Edgar Filing: Transocean Ltd.

form10_q3q2010.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 September 30, 2010

¨ 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.)

Chemin de Blandonnet 10 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 October 26, 2010, 319,020,214 shares were outstanding.

TRANSOCEAN LTD.

INDEX TO FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 2010

PART I. FINANCIAL INFORMATION		Page
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	25
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	52
Item 4.	Controls and Procedures	53

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	54
Item 1A.	Risk Factors	54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 6.	Exhibits	61

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 September 30,						Nine months ended September 30,
	2010			2009			2010			2009

Operating revenues
Contract drilling revenues	$	2,204		$	2,602		$	6,935		$	8,061
Contract drilling intangible revenues		23			58			85			237
Other revenues		82			163			396			525
		2,309			2,823			7,416			8,823
Costs and expenses
Operating and maintenance		1,213			1,396			3,767			3,844
Depreciation, depletion and amortization		394			367			1,195			1,082
General and administrative		59			54			180			163
		1,666			1,817			5,142			5,089
Loss on impairment		—			(46	)		(2	)		(334	)
Gain (loss) on disposal of assets, net		2			(3	)		256			(3	)
Operating income		645			957			2,528			3,397

Other income (expense), net
Interest income		7			—			17			2
Interest expense, net of amounts capitalized		(142	)		(115	)		(415	)		(365	)
Loss on retirement of debt		(22	)		(7	)		(20	)		(17	)
Other, net		8			9			18			9
		(149	)		(113	)		(400	)		(371	)

Income before income tax expense		496			844			2,128			3,026
Income tax expense		118			138			345			573

Net income		378			706			1,783			2,453
Net income (loss) attributable to noncontrolling interest		10			(4	)		23			(5	)

Net income attributable to controlling interest	$	368		$	710		$	1,760		$	2,458

Earnings per share
Basic	$	1.15		$	2.20		$	5.47		$	7.63
Diluted	$	1.15		$	2.19		$	5.47		$	7.61

Weighted average shares outstanding
Basic		319			321			320			320
Diluted		319			322			320			321

See accompanying notes.

- 1 -

Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009

Net income	$	378		$	706		$	1,783		$	2,453

Other comprehensive income (loss) before income taxes
Unrecognized components of net periodic benefit cost		1			—			(9	)		(39	)
Recognized components of net periodic benefit cost		7			4			16			13
Unrealized loss on derivative instruments		(11	)		(10	)		(34	)		(3	)
Other, net		2			2			5			4

Other comprehensive loss before income taxes		(1	)		(4	)		(22	)		(25	)
Income taxes related to other comprehensive loss		—			—			(1	)		3
Other comprehensive loss, net of income taxes		(1	)		(4	)		(23	)		(22	)

Total comprehensive income		377			702			1,760			2,431
Total comprehensive loss attributable to noncontrolling interest		—			(14	)		(8	)		(4	)

Total comprehensive income attributable to controlling interest	$	377		$	716		$	1,768		$	2,435

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share data)

	September 30, 2010			December 31, 2009
	(Unaudited)
Assets
Cash and cash equivalents	$	4,636		$	1,130
Accounts receivable, net of allowance for doubtful accounts of $39 and $65 at September 30, 2010 and December 31, 2009, respectively		2,299			2,385
Materials and supplies, net of allowance for obsolescence of $69 and $66 at September 30, 2010 and December 31, 2009, respectively		501			462
Deferred income taxes, net		100			104
Assets held for sale		—			186
Other current assets		234			209
Total current assets		7,770			4,476

Property and equipment		27,644			27,383
Property and equipment of consolidated variable interest entities		2,192			1,968
Less accumulated depreciation		7,423			6,333
Property and equipment, net		22,413			23,018
Goodwill		8,132			8,134
Other assets		1,015			808
Total assets	$	39,330		$	36,436

Liabilities and equity
Accounts payable	$	791		$	780
Accrued income taxes		226			240
Debt due within one year		1,635			1,568
Debt of consolidated variable interest entities due within one year		82			300
Other current liabilities		2,030			730
Total current liabilities		4,764			3,618

Long-term debt		10,237			8,966
Long-term debt of consolidated variable interest entities		886			883
Deferred income taxes, net		652			726
Other long-term liabilities		1,752			1,684
Total long-term liabilities		13,527			12,259

Commitments and contingencies

Shares, CHF 15.00 par value, 502,852,947 authorized, 167,617,649 conditionally authorized, 335,235,298 issued at September 30, 2010 and December 31, 2009; 319,017,904 and 321,223,882 outstanding at September 30, 2010 and December 31, 2009, respectively		4,481			4,472
Additional paid-in capital		6,354			7,407
Treasury shares, at cost, 2,863,267 and none held at September 30, 2010 and December 31, 2009, respectively		(240	)		—
Retained earnings		10,768			9,008
Accumulated other comprehensive loss		(327	)		(335	)
Total controlling interest shareholders’ equity		21,036			20,552
Noncontrolling interest		3			7
Total equity		21,039			20,559
Total liabilities and equity	$	39,330		$	36,436

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

(Unaudited)

	Nine months ended September 30,
	2010			2009
Shares outstanding
Balance, beginning of period		321			319
Issuance of shares under share-based compensation plans		1			2
Purchases of shares held in treasury		(3	)		—
Balance, end of period		319			321
Shares
Balance, beginning of period	$	4,472		$	4,444
Issuance of shares under share-based compensation plans		9			26
Balance, end of period	$	4,481		$	4,470
Additional paid-in capital
Balance, beginning of period	$	7,407		$	7,313
Share-based compensation expense		79			66
Issuance of shares under share-based compensation plans		(13	)		7
Obligation for cash distribution		(1,123	)		—
Repurchases of convertible senior notes		11			19
Changes in ownership of noncontrolling interest and other, net		(7	)		(11	)
Balance, end of period	$	6,354		$	7,394
Treasury shares, at cost
Balance, beginning of period	$	—		$	—
Purchases of shares held in treasury		(240	)		—
Balance, end of period	$	(240	)	$	—
Retained earnings
Balance, beginning of period	$	9,008		$	5,827
Net income attributable to controlling interest		1,760			2,458
Balance, end of period	$	10,768		$	8,285
Accumulated other comprehensive loss
Balance, beginning of period	$	(335	)	$	(420	)
Other comprehensive loss attributable to controlling interest		8			(23	)
Balance, end of period	$	(327	)	$	(443	)
Total controlling interest shareholders’ equity
Balance, beginning of period	$	20,552		$	17,164
Total comprehensive income attributable to controlling interest		1,768			2,435
Share-based compensation expense		79			66
Issuance of shares under share-based compensation plans		(4	)		33
Purchases of shares held in treasury		(240	)		—
Obligation for cash distribution		(1,123	)		—
Repurchases of convertible senior notes		11			19
Changes in ownership of noncontrolling interest and other, net		(7	)		(11	)
Balance, end of period	$	21,036		$	19,706
Total noncontrolling interest
Balance, beginning of period	$	7		$	3
Net income (loss) attributable to noncontrolling interest		23			(5	)
Other comprehensive income (loss) attributable to noncontrolling interest		(31	)		1
Changes in ownership of noncontrolling interest and other, net		4			—
Balance, end of period	$	3		$	(1	)
Total equity
Balance, beginning of period	$	20,559		$	17,167
Total comprehensive income		1,760			2,431
Share-based compensation expense		79			66
Issuance of shares under share-based compensation plans		(4	)		33
Purchases of shares held in treasury		(240	)		—
Obligation for cash distribution		(1,123	)		—
Repurchases of convertible senior notes		11			19
Changes in ownership of noncontrolling interest and other, net		(3	)		(11	)
Balance, end of period	$	21,039		$	19,705

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Three months ended September 30,						Nine months ended September 30,
	2010			2009			2010			2009

Cash flows from operating activities
Net income	$	378		$	706		$	1,783		$	2,453
Adjustments to reconcile net income to net cash provided by operating activities
Amortization of drilling contract intangibles		(23	)		(58	)		(85	)		(237	)
Depreciation, depletion and amortization		394			367			1,195			1,082
Share-based compensation expense		26			23			79			66
Excess tax benefit from share-based compensation plans		—			(9	)		(1	)		(10	)
(Gain) loss on disposal of assets, net		(2	)		3			(256	)		3
Loss on impairment		—			46			2			334
Loss on retirement of debt		22			7			20			17
Amortization of debt issue costs, discounts and premiums, net		48			51			148			160
Deferred income taxes		(40	)		24			(74	)		50
Other, net		2			7			1			30
Deferred revenue, net		47			29			205			72
Deferred expenses, net		(18	)		(3	)		(55	)		(38	)
Changes in operating assets and liabilities		(125	)		213			188			441
Net cash provided by operating activities		709			1,406			3,150			4,423

Cash flows from investing activities
Capital expenditures		(304	)		(540	)		(983	)		(2,195	)
Proceeds from disposal of assets, net		—			2			51			10
Proceeds from insurance recoveries for loss of drilling unit		—			—			560			—
Proceeds from payments on notes receivable		10			—			31			—
Proceeds from short-term investments		—			29			5			422
Purchases of short-term investments		—			(34	)		—			(268	)
Joint ventures and other investments, net		(4	)		5			(5	)		5
Net cash used in investing activities		(298	)		(538	)		(341	)		(2,026	)

Cash flows from financing activities
Change in short-term borrowings, net		46			254			(131	)		(246	)
Proceeds from debt		2,000			26			2,054			345
Repayments of debt		(691	)		(1,173	)		(966	)		(2,583	)
Purchases of shares held in treasury		—			—			(240	)		—
Financing costs		(15	)		—			(15	)		(2	)
Proceeds from (taxes paid for) share-based compensation plans, net		(2	)		(6	)		(3	)		16
Excess tax benefit from share-based compensation plans		—			9			1			10
Other, net		(1	)		1			(3	)		(14	)
Net cash provided by (used in) financing activities		1,337			(889	)		697			(2,474	)

Net increase (decrease) in cash and cash equivalents		1,748			(21	)		3,506			(77	)
Cash and cash equivalents at beginning of period		2,888			907			1,130			963
Cash and cash equivalents at end of period	$	4,636		$	886		$	4,636		$	886

See accompanying notes.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Nature of 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. Our mobile offshore drilling fleet is considered one of the most modern and versatile fleets in the world. Specializing in technically demanding sectors of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services, we contract our drilling rigs, related equipment and work crews predominantly on a dayrate basis to drill oil and gas wells. At September 30, 2010, we owned, had partial ownership interests in or operated 139 mobile offshore drilling units. As of this date, our fleet consisted of 45 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 26 Midwater Floaters, 10 High-Specification Jackups, 55 Standard Jackups and three Other Rigs. We also have three Ultra-Deepwater Floaters under construction (see Note 8—Drilling Fleet).

We also provide oil and gas drilling management services, drilling engineering and drilling project management services, and we participate in oil and gas exploration and production activities. Drilling management services are provided through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our U.K. subsidiaries (together, “ADTI”). ADTI conducts drilling management services primarily on either a dayrate or a completed-project, fixed-price (or “turnkey”) basis. Oil and gas properties consist of exploration, development and production activities performed by Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, “CMI”), our oil and gas subsidiaries.

Note 2—Significant Accounting Policies

Basis of presentation—We have prepared our accompanying condensed consolidated financial statements without audit in accordance with accounting principles generally accepted in the United States (“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 identified. Operating results for the three and nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 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, 2009 and 2008 and for each of the three years ended December 31, 2009 included in our current report on Form 8-K filed on September 16, 2010.

Accounting estimates—The preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires us 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, property and equipment, investments, notes receivable, goodwill and other intangible assets, income taxes, share-based compensation, defined benefit pension plans and other postretirement benefits and contingencies. 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) unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) unobservable inputs that require significant 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.

Principles of consolidation—We consolidate those investments that meet the criteria of a variable interest entity where we are deemed to be the primary beneficiary for accounting purposes and for entities in which we have a majority voting interest. Intercompany transactions and accounts are eliminated in consolidation. We apply the equity method of accounting for investments in joint ventures and other entities when we have the ability to exercise significant influence over an 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 investments in joint ventures and other entities if we do not have the ability to exercise significant influence over the unconsolidated affiliate. See Note 4—Variable Interest Entities.

Share-based compensation—Share-based compensation expense was $26 million and $79 million for the three and nine months ended September 30, 2010, respectively. Share-based compensation expense was $23 million and $66 million for the three and nine months ended September 30, 2009, respectively.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Capitalized interest—We capitalize interest costs for qualifying construction and upgrade projects. We capitalized interest costs on construction work in progress of $20 million and $67 million for the three and nine months ended September 30, 2010, respectively. We capitalized interest costs on construction work in progress of $48 million and $143 million for the three and nine months ended September 30, 2009, respectively.

Reclassifications—We have made certain reclassifications to prior period amounts to conform with the current period’s presentation. These 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 15—Subsequent Events.

Note 3—New Accounting Pronouncements

Recently adopted accounting standards

Consolidation—Effective January 1, 2010, we adopted the accounting standards update that requires enhanced transparency of our involvement with variable interest entities, which (a) amends certain guidance for determining whether an enterprise is a variable interest entity, (b) requires a qualitative rather than a quantitative analysis to determine the primary beneficiary, and (c) requires continuous assessments of whether an enterprise is the primary beneficiary of a variable interest entity. We evaluated these requirements, particularly with regard to our interests in Transocean Pacific Drilling Inc. (“TPDI”) and Angola Deepwater Drilling Company Limited (“ADDCL”) and our adoption did not have a material effect on our condensed consolidated statement of financial position, results of operations or cash flows. See Note 4—Variable Interest Entities.

Fair value measurements and disclosures—Effective January 1, 2010, we adopted the effective provisions of the accounting standards update that clarifies existing disclosure requirements and introduces additional disclosure requirements for fair value measurements. The update requires entities to disclose the amounts of and reasons for significant transfers between Level 1 and Level 2, the reasons for any transfers into or out of Level 3, and information about recurring Level 3 measurements of purchases, sales, issuances and settlements on a gross basis. The update also clarifies that entities must provide (a) fair value measurement disclosures for each class of assets and liabilities and (b) information about both the valuation techniques and inputs used in estimating Level 2 and Level 3 fair value measurements. We have applied the effective provisions of this accounting standards update in preparing the disclosures in our notes to condensed consolidated financial statements and our adoption did not have a material effect on such disclosures. See Note 2—Significant Accounting Policies.

Subsequent events—Effective for financial statements issued after February 2010, we adopted the accounting standards update regarding subsequent events, which clarifies that SEC filers are not required to disclose the date through which management evaluated subsequent events in the financial statements. Our adoption did not have a material effect on the disclosures contained within our notes to condensed consolidated financial statements. See Note 2—Significant Accounting Policies.

Recently issued accounting standards

Fair value measurements and disclosures—Effective January 1, 2011, we will adopt the remaining provisions of the accounting standards update that clarifies existing disclosure requirements and introduces additional disclosure requirements for fair value measurements. The update requires entities to separately disclose information about purchases, sales, issuances, and settlements in the reconciliation of recurring Level 3 measurements on a gross basis. The update is effective for interim and annual periods beginning after December 15, 2010. We do not expect that our adoption will have a material effect on the disclosures contained in our notes to consolidated financial statements.

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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—TPDI and ADDCL, two joint venture companies in which we hold interests, were formed to own and operate certain ultra-deepwater drillships. We have determined that each of these joint venture companies meets the criteria of a variable interest entity for accounting purposes because their equity at risk is insufficient to permit them to carry on their activities without additional subordinated financial support from us. We have also determined, in each case, that we are the primary beneficiary for accounting purposes since (a) we have the power to direct the construction, marketing and operating activities, which are the activities that most significantly impact each entity’s economic performance, and (b) we have the obligation to absorb a majority of the losses or the right to receive a majority of the benefits that could be potentially significant to the variable interest entity. As a result, we consolidate TPDI and ADDCL in our condensed consolidated financial statements, we eliminate intercompany transactions, and we present the interests that are not owned by us as noncontrolling interest on our condensed consolidated balance sheets. The carrying amounts associated with these two joint venture companies, after eliminating the effect of intercompany transactions, were as follows (in millions):

	September 30, 2010						December 31, 2009
	Assets		Liabilities		Net carrying amount		Assets		Liabilities		Net carrying amount
Variable interest entity
TPDI	$	1,609	$	793	$	816	$	1,500	$	763	$	737
ADDCL		881		352		529		582		482		100
Total	$	2,490	$	1,145	$	1,345	$	2,082	$	1,245	$	837

Pacific Drilling Limited (“Pacific Drilling”), a Liberian company, owns the 50 percent interest in TPDI that is not owned by us, and we present its interest in TPDI as noncontrolling interest on our condensed consolidated balance sheets. Beginning on October 18, 2010, Pacific Drilling will have the unilateral right to exchange its interest in TPDI for our shares or cash, at its election, measured at an amount based on an appraisal of the fair value of the drillships, subject to certain adjustments. Accordingly, when this option becomes exercisable, we will reclassify the carrying amount of Pacific Drilling’s interest from permanent equity to temporary equity, located between liabilities and equity on our condensed consolidated balance sheets, since the event that gives rise to a potential redemption of the noncontrolling interest is not within our control.

Unconsolidated variable interest entities—In January 2010, we completed the sale of two Midwater Floaters, GSF Arctic II and GSF Arctic IV, to subsidiaries of Awilco Drilling Limited (“ADL”), a U.K. company (see Note 8—Drilling Fleet). We have determined that ADL meets the criteria of a variable interest entity for accounting purposes because its equity at risk is insufficient to permit it to carry on its activities without additional subordinated financial support. We have also determined that we are not the primary beneficiary for accounting purposes since, although we hold a significant financial interest in the variable interest entity and have the obligation to absorb losses or receive benefits that could be potentially significant to the variable interest entity, we do not have the power to direct the marketing and operating activities, which are the activities that most significantly impact the entity’s economic performance.

In connection with the sale, we received net cash proceeds of $38 million and non-cash proceeds in the form of two notes receivable in the aggregate amount of $165 million. The notes receivable, which are secured by the drilling units, have stated interest rates of 9 percent and are payable in scheduled quarterly installments of principal and interest through maturity in January 2015. We have also committed to provide ADL with a working capital loan, which is also secured by the drilling units, with a maximum borrowing amount of $35 million. Additionally, we continue to operate GSF Arctic IV under a short-term bareboat charter with ADL, which is expected to end in early November 2010. At September 30, 2010, the notes receivable and working capital loan receivable represented aggregate carrying amounts of $113 million and $6 million, respectively, which, together, represented our maximum exposure to loss.

Note 5—Impairments

Goodwill and other indefinite-lived intangible assets—During the nine months ended September 30, 2010, we recognized a loss on impairment of goodwill associated with our oil and gas properties reporting unit in the amount of $2 million ($0.01 per diluted share), which had no tax effect. The carrying amount of goodwill associated with our oil and gas properties reporting unit was $2 million at December 31, 2009.

During the nine months ended September 30, 2009, we determined that the trade name intangible asset associated with our drilling management services reporting unit was impaired due to market conditions resulting from the global economic downturn and continued pressure on commodity prices. We estimated the fair value of the trade name intangible asset using the relief from royalty method, a valuation methodology that applies the income approach. Our valuation required us to project the future performance of the drilling management services reporting unit based on unobservable inputs that require significant judgment for which there is little or no market data, including assumptions for future commodity prices, projected demand for our services, rig availability and dayrates. As a result, we determined that the carrying amount of the trade name intangible asset exceeded its fair value, and we recognized a loss on impairment of $6 million ($0.02 per diluted share), which had no tax effect, during the three and nine months ended September 30, 2009. The carrying amount of the trade name intangible asset, recorded in other assets on our condensed consolidated balance sheets, was $39 million at both September 30, 2010 and December 31, 2009.

- 8 -

Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Definite-lived intangible assets—During the three and nine months ended September 30, 2009, we determined that the customer relationships intangible asset associated with our drilling management services reporting unit was impaired due to market conditions resulting from the global economic downturn and continued pressure on commodity prices. We estimated the fair value of the customer relationships intangible asset using the multiperiod excess earnings method, a valuation methodology that applies the income approach. Our valuation required us to project the future performance of the drilling management services reporting unit based on unobservable inputs that require significant judgment for which there is little or no market data, including assumptions for future commodity prices, projected demand for our services, rig availability and dayrates. As a result of our impairment testing, we determined that the carrying amount of the customer relationships intangible asset exceeded its fair value and recognized losses on impairment of $40 million ($0.12 per diluted share) and $49 million ($0.15 per diluted share), both of which had no tax effect, during the three and nine months ended September 30, 2009, respectively. The carrying amount of the customer relationships intangible asset, recorded in other assets on our condensed consolidated balance sheets, was $60 million and $64 million at September 30, 2010 and December 31, 2009, respectively.

Assets held for sale—During the nine months ended September 30, 2009, we determined that GSF Arctic II and GSF Arctic IV, both previously classified as assets held for sale, were impaired due to the global economic downturn and pressure on commodity prices, both of which have had an adverse effect on our industry. We estimated the fair values of these rigs based on an 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 and considering our undertakings to the Office of Fair Trading in the U.K. (“OFT”) that required the sale of the rigs with certain limitations and in a limited amount of time. We based our estimates on unobservable inputs that require significant judgment, for which there is little or no market data, including non-binding price quotes from unaffiliated parties, considering the then-current market conditions and restrictions imposed by the OFT. As a result of our evaluation, we recognized a loss on impairment of $279 million ($0.87 per diluted share), which had no tax effect, for the nine months ended September 30, 2009. The carrying amount of assets held for sale was $186 million at December 31, 2009, and these assets were sold in the nine months ended September 30, 2010. See Note 8—Drilling Fleet.

Note 6—Income Taxes

Overview—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.

Tax provision—We conduct operations through our various subsidiaries in a number of countries throughout the world, all of which have taxation regimes with varying nominal rates, deductions, credits and other tax attributes. Our provision for income taxes is based on the tax laws and rates applicable in the jurisdictions in which we operate and earn income. There is little to no expected relationship between the provision for or benefit from income taxes and income or loss before income taxes considering, among other factors, (a) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (b) rig movements between taxing jurisdictions and (c) our rig operating structures.

Our estimated annual effective tax rates for the nine months ended September 30, 2010 and September 30, 2009 were 17.0 percent and 15.7 percent, respectively. These rates were based on projected annual income before income taxes for each period after adjusting for certain items, such as impairment losses, the gain resulting from the insurance recoveries on the loss of Deepwater Horizon and various other discrete items.

We record a valuation allowance for deferred tax assets, including those resulting from net operating losses, when it is more likely than not that we will not realize some or all of the benefit from the deferred tax assets. At September 30, 2010 and December 31, 2009, the valuation allowance for non-current deferred tax assets was $73 million and $69 million, respectively.

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 1999. For the nine months ended September 30, 2010 and September 30, 2009, the amount of current tax benefit recognized from the settlement of disputes with tax authorities and from the expiration of statutes of limitations was insignificant.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

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):

	September 30, 2010		December 31, 2009
Unrecognized tax benefits, excluding interest and penalties	$	481	$	460
Interest and penalties		226		200
Unrecognized tax benefits, including interest and penalties	$	707	$	660

Our tax returns in the other major jurisdictions in which we operate are generally subject to examination for periods ranging from three to six years. We have agreed to extensions beyond the statute of limitations in three major jurisdictions for up to 15 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 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.

Tax positions—With respect to our 2004 and 2005 U.S. federal income tax returns, the U.S. tax authorities have withdrawn all of their previously proposed tax adjustments, except a claim regarding transfer pricing for certain charters of drilling rigs between our subsidiaries, resulting in a total proposed adjustment of approximately $79 million, exclusive of interest. We believe an unfavorable outcome on this assessment with respect to 2004 and 2005 activities would not result in a material adverse effect on our consolidated financial position, results of operations or cash flows. Although we believe the transfer pricing for these charters is materially correct, we have been unable to reach a resolution with the tax authorities. In August 2010, we filed a petition with the U.S. Tax Court.

In May 2010, we received an assessment from the U.S. tax authorities related to our 2006 and 2007 U.S. federal income tax returns. We filed a protest letter with the U.S. tax authorities covering these assessments in July 2010. The significant issues raised in the assessment relate to transfer pricing for certain charters of drilling rigs between our subsidiaries and the creation of intangible assets resulting from the performance of engineering services between our subsidiaries. These two items would result in net adjustments of approximately $278 million of additional taxes, exclusive of interest. An unfavorable outcome on these adjustments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe our returns are materially correct as filed, and we intend to continue to vigorously defend against all such claims.

In addition, the assessment included adjustments related to a series of restructuring transactions that occurred between 2001 and 2004. These restructuring transactions ultimately resulted in the disposition of our interests in our former subsidiary TODCO in 2004 and 2005. The authorities are disputing the amount of capital losses resulting from the disposition of TODCO. We utilized a portion of the capital losses to offset capital gains on the 2006, 2007, 2008 and 2009 tax returns. The majority of the capital losses expired on December 31, 2009. The adjustments would also impact the amount of certain net operating losses and other carryovers into 2006 and later years. The authorities are also contesting the characterization of certain amounts of income received in 2006 and 2007 as capital gain and thus the availability of the capital gain for offset by the capital loss. Claims with respect to our U.S. federal income tax returns for 2006 through 2009 could result in net tax adjustments of approximately $295 million. An unfavorable outcome on these potential adjustments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe that our tax returns are materially correct as filed, and we intend to vigorously defend against any potential claims.

The assessment also included certain claims with respect to withholding taxes and certain other items resulting in net tax adjustments of approximately $166 million, exclusive of interest. In addition, the tax authorities assessed penalties associated with the various tax adjustments in the aggregate amount of approximately $92 million, exclusive of interest. We believe that our tax returns are materially correct as filed, and we intend to vigorously defend against any potential claims.

Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 2001 and 2002 as well as the actions of certain of our former external advisors on these transactions. The authorities issued tax assessments of (a) approximately $266 million plus interest, related to certain restructuring transactions, (b) approximately $116 million plus interest, related to the migration of a subsidiary that was previously subject to tax in Norway, (c) approximately $70 million plus interest, related to a 2001 dividend payment and (d) approximately $7 million plus interest, related to certain foreign exchange deductions and dividend withholding tax. We have filed or expect to file appeals to these tax assessments. We may be required to provide some form of financial security, in an amount up to $939 million, including interest and penalties, for these assessed amounts as this dispute is appealed and addressed by the Norwegian courts. The authorities have indicated that they plan to seek penalties of 60 percent on all matters. For these matters, we believe our returns are materially correct as filed, and we have and will continue to respond to all information requests from the Norwegian authorities. We intend to vigorously contest any assertions by the Norwegian authorities in connection with the various transactions being investigated.

- 10 -

Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

During the nine months ended September 30, 2010, our long-term liability for unrecognized tax benefits related to these Norwegian tax issues increased $3 million to $184 million due to the accrual of interest and exchange rate fluctuations. An unfavorable outcome on these Norwegian civil tax matters could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate resolution of these matters to have a material adverse effect on our consolidated financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows.

The Norwegian authorities issued notification of criminal charges against Transocean Ltd. and certain of its subsidiaries related to disclosures included in one of our Norwegian tax returns. This notification, however, does not itself constitute an indictment under Norwegian law nor does it initiate legal proceedings but represents a formal expression of suspicion and continued investigation. All income taxes, interest charges and penalties related to this Norwegian tax return have previously been settled. We believe that these charges are without merit and plan to vigorously defend Transocean Ltd. and its subsidiaries to the fullest extent.

Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. The Brazilian tax authorities have issued tax assessments totaling $115 million, plus a 75 percent penalty of $86 million and $111 million of interest through September 30, 2010. An unfavorable outcome on these proposed assessments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008, and we are currently engaged in the appeals process.

Note 7—Earnings Per Share

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

	Three months ended September 30,												Nine months ended September 30,
	2010						2009						2010						2009
	Basic			Diluted			Basic			Diluted			Basic			Diluted			Basic			Diluted
Numerator for earnings per share
Net income attributable to controlling interest	$	368		$	368		$	710		$	710		$	1,760		$	1,760		$	2,458		$	2,458
Undistributed earnings allocable to participating securities		(2	)		(2	)		(4	)		(4	)		(10	)		(10	)		(14	)		(14	)
Net income available to shareholders	$	366		$	366		$	706		$	706		$	1,750		$	1,750		$	2,444		$	2,444

Denominator for earnings per share
Weighted-average shares outstanding		319			319			321			321			320			320			320			320
Effect of stock options and other share-based awards		—			—			—			1			—			—			—			1
Weighted-average shares for per share calculation		319			319			321			322			320			320			320			321

Earnings per share	$	1.15		$	1.15		$	2.20		$	2.19		$	5.47		$	5.47		$	7.63		$	7.61

For the three and nine months ended September 30, 2010, 2.3 million and 2.1 million share-based awards, respectively, were excluded from the calculation since the effect would have been anti-dilutive. For the three and nine months ended September 30, 2009, 1.6 million and 1.7 million share-based awards, respectively, were excluded from the calculation since the effect would have been anti-dilutive.

The 1.625% Series A Convertible Senior Notes, 1.50% Series B Convertible Senior Notes and 1.50% Series C Convertible Senior Notes did not have an effect on the calculation for the periods presented. See Note 9—Debt.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 8—Drilling Fleet

Expansion—Construction work in progress, recorded in property and equipment, was $2.8 billion and $3.7 billion at September 30, 2010 and December 31, 2009, respectively. The following table presents actual capital expenditures and other capital additions, including capitalized interest, for our remaining major construction projects (in millions):

	Nine months ended September 30, 2010		Through December 31, 2009		Total costs

Discoverer India	$	188	$	541	$	729
Discoverer Luanda (a)		161		535		696
Deepwater Champion (b)		74		527		601
Dhirubhai Deepwater KG2 (c) (d)		36		641		677
Discover Inspiration (c)		11		667		678
Capitalized interest		67		183		250
Mobilization costs		54		19		73
Total	$	591	$	3,113	$	3,704

__________________________

(a)	The costs for Discoverer Luanda represent 100 percent of expenditures incurred since inception. ADDCL is responsible for all of these costs. We hold a 65 percent interest in ADDCL, and Angco Cayman Limited holds the remaining 35 percent interest.

(b)	These costs include our initial investment in Deepwater Champion of $109 million, representing the estimated fair value of the rig at the time of our merger with GlobalSantaFe Corporation (“GlobalSantaFe”) in November 2007.

(c)	The accumulated construction costs of these rigs are no longer included in construction work in progress, as their construction projects had been completed as of September 30, 2010.

(d)	The cost for Dhirubhai Deepwater KG2 represents 100 percent of TPDI’s expenditures, including those incurred prior to our investment in the joint venture. TPDI is responsible for all of these costs. We hold a 50 percent interest in TPDI, and Pacific Drilling holds the remaining 50 percent interest.

During the nine months ended September 30, 2010, we acquired GSF Explorer, an asset formerly held under capital lease, in exchange for a cash payment in the amount of $15 million, terminating the capital lease obligation. See Note 9—Debt.

Dispositions—During the nine months ended September 30, 2010, we completed the sale of two Midwater Floaters, GSF Arctic II and GSF Arctic IV. In connection with the sale, we received net cash proceeds of $38 million and non-cash proceeds in the form of two notes receivable in the aggregate amount of $165 million. The notes receivable, which are secured by the drilling units, have stated interest rates of 9 percent and are payable in scheduled quarterly installments of principal and interest through maturity in January 2015. We estimated the fair values of the notes receivable based on unobservable inputs that require significant judgment, for which there is little or no market data, including the credit rating of the buyer. We continue to operate GSF Arctic IV under a short-term bareboat charter with the new owner of the vessel, which is expected to end in early November 2010. As a result of the sale, we recognized a loss on disposal of assets in the amount of $15 million ($0.04 per diluted share), which had no tax effect for the nine months ended September 30, 2010. For the three and nine months ended September 30, 2010, we recognized gains on disposal of other unrelated assets in the amounts of $2 million and $4 million, respectively.

During the nine months ended September 30, 2009, we received net proceeds of $10 million in connection with our sale of Sedco 135-D and disposals of other unrelated property and equipment, and these disposals had no net effect on income taxes or net income. In addition, we received net proceeds of $4 million in exchange for our 45 percent ownership interest in Caspian Drilling Company Limited, which operates Dada Gorgud and Istigal under long-term bareboat charters with the owner of the rigs. During the three and nine months ended September 30, 2009, we recognized a loss on disposal of assets of $3 million, which had no tax effect.

Deepwater Horizon—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. The rig’s insured value was $560 million, which was not subject to a deductible, and our insurance underwriters declared the vessel a total loss. During the nine months ended September 30, 2010, we received $560 million in cash proceeds from insurance recoveries related to the loss of the drilling unit and, for the nine months ended September 30, 2010, we recognized a gain on the loss of the rig in the amount of $267 million ($0.83 per diluted share), which had no tax effect. See Note 12—Contingencies.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 9—Debt

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

	September 30, 2010						December 31, 2009
	Transocean Ltd. and subsidiaries		Consolidated variable interest entities		Consolidated total		Transocean Ltd. and subsidiaries		Consolidated variable interest entities		Consolidated total

ODL Loan Facility	$	10	$	—	$	10	$	10	$	—	$	10
Commercial paper program (a)		150		—		150		281		—		281
6.625% Notes due April 2011 (a)		167		—		167		170		—		170
5% Notes due February 2013		256		—		256		247		—		247
5.25% Senior Notes due March 2013 (a)		514		—		514		496		—		496
TPDI Credit Facilities due March 2015		—		578		578		—		581		581
4.95% Senior Notes due November 2015 (a)		1,099		—		1,099		—		—		—
ADDCL Credit Facilities due November 2017		—		242		242		—		454		454
TPDI Notes due October 2019		—		148		148		—		148		148
6.00% Senior Notes due March 2018 (a)		997		—		997		997		—		997
7.375% Senior Notes due April 2018 (a)		247		—		247		247		—		247
6.50% Senior Notes due November 2020 (a)		899		—		899		—		—		—
Capital lease obligation due July 2026		—		—		—		15		—		15
8% Debentures due April 2027 (a)		57		—		57		57		—		57
7.45% Notes due April 2027 (a)		96		—		96		96		—		96
7% Senior Notes due June 2028		312		—		312		313		—		313
Capital lease contract due August 2029		699		—		699		711		—		711
7.5% Notes due April 2031 (a)		598		—		598		598		—		598
1.625% Series A Convertible Senior Notes due December 2037 (a)		1,291		—		1,291		1,261		—		1,261
1.50% Series B Convertible Senior Notes due December 2037 (a)		1,762		—		1,762		2,057		—		2,057
1.50% Series C Convertible Senior Notes due December 2037 (a)		1,719		—		1,719		1,979		—		1,979
6.80% Senior Notes due March 2038 (a)		999		—		999		999		—		999
Total debt		11,872		968		12,840		10,534		1,183		11,717
Less debt due within one year
ODL Loan Facility		10		—		10		10		—		10
Commercial paper program (a)		150		—		150		281		—		281
6.625% Notes due April 2011 (a)		167		—		167		—		—		—
TPDI Credit Facilities due March 2015		—		70		70		—		52		52
ADDCL Credit Facilities due November 2017		—		12		12		—		248		248
Capital lease contract due August 2029		17		—		17		16		—		16
1.625% Series A Convertible Senior Notes due December 2037 (a)		1,291		—		1,291		1,261		—		1,261
Total debt due within one year		1,635		82		1,717		1,568		300		1,868
Total long-term debt	$	10,237	$	886	$	11,123	$	8,966	$	883	$	9,849

__________________________

(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 commercial paper program and the Five-Year Revolving Credit Facility. Transocean Ltd. has no independent assets or operations, its guarantee of debt securities of Transocean Inc. is full and unconditional and its only other subsidiary, not owned indirectly through Transocean Inc., is minor. Transocean Inc.’s only operating assets are its investments in its operating subsidiaries. Transocean Inc.’s independent assets and operations, other than those related to investments in its subsidiaries and balances primarily pertaining to its cash and cash equivalents and debt are less than three percent of the total consolidated assets and operations of Transocean Ltd., and thus, substantially all of the assets and operations exist within these non-guarantor operating companies. Furthermore, Transocean Ltd. and Transocean Inc. are not subject to any significant restrictions on their ability to obtain funds from their consolidated subsidiaries or entities accounted for under the equity method by dividends, loans or return of capital distributions.

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Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Scheduled maturities—In preparing the scheduled maturities of our debt, we assume the noteholders will exercise their options to require us to repurchase the 1.625% Series A Convertible Senior Notes (the “Series A Notes”), 1.50% Series B Convertible Senior Notes (the “Series B Notes”) and 1.50% Series C Convertible Senior Notes (the “Series C Notes,” and collectively with the Series A Notes and the Series B Notes, the “Convertible Senior Notes”) in December 2010, 2011 and 2012, respectively. At September 30, 2010, the scheduled maturities of our debt were as follows (in millions):

	Transocean Ltd. and subsidiaries			Consolidated variable interest entities		Consolidated total
Twelve months ending September 30,
2011	$	1,641		$	82	$	1,723
2012		1,854			96		1,950
2013		2,630			98		2,728
2014		21			100		121
2015		23			329		352
Thereafter		5,904			263		6,167
Total debt, excluding unamortized discounts, premiums and fair value adjustments		12,073			968		13,041
Total unamortized discounts, premiums and fair value adjustments		(201	)		—		(201	)
Total debt	$	11,872		$	968	$	12,840

Commercial paper program—We maintain a commercial paper program, which is supported by the Five-Year Revolving Credit Facility, under which we may issue privately placed, unsecured commercial paper notes for general corporate purposes up to a maximum aggregate outstanding amount of $1.5 billion. At September 30, 2010, $150 million in commercial paper was outstanding at a weighted-average interest rate of 0.8 percent, including commissions.

Five-Year Revolving Credit Facility—We have a $2.0 billion, five-year revolving credit facility under the Five-Year Revolving Credit Facility Agreement dated November 27, 2007, as amended (the “Five-Year Revolving Credit Facility”). Throughout the term of the Five-Year Revolving Credit Facility, we pay a facility fee on the daily amount of the underlying commitment, whether used or unused, which ranges from 0.10 percent to 0.30 percent and was 0.175 percent at September 30, 2010. At September 30, 2010, we had $81 million in letters of credit issued and outstanding and no borrowings outstanding under the Five-Year Revolving Credit Facility.

TPDI Credit Facilities—TPDI has a bank credit agreement for a $1.265 billion secured credit facility (the “TPDI Credit Facilities”) comprised of a $1.0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, which was established to finance the construction of and is secured by Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the secured term loan with an aggregate commitment of $595 million. At September 30, 2010, $1.1 billion was outstanding under the TPDI Credit Facilities, of which $560 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate on September 30, 2010 was 1.9 percent. See Note 10—Derivatives and Hedging.

In April 2010, we had a letter of credit issued in the amount of $60 million on behalf of TPDI to satisfy its liquidity requirements under the TPDI Credit Facilities.

4.95% Senior Notes and 6.50% Senior Notes—In September 2010, we issued $1.1 billion aggregate principal amount of 4.95% Senior Notes due November 2015 (the “4.95% Senior Notes”) and $900 million aggregate principal amount of 6.50% Senior Notes due November 2020 (the “6.50% Senior Notes,” and together with the 4.95% Senior Notes, the “Senior Notes”). We are required to pay interest on the Senior Notes on May 15 and November 15 of each year, beginning November 15, 2010. We may redeem some or all of the Senior Notes at any time at a redemption price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any, and a make whole premium. The indenture pursuant to which the Senior Notes were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At September 30, 2010, $1.1 billion and $900 million aggregate principal amount of the 4.95% Senior Notes and 6.50% Senior Notes, respectively, were outstanding.

TPDI Notes—TPDI has issued promissory notes (the “TPDI Notes”) payable to its two shareholders, Pacific Drilling and one of our subsidiaries, which have maturities through October 2019. At September 30, 2010, the aggregate outstanding principal amount was $296 million, of which $148 million was due to one of our subsidiaries and has been eliminated in consolidation. The weighted-average interest rate on September 30, 2010 was 2.6 percent.

- 14 -

Index

TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Additionally, ADDCL has a secondary bank credit agreement for a $90 million credit facility (the “ADDCL Secondary Loan Facility”), for which one of our subsidiaries provides 65 percent of the total commitment. At September 30, 2010, $77 million was outstanding under the ADDCL Secondary Loan Facility, of which $50 million was provided by one of our subsidiaries and has been eliminated in consolidation. The weighted-average interest rate on September 30, 2010 was 3.4 percent.

Capital lease obligation—During the nine months ended September 30, 2010, we acquired GSF Explorer, an asset formerly held under a capital lease, in exchange for a cash payment of $15 million, thereby terminating the capital lease obligation. In connection with the termination of the capital lease obligation, we recognized a gain on debt retirement of $2 million, which had no per diluted share or tax effect. See Note 8—Drilling Fleet.

Convertible Senior Notes—The carrying amounts of the liability components of the Convertible Senior Notes were as follows (in millions):

	September 30, 2010							December 31, 2009
	Principal amount		Unamortized discount			Carrying amount		Principal amount		Unamortized discount			Carrying amount
Carrying amount of liability component
Series A Convertible Senior Notes due 2037	$	1,299	$	(8	)	$	1,291	$	1,299	$	(38	)	$	1,261
Series B Convertible Senior Notes due 2037		1,836		(74	)		1,762		2,200		(143	)		2,057
Series C Convertible Senior Notes due 2037		1,861		(142	)		1,719		2,200		(221	)		1,979

The carrying amounts of the equity components of the Convertible Senior Notes were as follows (in millions):

	September 30, 2010		December 31, 2009
Carrying amount of equity component
Series A Convertible Senior Notes due 2037	$	114	$	114
Series B Convertible Senior Notes due 2037		230		275
Series C Convertible Senior Notes due 2037		298		352

Including the amortization of the unamortized discount, the effective interest rates were 4.88 percent for the Series A Notes, 5.08 percent for the Series B Notes, and 5.28 percent for the Series C Notes. At September 30, 2010, the remaining period over which the discount will be amortized was less than a year for the Series A Notes, 1.2 years for the Series B Notes and 2.2 years for the Series C Notes. Interest expense, excluding amortization of debt issue costs, was as follows (in millions):

	Three months ended September 30,				Nine months ended September 30,
	2010		2009		2010		2009
Interest expense
Series A Convertible Senior Notes due 2037	$	15	$	19	$	46	$	66
Series B Convertible Senior Notes due 2037		25		25		77		75
Series C Convertible Senior Notes due 2037		25		25		77		75

Under certain conditions, holders have the right to convert the Convertible Senior Notes at the applicable conversion rate. As of September 30, 2010, the applicable conversion rate was 5.9310 shares per $1,000 note, equivalent to a conversion price of $168.61 per share. The conversion rate is subject to increase upon the occurrence of certain fundamental changes and adjustment for other corporate events, such as the distribution of cash to our shareholders (see Note 13—Equity).

During the three and nine months ended September 30, 2010, we repurchased an aggregate principal amount of $363 million of the Series B Notes for an aggregate cash payment of $351 million and an aggregate principal amount of $340 million of the Series C Notes for an aggregate cash payment of $318 million. In connection with the repurchases, we recognized a loss on retirement of $22 million ($0.07 per diluted share), with no tax effect, associated with the debt components of the repurchased notes, and we recorded additional paid-in capital of $11 million associated with the equity components of the repurchased notes. See Note 15—Subsequent Events.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

During the nine months ended September 30, 2009, we repurchased an aggregate principal amount of $615 million of the Series A Notes for an aggregate cash payment of $581 million. During the three and nine months ended September 30, 2009, we recognized a loss on retirement of $7 million ($0.02 per diluted share), with no tax effect, and $16 million ($0.05 per diluted share), with no tax effect, respectively, associated with the debt component of the Series A Notes and recorded additional paid-in capital of $19 million associated with the equity component of the Series A Notes.

Note 10—Derivatives and Hedging

Cash flow hedges—TPDI has entered into interest rate swaps, which have been designated and have qualified as a cash flow hedge, to reduce the variability of cash interest payments associated with the variable-rate borrowings under the TPDI Credit Facilities. The aggregate notional amount corresponds with the aggregate outstanding amount of the borrowings under the TPDI Credit Facilities. As of September 30, 2010, the aggregate notional amount was $1.1 billion, of which $560 million was attributable to the intercompany borrowings provided by one of our subsidiaries and the related balances have been eliminated in consolidation. At September 30, 2010, the weighted-average variable interest rate associated with the interest rate swaps was 0.5 percent, and the weighted-average fixed interest rate was 2.3 percent. At September 30, 2010, the interest rate swaps represented a liability measured at a fair value of $21 million, recorded in other long-term liabilities, with a corresponding increase to accumulated other comprehensive loss. At December 31, 2009, the interest rate swaps represented an asset measured at a fair value of $5 million, recorded in other assets, and a liability measured at a fair value of less than $1 million, recorded in other long-term liabilities, with a corresponding net decrease to accumulated other comprehensive loss. The amount associated with the ineffective portion of the cash flow hedges was less than $1 million, recorded in interest expense for the nine months ended September 30, 2010. There was no ineffectiveness for the three months ended September 30, 2010, or for the three and nine months ended September 30, 2009.

Fair value hedges—Two of our wholly owned subsidiaries have entered into interest rate swaps, which are designated and have qualified as fair value hedges, to reduce our exposure to changes in the fair values of the 5.25% Senior Notes and the 5.00% Notes. The interest rate swaps have aggregate notional amounts of $500 million and $250 million, respectively, equal to the 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. At September 30, 2010, the weighted-average variable interest rate on the interest rate swaps was 3.5 percent, and the fixed interest rates matched those of the underlying debt instruments. At September 30, 2010, the interest rate swaps represented an asset measured at fair value of $22 million, recorded in other assets, with a corresponding increase to the carrying amounts of the underlying debt instruments. At December 31, 2009, the interest rate swaps represented a liability measured at a fair value of $4 million, recorded in other long-term liabilities, with a corresponding decrease to the carrying amount of the underlying debt instrument.

Note 11—Postemployment Benefit Plans

Defined benefit pension plans and other postretirement employee benefit plans—We have several defined benefit pension plans, both funded and unfunded, covering substantially all of our U.S. employees, including certain frozen plans, assumed in connection with our mergers, that cover certain current employees and certain former employees and 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 our employees in those areas (the “Non-U.S. Plans”). Additionally, we offer several unfunded contributory and noncontributory other postretirement employee benefit plans (the “OPEB Plans”) covering substantially all of our U.S. employees. The components of net periodic benefit costs, before tax, and funding contributions were as follows (in millions):

	Three months ended September 30, 2010											Three months ended September 30, 2009
	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	$	10		$	5		$	—	$	15		$	11		$	5		$	—		$	16
Interest cost		14			7			1		22			12			4			—			16
Expected return on plan assets		(14	)		(5	)		—		(19	)		(13	)		(3	)		—			(16	)
Settlements and curtailments		6			1			—		7			2			1			—			3
Actuarial losses, net		3			(2	)		—		1			4			—			2			6
Prior service cost, net		—			—			—		—			—			—			(2	)		(2	)
Net periodic benefit costs	$	19		$	6		$	1	$	26		$	16		$	7		$	—		$	23

Funding contributions	$	14		$	29		$	1	$	44		$	3		$	13		$	1		$	17

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

	Nine months ended September 30, 2010												Nine months ended September 30, 2009
	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	$	31		$	15		$	1		$	47		$	33		$	13		$	1		$	47
Interest cost		41			15			2			58			37			12			1			50
Expected return on plan assets		(43	)		(13	)		—			(56	)		(40	)		(10	)		—			(50	)
Settlements and curtailments		8			2			—			10			4			1			—			5
Actuarial losses, net		10			2			—			12			13			—			2			15
Prior service cost, net		(1	)		—			(1	)		(2	)		(1	)		1			(2	)		(2	)
Net periodic benefit costs	$	46		$	21		$	2		$	69		$	46		$	17		$	2		$	65

Funding contributions	$	65		$	37		$	4		$	106		$	50		$	14		$	3		$	67

Note 12—Contingencies

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 BP America Production Co.

As we continue to investigate the cause or causes of the incident, we are evaluating its consequences. Although we cannot predict the final outcome or estimate the reasonably possible range of loss with certainty, as of September 30, 2010, we have recognized a liability of approximately $116 million, recorded in other current liabilities on our condensed consolidated balance sheet based on estimated losses related to the incident that we believe are probable and for which a reasonable estimate can be made. We believe that a portion of this liability is recoverable from insurance and have recognized a receivable of approximately $87 million, recorded in accounts receivable, net. New information or future developments could require us to adjust our disclosures and our estimated liabilities and insurance recoveries. See “—Retained risk” and “—Contractual indemnity.”

Litigation—As of September 30, 2010, 291 actions or claims were pending against Transocean entities, along with other unaffiliated defendants, in state and federal courts. Additionally, government agencies have initiated investigations into the Macondo well incident. We have categorized below the nature of the legal actions or claims. We are evaluating all claims and intend to vigorously defend any claims and pursue any and all defenses available. In addition, we believe we are entitled to contractual defense and indemnity for all wrongful death and personal injury claims made by non-employees and third-party subcontractors’ employees as well as all liabilities for pollution or contamination, other than for pollution or contamination originating on or above the surface of the water. See “—Contractual indemnity.”

Wrongful death and personal injury—As of September 30, 2010, we and one or more of our subsidiaries have been named, along with other unaffiliated defendants, in 19 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. The complaints generally allege negligence and seek awards of unspecified economic damages and punitive damages. BP plc (together with its affiliates, “BP”), MI-SWACO and Weatherford Ltd. 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.”

Economic loss—As of September 30, 2010, we and one or more of our subsidiaries were named, along with other unaffiliated defendants, in 70 individual complaints as well as 187 putative class-action complaints that were pending in the federal and state courts in Louisiana, Texas, Mississippi, Alabama, Georgia, Kentucky, South Carolina, Tennessee, Florida and possibly other courts. The complaints generally allege, among other things, potential economic losses as a result of environmental pollution arising out of the Macondo well incident and are based primarily on the Oil Pollution Act of 1990 (“OPA”) and state OPA analogues. See “—Environmental matters.” One complaint also alleges a violation of the Racketeer Influenced and Corrupt Organizations Act. The plaintiffs are generally seeking awards of unspecified economic, compensatory and punitive damages, as well as injunctive relief. See “—Contractual indemnity.” Per the order of the Multi-District Litigation Panel, the majority of the economic loss claims filed in federal courts have been centralized for discovery purposes in the U.S. District Court, Eastern District of Louisiana. Absent agreement of the parties, however, the cases will be tried in the courts from which they were transferred.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Federal securities claims—Three federal securities law class actions are currently pending, naming us and certain of our officers and directors as defendants. Though all three were originally filed in the U.S. District Court, Southern District of New York, one of the cases was dismissed and re-filed in the U.S. District Court, Southern District of Texas. Two of these actions generally allege violations of Section 10(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 10b-5 promulgated under the Exchange Act and Section 20(a) of the Exchange Act in connection with the Macondo well incident. The plaintiffs are generally seeking awards of unspecified economic damages, including damages resulting from the decline in our stock price after the Macondo well incident. The third action was filed by a former GlobalSantaFe shareholder, alleging that the proxy statement related to our shareholder meeting in connection with our merger with GlobalSantaFe violated Section 14(a) of the Exchange Act, Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act. The plaintiff claims that GlobalSantaFe shareholders received inadequate consideration for their shares as a result of the alleged violations and seeks rescission and compensatory damages.

While we cannot predict or provide assurance as to the final outcome of these federal securities claims, we believe the likelihood is no more than remote that they will have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Shareholder derivative claims—In June 2010, two shareholder derivative suits were filed by our shareholders naming us as a nominal defendant and certain of our officers and directors as defendants in the District Courts of the State of Texas. The first case generally alleges breach of fiduciary duty, unjust enrichment, abuse of control, gross mismanagement and waste of corporate assets in connection with the Macondo well incident and the other generally alleges breach of fiduciary duty, unjust enrichment and waste of corporate assets in connection with the Macondo well incident. The plaintiffs are generally seeking, on behalf of Transocean, restitution and disgorgement of all profits, benefits and other compensation from the defendants.

Additionally, two shareholder derivative suits were filed by BP shareholders, naming BP as a nominal defendant and asserting claims against other entities, including Cameron International Corporation, a subsidiary of Halliburton Company and us. Both of these cases were filed in the U.S. District Court, Eastern District of Louisiana, but have been transferred to the U.S. District Court, Southern District of Texas. The plaintiffs generally claim breach of contract, professional negligence, and aiding and abetting of alleged breaches of fiduciary duty of BP officers and directors by the non-BP defendants and seek contribution and the establishment of a constructive trust for any damages recovered.

Environmental matters—Environmental claims under two different schemes, statutory and common law, and in two different regimes, federal and state, have been asserted against us. See “—Litigation—Economic loss.” Liability under many statutes is imposed without fault, but such statutes often allow the amount of damages to be limited. In contrast, common law liability requires proof of fault and causation, but generally has no readily defined limitation on damages, other than the type of damages that may be redressed. We have described below certain significant applicable environmental statutes and matters relating to the Macondo well incident. As described below, we believe that we have limited statutory environmental liability and we are entitled to contractual defense and indemnity for all liabilities for pollution or contamination, other than for pollution or contamination originating on or above the surface of the water. See “—Contractual indemnity.”

Oil Pollution Act—OPA imposes strict liability on responsible parties of vessels or facilities from which oil is discharged into or upon navigable waters or adjoining shore lines. OPA defines the responsible parties with respect to the source of discharge. We believe that the owner or operator of a mobile offshore drilling unit (“MODU”), such as Deepwater Horizon, is only a responsible party with respect to discharges from the vessel that occur on or above the surface of the water. As the responsible party for Deepwater Horizon, we believe we are responsible only for the discharges of oil emanating from the rig. Therefore, we believe we are not responsible for the discharged hydrocarbons from the Macondo well.

Responsible parties for discharges are liable for: (1) removal and cleanup costs, (2) damages that result from the discharge, including natural resources damages, generally up to a statutorily defined limit, (3) reimbursement for government efforts and (4) certain other specified damages. For responsible parties of MODUs, the limitation on liability is determined based on the gross tonnage of the vessel. The statutory limits are not applicable, however, if the discharge is the result of gross negligence, willful misconduct, or violation of federal construction or permitting regulations by the responsible party or a party in a contractual relationship with the responsible party.

Additionally, the National Pollution Funds Center (“NPFC”), a division of the U.S. Coast Guard, is charged with administering the Oil Spill Liability Trust Fund (“OSLTF”). The NPFC collects fines and civil penalties under OPA from responsible parties, as defined in the statute. The payments are directed to the OSLTF. To date, the NPFC has issued seven invoices to BP, Anadarko Petroleum Corporation (together with its affiliates, “Anadarko”) and Mitsui & Co. (together with its affiliates, “Mitsui”), as the operator and owners of the well and, thus, the statutorily defined responsible parties for discharges from the well and wellhead. To date, BP has paid six of these invoices. Invoices have also been sent to us, and we have acknowledged responsible party status only with respect to discharges from the vessel on or above the surface of the water, if any.

We have also received claims directly from individuals, pursuant to OPA, requesting compensation for loss of income as a result of the Macondo well incident. BP has accepted responsible party status with the U.S. Coast Guard for the release of hydrocarbons from the Macondo well and has stated its intent to pay all legitimate claims, and we have not paid any of these claims.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Other federal statutes—Several of the claimants have made assertions under other statutes, including the Clean Water Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Air Act, the Comprehensive Environmental Response Compensation and Liability Act and the Emergency Planning and Community Right-to-Know Act.

State environmental laws—As of September 30, 2010, claims had been asserted by private claimants under state environmental statutes in Florida, Louisiana, Mississippi and Texas. As described below, claims asserted by various state and local governments are pending in Alabama, Florida, Louisiana and Texas.

In June 2010, the Louisiana Department of Environmental Quality (the “LDEQ”) issued a consolidated compliance order and notice of potential penalty to us and certain of our subsidiaries asking us to eliminate and remediate discharges of oil and other pollutants into waters and property located in the State of Louisiana, and to submit a plan and report in response to the order. We have requested that the LDEQ rescind the enforcement actions against us and our subsidiaries because the remediation actions that are the subject of such orders are actions that do not involve us or our subsidiaries, as we are not involved in the remediation or clean-up activities. Alternatively, if the LDEQ will not rescind the enforcement actions altogether, we have requested the LDEQ to dismiss the enforcement actions against us and certain of our subsidiaries as these entities are not proper parties to the enforcement actions and were improperly served. We have requested an administrative hearing on the charges alleged in these orders.

Additionally, suits have been filed by the State of Alabama and the cities of Greenville, Evergreen, Georgiana, and McKenzie, Alabama in the U.S. District Court, Middle District of Alabama; the Mexican States of Veracruz, Quintana Roo, and Tamaulipas in the U.S. District Court, Western District of Texas; and the City of Panama City Beach, Florida in the U.S. District Court, Northern District of Florida. Generally, these governmental entities allege economic losses under OPA and other statutory environmental state claims and also assert various common law state claims.

By letter dated May 5, 2010, the Attorneys General of the five Gulf Coast states of Alabama, Florida, Louisiana, Mississippi and Texas informed us that they intend to seek recovery of pollution clean-up costs and related damages arising from the Macondo well incident. 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 each 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 will similarly fulfill its obligations under OPA for discharges from the undersea well.

Wreck removal—We may be requested by authorities to remove the diesel fuel from the wreckage, if it is present, as well as various forms of debris from Deepwater Horizon. 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.

Contractual indemnity—Under our drilling contract for Deepwater Horizon, the operator has agreed, among other things, to assume full 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 for pollution or contamination originating on or above the surface of the water from hydrocarbons or other specified substances within the control and possession of the contractor, as to which we agreed to assume responsibility and protect, release and indemnify the operator. Although we do not believe it is applicable to the Macondo well incident, we also agreed to indemnify and defend the operator 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. The operator has also agreed, among other things, (1) 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 (2) 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 the operator for personal injury and death of our employees, invitees and the employees of our subcontractors while the operator agreed to defend, release and indemnify us for personal injury and death of its employees, invitees and the employees of its other subcontractors (other than us). We have also agreed to defend, release and indemnify the operator for damages to the rig and equipment, including salvage or removal costs.

Given the potential amounts involved in connection with the Macondo well incident, the operator may seek to avoid its indemnification obligations. In particular, the operator, in response to our request for indemnification, has generally reserved all of its rights and stated that it could not at this time conclude that it is obligated to indemnify us. In doing so, the operator has asserted that the facts are not sufficiently developed to determine who is responsible and has cited a variety of possible legal theories based upon the contract and facts still to be developed. We believe this reservation of rights is without justification and that the operator is required to honor its indemnification obligations contained in our contract and described above.

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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. A Special Master, appointed to administer these cases pre-trial, subsequently required that each individual plaintiff file a separate lawsuit, and the original 21 multi-plaintiff complaints were then dismissed by the Circuit Courts. The amended complaints resulted in one of our subsidiaries being named as a direct defendant in seven cases. We have or may have an indirect interest in an additional 17 cases. The complaints generally allege that the defendants used or manufactured asbestos-containing products 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. The plaintiffs generally seek awards of unspecified compensatory and punitive damages. 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. None of the cases in which one of our subsidiaries is a named defendant has been scheduled for trial in 2010, and the preliminary information available on these claims is not sufficient to determine if there is an identifiable period for alleged exposure to asbestos, whether any asbestos exposure in fact occurred, the vessels potentially involved in the claims, or the basis on which the plaintiffs would support claims that their injuries were related to exposure to asbestos. However, the initial evidence available would suggest that we would have significant defenses to liability and damages. In 2009, two cases that were part of the original 2004 multi-plaintiff suits went to trial in Mississippi against unaffiliated defendant companies which allegedly manufactured drilling-related products containing asbestos. We were not a defendant in either of these cases. One of the cases resulted in a substantial jury verdict in favor of the plaintiff, and this verdict was subsequently vacated by the trial judge on the basis that the plaintiff failed to meet its burden of proof. While the court’s decision is consistent with our general evaluation of the strength of these cases, it has not been reviewed on appeal. The second case resulted in a verdict completely in favor of the defendants. There have been no other trials involving any of the parties to the original 21 complaints. We intend to defend these lawsuits vigorously, although there can be no assurance as to the ultimate 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, fundings from settlements with insurers, assigned rights from insurers and “coverage-in-place” settlement agreements with insurers, and funds received from the cancellation of certain insurance policies. The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging personal injury as a result of exposure to asbestos. As of September 30, 2010, the subsidiary was a defendant in approximately 1,049 lawsuits. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 2,505 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 this subsidiary in 1990. Through September 30, 2010, the amounts expended to resolve claims, including both attorneys’ fees and expenses and settlement costs, have not been material, and all deductibles with respect to the primary insurance have been satisfied. 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 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 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 final outcome of these matters, we do not believe that the current value of the claims where we have been identified 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 approximately $179 million 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 subsidiary’s 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.

Patent litigation—In 2007, several of our subsidiaries were sued by Heerema Engineering Services (“Heerema”) in the United States District Court for the Southern District of Texas for patent infringement, claiming that we infringe their U.S. patent entitled Method and Device for Drilling Oil and Gas. Heerema claims that our Enterprise class, advanced Enterprise class, Express class and Development Driller class of drilling rigs operating in the U.S. Gulf of Mexico infringe on this patent. Heerema seeks unspecified damages and injunctive relief. The court has held a hearing on construction of their patent but has not yet issued a decision. We deny liability for patent infringement, believe that their patent is invalid and intend to vigorously defend against the claim. We do not expect the liability, if any, resulting from this claim 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)

Other matters—We are involved in various tax matters and various regulatory matters. We are also involved in lawsuits relating to damage claims arising out of hurricanes Katrina and Rita, all of which are insured and which are not material to us. In addition, as of September 30, 2010, we were involved in a number of other lawsuits, including a dispute for municipal tax payments in Brazil and a dispute involving customs procedures in India, neither of which is material to us, and 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 or threatened litigation. There can be no assurance that our beliefs or expectations as to the outcome or effect of any 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 the Comprehensive Environmental Response, Compensation and Liability Act (“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 U.S. Environmental Protection Agency (“EPA”) and the U.S. Department of Justice (“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:

§	the actual responsibility attributed to us and the other PRPs at the site;

§	appropriate investigatory or remedial actions; and

§	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:

§	the volume and nature of material, if any, contributed to the site for which we are responsible;

§	the numbers of other PRPs and their financial viability; and

§	the remediation methods and technology to be used.

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 financial position, or ongoing results of operations. Estimated costs of future expenditures for environmental remediation obligations are not discounted to their present value.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Contamination litigation

On July 11, 2005, one of our subsidiaries was served with a lawsuit filed on behalf of three landowners in Louisiana in the 12th Judicial District Court for the Parish of Avoyelles, State of Louisiana. The lawsuit named 19 other defendants, all of which were alleged to have contaminated the plaintiffs’ property with naturally occurring radioactive material, produced water, drilling fluids, chlorides, hydrocarbons, heavy metals and other contaminants as a result of oil and gas exploration activities. Experts retained by the plaintiffs issued a report suggesting significant contamination in the area operated by the subsidiary and another codefendant, and claimed that over $300 million would be required to properly remediate the contamination. The experts retained by the defendants conducted their own investigation and concluded that the remediation costs would amount to no more than $2.5 million.

The plaintiffs and the codefendant threatened to add GlobalSantaFe as a defendant in the lawsuit under the “single business enterprise” doctrine contained in Louisiana law. The single business enterprise doctrine is similar to corporate veil piercing doctrines. On August 16, 2006, our subsidiary and its immediate parent company, each of which is an entity that no longer conducts operations or holds assets, filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware. Later that day, the plaintiffs dismissed our subsidiary from the lawsuit. Subsequently, the codefendant filed various motions in the lawsuit and in the Delaware bankruptcies attempting to assert alter ego and single business enterprise claims against GlobalSantaFe and two other subsidiaries in the lawsuit. The efforts to assert alter ego and single business enterprise theory claims against GlobalSantaFe were rejected by the Court in Avoyelles Parish, and the lawsuit against the other defendant went to trial on February 19, 2007. This lawsuit was resolved at trial with a settlement by the codefendant that included a $20 million payment and certain cleanup activities to be conducted by the codefendant. The codefendant further claimed to receive a right to continue to pursue the original plaintiff's claims.

The codefendant sought to dismiss the bankruptcies. In addition, the codefendant filed proofs of claim against both our subsidiary and its parent with regard to its claims arising out of the settlement of the lawsuit. On February 15, 2008, the Bankruptcy Court denied the codefendant’s request to dismiss the bankruptcy case but modified the automatic stay to allow the codefendant to proceed on its claims against the debtors, our subsidiary and its parent, and their insurance companies. The codefendant subsequently filed suit against the debtors and certain of its insurers in the Court of Avoyelles Parish to determine their liability for the settlement. The denial of the motion to dismiss the bankruptcies was appealed. On appeal the bankruptcy cases were ordered to be dismissed, and the bankruptcies were dismissed on June 14, 2010.

On March 10, 2010, GlobalSantaFe and the two subsidiaries filed a declaratory judgment action in State District Court in Houston, Texas against the codefendant and the debtors seeking a declaration that GlobalSantaFe and the two subsidiaries had no liability under legal theories advanced by the codefendant. On March 11, 2010, the codefendant filed a motion for leave to amend the pending litigation in Avoyelles Parish to add GlobalSantaFe, Transocean Worldwide Inc., its successor and our wholly owned subsidiary, and one of the subsidiaries as well as various additional insurers. Leave to amend was granted and the amended petition was filed. An extension to respond for all purposes was agreed until April 28, 2010 for the debtors, GlobalSantaFe, Transocean Worldwide Inc. and the subsidiary. On April 28, 2010, GlobalSantaFe and its two subsidiaries filed various exceptions seeking dismissal of the Avoyelles Parish lawsuit, which have been denied.

We believe that these legal theories should not be applied against GlobalSantaFe or Transocean Worldwide Inc. Our subsidiary, its parent and GlobalSantaFe intend to continue to vigorously defend against any action taken in an attempt to impose liability against them under the theories discussed above or otherwise and believe they have good and valid defenses thereto. We do not believe that these claims will have a material impact on our consolidated statement of financial position, results of operations or cash flows.

Retained risk

Our hull and machinery and excess liability insurance program consists of commercial market and captive insurance policies primarily with 12-month and 11-month policy periods beginning on May 1, 2010 and June 1, 2010, respectively.

Under the hull and machinery program, we generally maintain a $125 million per occurrence deductible, limited to a maximum of $250 million per policy period. Subject to the same shared deductible, we also have coverage for costs incurred to mitigate damage to a rig up to an amount equal to 25 percent of a rig’s insured value. Also subject to the same shared deductible, we have coverage for wreck removal for an amount up to 25 percent of a rig’s insured value, with any excess generally covered to the extent of our excess liability coverage described below. However, the shared deductible is $0 in the event of a total loss or a constructive total loss of a drilling unit.

We carry $950 million of commercial market excess liability coverage, exclusive of 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 has separate (1) $10 million per occurrence deductibles on crew personal injury liability and on collision liability claims and (2) a separate $5 million per occurrence deductible on other third-party non-crew claims. These types of excess liability coverages are subject to an additional aggregate self-insured retention of $50 million that is applied to any occurrence in excess of the per occurrence deductible until the $50 million is exhausted. We generally retain the risk for any liability losses in excess of $1.0 billion.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

We also carry $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. As of September 30, 2010, the insured value of our drilling rig fleet was approximately $37.9 billion in the aggregate, excluding rigs under construction.

We have elected to self-insure operators extra expense coverage for ADTI and CMI. This coverage provides protection against expenses related to well control, pollution and redrill liability associated with blowouts. ADTI’s customers assume, and indemnify ADTI for, liability associated with blowouts in excess of a contractually agreed amount, generally $50 million.

We generally do not have commercial market insurance coverage for physical damage losses, including liability for wreck removal expenses, to our fleet caused by named windstorms in the U.S. Gulf of Mexico and war perils worldwide. Except with respect to Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2, we generally do not carry insurance for loss of revenue unless contractually required.

Letters of credit and surety bonds

We had letters of credit outstanding totaling $541 million and $567 million at September 30, 2010 and December 31, 2009, respectively. These letters of credit guarantee various contract bidding and performance activities under various committed and uncommitted credit lines provided by several banks. In April 2010, we had a letter of credit issued in the amount of $60 million on behalf of TPDI to satisfy its liquidity requirements under the TPDI Credit Facilities, which is included in the total as of September 30, 2010 (see Note 9—Debt).

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. Surety bonds outstanding totaled $25 million and $31 million at September 30, 2010 and December 31, 2009, respectively.

Note 13—Equity

Shares held by subsidiary—In December 2008, we issued 16 million of our shares to one of our subsidiaries 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 September 30, 2010 and December 31, 2009, our subsidiary held 13,354,127 shares and 14,011,416 shares, respectively.

During the nine months ended September 30, 2010, following the authorization by our board of directors, we repurchased 2,863,267 of our shares under our share repurchase program for an aggregate purchase price of CHF 257 million, equivalent to $240 million. We did not repurchase any of our shares during the three months ended September 30, 2010. At September 30, 2010, we held 2,863,267 treasury shares purchased under our share repurchase program, recorded at cost.

Distribution—In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.51, using an exchange rate of USD 1.00 to CHF 0.98 as of the close of trading on September 30, 2010. According to such shareholders’ approval, the cash distribution would be calculated and paid in four quarterly installments. Under Swiss law, upon satisfaction of all legal requirements, we must submit an application to the Commercial Register in the Canton of Zug to register the applicable par value reduction. On August 13, 2010, the Commercial Register of the Canton of Zug rejected our application to register the first of four planned partial par value reductions, and we have appealed this decision. Without effective registration of the applicable par value reduction, we will not be able to proceed with the payment of the first or any subsequent installment of our cash distribution to shareholders.

We intend to fund any installments using our available cash balances and our cash flows from operations. Shareholders are expected to be paid in U.S. dollars, converted using an exchange rate determined by us approximately two business days prior to the payment date, unless shareholders elect to receive the payment in Swiss francs. Distributions to shareholders in the form of a reduction in par value of our shares are not subject to the 35 percent Swiss withholding tax. In May 2010, we recognized a distribution payable in the amount of approximately $1.0 billion, recorded in other current liabilities, with a corresponding entry to additional paid-in capital. We adjust the carrying amount of the liability for changes in foreign currency exchange rates with a corresponding adjustment to additional paid-in capital. Upon registration of an installment with the Commercial Register of the Canton of Zug, we expect to reduce our par value and reclassify from additional paid-in capital to shares the portion of the distribution associated with the respective installment. At September 30, 2010, the carrying amount of the unpaid distribution payable was $1.1 billion.

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TRANSOCEAN LTD. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

Note 14—Fair Value of Financial Instruments

We estimate 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 approximates fair value because of the short maturities of those instruments.

Accounts receivable—The carrying amount, net of valuation allowance, approximates fair value because of the short maturities of those instruments.

Short-term investments—The carrying amount of our short-term investments approximates fair value and represents our estimate of the amount we expect to recover. Our short-term investments primarily include our investment in The Reserve International Liquidity Fund Ltd. At September 30, 2010 and December 31, 2009, the carrying amount of our short-term investments was $32 million and $38 million, respectively, recorded in other current assets on our condensed consolidated balance sheets.

Notes receivable and working capital loan receivable—The carrying amount represents the estimated fair value, measured using unobservable inputs that require significant judgment, for which there is little or no market data, including the credit rating of the borrower. At September 30, 2010, the aggregate carrying amount of our notes receivable and working capital loan receivable was $119 million, including $4 million and $115 million recorded in other current assets and other assets, respectively. We did not hold notes receivable as of December 31, 2009.

Debt—The fair value of our fixed-rate debt is measured using direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets. Our variable-rate debt is included in the fair values stated below at its carrying amount since the short-term interest rates cause the face value to approximate its fair value. The TPDI Notes and Overseas Drilling Limited (“ODL”) Loan Facility are included in the fair values stated below at their aggregate carrying amount of $158 million at September 30, 2010 and December 31, 2009, since there is no available market price for such related-party debt. The carrying amounts and estimated fair values of our long-term debt, including debt due within one year, were as follows (in millions):

	September 30, 2010				December 31, 2009
	Carrying amount		Fair value		Carrying amount		Fair value

Long-term debt, including current maturities	$	11,872	$	12,233	$	10,534	$	11,218
Long-term debt of consolidated variable interest entities, including current maturities		968		989		1,183		1,178

Derivative instruments—The carrying amount of our derivative instruments represents the estimated fair value, measured using direct or indirect observable inputs, including quoted prices or other market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets. At September 30, 2010, the carrying amounts of our derivative instruments were $22 million and $21 million, recorded in other assets and other long-term liabilities, respectively, on our condensed consolidated balance sheets. At December 31, 2009, the carrying amounts of our derivative instruments were $5 million and $5 million, recorded in other assets and other long-term liabilities, respectively, on our condensed consolidated balance sheets.

Note 15—Subsequent Events

Debt repurchases—As of November 3, 2010 and subsequent to September 30, 2010, we had repurchased aggregate principal amounts of $154 million and $139 million of the Series B Notes and the Series C Notes for aggregate cash payments of $152 million and $135 million, respectively.

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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 Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements in this quarterly report include, but are not limited to, statements about the following subjects:

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

the offshore drilling market, including the impact of the drilling moratorium in the United States (“U.S.”) Gulf of Mexico, 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 the downturn in the global economy or market outlook for our various geographical operating sectors and classes of rigs,

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

§	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,

§	liquidity and adequacy of cash flow for our obligations, including our ability and the expected timing to access certain investments in highly liquid instruments,

§	our results of operations and cash flow from operations, including revenues and expenses,

§	uses of excess cash, including the payment of dividends and other distributions, debt retirement , including repurchases of convertible senior notes, and share repurchases under our share repurchase program,

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

§	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 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,

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

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

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

§	those described under “Item 1A. Risk Factors” included herein and in our annual report on Form 10-K for the year ended December 31, 2009 and our quarterly reports on Form 10-Q for the three months ended March 31, 2010 and June 30, 2010,

§	the adequacy of and access to sources of liquidity,

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

§	our inability to renew contracts at comparable dayrates,

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

§	the effect and results of litigation, tax audits 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, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law.

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Index

Business

We have two reportable segments: (1) contract drilling services and (2) other operations. Contract drilling services, our primary business, involves contracting our mobile offshore drilling fleet, related equipment and work crews primarily on a dayrate basis to drill oil and gas wells. We believe our drilling fleet is one of the most modern and versatile fleets in the world, consisting of floaters, jackups and other rigs used in support of offshore drilling activities and offshore support services on a worldwide basis. We specialize in technically demanding regions of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services.

Our contract drilling 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.

Our other operations segment includes drilling management services and oil and gas properties. We provide drilling management services through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our U.K. subsidiaries (together, “ADTI”). ADTI provides oil and gas drilling management services on either a dayrate basis or a completed-project, fixed-price (or “turnkey”) basis, as well as drilling engineering and drilling project management services. Our oil and gas properties consist of exploration, development and production activities carried out through Challenger Minerals Inc. and Challenger Minerals (North Sea) Limited (together, “CMI”), our oil and gas subsidiaries.

Significant Events

Debt issuance—In September 2010, we issued $1.1 billion aggregate principal amount of 4.95% Senior Notes due November 2015 (the “4.95% Senior Notes”) and $900 million aggregate principal amount of 6.50% Senior Notes due November 2020 (the “6.50% Senior Notes” and together with the 4.95% Senior Notes, the “Senior Notes”). See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Debt repurchases—During the three and nine months ended September 30, 2010, we repurchased an aggregate principal amount of $363 million of our 1.50% Series B Convertible Senior Notes due 2037 (“Series B Notes”) for an aggregate cash payment of $351 million and an aggregate principal amount of $340 million of our 1.50% Series C Convertible Senior Notes due 2037 (“Series C Notes”) for an aggregate cash payment of $318 million. In connection with the repurchases, we recognized a loss on retirement of $22 million. As of November 3, 2010 and subsequent to September 30, 2010, we had repurchased aggregate principal amounts of $154 million and $139 million of the Series B Notes and the Series C Notes for aggregate cash payments of $152 million and $135 million, respectively. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Fleet expansion—In the nine months ended September 30, 2010, we completed construction of four Ultra-Deepwater newbuilds, two of which have commenced their respective contracts. See “—Outlook.”

Macondo well incident—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, and the rig has been declared a total loss. Eleven persons were declared dead and others were injured as a result of the incident. As investigations pertaining to the cause or causes of the incident continue, we are evaluating its consequences, which could ultimately have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. Although the rig was operating under a contract which was to extend through September 2013, the total loss of the rig resulted in an automatic termination of the agreement. At the time of the incident, the backlog associated with the Deepwater Horizon drilling contract was approximately $590 million. See “—Contingencies—Macondo well incident.”

Exchange listing—Effective April 20, 2010, our shares began trading on the SIX Swiss Exchange under the symbol “RIGN.” Our shares also continue to be listed on the New York Stock Exchange under the symbol “RIG.”

Share repurchase program—As of September 30, 2010, we had repurchased a total of 2,863,267 of our shares under our share repurchase program for an aggregate purchase price of CHF 257 million, equivalent to $240 million. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

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Index

Outlook

Drilling market—We expect market utilization to remain steady over the next few quarters for the jackup and midwater floater markets due to continued stability in oil and gas prices. Additionally, we expect this commodity price stability to result in contracting opportunities for all classes within our drilling fleet for the remainder of 2010 and throughout 2011. However, considering the potential impact of the available capacity in 2010 and 2011 resulting from uncontracted newbuilds and existing units in the market, coupled with the continued uncertainties surrounding the recently lifted drilling moratorium in the U.S. Gulf of Mexico, projected utilization for our High-Specification Floater fleet is uncertain. Consequently, we do not believe that the increased tendering activity that we are currently experiencing will lead to a corresponding increase in dayrates in the near term.

As of October 14, 2010, our contract backlog had declined to $26.1 billion from $27.6 billion as of July 15, 2010. Although we are currently engaged in advanced discussions with customers on several additional opportunities, our backlog may continue to decline if we are unable to obtain new contracts for our rigs that sufficiently replace existing backlog as it is consumed over time or if any contracts are terminated.

On May 30, 2010, the U.S. government implemented a moratorium on certain drilling activities in the U.S. Gulf of Mexico. On October 12, 2010, the U.S. government lifted the moratorium, which was originally expected to last until November 30, 2010. In order to obtain drilling permits and resume drilling activities, operators must submit applications that demonstrate compliance with enhanced regulations, which now require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. We are working in close consultation with our customers to review and implement the new rules and requirements. At the time the moratorium was implemented, we had 14 rigs under contract in the U.S. Gulf of Mexico. While the moratorium was in effect, two rigs were moved, at the customers’ elections, to locations outside of the U.S. Gulf of Mexico. We are unable to predict, with certainty, the full impact that the continuing effect of the moratorium and the enhanced regulations will have on our operations. The backlog associated with the contracts for our remaining rigs in the U.S. Gulf of Mexico was approximately $7 billion as of October 14, 2010, of which $2.0 billion could be lost if our customers are legally permitted to and choose to exercise their termination rights under certain contracts.

While the moratorium was in place, several customers either declared force majeure or indicated that they may declare force majeure under their respective contracts. We do not believe that a force majeure event existed as a result of the drilling moratorium nor do we believe that the enhanced regulations in effect following the moratorium amount to a force majeure event under the drilling contracts for the rigs in the U.S. Gulf of Mexico, but we cannot predict if customers may continue to assert claims of force majeure as a result of the new regulations. If an actual force majeure event occurs, as determined under the applicable drilling contract, these agreements generally allow for a period of 30 to 60 days during which the rig will earn a force majeure rate, which is generally between 85 percent and 100 percent of the contracted dayrate. Following this period, and in some cases subject to a notice or waiting period, either we or the customer may terminate the contract. In some contracts, we have the right to further extend the contract for a period of time by electing to continue the contract at a zero dayrate, thereby retaining the backlog associated with the contract for possible recognition in a later period. Some drilling contracts for rigs in the U.S. Gulf of Mexico include early termination provisions that require the payment of the contractual dayrate for the remaining term of the contract upon termination for force majeure either in a lump sum or over an extended term. We have, in some instances, negotiated, and may continue to negotiate special standby rates with some of our customers under our drilling contracts for rigs in the U.S. Gulf of Mexico. These special standby rates are significantly lower than the regular contract dayrate and apply during periods when the customer is prevented from performing drilling operations for reasons beyond the customer’s control. For every day on special standby rate, the contract term of the applicable contract is extended by an equal number of days.

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Index

Fleet status—The uncommitted fleet rate is the number of uncommitted days as a percentage of the total number of available rig calendar days in the period. As of October 14, 2010, the uncommitted fleet rates for the remainder of 2010, 2011, 2012 and 2013 are as follows:

	2010		2011		2012		2013
Uncommitted fleet rate
High-Specification Floaters	9	%	18	%	31	%	46	%
Midwater Floaters	35	%	59	%	81	%	95	%
High-Specification Jackups	48	%	52	%	77	%	100	%
Standard Jackups	55	%	69	%	85	%	93	%

As of October 14, 2010, we have nine existing contracts with fixed-price or capped options that are exercisable, at the customer’s discretion, any time through their expiration dates. During periods when dayrates on new contracts are increasing relative to existing contracts, the likelihood of customers exercising fixed-price options increases, and during periods when dayrates on new contracts are decreasing relative to existing contracts, the likelihood of customers exercising fixed-price options decreases. Given current market conditions, we expect that a number of these options will not be exercised by our customers in the remainder of 2010. 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—Our Ultra-Deepwater Floater fleet is fully contracted for 2010, and we are in discussions with customers to contract the one remaining Ultra-Deepwater Floater with availability in 2011. We recently extended a Deepwater Floater available in 2011 for a one-year period and are actively pursuing opportunities for the two remaining available 2010 Deepwater Floaters. Recent subletting of our High-Specification Floater fleet has had minimal impact on our operations in 2010 thus far, but we cannot be certain of the impact on our operations in 2011 and beyond. As of October 14, 2010, we had 43 of our 48 current and future High-Specification Floaters, including all of our newbuilds, contracted through the end of 2010, and 36 of 48 rigs in this fleet, including all of our newbuilds, contracted beyond 2011. We believe the continued exploration successes in the major deepwater offshore provinces will generate additional demand and should support our long-term positive outlook for our High-Specification Floater fleet.

Midwater Floaters—For our Midwater Floater fleet, which includes 26 semisubmersible rigs, near-term customer interest has remained steady and in line with the previous quarter. Although we stacked an additional unit in West Africa due to the lack of opportunities in that region during the second quarter of 2010, we also executed several contracts for our Midwater Floater fleet for short-term work during the third quarter of 2010. Fifty-four percent of our Midwater Floater fleet is committed to contracts that extend beyond 2010. We believe the recent tendering activity, although generally for short-term work, may result in our active rigs working beyond their current contracts on a well-to-well basis. Market utilization for this fleet, however, may face challenges from the moored Deepwater Floaters coming available in the remainder of 2010 and potentially competing in the midwater market due to the lack of current opportunities in the deepwater market and additional capacity resulting from the enhanced regulations in the U.S. Gulf of Mexico.

High-Specification Jackups—The High-Specification Jackup fleet is experiencing rising utilization and dayrates, and we expect this fleet to remain attractive to customers through the remainder of 2010. Tendering activity remained steady during the third quarter of 2010, which resulted in extensions of several existing contracts. As of October 14, 2010, we had three of our 10 High-Specification Jackups stacked. Although we have one High-Specification Jackup completing its current contract in the fourth quarter of 2010, the continued increase in tendering activity could result in the extension of this contract.

Standard Jackups—Considering the number of units currently stacked, the customer preference for the high-specification capable units entering the market, and the absence of a corresponding increase in customer demand, we expect near-term dayrates for our Standard Jackup fleet to remain flat or slightly decrease as contracts are renewed or completed. As of October 14, 2010, we had 26 of our 55 Standard Jackups stacked. We expect a few more of our Standard Jackups to be stacked in the fourth quarter of 2010 and the first quarter of 2011, and we also expect to reactivate a few of our Standard Jackups that require minimal reactivation costs during these periods.

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Index

Key measures—Key measures of our results of operations and financial condition are as follows:

	Three months ended September 30,								Nine months ended September 30,
	2010			2009			Change		2010			2009			Change
Performance indicators
Average daily revenue (a)(b)	$	271,200		$	283,800		$	(12,600)	$	284,600		$	264,500		$	20,100
Utilization (b)(c)		64	%		75	%		n/a		65	%		83	%		n/a

Statement of operations data
Operating revenues	$	2,309		$	2,823		$	(514)	$	7,416		$	8,823		$	(1,407)
Operating and maintenance expense		1,213			1,396			(183)		3,767			3,844			(77)
Operating income		645			957			(312)		2,528			3,397			(869)
Net income attributable to controlling interest		368			710			(342)		1,760			2,458			(698)

	September 30, 2010		December 31, 2009		Change
Balance sheet data
Cash and cash equivalents	$	4,636	$	1,130	$	3,506
Total assets		39,330		36,436		2,894
Total debt		12,840		11,717		1,123

__________________________

“n/a” means not applicable.

(a)

Average daily revenue is defined as contract drilling revenue earned per revenue earning day. A revenue earning day is defined as a day for which a rig earns dayrate after commencement of operations. Stacking rigs, such as Midwater Floaters, High-Specification Jackups and Standard Jackups, has the effect of increasing the average daily revenue since these rig types are typically contracted at lower dayrates compared to the High-Specification Floaters. Average daily revenue includes our rigs that are operating on standby rates located in the U.S. Gulf of Mexico.

(b)	Calculation excludes results for Joides Resolution, a drillship engaged in scientific geological coring activities that is owned by an unconsolidated joint venture in which we have a 50 percent interest and for which we apply the equity method of accounting.

(c)

Utilization is the total actual number of revenue earning days as a percentage of the total number of calendar days in the period. Idle and stacked rigs are included in the calculation and reduce the utilization rate to the extent these rigs are not earning revenues. Newbuilds are included in the calculation upon acceptance by the customer.

As a result of the market pressures experienced in the nine months ended September 30, 2010, our revenues declined relative to those recognized in the nine months ended September 30, 2009. The decline was primarily due to lower utilization, as reflected by 42 stacked and idle rigs as of September 30, 2010, compared to 29 stacked and idle rigs as of September 30, 2009, and coupled with the impact of the U.S. Gulf of Mexico drilling moratorium. This decline was partially offset by revenues from the commencement of operations of our newbuild rigs. The lower utilization also resulted in a decrease in our operating and maintenance expenses compared to the prior year period, which was partially offset by increased operating and maintenance expenses associated with the commencement of operations of our newbuild rigs and increased costs associated with the Macondo well incident, primarily related to insurance deductibles. As of September 30, 2010, we had increased our total debt compared to December 31, 2009, primarily due to the issuance of $2 billion of senior notes in September 2010, partially offset by repurchases of $703 million aggregate principal amount of the Series B Notes and Series C Notes (see “—Liquidity and Capital Resources—Sources and Uses of Liquidity”).

For the year ending December 31, 2010, we expect our total revenues to decline compared to our total revenues for the year ended December 31, 2009. We expect this reduction to result from lower drilling activity associated with stacked and idle rigs, higher out of service time for shipyard, maintenance and repair projects, lost revenues from the Deepwater Horizon contract termination, the impact of the U.S. Gulf of Mexico drilling moratorium and reduced operating activity associated with our integrated services. However, we expect the decrease in revenues to be partially offset by a full year of drilling operations of our five newbuilds delivered in 2009 and the commencement of drilling operations of four additional newbuilds in 2010. We expect our total revenues for the year ending December 31, 2011 to be slightly higher than our total revenues for the year ending December 31, 2010, primarily due to the increased drilling activity associated with our newbuilds delivered in 2010 and 2011 and the lifting of the U.S. Gulf of Mexico drilling moratorium, partially offset by reduced dayrates and the reduced drilling activity associated with our stacked and idle rigs. We are unable to predict, with certainty, the full impact that the continuing effects of the moratorium and the enhanced regulations described under “—Drilling market” will have on our operations in the U.S. Gulf of Mexico in 2010 and beyond. We have negotiated special standby rates with four of our customers under our drilling contracts for rigs in the U.S. Gulf of Mexico. These special standby rates are significantly lower than the regular contract dayrate and apply during periods when the customer is prevented from performing drilling operations. For every day on special standby rate, the contract term of the applicable contract is extended by an equal number of days.

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Index

We expect our total operating and maintenance expenses for the year ending December 31, 2010 to increase slightly compared to operating and maintenance expenses for the year ended December 31, 2009, primarily due to a full year of drilling operations for our five newbuilds delivered in 2009, the commencement of drilling operations of four additional newbuilds in 2010, an increase in maintenance and shipyard expenses and additional costs associated with the Macondo well incident as further discussed below. We expect these increases will be partially offset by reduced costs associated with stacked and idle rigs and reduced integrated services activity. Our projected operating and maintenance expenses for the year ending December 31, 2010 remain uncertain and could be affected by actual activity levels, rig reactivations, the enhanced regulations described under “—Drilling market”, the Macondo well incident and related contingencies, exchange rates and cost inflation as well as other factors. We expect our total operating and maintenance expenses for the year ending December 31, 2011 to be slightly higher than our total operating and maintenance expenses for the year ending December 31, 2010, primarily due to the increased drilling activity associated with our newbuilds delivered in 2010 and 2011, partially offset by the reduced drilling activity associated with our stacked and idle rigs.

Although we are currently unable to estimate the full impact of the Macondo well incident on our business, the incident could ultimately have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. We expect an increase of approximately $170 million in operating and maintenance expenses in 2010 comprised primarily of approximately $70 million of insurance deductibles, approximately $30 million of higher insurance premiums, approximately $29 million of additional legal expenses related to lawsuits and investigations, net of insurance recoveries, and approximately $41 million of additional costs primarily related to our internal investigation of the Macondo well incident, including consultant costs, travel costs and other miscellaneous costs. See “—Contingencies—Insurance matters” and “Part II. Other Information, Item 1A. Risk Factors.”

At September 30, 2010, the carrying amount of our property and equipment was $22.4 billion, representing 57 percent of our total assets, and the carrying amount of our goodwill was $8.1 billion, representing 21 percent of our total assets. In accordance with our critical accounting policies, we review our property and equipment for impairment when events or changes in circumstances indicate that the carrying amounts of our assets held and used may not be recoverable, and we conduct impairment testing for our goodwill when events and circumstances indicate that the fair value of a reporting unit falls below its carrying amount. If we are unable to secure new or extended contracts for our active units or the reactivation of any of our stacked units, or if we experience further declines in actual or anticipated dayrates, especially those in our Standard Jackup fleet, we may be required to recognize losses on impairment of the carrying amount of one or more of our asset groups. Additionally, we may be required to recognize losses on impairment of goodwill if we determine that the fair value of our contract drilling services reporting unit declines below its carrying amount. See “—Critical Accounting Policies and Estimates” and “Part II. Other Information, Item 1A. Risk Factors.”

Performance and Other Key Indicators

Contract backlog—The following table presents our contract backlog, including firm commitments only, for our contract drilling services segment as of October 14, 2010, July 15, 2010 and September 30, 2009. Firm commitments are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution. Our contract backlog is calculated by multiplying the full contractual operating dayrate 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 contractual operating dayrate may be higher than certain other rates included in the contract, such as a waiting-on-weather rate, repair rate, standby rate or force majeure rate. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.

	October 14, 2010		July 15, 2010		September 30, 2009
Contract backlog	(in millions)
High-Specification Floaters	$	22,107	$	22,969	$	26,608
Midwater Floaters		2,320		2,767		3,776
High-Specification Jackups		335		391		443
Standard Jackups		1,251		1,374		1,781
Other Rigs		55		62		86
Total	$	26,068	$	27,563	$	32,694

We have 12 rigs under contract and operating in the U.S. Gulf of Mexico. The backlog associated with the contracts relating to these rigs was approximately $7 billion as of October 14, 2010, of which $2.0 billion could be lost if our customers are legally permitted to and choose to exercise their termination rights under certain contracts.

Although Deepwater Horizon was operating under a contract, which was to extend through September 2013, the total loss of the rig resulted in an automatic termination of the agreement. At the time of the Macondo well incident, the backlog associated with the Deepwater Horizon drilling contract was approximately $590 million.

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Index

Fleet average daily revenue—The following table presents the average daily revenue for our contract drilling services segment for each of the quarters ended September 30, 2010, June 30, 2010 and September 30, 2009. See “—Outlook—Key measures” for a definition of average daily revenue.

	Three months ended
	September 30, 2010		June 30, 2010		September 30, 2009
Average daily revenue
High-Specification Floaters
Ultra-Deepwater Floaters (a)	$	422,800	$	482,100	$	458,500
Deepwater Floaters		365,600		395,800		355,600
Harsh Environment Floaters		414,100		428,500		386,000
Total High-Specification Floaters		403,900		447,800		409,300
Midwater Floaters		328,400		319,000		355,800
High-Specification Jackups		138,100		146,100		161,000
Standard Jackups		113,200		117,100		156,200
Other Rigs		72,900		72,000		73,300
Total fleet average daily revenue		271,200		284,200		283,800

__________________________

(a)	Average daily revenue for the three months ended September 30, 2010 compared to the three months ended June 30, 2010 decreased primarily due to special standby rates in effect for certain rigs during the U.S. Gulf of Mexico drilling moratorium.

Utilization—The following table presents the utilization rates for our contract drilling services segment for each of the quarters ended September 30, 2010, June 30, 2010 and September 30, 2009. See “—Outlook—Key measures” for a definition of utilization.

	Three months ended
	September 30, 2010			June 30, 2010			September 30, 2009
Utilization
High-Specification Floaters
Ultra-Deepwater Floaters		77	%		76	%		90	%
Deepwater Floaters		65	%		66	%		89	%
Harsh Environment Floaters		93	%		85	%		80	%
Total High-Specification Floaters		75	%		74	%		88	%
Midwater Floaters		73	%		69	%		72	%
High-Specification Jackups		61	%		70	%		70	%
Standard Jackups		52	%		53	%		68	%
Other Rigs		50	%		50	%		42	%
Total fleet average utilization		64	%		64	%		75	%

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Index

Operating Results

Three months ended September 30, 2010 compared to three months ended September 30, 2009

Following is an analysis of our operating results. See “—Outlook—Key measures” for a definition of revenue earning days, utilization and average daily revenue.

	Three months ended September 30,
	2010			2009			Change			% Change
	(In millions, except day amounts and percentages)
Revenue earning days		8,126			9,165			(1,039	)	(11)	%
Utilization		64	%		75	%		n/a		n/m
Average daily revenue	$	271,200		$	283,800		$	(12,600	)	(4)	%

Contract drilling revenues	$	2,204		$	2,602		$	(398	)	(15)	%
Contract drilling intangible revenues		23			58			(35	)	(60)	%
Other revenues		82			163			(81	)	(50)	%
		2,309			2,823			(514	)	(18)	%
Operating and maintenance expense		1,213			1,396			(183	)	(13)	%
Depreciation, depletion and amortization		394			367			27		7	%
General and administrative expense		59			54			5		9	%
		1,666			1,817			(151	)	(8)	%
Loss on impairment		—			(46	)		46		n/m
Gain (loss) on disposal of assets, net		2			(3	)		5		n/m
Operating income		645			957			(312	)	(33)	%
Other income (expense), net
Interest income		7			—			7		n/m
Interest expense, net of amounts capitalized		(142	)		(115	)		(27	)	23	%
Loss on retirement of debt		(22	)		(7	)		(15	)	n/m
Other, net		8			9			(1	)	(11)	%
Income before income taxes		496			844			(348	)	(41)	%
Income tax expense		118			138			(20	)	(14)	%
Net income		378			706			(328	)	(46)	%
Net income (loss) attributable to noncontrolling interest		10			(4	)		14		n/m
Net income attributable to controlling interest	$	368		$	710		$	(342	)	(48)	%

__________________________

“n/a” means not applicable

“n/m” means not meaningful

Operating revenues—Contract drilling revenues decreased $398 million for the three months ended September 30, 2010 compared to revenues for the three months ended September 30, 2009, primarily due to lower utilization and lower average daily revenue. The lower utilization and lower average daily revenue for the three months ended September 30, 2010, as compared to the three months ended September 30, 2009, resulted in lower contract drilling revenues as follows: (a) approximately $375 million due to reduced drilling activity as 42 rigs were stacked or idle at September 30, 2010 compared to 29 rigs that were stacked or idle, including one held for sale, at September 30, 2009, (b) approximately $130 million primarily due to special standby rates in effect during the U.S. Gulf of Mexico drilling moratorium, (c) approximately $55 million in higher out-of-service time for shipyard, mobilization, maintenance and repair projects in the three months ended September 30, 2010 compared to the same period in 2009 and (d) approximately $40 million from the lost revenues associated with the Deepwater Horizon contract. These decreases were partially offset by approximately $245 million of revenues associated with our newbuilds, which commenced operations during 2009 and 2010.

Contract drilling intangible revenues declined $35 million for the three months ended September 30, 2010, compared to the three months ended September 30, 2009, due to the completion of the contracts with which they were associated. Contract drilling intangible revenues represent the amortization of the fair value of drilling contracts in effect at the time of our merger with GlobalSantaFe Corporation (“GlobalSantaFe”). We recognize contract drilling intangible revenues over the respective contract period using the straight-line method of amortization.

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Index

Other revenues decreased $81 million for the three months ended September 30, 2010 compared to the three months ended September 30, 2009, primarily due to reduced integrated services activity of $39 million, reduced activity associated with our other operations segment of $32 million and lower reimbursable revenues of $9 million.

Costs and expenses—Operating and maintenance expenses decreased $183 million, or 13 percent, for the three months ended September 30, 2010 compared to the three months ended September 30, 2009. The decrease was due to the following: (a) approximately $110 million of reduced litigation expense, (b) approximately $100 million resulting from lower utilization, (c) approximately $35 million due to reduced activity in our integrated services operations and (d) approximately $30 million due to reduced activity in our other operations segment. These reductions were partially offset by approximately $70 million of increased expenses due to our newbuilds, which commenced operations during 2009 and 2010, approximately $25 million in increased shipyard and maintenance expense and approximately $15 million of expenses related to costs associated with the Macondo well incident, net of insurance recoveries.

Depreciation, depletion and amortization increased for the three months ended September 30, 2010, primarily due to expense related to the commencement of operations of seven newbuilds subsequent to September 30, 2009.

During the three months ended September 30, 2009, we determined that the intangible assets associated with ADTI, our drilling management services reporting unit, were impaired due to diminished demand resulting from the global economic downturn. We recognized losses of $40 million and $6 million related to the impairment of the ADTI customer relationships and trade name intangible assets, respectively, associated with our drilling management services reporting unit during the three months ended September 30, 2009. There were no comparable adjustments during the three months ended September 30, 2010.

The increase in interest expense for the three months ended September 30, 2010 was primarily attributable to a $28 million reduction of capitalized interest, compared to the three months ended September 30, 2009.

During the three months ended September 30, 2010, we recognized a loss on retirement of debt of $22 million related to repurchases of the Series B Notes and Series C Notes. During the three months ended September 30, 2009, we recognized a loss on retirement of debt of $7 million related to repurchases of 1.625% Series A Convertible Senior Notes (“Series A Notes,” and collectively with the Series B Notes and Series C Notes, the “Convertible Senior Notes”) and the early termination of the Term Loan.

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. The estimated annual effective tax rates at September 30, 2010 and 2009 were 17.0 percent and 15.7 percent, respectively, based on projected 2010 and 2009 annual income before income taxes, after excluding certain items, such as losses on impairment, debt retirements and certain asset disposals, and the gain resulting from insurance recoveries on the loss of Deepwater Horizon. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. For the three months ended September 30, 2010 and September 30, 2009, the impact of the various discrete period tax items was a net tax expense of $7 million and a net tax benefit of $29 million, respectively. These discrete tax items, coupled with the excluded income and expense items noted above, resulted in tax rates of 23.8 percent and 16.4 percent on income before income tax expense for the three months ended September 30, 2010 and September 30, 2009, respectively.

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.

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Index

Nine months ended September 30, 2010 compared to nine months ended September 30, 2009

Following is an analysis of our operating results. See “—Outlook—Key measures” for a definition of revenue earning days, utilization and average daily revenue.

	Nine months ended September 30,
	2010			2009			Change			% Change
	(In millions, except day amounts and percentages)
Revenue earning days		24,367			30,476			(6,109	)	(20)	%
Utilization		65	%		83	%		n/a		n/m
Average daily revenue	$	284,600		$	264,500		$	20,100		8	%

Contract drilling revenues	$	6,935		$	8,061		$	(1,126	)	(14)	%
Contract drilling intangible revenues		85			237			(152	)	(64)	%
Other revenues		396			525			(129	)	(25)	%
		7,416			8,823			(1,407	)	(16)	%
Operating and maintenance expense		3,767			3,844			(77	)	(2)	%
Depreciation, depletion and amortization		1,195			1,082			113		10	%
General and administrative expense		180			163			17		10	%
		5,142			5,089			53		1	%
Loss on impairment		(2	)		(334	)		332		n/m
Gain (loss) on disposal of assets, net		256			(3	)		259		n/m
Operating income		2,528			3,397			(869	)	(26)	%
Other income (expense), net
Interest income		17			2			15		n/m
Interest expense, net of amounts capitalized		(415	)		(365	)		(50	)	14	%
Loss on retirement of debt		(20	)		(17	)		(3	)	18	%
Other, net		18			9			9		n/m
Income before income taxes		2,128			3,026			(898	)	(30)	%
Income tax expense		345			573			(228	)	(40)	%
Net income		1,783			2,453			(670	)	27	%
Net income (loss) attributable to noncontrolling interest		23			(5	)		28		n/m
Net income attributable to controlling interest	$	1,760		$	2,458		$	(698	)	(28)	%

__________________________

“n/a” means not applicable

“n/m” means not meaningful

Operating revenues—Contract drilling revenues decreased $1.1 billion for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009 primarily due to lower utilization. The lower utilization during the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009, resulted in reduced contract drilling revenues as follows: (a) approximately $1.2 billion due to reduced drilling activity, as 42 rigs were stacked or idle at September 30, 2010 compared to 29 rigs that were stacked or idle, including one held for sale, at September 30, 2009, (b) approximately $430 million due to higher out-of-service time for shipyard, mobilization, maintenance and repair projects in the nine months ended September 30, 2010 compared to the same period in 2009, (c) approximately $130 million primarily due to special standby rates in effect during the U.S. Gulf of Mexico drilling moratorium and (d) approximately $75 million from the lost revenues associated with the Deepwater Horizon contract. This reduced activity was partially offset by increased revenues of approximately $730 million associated with our newbuilds, which commenced operations during 2009 and 2010.

Contract drilling intangible revenues declined $152 million for the nine months ended September 30, 2010, compared to the nine months ended September 30, 2009, due to completion of the contracts with which they were associated. Contract drilling intangible revenues represent the amortization of the fair value of drilling contracts in effect at the time of our merger with GlobalSantaFe. We recognize contract drilling intangible revenues over the respective contract period using the straight-line method of amortization.

Other revenues decreased $129 million for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009, primarily due to reduced integrated services activity of $96 million and lower reimbursable revenues of $29 million.

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Index

Costs and expenses—Operating and maintenance expenses decreased $77 million, or two percent, for the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009. The decrease was due to the following: (a) approximately $290 million resulting from lower utilization, (b) approximately $110 million of reduced litigation expense, (c) approximately $80 million due to reduced activity in our integrated services operations and (d) $35 million related to the sale of our ownership interests in two rigs. These reductions were partially offset by approximately $210 million of expenses resulting from our newbuilds, which commenced operations during 2009 and 2010, approximately $150 million in increased shipyard and maintenance expense and approximately $100 million of expenses related to costs associated with the Macondo well incident, net of insurance recoveries.

Depreciation, depletion and amortization increased primarily due to $95 million of additional expense related to the commencement of operations of seven newbuilds subsequent to September 30, 2009, $21 million of accelerated depletion of our oil and gas properties during the nine months ended September 30, 2010, partially offset by $3 million of other adjustments, net.

During the nine months ended September 30, 2010, general and administrative expenses increased primarily due to $12 million of additional share-based compensation expense and $3 million of higher personnel expenses.

During the nine months ended September 30, 2009, GSF Arctic II and GSF Arctic IV, both previously classified as assets held for sale, were impaired due to the global economic downturn and pressure on commodity prices, both of which have had an adverse effect on our industry. We recognized a $279 million loss on impairment of these rigs during the nine months ended September 30, 2009. We also recognized losses of $49 million and $6 million related to the impairment of the customer relationships and trade name intangible assets, respectively, associated with our drilling management services reporting unit during the nine months ended September 30, 2009 with no comparable adjustments during the nine months ended September 30, 2010.

During the nine months ended September 30, 2010, we recognized a net gain on disposal of assets of $256 million, including a $267 million gain on the loss of Deepwater Horizon, which resulted from insurance recoveries received during the nine months ended September 30, 2010 that exceeded the carrying amount of the rig. Partially offsetting the gain was a loss of $15 million related to the sale of GSF Arctic II and GSF Arctic IV. There were no comparable transactions during the nine months ended September 30, 2009.

The increase in interest expense for the nine months ended September 30, 2010 was primarily attributable to a $76 million reduction of capitalized interest, compared to the nine months ended September 30, 2009, $33 million of interest expense associated with the Petrobras 10000 capital lease and $15 million of interest expense associated with additional borrowings and debt issued subsequent to September 30, 2009. Partially offsetting the increase was $74 million associated with debt repaid or repurchased subsequent to September 30, 2009.

During the nine months ended September 30, 2010, we recognized losses on retirement of debt of $22 million primarily related to repurchases of the Series B Notes and Series C Notes and recognized a gain on debt retirement of $2 million related to the termination of the GSF Explorer capital lease obligation. During the nine months ended September 30, 2009, we recognized a loss on retirement of debt of $17 million related to repurchases of Series A Notes and the early termination of the Term Loan.

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. The estimated annual effective tax rates at September 30, 2010 and 2009 were 17.0 percent and 15.7 percent, respectively, based on projected 2010 and 2009 annual income before income taxes, after excluding certain items, such as losses on impairment, net gains on disposal of assets, costs for litigation matters, and the gain resulting from insurance recoveries on the loss of Deepwater Horizon. The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits. For the nine months ended September 30, 2010 and September 30, 2009, the impact of the various discrete period tax items was a net tax expense of $14 million and $22 million, respectively. These discrete tax items, coupled with the excluded income and expense items noted above, resulted in tax rates of 16.2 percent and 18.9 percent on income before income tax expense for the nine months ended September 30, 2010 and September 30, 2009, respectively.

There is little to no expected relationship between our provision for income taxes and income before income taxes considering, among other factors, (a) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (b) rig movements between taxing jurisdictions and (c) our rig operating structures. With respect to the estimated annual effective tax rate calculation for the nine months ended September 30, 2010, 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 and Nigeria. Conversely, the most significant countries in which we operated during this period that impose income taxes based on income before income tax include Brazil and the U.S.

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Index

Liquidity and Capital Resources

Sources and uses of cash

Our primary sources of cash during the nine months ended September 30, 2010 were our cash flows from operating activities, proceeds from the issuance in September 2010 of our 4.95% Senior Notes and our 6.50% Senior Notes and the receipt of insurance proceeds of $560 million following the total loss of Deepwater Horizon. Our primary uses of cash were capital expenditures (including for newbuild construction), repurchases of Series B Notes and Series C Notes and repurchases of shares under our share repurchase program. At September 30, 2010, we had $4.6 billion in cash and cash equivalents.

	Nine months ended September 30,
	2010			2009			Change
Cash flows from operating activities	(In millions)
Net income	$	1,783		$	2,453		$	(670	)
Amortization of drilling contract intangibles		(85	)		(237	)		152
Depreciation, depletion and amortization		1,195			1,082			113
Loss on impairment		2			334			(332	)
(Gain) loss on disposal of assets, net		(256	)		3			(259	)
Other non-cash items		323			347			(24	)
Changes in operating assets and liabilities		188			441			(253	)
	$	3,150		$	4,423		$	(1,273	)

Net cash provided by operating activities decreased primarily due to less cash generated from net income, after adjusting for non-cash items largely related to a loss on impairment primarily related to two rigs previously held for sale during the nine months ended September 30, 2009 and a gain on the loss of Deepwater Horizon during the nine months ended September 30, 2010.

	Nine months ended September 30,
	2010			2009			Change
Cash flows from investing activities	(In millions)
Capital expenditures	$	(983	)	$	(2,195	)	$	1,212
Proceeds from disposal of assets, net		51			10			41
Proceeds from insurance recoveries for loss of drilling unit		560			—			560
Proceeds from short-term investments		5			422			(417	)
Purchases of short-term investments		—			(268	)		268
Joint ventures and other investments, net		26			5			21
	$	(341	)	$	(2,026	)	$	1,685

Net cash used in investing activities decreased primarily due to reduced capital expenditures for the construction of five of our Ultra-Deepwater Floaters during the nine months ended September 30, 2010 compared to capital expenditures for the construction of 10 of our Ultra-Deepwater Floaters during the nine months ended September 30, 2009. In addition, net cash used in investing activities declined as a result of the proceeds from insurance recoveries for the loss of Deepwater Horizon in the nine months ended September 30, 2010 and purchases of short-term investments in the nine months ended September 30, 2009, with no comparable activity in the current period. These reductions of cash used in investing activities were partially offset by reduced proceeds from short-term investments resulting from diminished investing activity in marketable securities and reduced recoveries from The Reserve International Liquidity Fund and The Reserve Primary Fund during the nine months ended September 30, 2010 compared to the nine months ended September 30, 2009.

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Index

	Nine months ended September 30,
	2010			2009			Change
Cash flows from financing activities	(In millions)
Change in short-term borrowings, net	$	(131	)	$	(246	)	$	115
Proceeds from debt		2,054			345			1,709
Repayments of debt		(966	)		(2,583	)		1,617
Purchases of shares held in treasury		(240	)		—			(240	)
Financing costs		(15	)		(2	)		(13	)
Proceeds from (taxes paid for) share-based compensation plans, net		(3	)		16			(19	)
Excess tax benefit from share-based compensation plans		1			10			(9	)
Other, net		(3	)		(14	)		(11	)
	$	697		$	(2,474	)	$	3,171

Net cash provided by financing activities increased primarily due to increased proceeds from borrowing and issuing debt and reduced cash used to repay or repurchase debt during the nine months ended September 30, 2010 relative to the nine months ended September 30, 2009, partially offset by cash used to purchase our shares in the nine months ended September 30, 2010 with no comparable activity during the same period of 2009. Proceeds from debt increased primarily due to our issuance of $2.0 billion aggregate principal amount of senior notes in the nine months ended September 30, 2010, compared to borrowings of $345 million under the TPDI Credit Facilities and ADDCL Credit Facilities in the nine months ended September 30, 2009. Repayments of debt declined to $966 million for the nine months ended September 30, 2010 compared to $2.6 billion for the nine months ended September 30, 2009. In the nine months ended September 30, 2010, we paid $669 million for repurchases of our Convertible Senior Notes and repaid borrowings of $271 million under the TPDI Credit Facilities and ADDCL Credit Facilities. In the nine months ended September 30, 2009, we repaid the $2.0 billion term loan and paid $581 million for repurchases of our Convertible Senior Notes.

Drilling fleet expansion and dispositions

Expansion—Capital expenditures, including capitalized interest of $67 million, totaled $983 million during the nine months ended September 30, 2010, substantially all of which related to our contract drilling services segment. Having completed five of our 10 newbuild projects in the year ended December 31, 2009, the following table presents the historical and projected capital expenditures and other capital additions, including capitalized interest, for our remaining major construction projects (in millions):

	Total costs through September 30, 2010		Expected costs for the remainder of 2010		Estimated costs thereafter		Total estimated cost at completion

Discoverer India	$	729	$	9	$	12	$	750
Discoverer Luanda (a)		696		5		4		705
Discoverer Inspiration (b)		678		1		—		679
Dhirubhai Deepwater KG2 (b) (c)		677		3		—		680
Deepwater Champion (d)		601		150		14		765
Capitalized interest		250		40		12		302
Mobilization costs		73		9		28		110
Total	$	3,704	$	217	$	70	$	3,991

__________________________

(a)	The costs for Discoverer Luanda represent 100 percent of expenditures incurred since inception. Angola Deepwater Drilling Company Limited (“ADDCL”) is responsible for all of these costs. We hold a 65 percent interest in ADDCL, and Angco Cayman Limited holds the remaining 35 percent interest.

(b)	The accumulated construction costs of these rigs are no longer included in construction work in progress, as their construction projects had been completed as of September 30, 2010.

(c)

The cost for Dhirubhai Deepwater KG2 represents 100 percent of Transocean Pacific Drilling Inc. (“TPDI”) expenditures, including those incurred prior to our investment in the joint venture. TPDI is responsible for all of these costs. We hold a 50 percent interest in TPDI and Pacific Drilling Limited (“Pacific Drilling”) holds the remaining 50 percent interest.

(d)	These costs include our initial investment in Deepwater Champion of $109 million, representing the estimated fair value of the rig at the time of our merger with GlobalSantaFe in November 2007.

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During 2010, we expect capital expenditures to be approximately $1.3 billion, including approximately $698 million of cash capital costs for our major construction and conversion projects. The level of our capital expenditures is partly dependent upon financial market conditions, the actual level of operational and contracting activity and the level of capital expenditures requested by our customers for which they agree to reimburse us.

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 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 (see “—Sources and Uses of Liquidity”) and may utilize other commercial bank or capital market financings. We intend to fund the cash requirements of our joint ventures for capital expenditures in connection with newbuild construction through their respective credit facilities.

From time to time, we review possible acquisitions of businesses and drilling rigs and may, in the future, make significant capital commitments for such purposes. We may also consider investments related to major rig upgrades or new rig construction. 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. During the nine months ended September 30, 2010, we acquired GSF Explorer, an asset formerly held under capital lease, in exchange for a cash payment of $15 million, thereby terminating the capital lease obligation.

Dispositions—From time to time, we may review possible dispositions of drilling units. During the nine months ended September 30, 2010, we completed the sale of two Midwater Floaters, GSF Arctic II and GSF Arctic IV. In connection with the sale, we received net cash proceeds of $38 million and non-cash proceeds in the form of two notes receivable in the aggregate amount of $165 million. The notes receivable, which are secured by the drilling units, have stated interest rates of 9 percent and are payable in scheduled quarterly installments of principal and interest through maturity in January 2015. We estimated the fair values of the notes receivable based on unobservable inputs that require significant judgment, for which there is little or no market data, including the credit rating of the buyer. We continue to operate GSF Arctic IV under a short-term bareboat charter with the new owner of the vessel ending in November 2010. As a result of the sale, we recognized a loss on disposal of assets in the amount of $15 million for the nine months ended September 30, 2010.

Deepwater Horizon—On April 22, 2010, our Ultra-Deepwater Floater Deepwater Horizon sank after an explosion and fire onboard the rig. The rig’s insured value was $560 million, which was not subject to a deductible, and our insurance underwriters declared the vessel a total loss. During the nine months ended September 30, 2010, we received $560 million in cash proceeds from insurance recoveries related to the loss of the drilling unit and, for the three and nine months ended September 30, 2010, we recognized a gain on the loss of the rig in the amount of $267 million.

Sources and uses of liquidity

Overview—We expect to use existing cash balances, internally generated cash flows, bank credit agreements, proceeds from other debt issuances and proceeds from asset sales to fulfill anticipated obligations such as scheduled debt maturities or other payments, repayment of debt due within one year, including the expected repurchase of the Series A Notes that the noteholders may require us to repurchase in December 2010, capital expenditures, repurchases of the Series B Notes and the Series C Notes, shareholder-approved distributions and working capital needs. 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 to reduce other 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. From time to time, we may also use borrowings under bank lines of credit and under our commercial paper program to maintain liquidity for short-term cash needs.

In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.51, using an exchange rate of USD 1.00 to CHF 0.98 as of the close of trading on September 30, 2010. See “—Distribution.” In May 2009, our shareholders approved, and our board of directors subsequently authorized management to implement, a program 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 business on October 26, 2010 of USD 1.00 to CHF 0.98. See “—Share repurchase program.”

On June 28, 2010, we received a letter from the U.S. Department of Justice ("DOJ") asking us to meet with them to discuss our financial responsibilities in connection with the Macondo well incident and requesting that we provide them certain financial and organizational information. The letter also requested that we provide the DOJ advance notice of certain corporate actions involving the transfer of cash or other assets outside the ordinary course of business. We have engaged in discussions with the DOJ and have responded to their document requests, and we expect these efforts to continue. We can give no assurance that the DOJ investigation and other matters arising out of the Macondo well incident will not adversely affect our liquidity in the future.

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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, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry. The economic downturn and related financial market instability, as well as uncertainty related to our potential liabilities from the Macondo well incident, have had, and could continue to have, an impact 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. The 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 impacted our share price and could impact our ability to access capital markets in the future.

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.

Bank credit agreements—We have a $2.0 billion five-year revolving credit facility under the Five-Year Revolving Credit Facility Agreement dated November 27, 2007 (the “Five-Year Revolving Credit Facility”). 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 September 30, 2010, our debt to tangible capitalization ratio was 0.50 to 1.0. In order to borrow under the Five-Year Revolving Credit Facility, we must, at the time of the borrowing request, not be in default under the bank credit agreement and make certain representations and warranties, including with respect to compliance with laws and solvency, to the lenders. We are not required to make any representation to the lenders as to the absence of a material adverse effect. Borrowings under the Five-Year Revolving Credit Facility are 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. Although credit rating downgrades below investment grade do not constitute an event of default under the Five-Year Revolving Credit Facility, our commitment fee and lending margin are subject to change based on our credit rating. A default under our public debt indentures 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 and the commercial paper program for which it provides liquidity. As of October 26, 2010, we had $81 million in letters of credit issued and outstanding and no borrowings outstanding under the Five-Year Revolving Credit Facility.

Commercial paper program—We maintain a commercial paper program, which is supported by the Five-Year Revolving Credit Facility, under which we may issue privately placed, unsecured commercial paper notes up to a maximum aggregate outstanding amount of $1.5 billion. At October 26, 2010, $157 million in commercial paper was outstanding at a weighted-average interest rate of 0.9 percent, including commissions.

TPDI Credit Facilities—TPDI has a bank credit agreement for a $1.265 billion secured credit facility (the “TPDI Credit Facilities”), comprised of a $1.0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, which was established to finance the construction of and is secured by Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the term loan with an aggregate commitment of $595 million. The senior term loan requires quarterly payments with a final payment in March 2015. The junior term loan and the revolving credit facility are due in full in March 2015. The TPDI Credit Facilities may be prepaid in whole or in part without premium or penalty. The TPDI Credit Facilities have covenants that require TPDI to maintain a minimum cash balance and available liquidity, a minimum debt service ratio and a maximum leverage ratio. At October 26, 2010, $1.1 billion was outstanding under the TPDI Credit Facilities, of which $560 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate on October 26, 2010 was 1.9 percent.

In April 2010, we had a letter of credit issued in the amount of $60 million on behalf of TPDI to satisfy its liquidity requirements under the TPDI Credit Facilities.

TPDI Notes—TPDI has issued promissory notes payable to Pacific Drilling and one of our subsidiaries (the “TPDI Notes”). The TPDI Notes bear interest at London Interbank Offered Rate (“LIBOR”) plus the applicable margin of 2 percent and have maturities through October 2019. As of October 26, 2010, $296 million in promissory notes remained outstanding, $148 million of which was due to one of our subsidiaries and has been eliminated in consolidation. The weighted-average interest rate on October 26, 2010 was 2.6 percent.

ADDCL Credit Facilities—ADDCL has a senior secured bank credit agreement for a credit facility (the “ADDCL Primary Loan Facility”) comprised of Tranche A, Tranche B and Tranche C for $215 million, $270 million and $399 million, respectively, which was established to finance the construction of and is secured by Discoverer Luanda. Unaffiliated financial institutions provide the commitment for and borrowings under Tranche A. Tranche A bears interest at LIBOR plus the applicable margin of 0.725 percent. Tranche A requires semi-annual payments beginning in February 2011 and matures in August 2017. One of our subsidiaries provides the commitment for Tranche C. In March 2010, ADDCL terminated Tranche B, having repaid borrowings of $235 million under Tranche B using borrowings under Tranche C. The ADDCL Primary Loan Facility contains covenants that require ADDCL to maintain certain cash balances to service the debt and also limits ADDCL’s ability to incur additional indebtedness, to acquire assets, or to make distributions or other payments. At October 26, 2010, $215 million was outstanding under Tranche A at a weighted-average interest rate of 0.7 percent. At October 26, 2010, $399 million was outstanding under Tranche C, which was eliminated in consolidation.

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Additionally, ADDCL has a secondary bank credit agreement for a $90 million credit facility (the “ADDCL Secondary Loan Facility”), for which one of our subsidiaries provides 65 percent of the total commitment. The facility bears interest at LIBOR plus the applicable margin, ranging from 3.125 percent to 5.125 percent, depending on certain milestones. The ADDCL Secondary Loan Facility is payable in full on the earlier of (1) 90 days after the fifth anniversary of the first well commencement or (2) December 2015, and it may be prepaid in whole or in part without premium or penalty. Borrowings under the ADDCL Secondary Loan Facility are subject to acceleration by the unaffiliated financial institution upon the occurrence of certain events of default, including the occurrence of a credit rating assignment of less than Baa3 or BBB- by Moody’s Investors Service or Standard & Poor’s Ratings Services, respectively, for Transocean Inc.’s long-term, unsecured, unguaranteed and unsubordinated indebtedness. At October 26, 2010, $77 million was outstanding under the ADDCL Secondary Loan Facility, of which $50 million was provided by one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate on October 26, 2010 was 3.4 percent.

Capital lease contract—Petrobras 10000 is held by one of our subsidiaries under a capital lease contract that requires scheduled monthly payments of $6.0 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. As of October 26, 2010, $698 million was outstanding under the capital lease contract.

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 could, if determined adversely, have a material adverse effect on our subsidiary’s ability to perform its obligations under the capital lease contract. Additionally, another subsidiary of ours has guaranteed the obligations under the capital lease contract, and this guarantor subsidiary 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 the guarantor subsidiary 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.

Convertible Senior Notes—Our Series A Notes, Series B Notes and Series C Notes be converted at a rate of 5.9310 shares per $1,000 note, equivalent to a conversion price of $168.61 per share. Upon conversion, we will deliver, in lieu of shares, cash up to the aggregate principal amount of notes to be converted and shares in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted. The conversion rate is subject to increase upon the occurrence of certain fundamental changes and adjustment upon certain other corporate events, such as the distribution of cash to our shareholders as described below.

Holders of the Series A Notes and Series B Notes have the right to require us to repurchase their notes on December 15, 2010 and December 15, 2011, respectively. In addition, holders of any series of the Convertible Senior Notes will have the right to require us to repurchase their notes on December 14, 2012, December 15, 2017, December 15, 2022, December 15, 2027 and December 15, 2032, and upon the occurrence of a fundamental change, at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. As of October 26, 2010, $4.7 billion of the Convertible Senior Notes remained outstanding compared to $5.7 billion outstanding as of December 31, 2009.

Debt issuance—In September 2010, we issued $1.1 billion aggregate principal amount of 4.95% Senior Notes and $900 million aggregate principal amount of 6.50% Senior Notes. We are required to pay interest on the Senior Notes on May 15 and November 15 of each year, beginning November 15, 2010. We may redeem some or all of the Senior Notes at any time at a redemption price equal to 100 percent of the principal amount plus accrued and unpaid interest, if any, and a make whole premium. The indenture pursuant to which the Senior Notes were issued contains restrictions on creating liens, engaging in sale/leaseback transactions and engaging in merger, consolidation or reorganization transactions. At October 26, 2010, $1.1 billion and $900 million aggregate principal amount of the 4.95% Senior Notes and 6.50% Senior Notes, respectively, were outstanding.

Distribution—In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.51, using an exchange rate of USD 1.00 to CHF 0.98 as of the close of trading on September 30, 2010. According to such shareholders’ approval, the cash distribution would be calculated and paid in four quarterly installments. Under Swiss law, upon satisfaction of all legal requirements, we must submit an application to the Commercial Register in the Canton of Zug to register the applicable par value reduction. On August 13, 2010, the Commercial Register of the Canton of Zug rejected our application to register the first of the four installments. The Commercial Register’s rejection is related to the fact that we have been served in Switzerland with several complaints from lawsuits filed in the U.S. We continue to believe that all prerequisites for the registration of the first partial par value reduction have been satisfied and have appealed the decision of the Commercial Register. Without effective registration of the applicable par value reduction, we will not be able to proceed with the payment of the first or any subsequent installment of our cash distribution to shareholders.

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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 October 26, 2010 of USD 1.00 to CHF 0.98. 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. As of October 26, 2010, we have repurchased 2,863,267 of our shares under our share repurchase program for an aggregate purchase price of CHF 257 million, equivalent to $240 million. See “—Overview.”

We may decide, based upon our ongoing capital requirements, the price of our shares, matters relating to the Macondo well incident, regulatory and tax considerations, cash flow generation, the relationship between our contract backlog and our debt, general market conditions and other factors, that we should retain cash, reduce debt, make capital investments or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no incremental 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.

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 Swiss Exchange. 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 such company’s 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 October 26, 2010, Transocean Inc., our wholly owned subsidiary, held as treasury shares approximately four percent of our issued shares. At the annual general meeting in May 2009, the shareholders approved the release of 3.5 billion Swiss francs 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 3.5 billion Swiss franc share repurchase program for the purpose of the cancellation of shares (the “Currently Approved Program”). 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 six 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.

Redeemable noncontrolling interest—Pacific Drilling, a Liberian company, owns the 50 percent interest in TPDI that is not owned by us, and we present its interest in TPDI as noncontrolling interest on our condensed consolidated balance sheets. Beginning on October 18, 2010, Pacific Drilling had the unilateral right to exchange its interest in TPDI for our shares or cash, at its election, measured at an amount based on an appraisal of the fair value of the drillships, subject to certain adjustments. Accordingly, at the time this option became exercisable, subsequent to September 30, 2010, we reclassified the carrying amount of Pacific Drilling’s interest from permanent equity to temporary equity, located between liabilities and equity on our condensed consolidated balance sheets, since the event that gives rise to a potential redemption of the noncontrolling interest is not within our control.

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Contractual obligations—As of September 30, 2010, there have been no material changes from the contractual obligations as previously disclosed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our annual report on Form 10-K for the year ended December 31, 2009, except as noted below, presented at face value.

	For the twelve months ending September 30,
	Total		2011		2012-2013		2014-2015		Thereafter
	(in millions)
Contractual obligations
Debt (a)	$	11,374	$	1,624	$	4,446	$	—	$	5,304
Debt of consolidated variable interest entities		968		82		194		429		263
Interest on total debt (b)		5,128		478		798		707		3,145

__________________________

(a)

Noteholders may, at their option, require Transocean Inc. to repurchase the Series A Notes and the Series B Notes in December 2010 and 2011, respectively. In addition, holders of any series of the Convertible Senior Notes may, at their option, require Transocean Inc. to repurchase their notes in December 2012, 2017, 2022, 2027 and 2032. In preparing the table above, we have assumed that the holders of our notes exercise the options at the first available date.

(b)	Includes interest on debt and interest on debt of consolidated variable interest entities.

For the year ending December 31, 2010, the minimum funding requirement for our U.S. defined benefit pension plans is approximately $48 million, and in April 2010, we contributed $48 million to satisfy this funding requirement. For the year ending December 31, 2010, the minimum funding requirement for our non-U.S. defined benefit plans is approximately $39 million.

As of September 30, 2010, the total liability for unrecognized tax benefit related to uncertain tax positions was $707 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.51, using an exchange rate of USD 1.00 to CHF 0.98 as of the close of trading on September 30, 2010. According to such shareholders’ approval, the cash distribution would be calculated and paid in four quarterly installments following registration with the Commercial Register of the Canton of Zug. We had expected to pay the four installments within the 12 months following shareholder approval. Due to the uncertainty regarding the outcome of the appeal, however, we are unable to make any estimate as to the timing of the installment, if any. At September 30, 2010, the carrying amount of the unpaid distribution payable was $1.1 billion. See “—Distribution.”

Commercial commitments—As of September 30, 2010, there have been no material changes from the commercial commitments as previously disclosed in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our annual report on Form 10-K for the year ended December 31, 2009.

Derivative instruments

We have established policies and procedures for derivative instruments approved by our board of directors that provide for 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 and foreign 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 10—Derivatives and Hedging.

Contingencies

Macondo well incident

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 BP America Production Co.

The rig has been declared a total loss. Although the rig was operating under a contract, which was to extend through September 2013, the total loss of the rig resulted in an automatic termination of the agreement. The backlog associated with the Deepwater Horizon drilling contract was approximately $590 million. As we continue to investigate the cause or causes of the incident, we are evaluating its consequences, which could ultimately have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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Litigation—As of October 28, 2010, 298 legal actions or claims are currently pending against Transocean entities, along with other unaffiliated defendants, in state and federal courts. Additionally, government agencies have initiated investigations into the Macondo well incident. We have categorized below the nature of the legal actions or claims. We are evaluating all claims and intend to pursue any and all defenses available. In addition, we believe we are entitled to contractual defense and indemnity for all wrongful death and personal injury claims made by non-employees and third-party subcontractors’ employees as well as all liabilities for pollution or contamination, other than for pollution or contamination originating on or above the surface of the water. See “—Contractual indemnity.”

Wrongful death and personal injury—As of October 28, 2010, we and one or more of our subsidiaries have been named, along with other unaffiliated defendants, in 21 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. The complaints generally allege negligence and seek awards of unspecified economic damages and punitive damages. BP plc (together with its affiliates, “BP”), MI-SWACO and Weatherford Ltd. 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.”

Economic loss—As of October 28, 2010, we and one or more of our subsidiaries were named, along with other unaffiliated defendants, in 73 individual complaints as well as 188 putative class-action complaints currently pending in the federal and state courts in Louisiana, Texas, Mississippi, Alabama, Georgia, Kentucky, South Carolina, Tennessee, Florida, Delaware and possibly other courts. The complaints generally allege, among other things, potential economic losses as a result of environmental pollution arising out of the Macondo well incident and are based primarily on the Oil Pollution Act of 1990 (“OPA”) and state OPA analogues (see “—Environmental matters”). One complaint also alleges a violation of the Racketeer Influenced and Corrupt Organizations Act. The plaintiffs are generally seeking awards of unspecified economic, compensatory and punitive damages, as well as injunctive relief (see “—Contractual indemnity”). Per the order of the Multi-District Litigation Panel, the majority of the economic loss claims filed in federal courts have been centralized for discovery purposes in the U.S. District Court, Eastern District of Louisiana. Absent agreement of the parties, however, the cases will be tried in the courts from which they were transferred.

Environmental matters—Environmental claims under two different schemes, statutory and common law, and in two different regimes, federal and state, have been asserted against us. See “—Litigation—Economic loss.” Liability under many statutes is imposed without fault, but such statutes often allow the amount of damages to be limited. In contrast, common law liability requires proof of fault and causation but generally has no readily defined limitation on damages, other than the type of damages that may be redressed. We have described below certain significant applicable environmental statutes and matters relating to the Macondo well incident. As described below, we believe that we have limited statutory environmental liability, and we are entitled to contractual defense and indemnity for all liabilities for pollution or contamination, other than for pollution or contamination originating on or above the surface of the water. See “—Contractual indemnity.”

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Additionally, the National Pollution Funds Center (“NPFC”), a division of the U.S. Coast Guard, is charged with administering the Oil Spill Liability Trust Fund (“OSLTF”). The NPFC collects fines and civil penalties under OPA from responsible parties, as defined in the statute. The payments are directed to the OSLTF. To date, the NPFC has issued seven invoices to BP, Anadarko and Mitsui, as the operator and owners of the well and, thus, the statutorily defined responsible parties for discharges from the well and wellhead. To date, BP has paid six of these invoices. Invoices have also been sent to us, and we have acknowledged responsible party status only with respect to discharges from the vessel on or above the surface of the water, if any.

State environmental laws—As of October 26, 2010, claims had been asserted by private claimants under state environmental statutes in Florida, Louisiana, Mississippi and Texas. As described below, claims asserted by various state and local governments are pending in Alabama, Florida, Louisiana and Texas.

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Contractual indemnity—Under our drilling contract for Deepwater Horizon, the operator has agreed, among other things, to assume full 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 for pollution or contamination originating on or above the surface of the water from fuels, lubricants, motor oils and hydrocarbons or other specified substances within our control and possession, as to which we agreed to assume responsibility and protect, release and indemnify the operator. Although we do not believe it is applicable to the Macondo well incident, we also agreed to indemnify and defend the operator 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. The operator has also agreed, among other things, (1) 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 (2) 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 the operator for personal injury and death of our employees, invitees and the employees of our subcontractors while the operator agreed to defend, release and indemnify us for personal injury and death of its employees, invitees and the employees of its other subcontractors (other than us). We have also agreed to defend, release and indemnify the operator for damages to the rig and equipment (including salvage or removal costs). We understand that indemnification agreements are generally in place between the operator and its other subcontractors for their personnel and property.

Insurance coverage—We expect certain costs resulting from the Macondo well incident to be recoverable under insurance policies as described below.

Hull and machinery coverage—Deepwater Horizon had an insured value of $560 million, and there was no deductible for the total loss of the unit. During the nine months ended September 30, 2010, we received $560 million of cash proceeds from insurance recoveries for the loss of the drilling unit. During nine months ended September 30, 2010, we recognized a gain on the disposal of the rig in the amount of $267 million. We also have coverage for costs incurred in our attempt to mitigate or minimize damage to Deepwater Horizon up to an amount equal to 25 percent of the rig’s insured value, or $140 million. We also have coverage for wreck removal, which includes coverage for removal of diesel, 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 excess liability coverage described below, in the event wreck removal is required. As Deepwater Horizon was a total loss, there was no deductible for any applicable costs incurred to mitigate damages or for wreck removal, provided the costs are within the limits mentioned above.

Excess liability coverage—We carry $950 million of commercial market excess liability coverage, exclusive of 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. This $950 million excess liability limit is an annual aggregate limit covering the entire Transocean worldwide fleet, including Deepwater Horizon. Prior to the April 20, 2010 Macondo well incident, there were no known incidents or occurrences that would have eroded the $950 million aggregate excess liability limit. We generally retain the risk for any liability losses with respect to the Macondo well incident and any other incidents or occurrences in excess of $1.0 billion. In the case of the Macondo well incident, we expect to pay $65 million in deductible costs prior to any insurance reimbursements from the excess liability insurance. We expect liability costs from the Macondo well incident in excess of the $65 million deductible costs to be covered up to the $950 million excess liability limit.

In May 2010, we received notice from the operator under the drilling contract for Deepwater Horizon maintaining that it believes that it is entitled to additional insured status as provided for under the drilling contract. In response, many of our 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 judgment declaring that they have limited additional-insured obligation to the operator. In the actions, our insurers maintain that, although the drilling contract requires additional insured protection for certain entities related to the operator, the protection is limited to the liabilities assumed by us under the terms of the drilling contract, which includes above land or water surface pollution emanating from substances in our possession, such as fuels, lubricants, motor oils, and bilge. Our insurers maintain that, under the drilling contract, the operator accepted full responsibility and indemnified us for any pollution not assumed by us. Further, our insurers contend that the liabilities the operator currently faces arise from pollution originating from the operator’s well, below the surface and not within the scope of the additional insured protection.

Specifically, our insurers seek declarations that: (1) the operator assumed full responsibility in the drilling contract for any and all liabilities arising out of or in any way related to the release of oil originating from its well; (2) the additional insured status in the drilling contract therefore does not extend to the pollution liabilities the operator has incurred and will incur with respect to oil originating from its well; (3) our insurers have no additional obligation to the operator under any of the policies for the pollution liabilities it has incurred and will incur with respect to the oil originating from its well; and (4) the operator is not entitled to coverage under any of the policies for pollution liabilities it has incurred and will incur with respect to the oil originating from its well. The operator has filed a cross-claim, seeking contrary declarations.

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On October 28, 2010, our insurer notified us that they have received letters from representatives of Anadarko and Mitsui, each claiming rights under our insurance policies, as an additional insured as provided for under the drilling contract. Any such claim, if paid to the operators, could limit the amount of coverage otherwise available to us. We can provide no assurances as to the estimated costs, insurance recoveries, or other actions that will result from this incident. See “Part II. Other Information, Item 1A. Risk Factors.”

Other insurance—We also carry $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.

Limitation of liability action—At the instruction of our insurers and to preserve our insurance coverage, pursuant to the federal Limitation of a Shipowner’s Liability Act (the “Limitation Act”), we filed a complaint in the Houston Division of the Southern District of Texas on May 13, 2010 regarding the casualty of the Deepwater Horizon rig. The action has been transferred to the U.S. District Court, Eastern District of Louisiana for further proceedings. Under the Limitation Act, a vessel owner is generally liable only for the post-accident value of the vessel and cargo as long as the vessel owner can show that it had no knowledge of or privity of knowledge with entities that were negligent. Claims limited under the Limitation Act include personal injury, wrongful death, and damage to property contained on the rig. Statutory claims that may be asserted by the U.S. government or individuals under OPA, the Parks Systems Resource Protection Act, the National Marine Sanctuaries Act (the “NMSA”), the Rivers and Harbors Act or CERCLA and claims by the U.S. government for fines and penalties under the Clean Water Act, the NMSA, the Marine Mammal Protection Act, the Endangered Species Act, the Shipping Act, the Ports and Waterways Safety Act, the Act to Prevent Pollution from Ships, the Clean Air Act, the Resource Conservation and Recovery Act and the Outer Continental Shelf and Lands Act are not covered by the limitation proceeding. In addition, a number of similar state statutory environmental claims are not covered by the limitation proceeding.

Pursuant to the Limitation Act, we are seeking an injunction staying certain lawsuits underway in jurisdictions other than the Eastern District of Louisiana. In addition, we are seeking to limit our liability for personal injury, wrongful death and damage to property contained on the rig to $26,764,083, the value of the rig and its freight, including the accounts receivable and accrued accounts receivable, as of April 28, 2010. One objective of the filing is to consolidate lawsuits relating to the Deepwater Horizon casualty and to process these lawsuits and claims in an orderly fashion, before a single federal judge. The filing also seeks to establish a single fund from which legitimate claims may be paid.

After the transfer, the presiding judge in the Eastern District of Louisiana issued an order amending the deadline for filing notices of claims. Pursuant to the amended order, notices of claims must be filed with the court no later than April 20, 2011. A prior order excluded claims filed under OPA or state OPA analogue statutes enacted to impose liability for the discharge of oil or relating to any removal activities in connection with such a discharge are excluded from the limitation proceeding. If a lawsuit is filed under OPA by another party held responsible for the accident, such as the operator, the action could potentially be included in the limitation proceeding.

We expect that the order will be modified in the future, as necessary and appropriate, based on the review and assessment of newly filed claims.

The U.S. House of Representatives has recently passed legislation to repeal retroactively the Limitation Act. We can provide no assurance of the final form of such legislation, if enacted, or its anticipated impact on us.

Investigations—As a result of the Macondo well incident, the Department of Homeland Security and the Department of Interior have announced a joint investigation into the cause or causes of the incident and its effects. The U.S. Coast Guard and the Bureau of Ocean Energy Management, Regulation, and Enforcement (the “BOE”), formerly the Minerals Management Service, share jurisdiction over the investigation into the incident and we have participated in their hearings related to the incident. In connection with the investigation, we have received a subpoena from the Office of Inspector General of the Department of Interior for certain information. In addition, an investigation has been commenced by the Chemical Safety Board, the National Academy of Engineering and the President of the United States has established the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling to, among other things, examine the relevant facts and circumstances concerning the cause or causes of the Macondo well incident and develop options for guarding against future oil spills associated with offshore drilling. Further, we have participated in hearings related to the incident before various committees and subcommittees of the House of Representatives and the Senate of the United States, conferred with state and local government officials, and the DOJ has publicly announced that it has opened criminal and civil investigations of the Macondo well incident. The DOJ announced that it is reviewing, among other traditional criminal statutes, The Clean Water Act, The Oil Pollution Act of 1990, The Migratory Bird Treaty Act of 1918 and Endangered Species Act of 1973. We cannot predict the ultimate outcome of these investigations, the total costs to be incurred in completing the investigations, the potential impact on personnel and the effect of implementing measures that may result from these investigations or to what extent, if any, we could be subject to fines, sanctions or other penalties.

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U.S. Department of Justice—On June 28, 2010, we received a letter from the DOJ asking us to meet with them to discuss our financial responsibilities in connection with the Macondo well incident and requesting that we provide them certain financial and organizational information. The letter also requested that we provide the DOJ advance notice of certain corporate actions involving the transfer of cash or other assets outside the ordinary course of business. We have engaged in discussions with the DOJ and have responded to their document requests, and we expect these efforts to continue.

Drilling moratorium and enhanced regulations—On May 30, 2010, the BOE issued a notice to lessees and operators implementing a six-month moratorium on drilling activities with respect to new wells in water depths greater than 500 feet in the U.S. Gulf of Mexico. The notice also stated that the BOE would not consider for the six-month moratorium period drilling permits for wells and related activities for those water depths. Subsequently, on June 22, 2010, a United States District Court in the Eastern District of Louisiana granted a preliminary injunction that effectively lifted the moratorium. On July 12, 2010, the U.S. Department of the Interior issued a revised moratorium that was scheduled to end on November 30, 2010 and that applied to deepwater drilling configurations and technologies rather than specific water depths. On October 12, 2010, the U.S. government lifted its moratorium. Following the lifting of the moratorium on October 12, 2010, operators are required to submit applications in order to obtain drilling permits and resume drilling activities that demonstrate compliance with enhanced regulations, which now require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. We are working in close consultation with our customers to review the new rules and requirements. See “—Outlook—Drilling market.” Although the moratorium has been lifted, we are unable to predict the impact of the continuing effects of the moratorium and the related enhanced regulations on our operations.

On June 8, 2010, the BOE issued a directive to lessees and operators implementing new governmental safety and environmental requirements applicable to both deepwater and shallow water operations. Among other things, this directive requires each operator to conduct a specific review of its operations and to certify to the BOE that it is in compliance with the new requirements and current regulations. This directive also requires operators to submit independent third-party reports on the design and operation of certain pieces of drilling equipment, including blowout preventers and other well control systems, and instructs operators to conduct tests on the functionality of various rig parts and to submit the results of those tests to the BOE. Certain customers have indicated they will apply certain aspects of the enhanced regulations to their operations outside the U.S. Gulf of Mexico. We are unable to predict the impact of the application of these requirements on our operations.

Insurance matters

Our hull and machinery and excess liability insurance program is comprised of commercial market and captive insurance policies. We periodically evaluate our insurance limits and self-insured retentions. Although our existing insurance policies were scheduled to expire May 1, 2010, we negotiated with our underwriters a one-month extension on some of our insurance policies as we assessed the incident involving the loss of the Ultra-Deepwater Floater Deepwater Horizon. As a result, our current insurance program consists of insurance policies primarily with 12-month and 11-month policy periods beginning on May 1, 2010 and June 1, 2010, respectively.

Hull and machinery—We completed the renewal of our hull and machinery insurance coverage, effective June 1, 2010, with updated rig insured values, primarily based on fair market value appraisals, and with similar terms as previous policies. Under the hull and machinery program, we generally maintain a $125 million per occurrence deductible, limited to a maximum of $250 million per policy period. Subject to the same shared deductible, we also have coverage for costs incurred to mitigate damage to a rig up to an amount equal to 25 percent of a rig’s insured value. Also subject to the same shared deductible, we have additional coverage for wreck removal for up to 25 percent of a rig’s insured value, with any excess generally covered to the extent of our remaining excess liability coverage. The above shared deductible is $0 in the event of a total loss or a constructive total loss of a drilling unit.

Excess liability coverage—We completed the renewal of our excess liability insurance coverage with some policies effective May 1, 2010 and others effective June 1, 2010. These policies were renewed with substantially the same terms and conditions except for additional provisions to address the Macondo well incident. We renewed $950 million of commercial market excess liability coverage, exclusive of 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 has (1) separate $10 million per occurrence deductibles on crew personal injury liability and on collision liability claims and (2) a separate $5 million per occurrence deductible on other third-party non-crew claims. These types of excess liability coverages are subject to an additional aggregate self-insured retention of $50 million that is applied to any occurrence in excess of the per occurrence deductible until the $50 million is exhausted. We generally retain the risk for any liability losses in excess of $1.0 billion.

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See Notes to Condensed Consolidated Financial Statements Note 12—Contingencies—Retained risk and “Part II. Other Information, Item 1A. Risk Factors.”

Tax matters

We are a Swiss corporation and we operate through our various subsidiaries in a number of countries throughout the world. Our tax provision is based upon and subject to changes in the tax laws, regulations and treaties in effect in and between the countries in which our operations are conducted and income is earned. Our effective tax rate for financial reporting purposes fluctuates from year to year considering, among other factors, (a) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (b) rig movements between taxing jurisdictions and (c) our rig operating structures. A change in the tax laws, treaties or regulations in any of the countries in which we operate, or in which we are incorporated or resident, could result in a higher or lower effective tax rate on our worldwide earnings and, as a result, could have a material effect on our financial results.

In June 2010, the Senate Finance Committee and the Senate Permanent Subcommittee on Investigations commenced separate investigations into our tax practices, specifically including but not limited to the U.S. tax implications of our change of jurisdiction of incorporation to the Cayman Islands in 1999 and to Switzerland in 2008. We are cooperating with the committees and responding to their inquiries. We cannot predict the outcome of these investigations.

With respect to our 2004 and 2005 U.S. federal income tax returns, the U.S. tax authorities have withdrawn all of their previously proposed tax adjustments, except a claim regarding transfer pricing for certain charters of drilling rigs between our subsidiaries, reducing the total proposed adjustment to approximately $79 million, exclusive of interest. We believe an unfavorable outcome on this assessment with respect to 2004 and 2005 activities would not result in a material adverse effect on our consolidated financial position, results of operations or cash flows. If the authorities were to continue to pursue this transfer pricing position with respect to subsequent years and were successful in such assertion, our effective tax rate on worldwide earnings with respect to years following 2005 could increase substantially, and our earnings and cash flows from operations could be materially and adversely affected. Although we believe the transfer pricing for these charters is materially correct, we have been unable to reach a resolution with the tax authorities. In August 2010, we filed a petition in the U.S. Tax Court.

The U.S. tax authorities’ original assessment against our 2004 and 2005 activities also asserted that one of our key subsidiaries maintains a permanent establishment in the U.S. and is, therefore, subject to U.S. taxation on certain earnings effectively connected to such U.S. business. In November 2009, we were notified that this position was withdrawn by the U.S. tax authorities. If the authorities were to pursue this permanent establishment position with respect to years following 2005 and were successful in such assertion, our effective tax rate on worldwide earnings with respect to those years could increase substantially, and our earnings and cash flows from operations could be materially and adversely affected. We believe our returns are materially correct as filed, and we intend to continue to vigorously defend against any such claim.

In May 2010, we received an assessment from the U.S. tax authorities related to our 2006 and 2007 U.S. federal income tax returns. We filed a protest letter covering these assessments with the U.S. tax authorities in July 2010. The significant issues raised in the assessment relate to transfer pricing for certain charters of drilling rigs between our subsidiaries and the creation of intangible assets resulting from the performance of engineering services between our subsidiaries. These two items would result in net adjustments of approximately $278 million of additional taxes, exclusive of interest. An unfavorable outcome on these adjustments could result in a material adverse effect on our consolidated 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 2007 could increase substantially, and our earnings and cash flows from operations could be materially and adversely affected. We believe our returns are materially correct as filed, and we intend to continue to vigorously defend against all such claims.

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Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 2001 and 2002 as well as the actions of certain of our former external advisors on these transactions. The authorities issued tax assessments of approximately $266 million, plus interest, related to certain restructuring transactions, approximately $116 million, plus interest, related to the migration of a subsidiary that was previously subject to tax in Norway, approximately $70 million, plus interest, related to a 2001 dividend payment, and approximately $7 million, plus interest, related to certain foreign exchange deductions and dividend withholding tax. We have filed or expect to file appeals to these tax assessments. We may be required to provide some form of financial security, in an amount up to $939 million, including interest and penalties, for these assessed amounts as this dispute is appealed and addressed by the Norwegian courts. The authorities have indicated that they plan to seek penalties of 60 percent on all matters. For these matters, we believe our returns are materially correct as filed, and we have and will continue to respond to all information requests from the Norwegian authorities. We intend to vigorously contest any assertions by the Norwegian authorities in connection with the various transactions being investigated.

During the nine months ended September 30, 2010, our long-term liability for unrecognized tax benefits related to these Norwegian tax issues increased $3 million to $184 million due to the accrual of interest and exchange rate fluctuations. An unfavorable outcome on the Norwegian civil tax matters could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate resolution of these matters to have a material adverse effect on our consolidated financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows.

Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. The Brazil tax authorities have issued tax assessments totaling $115 million, plus a 75 percent penalty of $86 million and interest of $111 million through September 30, 2010. An unfavorable outcome on these assessments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008, and we are currently engaged in the appeals process.

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

Regulatory matters

In June 2007, GlobalSantaFe’s management retained outside counsel to conduct an internal investigation of its Nigerian and West African operations, focusing on brokers who handled customs matters with respect to its affiliates operating in those jurisdictions and whether those brokers have fully complied with the U.S. Foreign Corrupt Practices Act (“FCPA”) and local laws. GlobalSantaFe commenced its investigation following announcements by other oilfield service companies that they were independently investigating the FCPA implications of certain actions taken by third parties in respect of customs matters in connection with their operations in Nigeria, as well as another company’s announced settlement implicating a third party handling customs matters in Nigeria. In each case, the customs broker was reported to be Panalpina Inc., which GlobalSantaFe used to obtain temporary import permits for its rigs operating offshore Nigeria. GlobalSantaFe voluntarily disclosed its internal investigation to the DOJ and the SEC and, at their request, expanded its investigation to include the activities of its customs brokers in certain other African countries. The investigation focused on whether the brokers fully complied with the requirements of their contracts, local laws and the FCPA and GlobalSantaFe’s possible involvement in any inappropriate or illegal conduct in connection with such brokers. In late November 2007, GlobalSantaFe received a subpoena from the SEC for documents related to its investigation. In addition, the SEC advised GlobalSantaFe that it had issued a formal order of investigation. After the completion of the merger with GlobalSantaFe, outside counsel began formally reporting directly to the audit committee of our board of directors. Our legal representatives have kept the DOJ and SEC apprised of the scope and details of their investigation and produced relevant information in response to their requests.

On July 25, 2007, our legal representatives met with the DOJ in response to a notice we received requesting such a meeting regarding our engagement of Panalpina Inc. for freight forwarding and other services in the U.S. and abroad. The DOJ informed us that it was conducting an investigation of alleged FCPA violations by oil service companies who used Panalpina Inc. and other brokers in Nigeria and other parts of the world. We developed an investigative plan that allowed us to review and produce relevant and responsive information requested by the DOJ and SEC. The investigation was expanded to include one of our agents for Nigeria. This investigation and the legacy GlobalSantaFe investigation were conducted by outside counsel who reported directly to the audit committee of our board of directors. The investigation focused on whether the agent and the customs brokers fully complied with the terms of their respective agreements, the FCPA and local laws and the company’s and its employees’ possible involvement in any inappropriate or illegal conduct in connection with such brokers and agent. Our outside counsel coordinated their efforts with the DOJ and the SEC with respect to the implementation of our investigative plan, including keeping the DOJ and SEC apprised of the scope and details of the investigation and producing relevant information in response to their requests. The SEC also issued a formal order of investigation in this case and issued a subpoena for further information.

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We are in discussions with the SEC and DOJ with respect to resolution of these FCPA matters. There can be no assurance that these discussions will lead to a final settlement.

Our internal compliance program has detected a potential violation of U.S. sanctions regulations in connection with the shipment of goods to our operations in Turkmenistan. Goods bound for our rig in Turkmenistan were shipped through Iran by a freight forwarder. Iran is subject to a number of economic regulations, including sanctions administered by the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC”), and comprehensive restrictions on the export and re-export of U.S.-origin items to Iran. Iran has been designated as a state sponsor of terrorism by the U.S. State Department. Failure to comply with applicable laws and regulations relating to sanctions and export restrictions may subject us to criminal sanctions and civil remedies, including fines, denial of export privileges, injunctions or seizures of our assets. We have self-reported the potential violation to OFAC and retained outside counsel who conducted an investigation of the matter and submitted a report to OFAC. We are cooperating with OFAC with respect to resolution of the matter. We may incur significant legal fees and related expenses, and the investigations may involve management time. We cannot predict the ultimate outcome of their investigation, the total costs to be incurred in completing the investigation, the potential impact on personnel, the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws or to what extent, if at all, we could be subject to fines, sanctions or other penalties.

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. We have received and responded to an administrative subpoena from OFAC concerning our operations in Myanmar and a follow-up administrative subpoena from OFAC with questions relating to the previous Myanmar operations subpoena response and the self-reported shipment through Iran matter. We are cooperating with OFAC and believe that all of our operations fully comply with applicable laws. Although we are unable to predict the outcome of any of these matters, we do not expect the liability, if any, resulting from these inquiries to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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 new accounting pronouncements. 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 for the year ended December 31, 2009, included in our current report on Form 8-K, filed on September 16, 2010.

The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure 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, goodwill and other intangible assets, income taxes, share-based compensation, defined benefit pension plans and other postretirement benefits and contingent liabilities. 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, 2009. These estimates require significant judgments, assumptions and estimates. We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. During the nine months ended September 30, 2010, there have been no material changes to the judgments, assumptions and estimates, upon which our critical accounting estimates are based.

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New Accounting Pronouncements

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We are exposed to interest rate risk, primarily associated with our long-term and short-term debt. For our debt obligations, including obligations of our consolidated variable interest entities, as of September 30, 2010, the following table presents our scheduled debt maturities in U.S. dollars and related weighted-average stated interest rates for the twelve months ending September 30 (in millions, except interest rate percentages):

	Scheduled Maturity Date (a)							Fair Value
	2011	2012	2013	2014	2015	Thereafter	Total	9/30/10
Total debt
Fixed rate	$ 1,561	$ 1,924	$ 1,950	$ 91	$ 303	$ 5,904	$11,733	$11,919
Average interest rate	2.2%	1.6%	1.2%	3.6%	2.8%	6.5%	3.9%
Variable rate	$ 162	$ 26	$ 778	$ 30	$ 49	$ 263	$ 1,308	$ 1,303
Average interest rate	1.0%	1.2%	3.2%	1.2%	1.6%	2.0%	2.3%

__________________________

(a)	Expected maturity amounts are based on the face value of debt.

In preparing the scheduled maturities of our debt, we assume the noteholders will exercise their options to require us to repurchase the 1.625% Series A Convertible Senior Notes, 1.50% Series B Convertible Senior Notes and 1.50% Series C Convertible Senior Notes in December 2010, 2011 and 2012, respectively.

We have engaged in certain hedging activities designed to reduce our exposure to interest rate risk, and the effect of our derivative instruments is included in the table above (see Notes to Condensed Consolidated Financial Statements—Note 10—Derivatives and Hedging).

At September 30, 2010, the face value of our variable-rate debt was approximately $1.3 billion, which represented 10 percent of the face value of our total debt, including the effect of our hedging activities. At September 30, 2010, our variable-rate debt, excluding the effect of our hedging activities, primarily consisted of borrowings under the ADDCL Credit Facilities and the TPDI Credit Facilities. At December 31, 2009, the face value of our variable-rate debt was approximately $1.7 billion, which represented 14 percent of the face value of our total debt, including the effect of our hedging activities. At December 31, 2009, our variable-rate debt, excluding the effect of our hedging activities, primarily consisted of notes issued under our commercial paper program and borrowings under the ADDCL Credit Facilities and the TPDI Credit Facilities. Based upon variable-rate debt amounts outstanding as of September 30, 2010 and December 31, 2009, a one percentage point change in annual interest rates would result in a corresponding change in annual interest expense of approximately $13 million and $17 million, respectively.

The fair value of our debt was $13.2 billion and $12.4 billion at September 30, 2010 and December 31, 2009, respectively. The $0.8 billion increase was primarily due to the issuance of $2.0 billion of senior notes during the nine months ended September 30, 2010, partially offset by repurchases of $703 million of the Series B Notes and Series C Notes and changes in market rates for corporate bonds.

A large portion of our cash investments is subject to variable interest rates and would earn commensurately higher rates of return if interest rates increase. Based upon our cash investments as of September 30, 2010 and December 31, 2009, a one percentage point change in interest rates would result in a corresponding change in annual interest income of approximately $46 million and $11 million, respectively.

Foreign Exchange Risk

We are exposed to foreign exchange risk associated with our international operations. For a discussion of our foreign exchange 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, 2009. There have been no material changes to these previously reported matters during the nine months ended September 30, 2010.

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Item 4. Controls and Procedures

Disclosure controls and procedures—In accordance with Exchange Act Rules 13a-15 and 15d-15, 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 were effective as of September 30, 2010 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act was (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 Securities and Exchange Commission’s rules and forms.

Internal controls over financial reporting—There were no changes to our internal controls during the quarter ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Other matters—In April 2010, we implemented a new global Enterprise Resource Planning (“ERP”) system, a fully integrated software environment, designed to optimize and standardize processes in treasury, accounting, supply chain management, asset management and information technology. Although we have updated our internal controls that have been affected by the ERP implementation, we do not believe that the ERP implementation has had an adverse effect on our internal controls 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 Notes to Condensed Consolidated Financial Statements Note 12—Contingencies and “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident.” We are also involved in various tax matters as described in Notes to Condensed Consolidated Financial Statements Note 6—Income Taxes. As of September 30, 2010, 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 cannot predict with certainty the outcome or effect of any of the matters specifically described 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

In addition to the risk factors set forth below and the other information set forth in this quarterly report on Form 10-Q, careful consideration should be given to factors described in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2009 and in our quarterly report on Form 10-Q for the quarter ended June 30, 2010, that could materially affect our business, financial condition or future results.

The Macondo well incident could result in increased expenses and decreased revenues, which could ultimately have a material adverse effect on us.

Numerous lawsuits have been filed against us and unaffiliated defendants related to the Macondo well incident, and we expect additional lawsuits to be filed. We may be subject to claims alleging that we are jointly and severally liable, along with BP plc (together with its affiliates, “BP”) and others, for damages arising from the Macondo well incident. We expect to incur significant legal fees and costs in responding to these matters. We may also be subject to governmental fines or penalties. Although we have excess liability insurance coverage, our personal injury and other third party liability insurance coverage is subject to deductibles and overall aggregate policy limits. In addition, we have also been placed on notice by the Macondo well operator that it intends to make a claim on our excess liability coverage. Such a claim, if paid, could limit the amount of coverage otherwise available to us. There can be no assurance that our insurance will ultimately be adequate to cover all of our potential liabilities in connection with these matters. For a discussion of the potential impact of the failure of the Macondo well operator to honor its indemnification obligations to us, see “We could experience a material adverse effect on our consolidated statement of financial position, results of operations and cash flows to the extent any of the operator’s indemnification obligations to us are not enforceable or the operator does not indemnify us” below. If we ultimately incur substantial liabilities in connection with these matters with respect to which we are neither insured nor indemnified, those liabilities could have a material adverse effect on us.

As a result of the incident, our business will be negatively impacted by the loss of revenue from the Deepwater Horizon. The backlog associated with the Deepwater Horizon drilling contract was approximately $590 million through the end of the contract term in 2013. We do not carry insurance for loss of revenue. In addition, we expect an increase of approximately $170 million in operating and maintenance expenses in 2010 comprised primarily of approximately $70 million of insurance deductibles, approximately $30 million of higher insurance premiums, approximately $29 million of additional legal expenses related to lawsuits and investigations, net of insurance recoveries, and approximately $41 million of additional costs primarily related to our internal investigation of the Macondo well incident, including consultant costs, travel costs and other miscellaneous costs. We may also experience increased operating and maintenance expenses resulting from changing regulations and practices related to the Macondo well incident. The uncertainties and contingencies resulting from the incident, which have resulted in a reduction of our credit rating by two rating agencies, could result in further reductions of our credit ratings by the rating agencies or could have a material adverse effect on our ability to access the debt and equity markets, and of which could ultimately have an adverse impact on our liquidity in the future. Both Moody’s Investors Service and Standard & Poor’s recently downgraded their ratings of our senior unsecured debt with a negative outlook. We cannot be certain that our credit ratings will not be downgraded in the future.

Our relationship with BP, one of which was the operator on the Macondo well, could also be negatively impacted by the Macondo well incident. For 2009, BP was our most significant customer, accounting for 12 percent of our 2009 operating revenues. As of October 14, 2010, the contract backlog associated with our contracts with BP and its affiliates was $3.1 billion.

Our business may also be adversely impacted by any negative publicity relating to the incident and us, any negative perceptions about us by customers, the skilled personnel that we require to support our operations or others, any further increases in premiums for insurance or difficulty in obtaining coverage and the diversion of management’s attention from our other operations to focus on matters relating to the incident. Ultimately, these factors could have a material adverse effect on our statement of financial position, results of operations or cash flows.

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The continuing effects of the moratorium on drilling operations in the U.S Gulf of Mexico and new related enhanced regulations could materially and adversely affect our business.

In May 2010, the U.S. government implemented a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico, which was lifted on October 12, 2010. While the moratorium was in place, some operators claimed that the moratorium was a force majeure event under their drilling contracts that allowed them to terminate these contracts. We do not believe that a force majeure event existed as a result of the moratorium or the enhanced drilling regulations in effect following the moratorium and are in discussions with our customers. In some instances, we have negotiated lower special standby dayrates with our customers for rigs in the U.S. Gulf of Mexico for the period in which the moratorium is in effect but have also agreed to extend the terms of these contracts. In order to obtain drilling permits and resume drilling activities, operators must submit applications that demonstrate compliance with enhanced regulations, which now require independent third-party inspections, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements. We are working in close consultation with our customers to review and implement the new rules and requirements. We cannot predict when, if at all, operators will be able to satisfy these requirements. The continuing effects of the moratorium and enhanced regulations may result in a number of rigs being moved, or becoming available for movement to locations outside of the U.S. Gulf of Mexico, which could potentially reduce dayrates worldwide and negatively affect our ability to contract our rigs that are currently uncontracted or coming off contract. The continuing effects of the moratorium and enhanced regulations may also decrease the demand for drilling services, negatively affect dayrates and increase out-of-service time, which could ultimately have a material adverse affect on our revenue and profitability. We are unable to predict the full impact that the continuing effects of the moratorium and the enhanced regulations will have on our operations.

In connection with the moratorium, new governmental safety and environmental requirements applicable to both deepwater and shallow water operations were adopted. These new safety and environmental guidelines, and any further new guidelines or regulations the U.S. government may issue or any other steps the U.S. government may take, could disrupt or delay operations, increase the cost of operations, increase out-of-service time or reduce the area of operations for drilling rigs in U.S. offshore areas. The U.S. government and other governments could adopt similar moratoria and take similar actions relating to implementing new safety and environmental regulations in the future. Additional governmental regulations and requirements concerning licensing, taxation, equipment specifications and training requirements could increase the costs of our operations, increase certification and permitting requirements, increase review periods and impose increased liability on offshore operations. Legislation pending before the U.S. Congress would impose some of these regulations and requirements. Additionally, increased costs for our customers’ operations in the U.S. Gulf of Mexico, along with permitting delays, could affect the economics of currently planned exploration and development activity in the area and reduce demand for our services, which could ultimately have a material adverse affect on our revenue and profitability.

Our industry is highly competitive and cyclical, with intense price competition.

The offshore contract drilling industry is highly competitive with numerous industry participants, none of which has a dominant market share. Drilling contracts are traditionally awarded on a competitive bid basis. Intense price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and the quality and technical capability of service and equipment may also be considered.

Our industry has historically been cyclical and is impacted by oil and gas price levels and volatility. There have been periods of high demand, short rig supply and high dayrates, followed by periods of low demand, excess rig supply and low dayrates. Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. Since the onset of the worldwide financial and economic downturn, we have experienced weakness in our Midwater Floater, High-Specification Jackups and Standard Jackup markets. We have idled rigs, and may in the future idle additional rigs or enter into lower dayrate contracts in response to market conditions. We cannot predict when any idled or stacked rigs will return to service.

During prior periods of high utilization and dayrates, industry participants have increased the supply of rigs by ordering the construction of new units. This has typically resulted in an oversupply of drilling units and has caused a subsequent decline in utilization and dayrates, sometimes for extended periods of time. There are numerous high-specification rigs and jackups under contract for construction. The entry into service of these new units will increase supply and could curtail a strengthening, or trigger a reduction, in dayrates as rigs are absorbed into the active fleet. Any further increase in construction of new drilling units would likely exacerbate the negative impact on utilization and dayrates. Lower utilization and dayrates could adversely affect our revenues and profitability. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on certain classes of our drilling rigs or our goodwill balance if future cash flow estimates, based upon information available to management at the time, indicate that the carrying values of these rigs, goodwill or other intangible assets may not be recoverable.

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Our non-U.S. operations involve additional risks not generally associated with U.S. operations.

We operate in various regions throughout the world, which may expose us to political and other uncertainties, including risks of:

§	terrorist acts, war, piracy and civil disturbances;

§	seizure, expropriation or nationalization of equipment;

§	imposition of trade barriers;

§	import-export quotas;

§	wage and price controls;

§	unexpected changes in law and regulatory requirements, including changes in interpretation and enforcement of existing laws;

§	damage to our equipment or violence directed at our employees, including kidnappings;

§	complications associated with supplying, repairing and replacing equipment in remote locations; and

§	the inability to repatriate income or capital.

We are protected to some extent against loss of capital assets, but generally not loss of revenue, from most of these risks through indemnity provisions in our drilling contracts. Our assets are generally not insured against risk of loss due to perils such as terrorist acts, civil unrest, expropriation, nationalization and acts of war.

Many governments favor or effectively require the awarding of drilling contracts to local contractors or require foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our ability to compete.

Our non-U.S. contract drilling operations are subject to various laws and regulations in certain countries in which we operate, including laws and regulations relating to the import and export, equipment and operation of drilling units, currency conversions and repatriation, oil and gas exploration and development, and taxation of offshore earnings and earnings of expatriate personnel. We are also subject to the U.S. Treasury Department’s Office of Foreign Assets Control (“OFAC”) and other U.S. laws and regulations governing our international operations. In addition, various state and municipal governments, universities and other investors have proposed or adopted divestment and other initiatives regarding investments (including, with respect to state governments, by state retirement systems) in companies that do business with countries that have been designated as state sponsors of terrorism by the U.S. State Department. We had a noncontrolling interest in a Libyan joint venture that operates to a limited extent in Syria, which has been designated as a state sponsor of terrorism by the U.S. State Department. We sold our noncontrolling interest in this joint venture in November 2009. Our internal compliance program has identified and we have self-reported a potential OFAC compliance issue involving the shipment of goods by a freight forwarder through Iran, a country that has been designated as a state sponsor of terrorism by the U.S. State Department. See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Regulatory matters.” We have also operated rigs in Myanmar, a country that is subject to some U.S. trading sanctions. We have received and responded to an administrative subpoena from OFAC concerning our operations in Myanmar and a follow up administrative subpoena from OFAC with questions relating to the previous Myanmar operations subpoena response and the self-reported shipment through Iran matter. Failure to comply with applicable laws and regulations, including those relating to sanctions and export restrictions, may subject us to criminal sanctions or civil remedies, including fines, denial of export privileges, injunctions or seizures of assets. Investors could view any potential violations of OFAC regulations negatively, which could adversely affect our reputation and the market for our shares.

Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and gas and other aspects of the oil and gas industries in their countries, including local content requirements for participating in tenders for certain drilling contracts. In addition, government action, including initiatives by the Organization of the Petroleum Exporting Countries (“OPEC”), may continue to cause oil or gas price volatility. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies and may continue to do so.

A substantial portion of our drilling contracts are partially payable in local currency. Those amounts may exceed our local currency needs, leading to the accumulation of excess local currency, which, in certain instances, may be subject to either temporary blocking or other difficulties converting to U.S. dollars. Excess amounts of local currency may be exposed to the risk of currency exchange losses.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import and export activities are governed by unique customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the U.S., control the import and export of certain goods, services and technology and impose related import and export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities, and we are also subject to the U.S. anti-boycott law.

The laws and regulations concerning import and export activity, recordkeeping and reporting, import and export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. The adverse impact of the global economic crisis may increase some foreign government’s efforts to enact, enforce, amend or interpret laws and regulations as a method to increase revenue. Shipments can be delayed and denied import or export for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with these applicable legal and regulatory obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.

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Our business involves numerous operating hazards.

Our operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, punch-throughs, craterings, fires and natural disasters such as hurricanes and tropical storms. In particular, the South China Sea, the Northwest Coast of Australia and the Gulf of Mexico area are subject to typhoons, hurricanes or other extreme weather conditions on a relatively frequent basis, and our drilling rigs in these regions may be exposed to damage or total loss by these storms, some of which may not be covered by insurance. The occurrence of these events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury to or death of rig personnel. Some experts believe global climate change could increase the frequency and severity of these extreme weather conditions. We are also subject to personal injury and other claims by rig personnel as a result of our drilling operations. Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services, or personnel shortages. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Damage to the environment could also result from our operations, particularly through oil spillage or extensive uncontrolled fires. We may also be subject to property, environmental and other damage claims by oil and gas companies. Our insurance policies and contractual rights to indemnity may not adequately cover losses, and we do not have insurance coverage or rights to indemnity for all risks. Consistent with standard industry practice, our customers generally assume, and indemnify us against, well control and subsurface risks under dayrate contracts. Under all of our current drilling contracts, the operator indemnifies us for pollution damages in connection with reservoir fluids stemming from operations under the contract; and we indemnify the operator for pollution from substances in our control that originate from the rig (e.g., diesel used onboard the rig or other fluids stored onboard the rig and above the water surface). Also, under all of our current drilling contracts, the operator indemnifies us against damage to the well or reservoir and loss of subsurface oil and gas and the cost of bringing the well under control. However, our drilling contracts are individually negotiated, and the degree of indemnification we receive from the operator against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated. In some instances, we have contractually agreed upon certain limits to our indemnification rights and can be responsible for damages up to a specified maximum dollar amount, which amount is usually $5 million or less, although the amount can be greater depending on the nature of our liability. In most instances in which we are indemnified for damages to the well, we have the responsibility to redrill the well at a reduced dayrate. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations.

The interpretation and enforceability of a contractual indemnity depends upon the specific facts and circumstances involved, as governed by applicable laws. The question may ultimately need to be decided by a court or other proceeding which will need to consider the specific contract language, the facts and applicable laws. The inability of our customers to fulfill their indemnification obligations to us could have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows.

We maintain insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. We generally have no coverage for named storms in the U.S. Gulf of Mexico and war perils worldwide. We also self-insure coverage for expenses to ADTI and CMI related to well control and redrill liability for well blowouts. Also, pollution and environmental risks generally are not totally insurable. We maintain a $125 million per occurrence deductible for damage to our offshore drilling equipment. However, in the event of a total loss of a drilling unit there is no deductible. We also maintain per occurrence deductibles ranging from $1 million to $25 million for various third-party liabilities and an additional annual self-insured retention of $50 million.

If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a customer, it could adversely affect our consolidated statement of financial position, results of operations or cash flows. The amount of our insurance may be less than the related impact on enterprise value after a loss. Our insurance coverage will not in all situations provide sufficient funds to protect us from all liabilities that could result from our drilling operations. Our coverage includes annual aggregate policy limits. As a result, we retain the risk for any losses in excess of these limits. We generally do not carry insurance for loss of revenue unless contractually required, and certain other claims may also not be reimbursed by insurance carriers. Any such lack of reimbursement may cause us to incur substantial costs. In addition, we could decide to retain substantially more risk in the future. Moreover, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider reasonable or be able to obtain insurance against certain risks. As of October 26, 2010, all of the rigs that we owned or operated were covered by existing insurance policies.

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We have a substantial amount of debt, and we may lose the ability to obtain future financing and suffer competitive disadvantages.

Our overall debt level was approximately $13 billion, $12 billion and $14 billion at September 30, 2010, December 31, 2009 and December 31, 2008, respectively. This substantial level of debt and other obligations could have significant adverse consequences on our business and future prospects, including the following:

§	we may not be able to obtain financing in the future for working capital, capital expenditures, acquisitions, debt service requirements or other purposes;

§	we may not be able to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service the debt;

§	we could become more vulnerable to general adverse economic and industry conditions, including increases in interest rates, particularly given our substantial indebtedness, some of which bears interest at variable rates;

we may not be able to meet financial ratios or satisfy certain other conditions included in our bank credit agreements due to market conditions or other events beyond our control, which could result in our inability to meet requirements for borrowings under our bank credit agreements or a default under these agreements and trigger cross default provisions in our other debt instruments;

§	less levered competitors could have a competitive advantage because they have lower debt service requirements; and

§	we may be less able to take advantage of significant business opportunities and to react to changes in market or industry conditions than our competitors.

Our overall debt level and/or market conditions could lead the credit rating agencies to lower our corporate credit ratings below current levels and possibly below investment grade.

Our high leverage level and/or market conditions could lead the credit rating agencies to downgrade our credit ratings below current levels and possibly to non-investment grade levels. Such ratings levels could limit our ability to refinance our existing debt, cause us to issue debt with less favorable terms and conditions and increase certain fees we pay under our credit facilities. In addition, such ratings levels could negatively impact current and prospective customers’ willingness to transact business with us. Suppliers may lower or eliminate the level of credit provided through payment terms 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 Macondo well incident could result in a reduction of our credit ratings by the ratings agencies. Both Moody’s Investors Service and Standard & Poor’s recently downgraded their ratings of our senior unsecured debt with a negative outlook. We cannot provide assurance that our credit ratings will not be downgraded in the future. See “The Macondo well incident could result in increased expenses and decreased revenues, which could ultimately have a material adverse effect on us.”

We are subject to litigation that, if not resolved in our favor and not sufficiently insured against, could have a material adverse effect on us.

We are subject to a variety of litigation and may be sued in additional cases. Numerous lawsuits have been filed against us and unaffiliated defendants related to the Macondo well incident, and we expect additional lawsuits to be filed. See “The Macondo well incident could result in increased expenses and decreased revenues, which could ultimately have a material adverse effect on us.” Certain of our subsidiaries are named as defendants in numerous lawsuits alleging personal injury as a result of exposure to asbestos or toxic fumes or resulting from other occupational diseases, such as silicosis, and various other medical issues that can remain undiscovered for a considerable amount of time. Some of these subsidiaries that have been put on notice of potential liabilities have no assets. Our patent for dual-activity technology has been challenged, and we have been accused of infringing other patents. Other subsidiaries are subject to litigation relating to environmental damage. We cannot predict the outcome of the cases involving those subsidiaries or the potential costs to resolve them. Insurance may not be applicable or sufficient in all cases, insurers may not remain solvent, and policies may not be located. Suits against non-asset-owning subsidiaries have and may in the future give rise to alter ego or successor-in-interest claims against us and our asset-owning subsidiaries to the extent a subsidiary is unable to pay a claim or insurance is not available or sufficient to cover the claims. To the extent that one or more pending or future litigation matters is not resolved in our favor and is not covered by insurance, a material adverse effect on our financial results and condition could result.

Our ability to operate our rigs in the U.S. Gulf of Mexico could be restricted by governmental regulation.

Hurricanes Ivan, Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the U.S. Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. In 2006, the Minerals Management Service of the U.S. Department of the Interior, now the Bureau of Ocean Energy Management, Regulation, and Enforcement (the “BOE”), issued interim guidelines requiring that semisubmersibles operating in the U.S. Gulf of Mexico assess their mooring systems against stricter criteria. In 2007, additional guidelines were issued which impose stricter criteria, requiring rigs to meet 25-year storm conditions. Although all of our semisubmersibles currently operating in the U.S. Gulf of Mexico meet the 2007 requirements, these guidelines may negatively impact our ability to operate other semisubmersibles in the U.S. Gulf of Mexico in the future. In response to the Macondo well incident, in May 2010, the U.S. government implemented a moratorium on certain drilling activities in the U.S. Gulf of Mexico, which has since been lifted. For more information, please read “The continuing effects of the moratorium on drilling operations in the U.S Gulf of Mexico and new related enhanced regulations could materially and adversely affect our business.” Moreover, the BOE may issue additional regulations that could increase the cost of operations or reduce the area of operations for our rigs in the future, thus reducing their marketability. Implementation of additional BOE regulations may subject us to increased costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations in the U.S. Gulf of Mexico.

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U.S. tax authorities could treat us as a “passive foreign investment company,” which could have adverse U.S. federal income tax consequences to U.S. holders.

A foreign corporation will be treated as a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes if either (1) at least 75 percent of its gross income for any taxable year consists of certain types of “passive income” or (2) at least 50 percent of the average value of the corporation’s assets produce or are held for the production of those types of “passive income.” For purposes of these tests, “passive income” includes dividends, interest and gains from the sale or exchange of investment property and certain rents and royalties, but does not include income derived from the performance of services.

We believe that we have not been and will not be a PFIC with respect to any taxable year. Based upon our operations as described herein, our income from offshore contract drilling services should be treated as services income for purposes of determining whether we are a PFIC. Accordingly, we believe that our income from our offshore contract drilling services should not constitute “passive income,” and the assets that we own and operate in connection with the production of that income should not constitute passive assets.

There is significant legal authority supporting this position, including statutory provisions, legislative history, case law and U.S. Internal Revenue Service (“IRS”) pronouncements concerning the characterization, for other tax purposes, of income derived from services where a substantial component of such income is attributable to the value of the property or equipment used in connection with providing such services. It should be noted, however, that a recent case and an IRS pronouncement which relies on the recent case characterize income from time chartering of vessels as rental income rather than services income for other tax purposes. However, the IRS subsequently has formally announced that it does not agree with the decision in that case. Moreover, we believe that the terms of the time charters in the recent case differ in material respects from the terms of our drilling contracts with customers. No assurance can be given that the IRS or a court will accept our position, and there is a risk that the IRS or a court could determine that we are a PFIC.

If we were to be treated as a PFIC for any taxable year, our U.S. shareholders would face adverse U.S. tax consequences. Under the PFIC rules, unless a shareholder makes certain elections available under the Internal Revenue Code of 1986, as amended (which elections could themselves have adverse consequences for such shareholder), such shareholder would be liable to pay U.S. federal income tax at the highest applicable income tax rates on ordinary income upon the receipt of excess distributions (as defined for U.S. tax purposes) and upon any gain from the disposition of our shares, plus interest on such amounts, as if such excess distribution or gain had been recognized ratably over the shareholder’s holding period of our shares. In addition, under applicable statutory provisions, the preferential 15 percent tax rate on “qualified dividend income,” which applies to dividends paid to non-corporate shareholders prior to 2011, does not apply to dividends paid by a foreign corporation if the foreign corporation is a PFIC for the taxable year in which the dividend is paid or the preceding taxable year.

Our status as a Swiss corporation may limit our flexibility with respect to certain aspects of capital management and may cause us to be unable to make distributions or repurchase shares without subjecting our shareholders to Swiss withholding tax.

Swiss law allows our shareholders to authorize share capital that can be issued by the board of directors without additional shareholder approval, but this authorization is limited to 50 percent of the existing registered share capital and must be renewed by the shareholders every two years. Our current authorized share capital expires on December 18, 2010. Additionally, subject to specified 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. In the event we need to raise common equity capital at a time when the trading price of our shares is below the par value of the shares (currently CHF 15, equivalent to $15 based on a foreign exchange rate of USD 1.00 to CHF 0.98 on October 26, 2010), we will need to obtain approval of shareholders to decrease the par value of our shares or issue another class of shares with a lower par value. Any reduction in par value would decrease our par value available for future repayment of share capital not subject to Swiss withholding tax. Swiss law also reserves for approval by shareholders certain corporate actions over which a board of directors would have authority in some other jurisdictions. For example, dividends must be approved by shareholders. These Swiss law requirements relating to our capital management may limit our flexibility, and situations may arise where greater flexibility would have provided substantial benefits to our shareholders.

If we are not successful in our efforts to make distributions, if any, through a reduction of par value or, after January 1, 2011, make distributions, if any, out of qualifying additional paid-in capital as shown on Transocean Ltd.’s standalone Swiss statutory financial statements, then any dividends paid by us will generally be subject to a Swiss federal withholding tax at a rate of 35 percent. Payment of a capital distribution in the form of a par value reduction is not subject to Swiss withholding tax. However, we may not be able to meet the legal requirements for a reduction in par value. On August 13, 2010, the Commercial Register of the Canton of Zug rejected our application to register the first of four planned partial par value reductions previously approved by our shareholders in an amount of CHF 0.86 per issued share, equal to approximately $0.88 (using an exchange rate of USD 1.00 to CHF 0.98 as of the close of trading on October 26, 2010). The Commercial Register’s rejection is related to the fact that Transocean Ltd. has been served in Switzerland with several complaints from lawsuits filed in the U.S. We continue to believe that all prerequisites for the registration of the first par value reduction have been satisfied and have appealed the decision of the Commercial Register. Without effective registration of the applicable par value reduction, we will not be able to proceed with the payment of the first or any subsequent installment of our cash distribution to shareholders. The Swiss withholding tax rules could also be changed in the future. In addition, over the long term, the amount of par value available for us to use for par value reductions or the amount of qualifying additional paid-in capital available for us to pay out as distributions will be limited. If we are unable to make a distribution through a reduction in par value or, after January 1, 2011, make a distribution out of qualifying additional paid-in capital as shown on Transocean Ltd.’s standalone Swiss statutory financial statements, we may not be able to make distributions without subjecting our shareholders to Swiss withholding taxes.

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Under present Swiss tax law, repurchases of shares for the purposes of capital reduction are treated as a partial liquidation subject to a 35 percent Swiss withholding tax on the difference between the repurchase price and the par value. At our 2009 annual general meeting, our shareholders approved the repurchase of up to 3.5 billion Swiss francs of our shares for cancellation (the “Share Repurchase Program”). On February 12, 2010, our board of directors authorized our management to implement the Share Repurchase Program. We may repurchase shares under the Share Repurchase Program via a second trading line on the SIX from institutional investors who are generally able to receive a full refund of the Swiss withholding tax. Alternatively, in relation to the U.S. market, we may repurchase shares under the Share Repurchase Program using an alternative procedure pursuant to which we can repurchase shares under the Share Repurchase Program via a “virtual second trading line” from market players (in particular, banks and institutional investors) who are generally entitled to receive a full refund of the Swiss withholding tax. There may not be sufficient liquidity in our shares on the SIX to repurchase the amount of shares that we would like to repurchase using the second trading line on the SIX. In addition, our ability to use the “virtual second trading line” is limited to the share repurchase program currently approved by our shareholders, and any use of the “virtual second trading line” with respect to future share repurchase programs will require the approval of the competent Swiss tax and other authorities. We may not be able to repurchase as many shares as we would like to repurchase for purposes of capital reduction on either the “virtual second trading line” or, in the future, a SIX second trading line without subjecting the selling shareholders to Swiss withholding taxes.

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

Issuer Purchases of Equity Securities

Period	(a) Total Number of Shares Purchased (1)	(b) Average Price Paid Per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)		(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (2) (in millions)
July 2010	52,789	$	50.40		—	$	3,360
August 2010	803	$	54.19		—	$	3,360
September 2010	153	$	54.90		—	$	3,360
Total	53,745	$	50.47		—	$	3,360

__________________________

(1)	Total number of shares purchased in the third quarter of 2010 includes 53,745 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 the close of trading on September 30, 2010 of USD 1.00 to CHF 0.98). On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We may decide, based upon our ongoing capital requirements, the price of our shares, matters relating to the Macondo well incident, regulatory and tax considerations, cash flow generation, the relationship between our contract backlog and our debt, general market conditions and other factors, that we should retain cash, reduce debt, make capital investments or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no 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 September 30, 2010, we have repurchased a total of 2,863,267 of our shares under this share repurchase program at a total cost of $240 million ($83.74 per share). See “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources and Uses of Liquidity—Overview.”

Item 6. Exhibits

(a) Exhibits

The following exhibits are filed in connection with this Report:

Number

Description

†

4.1

Fourth Supplemental Indenture, dated as of September 21, 2010, among Transocean Ltd., Transocean Inc. and Wells Fargo Bank, National Association, as trustee

†

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.

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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 November 3, 2010.

TRANSOCEAN LTD.

By: /s/ Ricardo H. Rosa

Ricardo H. Rosa

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

By: /s/ John H. Briscoe

John H. Briscoe

Vice President and Controller

(Principal Accounting Officer)