwegian statutory financial statements for the years ended December 31, 1996 through 2001. We believe our Norwegian tax returns are materially correct as filed, and we intend to continue to vigorously contest any assertions to the contrary by the Norwegian civil and criminal authorities in connection with the various transactions being investigated. An unfavorable outcome on the Norwegian civil or criminal tax matters could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Brazil tax investigations—Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. In December 2005, the Brazilian tax authorities issued an aggregate tax assessment of BRL 723 million, equivalent to approximately $226 million, including a 75 percent penalty and interest. On January 25, 2008, we filed a protest letter with the Brazilian tax authorities, and we are currently engaged in the appeals process. On May 19, 2014, with respect to our Brazilian income tax returns for the years 2009 and 2010, the Brazilian tax authorities issued an aggregate tax assessment of BRL 126 million, equivalent to approximately $39 million, including a 75 percent penalty and interest. On June 18, 2014, we filed a protest letter with the Brazilian tax authorities. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. An unfavorable outcome on these proposed assessments could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Other tax matters—We conduct operations through our various subsidiaries in a number of countries throughout the world. Each country has its own tax regimes with varying nominal rates, deductions, employee contribution requirements and tax attributes. From time to time, we may identify changes to previously evaluated tax positions that could result in adjustments to our recorded assets and liabilities. Although we are unable to predict the outcome of these changes, we do not expect the effect, if any, resulting from these adjustments to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 7—Discontinued Operations

Summarized results of discontinued operations

The summarized results of operations included in income from discontinued operations were as follows (in millions):

	Three months ended March 31,
	2015			2014
Operating revenues	$	—		$	108
Operating and maintenance expense		(1	)		(104	)
Loss on disposal of assets in discontinued operations, net		—			(10	)
Loss from discontinued operations before income tax expense		(1	)		(6	)
Income tax expense		(1	)		(2	)
Loss from discontinued operations, net of tax	$	(2	)	$	(8	)

Standard jackup and swamp barge contract drilling services

Overview—In September 2012, in connection with our efforts to dispose of non-strategic assets and to reduce our exposure to low-specification drilling units, we committed to a plan to discontinue operations associated with the standard jackup and swamp barge asset groups, components of our contract drilling services operating segment.

Sale transactions with Shelf Drilling—In November 2012, we completed the sale of 38 drilling units to Shelf Drilling Holdings, Ltd. (“Shelf Drilling”). For a transition period following the completion of the sale transactions, we agreed to continue to operate a substantial portion of the standard jackups under operating agreements with Shelf Drilling and to provide certain other transition services to Shelf Drilling. Under the operating agreements, we agreed to remit the collections from our customers under the associated drilling contracts to Shelf Drilling, and Shelf Drilling agreed to reimburse us for our direct costs and expenses incurred while operating the standard jackups on behalf of Shelf Drilling with certain exceptions. Amounts due to Shelf Drilling under the operating agreements and transition services agreement may be contractually offset against amounts due from Shelf Drilling. The costs to us for providing such operating and transition services, including allocated indirect costs, have exceeded the amounts we receive from Shelf Drilling for providing such services.

Under the operating agreements, we agreed to continue to operate these standard jackups on behalf of Shelf Drilling for periods ranging from nine months to 27 months, until expiration or novation of the underlying drilling contracts by Shelf Drilling. As of March 31, 2015, we no longer operated drilling units for Shelf Drilling. Until the expiration or novation of such drilling contracts, we retained possession of the materials and supplies associated with the standard jackups that we operated under the operating agreements. In the three months ended March 31, 2015 and 2014, we received cash proceeds of $2 million and $3 million, respectively, associated with the sale of equipment and materials and supplies to Shelf Drilling upon expiration or novation of the drilling contracts. Under a transition services agreement, we provided certain transition services through May 2014.

For a period through November 2015, we agreed to provide to Shelf Drilling up to $125 million of financial support by maintaining letters of credit, surety bonds and guarantees for various contract bidding and performance activities associated with the drilling units sold to Shelf Drilling and in effect at the closing of the sale transactions. At the time of the sale transactions, we had $113 million of outstanding letters of credit, issued under our committed and uncommitted credit lines, in support of rigs sold to Shelf Drilling. Included within the $125 million maximum amount, we agreed to provide up to $65 million of additional financial support in connection with any new drilling contracts related to such drilling units. Shelf Drilling is required to reimburse us in the event that any of these instruments are called. At March 31, 2015 and December 31, 2014, we had $79 million and $91 million, respectively, of outstanding letters of credit, issued under our committed and uncommitted credit lines, in support of drilling units sold to Shelf Drilling. See Note 13—Commitments and Contingencies.

Other dispositions—During the three months ended March 31, 2014, we recognized a net gain of $1 million, which had no tax effect, related to the disposal of assets unrelated to rig sales.

Drilling management services

Overview—In February 2014, in connection with our efforts to discontinue non-strategic operations, we completed the sale of ADTI, which performs drilling management services in the North Sea. As a result of the sale, we reclassified the results of operations of our drilling management services operating segment to discontinued operations for all periods presented.

Disposition—In the three months ended March 31, 2014, we received net cash proceeds of $11 million and recognized a net loss of $11 million ($0.03 per diluted share), which had no tax effect, associated with the sale of the drilling management services business. We also agreed to provide a $15 million working capital line of credit to the buyer through March 2016. We earn interest on the outstanding borrowings at a fixed rate of 8.3 percent per annum, payable quarterly. At March 31, 2015 and December 31, 2014, ADTI had borrowings of $15 million outstanding under the working capital line of credit, recorded in other assets.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 8—Earnings (Loss) Per Share

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

	Three months ended March 31,
	2015						2014
	Basic			Diluted			Basic			Diluted
Numerator for earnings (loss) per share
Income (loss) from continuing operations attributable to controlling interest	$	(481	)	$	(481	)	$	464		$	464
Undistributed earnings allocable to participating securities		—			—			(4	)		(4	)
Income (loss) from continuing operations available to shareholders	$	(481	)	$	(481	)	$	460		$	460

Denominator for earnings (loss) per share
Weighted-average shares outstanding		363			363			361			361
Effect of stock options and other share-based awards		—			—			—			—
Weighted-average shares for per share calculation		363			363			361			361

Per share earnings (loss) from continuing operations	$	(1.32	)	$	(1.32	)	$	1.27		$	1.27

In the three months ended March 31, 2015 and 2014, we excluded 5.0 million and 2.3 million share-based awards, respectively, from the calculation since the effect would have been anti-dilutive.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 9—Drilling Fleet

Construction work in progress—For the three months ended March 31, 2015 and 2014, the changes in our construction work in progress, including capital expenditures and capitalized interest, were as follows (in millions):

	Three months ended March 31,
	2015				2014
Construction work in progress, at beginning of period	$	2,451		$	2,710

Newbuild construction program
Deepwater Invictus (a) (b)		—			442
Deepwater Asgard (a) (b)		—			230
Deepwater Thalassa (c)		25			32
Deepwater Proteus (c)		9			6
Deepwater Conqueror (d)		18			80
Deepwater Pontus (c)		18			79
Deepwater Poseidon (c)		6			24
Ultra-Deepwater drillship TBN1 (e)		2			27
Transocean Cassiopeia (f)		1			1
Ultra-Deepwater drillship TBN2 (e)		—			27
Transocean Centaurus (f)		1			1
Transocean Cepheus (f)		1			1
Transocean Cetus (f)		1			1
Transocean Circinus (f)		1			1
Other construction projects and capital additions		118			179
Total capital expenditures		201			1,131
Changes in accrued capital expenditures		(22	)		(48	)

Property and equipment placed into service
Other property and equipment		(91	)		(178	)
Construction work in progress, at end of period	$	2,539		$	3,615

_____________________________

(a)	The accumulated construction costs of this rig are no longer included in construction work in progress, as the construction project had been completed as of March 31, 2015.

(b)

The Ultra-Deepwater drillships Deepwater Invictus and Deepwater Asgard, commenced operations in July 2014 and August 2014, respectively. The total carrying amount included capitalized costs of $272 million, representing the estimated fair value of construction in progress acquired in connection with our acquisition of Aker Drilling ASA in October 2011.

(c)

Deepwater Thalassa, Deepwater Proteus, Deepwater Pontus and Deepwater Poseidon, four newbuild Ultra-Deepwater drillships under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, are expected to commence operations in the first quarter of 2016, the third quarter of 2016, the first quarter of 2017 and the second quarter of 2017, respectively.

(d)	Deepwater Conqueror, a newbuild Ultra-Deepwater drillship under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, is expected to commence operations in the fourth quarter of 2016.

(e)	Our two unnamed dynamically positioned Ultra-Deepwater drillships under construction at the Jurong Shipyard PTE Ltd. in Singapore do not yet have drilling contracts and are expected to be delivered in the second quarter of 2017 and the first quarter of 2018, respectively.

(f)

Transocean Cassiopeia, Transocean Centaurus, Transocean Cepheus, Transocean Cetus and Transocean Circinus, five Keppel FELS Super B 400 Bigfoot class design newbuild High-Specification Jackups under construction at Keppel FELS’ shipyard in Singapore do not yet have drilling contracts and are expected to be delivered in the first quarter of 2018, the third quarter of 2018, the first quarter of 2019, the third quarter of 2019 and the first quarter of 2020, respectively. These delivery expectations reflect our decision to delay delivery in consideration of existing market conditions.

Dispositions—During the three months ended March 31, 2015, in connection with our efforts to dispose of non-strategic assets, we completed the sale of the Deepwater Floater Discoverer Seven Seas and the Midwater Floater C. Kirk Rhein, Jr. along with related equipment, and in the three months ended March 31, 2015, we received aggregate net cash proceeds of $5 million. During the three months ended March 31, 2014, in connection with our efforts to dispose of non-strategic assets, we completed the sale of the High-Specification Jackup GSF Monitor along with related equipment, and in the three months ended March 31, 2014, we received net cash proceeds of $83 million. In the three months ended March 31, 2015 and 2014, we received cash proceeds of $2 million and $8 million, respectively, and recognized an aggregate net loss of $9 million and $3 million, respectively, associated with the disposal of certain corporate assets and unrelated rig equipment.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

During the three months ended March 31, 2015, we committed to a plan to sell the Ultra-Deepwater Floater Deepwater Expedition, the Deepwater Floaters Sedco 707 and Transocean Rather and the Midwater Floaters GSF Aleutian Key, GSF Arctic III and Transocean Legend, along with related equipment. At March 31, 2015, the aggregate carrying amount of our assets held for sale was $23 million, including the Ultra-Deepwater Floater Deepwater Expedition, the Deepwater Floaters Sedco 707, Sedco 710, Sovereign Explorer and Transocean Rather and the Midwater Floaters Falcon 100, GSF Aleutian Key, GSF Arctic I, GSF Arctic III, J.W. McLean, Sedco 601, Sedco 700, Sedneth 701 and Transocean Legend, along with related equipment. At December 31, 2014, the aggregate carrying amount of our assets held for sale was $25 million, including an aggregate carrying amount of $23 million for the Deepwater Floaters Discoverer Seven Seas, Sedco 710 and Sovereign Explorer and the Midwater Floaters C. Kirk Rhein, Jr., Falcon 100, GSF Arctic I, J.W. McLean, Sedco 601, Sedco 700 and Sedneth 701, along with related equipment, and an aggregate carrying amount of $2 million for the then remaining assets of our discontinued operations.

See Note 5—Impairments, Note 7—Discontinued Operations and Note 18—Subsequent Events.

Note 10—Debt

Debt, net of unamortized discounts, premiums and fair value adjustments, was comprised of the following (in millions):

	March 31, 2015		December 31, 2014
4.95% Senior Notes due November 2015 (a)	$	896	$	898
5.05% Senior Notes due December 2016 (a)		1,000		999
2.5% Senior Notes due October 2017 (a)		749		748
Eksportfinans Loans due January 2018		288		369
6.00% Senior Notes due March 2018 (a)		1,004		1,001
7.375% Senior Notes due April 2018 (a)		247		247
6.50% Senior Notes due November 2020 (a)		921		911
6.375% Senior Notes due December 2021 (a)		1,199		1,199
3.8% Senior Notes due October 2022 (a)		746		745
7.45% Notes due April 2027 (a)		97		97
8% Debentures due April 2027 (a)		57		57
7% Notes due June 2028		309		309
Capital lease contract due August 2029		609		615
7.5% Notes due April 2031 (a)		599		598
6.80% Senior Notes due March 2038 (a)		999		999
7.35% Senior Notes due December 2041 (a)		300		300
Total debt		10,020		10,092
Less debt due within one year
4.95% Senior Notes due November 2015 (a)		896		898
Eksportfinans Loans due January 2018		106		114
Capital lease contract due August 2029		22		21
Total debt due within one year		1,024		1,033
Total long-term debt	$	8,996	$	9,059

_____________________________

(a)

Transocean Inc., a 100 percent owned subsidiary of Transocean Ltd., is the issuer of the notes and debentures, which have been guaranteed by Transocean Ltd. Transocean Ltd. has also guaranteed borrowings under the Five-Year Revolving Credit Facility. Transocean Ltd. and Transocean Inc. are not subject to any significant restrictions on their ability to obtain funds from their consolidated subsidiaries by dividends, loans or return of capital distributions. See Note 17—Condensed Consolidating Financial Information.

Scheduled maturities—At March 31, 2015, the scheduled maturities of our debt were as follows (in millions):

Twelve months ending March 31,
2016	$	1,022
2017		1,131
2018		1,858
2019		277
2020		33
Thereafter		5,675
Total debt, excluding unamortized discounts, premiums and fair value adjustments		9,996
Total unamortized discounts, premiums and fair value adjustments, net		24
Total debt	$	10,020

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Five-Year Revolving Credit Facility—In June 2014, we entered into an amended and restated bank credit agreement, which established a $3.0 billion unsecured five-year revolving credit facility, that is scheduled to expire on June 28, 2019 (the “Five-Year Revolving Credit Facility”). 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 to tangible capitalization ratio of 0.6 to 1.0. Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default, borrowings are guaranteed by Transocean Ltd. and may be prepaid in whole or in part without premium or penalty.

We may borrow under the Five-Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate (“LIBOR”) plus a margin (the “Five-Year Revolving Credit Facility Margin”), which ranges from 1.125 percent to 2.0 percent based on the credit rating of our non-credit enhanced senior unsecured long-term debt (“Debt Rating”), or (2) the base rate specified in the credit agreement plus the Five-Year Revolving Credit Facility Margin, less one percent per annum. Throughout the term of the Five-Year Revolving Credit Facility, we pay a facility fee on the daily unused amount of the underlying commitment which ranges from 0.15 percent to 0.35 percent depending on our Debt Rating. In the three months ended March 31, 2015, our Debt Rating was reduced, and as a result, effective March 19, 2015, the Five-Year Revolving Credit Facility Margin increased to 1.75 percent from 1.5 percent and the facility fee increased to 0.275 percent from 0.225 percent. At March 31, 2015, we had no borrowings outstanding or letters of credit issued, and we had $3.0 billion of available borrowing capacity under the Five-Year Revolving Credit Facility.

5.05% Senior Notes, 6.375% Senior Notes and 7.35% Senior Notes—In December 2011, we issued $1.0 billion aggregate principal amount of 5.05% Senior Notes due December 2016 (the “5.05% Senior Notes”), $1.2 billion aggregate principal amount of 6.375% Senior Notes due December 2021 (the “6.375% Senior Notes”) and $300 million aggregate principal amount of 7.35% Senior Notes due December 2041 (the “7.35% Senior Notes”). The interest rates for the notes are subject to adjustment from time to time upon a change to our Debt Rating. In the three months ended March 31, 2015, our Debt Rating was reduced and, as a result, effective June 15, 2015, the interest rates on the 5.05% Senior Notes, the 6.375% Senior Notes and the 7.35% Senior Notes will increase 0.5 percent from the stated rate to 5.55 percent, 6.875 percent and 7.85 percent, respectively. At March 31, 2015, the aggregate outstanding principal amount of the 5.05% Senior Notes, the 6.375% Senior Notes and the 7.35% Senior Notes was $1.0 billion, $1.2 billion and $300 million, respectively.

2.5% Senior Notes and 3.8% Senior Notes—In September 2012, we issued $750 million aggregate principal amount of 2.5% Senior Notes due October 2017 (the “2.5% Senior Notes”) and $750 million aggregate principal amount of 3.8% Senior Notes due October 2022 (the “3.8% Senior Notes”). The interest rates for the notes are subject to adjustment from time to time upon a change to our Debt Rating. In the three months ended March 31, 2015, our Debt Rating was reduced and, as a result, effective April 15, 2015, the interest rates on the 2.5% Senior Notes and the 3.8% Senior Notes will increase 0.5 percent from the stated rate to 3.0 percent and 4.3 percent, respectively. At March 31, 2015, the aggregate outstanding principal amount of the 2.5% Senior Notes and the 3.8% Senior Notes was $750 million each.

Eksportfinans Loans—We have borrowings under the Loan Agreement dated September 12, 2008 and the Loan Agreement dated November 18, 2008, between one of our subsidiaries and Eksportfinans ASA (together, the “Eksportfinans Loans”). At March 31, 2015 and December 31, 2014, aggregate borrowings of NOK 2.3 billion and NOK 2.8 billion, respectively, equivalent to approximately $290 million and $370 million, respectively, were outstanding under the Eksportfinans Loans.

The Eksportfinans Loans require collateral to be held by a financial institution through expiration (the “Aker Restricted Cash Investments”). At March 31, 2015 and December 31, 2014, the aggregate principal amount of the Aker Restricted Cash Investments was NOK 2.3 billion and NOK 2.8 billion, respectively, equivalent to approximately $290 million and $370 million, respectively.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 11—Derivatives and Hedging

In March and April 2014, we entered into interest rate swaps, which are designated and qualify as a fair value hedge, to reduce our exposure to changes in the fair value of the 6.0% Senior Notes due March 2018 and the 6.5% Senior Notes due November 2020, respectively. The interest rate swaps have aggregate notional amounts equal to the corresponding face values of the hedged instruments and have stated maturities that coincide with those of the hedged instruments. We have determined that the hedging relationships qualify for and we have applied the shortcut method of accounting, under which the interest rate swaps are considered to have no ineffectiveness and no ongoing assessment of effectiveness is required. Accordingly, changes in the fair value of the interest rate swaps recognized in interest expense offset the changes in the fair value of the hedged fixed-rate notes.

At March 31, 2015, the aggregate notional amounts and the weighted average interest rates associated with our derivatives designated as hedging instruments were as follows (in millions, except weighted average interest rates):

	Pay						Receive
	Aggregate notional amount		Fixed or variable rate	Weighted average rate			Aggregate notional amount		Fixed or variable rate	Weighted average rate
Interest rate swaps, fair value hedge	$	1,500	Variable		4.69	%	$	1,500	Fixed		6.25	%

The balance sheet classification and aggregate carrying amount of our derivatives designated as hedging instruments, measured at fair value, were as follows (in millions):

		March 31,		December 31,
	Balance sheet classification	2015		2014
Interest rate swaps, fair value hedges	Other current assets	$	6	$	4
Interest rate swaps, fair value hedges	Other assets		27		11

Note 12—Postemployment Benefit Plans

Defined benefit pension plans and other postretirement employee benefit plans

Effective January 1, 2015, we froze benefits of our qualified defined benefit pension plan in the U.S., which covers substantially all U.S. employees, and one of our unfunded supplemental benefit plans. Including these plans, we have several frozen defined benefit pension plans, both funded and unfunded, that cover certain current and former U.S. employees and certain former directors of our predecessors (the “U.S. Plans”). We also have various defined benefit plans in the U.K., Norway, Nigeria, Egypt and Indonesia that cover certain current and former employees in those areas (the “Non-U.S. Plans”). Additionally, we maintain several unfunded contributory and noncontributory other postretirement employee benefit plans covering substantially all of our U.S. employees (the “OPEB Plans”).

The components of net periodic benefit costs, before tax, and funding contributions for these plans were as follows (in millions):

	Three months ended March 31, 2015											Three months ended March 31, 2014
	U.S. Plans			Non-U.S. Plans			OPEB Plans		Total			U.S. Plans			Non-U.S. Plans			OPEB Plans		Total
Net periodic benefit costs
Service cost	$	1		$	7		$	—	$	8		$	11		$	8		$	—	$	19
Interest cost		16			5			1		22			17			6			1		24
Expected return on plan assets		(22	)		(6	)		—		(28	)		(19	)		(7	)		—		(26	)
Actuarial losses, net		3			2			—		5			5			1			—		6
Net periodic benefit costs	$	(2	)	$	8		$	1	$	7		$	14		$	8		$	1	$	23

Funding contributions	$	—		$	9		$	2	$	11		$	1		$	9		$	—	$	10

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 13—Commitments and Contingencies

Macondo well incident settlement obligations

On April 22, 2010, the Ultra-Deepwater Floater Deepwater Horizon sank after a blowout of the Macondo well caused a fire and explosion on the rig. Eleven persons were declared dead and others were injured as a result of the incident. At the time of the explosion, Deepwater Horizon was located approximately 41 miles off the coast of Louisiana in Mississippi Canyon Block 252 and was contracted to an affiliate of BP plc (together with its affiliates, “BP”).

On January 3, 2013, we reached an agreement with the U.S. Department of Justice (“DOJ”) to resolve certain outstanding civil and potential criminal charges against us arising from the Macondo well incident. As part of this resolution, we agreed to a guilty plea (“Plea Agreement”) and a civil consent decree (“Consent Decree”) by which, among other things, we agreed to pay $1.4 billion in fines, recoveries and civil penalties, excluding interest, in scheduled payments through February 2017. In the three months ended March 31, 2015 and 2014, we paid an aggregate installment of $264 million and $472 million, respectively, including interest, towards our obligations under the Plea Agreement and Consent Decree.

Macondo well incident contingencies

Overview—We have recognized a liability for estimated loss contingencies associated with litigation and investigations resulting from the incident that we believe are probable and for which a reasonable estimate can be made. At March 31, 2015 and December 31, 2014, the liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made was $426 million, recorded in other current liabilities. The litigation and investigations also give rise to certain loss contingencies that we believe are either reasonably possible or probable but for which we do not believe a reasonable estimate can be made. Although we have not recognized a liability for such loss contingencies, these contingencies could result in liabilities that we ultimately recognize.

We have also recognized an asset associated with the portion of our estimated losses, primarily related to the personal injury and fatality claims of our crew and vendors, that we believe is probable of recovery from insurance. At March 31, 2015 and December 31, 2014, the insurance recoverable asset was $10 million, recorded in other assets. Although we have available policy limits that could result in additional amounts recoverable from insurance, recovery of such additional amounts is not probable and we are not currently able to estimate such amounts (see “—Insurance coverage”). Our estimates involve a significant amount of judgment. As a result of new information or future developments, we may increase our estimated loss contingencies arising out of the Macondo well incident or reduce our estimated recoveries from insurance, and the resulting losses could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Multidistrict litigation proceeding—Most of the Macondo well related claims have been consolidated by the U.S. Judicial Panel on Multidistrict Litigation and transferred to the U.S. District Court for the Eastern District of Louisiana (the “MDL Court”) for pretrial purposes if they were not filed originally in that court. These claims include, inter alia, claims by private parties represented by the Plaintiffs’ Steering Committee (the “PSC”), claims by state and local governments, and the claims of the U.S. As of March 31, 2015, the MDL Court has completed two phases of a trial, and additional litigation is ongoing.

Phase One trial—The MDL Court held the Phase One trial between February and April 2013, and entered its Findings of Fact and Conclusions of Law (the “Phase One Ruling”) on September 4, 2014. The trial addressed the claims, cross claims, and counter-claims asserted in our petition to limit liability under the Limitation of Liability Act and the claims asserted by the DOJ in its civil complaint against various defendants. The trial focused on fault issues, including negligence and gross negligence; other bases of liability of the various defendants with respect to the cause of the blowout and the initiation of the oil spill; and fault allocation among the defendants. The Phase One Ruling concluded that BP was grossly negligent and reckless and 67 percent at fault for the blowout, explosion, and spill; that Transocean was negligent and 30 percent at fault; and that Halliburton Company (“Halliburton”) was negligent and three percent at fault.

The finding that Transocean was negligent, but not grossly negligent, means that we are not liable for punitive damages. Because the MDL Court found we were not grossly negligent, it concluded that BP’s contractual agreement to indemnify us for compensatory damages caused by pollution that did not originate on or above the surface of the water is valid and enforceable. The MDL Court also ruled that BP’s contractual agreement to release its own claims against us is valid and enforceable. This release bars the PSC from pursuing claims that have purportedly been assigned to it by BP in a settlement reached between BP and the PSC prior to the Phase One trial (see “—Impact of BP/PSC settlement on pending claims").

The MDL Court’s rulings include a number of Transocean-specific findings and conclusions. The MDL Court found that the Deepwater Horizon’s crew was negligent in its conduct of a negative pressure test, which was intended, among other things, to test the integrity of the cement in the well, and in certain well control decisions in the hour before the blowout. The MDL Court found three other bases for imposing negligence liability on Transocean as follows: (1) the crew’s improper diversion of fluids that had entered the riser to the rig’s mud-gas separator instead of overboard; (2) the crew’s failure to properly maintain the blowout preventer; and (3) the master’s failure to timely activate the Emergency Disconnect System as a consequence of an ambiguous command structure. The MDL Court held that these three failures were “within Transocean’s privity and knowledge.” As a result, the MDL Court held that Transocean Holdings LLC, Transocean Deepwater Inc., and Transocean Offshore Deepwater Drilling Inc., three of our wholly owned subsidiaries, could not limit their liability under the Limitation of Liability Act. Under the MDL Court’s ruling, however, we are entitled to indemnity from BP for any compensatory damages caused by pollution that did not originate on or above the surface of the water.

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The MDL Court also concluded that we were an “operator” of the Macondo well for purposes of 33 U.S.C. § 2704(c)(3), a provision of the Oil Pollution Act (“OPA”) that permits government entities to recover removal costs by owners and operators of a facility or vessel that caused a discharge. The MDL Court, however, reiterated that “Transocean’s liability to government entities for removal costs is ultimately shifted to BP by virtue of contractual indemnity.”

The MDL Court released two Transocean entities from liability under general maritime law. First, the MDL Court held that Transocean Ltd. was not liable under general maritime law. The MDL Court also granted a motion for judgment on partial findings by Triton Asset Leasing GmbH, the entity that owned Deepwater Horizon and our wholly owned subsidiary, on the grounds that any negligence or unseaworthiness that caused the blowout arose after the bareboat charter commenced.

Following the Phase One Ruling, BP filed a motion to amend the Phase One Findings of Fact and Conclusions of Law, alter or amend the judgment, or for a new trial, alleging the MDL Court made errors in its conclusions about the causes of the failure of the cement in the well. The MDL Court denied the motion.

The Phase One Ruling did not quantify damages or result in a final monetary judgment. However, because it is a determination of liability under maritime law, the Phase One Ruling is appealable, and BP, the PSC, Transocean, Halliburton and the State of Alabama have all appealed or cross-appealed aspects of the ruling. The U.S. Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) has issued an order providing that BP and the PSC must file their opening briefs by May 11, 2015. Transocean, Halliburton and the State of Alabama must file their opening briefs within 30 days following the BP and the PSC opening brief filings. Parties must file opposition and reply briefs thereafter. We can provide no assurances as to the outcome of these appeals, as to the timing of any further rulings, or that we will not enter into additional settlements as to some or all of the matters related to the Macondo well incident, including those to be determined at a trial, or the timing or terms of any such settlements.

Phase Two trial—The Phase Two of the trial occurred between September 30, 2013 and October 17, 2013. The first segment of the trial addressed BP’s conduct related to stopping the release of hydrocarbons after April 22, 2010, and the second segment addressed quantification of the amount of oil discharged. We participated in the first segment of the trial, but were not a party to the second segment because the ruling as to the quantification of oil primarily relates to setting the statutory maximum civil penalty under the CWA, and we have settled the DOJ’s CWA penalty claim against us. On January 15, 2015, the MDL Court issued its Findings of Facts and Conclusions of Law (the “Phase Two Ruling”).

As to the first segment of the trial, the MDL Court ruled that BP was not grossly negligent, reckless, willful or wanton in its source control planning before the spill. The MDL Court declined to decide whether BP was negligent in its planning because it ruled that any negligence finding would not change its fault determinations from Phase One. The MDL Court also found that it had not been shown that BP’s misrepresentation about the flow rate from the well delayed the capping of the well or adversely affected source control, or that post-blowout source control decisions were unreasonable.

As to the second segment of the trial, the MDL Court found that four million barrels of oil discharged during the spill. After deducting the barrels that were collected, the MDL Court found that, for purposes of calculating the maximum CWA civil penalty that may be imposed on BP and Anadarko, 3.19 million barrels of oil discharged.

Because the Phase One Ruling upheld BP’s indemnity obligation to us, the Phase Two Ruling had no adverse effect on our litigation posture. Several parties have filed notices of appeal from the Phase Two Ruling. Transocean has not appealed the ruling. A briefing schedule has not yet been set for the appeal.

Pending claims—As of March 31, 2015, approximately 1,405 actions or claims were pending against us, along with other unaffiliated defendants. These claims were originally filed in various state and federal courts, and most have been consolidated in the MDL Court. Additionally, government agencies have initiated investigations into the Macondo well incident. We have categorized below the nature of these claims. We are vigorously defending all claims and pursuing any and all defenses available.

Wrongful death and personal injury claims—As of March 31, 2015, we and certain of our subsidiaries have been named, along with unaffiliated defendants, in nine complaints that were pending in state and federal courts in Louisiana and Texas involving multiple plaintiffs that allege wrongful death and other personal injuries arising out of the Macondo well incident. Nine complaints involve fatalities and 63 complaints seek recovery for bodily injuries. Per the order of the Judicial Panel on Multidistrict Litigation, all claims but one have been centralized for discovery purposes in the MDL Court. The complaints by our employees or representatives of our employees generally allege negligence, unseaworthiness and gross negligence and seek maintenance and cure under the Jones Act and general maritime law and are seeking awards of unspecified economic damages and punitive damages. BP, MI-SWACO, Weatherford International Ltd. and Cameron International Corporation (“Cameron”) and certain of their affiliates, have, based on contractual arrangements, also made indemnity demands upon us with respect to personal injury and wrongful death claims asserted by our employees or representatives of our employees against these entities. See “—Contractual indemnity.”

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Economic loss and punitive damages claims—As of March 31, 2015, we and certain of our subsidiaries were named, along with other unaffiliated defendants, in 982 pending individual complaints as well as 190 putative class-action complaints that were filed in the federal and state courts in Louisiana, Texas, Mississippi, Alabama, Georgia, Kentucky, South Carolina, Tennessee, Florida and possibly other courts. Most of these complaints have been consolidated in the MDL Court. The complaints generally allege, among other things, economic losses as a result of environmental pollution arising out of the Macondo well incident and are based primarily on OPA, state OPA analogues, and/or general maritime law. The plaintiffs are generally seeking awards of unspecified economic, compensatory and punitive damages, as well as injunctive relief. No classes have been certified at this time. Those plaintiffs who have settled their claims against BP as part of BP’s settlement with the PSC have given up their claims for compensatory damages against us, but purport to retain their claims for punitive damages (see “-Impact of BP/PSC settlement on pending claims”).

Cross-claims, counter-claims, and third party claims—Several defendants in the MDL litigation have filed cross-claims or third-party claims against us and certain of our subsidiaries. BP filed a claim seeking contribution under OPA and maritime law and seeking subrogation, and also alleging breach of contract, unseaworthiness, negligence and gross negligence. Through these claims, BP sought to recover from us damages it has paid or may pay arising from the Macondo well incident. BP also sought a declaration that it is not liable in contribution, indemnification, or otherwise to us. BP has assigned some of its claims as part of its settlement with the PSC (see “-Impact of BP/PSC settlement on pending claims”).

Certain other parties, including (a) Anadarko Petroleum Corporation (“Anadarko”), which owned a 25 percent non-operating interest in the Macondo well, (b) MOEX Offshore 2007 LLC (“MOEX”), which owned a 10 percent non-operating interest in the Macondo well, (c) Cameron, the manufacturer and designer of the blowout preventer, and (d) Halliburton, which provided cementing and mud-logging services to the operator have asserted claims seeking indemnity and contribution under various theories. BP has reached settlements with certain parties, including Anadarko, MOEX and Cameron, in which BP has agreed to indemnify those parties for certain liabilities, including compensatory damages.

We have filed cross-claims and counter-claims against BP, Halliburton, Anadarko, MOEX, certain of these parties’ affiliates, the U.S. and certain other third parties. We seek indemnity, contribution, including contribution under OPA, and subrogation under OPA, and have asserted claims for breach of warranty of workmanlike performance, strict liability for manufacturing and design defect, breach of express contract, and damages for the difference between the fair market value of Deepwater Horizon and the amount received from insurance proceeds. The Consent Decree limits our ability to seek indemnification or reimbursement with respect to payments made under the Consent Decree and dismissed our claims against the U.S. We are not pursuing arbitration on the key contractual issues with BP; instead, we are relying on the court to resolve the disputes.

Impact of BP/PSC settlement on pending claims—Before the Phase One trial, in March 2012, BP and the PSC agreed to a partial settlement related primarily to private party environmental and economic loss claims as well as response effort-related claims (the “BP/PSC Settlement”). The BP/PSC Settlement agreement provides that (i) to the extent permitted by law, BP will assign to the settlement class certain of BP’s claims against us for damages, but the settlement class cannot recover from us on those claims unless it is finally determined that we cannot recover such amounts from BP by way of indemnity or any other theory, and (ii) the settlement class releases all claims for compensatory damages against us but purports to retain claims for punitive damages against us. This provision of the settlement became effective on December 8, 2014, when the Supreme Court denied BP’s petition for certiorari seeking review of the trial court’s approval of the settlement. The Phase One Ruling, however, precludes the PSC from recovering on the claims assigned by BP to the settlement class and on the purportedly reserved punitive damages claims (see “-Phase One trial”).

On December 21, 2012, the MDL Court granted final approval of the economic and property damage class settlement between BP and the PSC. Various parties who objected to the BP/PSC Settlement appealed the MDL Court’s final approval of the BP/PSC Settlement to the Fifth Circuit, and BP later appealed rulings challenging the manner in which the settlement has been interpreted by the MDL Court. In the appeals by BP, the Fifth Circuit ordered the MDL Court to reconsider certain rulings governing the method by which lost profits are calculated for businesses claiming economic loss, but the Fifth Circuit otherwise affirmed the district court’s interpretation of the settlement agreement. In the appeal by objectors to the settlement, the Fifth Circuit affirmed the MDL Court’s approval of the settlement. The Fifth Circuit subsequently denied BP’s petitions for rehearing in both appeals. On December 8, 2014, the Supreme Court denied BP’s petition for certiorari.

Impact of Halliburton/PSC settlement on pending claims—On September 2, 2014, Halliburton and the PSC filed a proposed settlement of the PSC’s punitive damages and assigned claims against Halliburton. The proposed agreement purports to reserve the PSC’s rights to continue pursuing assigned or punitive damages claims against us, but the MDL Court’s Phase One Ruling prevents the PSC from pursuing those claims. The proposed agreement also prohibits the PSC from settling any assigned claims against us unless we agree to release Halliburton from any claims for contribution or indemnity for amounts paid under the settlement. The proposed agreement does not impact Halliburton’s cross-claims and counter claims against us. The MDL Court has not yet approved the settlement.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

U.S. Department of Justice claims—On December 15, 2010, the DOJ filed a civil lawsuit against us and certain of our subsidiaries and other unaffiliated defendants. The complaint alleged violations under OPA and the CWA. The CWA claims for both monetary and injunctive relief have been resolved through our Consent Decree with the DOJ. See “—Macondo well incident settlement obligations.”

The Consent Decree did not resolve the rights of the U.S. with respect to other matters, including certain liabilities under OPA for Natural Resource Damages (“NRD”) or for removal costs. The MDL Court has held that we are not a responsible party under OPA for NRD resulting from discharge of oil from the Macondo well below the surface of the water. If this ruling is upheld on appeal, our NRD liability as a responsible party would be limited to damages arising from any discharge on or above the surface of the water. In the Phase One Ruling, the MDL Court also found that Transocean was the “operator” of the Macondo well and was therefore liable for removal costs under 33 U.S.C. § 2704(c)(3), a separate provision of OPA that permits government entities to recover removal costs from owners and operators of a facility or vessel from which oil discharges. However, the MDL Court found that “Transocean’s liability to government entities for removal costs is ultimately shifted to BP by virtue of the contractual indemnity.”

In addition to the civil complaint, the DOJ served us with civil investigative demands on December 8, 2010. These demands were part of an investigation by the DOJ to determine if we made false claims, or false statements in support of claims, in violation of the False Claims Act, in connection with the operator’s acquisition of the leasehold interest in the Mississippi Canyon Block 252, Gulf of Mexico and drilling operations on Deepwater Horizon. The resolution with the DOJ of civil and potential criminal claims did not include potential claims arising from this False Claims Act investigation. As part of the settlement discussions, however, we inquired whether the U.S. intends to pursue any actions under the False Claims Act as discussed below. In response, the DOJ sent us a letter stating that the Civil Division of the DOJ, based on facts then known, was no longer pursuing, and did not have any present intention to pursue any investigation or claims, under the False Claims Act against the various Transocean entities for their involvement in the Macondo well incident.

State and other government claims—Claims have been filed against us by over 200 state, local and foreign governments, including the States of Alabama, Florida, Louisiana, Mississippi and Texas; the Mexican States of Veracruz, Quintana Roo, Tamaulipas and Yucatan; the federal government of Mexico and other local governments by and on behalf of multiple towns and parishes. These governments generally assert claims under OPA, other statutory environmental state claims, general maritime law and various other common law claims. A local government master complaint also was filed in the MDL Court in which cities, municipalities, and other local government entities have joined.

The MDL Court dismissed damages claims brought under state common and statutory law and subsequently dismissed civil penalty claims brought under state statutory law. Certain Louisiana parishes appealed the dismissal of their civil penalty claims brought under Louisiana law. The Fifth Circuit affirmed the MDL Court’s dismissal of these claims, and the Supreme Court denied certiorari.

The state, local and foreign government claims include claims under OPA for economic damages, natural resource damages and removal costs. As noted above, the MDL Court concluded that we were an “operator” of the Macondo well for purposes of OPA. The MDL Court, however, reiterated that “Transocean’s liability to government entities for removal costs is ultimately shifted to BP by virtue of contractual indemnity.”

The OPA claims of the Mexican States of Veracruz, Quintana Roo, Tamaulipas and Yucatan were dismissed for failure to demonstrate that recovery under OPA was authorized by treaty or executive agreement. The MDL Court subsequently granted summary judgment on the Mexican States’ general maritime law claims on the ground that the federal government of Mexico, rather than the Mexican States, had the proprietary interest in the property and natural resources allegedly injured by the spill. The Mexican States have appealed the grant of summary judgment on their general maritime law claims to the Fifth Circuit, and the Fifth Circuit heard arguments on October 27, 2014. The claims of the federal government of Mexico remain pending, but under the Phase One Ruling, we are entitled to indemnity from BP for any compensatory damages caused by pollution that did not originate on or above the surface of the water.

In addition, by letter dated June 21, 2010, the Attorneys General of the 11 Atlantic Coast states of Connecticut, Delaware, Georgia, Maine, Maryland, Massachusetts, New Hampshire, New York, North Carolina, Rhode Island and South Carolina informed us that their states have not sustained any damage from the Macondo well incident but they would like assurances that we will be responsible financially if damages are sustained. We responded to the letter from the Attorneys General and indicated that we intend to fulfill our obligations as a responsible party for any discharge of oil from Deepwater Horizon on or above the surface of the water, and we assume that the operator and other leaseholders will similarly fulfill their obligations under OPA for discharges from the undersea well.

The MDL Court has begun proceeding with respect to Alabama’s compensatory damages claims under OPA and general maritime law. BP has moved to strike Alabama’s demand for a jury trial, and we have joined that motion along with Halliburton. On March 31, 2015, however, the MDL Court denied the motion, ruling that Alabama is entitled to a jury trial on its OPA damages claim.

On November 14, 2014, the MDL Court approved a stipulation between us, Alabama, and BP in which the parties agreed that we would be excused from participating in the Alabama compensatory damages trial and in further pretrial proceedings related to that trial. Pursuant to the stipulation, we agreed not to challenge in any future proceeding the amount of compensatory damages, excluding NRD, that may be determined at the trial. The parties further agreed that the amount of damages determined at trial would fully satisfy Alabama’s compensatory damages claims under OPA and general maritime law, excluding NRD, and that certain issues, including what damages, if any, resulted from above-surface discharge, will not be determined in the Alabama compensatory damages trial.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Natural Resources Damages Assessment—Under OPA, designated state and federal trustees are authorized to undertake a natural resources damages assessment (“NRDA”) to assess potential natural resource injuries resulting from a discharge of oil or the substantial threat of a discharge and response activities and develop and implement a plan for restoration of injured resources, if any. The trustees invite responsible parties to participate in and fund such efforts. As of March 31, 2015, we have received at least 11 such requests from government agencies. We responded to these requests and declined to participate in the funding on the grounds that we are not a responsible party for discharges from the wellhead. The NRDA trustees are proceeding with the NRDA with funding provided by BP.

Citizen suits under environmental statutes—The Center for Biological Diversity (the “Center”), a private environmental group, sued BP, us and certain of our affiliates under multiple federal environmental statutes seeking monetary penalties and injunctive relief. The MDL Court dismissed all of the claims, and in January 2013, the Fifth Circuit affirmed the dismissal with one exception: the Fifth Circuit remanded to the MDL Court the Center’s claim for injunctive relief, but not for penalties, based on BP and Transocean’s alleged failure to make certain reports about the constituents of oil spilled into the U.S. Gulf of Mexico as required by EPCRA.

In April 2014, BP and we moved for summary judgment and the Center moved for partial summary judgment against BP. It did not move for partial summary judgment against us, though it purported to reserve its right to do so in the future. The MDL Court has not indicated when it will rule on the motions.

Federal securities claims—On September 30, 2010, a proposed federal securities class action was filed in the U.S. District Court for the Southern District of New York, naming us, former chief executive officers of Transocean Ltd. and one of our acquired companies as defendants. In the action, a former shareholder of the acquired company alleged that the joint proxy statement relating to our shareholder meeting in connection with the merger with the acquired company violated Section 14(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The plaintiff claimed that the acquired company’s shareholders received inadequate consideration for their shares as a result of the alleged violations and sought compensatory and rescissory damages and attorneys’ fees on behalf of the plaintiff and the proposed class members. In connection with this action, we are obligated to pay the defense fees and costs for the individual defendants, which may be covered by our directors’ and officers’ liability insurance, subject to a deductible. On March 11, 2014, the District Court for the Southern District of New York dismissed the claims as time-barred. Plaintiffs appealed to the U.S. Court of Appeals for the Second Circuit and filed an opening brief on December 19, 2014. On February 17, 2015, defendants filed their brief in opposition. On March 3, 2015, plaintiffs filed their reply brief. Oral argument has not yet been scheduled.

Wreck removal—By letter dated December 6, 2010, the U.S. Coast Guard requested that we formulate and submit a comprehensive oil removal plan to remove any diesel fuel that can be recovered from Deepwater Horizon. We have conducted a survey of the rig wreckage and have confirmed that no diesel fuel remains on the rig. The U.S. Coast Guard has not requested that we remove the rig wreckage from the sea floor. In February 2013, the U.S. Coast Guard submitted a request seeking analysis and recommendations as to the potential life of the rig’s riser and cofferdam, which are resting on the seafloor and potential remediation or removal options. We have insurance coverage for wreck removal for up to 25 percent of Deepwater Horizon’s insured value, or $140 million, with any excess wreck removal liability generally covered to the extent of our remaining excess liability limits.

Insurance coverage—At the time of the Macondo well incident, our excess liability insurance program offered aggregate insurance coverage of $950 million, excluding a $15 million deductible and a $50 million self-insured layer through our wholly owned captive insurance subsidiary. This excess liability insurance coverage consisted of a first and a second layer of $150 million each, a third and fourth layer of $200 million each and a fifth layer of $250 million. The first four excess layers have similar coverage and contractual terms, while the $250 million fifth layer is on a different policy form, which varies to some extent from the underlying coverage and contractual terms. Generally, we believe that the policy forms for all layers include coverage for personal injury and fatality claims, subject to reasonableness determinations, of our crew and vendors, for which indemnity agreements are in place as to the latter, actual and compensatory damages, punitive damages and related legal defense costs. The policy forms for the first four excess layers provide coverage for fines; however, we do not expect payments deemed to be criminal in nature to be covered by any of the layers.

In May 2010, we received notice from BP claiming an entitlement to unlimited additional insured status under our excess liability insurance program. Our insurers have also received notices from Anadarko and MOEX advising of their intent to preserve any rights they may have to our insurance policies as an additional insured under the drilling contract. In response, our wholly owned captive insurance subsidiary and our first four excess layer insurers filed declaratory judgment actions in the Houston Division of the U.S. District Court for the Southern District of Texas in May 2010 seeking a declaration that they have limited additional insured obligations to BP. We are parties to the declaratory judgment actions, which were transferred to the MDL Court for discovery and other purposes. On November 15, 2011, the MDL Court ruled that BP’s coverage rights are limited to the scope of our indemnification of BP in the drilling contract. A final judgment was entered against BP, Anadarko and MOEX, and BP appealed. On March 1, 2013, the Fifth Circuit issued an opinion reversing the decision of the MDL Court, and holding that BP is an unrestricted additional insured under the policies issued by our wholly owned captive insurance company and the first four excess layer insurers. We and the insurers filed petitions for rehearing with the Fifth Circuit. On August 29, 2013, the Fifth Circuit withdrew the March 1, 2013 opinion and certified certain insurance law questions to the Texas Supreme Court. The Texas Supreme Court accepted certification of these questions, and the oral argument was held on September 16, 2014. On February 13, 2015, the Texas Supreme Court issued its answer to one of the Fifth Circuit’s questions by determining that BP is not entitled to coverage under certain of our insurance policies for damages arising from subsurface pollution because BP assumed, and we did not assume, liability for such claims. BP is seeking rehearing by the Texas Supreme Court.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

We believe that additional insured coverage for BP, Anadarko or MOEX under the $250 million fifth layer of our insurance program is limited to the scope of our indemnification of BP under the drilling contract. While we cannot predict the outcome of any subsequent proceedings in the Texas Supreme Court or the Fifth Circuit, we do not expect them to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

On June 17, 2011 and July 31, 2012, our first layer and second layer of excess insurers, respectively, each representing $150 million of insurance coverage, filed interpleader actions. On February 14, 2013, the third and fourth layers, each representing $200 million of insurance coverage, filed interpleader actions substantially similar to those of the first and second layers. The insurers contend that they face multiple, and potentially competing, claims to the relevant insurance proceeds. In these actions, the insurers effectively ask the court to manage disbursement of the funds to the alleged claimants, as appropriate, and discharge the insurers of any additional liability. The parties to the first and second excess insurer interpleader actions have executed protocol agreements to facilitate the reimbursement and funding of settlements of personal injury and fatality claims of our crew and vendors (collectively, “crew claims”) using insurance funds and claims were submitted to the court for review. Following the court’s determination and approval of the amounts to be paid by the insurers with respect to the crew claims submitted by the parties, the first layer of excess insurers made reimbursement payments to the parties for crew claims during the years ended December 31, 2013 and 2014. Additional claims may be submitted to the court for a determination and approval of the amounts insurers owe. Parties to the third and fourth excess insurer interpleader actions have agreed to adjourn the deadline for responses to the pleadings to an unspecified date that will follow a decision in another action that pertains to our insurance.

Contractual indemnity—Under our drilling contract for Deepwater Horizon, BP has agreed, among other things, to assume responsibility for and defend, release and indemnify us from any loss, expense, claim, fine, penalty or liability for pollution or contamination, including control and removal thereof, arising out of or connected with operations under the contract other than those for pollution or contamination originating on or above the surface of the water from hydrocarbons or other specified substances within our control and possession, as to which we agreed to assume responsibility and protect, release and indemnify BP. Although we do not believe it is applicable to the Macondo well incident, we also agreed to indemnify and defend BP up to a limit of $15 million for claims for loss or damage to third parties arising from pollution caused by the rig while it is off the drilling location, while the rig is underway or during drive off or drift off of the rig from the drilling location. BP has also agreed, among other things, (i) to defend, release and indemnify us against loss or damage to the reservoir, and loss of property rights to oil, gas and minerals below the surface of the earth and (ii) to defend, release and indemnify us and bear the cost of bringing the well under control in the event of a blowout or other loss of control. We agreed to defend, release and indemnify BP for personal injury and death of our employees and the employees of our contractors while BP agreed to defend, release and indemnify us for personal injury and death of its employees and the employees of its contractors, other than us. We also agreed to defend, release and indemnify BP for damages to the rig and equipment, including salvage or removal costs.

BP has sought to avoid its indemnification obligations. On January 26, 2012, the MDL Court ruled that the drilling contract requires BP to indemnify us for compensatory damages sought by third parties related to pollution that did not originate from the rig on or above the surface of the water, regardless of whether the claim is the result of our strict liability, negligence, or gross negligence. The MDL Court ruled that BP had a contractual duty to defend us, but that the duty to defend only required BP to reimburse our defense costs after there is a judicial determination on the merits. The MDL Court did not rule on the scope of BP’s duty to defend, although it did rule that BP is not obligated to pay the attorneys’ fees incurred by us in proving our right to indemnification. The MDL Court also held that BP does not owe us indemnity for civil penalties under the CWA or punitive damages. We subsequently agreed, as part of our Consent Decree not to seek indemnity or reimbursement of our CWA civil penalty payments from BP or the other non-insurer defendants named in the complaint by the U.S.

The MDL Court’s 2012 order deferred ruling on BP’s argument that we committed a core breach of the drilling contract or otherwise materially increased BP’s risk or prejudiced its rights so as to vitiate BP’s indemnity obligations. In the Phase One Ruling, however, the MDL Court found we were not grossly negligent and otherwise upheld the indemnities, implicitly finding no core breach of contract occurred. The impact of this ruling is that BP is obligated to indemnify us as provided for in the contract and that we are entitled to recover certain of our attorneys’ fees from BP as a result of its contractual duty to defend us.

The MDL Court has not ruled on the issue of whether contractual indemnity for criminal fines and penalties is enforceable, but the law generally considers contractual indemnity for criminal fines and penalties to be against public policy.

In the Phase One Ruling, the MDL Court noted that a finding of gross negligence against us would have invalidated BP’s release, in the drilling contract of its direct claims against us. As a result of the MDL Court’s finding of simple negligence as to us, however, the MDL Court ruled that BP’s release of its claims against us is valid and enforceable. Accordingly, the PSC is precluded from pursuing BP’s direct claims against us that were assigned to the PSC as part of the BP/PSC Settlement. This ruling and the MDL Court’s other rulings regarding indemnity may be challenged in the pending appeals from the Phase One Ruling.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Other legal proceedings

Asbestos litigation—In 2004, several of our subsidiaries were named, along with numerous other unaffiliated defendants, in 21 complaints filed on behalf of 769 plaintiffs in the Circuit Courts of the State of Mississippi and which claimed injuries arising out of exposure to asbestos allegedly contained in drilling mud during these plaintiffs’ employment in drilling activities between 1965 and 1986. The complaints generally allege that the defendants used or manufactured asbestos containing drilling mud additives for use in connection with drilling operations and have included allegations of negligence, products liability, strict liability and claims allowed under the Jones Act and general maritime law. In each of these cases, the complaints have named other unaffiliated defendant companies, including companies that allegedly manufactured the drilling-related products that contained asbestos. The plaintiffs generally seek awards of unspecified compensatory and punitive damages, but the court-appointed special master has ruled that a Jones Act employer defendant, such as us, cannot be sued for punitive damages. After ten years of litigation, this group of cases has been winnowed to the point where now only 15 plaintiffs’ individual claims remain pending in Mississippi in which we have or may have an interest.

During the year ended December 31, 2014, a group of lawsuits premised on the same allegations as those in Mississippi were filed in Louisiana. As of March 31, 2015, eight plaintiffs have claims pending against one or more of our subsidiaries in four different lawsuits filed in Louisiana.

We intend to defend these lawsuits vigorously, although we can provide no assurance as to the outcome. We historically have maintained broad liability insurance, although we are not certain whether insurance will cover the liabilities, if any, arising out of these claims. Based on our evaluation of the exposure to date, we do not expect the liability, if any, resulting from these claims to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

One of our subsidiaries was involved in lawsuits arising out of the subsidiary’s involvement in the design, construction and refurbishment of major industrial complexes. The operating assets of the subsidiary were sold and its operations discontinued in 1989, and the subsidiary has no remaining assets other than the insurance policies involved in its litigation, with its insurers and, either directly or indirectly through a qualified settlement fund. The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging bodily injury or personal injury as a result of exposure to asbestos. As of March 31, 2015, the subsidiary was a defendant in approximately 693 lawsuits, some of which include multiple plaintiffs, and we estimate that there are approximately 945 plaintiffs in these lawsuits. For many of these lawsuits, we have not been provided with sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries. The first of the asbestos-related lawsuits was filed against the subsidiary in 1990. Through March 31, 2015, the costs incurred to resolve claims, including both defense fees and expenses and settlement costs, have not been material, all known deductibles have been satisfied or are inapplicable, and the subsidiary’s defense fees and expenses and settlement costs have been met by insurance made available to the subsidiary. The subsidiary continues to be named as a defendant in additional lawsuits, and we cannot predict the number of additional cases in which it may be named a defendant nor can we predict the potential costs to resolve such additional cases or to resolve the pending cases. However, the subsidiary has in excess of $1.0 billion in insurance limits potentially available to the subsidiary. Although not all of the policies may be fully available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient funding directly or indirectly from settlements and claims payments from insurers, assigned rights from insurers and coverage-in-place settlement agreements with insurers to respond to these claims. While we cannot predict or provide assurance as to the outcome of these matters, we do not believe that the ultimate liability, if any, arising from these claims will have a material impact on our consolidated statement of financial position, results of operations or cash flows.

Rio de Janeiro tax assessment—In the third quarter of 2006, we received tax assessments of BRL 428 million, equivalent to approximately $134 million, including interest and penalties, from the state tax authorities of Rio de Janeiro in Brazil against one of our Brazilian subsidiaries for taxes on equipment imported into the state in connection with our operations. The assessments resulted from a preliminary finding by these authorities that our record keeping practices were deficient. We currently believe that the substantial majority of these assessments are without merit. We filed an initial response with the Rio de Janeiro tax authorities on September 9, 2006 refuting these additional tax assessments. In September 2007, we received confirmation from the state tax authorities that they believe the additional tax assessments are valid, and as a result, we filed an appeal on September 27, 2007 to the state Taxpayer’s Council contesting these assessments. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Brazilian import license assessment—In the fourth quarter of 2010, we received an assessment from the Brazilian federal tax authorities in Rio de Janeiro of BRL 539 million, equivalent to approximately $169 million, including interest and penalties, based upon the alleged failure to timely apply for import licenses for certain equipment and for allegedly providing improper information on import license applications. We believe that a substantial majority of the assessment is without merit and are vigorously pursuing legal remedies. The case was decided partially in favor of our Brazilian subsidiary in the lower administrative court level. The decision cancelled the majority of the assessment, reducing the total assessment to BRL 36 million, equivalent to approximately $11 million. On July 14, 2011, we filed an appeal to eliminate the assessment. On May 23, 2013, a ruling was issued that eliminated all assessment amounts. A further appeal by the taxing authorities was filed in November 2014. While we cannot predict or provide assurance as to the outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Petrobras withholding taxes—In July 2014, we received letters from Petróleo Brasileiro S.A. (“Petrobras”) informing us that the Brazilian Federal Revenue Service (the “RFB”) is assessing Petrobras for withholding taxes presumably due and unpaid on payments made in 2008 and 2009 to beneficiaries domiciled outside of Brazil in connection with the charter agreements related to work performed by its contractors, including us. Petrobras contracts include a structure for chartering vessels owned by entities not domiciled in Brazil. Petrobras is challenging such tax assessment and has indicated that, if it loses the tax dispute, it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that Petrobras is being requested to pay. Petrobras has informed us that it has received from the RFB notices of deficiencies for BRL 283 million, equivalent to approximately $89 million, excluding penalties, interest and fees, related to work performed by us. We have informed Petrobras that we believe it has no basis for seeking reimbursement from us, and we intend to vigorously challenge any assertions to the contrary. Effective January 1, 2015, the Brazilian Government enacted a new law that expressly applies zero rate withholding to charter payments made in connection with a vessel to a beneficiary domiciled outside of Brazil when the agreement is entered into jointly with a services contract to operate the vessel. All of our charter contracts with Petrobras met the criteria for such withholding. While the law and ruling are not retroactive, such rulings strengthen Petrobras’ argument for challenging the tax assessment. An unfavorable outcome on these matters could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Nigerian Cabotage Act litigation—In October 2007, three of our subsidiaries were each served a Notice and Demand from the Nigeria Maritime Administration and Safety Agency, imposing a two percent surcharge on the value of all contracts performed by us in Nigeria pursuant to the Coastal and Inland Shipping (Cabotage) Act 2003 (the “Cabotage Act”). Our subsidiaries each filed an originating summons in the Federal High Court in Lagos challenging the imposition of this surcharge on the basis that the Cabotage Act and associated levy is not applicable to drilling rigs. The respondents challenged the competence of the suits on several procedural grounds. The court upheld the objections and dismissed the suits. In December 2010, our subsidiaries filed a new joint Cabotage Act suit. While we cannot predict or provide assurance as to the outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Other matters—We are involved in various tax matters, various regulatory matters, and a number of claims and lawsuits, asserted and unasserted, all of which have arisen in the ordinary course of our business. We do not expect the liability, if any, resulting from these other matters to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending, threatened, or possible litigation or liability. We can provide no assurance that our beliefs or expectations as to the outcome or effect of any tax, regulatory, lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Other environmental matters

Hazardous waste disposal sites—We have certain potential liabilities under CERCLA and similar state acts regulating cleanup of various hazardous waste disposal sites, including those described below. CERCLA is intended to expedite the remediation of hazardous substances without regard to fault. Potentially responsible parties (“PRPs”) for each site include present and former owners and operators of, transporters to and generators of the substances at the site. Liability is strict and can be joint and several.

We have been named as a PRP in connection with a site located in Santa Fe Springs, California, known as the Waste Disposal, Inc. site. We and other PRPs have agreed with the EPA and the DOJ to settle our potential liabilities for this site by agreeing to perform the remaining remediation required by the EPA. The form of the agreement is a consent decree, which has been entered by the court. The parties to the settlement have entered into a participation agreement, which makes us liable for approximately eight percent of the remediation and related costs. The remediation is complete, and we believe our share of the future operation and maintenance costs of the site is not material. There are additional potential liabilities related to the site, but these cannot be quantified, and we have no reason at this time to believe that they will be material.

One of our subsidiaries has been ordered by the California Regional Water Quality Control Board (“CRWQCB”) to develop a testing plan for a site known as Campus 1000 Fremont in Alhambra, California. This site was formerly owned and operated by certain of our subsidiaries. It is presently owned by an unrelated party, which has received an order to test the property. We have also been advised that one or more of our subsidiaries is likely to be named by the EPA as a PRP for the San Gabriel Valley, Area 3, Superfund site, which includes this property. Testing has been completed at the property, but no contaminants of concern were detected. In discussions with CRWQCB staff, we were advised of their intent to issue us a “no further action” letter, but it has not yet been received. Based on the test results, we would contest any potential liability. We have no knowledge at this time of the potential cost of any remediation, who else will be named as PRPs, and whether in fact any of our subsidiaries is a responsible party. The subsidiaries in question do not own any operating assets and have limited ability to respond to any liabilities.

Resolutions of other claims by the EPA, the involved state agency or PRPs are at various stages of investigation. These investigations involve determinations of (a) the actual responsibility attributed to us and the other PRPs at the site, (b) appropriate investigatory or remedial actions and (c) allocation of the costs of such activities among the PRPs and other site users. Our ultimate financial responsibility in connection with those sites may depend on many factors, including (i) the volume and nature of material, if any, contributed to the site for which we are responsible, (ii) the number of other PRPs and their financial viability and (iii) the remediation methods and technology to be used.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

It is difficult to quantify with certainty the potential cost of these environmental matters, particularly in respect of remediation obligations. Nevertheless, based upon the information currently available, we believe that our ultimate liability arising from all environmental matters, including the liability for all other related pending legal proceedings, asserted legal claims and known potential legal claims which are likely to be asserted, is adequately accrued and should not have a material effect on our consolidated statement of financial position or results of operations.

Retained risk

Overview—Our hull and machinery and excess liability insurance program is comprised of commercial market and captive insurance policies that we renew annually on May 1. We periodically evaluate our insurance limits and self-insured retentions. At March 31, 2015, the insured value of our drilling rig fleet was approximately $27.6 billion, excluding our rigs under construction. We generally do not carry commercial market insurance coverage for loss of revenues or 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—At March 31, 2015, under the hull and machinery program, we generally maintained a $125 million per occurrence deductible, limited to a maximum of $200 million per policy period. 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 rig damage, wreck or debris removal and collision liability. Any excess wreck or debris removal costs and excess collision liability costs are generally covered to the extent of our remaining excess liability coverage.

Excess liability coverage—At March 31, 2015, we carried excess liability coverage of $700 million in the commercial market excluding the deductibles and self-insured retention noted below, which generally covers offshore risks such as personal injury, third-party property claims, and third-party non-crew claims, including wreck removal and pollution. Our excess liability coverage had separate $10 million per occurrence deductibles on collision liability claims and $5 million per occurrence deductibles on crew personal injury claims and on other third-party non-crew claims. Through our wholly owned captive insurance company, we retained the risk of the primary $50 million excess liability coverage. In addition, we generally retained the risk for any liability losses in excess of $750 million.

Other insurance coverage—At March 31, 2015, we also carried $100 million of additional insurance that generally covers 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 provides coverage for such expenses in circumstances in which we have legal or contractual liability arising from our gross negligence or willful misconduct.

Letters of credit and surety bonds

At March 31, 2015 and December 31, 2014, we had outstanding letters of credit totaling $305 million and $338 million, respectively, issued under various committed and uncommitted credit lines provided by several banks to guarantee various contract bidding, performance activities and customs obligations, including letters of credit totaling $79 million and $91 million, respectively, that we agreed to maintain in support of the operations for Shelf Drilling (see Note 7—Discontinued Operations).

As is customary in the contract drilling business, we also have various surety bonds in place that secure customs obligations relating to the importation of our rigs and certain performance and other obligations. At March 31, 2015 and December 31, 2014, we had outstanding surety bonds totaling $6 million.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 14—Shareholders’ Equity

Distributions of qualifying additional paid-in capital—On February 15, 2015, our board of directors announced its recommendation that our shareholders at the 2015 annual general meeting approve a distribution of qualifying additional paid-in capital in the form of a U.S. dollar denominated dividend of $0.60 per outstanding share, payable in four quarterly installments of $0.15 per outstanding share, subject to certain limitations. If approved, we expect that the dividend installments will be paid in June 2015, September 2015, December 2015 and March 2016.

In May 2014, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid-in capital in the form of a U.S. dollar denominated dividend of $3.00 per outstanding share, payable in four quarterly installments of $0.75 per outstanding share, subject to certain limitations. At December 31, 2014, the aggregate carrying amount of the distribution payable was $272 million. On March 18, 2015, we paid the final installment in the aggregate amount of $272 million to shareholders of record as of February 20, 2015.

In May 2013, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid-in capital in the form of a U.S. dollar denominated dividend of $2.24 per outstanding share, payable in four quarterly installments of $0.56 per outstanding share, subject to certain limitations. On March 19, 2014, we paid the final installment in the aggregate amount of $202 million to shareholders of record as of February 21, 2014.

Shares held by subsidiary—One of our subsidiaries holds our shares for future use to satisfy our obligations to deliver shares in connection with awards granted under our incentive plans or other rights to acquire our shares. At March 31, 2015 and December 31, 2014, our subsidiary held 7.6 million shares and 8.7 million shares, respectively.

Accumulated other comprehensive loss—The changes in accumulated other comprehensive loss, presented net of tax, were as follows (in millions):

	Three months ended March 31, 2015								Three months ended March 31, 2014
	Defined benefit pension plans			Derivative instruments		Total			Defined benefit pension plans			Derivative instruments			Total
Balance, beginning of period	$	(404	)	$	—	$	(404	)	$	(264	)	$	2		$	(262	)
Other comprehensive loss before reclassifications		(11	)		—		(11	)		(5	)		—			(5	)
Reclassifications to net income		1			—		1			6			(2	)		4
Other comprehensive income (loss), net		(10	)		—		(10	)		1			(2	)		(1	)
Balance, end of period	$	(414	)	$	—	$	(414	)	$	(263	)	$	—		$	(263	)

Significant reclassifications from accumulated other comprehensive income to net income included the following (in millions):

		Three months ended March 31,
	Statement of operations classification	2015			2014
Defined benefit pension plans
Actuarial losses		$	5		$	6
Total amortization, before income taxes	Net periodic benefit costs (a)		5			6
Income tax benefit	Income tax expense		(4	)		—
Total amortization, net of income taxes		$	1		$	6

_____________________________

(a)

We recognize the amortization of accumulated other comprehensive income components related to defined benefit pension plans in net periodic benefit costs. In the three months ended March 31, 2015, our net periodic benefit costs included $4 million and $1 million, recorded in operating and maintenance costs and general and administrative costs, respectively. In the three months ended March 31, 2014, our net periodic benefit costs included $4 million and $2 million, recorded in operating and maintenance costs and general and administrative costs, respectively. See Note 12—Postemployment Benefit Plans.

Note 15—Noncontrolling interest

In the three months ended March 31, 2015, Transocean Partners declared and paid an aggregate distribution of $25 million to its unitholders of record as of February 20, 2015, of which $18 million was paid to us and was eliminated in consolidation.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 16—Financial Instruments

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

	March 31, 2015				December 31, 2014
	Carrying amount		Fair value		Carrying amount		Fair value
Cash and cash equivalents	$	2,682	$	2,682	$	2,635	$	2,635
Notes and other loans receivable		15		15		15		15
Restricted cash investments		296		309		377		394
Long-term debt, including current maturities		10,020		8,834		10,092		9,778
Derivative instruments, assets		33		33		15		15

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

Cash and cash equivalents—The carrying amount of cash and cash equivalents represents the historical cost, plus accrued interest, which approximates fair value because of the short maturities of those instruments. We measured the estimated fair value of our cash equivalents using significant other observable inputs, representative of a Level 2 fair value measurement, including the net asset values of the investments. At March 31, 2015 and December 31, 2014, the aggregate carrying amount of our cash equivalents was $1.8 billion and $1.7 billion, respectively.

Notes and other loans receivable—We hold certain notes and other loans receivable, which originated in connection with certain asset dispositions and supplier advances. The carrying amount represents the amortized cost of our investments. We measured the estimated fair value using significant unobservable inputs, representative of a Level 3 fair value measurement, including the credit ratings of the borrowers. At March 31, 2015 and December 31, 2014, the aggregate carrying amount of our notes receivable and other loans receivable was $15 million, recorded in other assets.

Restricted cash investments—The carrying amount of the Eksportfinans Restricted Cash Investments represents the amortized cost of our investment. We measured the estimated fair value of the Eksportfinans Restricted Cash Investments using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads of the instruments. At March 31, 2015 and December 31, 2014, the aggregate carrying amount of the Eksportfinans Restricted Cash Investments was $288 million and $369 million, respectively. At March 31, 2015 and December 31, 2014, the estimated fair value of the Eksportfinans Restricted Cash Investments was $301 million and $386 million, respectively.

The carrying amount of the restricted cash investments for certain contingent obligations approximates fair value due to the short term nature of the instruments in which the restricted cash investments are held. At March 31, 2015 and December 31, 2014, the aggregate carrying amount of the restricted cash investments for certain contingent obligations was $8 million, recorded in other current liabilities.

Debt—We measured the estimated fair value of our fixed-rate debt using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads for the instruments. At March 31, 2015 and December 31, 2014, the aggregate carrying amount of our fixed-rate debt was $10.0 billion and $10.1 billion, respectively. At March 31, 2015 and December 31, 2014, the aggregate estimated fair value of our fixed-rate debt was $8.8 billion and $9.8 billion, respectively.

Derivative instruments—The carrying amount of our derivative instruments represents the estimated fair value. We measured the estimated fair value using significant other observable inputs, representative of a Level 2 fair value measurement, including the interest rates and terms of the instruments.

Note 17—Condensed Consolidating Financial Information

Transocean Inc., a wholly owned subsidiary of Transocean Ltd., is the issuer of certain notes and debentures, which have been guaranteed by Transocean Ltd. Transocean Ltd.’s guarantee of debt securities of Transocean Inc. is full and unconditional. Transocean Ltd. is not subject to any significant restrictions on its ability to obtain funds by dividends, loans or return of capital distributions from its consolidated subsidiaries.

The following tables present condensed consolidating financial information for (a) Transocean Ltd. (the “Parent Guarantor”), (b) Transocean Inc. (the “Subsidiary Issuer”), and (c) the other direct and indirect wholly owned and partially owned subsidiaries of the Parent Guarantor, none of which guarantee any indebtedness of the Subsidiary Issuer (the “Other Subsidiaries”). The condensed consolidating financial information may not necessarily be indicative of the results of operations, financial position or cash flows had the subsidiaries operated as independent entities.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

The following tables include the consolidating adjustments necessary to present the condensed financial statements on a consolidated basis (in millions):

	Three months ended March 31, 2015
	Parent Guarantor			Subsidiary Issuer			Other Subsidiaries			Consolidating adjustments		Consolidated
Operating revenues	$	—		$	—		$	2,043		$	—	$	2,043
Cost and expenses		4			2			1,415			—		1,421
Loss on impairment		—			—			(936	)		—		(936	)
Loss on disposal of assets, net		—			—			(7	)		—		(7	)
Operating loss		(4	)		(2	)		(315	)		—		(321	)

Other income (expense), net
Interest income (expense), net		—			(161	)		51			—		(110	)
Equity in earnings		(479	)		(268	)		—			747		—
Other, net		—			39			8			—		47
		(479	)		(390	)		59			747		(63	)
Loss from continuing operations before income tax expense		(483	)		(392	)		(256	)		747		(384	)
Income tax expense		—			—			83			—		83
Loss from continuing operations		(483	)		(392	)		(339	)		747		(467	)
Gain (loss) from discontinued operations, net of tax		—			1			(3	)		—		(2	)

Net loss		(483	)		(391	)		(342	)		747		(469	)
Net income attributable to noncontrolling interest		—			—			14			—		14
Net loss attributable to controlling interest		(483	)		(391	)		(356	)		747		(483	)

Other comprehensive income (loss) before income taxes		(2	)		(9	)		3			—		(8	)
Income taxes related to other comprehensive loss		—			—			(2	)		—		(2	)
Other comprehensive income (loss), net of income taxes		(2	)		(9	)		1			—		(10	)

Total comprehensive loss		(485	)		(400	)		(341	)		747		(479	)
Total comprehensive income attributable to noncontrolling interest		—			—			14			—		14
Total comprehensive loss attributable to controlling interest	$	(485	)	$	(400	)	$	(355	)	$	747	$	(493	)

	Three months ended March 31, 2014
	Parent Guarantor			Subsidiary Issuer			Other Subsidiaries			Consolidating adjustments			Consolidated
Operating revenues	$	—		$	—		$	2,343		$	(4	)	$	2,339
Cost and expenses		9			1			1,593			(4	)		1,599
Loss on impairment		—			—			(65	)		—			(65	)
Loss on disposal of assets, net		—			—			(3	)		—			(3	)
Operating income (loss)		(9	)		(1	)		682			—			672

Other income (expense), net
Interest income (expense), net		6			139			(261	)		—			(116	)
Equity in earnings		459			287			—			(746	)		—
Other, net		—			1			(3	)		—			(2	)
		465			427			(264	)		(746	)		(118	)
Income from continuing operations before income tax expense		456			426			418			(746	)		554
Income tax expense		—			—			80			—			80
Income from continuing operations		456			426			338			(746	)		474
Gain (loss) from discontinued operations, net of tax		—			4			(12	)		—			(8	)

Net Income		456			430			326			(746	)		466
Net income attributable to noncontrolling interest		—			—			10			—			10
Net income attributable to controlling interest		456			430			316			(746	)		456

Other comprehensive income (loss) before income taxes		(2	)		(6	)		7			—			(1	)
Income taxes related to other comprehensive loss		—			—			—			—			—
Other comprehensive income (loss), net of income taxes		(2	)		(6	)		7			—			(1	)

Total comprehensive income		454			424			333			(746	)		465
Total comprehensive income attributable to noncontrolling interest		—			—			10			—			10
Total comprehensive income attributable to controlling interest	$	454		$	424		$	323		$	(746	)	$	455

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

	March 31, 2015
	Parent Guarantor		Subsidiary Issuer		Other Subsidiaries		Consolidating adjustments			Consolidated
Assets
Cash and cash equivalents	$	19	$	1,160	$	1,503	$	—		$	2,682
Other current assets		3		741		4,908		(2,491	)		3,161
Total current assets		22		1,901		6,411		(2,491	)		5,843

Property and equipment, net		—		—		20,566		—			20,566
Investment in affiliates		13,210		30,270		—		(43,480	)		—
Other assets		—		4,241		26,637		(30,182	)		696
Total assets		13,232		36,412		53,614		(76,153	)		27,105

Liabilities and equity
Debt due within one year		—		896		128		—			1,024
Other current liabilities		6		465		4,169		(2,491	)		2,149
Total current liabilities		6		1,361		4,297		(2,491	)		3,173

Long-term debt		—		22,217		16,961		(30,182	)		8,996
Other long-term liabilities		25		285		1,105		—			1,415
Total long-term liabilities		25		22,502		18,066		(30,182	)		10,411

Commitments and contingencies
Redeemable noncontrolling interest		—		—		11		—			11

Total equity		13,201		12,549		31,240		(43,480	)		13,510
Total liabilities and equity	$	13,232	$	36,412	$	53,614	$	(76,153	)	$	27,105

	December 31, 2014
	Parent Guarantor		Subsidiary Issuer		Other Subsidiaries		Consolidating adjustments			Consolidated
Assets
Cash and cash equivalents	$	16	$	842	$	1,777	$	—		$	2,635
Other current assets		12		757		5,228		(2,631	)		3,366
Total current assets		28		1,599		7,005		(2,631	)		6,001

Property and equipment, net		—		—		21,538		—			21,538
Investment in affiliates		13,952		30,925		—		(44,877	)		—
Other assets		—		3,899		25,883		(28,908	)		874
Total assets		13,980		36,423		54,426		(76,416	)		28,413

Liabilities and equity
Debt due within one year		—		898		135		—			1,033
Other current liabilities		287		473		4,608		(2,631	)		2,737
Total current liabilities		287		1,371		4,743		(2,631	)		3,770

Long-term debt		—		21,486		16,481		(28,908	)		9,059
Other long-term liabilities		22		280		1,289		—			1,591
Total long-term liabilities		22		21,766		17,770		(28,908	)		10,650

Commitments and contingencies
Redeemable noncontrolling interest		—		—		11		—			11

Total equity		13,671		13,286		31,902		(44,877	)		13,982
Total liabilities and equity	$	13,980	$	36,423	$	54,426	$	(76,416	)	$	28,413

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

	Three months ended March 31, 2015
	Parent Guarantor			Subsidiary Issuer			Other Subsidiaries			Consolidating adjustments			Consolidated

Cash flows from operating activities	$	2		$	(75	)	$	599		$	—		$	526

Cash flows from investing activities
Capital expenditures		—			—			(201	)		—			(201	)
Proceeds from disposal of assets, net		—			—			7			—			7
Proceeds from disposal of assets in discontinued operations, net		—			—			2			—			2
Investing activities with affiliates, net		—			(353	)		(746	)		1,099			—
Net cash used in investing activities		—			(353	)		(938	)		1,099			(192	)

Cash flows from financing activities
Repayments of debt		—			—			(63	)		—			(63	)
Proceeds from restricted cash investments		—			—			57			—			57
Distribution of qualifying additional paid-in capital		(272	)		—			—			—			(272	)
Distribution to holders of noncontrolling interest		—			—			(7	)		—			(7	)
Financing activities with affiliates, net		275			746			78			(1,099	)		—
Other, net		(2	)		—			—			—			(2	)
Net increase (decrease) cash provided by (used in) financing activities		1			746			65			(1,099	)		(287	)

Net increase (decrease) in cash and cash equivalents		3			318			(274	)		—			47
Cash and cash equivalents at beginning of period		16			842			1,777			—			2,635
Cash and cash equivalents at end of period	$	19		$	1,160		$	1,503		$	—		$	2,682

	Three months ended March 31, 2014
	Parent Guarantor			Subsidiary Issuer			Other Subsidiaries			Consolidating adjustments			Consolidated

Cash flows from operating activities	$	10		$	(128	)	$	254		$	—		$	136

Cash flows from investing activities
Capital expenditures		—			—			(1,131	)		—			(1,131	)
Proceeds from disposal of assets, net		—			—			91			—			91
Proceeds from disposal of assets in discontinued operations, net		—			—			14			—			14
Investing activities with affiliates, net		—			(737	)		62			675			—
Other, net		—			—			(12	)		—			(12	)
Net cash used in investing activities		—			(737	)		(976	)		675			(1,038	)

Cash flows from financing activities
Repayments of debt		—			—			(237	)		—			(237	)
Proceeds from restricted cash investments		—			—			107			—			107
Deposits to restricted cash investments		—			—			(20	)		—			(20	)
Distribution of qualifying additional paid-in capital		(202	)		—			—			—			(202	)
Financing activities with affiliates, net		217			(42	)		500			(675	)		—
Other, net		(2	)		—			—			—			(2	)
Net increase (decrease) cash provided by (used in) financing activities		13			(42	)		350			(675	)		(354	)

Net increase (decrease) in cash and cash equivalents		23			(907	)		(372	)		—			(1,256	)
Cash and cash equivalents at beginning of period		4			1,617			1,622			—			3,243
Cash and cash equivalents at end of period	$	27		$	710		$	1,250		$	—		$	1,987

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued

(Unaudited)

Note 18—Subsequent Events

Assets held for sale—Subsequent to March 31, 2015, in connection with our strategy to reduce our exposure to lower-specification drilling units, we committed to a plan to sell for scrap value the Ultra-Deepwater Floater GSF Explorer along with related equipment. As a result, in the three months ending June 30, 2015, we expect to recognize a loss, ranging from $100 million to $120 million, net of tax, associated with the impairment of these assets. After consideration of the impairment, the remaining aggregate carrying amount of the reclassified rig and related equipment was approximately $5 million to $20 million.

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Index

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

Forward-Looking Information

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

§	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,

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

§	uses of excess cash, including the payment of dividends and other distributions, share repurchases and debt retirement, including the amounts, timing and, as applicable shareholder proposals or approvals associated with uses of excess cash,

§	newbuild, upgrade, shipyard and other capital projects, including completion, delivery and commencement of operation dates, expected downtime and lost revenue, the level of expected capital expenditures and the timing and cost of completion of capital projects,

§	the cost and timing of acquisitions and the proceeds and timing of dispositions,

§	the optimization of rig-based spending,

§	the impact of the Macondo well incident, claims, settlement and related matters,

§	tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues, including those associated with our activities in Brazil, Norway, the United Kingdom (“U.K.”) and the U.S.,

§	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,

§	insurance matters, including adequacy of insurance, renewal of insurance, insurance proceeds and cash investments of our wholly owned captive insurance company,

§	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 payments and benefit payments.

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

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

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

§	those described under “Item 1A. Risk Factors” included in Part I of our annual report on Form 10-K for the year ended December 31, 2014,

§	the adequacy of and access to sources of liquidity,

§	our inability to obtain drilling contracts for our rigs that do not have contracts,

§	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,

§	losses on impairment of long-lived assets,

§	shipyard, construction and other delays,

§	the results of meetings of our shareholders,

§	changes in political, social and economic conditions,

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

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

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

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Index

Business

We provide contract drilling services, in a single, global operating segment, which involves contracting our mobile offshore drilling fleet, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We specialize in technically demanding regions of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services. We believe our drilling fleet is one of the most versatile fleets in the world, consisting of floaters and high-specification jackups used in support of offshore drilling activities and offshore support services on a worldwide basis.

Our contract drilling services operations are geographically dispersed in oil and gas exploration and development areas throughout the world. Although rigs can be moved from one region to another, the cost of moving rigs and the availability of rig-moving vessels may cause the supply and demand balance to fluctuate somewhat between regions. Still, significant variations between regions do not tend to persist long term because of rig mobility. Our fleet operates in a single, global market for the provision of contract drilling services. The location of our rigs and the allocation of resources to build or upgrade rigs are determined by the activities and needs of our customers.

Significant Events

In May 2013, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid-in capital in the form of a U.S. dollar denominated dividend of $2.24 per outstanding share, payable in four quarterly installments, subject to certain limitations. In March 2014, we paid the final installment in the aggregate amount of $202 million to shareholders as of the record date. See “—Liquidity and Capital Resources—Sources and uses of liquidity.”

Impairments of long-lived assets—In the three months ended March 31, 2015, we identified indicators that our Deepwater Floater asset group may not be recoverable, and as a result of our testing, we recognized a loss of $507 million ($481 million, net of tax) associated with the impairment of these long-lived assets. See “—Operating Results” and Notes to Condensed Consolidated Financial Statements—Note 5—Impairments.

During the three months ended March 31, 2015, we committed to a plan to sell for scrap value the Ultra-Deepwater Floater Deepwater Expedition, the Deepwater Floaters Sedco707 and Transocean Rather and the Midwater Floaters GSF Aleutian Key, GSF Arctic III and Transocean Legend, along with related equipment. As a result, we recognized an aggregate loss of $429 million ($393 million, net of tax) associated with the impairment of these assets. Subsequent to March 31, 2015, we committed to a plan to sell for scrap value the Ultra-Deepwater Floater GSF Explorer along with related equipment and in the three months ending June 30, 2015, we expect to recognize a loss, ranging from $100 million to $120 million, net of tax, associated with the impairment of these assets. See “—Liquidity and Capital Resources—Drilling fleet.”

Dispositions—During the three months ended March 31, 2015, we completed the sale of the Deepwater Floater Discoverer Seven Seas and the Midwater Floater C. Kirk Rhein, Jr. along with related equipment and we received net cash proceeds of $5 million. During the three months ended March 31, 2014, we completed the sale of the High-Specification Jackup GSF Monitor along with related equipment and we received net cash proceeds of $83 million. See “—Liquidity and Capital Resources—Drilling fleet.”

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Index

Outlook

Drilling market—Although our long-term view of the offshore drilling market remains favorable, particularly for high-specification assets, we expect the near to medium term to be challenging given weak commodity pricing, coupled with our customers’ focus on capital allocation, cost reductions and delays of various exploration and development programs. The significant and rapid decline in oil and natural gas prices has accelerated the decline in demand for drilling rigs across all asset classes and regions. As a result of this decline in demand, coupled with the number of newbuild units being introduced into the market in the near term, we currently expect the pace of executing drilling contracts for the global floater fleet to remain stagnant in the near to medium term, giving rise to 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 April 16, 2015, the contract backlog for our continuing operations was $19.9 billion compared to $21.2 billion as of February 17, 2015.

Following the Macondo well incident, the U.S. government implemented enhanced regulations related to offshore drilling in the U.S. Gulf of Mexico, which require operators to submit applications for new drilling permits that demonstrate compliance with such enhanced regulations. The enhanced regulations require independent third-party inspection, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. The voluntary application by some of our customers of such third-party inspections and certifications of well control equipment operating outside the U.S. Gulf of Mexico has caused and may continue to cause us to experience additional out of service time and incur additional maintenance costs. We have entered into an agreement with the U.S. Department of Justice (“DOJ”) that also requires us to undertake certain inspections and certifications beyond current legal standards. Although the enhanced regulations and additional maintenance requirements have affected our revenues, costs and out of service time, we are unable to predict, with certainty, the magnitude with which these matters will continue to impact our operations.

Fleet status—As of April 16, 2015, uncommitted fleet rates for the remainder of 2015, 2016, 2017, 2018 and 2019 were as follows:

	2015		2016		2017		2018		2019
Uncommitted fleet rate (a)
High-Specification Floaters	35	%	56	%	69	%	79	%	83	%
Midwater Floaters	34	%	82	%	100	%	100	%	100	%
High-Specification Jackups	28	%	59	%	80	%	93	%	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.

As of April 16, 2015, we had six existing drilling contracts that had fixed-price or capped options to extend the contract terms, which are exercisable, at the customer’s discretion, any time through their expiration dates. Customers are more likely to exercise fixed-price options when dayrates are higher on new contracts relative to existing contracts, and customers are less likely to exercise fixed-price options when dayrates are lower on new contracts relative to existing contracts. Given current market conditions, we are uncertain whether these options will be exercised by our customers, and, therefore, we have excluded the effect of priced options in the presentation of our uncommitted fleet rates above. Additionally, well-in-progress or similar provisions of our existing contracts may delay the start of higher or lower dayrates in subsequent contracts, and some of the delays could be significant.

High-Specification Floaters—During the first quarter of 2015, three new contracts for Ultra-Deepwater Floaters were entered into worldwide. This quarter, we entered into two short-term extensions with a customer for Sedco Express. However, availability continues to exceed demand as customers increasingly focus on capital discipline, resulting in further delays to drilling programs and pressure on dayrates and rig utilization through 2015. Our Ultra-Deepwater Floater fleet has nine units with availability in 2015 and four units that are stacked.

The Deepwater Floater fleet rig utilization rate for the industry decreased during the first quarter of 2015 with one new contract entered into worldwide. Our Deepwater Floater fleet has three active units with availability in 2015. The pace of tendering and length of contract terms have decreased, and we are experiencing increased competition for each tendering opportunity. As of April 16, 2015, we had 22 of our 41 High-Specification Floaters contracted through the end of 2015.

Although we believe continued exploration successes in the major deepwater offshore provinces and the emerging markets will eventually generate additional demand and support our long-term positive outlook for our High-Specification Floater fleet, we expect reduced dayrates, increased idling of rigs and more intense competition for our floaters in the short term.

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Index

Midwater Floaters—Customer demand for our Midwater Floater fleet, which includes 14 semisubmersible rigs, continues to show signs of weakness. We have eight units available in our active fleet in 2015. Demand for rigs in this class has declined, pressuring global rig utilization rates and dayrates for this asset class. We have observed higher capability assets competing with these assets more frequently, increasing the likelihood that some of the industry’s rigs in this asset class may be permanently retired.

High-Specification Jackups—Market conditions for High-Specification Jackups are beginning to show signs of weakness as many newbuilds are delivered and programs are delayed. The newbuilds are expected to displace older assets with lower capabilities. During the first quarter, one of our High-Specification Jackups was awarded a two-month extention. As of April 16, 2015, three of our 10 High-Specification Jackups have availability in 2015.

Operating results—We expect our total revenues for the year ending December 31, 2015 to be less than our total revenues for the year ended December 31, 2014 primarily due to increased idle and stacked time of our fleet, lower dayrates on new contracts and asset disposals, partially offset by full years of operations for our two newbuild Ultra-Deepwater Floaters placed into service in the third quarter of 2014 and fewer anticipated out of service days for maintenance and contract preparations. We are unable to predict, with certainty, the impact on our business from any changes to offshore activity levels, the results of our efforts to improve our revenue efficiency rates or the full impact that the enhanced regulations and other matters, described under “—Drilling market”, will have on our operations for the year ending December 31, 2015 and beyond.

We expect our total operating and maintenance expenses for the year ending December 31, 2015 to be less than our total operating and maintenance expenses for the year ended December 31, 2014 primarily due to lower costs resulting from increased idle time and stacked rigs, improvements to our cost structure, and asset divestitures, partially offset by full years of operations for our newbuild Ultra-Deepwater Floaters placed into service in the third quarter of 2014. Our projected operating and maintenance expenses for the year ending December 31, 2015 are subject to change and could be affected by actual activity levels, changes in shipyard timing, the effective execution of our cost-saving initiatives, the enhanced regulations and other matters described under “—Drilling market”, the Macondo well incident and related contingencies, exchange rates and cost inflation above expectations, as well as other factors. It is difficult to project operating and maintenance expenses given the nature and variety of these factors that impact these expenses. See “—Forward-Looking Information.”

Although we are unable to estimate the full direct and indirect effect that the Macondo well incident will have on our business, the incident has had and could continue to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. See “—Contingencies—Macondo well incident.”

In accordance with our critical accounting policies, we review our property and equipment for impairment when events occur or circumstances change that may indicate that the carrying amounts of our assets held and used may not be recoverable. If we experience increasingly unfavorable changes to actual or anticipated dayrates or other impairment indicators, or if we are unable to secure new or extended contracts for our active units or the reactivation of any of our stacked units, we may be required to recognize additional losses in future periods as a result of impairments of the carrying amount of one or more of our asset groups. At March 31, 2015, the carrying amount of our property and equipment, net of accumulated depreciation, was $20.6 billion, representing 76 percent of our total assets.

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Index

Performance and Other Key Indicators

Contract backlog—Contract backlog is defined as the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions, which are not expected to be significant to our contract drilling revenues.

The 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, which are excluded from the amounts presented for contract backlog.

The contract backlog for our contract drilling services was as follows:

	April 16, 2015		February 17, 2015		October 15, 2014
Contract backlog	(In millions)
High-Specification Floaters
Ultra-Deepwater Floaters	$	15,944	$	16,529	$	17,540
Deepwater Floaters		542		673		833
Harsh Environment Floaters		1,434		1,591		2,017
Total High-Specification Floaters		17,920		18,793		20,390
Midwater Floaters		1,251		1,613		2,165
High-Specification Jackups		753		834		1,018
Total	$	19,924	$	21,240	$	23,573

Our contract backlog includes only firm commitments, which are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution. Our contract backlog includes amounts associated with our newbuild units that are currently under construction. 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 contract drilling services was as follows:

	Three months ended
	March 31, 2015		December 31, 2014		March 31, 2014
Average daily revenue
High-Specification Floaters
Ultra-Deepwater Floaters	$	535,100	$	544,800	$	547,000
Deepwater Floaters		342,100		391,100		392,000
Harsh Environment Floaters		531,300		484,000		454,700
Total High-Specification Floaters		491,500		498,300		500,900
Midwater Floaters		343,300		338,500		334,500
High-Specification Jackups		174,400		170,200		162,000
Total fleet average daily revenue		398,300		406,400		413,100

Our average daily revenue fluctuates relative to market conditions and our revenue efficiency. Our total fleet average daily revenue is also affected by the mix of rig classes being operated, as Midwater Floaters and High-Specification Jackups are typically contracted at lower dayrates compared to High-Specification Floaters. We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer. We remove rigs from the calculation upon disposal, classification as held for sale or classification as discontinued operations.

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Index

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 contract drilling services were as follows:

	Three months ended
	March 31, 2015			December 31, 2014			March 31, 2014
Revenue efficiency
High-Specification Floaters
Ultra-Deepwater Floaters		97	%		95	%		96	%
Deepwater Floaters		96	%		96	%		101	%
Harsh Environment Floaters		97	%		96	%		96	%
Total High-Specification Floaters		97	%		96	%		97	%
Midwater Floaters		91	%		93	%		91	%
High-Specification Jackups		99	%		99	%		95	%
Total fleet average revenue efficiency		96	%		95	%		96	%

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. We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer. We exclude rigs that are not operating under contract, such as those that are stacked.

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 contract drilling services were as follows:

	Three months ended
	March 31, 2015			December 31, 2014			March 31, 2014
Rig utilization
High-Specification Floaters
Ultra-Deepwater Floaters		68	%		69	%		90	%
Deepwater Floaters		85	%		64	%		61	%
Harsh Environment Floaters		78	%		100	%		100	%
Total High-Specification Floaters		73	%		72	%		84	%
Midwater Floaters		85	%		65	%		62	%
High-Specification Jackups		99	%		95	%		84	%
Total fleet average utilization		79	%		73	%		78	%

Our rig utilization rate declines as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues. We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer. We remove rigs from the calculation upon disposal, classification as held for sale or classification as discontinued operations. Accordingly, our rig utilization can increase when idle or stacked units are removed from our drilling fleet.

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Index

Operating Results

Three months ended March 31, 2015 compared to three months ended March 31, 2014

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

	Three months ended March 31,
	2015			2014			Change			% Change
	(In millions, except day amounts and percentages)

Operating days		4,927			5,538			(611	)	(11)	%
Average daily revenue	$	398,300		$	413,100		$	(14,800	)	(4)	%
Revenue efficiency		96	%		96	%
Rig utilization		79	%		78	%

Contract drilling revenues	$	2,000		$	2,292		$	(292	)	(13)	%
Other revenues		43			47			(4)		(9)	%
		2,043			2,339			(296	)	(13)	%
Operating and maintenance expense		(1,084	)		(1,269	)		185		15	%
Depreciation expense		(291	)		(273	)		(18	)	(7)	%
General and administrative expense		(46	)		(57	)		11		19	%
Loss on impairment		(936	)		(65	)		(871	)	n/m
Loss on disposal of assets, net		(7	)		(3	)		(4	)	n/m
Operating (loss) income		(321	)		672			(993	)	n/m
Other income (expense), net
Interest income		6			10			(4	)	(40)	%
Interest expense, net of amounts capitalized		(116	)		(126	)		10		8	%
Other, net		47			(2	)		49		n/m
Income (loss) from continuing operations before income tax expense		(384	)		554			(938	)	n/m
Income tax expense		(83	)		(80	)		(3	)	(4)	%
Income (loss) from continuing operations	$	(467	)	$	474		$	(941	)	n/m

_____________________________

“n/m” means not meaningful.

Operating revenues—Contract drilling revenues decreased for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 by approximately $295 million due to reduced activity, including approximately $215 million resulting from rigs sold or classified as held for sale and approximately $195 million resulting from additional rigs idle or stacked. This decrease was partially offset by approximately $115 million of increased revenues associated with our two newbuild Ultra-Deepwater drillships that commenced operations subsequent to March 31, 2014.

Costs and expenses—Operating and maintenance costs and expenses decreased for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to the following: (a) approximately $95 million of decreased costs and expenses due to reduced activity, including approximately $75 million resulting from rigs sold or classified as held for sale and approximately $20 million resulting from additional rigs idle or stacked, (b) approximately $70 million of decreased costs and expenses resulting from reduced in-service and out-of-service maintenance costs and (c) approximately $30 million of decreased costs and expenses resulting from reduced personnel costs, both offshore and onshore. These decreases were partially offset by approximately $30 million of increased costs and expenses associated with our two newbuild Ultra-Deepwater drillships that commenced operations subsequent to March 31, 2014.

Depreciation expense increased for the three months ended March 31, 2015 compared to the three months ended March 31, 2014 primarily due to the following: (a) approximately $30 million of increased depreciation resulting from the reduction of the salvage values for certain drilling units and (b) approximately $12 million of increased depreciation resulting from the introduction of our two newbuild Ultra-Deepwater drillships that commenced operations subsequent to March 31, 2014. These increases were partially offset by the following: (a) approximately $26 million of decreased depreciation resulting from rigs sold or classified as held for sale subsequent to March 31, 2014 and (b) approximately $13 million of decreased depreciation resulting from the impairment of our Deepwater Floater asset group in the three months ended September 30, 2014.

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In the three months ended March 31, 2015, we recognized losses on the impairment of long-lived assets, including a loss of $507 million associated with the impairment of our Deepwater Floater asset group and an aggregate loss of $429 million associated with the impairment of the Ultra-Deepwater Floater Deepwater Expedition, the Deepwater Floaters Sedco 707 and Transocean Rather and the Midwater Floaters GSF Aleutian Key, GSF Arctic III and Transocean Legend, along with related equipment, which were classified as assets held for sale at the time of impairment. In the three months ended March 31, 2014, we recognized a loss of $65 million associated with impairment of the Midwater Floater Sedneth 701 and the High-Specification Jackup GSF Magellan, along with related equipment, which were classified as assets held for sale at the time of impairment.

Other income and expense—In the three months ended March 31, 2015, we recognized other income, net, primarily related to the following: (a) a gain of $30 million associated with income from a license fee related to our dual-activity patent, (b) a gain of $13 million associated with currency exchange and (c) a gain of $4 million associated with royalty payments related to our dual-activity patent.

Income tax expense—We operate internationally and provide for income taxes based on the tax laws and rates in the countries in which we operate and earn income. At March 31, 2015 and 2014, the annual effective tax rates were 25.8 percent and 15.1 percent, respectively, based on income (loss) from continuing operations before income taxes, after excluding certain items, such as losses on impairment and gains and losses on certain asset disposals. 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 March 31, 2015 and 2014, the effect of the various discrete period tax items was a net tax expense of less than $1 million and a net tax benefit of $13 million, respectively. For the three months ended March 31, 2015 and 2014, these discrete tax items, coupled with the excluded income and expense items noted above, resulted in effective tax rates of (21.6) percent and 14.4 percent, respectively, based on income (loss) from continuing operations before income taxes.

The relationship between our provision for or benefit from income taxes and our income before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures. Generally, our annual marginal tax rate is lower than our annual effective tax rate. Consequently, our income tax expense does not change proportionally with our income before income taxes. Significant decreases in our income before income taxes typically lead to higher effective tax rates, while significant increases in income before income taxes can lead to lower effective tax rates, subject to the other factors impacting income tax expense noted above. With respect to the annual effective tax rate calculation for the three months ended March 31, 2015, a significant portion of our income tax expense was generated in countries in which income taxes are imposed on gross revenues, with the most significant of these countries being Angola, India, Nigeria, Indonesia and the Republic of Congo. Conversely, the countries in which we incurred the most significant income taxes during this period that were based on income before income tax include Norway, the U.K., Switzerland, Brazil and the U.S.

Our rig operating structures further complicate our tax calculations, especially in instances where we have more than one operating structure for the particular taxing jurisdiction and, thus, more than one method of calculating taxes depending on the operating structure utilized by the rig under the contract. For example, two rigs operating in the same country could generate significantly different provisions for income taxes if they are owned by two different subsidiaries that are subject to differing tax laws and regulations in the respective country of incorporation.

Discontinued operations

Overview—We have discontinued the operations of (a) the standard jackup and swamp barge contract drilling services and (b) the drilling management services operating segment.

A summary of the results of our discontinued operations, before income taxes, was as follows:

	Three months ended March 31,
	2015			2014
	(In millions)
Loss on disposal of assets in discontinued operations, net	$	—		$	(10	)
Other income (loss) from operations of discontinued operations		(1	)		4

In the three months ended March 31, 2015 and 2014, other income from operations of discontinued operations was negligible, primarily as the result of the operations of standard jackups under operating agreements with Shelf Drilling.

Standard jackup and swamp barge contract drilling services—In September 2012, in connection with our efforts to dispose of non-strategic assets and to reduce our exposure to low-specification drilling units, we committed to a plan to discontinue operations associated with the standard jackup and swamp barge asset groups. In November 2012, we completed the sale of 38 drilling units to Shelf Drilling.

For a transition period following the completion of the sale transactions, we agreed to continue to operate a substantial portion of the standard jackups under operating agreements with Shelf Drilling and to provide certain other transition services to Shelf Drilling. Under the operating agreements, we agreed to remit the collections from our customers under the associated drilling contracts to Shelf Drilling, and Shelf Drilling agreed to reimburse us for our direct costs and expenses incurred while operating the standard jackups on behalf of Shelf Drilling with certain exceptions. The cost to us for providing such operating and transition services, including allocated indirect costs, have exceeded the amounts we receive from Shelf Drilling for providing such services.

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During the three months ended March 31, 2014, we recognized a net gain of $1 million, which had not tax effect, related to the disposals of assets unrelated to rig sales.

Drilling management services—In February 2014, in connection with our efforts to discontinue non-strategic operations, we completed the sale of ADTI, which performs drilling management services in the North Sea. Following the completion of the sale transaction, we agreed to provide a $15 million working capital line of credit to the buyer through March 2016. In the three months ended March 31, 2014, we recognized a net loss of $11 million associated with the sale of the drilling management services business.

See Notes to Condensed Consolidated Financial Statements—Note 7—Discontinued Operations.

Liquidity and Capital Resources

Sources and uses of cash

At March 31, 2015, we had $2.7 billion in cash and cash equivalents. At any given time, we may require a significant portion of our cash and cash equivalents for working capital and other needs related to the operation of our business. At March 31, 2015, we estimate the amount of cash required for these purposes, which is not generally available to us for other uses, was approximately $1.3 billion.

For the three months ended March 31, 2015, our primary sources of cash were our cash flows from operating activities, proceeds from asset disposals, and net proceeds from restricted cash investments. Our primary uses of cash were capital expenditures, primarily associated with our newbuild construction projects, repayments of debt, payments to our shareholders installments of distributions of qualifying paid-in capital and payment of our Macondo well incident settlement obligations.

	Three months ended March 31,
	2015			2014			Change
	(In millions)
Cash flows from operating activities
Net income (loss)	$	(469	)	$	466		$	(935	)
Depreciation		291			273			18
Loss on impairment		936			65			871
Loss on disposal of assets, net		7			13			(6	)
Other non-cash items, net		(53	)		33			(86	)
Changes in Macondo well incident assets and liabilities, net		(260	)		(457	)		197
Changes in other operating assets and liabilities, net		74			(257	)		331
	$	526		$	136		$	390

Net cash provided by operating activities increased primarily due to changes in working capital, including a decrease in scheduled cash payments for Macondo well incident settlement obligations.

	Three months ended March 31,
	2015			2014			Change
	(In millions)
Cash flows from investing activities
Capital expenditures	$	(201	)	$	(1,131	)	$	930
Proceeds from disposal of assets, net		9			105			(96	)
Other, net		—			(12	)		12
	$	(192	)	$	(1,038	)	$	846

Net cash used in investing activities decreased primarily due to a decrease in capital expenditures associated with the timing of milestone payments for our major construction projects.

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	Three months ended March 31,
	2015			2014			Change
	(In millions)
Cash flows from financing activities
Repayments of debt	$	(63	)	$	(237	)	$	174
Proceeds from and deposits to restricted cash investments, net		57			87			(30	)
Distribution of qualifying additional paid-in capital		(272	)		(202	)		(70	)
Other, net		(9	)		(2	)		(7	)
	$	(287	)	$	(354	)	$	67

Net cash used in financing activities decreased primarily due to a reduction in cash used to repay debt. Partially offsetting the decrease was an increase in cash used to pay our shareholders the final installment of the distribution of qualifying additional paid-in capital.

Drilling fleet

Expansion—From time to time, we review possible acquisitions of businesses and drilling rigs and may make significant future capital commitments for such purposes. We may also consider investments related to major rig upgrades or new rig construction, including new rigs the construction of which we may begin without first obtaining customer contracts. Any such acquisition, upgrade or new rig construction could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities. Our failure to secure drilling contracts for rigs under construction could have an adverse effect on our results of operations or cash flows.

In the three months ended March 31, 2015, we made capital expenditures of $201 million, including capitalized interest of $26 million. The following table presents the historical and projected capital expenditures and capitalized interest, for our ongoing major construction projects:

	Total costs through December 31, 2014		Total costs for the three months ended March 31, 2015		Expected costs for the nine months ending December 31, 2015		Estimated costs thereafter		Total estimated costs at completion
	(In millions)
Deepwater Thalassa (a)	$	375	$	25	$	474	$	46	$	920
Deepwater Proteus (a)		338		9		434		74		855
Deepwater Conqueror (b)		226		18		81		490		815
Deepwater Pontus (a)		310		18		44		428		800
Deepwater Poseidon (a)		282		6		55		462		805
Ultra-Deepwater drillship TBN1 (c)		32		2		10		656		700
Transocean Cassiopeia (d)		49		1		4		206		260
Ultra-Deepwater drillship TBN2 (c)		27		—		71		597		695
Transocean Centaurus (d)		48		1		4		212		265
Transocean Cepheus (d)		48		1		4		217		270
Transocean Cetus (d)		48		1		4		222		275
Transocean Circinus (d)		48		1		3		228		280
Total	$	1,831	$	83	$	1,188	$	3,838	$	6,940

_____________________________

(a)

(b)	Deepwater Conqueror, a newbuild Ultra-Deepwater drillship under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, is expected to commence operations in the fourth quarter of 2016.

(c)	Our two unnamed dynamically positioned Ultra-Deepwater drillships under construction at the Jurong Shipyard PTE Ltd. in Singapore do not yet have drilling contracts and are expected to be delivered in the second quarter of 2017 and the first quarter of 2018, respectively.

(d)

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For the year ending December 31, 2015, we expect total capital expenditures to be approximately $1.7 billion, approximately $1.3 billion of which is associated with our major construction projects. The ultimate amount of our capital expenditures is partly dependent upon financial market conditions, the actual level of operational and contracting activity, the costs associated with the new regulatory environment and customer requested capital improvements and equipment for which the customer agrees to reimburse us.

At April 28, 2015, we held options with Jurong Shipyard PTE Ltd. in Singapore to order up to two newbuild Ultra-Deepwater drillships, which must be exercised by August 2015 and February 2016. We previously allowed one of the original three drillship options to expire unexercised. We previously held options with Keppel FELS shipyard in Singapore to order up to five Super B 400 Bigfoot class design High-Specification Jackups, all of which we have either let expire unexercised or cancelled, in connection with our further delay of the delivery of the five High-Specification Jackups under construction.

As with any major shipyard project that takes place over an extended period of time, the actual costs, the timing of expenditures and the project completion date may vary from estimates based on numerous factors, including actual contract terms, weather, exchange rates, shipyard labor conditions, availability of suppliers to recertify equipment and the market demand for components and resources required for drilling unit construction.

We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales. We also have available credit under the Five-Year Revolving Credit Facility, as described below, and may utilize other commercial bank or capital market financings. Economic conditions could impact the availability of these sources of funding.

Dispositions—From time to time, we may also review the possible disposition of non-strategic drilling units. Considering recent market conditions, we have committed to plans to sell certain lower-specification drilling units for scrap value. During the three months ended March 31, 2015, we identified six such drilling units that we intend to sell for scrap value, including the Ultra-Deepwater Floater Deepwater Expedition, the Deepwater Floaters Sedco 707 and Transocean Rather and the Midwater Floaters GSF Aleutian Key, GSF Arctic III and Transocean Legend. In April 2015, we committed to a plan to sell for scrap value the Ultra-Deepwater Floater GSF Explorer. We continue to evaluate the drilling units in our fleet and may identify additional lower-specification drilling units to be sold for scrap value.

During the three months ended March 31, 2015, we completed the sale of the Deepwater Floater Discoverer Seven Seas and the Midwater Floater C. Kirk Rhein, Jr. along with related equipment and we received net cash proceeds of $5 million. During the three months ended March 31, 2014, we completed the sale of the High-Specification Jackup GSF Monitor along with related equipment and we received net cash proceeds of $83 million.

Sources and uses of liquidity

Overview—We expect to use existing cash balances, internally generated cash flows, borrowings under our bank credit agreement, proceeds from the disposal of assets, proceeds from the issuance of debt or proceeds from the sale of additional noncontrolling interests in or issuance of debt of Transocean Partners to fulfill anticipated obligations, such as scheduled debt maturities or other payments, repayment of debt due within one year, capital expenditures, shareholder-approved distributions, payments of our Macondo well incident settlement obligations, working capital and other needs in our operations. Subject in each case to then existing market conditions and to our then expected liquidity needs, among other factors, we may continue to use a portion of our internally generated cash flows and proceeds from asset sales or proceeds from the sale of additional noncontrolling interests in or issuance of debt of Transocean Partners to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings.

At any given time, we may require a significant portion of our cash on hand for working capital and other needs related to the operation of our business. We currently estimate this amount to be approximately $1.3 billion. As a result, this portion of cash is not generally available to us for other uses. From time to time, we may also use borrowings under our bank credit agreement to maintain liquidity for short-term cash needs.

On January 3, 2013, we reached an agreement with the DOJ to resolve certain outstanding civil and potential criminal charges against us arising from the Macondo well incident (see “—Plea Agreement obligations” and “—Consent Decree obligations”). However, we are unable to predict the ultimate outcome of the investigations of the Macondo well incident and the DOJ lawsuits and other litigation related to other claims that were not addressed in our resolution with the DOJ. We can give no assurance that the matters arising out of the Macondo well incident will not adversely affect our liquidity in the future.

Our access to debt and equity markets may be limited due to a variety of events, including, among others, credit rating agency downgrades of our debt ratings, potential liability related to the Macondo well incident, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry. During the three months ended March 31, 2015, two credit rating agencies downgraded their credit ratings of our non-credit enhanced senior unsecured long-term debt (“Debt Rating”) to Debt Ratings that are considered below investment grade. Such downgrades have caused, and any further downgrades may cause, us to experience increased fees under our credit facility and interest rates under agreements governing our senior notes and may limit our ability to access debt markets. Uncertainty related to our potential liabilities from the Macondo well incident has had, and could continue to have, an adverse effect on our business and our financial condition. Our ability to access such markets may be severely 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. Uncertainty related to our potential liabilities from the Macondo well incident has had an adverse effect on our share price, could impact our ability to access capital markets in the future and has had, and could continue to have, an adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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Our internally generated cash flow is directly related to our business and the market sectors in which we operate. Should the drilling market deteriorate, or should we experience poor results in our operations, cash flow from operations may be reduced. We have, however, continued to generate positive cash flow from operating activities over recent years and expect that such cash flow will continue to be positive over the next year.

In May 2014, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid-in capital in the form of a U.S. dollar denominated dividend of $3.00 per outstanding share, payable in four quarterly installments, subject to certain limitations. We do not pay the distribution of qualifying additional paid-in capital with respect to our shares held in treasury or held by our subsidiary. In May 2014, we recognized a liability of $1.1 billion for the distribution payable, recorded in other current liabilities, with a corresponding entry to additional paid-in capital. On June 18, September 17 and December 17, 2014, we paid the first three installments in the aggregate amount of $816 million to shareholders of record as of May 30, August 22 and November 14, 2014, respectively. On March 18, 2015, we paid the final installment in the aggregate amount of $272 million to shareholders of record as of February 20, 2015.

In May 2013, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid-in capital in the form of a U.S. dollar denominated dividend of $2.24 per outstanding share, payable in four quarterly installments, subject to certain limitations. We did not pay the distribution of qualifying additional paid-in capital with respect to our shares held in treasury or held by our subsidiary. On March 19, 2014, we paid the final installment in the aggregate amount of $202 million to shareholders of record as of February 21, 2014.

Noncontrolling interest in Transocean Partners—On July 31, 2014, we announced the pricing of an initial public offering of common units representing limited liability company interests in Transocean Partners, which began trading on the New York Stock Exchange under the ticker symbol “RIGP,” for $22.00 per unit. On August 5, 2014, we completed the initial public offering of 20.1 million common units, which represents a 29.2 percent limited liability company interest in Transocean Partners. Through Transocean Partners Holdings Limited, a Cayman Islands company and our wholly owned subsidiary, we hold the remaining 21.3 million common units and 27.6 million subordinated units, which collectively represent a 70.8 percent limited liability company interest. As a result of the offering, we received net cash proceeds of approximately $417 million, after deducting approximately $26 million for underwriting discounts and commissions and other estimated offering expenses. We may consider selling additional noncontrolling interests in or debt securities of Transocean Partners to provide additional sources of liquidity.

On November 4, 2014, Transocean Partners declared a distribution of $0.2246 per outstanding unit. On November 24, 2014, Transocean Partners paid to its unitholders of record as of November 17, 2014 an aggregate distribution of $15 million, of which $11 million was paid to us and eliminated in consolidation. On February 9, 2015, Transocean Partners declared a dividend of $0.3625 per outstanding unit. On February 26, 2015, Transocean Partners paid to its unitholders of record as of February 20, 2015 an aggregate dividend of $25 million, of which $18 million was paid to us and eliminated in consolidation.

See Notes to Consolidated Financial Statements—Note 15—Noncontrolling interest.

Revolving Credit Facility—In June 2014, we entered into an amended and restated bank credit agreement, which established a $3.0 billion unsecured five-year revolving credit facility, that is scheduled to expire on June 28, 2019 (the “Five-Year Revolving Credit Facility”). 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 to tangible capitalization ratio of 0.6 to 1.0. As of March 31, 2015, our debt to tangible capitalization ratio, as defined, was 0.4 to 1.0. In order to borrow or have letters of credit issued under the Five-Year Revolving Credit Facility, we must, at the time of the borrowing request, not be in default under the bank credit agreements and make certain representations and warranties, including with respect to compliance with laws and solvency, to the lenders, but we are not required to make any representation to the lenders as to the absence of a material adverse effect. Repayment of borrowings under the Five-Year Revolving Credit Facility is subject to acceleration upon the occurrence of an event of default. We are also subject to various covenants under the indentures pursuant to which our public debt was issued, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in certain merger, consolidation or reorganization transactions. A default under our public debt indentures, our capital lease contract or any other debt owed to unaffiliated entities that exceeds $125 million could trigger a default under the Five-Year Revolving Credit Facility and, if not waived by the lenders, could cause us to lose access to the Five-Year Revolving Credit Facility.

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We may borrow under the Five-Year Revolving Credit Facility at either (1) the adjusted London Interbank Offered Rate (“LIBOR”) plus a margin (the “Five-Year Revolving Credit Facility Margin”), which ranges from 1.125 percent to 2.0 percent based on the credit rating of our non-credit enhanced senior unsecured long-term debt (“Debt Rating”), or (2) the base rate specified in the credit agreement plus the Five-Year Revolving Credit Facility Margin, less one percent per annum. Throughout the term of the Five-Year Revolving Credit Facility, we pay a facility fee on the daily unused amount of the underlying commitment which ranges from 0.15 percent to 0.35 percent depending on our Debt Rating. At April 28, 2015, based on our Debt Rating on that date, the Five-Year Revolving Credit Facility Margin was 1.75 percent and the facility fee was 0.275 percent. At April 28, 2015, we had no borrowings outstanding, no letters of credit issued, and $3.0 billion of available borrowing capacity under the Five-Year Revolving Credit Facility.

Eksportfinans Loans—We have outstanding borrowings under the Loan Agreement dated September 12, 2008 (“Eksportfinans Loan A”) and outstanding borrowings under the Loan Agreement dated November 18, 2008 (“Eksportfinans Loan B,” and together with Eksportfinans Loan A, the “Eksportfinans Loans”), between one of our subsidiaries and Eksportfinans ASA, which were established to finance the construction and delivery of the Harsh Environment Ultra-Deepwater semisubmersibles Transocean Spitsbergen and Transocean Barents. Eksportfinans Loan A and Eksportfinans Loan B bear interest at a fixed rate of 4.15 percent and require semi-annual installments of principal and interest through September 2017 and January 2018, respectively. At April 28, 2015, borrowings of $132 million and $158 million were outstanding under Eksportfinans Loan A and Eksportfinans Loan B, respectively.

The Eksportfinans Loans require restricted cash investments to be held at a certain financial institution through expiration (the “Eksportfinans Restricted Cash Investments”). The Eksportfinans Restricted Cash Investments bear interest at a fixed rate of 4.15 percent with semi-annual installments that correspond with those of the Eksportfinans Loans. At April 28, 2015, the aggregate principal amount of the Eksportfinans Restricted Cash Investments was $290 million.

Capital lease contract—Petrobras 10000 is held by one of our subsidiaries under a capital lease contract that requires scheduled monthly payments of $6 million through its stated maturity on August 4, 2029, at which time our subsidiary will have the right and obligation to acquire Petrobras 10000 from the lessor for one dollar. Upon the occurrence of certain termination events, our subsidiary is also required to purchase Petrobras 10000 and pay a termination amount determined by a formula based upon the total cost of the drillship. The capital lease contract includes limitations on creating liens on Petrobras 10000 and requires our subsidiary to make certain representations in connection with each monthly payment, including with respect to the absence of pending or threatened litigation or other proceedings against our subsidiary or any of its affiliates, which, if determined adversely, could have a material adverse effect on our subsidiary’s ability to perform its obligations under the capital lease contract. Additionally, Transocean Inc. has guaranteed the obligations under the capital lease contract, and Transocean Inc. is required to maintain an adjusted net worth, as defined, of at least $5.0 billion as of the end of each fiscal quarter. In the event Transocean Inc. does not satisfy this covenant at the end of any fiscal quarter, it is required to deposit the deficit amount, determined as the difference between $5.0 billion and the adjusted net worth for such fiscal quarter, into an escrow account for the benefit of the lessor. At April 28, 2015, $607 million was outstanding under the capital lease contract.

Plea Agreement obligations—Pursuant to a cooperation guilty plea agreement by and among the DOJ and certain of our affiliates (the “Plea Agreement”), which was accepted by the court on February 14, 2013, we agreed to pay a criminal fine of $100 million and to consent to the entry of an order requiring us to pay a total of $150 million to the National Fish & Wildlife Foundation, and $150 million to the National Academy of Sciences. In the three months ended March 31, 2015, we paid a scheduled installment of $60 million. At April 28, 2015, the remaining balance of our Plea Agreement obligations was $120 million, payable to the National Academy of Sciences, $60 million of which is due on or before February 12, 2016 and $60 million of which is due on or before February 14, 2017.

Consent Decree obligations—Pursuant to a civil consent decree by and among the DOJ and certain of our affiliates (the “Consent Decree”), which was approved by the court on February 19, 2013, we agreed to pay a civil penalty totaling $1.0 billion, plus interest at a fixed rate of 2.15 percent. In the three months ended March 31, 2015, we paid the final installment of $204 million, including interest, in satisfaction of our obligations due under the Consent Decree.

Share repurchase program—In May 2009, at our annual general meeting, our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to CHF 3.5 billion, which is equivalent to approximately $3.6 billion at an exchange rate as of the close of trading on April 28, 2015 of $1.00 to CHF 0.96. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We intend to fund any repurchases using available cash balances and cash from operating activities. On May 24, 2013, we received approval from the Swiss authorities for the continuation of the share repurchase program for an additional three-year repurchase period through May 23, 2016. In the three months ended March 31, 2015, we did not purchase shares under our share repurchase program.

We may decide, based upon our ongoing capital requirements, our program of distributions to our shareholders, the price of our shares, matters relating to the Macondo well incident, regulatory and tax considerations, cash flow generation, the amount and duration of our contract backlog, general market conditions, debt ratings considerations and other factors, that we should retain cash, reduce debt, make capital investments or acquisitions or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no additional shares under this program. Decisions regarding the amount, if any, and timing of any share repurchases will be made from time to time based upon these factors.

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Any shares repurchased under this program are expected to be purchased from time to time either, with respect to the U.S. market, from market participants that have acquired those shares on the open market and that can fully recover Swiss withholding tax resulting from the share repurchase or, with respect to the Swiss market, on the second trading line for our shares on the SIX. Repurchases could also be made by tender offer, in privately negotiated transactions or by any other share repurchase method. Any repurchased shares would be held by us for cancellation by the shareholders at a future annual general meeting. The share repurchase program could be suspended or discontinued by our board of directors or company management, as applicable, at any time.

Under Swiss corporate law, the right of a company and its subsidiaries to repurchase and hold its own shares is limited. A company may repurchase its shares to the extent it has freely distributable reserves as shown on its Swiss statutory balance sheet in the amount of the purchase price and the aggregate par value of all shares held by the company as treasury shares does not exceed 10 percent of the company’s share capital recorded in the Swiss Commercial Register, whereby for purposes of determining whether the 10 percent threshold has been reached, shares repurchased under a share repurchase program for cancellation purposes authorized by the company’s shareholders are disregarded. As of April 28, 2015, Transocean Inc., our wholly owned subsidiary, held as treasury shares approximately three percent of our issued shares. At the annual general meeting in May 2009, the shareholders approved the release of CHF 3.5 billion of additional paid-in capital to other reserves, or freely available reserves as presented on our Swiss statutory balance sheet, to create the freely available reserve necessary for the CHF 3.5 billion share repurchase program for the purpose of the cancellation of shares (the “Currently Approved Program”). At the May 2011 annual general meeting, our shareholders approved the reallocation of CHF 3.2 billion, which is the remaining amount authorized under the share repurchase program, from free reserve to legal reserve, reserve from capital contributions. This amount will continue to be available for Swiss federal withholding tax-free share repurchases. We may only repurchase shares to the extent freely distributable reserves are available. Our board of directors could, to the extent freely distributable reserves are available, authorize the repurchase of additional shares for purposes other than cancellation, such as to retain treasury shares for use in satisfying our obligations in connection with incentive plans or other rights to acquire our shares. Based on the current amount of shares held as treasury shares, approximately seven percent of our issued shares could be repurchased for purposes of retention as additional treasury shares. Although our board of directors has not approved such a share repurchase program for the purpose of retaining repurchased shares as treasury shares, if it did so, any such shares repurchased would be in addition to any shares repurchased under the Currently Approved Program.

Contractual obligations—As of March 31, 2015, there have been no material changes to the contractual obligations as previously disclosed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2014.

Other commercial commitments—As of March 31, 2015, there have been no material changes to the commercial commitments as previously disclosed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2014.

Derivative instruments

Our board of directors has approved policies and procedures for derivative instruments that require the approval of our Chief Financial Officer prior to entering into any derivative instruments. From time to time, we may enter into a variety of derivative instruments in connection with the management of our exposure to fluctuations in interest rates or currency exchange rates. We do not enter into derivative transactions for speculative purposes; however, we may enter into certain transactions that do not meet the criteria for hedge accounting. See Notes to Condensed Consolidated Financial Statements—Note 11—Derivatives and Hedging.

In April 2015, we terminated the interest rate swaps that were designated as a fair value hedge of the 6.5% Senior Notes due November 2020. In connection with the terminations, we received an aggregate net cash payment of $24 million.

Contingencies

Except as noted in this report, including in our Notes to Condensed Consolidated Financial Statements—Note 6—Income Taxes, Note 13—Commitments and Contingencies and Note 18—Subsequent Events, there have been no material changes to those actions, claims and other matters pending as discussed in Notes to Consolidated Financial Statements—Note 15—Commitments and Contingencies, Note 27—Subsequent Events and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident” in our annual report on Form 10-K for the year ended December 31, 2014. As of March 31, 2015, we were also involved in a number of lawsuits which have arisen in the ordinary course of our business and for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated financial position, results of operations or cash flows. We can provide no assurance that our expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Macondo well incident

Overview—On April 22, 2010, the Ultra-Deepwater Floater Deepwater Horizon sank after a blowout of the Macondo well caused a fire and explosion on the rig. Eleven persons were declared dead and others were injured as a result of the incident. At the time of the explosion, Deepwater Horizon was located approximately 41 miles off the coast of Louisiana in Mississippi Canyon Block 252 and was contracted to an affiliate of BP plc (together with its affiliates, “BP”). The rig was declared a total loss. Although we are unable to estimate the full direct and indirect effect that the Macondo well incident will have on our business, the incident has had and could continue to have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows.

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We have recognized a liability for estimated loss contingencies associated with litigation and investigations resulting from the incident that we believe are probable and for which a reasonable estimate can be made. At March 31, 2015 and December 31, 2014, the liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made was $426 million, recorded in other current liabilities. The litigation and investigations also give rise to certain loss contingencies that we believe are either reasonably possible or probable but for which we do not believe a reasonable estimate can be made. Although we have not recognized a liability for such loss contingencies, these contingencies could result in liabilities that we ultimately recognize.

We have also recognized an asset associated with the portion of our estimated losses, primarily related to the personal injury and fatality claims of our crew and vendors, that we believe is probable of recovery from insurance. At March 31, 2015 and December 31, 2014, the insurance recoverable asset was $10 million, recorded in other assets. Although we have available policy limits that could result in additional amounts recoverable from insurance, recovery of such additional amounts is not probable and we are not currently able to estimate such amounts. Our estimates involve a significant amount of judgment. As a result of new information or future developments, we may increase our estimated loss contingencies arising out of the Macondo well incident or reduce our estimated recoveries from insurance, and the resulting losses could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

We can provide no assurance as to the outcome of the trial, the timing of any upcoming phase of trial or ruling, that we will not enter into additional settlements as to some or all of the matters related to the Macondo well incident, including those to be determined at a trial, or the timing or terms of any such settlement. We can provide no assurance as to the estimated costs, insurance recoveries, or other actions that will result from the Macondo well incident.

Multidistrict litigation proceeding—Many of the Macondo well related claims are pending in the U.S. District Court for the Eastern District of Louisiana (the “MDL Court”). In March 2012, BP and the Plaintiff’s Steering Committee (the “PSC”) announced that they had agreed to a partial settlement related primarily to private party environmental and economic loss claims as well as response effort related claims (the “BP/PSC Settlement”). On December 21, 2012, the MDL Court granted final approval of the economic and property damage class settlement between BP and the PSC. Various parties who objected to the BP/PSC Settlement filed appeals in the U.S. Court of Appeals for the Fifth Circuit (the “Fifth Circuit”) challenging the MDL Court’s final approval of the BP/PSC Settlement. BP filed appeals in the Fifth Circuit challenging the manner in which the BP/PSC Settlement has been interpreted by the MDL Court with respect to business economic loss claims (“BEL Claims”). In these appeals, BP argues that, if the MDL Court’s interpretation of the settlement with respect to BEL Claims is not overturned, the entire BP/PSC Settlement is invalid and should not have been approved. On October 2, 2013, a panel of the Fifth Circuit issued an opinion questioning the manner in which the settlement had been interpreted with respect to BEL Claims. On December 24, 2013, the MDL Court issued an order (the “BEL Order”) regarding the BEL Claims. BP appealed the BEL Order, but on March 3, 2014, the same panel of the Fifth Circuit affirmed the MDL Court’s ruling that claimants were not required to submit evidence of causation.

On January 10, 2014, another panel of the Fifth Circuit affirmed the MDL Court’s final approval of the BP/PSC Settlement. Thereafter, BP and certain plaintiffs who objected to the settlement filed petitions seeking rehearing in the Fifth Circuit of both decisions. On May 20, 2014, the Fifth Circuit denied those petitions. On August 1, 2014, BP filed a petition for writ of certiorari in the U.S. Supreme Court seeking review of the Fifth Circuit’s decisions. On December 8, 2014, the Supreme Court denied BP’s petition for certiorari.

In December 2012, in response to the BP/PSC Settlement, we filed three motions seeking partial summary judgment on various claims, including punitive damages claims. If successful, these motions would eliminate or reduce our exposure to punitive damages. The MDL Court has not yet ruled on these motions.

The first phase of the trial began on February 25, 2013 and testimony concluded on April 17, 2013. This phase addressed fault issues, including negligence, gross negligence, or other bases of liability of the various defendants with respect to the cause of the blowout and the initiation of the oil spill, as well as limitation of liability issues. On September 4, 2014, the MDL Court entered Findings of Fact and Conclusions of Law for the Phase One trial. The MDL Court concluded that BP was grossly negligent and reckless and 67 percent at fault for the blowout, explosion, and spill; that Transocean was negligent and 30 percent at fault; and that Halliburton was negligent and three percent at fault. Because the MDL Court found that Transocean was not grossly negligent, it concluded that BP’s contractual agreement to indemnify us for compensatory damages is valid and enforceable and that we no longer have exposure for punitive damages. The MDL Court also ruled that BP’s contractual agreement to release its own claims against us is valid and enforceable. This release bars the PSC from pursuing claims that have been assigned to it by BP in the BP/PSC Settlement.

On October 2, 2014, BP filed a motion to amend the Phase One Findings of Fact and Conclusions of Law, alter or amend the judgment, or for a new trial. That motion asserts that the MDL Court made errors in its conclusions about the causes of the failure of the cement in the well. On November 13, 2014, the MDL Court denied this motion.

The second phase of the trial occurred between September 30, 2013 and October 17, 2013, and the MDL Court issued its Findings of Fact and Conclusions of Law (the “Phase Two Ruling”) on January 15, 2015. The first segment of the trial addressed BP’s conduct related to stopping the release of hydrocarbons. The MDL Court ruled that BP was not grossly negligent, reckless, willful or wanton in its source control planning before the spill. The MDL Court declined to decide whether BP was negligent in its planning because it ruled that any negligence finding would not change its fault determinations from the first phase of the trial. The MDL Court also found that it had not been shown that BP’s misrepresentations about the flow rate from the well delayed the capping of the well or adversely affected source control, or that post-blowout source control decisions were unreasonable.

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The second segment of the trial addressed quantification of the amount of oil discharged and the MDL Court found that four million barrels of oil discharged during the spill. After deducting the barrels that were collected, the MDL Court found that, for purposes of calculating the maximum CWA civil penalty that may be imposed on BP and Anadarko, 3.19 million barrels of oil discharged. We participated in the first segment of trial, but were not a party to the second segment because the ruling as to the quantification of oil primarily relates to setting maximum CWA civil penalty and we have settled the DOJ’s CWA penalty claim against us.

See Notes to Condensed Consolidated Financial Statements—Note 13—Commitments and Contingencies.

Insurance matters

Overview—Our hull and machinery and excess liability insurance program is comprised of commercial market and captive insurance policies that we renew annually on May 1. We periodically evaluate our insurance limits and self-insured retentions. Effective May 1, 2015, we renewed our hull and machinery and excess liability insurance policies with terms substantially similar to those of our former insurance program. At May 1, 2015, the insured value of our drilling rig fleet was approximately $26.5 billion, excluding our rigs under construction. We generally do not carry commercial market insurance coverage for loss of revenues or 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.

See Notes to Condensed Consolidated Financial Statements—Note 13—Commitments and Contingencies.

Tax matters

We are a Swiss corporation, and we operate through our various subsidiaries in a number of countries throughout the world. Our provision for income taxes is based on the tax laws and rates applicable in the jurisdictions in which we operate and earn income. The relationship between our provision for or benefit from income taxes and our income or loss before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues rather than income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures. Generally, our annual marginal tax rate is lower than our annual effective tax rate.

We conduct operations through our various subsidiaries in a number of countries throughout the world. Each country has its own tax regimes with varying nominal rates, deductions and tax attributes. From time to time, we may identify changes to previously evaluated tax positions that could result in adjustments to our recorded assets and liabilities. Although we are unable to predict the outcome of these changes, we do not expect the effect, if any, resulting from these adjustments to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

We file federal and local tax returns in several jurisdictions throughout the world. Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments. We are defending our tax positions in those jurisdictions. We are also defending against tax-related claims in courts, including our ongoing criminal trial in Norway.

While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated statement of financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows.

See Notes to Condensed Consolidated Financial Statements—Note 6—Income Taxes.

Regulatory matters

For a description of regulatory and environmental matters relating to the Macondo well incident, please see “—Macondo well incident.”

Other matters

In addition, from time to time, we receive inquiries from governmental regulatory agencies regarding our operations around the world, including inquiries with respect to various tax, environmental, regulatory and compliance matters. To the extent appropriate under the circumstances, we investigate such matters, respond to such inquiries and cooperate with the regulatory agencies.

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Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements. This discussion should be read in conjunction with disclosures included in the notes to our condensed consolidated financial statements related to estimates, contingencies and other accounting policies. Significant accounting policies are discussed in Note 2 to our condensed consolidated financial statements in this quarterly report on Form 10-Q and in Note 2 to our consolidated financial statements in our annual report on Form 10-K for the year ended December 31, 2014.

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 allowance for doubtful accounts, materials and supplies obsolescence, investments, property and equipment, income taxes, defined benefit pension plans and other postretirement employee benefits, contingent liabilities and share-based compensation. These estimates require significant judgments, assumptions and estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 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 three months ended March 31, 2015, 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 in this quarterly report on Form 10-Q and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2014.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest rate risk—We are exposed to interest rate risk associated with our restricted cash investments, our long-term and short-term debt and our derivative instruments. For a discussion of our interest rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our annual report on Form 10-K for the year ended December 31, 2014. There have been no material changes to these previously reported matters during the three months ended March 31, 2015.

Currency exchange rate risk—We are exposed to currency exchange rate risk associated with our international operations. For a discussion of our currency exchange rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our annual report on Form 10-K for the year ended December 31, 2014. There have been no material changes to these previously reported matters during the three months ended March 31, 2015.

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 March 31, 2015 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 U.S. Securities and Exchange Commission’s rules and forms.

Internal control over financial reporting—There were no changes to our internal control over financial reporting during the quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

We have certain actions, claims and other matters pending as discussed and reported in “Part II. Item 8. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 15—Commitments and Contingencies” and “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident” in our annual report on Form 10-K for the year ended December 31, 2014. We are also involved in various tax matters as described in “Part II. Financial Statements and Supplementary Data—Notes to Consolidated Financial Statements—Note 6—Income Taxes” and in “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Tax matters” in our annual report on Form 10-K for the year ended December 31, 2014. All such actions, claims, tax and other matters are incorporated herein by reference.

As of March 31, 2015, we were also involved in a number of other lawsuits and other matters which have arisen in the ordinary course of our business and for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated statement of financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of the matters referred to above or of any such other pending or threatened litigation or legal proceedings. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Item 1A.

Risk Factors

There have been no material changes to the risk factors as previously disclosed in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2014, except as noted below.

Our status as a Swiss corporation may limit our flexibility with respect to certain aspects of our capital management.

Subject to specific exceptions, Swiss law grants preemptive rights to existing shareholders to subscribe for new issuances of shares. Swiss law also does not provide as much flexibility in the various terms that can attach to different classes of shares as the laws of some other jurisdictions. Further, new shares can only be issued at an issue price at or above the par value of the shares, currently CHF 15, equivalent to $15.46 based on a currency exchange rate of USD 1.00 to CHF 0.97 on March 31, 2015, should we choose to raise capital by issuing shares of the same class at a time when the trading price of the class of shares is below their then-current par value, we may be required to first effect a decrease in the par value of our shares by initiating a two-month statutory proceeding pursuant to Swiss corporate law. One of the prerequisites of such statutory proceeding is that shareholders approve the decrease in par value at a general meeting. Swiss law also reserves for approval by shareholders certain corporate actions over which a board of directors would have authority in some other jurisdictions. These Swiss law requirements relating to our equity and capital management may limit our flexibility.

The recent downgrades in our credit ratings by various credit rating agencies could impact our access to capital and materially adversely affect our business and financial condition.

Certain credit rating agencies have recently downgraded the credit ratings of our non-credit enhanced senior unsecured long-term debt (“Debt Rating”) on more than one occasion in the past. For example, in February 2015, Moody’s Investors Service downgraded our Debt Rating to Ba1 from Baa3, and in March 2015, Standard & Poor’s downgraded our Debt Rating to BB+ from BBB-, which both such Debt Ratings are considered below investment grade.

Our Debt Rating levels could have material adverse consequences on our business and future prospects and could:

§	limit our ability to access debt markets, including for the purpose of refinancing our existing debt;

§	cause us to refinance or issue debt with less favorable terms and conditions, which debt may require collateral and restrict, among other things, our ability to pay distributions or repurchase shares;

§	increase certain fees under our credit facilities and interest rates under agreements governing certain of our senior notes;

§	negatively impact current and prospective customers’ willingness to transact business with us;

§	impose additional insurance, guarantee and collateral requirements;

§	limit our access to bank and third-party guarantees, surety bonds and letters of credit; and

§	suppliers and financial institutions may lower or eliminate the level of credit provided through payment terms or intraday funding when dealing with us thereby increasing the need for higher levels of cash on hand, which would decrease our ability to repay debt balances.

The most recent downgrade has caused, and any further downgrades may cause, us to experience, any of the effects listed above. We cannot provide assurance that other credit rating agencies will not also downgrade our credit ratings to below investment grade levels in the near future.

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Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

Period	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2) (in millions)
January 2015	—	$	—	—	$	3,368
February 2015	—		—	—		3,368
March 2015	14,670		16.11	—		3,368
Total	14,670	$	16.11	—	$	3,368

_____________________________

(1)

Total number of shares purchased in the first quarter of 2015 consists of 14,670 shares withheld by us through a broker arrangement and limited to statutory tax in satisfaction of withholding taxes due upon the vesting of restricted shares granted to our employees under our Long-Term Incentive Plan.

(2)

In May 2009, at the annual general meeting of Transocean Ltd., our shareholders approved and authorized our board of directors, at its discretion, to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to CHF 3.5 billion, which is equivalent to approximately $3.6 billion at an exchange rate as of March 31, 2015 of USD 1.00 to CHF 0.97. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. On May 24, 2013, we received approval from the Swiss authorities for the continuation of the share repurchase program for a further three-year repurchase period through May 23, 2016. We may decide, based upon our ongoing capital requirements, our program of distributions to our shareholders, the price of our shares, matters relating to the Macondo well incident, regulatory and tax considerations, cash flow generation, the amount and duration of our contract backlog, general market conditions, debt rating considerations and other factors, that we should retain cash, reduce debt, make capital investments or acquisitions or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no additional shares under this program. Decisions regarding the amount, if any, and timing of any share repurchases would be made from time to time based upon these factors. Through March 31, 2015, we have repurchased a total of 2,863,267 of our shares under this share repurchase program at a total cost of $240 million, equivalent to an average cost of $83.74 per share. See “—Sources and uses of liquidity.”

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

Articles of Association of Transocean Ltd (incorporated by reference to Exhibit 3.1 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended September 30, 2014)

3.2

Organizational Regulations of Transocean Ltd. (incorporated by reference to Exhibit 3.2 to Transocean Ltd.’s Quarterly Report on Form 10-Q (Commission File No. 000-53533) for the quarter ended September 30, 2014)

10.1

Separation Agreement among Transocean Ltd., Transocean Offshore Deepwater Drilling Inc. and Steven Newman, dated March 31, 2015 (incorporated by reference to Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on April 1, 2015)

10.2

Employment Agreement between Transocean Ltd. and Ian C. Strachan, dated April 15, 2015 (incorporated by reference to Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on April 16, 2015)

10.3

Employment Agreement among Transocean Offshore Deepwater Drilling Inc., Transocean Ltd. and Jeremy D. Thigpen, dated April 21, 2015 (incorporated by reference to Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on April 22, 2015)

†

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.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 May 6, 2015.

TRANSOCEAN LTD.

By: /s/ Esa Ikäheimonen

Esa Ikäheimonen

Executive Vice President, Chief Financial Officer

(Principal Financial Officer)

By: /s/ David Tonnel

David Tonnel

Senior Vice President, Finance and Controller

(Principal Accounting Officer)

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