RIG 10-Q Quarterly Report June 30, 2013 | Alphaminr
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RIG 10-Q Quarter ended June 30, 2013

Balance Sheet
Cash Flow
Income Statement
TRANSOCEAN LTD.
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10-Q 1 form10_q2q2013.htm FORM 10-Q 2Q2013 form10_q2q2013.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 June 30, 2013

OR

¨ 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)
Transocean Logo

Zug, Switzerland
98-0599916
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
10 Chemin de Blandonnet
Vernier, Switzerland
1214
(Address of principal executive offices)
(Zip Code)
+41 (22) 930-9000
(Registrant’s telephone number, including area code)

_________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes þ No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer ¨ Non-accelerated filer (do not check if a smaller reporting company) ¨ Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

As of July 30, 2013, 360,410,783 shares were outstanding.



TRANSOCEAN LTD. AND SUBSIDIARIES
INDEX TO FORM 10-Q
QUARTER ENDED JUNE 30, 2013

Page




-1-
PART I. FINANCIAL INFORMATION
Financial Statements

TRANSOCEAN LTD. AND SUBSIDIARIES
(In millions, except per share data)
(Unaudited)

Three months ended
June 30,
Six months ended
June 30,
2013
2012
2013
2012
Operating revenues
Contract drilling revenues
$
2,321
$
2,174
$
4,466
$
4,188
Other revenues
76
155
128
251
2,397
2,329
4,594
4,439
Costs and expenses
Operating and maintenance
1,393
2,105
2,768
3,347
Depreciation
286
280
561
565
General and administrative
77
79
144
148
1,756
2,464
3,473
4,060
Loss on impairment
(37
)
—
(37
)
(140
)
Loss on disposal of assets, net
(2
)
(7
)
(9
)
(10
)
Operating income (loss)
602
(142
)
1,075
229
Other income (expense), net
Interest income
11
13
28
28
Interest expense, net of amounts capitalized
(146
)
(183
)
(303
)
(363
)
Other, net
(16
)
(6
)
(17
)
(24
)
(151
)
(176
)
(292
)
(359
)
Income (loss) from continuing operations before income tax expense
451
(318
)
783
(130
)
Income tax (benefit) expense
130
(15
)
149
19
Income (loss) from continuing operations
321
(303
)
634
(149
)
Loss from discontinued operations, net of tax
(10
)
—
(10
)
(136
)
Net income (loss)
311
(303
)
624
(285
)
Net income (loss) attributable to noncontrolling interest
4
1
(4
)
9
Net income (loss) attributable to controlling interest
$
307
$
(304
)
$
628
$
(294
)
Earnings (loss) per share-basic
Earnings (loss) from continuing operations
$
0. 87
$
(0.86
)
$
1.76
$
(0.45
)
Loss from discontinued operations
(0.03
)
—
(0.03
)
(0.39
)
Earnings (loss) per share
$
0. 84
$
(0.86
)
$
1.73
$
(0.84
)
Earnings (loss) per share-diluted
Earnings (loss) from continuing operations
$
0. 87
$
(0.86
)
$
1.76
$
(0.45
)
Loss from discontinued operations
(0.03
)
—
(0.03
)
(0.39
)
Earnings (loss) per share
$
0. 84
$
(0.86
)
$
1.73
$
(0.84
)
Weighted - average shares outstanding
Basic
360
353
360
352
Diluted
360
353
360
352
See accompanying notes.


-1-

TRANSOCEAN LTD. AND SUBSIDIARIES
(In millions)
(Unaudited)


Three months ended
June 30,
Six months ended
June 30,
2013
2012
2013
2012
Net income (loss)
$
311
$
(303
)
$
624
$
(285
)
Other comprehensive income (loss) before reclassifications
Components of net periodic benefit costs
83
1
48
(27
)
Loss on derivative instruments
—
(3
)
(5
)
—
Reclassifications to net income
Components of net periodic benefit costs
13
10
27
23
Loss on derivative instruments
11
6
18
3
Other comprehensive income (loss) before income taxes
107
14
88
(1
)
Income taxes related to other comprehensive income (loss)
(1
)
1
—
(2
)
Other comprehensive income (loss), net of income taxes
106
15
88
(3
)
Total comprehensive income (loss)
417
(288
)
712
(288
)
Total comprehensive income (loss) attributable to noncontrolling interest
4
1
(3
)
9
Total comprehensive income (loss) attributable to controlling interest
$
413
$
(289
)
$
715
$
(297
)


See accompanying notes.

-2-
TRANSOCEAN LTD. AND SUBSIDIARIES
(In millions, except share data)
(Unaudited)


June 30,
2013
December 31,
2012
Assets
Cash and cash equivalents
$
3,357
$
5,134
Accounts receivable, net of allowance for doubtful accounts
of $20 at June 30, 2013 and December 31, 2012
2,105
2,200
Materials and supplies, net of allowance for obsolescence
of $70 and $66 at June 30, 2013 and December 31, 2012, respectively
680
610
Assets held for sale
143
179
Deferred income taxes, net
167
142
Other current assets
414
382
Total current assets
6,866
8,647
Property and equipment
27,525
26,967
Less accumulated depreciation
(7,461
)
(7,118
)
Property and equipment of consolidated variable interest entities, net of accumulated depreciation
992
1,031
Property and equipment, net
21,056
20,880
Goodwill
2,987
2,987
Other assets
1,306
1,741
Total assets
$
32,215
$
34,255
Liabilities and equity
Accounts payable
$
921
$
1,047
Accrued income taxes
131
116
Debt due within one year
161
1,339
Debt of consolidated variable interest entities due within one year
30
28
Other current liabilities
2,552
2,933
Total current liabilities
3,795
5,463
Long - term debt
10,460
10,929
Long - term debt of consolidated variable interest entities
148
163
Deferred income taxes, net
361
366
Other long - term liabilities
1,787
1,604
Total long - term liabilities
12,756
13,062
Commitments and contingencies
Shares, CHF 15.00 par value, 373,830,649 authorized, 167,617,649 conditionally authorized, 373,830,649 issued and 360,384,335 outstanding at June 30, 2013 and 402,282,355 authorized, 167,617,649 conditionally authorized, 373,830,649 issued and 359,505,251 outstanding at December 31, 2012
5,142
5,130
Additional paid - in capital
6,731
7,521
Treasury shares, at cost, 2,863,267 held at June 30, 2013 and December 31, 2012
(240
)
(240
)
Retained earnings
4,483
3,855
Accumulated other comprehensive loss
(434
)
(521
)
Total controlling interest shareholders’ equity
15,682
15,745
Noncontrolling interest
(18
)
(15
)
Total equity
15,664
15,730
Total liabilities and equity
$
32,215
$
34,255


See accompanying notes.

-3-
TRANSOCEAN LTD. AND SUBSIDIARIES
(In millions)
(Unaudited)


Six months ended
June 30,
Six months ended
June 30,
2013
2012
2013
2012
Shares
Amount
Shares
Balance, beginning of period
360
350
$
5,130
$
4,982
Issuance of shares under share-based compensation plans
—
—
12
11
Issuance of shares in exchange for noncontrolling interest
—
9
—
134
Balance, end of period
360
359
$
5,142
$
5,127
Additional paid-in capital
Balance, beginning of period
$
7,521
$
7,211
Share-based compensation
49
48
Issuance of shares under share-based compensation plans
(25
)
(17
)
Issuance of shares in exchange for noncontrolling interest
—
233
Reclassification of obligation for distribution of qualifying additional paid-in capital
(816
)
—
Other, net
2
(3
)
Balance, end of period
$
6,731
$
7,472
Treasury shares, at cost
Balance, beginning of period
$
(240
)
$
(240
)
Balance, end of period
$
(240
)
$
(240
)
Retained earnings
Balance, beginning of period
$
3,855
$
4,180
Net income (loss) attributable to controlling interest
628
(294
)
Fair value adjustment of redeemable noncontrolling interest
—
(106
)
Balance, end of period
$
4,483
$
3,780
Accumulated other comprehensive loss
Balance, beginning of period
$
(521
)
$
(496
)
Other comprehensive income (loss) attributable to controlling interest
87
(3
)
Reclassification from redeemable noncontrolling interest
—
(17
)
Balance, end of period
$
(434
)
$
(516
)
Total controlling interest shareholders’ equity
Balance, beginning of period
$
15,745
$
15,637
Total comprehensive income (loss) attributable to controlling interest
715
(297
)
Share-based compensation
49
48
Issuance of shares under share-based compensation plans
(13
)
(6
)
Issuance of shares in exchange for noncontrolling interest
—
367
Fair value adjustment of redeemable noncontrolling interest
—
(106
)
Reclassification from redeemable noncontrolling interest
—
(17
)
Reclassification of obligation for distribution of qualifying additional paid-in capital
(816
)
—
Other, net
2
(3
)
Balance, end of period
$
15,682
$
15,623
Noncontrolling interest
Balance, beginning of period
$
(15
)
$
(10
)
Total comprehensive loss attributable to noncontrolling interest
(3
)
(4
)
Balance, end of period
$
(18
)
$
(14
)
Total equity
Balance, beginning of period
$
15,730
$
15,627
Total comprehensive income (loss)
712
(301
)
Share-based compensation
49
48
Issuance of shares under share-based compensation plans
(13
)
(6
)
Issuance of shares in exchange for noncontrolling interest
—
367
Fair value adjustment of redeemable noncontrolling interest
—
(106
)
Reclassification from redeemable noncontrolling interest
—
(17
)
Reclassification of obligation for distribution of qualifying additional paid-in capital
(816
)
—
Other, net
2
(3
)
Balance, end of period
$
15,664
$
15,609

See accompanying notes.

-4-
TRANSOCEAN LTD. AND SUBSIDIARIES
(In millions)
(Unaudited)


Three months ended
June 30,
Six months ended
June 30,
2013
2012
2013
2012
Cash flows from operating activities
Net income (loss)
$
311
$
(303
)
$
624
$
(285
)
Adjustments to reconcile to net cash provided by operating activities
Amortization of drilling contract intangibles
(7
)
(12
)
(16
)
(23
)
Depreciation
286
280
561
565
Depreciation and amortization of assets in discontinued operations
—
65
—
135
Share-based compensation expense
28
25
49
48
Loss on impairment
37
—
37
140
Loss on impairment of assets in discontinued operations
—
12
—
105
Loss on disposal of assets, net
2
7
9
10
Gain on disposal of assets in discontinued operations, net
(3
)
(72
)
(18
)
(71
)
Amortization of debt issue costs, discounts and premiums, net
2
17
2
35
Deferred income taxes
(8
)
(26
)
(36
)
(43
)
Other, net
33
20
48
35
Changes in deferred revenue, net
(29
)
7
(35
)
(5
)
Changes in deferred expenses, net
(9
)
28
8
(21
)
Changes in operating assets and liabilities
(227
)
411
(711
)
374
Net cash provided by operating activities
416
459
522
999
Cash flows from investing activities
Capital expenditures
(352
)
(207
)
(840
)
(445
)
Capital expenditures for discontinued operations
—
(29
)
—
(51
)
Proceeds from disposal of assets, net
3
1
4
8
Proceeds from disposal of assets in discontinued operations, net
—
160
63
194
Proceeds from sale of preference shares
185
—
185
—
Other, net
3
13
12
25
Net cash used in investing activities
(161
)
(62
)
(576
)
(269
)
Cash flows from financing activities
Changes in short-term borrowings, net
—
(260
)
—
(260
)
Repayments of debt
(406
)
(173
)
(1,596
)
(320
)
Proceeds from restricted cash investments
78
84
206
192
Deposits to restricted cash investments
(45
)
(74
)
(104
)
(116
)
Distribution of qualifying additional paid-in capital
(204
)
—
(204
)
(278
)
Other, net
(10
)
8
(25
)
(1
)
Net cash used in financing activities
(587
)
(415
)
(1,723
)
(783
)
Net decrease in cash and cash equivalents
(332
)
(18
)
(1,777
)
(53
)
Cash and cash equivalents at beginning of period
3,689
3,982
5,134
4,017
Cash and cash equivalents at end of period
$
3,357
$
3,964
$
3,357
$
3,964


See accompanying notes.

-5-
TRANSOCEAN LTD. AND SUBSIDIARIES
(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.  We specialize in technically demanding sectors of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services.  Our mobile offshore drilling fleet is considered one of the most versatile fleets in the world.  We contract our drilling rigs, related equipment and work crews predominantly on a dayrate basis to drill oil and gas wells.  At June 30, 2013, we owned or had partial ownership interests in and operated 81 mobile offshore drilling units associated with our continuing operations.  At June 30, 2013, our fleet consisted of 47 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 23 Midwater Floaters, and 11 High-Specification Jackups.  At June 30, 2013, we also had six Ultra-Deepwater drillships and one High-Specification Jackup under construction or under contract to be constructed.  See Note 9—Drilling Fleet.
We also provide oil and gas drilling management services, drilling engineering and drilling project management services outside the United States (“U.S.”) through Applied Drilling Technology Inc., our wholly owned subsidiary, and through ADT International, a division of one of our United Kingdom (“U.K.”) subsidiaries (together, “ADTI”).  ADTI conducts drilling management services primarily either on a dayrate or on a completed-project, fixed-price or turnkey basis.
In November 2012, in connection with our efforts to dispose of non-strategic assets and to reduce our exposure to low-specification drilling units, we completed the sale of 38 drilling units to Shelf Drilling Holdings, Ltd. (together with its affiliates, “Shelf Drilling”).  See Note 7—Discontinued Operations.
Note 2—Significant Accounting Policies
Basis of presentation —We have prepared our accompanying unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the U.S. for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the U.S. Securities and Exchange Commission (“SEC”).  Pursuant to such rules and regulations, these financial statements do not include all disclosures required by accounting principles generally accepted in the U.S. for complete financial statements.  The condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods.  Such adjustments are considered to be of a normal recurring nature unless otherwise noted.  Operating results for the three and six months ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013 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, 2012 and 2011 and for each of the three years in the period ended December 31, 2012 included in our annual report on Form 10-K filed on March 1, 2013 .
Accounting estimates —To prepare financial statements in accordance with accounting principles generally accepted in the U.S., we are required to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities.  On an ongoing basis, we evaluate our estimates and assumptions, including those related to our discontinued operations, allowance for doubtful accounts, materials and supplies obsolescence, property and equipment, investments, notes receivable, goodwill, income taxes, contingencies, share-based compensation, defined benefit pension plans and other postretirement benefits.  We base our estimates and assumptions on historical experience and on various other factors we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources.  Actual results could differ from such estimates.
Fair value measurements —We estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the principal market for the asset or liability.  Our valuation techniques require inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) significant observable inputs, including unadjusted quoted prices for identical assets or liabilities in active markets (“Level 1”), (2) significant other observable inputs, including direct or indirect market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (“Level 2”) and (3) significant unobservable inputs, including those that require considerable judgment for which there is little or no market data (“Level 3”).  When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.
Consolidation —We consolidate entities in which we have a majority voting interest and entities that meet the criteria for variable interest entities for which we are deemed to be the primary beneficiary for accounting purposes.  We eliminate intercompany transactions and accounts in consolidation.  We apply the equity method of accounting for an investment in an entity if we have the ability to exercise significant influence over the entity that (a) does not meet the variable interest entity criteria or (b) meets the variable interest entity criteria, but for which we are not deemed to be the primary beneficiary.  We apply the cost method of accounting for an investment in an entity if we do not have the ability to exercise significant influence over the unconsolidated entity.  See Note 4—Variable Interest Entities.

-6-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Share-based compensation —In the three and six months ended June 30, 2013, we recognized share - based compensation expense of $28 million and $49 million, respectively . In the three and six months ended June 30, 2012, we recognized share - based compensation expense of $25 million and $48 million, respectively .
Capitalized interest —We capitalize interest costs for qualifying construction and upgrade projects.  In the three and six months ended June 30, 2013, we capitalized interest costs on construction work in progress of $16 million and $37 million, respectively.  In the three and six months ended June 30, 2012, we capitalized interest costs on construction work in progress of $12 million and $25 million, respectively.
Reclassifications —We have made certain reclassifications, which did not have an effect on net income, to prior period amounts to conform with the current period’s presentation, including certain reclassifications to our consolidated statements of operations and cash flows to present discontinued operations (see Note 7—Discontinued Operations).  Other 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.
Note 3—New Accounting Pronouncements
Recently adopted accounting standards
Balance sheet —Effective January 1, 2013, we adopted the accounting standards update that expands the disclosure requirements for the offsetting of assets and liabilities related to certain financial instruments and derivative instruments.  The update requires disclosures to present both gross information and net information for financial instruments and derivative instruments that are eligible for net presentation due to a right of offset, an enforceable master netting arrangement or similar agreement.  Our adoption did not have a material effect on our disclosures contained in our notes to condensed consolidated financial statements.
Accumulated other comprehensive income —Effective January 1, 2013, we adopted the accounting standards update that requires disclosure of additional information about reclassifications out of accumulated other comprehensive income and to present reclassifications by component when reporting changes in accumulated other comprehensive income balances.  For significant amounts that are reclassified out of accumulated other comprehensive income to net income in their entirety during the reporting period, the update requires disclosure, either on the face of the statement or in the notes, of the effect on the line items in the statement where net income is presented.  For significant amounts that are not required to be reclassified in their entirety to net income during the reporting period, the update requires cross-references in the notes to other disclosures that provide additional information about those amounts.  Our adoption did not have a material effect on our condensed consolidated statement of other comprehensive income or the disclosures contained in our notes to condensed consolidated financial statements.
Note 4—Variable Interest Entities
Consolidated variable interest entities —The carrying amounts associated with our consolidated variable interest entities, after eliminating the effect of intercompany transactions, were as follows (in millions):
June 30, 2013
December 31, 2012
Assets
$
1,227
$
1,231
Liabilities
290
311
Net carrying amount
$
937
$
920

Angola Deepwater Drilling Company Limited (“ADDCL”), a consolidated Cayman Islands company, and Transocean Drilling Services Offshore Inc. (“TDSOI”), a consolidated British Virgin Islands company, are variable interest entities for which we are the primary beneficiary.  Accordingly, we consolidate the operating results, assets and liabilities of ADDCL and TDSOI.
Unconsolidated variable interest entities —As holder of two notes receivable, we hold a variable interest in Awilco Drilling plc (“Awilco”), a U.K. company listed on the Oslo Stock Exchange . The notes receivable were originally accepted in exchange for, and are secured by, two drilling units.  The notes receivable have stated interest rates of nine percent and are payable in scheduled quarterly installments of principal and interest through maturity in January 2015.  We evaluate the credit quality and financial condition of Awilco quarterly.  At June 30, 2013 and December 31, 2012, the aggregate carrying amount of the notes receivable was $96 million and $105 million, respectively.  At June 30, 2013, our aggregate exposure to loss on the notes receivable was $96 million.

-7-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Note 5—Impairments
Assets held for sale —In the three and six months ended June 30, 2013, we recognized an aggregate loss of $37 million ($0.10 per diluted share from continuing operations), which had no tax effect, associated with the impairment of the Deepwater Floater Sedco 709 and the Midwater Floaters C. Kirk Rhein, Jr. and Sedco 703 , all of which were classified as assets held for sale at the time of impairment.  We measured the impairments of the drilling units and related equipment as the amount by which the carrying amounts exceeded the estimated fair values less costs to sell.  We estimated the fair values of the assets using significant other observable inputs, representative of Level 2 fair value measurements, including nonbinding sale and purchase agreements for the drilling units and related equipment to be sold for scrap value.  See Note 9—Drilling Fleet.
Goodwill —During the six months ended June 30, 2012, we completed the measurement of the impairment that resulted from our annual goodwill impairment test for our contract drilling services reporting unit, performed as of October 1, 2011.  In the six months ended June 30, 2012, we recognized an incremental adjustment to our original estimate in the amount of $118 million ($0.34 per diluted share from continuing operations), which had no tax effect.  We estimated the implied fair value of the goodwill using a variety of valuation methods, including cost, income and market approaches.  Our estimate of fair value required us to use significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of our contract drilling services reporting unit, such as future commodity prices, projected demand for our services, rig availability and dayrates.
Definite - lived intangible assets —During the six months ended June 30, 2012, we determined that the customer relationships intangible asset associated with the U.K. operations of our drilling management services reporting unit was impaired due to the diminishing demand for our drilling management services.  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.  We estimated fair value using significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of the drilling management services reporting unit, such as future commodity prices, projected demand for our services, rig availability and dayrates.  In the six months ended June 30, 2012, as a result of our valuation, we determined that the carrying amount of the customer relationships intangible asset exceeded its fair value, and we recognized a loss on impairment of $22 million ($17 million, or $0.05 per diluted share from continuing operations, net of tax) .
Note 6—Income Taxes
Tax rate —Transocean Ltd., a holding company and Swiss resident, is exempt from cantonal and communal income tax in Switzerland, but is subject to Swiss federal income tax.  At the federal level, qualifying net dividend income and net capital gains on the sale of qualifying investments in subsidiaries are exempt from Swiss federal income tax.  Consequently, Transocean Ltd. expects dividends from its subsidiaries and capital gains from sales of investments in its subsidiaries to be exempt from Swiss federal income tax .
Our provision for income taxes is based on the tax laws and rates applicable in the jurisdictions in which we operate and earn income.  The relationship between our provision for or benefit from income taxes and our income or loss before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues rather than income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures . Generally, our annual marginal tax rate is lower than our annual effective tax rate.
In the six months ended June 30, 2013 and 2012, our estimated annual effective tax rates were 21.6 percent and 24.6 percent, respectively.  These rates were based on estimated annual income before income taxes for each period after adjusting for various discrete items, including certain immaterial adjustments to prior period tax expense.
Unrecognized tax benefits —The liabilities related to our unrecognized tax benefits, including related interest and penalties that we recognize as a component of income tax expense, were as follows (in millions):
June 3 0,
2013
December 31,
2012
Unrecognized tax benefits, excluding interest and penalties
$
370
$
382
Interest and penalties
185
199
Unrecognized tax benefits, including interest and penalties
$
555
$
581

In the year ending December 31, 2013, it is reasonably possible that our existing liabilities for unrecognized tax benefits may increase or decrease , primarily due to the progression of open audits or the expiration of statutes of limitation.  In the six months ended June 30, 2013, we recognized current tax benefit of $49 million, including penalties and interest, associated with the settlement of disputes with tax authorities and the expiration of statutes of limitations.  It is reasonably possible that the total amount of our existing liabilities for unrecognized tax benefit could decrease by up to 13 percent or increase by up to 5 percent in the next 12 months.
Tax returns —We file federal and local tax returns in several jurisdictions throughout the world.  With few exceptions, such as those noted below, we are no longer subject to examinations of our U.S. and non - U.S. tax matters for years prior to 2006 .

-8-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Our tax returns in the major jurisdictions in which we operate, other than the U.S., Norway and Brazil, which are mentioned below, are generally subject to examination for periods ranging from three to six years.  We have agreed to extensions beyond the statute of limitations in two major jurisdictions for up to 18 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 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 .
U.S. tax investigations —In February 2012, we received an assessment from the U.S. tax authorities related to our 2008 and 2009 U.S. federal income tax returns.  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.  With respect to transfer pricing issues related to certain charters of drilling rigs in 2008 and 2009, we reached an agreement with the U.S. tax authorities in December 2012, to settle this issue and other issues raised during the audit for $36 million, excluding interest and penalties.  The only remaining issue outstanding for these years relates to an asserted creation of intangible assets resulting from the performance of engineering services between our subsidiaries for which a royalty is asserted.  The initial assessment issued by the tax authorities on this item, if sustained, would result in net adjustments of approximately $363 million of additional taxes, excluding interest and penalties.  An unfavorable outcome on this adjustment could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.  Furthermore, if the authorities were to continue to pursue this position with respect to subsequent years and were successful in such assertion , our effective tax rate on worldwide earnings with respect to years following 2009 could increase substantially, and could have a material adverse effect on our consolidated results of operations and cash flows.  We believe our U.S. federal income tax returns are materially correct as filed, and we intend to continue to vigorously defend against all claims to the contrary .
Norway tax investigations and trial —Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 1999, 2001 and 2002 as well as the actions of certain employees of our former external tax advisors on these transactions.  The authorities issued tax assessments of approximately $117 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 provided a parent company guarantee in the amount of approximately $119 million with respect to one of these tax disputes.  Furthermore, we may be required to provide some form of additional financial security, in an amount up to $220 million, including interest and penalties, for other assessed amounts as these disputes are appealed and addressed by the Norwegian courts.  The authorities are seeking penalties of 60 percent on most but not all matters.  In November 2012, the Norwegian district court in Oslo heard the case regarding the disputed tax assessment of approximately $117 million related to the migration of our subsidiary.  On March 1, 2013, the Norwegian district court in Oslo overturned the tax assessment and ruled in our favor.  The tax authorities have filed an appeal.  We believe that our Norwegian tax returns are materially correct as filed, and we intend to continue to vigorously defend ourselves against all claims to the contrary.  In addition, we expect to file or have filed appeals to the two other tax assessments.
In June 2011, the Norwegian authorities issued criminal indictments against two of our subsidiaries alleging misleading or incomplete disclosures in Norwegian tax returns for the years 1999 through 2002, as well as inaccuracies in Norwegian statutory financial statements for the years ended December 31, 1996 through 2001.  The criminal trial commenced in December 2012.  Two employees of our former external tax advisors were also issued criminal indictments with respect to the disclosures in our tax returns, and our former external Norwegian tax attorney was issued criminal indictments related to certain of our restructuring transactions and the 2001 dividend payment.  We believe the charges brought against us are without merit and do not alter our technical assessment of the underlying claims.  In January 2012, the Norwegian authorities supplemented the previously issued criminal indictments by issuing a financial claim of approximately $313 million, jointly and severally, against our two subsidiaries, the two external tax advisors and the external tax attorney.  In February 2012, the authorities dropped the previously existing civil tax claim related to a certain restructuring transaction.  In April 2012, the Norwegian tax authorities supplemented the previously issued criminal indictments against our two subsidiaries by extending a criminal indictment against a third subsidiary, alleging misleading or incomplete disclosures in Norwegian tax returns for the years 2001 and 2002.  In May 2013, the Norwegian authorities dropped the financial claim of approximately $313 million against one of our subsidiaries and the criminal case related to the migration case of another subsidiary.  We believe our Norwegian tax returns are materially correct as filed, and we intend to continue to vigorously contest any assertions to the contrary by the Norwegian civil and criminal authorities in connection with the various transactions being investigated.  An unfavorable outcome on the Norwegian civil or criminal tax matters could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
Brazil tax investigations —Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination.  The Brazilian tax authorities have issued tax assessments totaling $97 million, plus a 75 percent penalty in the amount of $73 million and interest through December 31, 2011 in the amount of $155 million.  We believe our returns are materially correct as filed, and we are vigorously contesting these assessments.  On January 25, 2008, we filed a protest letter with the Brazilian tax authorities, and we are currently engaged in the appeals process.  An unfavorable outcome on these proposed assessments could result in a material adverse effect on our consolidated statement of financial position, results of operations or cash flows .

-9-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Other tax matters —We conduct operations through our various subsidiaries in a number of countries throughout the world.  Each country has its own tax regimes with varying nominal rates, deductions and tax attributes.  From time to time, we may identify changes to previously evaluated tax positions that could result in adjustments to our recorded assets and liabilities.  Although we are unable to predict the outcome of these changes, we do not expect the effect, if any, resulting from these adjustments to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
Note 7—Discontinued Operations
Summarized results of discontinued operations
The summarized results of operations included in income from discontinued operations were as follows (in millions):
Three months ended
June 30,
Six months ended
June 30,
2013
2012
2013
2012
Operating revenues
$
229
$
248
$
469
$
478
Operating and maintenance expense
(233
)
(255
)
(482
)
(478
)
Depreciation and amortization expense
—
(65
)
—
(135
)
Loss on impairment of assets in discontinued operations, net
—
(12
)
—
(105
)
Gain on disposal of assets in discontinued operations, net
3
72
18
71
Income (loss) from discontinued operations before income tax expense
(1
)
(12
)
5
(169
)
Income tax benefit (expense)
(9
)
12
(15
)
33
Income (loss) from discontinued operations, net of tax
$
(10
)
$
—
$
(10
)
$
(136
)

Assets and liabilities of discontinued operations
The carrying amounts of the major classes of assets and liabilities associated with our discontinued operations were classified as follows (in millions):
June 30,
2013
December 31,
2012
Assets
Rigs and related equipment, net
$
59
$
104
Materials and supplies, net
68
71
Other related assets
7
4
Assets held for sale
$
134
$
179
Liabilities
Deferred revenues
$
57
$
32
Other liabilities
—
3
Other current liabilities
$
57
$
35

-10-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)


Standard Jackup and swamp barge contract drilling operations
Overview —In September 2012, in connection with our efforts to dispose of non-strategic assets and to reduce our exposure to low-specification drilling units, we committed to a plan to discontinue operations associated with the Standard Jackup and swamp barge asset groups, components of our contract drilling services operating segment.  At June 30, 2013, the remaining Standard Jackups, which were not sold in the sale transactions with Shelf Drilling, including GSF Rig 127 , GSF Rig 134 , Trident IV - A and Trident VI , and related equipment, were classified as held for sale with an aggregate carrying amount of $63 million, including $4 million in materials and supplies.  At December 31, 2012, the remaining Standard Jackups, which were not sold in the sale transactions with Shelf Drilling, including D.R. Stewart , GSF Adriatic VIII , GSF Rig 127 , GSF Rig 134 , Interocean III , Trident IV - A and Trident VI , and related equipment, were classified as held for sale with an aggregate carrying amount of $112 million, including $8 million in materials and supplies.
Impairments —In the three and six months ended June 30, 2012, we recognized aggregate losses of $12 million ($0.03 per diluted share) and $29 million ($0.08 per diluted share), respectively, which had no tax effect in either period, associated with the impairment of GSF Adriatic II and GSF Rig 136 , which were classified as assets held for sale at the time of impairment.  We measured the impairment of the drilling unit and related equipment as the amount by which the carrying amount exceeded the estimated fair value less costs to sell.  We estimated the fair value of the assets using significant other observable inputs, representative of Level 2 fair value measurements, including a binding sale and purchase agreement for the drilling unit and related equipment.
Sale transactions with Shelf Drilling —In November 2012, we completed the sale of 38 drilling units to Shelf Drilling in exchange for cash proceeds of $568 million, subject to post-closing adjustments, and non-cash proceeds in the form of preference shares that had a stated value of $196 million and an estimated fair value of $194 million, including the fair value associated with embedded derivatives.  In June 2013, we sold the preference shares to an unaffiliated party for cash proceeds of $185 million and, in the three and six months ended June 30, 2013, we recognized a loss of $10 million ($0.03 per diluted share), recorded in other expense, net, which had no tax effect, associated with the sale.
For a transition period following the completion of the sale transactions with Shelf Drilling, we agreed to continue to operate a substantial portion of the Standard Jackups under operating agreements with Shelf Drilling and to provide certain other transition services to Shelf Drilling.  Under the operating agreements, we have agreed to remit the collections from our customers under the associated drilling contracts to Shelf Drilling, and Shelf Drilling has agreed to reimburse us for our direct costs and expenses incurred while operating the Standard Jackups on behalf of Shelf Drilling with certain exceptions.  Amounts due to Shelf Drilling under the operating agreements and transition services agreement may be contractually offset against amounts due from Shelf Drilling.  The costs to us for providing such operating and transition services, including allocated indirect costs, may exceed the amounts we receive from Shelf Drilling for providing such services.
Under the operating agreements, we agreed to continue to operate these Standard Jackups on behalf of Shelf Drilling for periods ranging from nine months to 27 months or until expiration or novation of the underlying drilling contracts by Shelf Drilling.  As of June 30, 2013, we operated 24 Standard Jackups under operating agreements with Shelf Drilling.  Until the expiration or novation of such drilling contracts, we retain possession of the materials and supplies associated with the Standard Jackups that we operate under the operating agreement.  At June 30, 2013 and December 31, 2012, the materials and supplies associated with the drilling units that we operated under operating agreements with Shelf Drilling had an aggregate carrying amount of $64 million and $63 million, respectively.  Under a transition services agreement, we agreed to provide certain transition services for a period of up to 18 months following the completion of the sale transactions.
For a period of up to three years following the closing of the sale transactions, we have agreed to provide to Shelf Drilling up to $125 million of financial support by maintaining letters of credit, surety bonds and guarantees for various contract bidding and performance activities associated with the drilling units sold to Shelf Drilling and in effect at the closing of the sale transactions.  At the time of the sale transactions, we had $113 million of outstanding letters of credit, issued under our committed and uncommitted credit lines, in support of rigs sold to Shelf Drilling.  Included within the $125 million maximum amount, we agreed to provide up to $65 million of additional financial support in connection with any new drilling contracts related to such drilling units.  Shelf Drilling is required to reimburse us in the event that any of these instruments are called.  At June 30, 2013 and December 31, 2012, we had $102 million and $113 million, respectively, of outstanding letters of credit, issued under our committed and uncommitted credit lines, in support of drilling units sold to Shelf Drilling.  See Note 13—Commitments and Contingencies.
Other dispositions —During the six months ended June 30, 2013, we completed the sale of the Standard Jackups D.R. Stewart , Interocean III and GSF Adriatic VIII along with related equipment.  In the six months ended June 30, 2013, in connection with the disposal of these assets, we received aggregate net cash proceeds of $63 million, and we recognized an aggregate net gain of $15 million ($0.04 per diluted share), which had no tax effect.  In the three and six months ended June 30, 2013, we recognized an aggregate net gain of $3 million associated with the disposal of unrelated assets.  In June 2013, we entered into an agreement to sell the Standard Jackup Trident IV-A and related equipment.

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TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



During the six months ended June 30, 2012, we completed the sales of the Standard Jackups GSF Adriatic II , GSF Rig 136 , Roger W. Mowell , Transocean Nordic and Transocean Shelf Explorer and related equipment.  In the three and six months ended June 30, 2012, in connection with the disposal of these assets, we received aggregate net cash proceeds of $145 million and $179 million, respectively, and we recognized an aggregate net gain of $64 million ($0.18 per diluted share from continuing operations), which had no tax effect.  In the three and six months ended June 30, 2012, we recognized aggregate net losses of $2 million and $3 million, respectively, associated with the disposal of unrelated assets.
U.S. Gulf of Mexico drilling management services
Overview —In March 2012, we announced our intent to discontinue drilling management operations in the shallow waters of the U.S. Gulf of Mexico, a component of our drilling management services operating segment, upon completion of our then existing contracts.  We elected to exit this market based on the declining market outlook for these services in the shallow waters of the U.S. Gulf of Mexico as well as the more difficult regulatory environment for obtaining drilling permits.  In December 2012, we completed the final drilling management project and discontinued offering our drilling management services in this region.
Impairments —During the six months ended June 30, 2012, we determined that the customer relationships intangible asset associated with the U.S. operations of our drilling management services reporting unit was impaired due to the declining market outlook for these services in the shallow waters of the U.S. Gulf of Mexico as well as the increased regulatory environment for obtaining drilling permits and the diminishing demand for our drilling management services.  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.  We estimated fair value using significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of the drilling management services reporting unit, such as future commodity prices, projected demand for our services, rig availability and dayrates.  As a result of our valuation, we determined that the carrying amount of the customer relationships intangible asset exceeded its fair value, and in the six months ended June 30, 2012, we recognized a loss on impairment of $31 million ($20 million or $0.06 per diluted share, net of tax).
During the six months ended June 30, 2012, we determined that the trade name intangible asset associated with our drilling management services reporting unit was impaired due to the declining market outlook for these services in the shallow waters of the U.S. Gulf of Mexico as well as the increased regulatory environment for obtaining drilling permits and the diminishing demand for drilling management services.  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.  We estimated fair value using significant unobservable inputs, representative of a Level 3 fair value measurement, including assumptions related to the future performance of the drilling management services reporting unit, such as future commodity prices, projected demand for drilling management services, rig availability and dayrates.  As a result of our valuation, we determined that the carrying amount of the trade name intangible asset exceeded its fair value, and in the six months ended June 30, 2012, we recognized a loss on impairment of $39 million ($25 million or $0.07 per diluted share, net of tax).
Oil and gas properties
Overview —In March 2011, in connection with our efforts to dispose of non-strategic assets, we engaged an unaffiliated advisor to coordinate the sale of the assets of our oil and gas properties reporting unit, formerly a component of our other operations segment, which comprised the exploration, development and production activities performed by Challenger Minerals Inc., Challenger Minerals (North Sea) Limited and Challenger Minerals (Ghana) Limited, our wholly owned oil and gas subsidiaries.  During the year ended December 31, 2012, we completed the sale of these assets.
Impairment —In the six months ended June 30, 2012, we recognized a loss of $6 million ($4 million or $0.01 per diluted share, net of tax) associated with the impairment of our oil and gas properties, which were classified as assets held for sale at the time of impairment, since the carrying amount of the properties exceeded the estimated fair value less costs to sell the properties.  We estimated fair value based on significant other observable inputs, representative of a Level 2 fair value measurement, including a binding sale and purchase agreement for the properties.
Dispositions —In April 2012, we completed the sale of the assets of Challenger Minerals Inc. for net cash proceeds of $7 million.  In May 2012, we received additional cash proceeds of $10 million from the buyer of Challenger Minerals (North Sea) Limited, and in the three and six months ended June 30, 2012, we recognized a gain of $10 million associated with the disposal of assets in discontinued operations.

-12-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Note 8—Earnings Per Share
The numerator and denominator used for the computation of basic and diluted per share earnings from continuing operations were as follows (in millions, except per share data):
Three months ended June 30,
Six months ended June 30,
2013
2012
2013
2012
Basic
Diluted
Basic
Diluted
Basic
Diluted
Basic
Diluted
Numerator for earnings (loss) per share
Income (loss) from continuing operations attributable to controlling interest
$
317
$
317
$
(304
)
$
(304
)
$
638
$
638
$
(158
)
$
(158
)
Undistributed earnings allocable to participating securities
(3
)
(3
)
—
—
(6
)
(6
)
—
—
Income (loss) from continuing operations available to  shareholders
$
314
$
314
$
(304
)
$
(304
)
$
632
$
632
$
(158
)
$
(158
)
Denominator for earnings (loss) per share
Weighted-average shares outstanding
360
360
353
353
360
360
352
352
Effect of stock options and other share-based awards
—
—
—
—
—
—
—
—
Weighted-average shares for per share calculation
360
360
353
353
360
360
352
352
Per share earnings (loss) from continuing operations
$
0. 87
$
0. 87
$
(0.86
)
$
(0.86
)
$
1.76
$
1.76
$
(0.45
)
$
(0.45
)
In the three and six months ended June 30, 2013 , we excluded 2.4 million and 2.3 million share-based awards, respectively, from the calculation since the effect would have been anti-dilutive.  In the three and six months ended June 30, 2012, we excluded 2.2 million and 2.0 million share-based awards, respectively, from the calculation since the effect would have been anti-dilutive.

-13-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Note 9—Drilling Fleet
Construction work in progress —Capital expenditures and other capital additions, including capitalized interest, for the six months ended June 30, 2013 and 2012 were as follows (in millions):
Six months ended June 3 0,
2013
2012
Construction work in progress, at beginning of period
$
1,972
$
1,360
Newbuild construction program
Ultra-Deepwater Floater TBN1 (a)
84
—
Ultra-Deepwater Floater TBN2 (a)
82
—
Ultra-Deepwater Floater TBN3 (a)
4
—
Ultra-Deepwater Floater TBN4 (a)
3
—
Transocean Ao Thai (b)
13
45
Deepwater Asgard (c)
24
21
Deepwater Invictus (c)
25
13
Transocean Siam Driller (d) (e)
74
26
Transocean Andaman (d) (e)
82
26
Transocean Honor (e) (f)
—
35
Other construction projects and capital additions
449
279
Total capital expenditures
840
445
Changes in accrued capital expenditures
(29
)
18
Property and equipment placed into service
Transocean Andaman (d)
(242
)
—
Transocean Siam Driller (d)
(236
)
—
Transocean Honor (f)
—
(262
)
Other property and equipment
(502
)
(304
)
Construction work in progress, at end of period
$
1,803
$
1,257
____________________________________
(a)
Our four newbuild Ultra-Deepwater drillships, under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, are expected to commence operations in the fourth quarter of 2015, the second quarter of 2016, the fourth quarter of 2016 and the first quarter of 2017.
(b)
Transocean Ao Thai , a Keppel FELS Super B class design High-Specification Jackup under construction at Keppel FELS’ yard in Singapore, is expected to commence operations in the fourth quarter of 2013.
(c)
Deepwater Asgard and Deepwater Invictus , two Ultra-Deepwater drillships under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, are expected to commence operations in the first quarter of 2014 and third quarter of 2014, respectively.
(d)
Transocean Siam Driller and Transocean Andaman , two Keppel FELS Super B class design High-Specification Jackups, commenced operations in March 2013 and May 2013, respectively.
(e)
The accumulated construction costs of this rig are no longer included in construction work in progress, as the construction project had been completed as of June 30, 2013.
(f)
Transocean Honor , a PPL Pacific Class 400 design High-Specification Jackup, owned through our 70 percent interest in TDSOI, commenced operations in May 2012.  The costs presented above represent 100 percent of TDSOI’s expenditures in the construction of Transocean Honor .
Dispositions —In June 2013, in connection with our efforts to dispose of non-strategic assets, we committed to plans to sell the Deepwater Floater Sedco 709 and the Midwater Floaters C. Kirk Rhein, Jr . and Sedco 703 along with related equipment.  At June 30, 2013, these drilling units and related equipment were classified as assets held for sale with an aggregate carrying amount of $9 million.  See Note 5—Impairments.

-14-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Note 10—Debt
Debt, net of unamortized discounts, premiums and fair value adjustments, was comprised of the following (in millions):
June 3 0 , 2013
December 31, 2012
Transocean
Ltd.
and
subsidiaries
Consolidated
variable
interest
entities
Consolidated
total
Transocean
Ltd.
and
subsidiaries
Consolidated
variable
interest
entities
Consolidated
total
5% Notes due February 2013
$
—
$
—
$
—
$
250
$
—
$
250
5.25% Senior Notes due March 2013 (a)
—
—
—
502
—
502
TPDI Credit Facilities due March 2015
—
—
—
403
—
403
4.95% Senior Notes due November 2015 (a)
1,115
—
1,115
1,118
—
1,118
Callable Bonds due February 2016
—
—
—
282
—
282
5.05% Senior Notes due December 2016 (a)
999
—
999
999
—
999
2.5% Senior Notes due October 2017 (a)
748
—
748
748
—
748
ADDCL Credit Facilities due December 2017
—
178
178
—
191
191
Eksportfinans Loans due January 2018
661
—
661
797
—
797
6.00% Senior Notes due March 2018 (a)
998
—
998
998
—
998
7.375% Senior Notes due April 2018 (a)
247
—
247
247
—
247
6.50% Senior Notes due November 2020 (a)
900
—
900
899
—
899
6.375% Senior Notes due December 2021 (a)
1,199
—
1,199
1,199
—
1,199
3.8% Senior Notes due October 2022 (a)
745
—
745
745
—
745
7.45% Notes due April 2027 (a)
97
—
97
97
—
97
8% Debentures due April 2027 (a)
57
—
57
57
—
57
7% Notes due June 2028
311
—
311
311
—
311
Capital lease contract due August 2029
647
—
647
657
—
657
7.5% Notes due April 2031 (a)
598
—
598
598
—
598
1.50% Series C Convertible Senior Notes due December 2037 (a)
—
—
—
62
—
62
6.80% Senior Notes due March 2038 (a)
999
—
999
999
—
999
7.35% Senior Notes due December 2041 (a)
300
—
300
300
—
300
Total debt
10,621
178
10,799
12,268
191
12,459
Less debt due within one year
5% Notes due February 2013
—
—
—
250
—
250
5.25% Senior Notes due March 2013 (a)
—
—
—
502
—
502
TPDI Credit Facilities due March 2015
—
—
—
70
—
70
Callable Bonds due February 2016
—
—
—
282
—
282
ADDCL Credit Facilities due December 2017
—
30
30
—
28
28
Eksportfinans Loans due January 2018
140
—
140
153
—
153
Capital lease contract due August 2029
21
—
21
20
—
20
1.50% Series C Convertible Senior Notes due December 2037 (a)
—
—
—
62
—
62
Total debt due within one year
161
30
191
1,339
28
1,367
Total long-term debt
$
10,460
$
148
$
10,608
$
10,929
$
163
$
11,092
___________________________________________

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

-15-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)


Scheduled maturities —At June 30, 2013, the scheduled maturities of our debt were as follows (in millions):
Transocean
Ltd.
and subsidiaries
Consolidated
variable
interest
entities
Consolidated
total
Twelve months ending June 30,
2014
$
161
$
30
$
191
2015
163
31
194
2016
1,264
62
1,326
2017
1,166
36
1,202
2018
2,130
19
2,149
Thereafter
5,731
—
5,731
Total debt, excluding unamortized discounts, premiums and fair value adjustments
10,615
178
10,793
Total unamortized discounts, premiums and fair value adjustments, net
6
—
6
Total debt
$
10,621
$
178
$
10,799
Five-Year Revolving Credit Facility —We have a $2.0 billion five-year revolving credit facility, established under a bank credit agreement dated November 1, 2011, as amended, that is scheduled to expire on November 1, 2016 (the “Five-Year Revolving Credit Facility”).  We pay a facility fee on the daily unused amount of the underlying commitment, which ranges from 0.125 percent to 0.325 percent, based on the credit rating of our non-credit enhanced senior unsecured long-term debt (“Debt Rating”), and was 0.275 percent at June 30, 2013.  At June 30, 2013, we had $24 million in letters of credit issued and outstanding, we had no borrowings outstanding, and we had $2.0 billion of available borrowing capacity under the Five-Year Revolving Credit Facility .
Three-Year Secured Revolving Credit Facility —We have a $900 million three-year secured revolving credit facility, established under a bank credit agreement dated October 25, 2012, that is scheduled to expire on October 25, 2015 (the “Three-Year Secured Revolving Credit Facility”).  We pay a facility fee on the daily unused amount of the underlying commitment, which ranges from 0.125 percent to 0.50 percent depending on our Debt Rating, and was 0.375 percent at June 3 0 , 2013 . At June 30, 2013, we had no borrowings outstanding, and we had $900 million of available borrowing capacity under the Three-Year Secured Revolving Credit Facility .
Borrowings under the Three-Year Secured Revolving Credit Facility are secured by the Ultra-Deepwater Floaters Deepwater Champion, Discoverer Americas and Discoverer Inspiration . At June 30, 2013 and December 31, 2012, the aggregate carrying amount of Deepwater Champion, Discoverer Americas and Discoverer Inspiration was $2.3 billion.
5% Notes —On February 15, 2013, we repaid the outstanding $250 million aggregate principal amount of the 5% Notes due February 2013 as of the stated maturity date.
5.25% Senior Notes —On March 15, 2013, we repaid the outstanding $500 million aggregate principal amount of the 5.25% Senior Notes due March 2013 as of the stated maturity date.
TPDI Credit Facilities —We had a $1.265 billion secured credit facility, comprised of a $1 .0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, established under a bank credit agreement dated October 28, 2008, that was scheduled to expire in March 2015 (the “TPDI Credit Facilities”) . One of our subsidiaries participated in the senior and junior term loans with an aggregate commitment of $595 million.
Under the TPDI Credit Facilities, we were required to satisfy certain liquidity requirements, including a requirement to maintain certain cash balances in restricted accounts for the payment of scheduled installments.  At December 31, 2012, we had cash investments of $23 million restricted for the TPDI Credit Facilities, and we had an outstanding letter of credit in the amount of $60 million to satisfy additional liquidity requirements under the TPDI Credit Facilities.
In June 2013, we repaid the $735 million of borrowings outstanding under the TPDI Credit Facilities, of which $367 million was paid to one of our subsidiaries and eliminated in consolidation.  Upon repayment of all borrowings, we terminated the TPDI Credit Facilities.  In the three and six months ended June 30, 2013, we recognized a loss of $1 million associated with the retirement of debt.  See Note 11—Derivatives and Hedging.

-16-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Callable Bonds —Aker Drilling was the obligor for the FRN Aker Drilling ASA Senior Unsecured Callable Bond Issue 2011/2016 (the “FRN Callable Bonds”) and the 11% Aker Drilling ASA Senior Unsecured Callable Bond Issue 2011/2016 (the “11% Callable Bonds,” and together with the FRN Callable Bonds, the “Callable Bonds”), which were publicly traded on the Oslo Stock Exchange.  On March 6, 2013, we redeemed the FRN Callable Bonds and the 11% Callable Bonds with aggregate outstanding principal amounts of NOK 940 million and NOK 560 million, equivalent to $164 million and $98 million, respectively, using an exchange rate of NOK 5.73 to $1.00.  In connection with the redemption, we made an aggregate cash payment of NOK 1,567 million, equivalent to $273 million.  In the six months ended June 30, 2013, we recognized a loss of $1 million associated with the retirement of debt.  See Note 11—Derivatives and Hedging .
ADDCL Credit Facilities —ADDCL has a senior secured credit facility, comprised of Tranche A for $215 million and Tranche C for $399 million, established under a bank credit agreement dated June 2, 2008 that is scheduled to expire in December 2017 (the “ADDCL Primary Loan Facility”) . Unaffiliated financial institutions provide the commitment for and borrowings under Tranche A, and one of our subsidiaries provides the commitment for Tranche C.  At June 30, 2013, $150 million was outstanding under Tranche A at a weighted-average interest rate of 1.1 percent.  At June 30, 2013, $399 million was outstanding under Tranche C and eliminated in consolidation.
Borrowings under the ADDCL Primary Loan Facility are secured by the Ultra-Deepwater Floater Discoverer Luanda. At June 30, 2013 and December 31, 2012, the carrying amount of Discoverer Luanda was $753 million and $786 million, respectively .
ADDCL also has a $90 million secondary credit facility, established under a bank credit agreement dated June 2, 2008 that is scheduled to expire in December 2015 (the “ADDCL Secondary Loan Facility” and together with the ADDCL Primary Loan Facility, the “ADDCL Credit Facilities”).  One of our subsidiaries provides 65 percent of the total commitment under the ADDCL Secondary Loan Facility.  At June 30, 2013, $80 million was outstanding under the ADDCL Secondary Loan Facility, of which $52 million was due to one of our subsidiaries and eliminated in consolidation.  On June 30, 2013, the weighted-average interest rate was 3.4 percent.
ADDCL is required to maintain certain cash balances in accounts restricted for the payment of the scheduled installments on the ADDCL Credit Facilities.  At June 30, 2013 and December 31, 2012, ADDCL had restricted cash investments of $18 million and $19 million, respectively.
Eksportfinans Loans —The Eksportfinans Loans require cash collateral to remain on deposit at a financial institution through expiration (the “Aker Restricted Cash Investments”).  At June 30, 2013 and December 31, 2012, the aggregate principal amount of the Aker Restricted Cash Investments was $664 million and $801 million, respectively.
1.50% Series C Convertible Senior Notes —In the six months ended June 30, 2013, interest expense for our 1.50% Series C Convertible Senior Notes, excluding amortization of debt issue costs, was less than $1 million.  In the three and six months ended June 30, 2012, interest expense for our 1.50% Series C Convertible Senior Notes, excluding amortization of debt issue costs, was $22 million and $43 million, respectively.  At December 31, 2012, the aggregate carrying amount of the 1.50% Series C Convertible Senior Notes included a liability component and an equity component of $62 million and $10 million, respectively.  On February 7, 2013, we redeemed the remaining $62 million aggregate principal amount of the Series C Convertible Senior Notes for an aggregate cash payment of $62 million.
Note 11—Derivatives and Hedging
Derivatives designated as hedging instruments —We previously had interest rate swaps, which were designated and qualified as fair value hedges, to reduce our exposure to changes in the fair values of the 5% Notes due February 2013 and the 5.25% Senior Notes due March 2013 . The interest rate swaps had aggregate notional amounts equal to the corresponding face values of the hedged instruments and have stated maturities that coincide with those of the hedged instruments.  During the six months ended June 30, 2013, these interest rate swaps expired.
We also previously had interest rate swaps, which were designated and 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 through December 31, 2014.  In June 2013, we repaid the borrowings under the TPDI Credit Facilities, and we terminated these interest rate swaps.  In connection with the termination, we made a net cash payment of $22 million, and we reclassified $9 million from accumulated other comprehensive loss to other expense, net.
Additionally, we had cross-currency interest rate swaps, which were designated and qualified as a cash flow hedge, to reduce the variability of cash interest payments and the final principal payment due at maturity in February 2016 associated with the changes in the U.S. dollar to Norwegian krone exchange rate.  In March 2013, in connection with our redemption of the 11% Callable Bonds, we terminated these cross-currency interest rate swaps and the related security agreement with respect to Transocean Spitsbergen and Transocean Barents .  As a result of the termination, we made a cash payment of $128 million and received a cash payment of NOK 705 million, applied to the redemption of the 11% Callable Bonds, and we reclassified $5 million from accumulated other comprehensive loss to other expense, net.  See Note 10—Debt.

-17-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



The effect on our condensed consolidated statements of operations resulting from changes in the fair values of derivatives designated as cash flow hedges was as follows (in millions):
Three months ended
June 30,
Six months ended
June 30,
Statement of operations classification
2013
2012
2013
2012
Loss associated with effective portion
Interest expense, net of amounts capitalized
$
2
$
2
$
4
$
3
Loss associated with effective portion
Other, net
—
4
—
—
Loss associated with terminations
Other, net
9
—
14
—

The balance sheet classification and aggregate carrying amount of our derivatives designated as hedging instruments, measured at fair value, were as follows (in millions):
Balance sheet classification
June 3 0,
2013
December 31,
2012
Interest rate swaps, fair value hedges
Other current assets
$
—
$
6
Interest rate swaps, cash flow hedges
Other long-term liabilities
—
13
Cross-currency swaps, cash flow hedges
Other current assets
—
1
Cross-currency swaps, cash flow hedges
Other assets
—
1
Derivatives not designated as hedging instruments —In connection with our sale transactions with Shelf Drilling, we received non-cash proceeds in the form of preference shares with a stated value of $195 million.  The preference shares contain two embedded derivatives, which were not designated and did not qualify as hedging instruments for accounting purposes, including (a) a ceiling dividend rate indexed to the price of Brent Crude oil and (b) a dividend rate premium triggered in the event of credit default.  At December 31, 2012, the embedded derivatives not designated as hedging instruments had an aggregate carrying amount of $2 million, recorded in other long-term liabilities.  In June 2013, we completed the sale of the preference shares with the embedded derivatives.  See Note 7—Discontinued Operations.
Note 12—Postemployment Benefit Plans
One-time termination benefit plans
During the six months ended June 30, 2013, we committed to a plan to improve the organizational efficiency of our shore-based support activities worldwide.  In connection with this initiative, we established certain one-time termination benefit plans for shore-based employees in the U.S. and the U.K. and for expatriate resident employees worldwide that were or are expected to be involuntarily terminated during the period from May 2013 through December 2014.  The plans generally offer affected individuals a lump sum benefit payment equivalent to between four weeks and 52 weeks of the employee’s weekly base salary, calculated based on the employee’s annual base salary and years of service with additional amounts paid to those employees that would otherwise have been eligible for a bonus payment under our annual incentive program, and allowed for early retirement and immediate vesting for qualifying individuals under our defined benefit plans and other postretirement employee benefit plans.
In the three and six months ended June 30, 2013, we recognized $10 million of expense associated with severance-related costs under these one-time termination benefit plans.  As of June 30, 2013, our payments for involuntary terminations under these plans were less than $1 million.

-18-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Defined benefit 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 covering substantially all of our U.S. employees (the “OPEB Plans”).
The components of net periodic benefit costs, before tax, and funding contributions for these plans were as follows (in millions):
Three months ended June 30, 2013
Three months ended June 30, 2012
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
$
15
$
7
$
—
$
22
$
12
$
9
$
—
$
21
Interest cost
16
5
—
21
15
8
—
23
Expected return on plan assets
(17
)
(5
)
—
(22
)
(16
)
(8
)
—
(24
)
Settlements and curtailments
1
—
—
1
—
—
—
—
Actuarial losses, net
13
1
—
14
10
1
—
11
Prior service cost, net
(1
)
—
—
(1
)
(1
)
—
—
(1
)
Transition obligation, net
—
—
—
—
—
—
—
—
Net periodic benefit costs
$
27
$
8
$
—
$
35
$
20
$
10
$
—
$
30
Funding contributions
$
59
$
3
$
—
$
62
$
100
$
9
$
1
$
110

Six months ended June 30, 2013
Six months ended June 30, 2012
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
$
29
$
14
$
—
$
43
$
24
$
16
$
—
$
40
Interest cost
31
11
1
43
29
13
1
43
Expected return on plan assets
(34
)
(11
)
—
(45
)
(31
)
(13
)
—
(44
)
Settlements and curtailments
1
—
—
1
2
—
—
2
Actuarial losses, net
26
2
—
28
20
2
—
22
Prior service cost, net
(1
)
—
—
(1
)
(1
)
—
—
(1
)
Transition obligation, net
—
—
—
—
—
—
—
—
Net periodic benefit costs
$
52
$
16
$
1
$
69
$
43
$
18
$
1
$
62
Funding contributions
$
60
$
20
$
1
$
81
$
103
$
17
$
2
$
122

Note 13—Commitments and Contingencies
Macondo well incident settlement obligations
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. (together with its affiliates, “BP”) .
On January 3, 2013, we reached an agreement with the U.S. Department of Justice (“DOJ”) to resolve certain outstanding civil and potential criminal charges against us arising from the Macondo well incident.  As part of this resolution, we agreed to a criminal plea (“Plea Agreement”) and a civil consent decree (“Consent Decree”) by which, among other things, we agreed to pay $1.4 billion in fines, recoveries and civil penalties, excluding interest, in scheduled payments through February 2017.

-19-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



In the three and six months ended June 30, 2013, we made an aggregate cash payment of $160 million in satisfaction of amounts due under the Plea Agreement, including $100 million for the payment of the criminal fine, $58 million for the initial payment to the National Fish and Wildlife Foundation and $2 million for the initial payment to the National Academy of Sciences.  In the six months ended June 30, 2013, we paid $404 million, including interest at a rate of 2.15 percent, in satisfaction of amounts due under the Consent Decree.  At June 30, 2013, our outstanding settlement obligations under the Plea Agreement and the Consent Decree, excluding interest, were as follows (in millions):
Plea
Agreement
Consent
Decree
Settlement
obligations
Twelve months ending June 30,
2014
$
60
$
400
$
460
2015
60
200
260
2016
60
—
60
2017
60
—
60
Total settlement obligations
$
240
$
600
$
840
The resolution with the DOJ of such civil and potential criminal claims did not include potential claims arising from the False Claims Act investigation.  As part of the settlement discussions, however, we inquired whether the U.S. intends to pursue any actions under the False Claims Act as discussed below.  In response, the DOJ sent us a letter stating that the Civil Division of the DOJ, based on facts then known, is no longer pursuing any investigation or claims, and did not have any present intention to pursue any investigation or claims, under the False Claims Act against the various Transocean entities for their involvement in the Macondo well incident.
We also agreed that any payments made pursuant to the Plea Agreement or the Consent Decree are not deductible for tax purposes and that we will not use payments pursuant to the Consent Decree as a basis for indemnity or reimbursement from BP or other non-insurer defendants named in the complaint by the U.S.
Plea Agreement —Pursuant to the Plea Agreement, which was accepted by the court on February 14, 2013, one of our subsidiaries pled guilty to one misdemeanor count of negligently discharging oil into the U.S. Gulf of Mexico, in violation of the Clean Water Act (“CWA”).  We agreed to pay a criminal fine of $100 million and to consent to the entry of an order requiring us to pay a total of $150 million to the National Fish & Wildlife Foundation and $150 million to the National Academy of Sciences.
Our subsidiary also agreed to five years of probation.  The DOJ agreed, subject to the provisions of the Plea Agreement, not to further prosecute us for certain conduct generally regarding matters under investigation by the DOJ’s Deepwater Horizon Task Force.  In addition, we agreed to continue to cooperate with the Deepwater Horizon Task Force in any ongoing investigation related to or arising from the accident.
Consent Decree —Pursuant to the Consent Decree, which was approved by the court on February 19, 2013, we agreed to take specified actions relating to operations in U.S. waters, including, among other things, the design and implementation of, and compliance with, additional systems and procedures; blowout preventer certification and reports; measures to strengthen well control competencies, drilling monitoring, recordkeeping, incident reporting, risk management and oil spill training, exercises and response planning; communication with operators; alarm systems; transparency and responsibility for matters relating to the Consent Decree; and technology innovation, with a first emphasis on more efficient, reliable blowout preventers.  We agreed to submit a performance plan (the “Performance Plan”) for approval by the U.S. within 120 days after the date of entry of the Consent Decree.  On July 14, 2013, we submitted our proposed Performance Plan, containing among other required items, interim milestones for actions in specified areas and a proposed schedule for reports required under the Consent Decree.  The Performance Plan has not yet been approved by the U.S.
The Consent Decree also provides for the appointment of (i) an independent auditor to review, audit and report on our compliance with the injunctive provisions of the Consent Decree and (ii) an independent process safety consultant to review, report on and assist with respect to the process safety aspects of the Consent Decree, including operational risk identification and risk management.  The Consent Decree requires certain plans, reports and submissions be made and be acceptable to the U.S. and also requires certain publicly available filings.
Under the terms of the Consent Decree, the U.S. agreed not to sue Transocean Ltd. and certain of our subsidiaries and certain related individuals for civil or administrative penalties for the Macondo well incident under specified provisions of the CWA, the Outer Continental Shelf Lands Act (“OSCLA”), the Endangered Species Act, the Marine Mammal Protection Act, the National Marine Sanctuaries Act, the federal Oil and Gas Royalty Management Act, the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Emergency Planning and Community Right to Know Act and the Clean Air Act.  In addition, the Consent Decree resolved our appeal of the incidents of noncompliance under the OSCLA issued by the Bureau of Safety and Environmental Enforcement (“BSEE”) on October 12, 2011 without any admission of liability by us, and we subsequently dismissed our appeal.

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The Consent Decree did not resolve the rights of the U.S. with respect to all other matters, including certain liabilities under the Oil Pollution Act of 1990 (“OPA”) for removal costs or resulting from a natural resources damages assessment ("NRDA").  However, the district court previously held that we are not liable under the OPA for damages caused by subsurface discharge from the Macondo well.  If this ruling is upheld on appeal, our NRDA liability would be limited to any such damages arising from the above-surface discharge.  The court has not yet ruled whether we could be liable for removal costs to the U.S. or any state or local government as an operator of the Macondo well.
We may request termination of the Consent Decree after we have: (i) completed timely the civil penalty payment requirements of the Consent Decree; (ii) operated under a fully approved Performance Plan required under the Consent Decree through a five-year performance period ending February 2017; (iii) complied with the terms of the Performance Plan and certain provisions of the Consent Decree, generally relating to a framework and outline of measures to improve performance, for at least 12 consecutive months prior to seeking termination; and (iv) complied with the other requirements of the Consent Decree, including payment of any stipulated penalties and compliant reporting.
EPA Agreement —On February 25, 2013, we and the U.S. Environmental Protection Agency (“EPA”) entered into an administrative agreement (the “EPA Agreement”), which has a five-year term.  The EPA Agreement resolved all matters relating to suspension, debarment and statutory disqualification arising from the matters contemplated by the Plea Agreement.  Subject to our compliance with the terms of the EPA Agreement, the EPA had agreed that it will not suspend, debar or statutorily disqualify us and will lift any existing suspension, debarment or statutory disqualification.
In the EPA Agreement, we agreed to, among other things, (1) comply with our obligations under the Plea Agreement and the Consent Decree; (2) continue the implementation of certain programs and systems, including the scheduled revision of our environmental management system and maintenance of certain compliance and ethics programs; (3) comply with certain employment and contracting procedures; (4) engage independent compliance auditors and a process safety consultant to, among other things, assess and report to the EPA on our compliance with the terms of the Plea Agreement, the Consent Decree and the EPA Agreement; and (5) give reports and notices with respect to various matters, including those relating to compliance, misconduct, legal proceedings, audit reports, the EPA Agreement, Consent Decree and Plea Agreement.  Subject to certain exceptions, the EPA Agreement prohibits us from entering into or engaging in certain business relationships with individuals or entities that are debarred, suspended, proposed for debarment or similarly restricted.
Macondo well incident contingencies
Overview —We have recognized a liability for estimated loss contingencies associated with litigation and investigations resulting from the incident that we believe are probable and for which a reasonable estimate can be made.  At June 30, 2013 and December 31, 2012, the liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made was $454 million and $1.9 billion, respectively, recorded in other current liabilities.  The litigation and investigations also give rise to certain loss contingencies that we believe are either reasonably possible or probable but for which we do not believe a reasonable estimate can be made.  Although we have not recognized a liability for such loss contingencies, these contingencies could increase the liabilities we ultimately recognize.
We have also recognized an asset associated with the portion of our estimated losses, primarily related to the personal injury and fatality claims of our crew and vendors, that we believe is probable of recovery from insurance.  Although we have available policy limits that could result in additional amounts recoverable from insurance, recovery of such additional amounts is not probable and we are not currently able to estimate such amounts (see “—Insurance coverage”).  Our estimates involve a significant amount of judgment.  As a result of new information or future developments, we may adjust our estimated loss contingencies arising out of the Macondo well incident or our estimated recoveries from insurance, and the resulting losses could have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows.  At June 30, 2013 and December 31, 2012, the insurance recoverable asset related to estimated losses primarily for additional personal injury and fatality claims of our crew and vendors that we believe are probable of recovery from insurance was $66 million and $153 million, respectively, recorded in other assets.
Multidistrict Litigation proceeding —Many of the Macondo well related claims are pending in the U.S. District Court, Eastern District of Louisiana (the “MDL Court”).  In March 2012, BP and the Plaintiff’s Steering Committee (the “PSC”) announced that they had agreed to a partial settlement related primarily to private party environmental and economic loss claims as well as response effort related claims (the “BP/PSC Settlement”).  The BP/PSC Settlement agreement provides that (a) to the extent permitted by law, BP will assign to the settlement class certain of BP’s claims, rights and recoveries against us for damages with protections such that the settlement class is barred from collecting any amounts from us unless it is finally determined that we cannot recover such amounts from BP, and (b) the settlement class releases all claims for compensatory damages against us but purports to retain claims for punitive damages against us.
On December 21, 2012, the MDL Court granted final approval of the economic and property damage class settlement between BP and the PSC.  In December 2012, in response to the settlements, we filed three motions seeking partial summary judgment on various claims, including punitive damages claims.  If successful, these motions would eliminate or reduce our exposure to punitive damages.  The MDL Court has not ruled on these motions.

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In May 2013, we filed a motion seeking partial summary judgment on claims asserted by BP against us seeking damages from loss of the well and for source-control and cleanup costs (the “Direct Damages” claims).  The Direct Damages claims are included in the claims BP assigned to the economic and property damages settlement class.  The motion argues that BP released the Direct Damages claims in its contract with us and that the release is enforceable even if we are found grossly negligent.  Some courts have held that such agreements will not be enforced if the defendant is found grossly negligent.  The MDL Court has not ruled on this motion.
The first phase of the trial commenced on February 25, 2013.  The trial addressed fault issues that had not previously been disposed of or resolved by settlement, summary judgment, or stipulation and that may properly be tried by the MDL Court without a jury, including negligence, gross negligence, or other bases of liability of the various defendants with respect to the issues, and limitation of liability issues.  On June 21, 2013, following the presentation of evidence and pursuant to the MDL Court order, the parties filed post-trial briefs and proposed findings of fact and conclusions of law.  The MDL Court ordered that reply briefs be filed by July 12, 2013.
If the MDL Court finds in this phase of the trial that we were grossly negligent, we will be exposed to at least three litigation risks: (1) the MDL Court could award punitive damages under general maritime law to plaintiffs who own property damaged by oil and to plaintiffs who are commercial fishermen; (2) the MDL Court could find that our gross negligence voids the release BP gave us in the drilling contract for direct claims by BP, which BP has assigned to the plaintiffs in the BP/PSC settlement; and (3) we could be liable for all other oil pollution damages claims, including claims for natural resource damages, if the MDL Court were to go beyond gross negligence for which we are to be indemnified and find a “core breach” of the drilling contract, or if the court of appeals were to reverse a prior ruling that BP owes us indemnity for these claims even in the event of gross negligence.  Our four pending motions for partial judgment on the pleadings or partial summary judgment, if successful, could reduce or eliminate our exposure to these claims.  A finding of gross negligence against us or against BP or a finding that either we or BP violated certain safety regulations would also result in the removal of the statutory liability caps under OPA.  Under the MDL Court’s present ruling, however, our liability for damages under OPA is limited to damages caused by discharge on or above the surface of the water.
The MDL Court has scheduled a trial date of September 30, 2013 for the second phase of the trial, which will address conduct related to stopping the release of hydrocarbons between April 22, 2010 and approximately September 19, 2010 and quantify the cumulative discharge of oil caused by the release.  In light of BP’s criminal plea agreement with the DOJ acknowledging that it provided the government with false or misleading information throughout the spill response, we have amended our pleadings to allege as an affirmative defense that BP’s fraud delayed the final capping of the well and that we should not be liable for damages resulting from this delay.
We can provide no assurances as to the outcome of the trial, as to the timing of any upcoming phase of trial, that we will not enter into additional settlements as to some or all of the matters related to the Macondo well incident, including those to be determined at a trial, or the timing or terms of any such settlements.
Litigation —As of June 30, 2013, 1,365 actions or claims were pending against us, 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 June 30, 2013, we have been named, along with other unaffiliated defendants, in certain complaints that were pending in state and federal courts in Louisiana and Texas involving multiple plaintiffs that allege wrongful death or other personal injuries arising out of the Macondo well incident.  Nine complaints involve fatalities and 63 complaints seek recovery for bodily injuries.  A number of these lawsuits have been settled.  Per the order of the Multidistrict Litigation Panel (“MDL”), all claims but one have been centralized for discovery purposes in the MDL Court.  The complaints generally allege negligence and seek awards of unspecified economic and punitive damages.  BP, MI-SWACO, Weatherford International Ltd. and Cameron International Corporation (“Cameron”) and certain of their affiliates, have, based on contractual arrangements, also made indemnity demands upon us with respect to personal injury and wrongful death claims asserted by our employees or representatives of our employees against these entities.  See “—Contractual indemnity.”
Economic loss —As of June 30, 2013, we and certain of our subsidiaries were named, along with other unaffiliated defendants, in 921 pending individual complaints as well as 199 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 OPA and state OPA analogues.  The plaintiffs are generally seeking awards of unspecified economic, compensatory and punitive damages, as well as injunctive relief.  No classes have been certified at this time.  Most of these actions have either been transferred to or are the subject of motions to transfer to the MDL.  See “—Contractual indemnity.”

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Cross-claims, counter-claims, and third party claims — In April 2011, several defendants in the MDL litigation filed cross - claims or third - party claims against us and certain of our subsidiaries, and other defendants.  BP filed a claim seeking contribution under the OPA and maritime law, subrogation and claimed breach of contract, unseaworthiness, negligence and gross negligence.  Through these claims, BP sought to recover from us damages it has paid or may pay arising from the Macondo well incident.  BP also sought a declaration that it is not liable in contribution, indemnification, or otherwise to us.  Anadarko Petroleum Corporation (“Anadarko”), which owned a 25 percent non - operating interest in the Macondo well, asserted claims of negligence, gross negligence, and willful misconduct and is seeking indemnity under state and maritime law and contribution under maritime and state law as well as OPA.  MOEX Offshore 2007 LLC (“MOEX”), which owns a 10 percent non-operating interest in the Macondo well, filed claims of negligence under state and maritime law, gross negligence under state law, gross negligence and willful misconduct under maritime law and is seeking indemnity under state and maritime law and contribution under maritime law and OPA.  Cameron, the manufacturer and designer of the blowout preventer, asserted multiple claims for contractual indemnity and declarations regarding contractual obligations under various contracts and quotes and is also seeking non - contractual indemnity and contribution under maritime law and OPA.  As part of the BP/PSC Settlement, one or more of these claims against us and certain of our subsidiaries have been assigned to the PSC settlement class.  Halliburton Company (“Halliburton”), which provided cementing and mud-logging services to the operator, filed a claim against us seeking contribution and indemnity under maritime law, contractual indemnity and alleging negligence and gross negligence.  Additionally, certain other third parties filed claims against us for indemnity and contribution.
In April 2011, we filed cross - claims and counter - claims against BP, Halliburton, Anadarko, MOEX, certain of these parties’ affiliates, the U.S. and certain other third parties.  We seek indemnity, contribution , including contribution under OPA, and subrogation under OPA, and we have asserted claims for breach of warranty of workmanlike performance, strict liability for manufacturing and design defect, breach of express contract, and damages for the difference between the fair market value of Deepwater Horizon and the amount received from insurance proceeds.  The Consent Decree limits our ability to seek indemnification or reimbursement with respect to certain of these matters against the owners of the Macondo well.  We are not pursuing arbitration on the key contractual issues with BP; instead, we are relying on the court to resolve the disputes.  With regard to the U.S., we are not currently seeking recovery of monetary damages, but rather a declaration regarding relative fault and contribution via credit, setoff, or recoupment.
Federal securities claims —A federal securities proposed class action is currently pending in the U.S. District Court, Southern District of New York, naming us and former chief executive officers of Transocean Ltd. and one of our acquired companies as defendants.  In the action, a former shareholder of the acquired company alleges that the joint proxy statement related to our shareholder meeting in connection with our merger with the acquired company violated Section 14(a) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 14a-9 promulgated thereunder and Section 20(a) of the Exchange Act.  The plaintiff claims that the acquired company’s shareholders received inadequate consideration for their shares as a result of the alleged violations and seeks compensatory and rescissory damages and attorneys’ fees on behalf of itself and the proposed class members.  In addition, we are obligated to pay the defense fees and costs for the individual defendants, which may be covered by our directors’ and officers’ liability insurance, subject to a deductible.  On October 4, 2012, the court denied our motion to dismiss the action.  On October 5, 2012, we asked the court to stay the action pending a decision by the Second Circuit Court of Appeals in an unrelated action involving the time period within which Section 14 claims can be filed that could be relevant to the disposition of this case.  On June 27, 2013, the Second Circuit Court of Appeals ruled on the issue in a manner that we believe supports our position that the plaintiff’s existing claims alleged in the action are time-barred.  At our request, the court lifted the stay so that we may seek dismissal of the action.
Other federal statutes —Several of the claimants have made assertions under the statutes, including the CWA, the Endangered Species Act, the Migratory Bird Treaty Act, the CERCLA and the Emergency Planning and Community Right-to-Know Act.
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 current and former officers and directors as defendants in state district court in Texas.  These cases allege breach of fiduciary duty, unjust enrichment, abuse of control, gross mismanagement and waste of corporate assets in connection with the Macondo well incident.  The plaintiffs are generally seeking to recover, on behalf of us, damages to the corporation and disgorgement of all profits, benefits, and other compensation from the individual defendants.  Any recovery of the damages or disgorgement by the plaintiffs in these actions would be paid to us.  If the plaintiffs prevail, we could be required to pay plaintiffs’ attorneys’ fees.  In addition, we are obligated to pay the defense fees and costs for the individual defendants, which may be covered by our directors’ and officers’ liability insurance, subject to a deductible.  The two actions have been consolidated before a single judge.  In August 2012, the defendants filed a motion to dismiss the complaint on the ground that if the actions are to proceed they must be maintained in the courts of Switzerland and on the ground that the plaintiffs lack standing to assert the claims alleged.  In December 2012, in response to defendants' motion to dismiss for lack of standing, the plaintiffs dismissed their action without prejudice.  In January 2013, one of the plaintiffs re-filed a complaint that was previously dismissed seeking to recover damages to the corporation and disgorgement of all profits, benefits, and other compensation from the individual defendants.  Defendants filed a motion to dismiss in March 2013.  Briefing on this motion to dismiss was completed on June 27, 2013, and a hearing was scheduled for July 26, 2013.

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U.S. Department of Justice claims —On December 15, 2010, the DOJ filed a civil lawsuit against us and other unaffiliated defendants.  The complaint alleged violations under OPA and the CWA, including claims for per barrel civil penalties of up to $1,100 per barrel or up to $4,300 per barrel if gross negligence or willful misconduct is established, and the DOJ reserved its rights to amend the complaint to add new claims and defendants.  The U.S. government has estimated that up to 4.1 million barrels of oil were discharged and subject to penalties.  The complaint asserted that all defendants named are jointly and severally liable for all removal costs and damages resulting from the Macondo well incident.  In response to the U.S. complaint, BP and Anadarko filed claims seeking contribution from us for any damages for which they may be found liable, including OPA damages.  On December 6, 2011, the DOJ filed a motion for partial summary judgment seeking a ruling that we were jointly and severally liable under OPA, and liable for civil penalties under the CWA, for all of the discharges from the Macondo well on the theory that discharges not only came from the well but also from the blowout preventer and riser, appurtenances of Deepwater Horizon .
On January 9, 2012, we filed our opposition to the motion and filed a cross-motion for partial summary judgment seeking a ruling that we are not liable for the subsurface discharge of hydrocarbons.  On February 22, 2012, the MDL Court ruled that we are not liable as a responsible party for damages under OPA with respect to the below surface discharges from the Macondo well.  The MDL Court did not rule on whether we could be liable for removal costs to the U.S. or any state or local government as an operator of the Macondo well.  The court also ruled that the below surface discharge was discharged from the well facility, and not from the Deepwater Horizon vessel, within the meaning of the CWA, and that we therefore are not liable for such discharges as an owner of the vessel under the CWA.  However, the MDL Court ruled that the issue of whether we could be held liable for such discharge under the CWA as an operator of the well facility could not be resolved on summary judgment.  We subsequently entered into an agreement with the DOJ regarding liability to the U.S. with respect to its CWA claim through the Consent Decree.  The Consent Decree did not resolve the rights of the U.S. with respect to certain liabilities under OPA for removal costs or natural resources damages.  See “—Macondo well incident settlement obligations” .
In addition to the civil complaint, the DOJ served us with civil investigative demands on December 8, 2010.  These demands were part of an investigation by the DOJ to determine if we made false claims, or false statements in support of claims, in violation of the False Claims Act, in connection with the operator’s acquisition of the leasehold interest in the Mississippi Canyon Block 252, Gulf of Mexico and drilling operations on Deepwater Horizon. As part of the settlement discussions, we inquired whether the U.S. intends to pursue any actions under the False Claims Act.  In response, the DOJ sent us a letter stating that the Civil Division of the DOJ, based on facts then known, is no longer pursuing any investigation or claims, and did not have any present intention to pursue any investigation or claims, under the False Claims Act against the various Transocean entities for their involvement in the Macondo well incident.
As noted above, the DOJ also conducted a criminal investigation into the Macondo well incident.  On March 7, 2011, the DOJ announced the formation of the Deepwater Horizon Task Force to lead the criminal investigation.  The task force investigated possible violations by us and certain unaffiliated parties of the CWA, the Migratory Bird Treaty Act, the Refuse Act, the Endangered Species Act, and the Seaman’s Manslaughter Act, among other federal statutes, and possible criminal liabilities , including fines under those statutes and under the Alternative Fines Act.  As discussed above, on January 3, 2013, we entered into the Plea Agreement with the DOJ resolving these claims.  See “—Macondo well incident settlement obligations.”
State and other government claims —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.  In October 2010, the LDEQ rescinded its enforcement actions against us and our subsidiaries but reserved its rights to seek civil penalties for future violations of the Louisiana Environmental Quality Act.
In September 2010, the State of Louisiana filed a declaratory judgment seeking to designate us as a responsible party under OPA and the Louisiana Oil Spill Prevention and Response Act for the discharges emanating from the Macondo well.
Subsequent to the Louisiana filing for declaratory judgment and prior to the tolling of the statute of limitations in April 2013, suits were filed by over 200 state, local and foreign governments, including the U.S. States of Alabama, Florida, Louisiana, Mississippi and Texas; the Mexican States of Veracruz, Quintana Roo and Tamaulipas (“Mexican States”); and by other local governments by and on behalf of multiple towns and parishes.  These governments generally assert claims under OPA, other statutory environmental state claims and various common law claims.  A local government master complaint also was filed in which cities, municipalities, and other local government entities can, and have, joined.  Most of these new government cases, including the suits filed by the attorneys general of Alabama, Florida, Louisiana, Mississippi and Texas, have been transferred to the MDL.
The Mexican States’ OPA claims were subsequently dismissed for failure to demonstrate that recovery under OPA was authorized by treaty or executive agreement.  However, the Court preserved some of the Mexican States’ negligence and gross negligence claims, but only to the extent there has been a physical injury to a proprietary interest.  As such, the ruling as to the Mexican States is not yet final and not subject to appeal at this time.

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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 cleanup 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.
On August 26, 2011, the MDL Court ruled on the motion to dismiss certain economic loss claims.  The court ruled that state law, both statutory and common law, is preempted by maritime law, notwithstanding OPA’s savings provisions.  Accordingly, all claims brought under state law were dismissed.  Secondly, general maritime law claims that do not allege physical damage to a proprietary interest were dismissed, unless the claim falls into the commercial fisherman exception.  The court ruled that OPA claims for economic loss do not require physical damage to a proprietary interest.  Third, the MDL Court ruled that presentment under OPA is a mandatory condition precedent to filing suit against a responsible party.  Finally, the MDL Court ruled that claims for punitive damages may be available under general maritime law in claims against responsible parties and non-responsible parties.  Certain Louisiana parishes have appealed portions of this ruling.  The appeal was argued to the Fifth Circuit Court of Appeals on March 5, 2013.  The court has not ruled on this appeal.
The state, local and foreign government claims include claims under OPA.  On February 22, 2012, the MDL Court ruled that we are not a responsible party under OPA for damages with respect to subsurface discharge from the Macondo well.
Prior to the expiration of the three-year statute of limitations on April 20, 2013, additional private plaintiffs filed new lawsuits relating to the Macondo well incident.  We are named as a defendant in many but not all of the new lawsuits.  The lawsuits seek recoveries for economic loss and punitive damages and allege claims under OPA, maritime law and state law.  Some of the new lawsuits were filed in the MDL Court, but many were filed in state and federal courts outside of the MDL Court.  Most of these cases have been transferred to the MDL and, consistent with our prior experience, we expect the remaining cases to be transferred to the MDL Court.
Wreck removal —By letter dated December 6, 2010, the U.S. Coast Guard requested us to formulate and submit a comprehensive oil removal plan to remove any diesel fuel contained in the sponsons and fuel tanks that can be recovered from Deepwater Horizon. We have conducted a survey of the rig wreckage and have confirmed that no diesel fuel remains on the rig.  The U.S. Coast Guard has not requested that we remove the rig wreckage from the sea floor.  In October 2012, a new sheen was reported and preliminarily determined to have originated from the Macondo well.  Sources state that BP was notified of the sheen in early September 2012 and had commenced an investigation to determine the source, whether the oil and mud were from the sea floor, the rig or rig equipment, or other sources.  In February 2013, the U . S . Coast Guard submitted a request seeking analysis and recommendations as to the potential life of the rig’s riser and cofferdam resting on the seafloor and potential remediation or removal options.  We have insurance coverage for wreck removal for up to 25 percent of Deepwater Horizon ’s insured value, or $140 million, with any excess wreck removal liability generally covered to the extent of our remaining excess liability limits.
Insurance coverage —At the time of the Macondo well incident, our excess liability insurance program offered aggregate insurance coverage of $950 million, excluding a $15 million deductible and a $50 million self-insured layer through our wholly owned captive insurance subsidiary.  This excess liability insurance coverage consisted of a first and a second layer of $150 million each, a third and fourth layer of $200 million each and a fifth layer of $250 million.  The first four excess layers have similar coverage and contractual terms, while the $250 million fifth layer is on a different policy form, which varies to some extent from the underlying coverage and contractual terms.  Generally, we believe that the policy forms for all layers include coverage for personal injury and fatality claims of our crew and vendors, actual and compensatory damages, punitive damages and related legal defense costs and that the policy forms for the first four excess layers provide coverage for fines; however, we do not expect payments deemed to be criminal in nature to be covered by any of the layers.
In May 2010, we received notice from BP maintaining that it believes that it is entitled to additional insured status under our excess liability insurance program.  Our insurers have also received notices from Anadarko and MOEX advising of their intent to preserve any rights they may have to our insurance policies as an additional insured under the drilling contract.  In response, our wholly owned captive insurance subsidiary and our first four excess layer insurers filed declaratory judgment actions in the Houston Division of the U.S. District Court for the Southern District of Texas in May 2010 seeking a judgment declaring that they have limited additional insured obligations to BP, Anadarko and MOEX.  We are parties to the declaratory judgment actions, which were transferred to the MDL Court for discovery and other purposes.  On November 15, 2011, the MDL Court ruled that BP’s coverage rights are limited to the scope of our indemnification of BP in the drilling contract.  A final judgment was entered against BP, Anadarko and MOEX, and BP appealed.  On March 1, 2013, the U.S. Court of Appeals for the Fifth Circuit reversed the decision of the MDL Court, and held that BP is an unrestricted additional insured under the policies issued by our wholly owned captive insurance company and the first four excess layer insurers.

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(Unaudited)



We believe that additional insured coverage for BP, Anadarko or MOEX under the $250 million fifth layer of our insurance program is limited to the scope of our indemnification of BP under the drilling contract.  We and the insurers filed petitions for rehearing en banc with the Fifth Circuit.  The court has not yet issued a ruling on the petitions.  While we cannot predict the outcome of the petitions for rehearing of the Fifth Circuit’s decision, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
Our first layer and second layer of excess insurers, each representing $150 million of insurance coverage, filed interpleader actions on June 17, 2011 and July 31, 2012, respectively.  On February 14, 2013, the third and fourth layers, each representing $200 million of insurance coverage, filed interpleader actions substantially similar to the prior filings.  The insurers contend that they face multiple, and potentially competing, claims to the relevant insurance proceeds.  In these actions, the insurers effectively ask the court to manage disbursement of the funds to the alleged claimants, as appropriate, and discharge the insurers of any additional liability.  The parties to the first and second excess insurer interpleader actions have executed protocol agreements to facilitate the reimbursement and funding of settlements of personal injury and fatality claims of our crew and vendors (collectively, “crew claims”) using insurance funds and claims were submitted to the court for review.  Following the court’s determination and approval of the amounts to be paid by the insurers with respect to the crew claims submitted by the parties to date, the first layer of excess insurers made reimbursement payments to the parties for crew claims in the three months ended June 30, 2013.  Parties to the third and fourth excess insurer interpleader actions have agreed to adjourn the deadline for responses to the pleadings to an unspecified date that will follow a decision in another action that pertains to our insurance.
Contractual indemnity —Under our drilling contract for Deepwater Horizon , 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.
Although we believe we are entitled to contractual defense and indemnity, the operator has sought to avoid its indemnification obligations.  In April 2011, the operator filed a claim seeking a declaration that it is not liable to us in contribution, indemnification, or otherwise.  On November 1, 2011, we filed a motion for partial summary judgment, seeking enforcement of the indemnity obligations for pollution and civil fines and penalties contained in the drilling contract with the operator.  On January 26, 2012, the court ruled that the drilling contract requires the operator to indemnify us for compensatory damages asserted by third parties against us related to pollution that did not originate on or above the surface of the water, even if the claim is the result of our strict liability, negligence, or gross negligence.  The ruling is not currently subject to appeal, but may be appealed once a final judgment in the case is rendered.  The court also held that the operator does not owe us indemnity to the extent that we are held liable for civil penalties under the CWA or for punitive damages, and we have since agreed with the DOJ that we will not seek indemnity or reimbursement of our Consent Decree payments from the operator or the other non-insured defendants named in the complaint by the U.S.  The court deferred ruling on the operator’s argument that we committed a core breach of the drilling contract or otherwise materially increased the operator’s risk or prejudiced its rights so as to vitiate the operator’s indemnity obligations.  Our motion for partial summary judgment and the court’s ruling did not address the issue of contractual indemnity for criminal fines and penalties.  The law generally considers contractual indemnity for criminal fines and penalties to be against public policy.  Our motion did not ask the court to rule on the validity of BP’s agreement in the drilling contract to release us from any claims asserted by BP itself.  Some courts have held that such agreements will not be enforced if the defendant is found to be grossly negligent.  In May 2013, we filed a motion for partial summary judgment seeking to enforce BP’s agreement to release claims made by BP itself.  The MDL Court has not yet ruled on this motion.
Other legal proceedings
Brazil Frade field incident —On or about November 7, 2011, oil was released from fissures in the ocean floor in the vicinity of a development well being drilled by Chevron off the coast of Rio de Janeiro in the Frade field with Sedco 706 .  The release was ultimately controlled, the well was plugged.

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TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



On or about December 13, 2011, a federal prosecutor in the town of Campos in Rio de Janeiro State filed a civil public action against Chevron and us seeking BRL 20.0 billion, equivalent to approximately $9 .0 billion, and seeking a preliminary and permanent injunction preventing Chevron and us from operating in Brazil.  The prosecutor amended the requested injunction on December 15, 2011, to seek to prevent Chevron and us from conducting extraction or transportation activities in Brazil and to seek to require Chevron to stop the release and remediate its effects.  On November 27, 2012, after various appeals related to jurisdiction and to the merits of preliminary injunctions against us and Chevron, the Court of Appeals in Rio de Janeiro ruled unanimously to suspend the preliminary injunction orders against us in this matter.
The prosecutor has announced that settlement discussions are underway for resolution of the civil proceedings, and the action of the trial court was temporarily suspended pending the settlement discussion.  There can be no assurance that any settlement will be achieved or the timing or terms of such settlement.  If these settlement efforts are not successful, the lawsuit will continue in the trial court, and there remains a risk that the preliminary injunction could be reinstated, or that at the conclusion of the case Brazilian authorities could permanently enjoin us from further operations in Brazil.  If either or both of these events occur, it could have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
On December 21, 2011, a federal police marshal investigating the release filed a report with the federal court in Rio de Janeiro State recommending the indictment of Chevron, us, and 17 individuals, five of whom are our employees.  The report recommended indictment on four counts, three alleging environmental offenses and one alleging false statements by Chevron in connection with its remediation efforts.  On February 19, 2013, the federal court in Rio de Janeiro rejected the charges and denied the criminal indictment of us and five of our employees.  The order dismissing the indictments has subsequently become final.
The drilling services and charter contracts between Chevron and us provide, among other things, for Chevron to indemnify and defend us for claims based on pollution or contamination originating from below the surface of the water, including claims for control or removal or property loss or damage, including but not limited to third-party claims and liabilities, with an excludable amount of $250,000 per occurrence if the claim arises from our negligence.  We have submitted a claim for indemnity and defense to Chevron under these contracts.  Chevron responded that our request was premature, and requested that we confirm our intent to indemnify and defend Chevron regarding alleged violations of safety regulations aboard Sedco 706 that have resulted in the issuance of notices of infractions and any other claims or liabilities that may fall within our legal obligations.  By letter dated September 6, 2012, Chevron agreed to indemnify us for all claims and liabilities resulting in judgments, awards or other monetary assessments of a strictly compensatory nature for alleged damages arising from pollution or contamination that originated below the surface of the water in connection with the incident.  Chevron has also agreed to assume our defense in the criminal and civil lawsuits and reimburse us for certain defense costs associated with the lawsuits.  We have been engaged in subsequent discussions with Chevron regarding the parameters of Chevron’s agreement and begun making arrangements to receive payment on certain of our claims for indemnity.
On March 15, 2012, Chevron publicly announced that it had identified a new sheen in Frade field whose source was determined to be seepage from an 800 - meter fissure 3 kilometers away from the location of the November 2011 incident.  Chevron and the Brazilian National Agency of Petroleum have publicly stated that, while further studies are being conducted, the new seepage, which was estimated by Chevron, at the time, to be five liters, is now believed to be unrelated to the November 2011 incident.
On March 27, 2012, the union of oil industry workers in Brazil, Federacao Unica dos Petroleiros (“FUP”), filed a civil lawsuit in federal court in Rio de Janeiro against Chevron and us alleging a number of claims, including negligence on our part, and seeking a permanent injunction enjoining our operations in Brazil.  The lawsuit sought unspecified damages.  On or about April 16, 2012, the court issued an order transferring this case to the same court in Rio de Janeiro in which the initial civil public action is pending.  On or about May 1, 2012, the Rio de Janeiro court dismissed this lawsuit, without prejudice, as duplicative of the other civil lawsuits.  The FUP has appealed this dismissal.  On October 26, 2012, the trial court issued an opinion suspending the lawsuit until a final decision is rendered on the merits on the first civil public action filed by the federal prosecutor; this opinion had the effect of staying the FUP’s appeal.
On or about April 3, 2012, the same federal prosecutor who filed the original civil public action and the criminal indictments filed a new civil public action against Chevron and us in federal court in Campos.  This lawsuit alleges the new seepage discovered in March 2012 is related to the November 2011 incident and release.  The lawsuit seeks an additional BRL 20.0 billion, equivalent to approximately $9.0 billion, in damages.  We were served in this matter on April 12, 2013, and our defense was filed on May 14, 2013.
Additional private civil lawsuits have been filed against Chevron and us in various states and counties within Brazil.  The approximately 230 private lawsuits allege moral damages of between $12,000 and $35,000 each and contain substantially identical allegations that the alleged pollution from the incident prevented the claimants from fishing.  We are in various stages in defense of these lawsuits and are submitting claims to Chevron for indemnity and defense in each case.
We are working toward resolving all valid claims that are brought based on the incidents and will vigorously defend any claims that may not be resolved . While we cannot predict or provide assurance as to the outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



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.  Each individual plaintiff was subsequently required to file a separate lawsuit, and the original 21 multi-plaintiff complaints were then dismissed by the Circuit Courts.  We have or may have an indirect interest in a total of 22 cases . The complaints generally allege that the defendants used or manufactured asbestos-containing drilling mud additives for use in connection with drilling operations and have included allegations of negligence, products liability, strict liability and claims allowed under the Jones Act and general maritime law.  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.  All of these cases are being governed for discovery and trial setting by a single Case Management Order entered by a Special Master appointed by the court to reside over all the cases, and of the 17 cases in which we are a named defendant, only one has been scheduled for trial and pre-trial discovery, which was scheduled to take place in 2013 . In that case, we recently were able to present a variety of pre-trial defense motions challenging the plaintiff’s evidence and resulting in a negotiated settlement for a nominal sum in the first quarter of 2013.  In 2011, the Special Master issued a ruling that a Jones Act employer defendant, such as us, cannot be sued for punitive damages, and this ruling has now been obtained in three of our 17 cases.  To date, seven of the 769 cases have gone to trial against defendants who allegedly manufactured or distributed drilling mud additives.  None of these cases have involved an individual Jones Act employer , and we have not been a defendant in any of these cases.  Two of the cases resulted in defense verdicts , and one case ended with a hung jury.  Four cases resulted in verdicts for the plaintiff.  Because the jury awarded punitive damages, two of these cases resulted in a substantial verdict in favor of the plaintiff; however , the trial court has since vacated both of these verdicts . The first plaintiff verdict was vacated 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 is currently being reviewed on appeal.  The second plaintiff verdict was vacated because the presiding judge was removed from hearing any asbestos cases due to a conflict of interest, but when this case ultimately went to trial earlier this year, it resulted in a defense verdict . The two remaining plaintiff verdicts are under appeal by the defendants.  We intend to defend these lawsuits vigorously, although we can provide no assurance as to the outcome.  We historically have maintained broad liability insurance, although we are not certain whether insurance will cover the liabilities, if any, arising out of these claims.  Based on our evaluation of the exposure to date, we do not expect the liability, if any, resulting from these claims to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
One of our subsidiaries was involved in lawsuits arising out of the subsidiary’s involvement in the design, construction and refurbishment of major industrial complexes.  The operating assets of the subsidiary were sold and its operations discontinued in 1989, and the subsidiary has no remaining assets other than the insurance policies involved in its litigation, with its insurers and, either directly or indirectly through a qualified settlement fund.  The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging bodily injury or personal injury as a result of exposure to asbestos.  As of June 30, 2013, the subsidiary was a defendant in approximately 889 lawsuits, some of which include multiple plaintiffs , and we estimate that there are approximately 1 , 880 plaintiffs in these lawsuits.  For many of these lawsuits, we have not been provided with sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries.  The first of the asbestos-related lawsuits was filed against the subsidiary in 1990.  Through June 30, 2013, the costs incurred to resolve claims, including both defense fees and expenses and settlement costs, have not been material, all known deductibles have been satisfied or are inapplicable, and the subsidiary’s defense fees and expenses and settlement costs have been met by insurance made available to the subsidiary.  The subsidiary continues to be named as a defendant in additional lawsuits, and we cannot predict the number of additional cases in which it may be named a defendant nor can we predict the potential costs to resolve such additional cases or to resolve the pending cases.  However, the subsidiary has in excess of $1.0 billion in insurance limits potentially available to the subsidiary.  Although not all of the policies may be fully available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient funding directly or indirectly from settlements and claims payments from insurers, assigned rights from insurers and coverage-in-place settlement agreements with insurers to respond to these claims.  While we cannot predict or provide assurance as to the outcome of these matters, we do not believe that the ultimate liability, if any, arising from these claims will have a material impact on our consolidated statement of financial position, results of operations or cash flows.
Rio de Janeiro tax assessment —In the third quarter of 2006, we received tax assessments of BRL 509 million, equivalent to approximately $228 million, including interest and penalties, from the state tax authorities of Rio de Janeiro in Brazil against one of our Brazilian subsidiaries for taxes on equipment imported into the state in connection with our operations.  The assessments resulted from a preliminary finding by these authorities that our record keeping practices were deficient.  We currently believe that the substantial majority of these assessments are without merit.  We filed an initial response with the Rio de Janeiro tax authorities on September 9, 2006 refuting these additional tax assessments.  In September 2007, we received confirmation from the state tax authorities that they believe the additional tax assessments are valid, and as a result, we filed an appeal on September 27, 2007 to the state Taxpayer’s Council contesting these assessments.  While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
Brazilian import license assessment —In the fourth quarter of 201 0 , we received an assessment from the Brazilian federal tax authorities in Rio de Janeiro of BRL 503 million, equivalent to approximately $226 million, including interest and penalties, based upon the alleged failure to timely apply for import licenses for certain equipment and for allegedly providing improper information on import license applications.  We believe that a substantial majority of the assessment is without merit and are vigorously pursuing legal remedies . The case was decided partially in favor of our Brazilian subsidiary in the lower administrative court level.  The decision cancelled the majority of the assessment, reducing the total assessment to BRL 32 million, equivalent to approximately $14 million.  On July 14, 2011, we filed an appeal to eliminate the assessment.  On May 23, 2013, a ruling was issued that eliminated all assessment amounts.  A further appeal by the taxing authorities is possible.  While we cannot predict or provide assurance as to the outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)


Other matters —We are involved in various tax matters , various regulatory matters, and a number of claims and lawsuits, 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.  We can provide 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 CERCLA and similar state acts regulating cleanup of various hazardous waste disposal sites, including those described below.  CERCLA is intended to expedite the remediation of hazardous substances without regard to fault.  Potentially responsible parties (“PRPs”) for each site include present and former owners and operators of, transporters to and generators of the substances at the site.  Liability is strict and can be joint and several.
We have been named as a PRP in connection with a site located in Santa Fe Springs, California, known as the Waste Disposal, Inc. site.  We and other PRPs have agreed with the EPA and the DOJ to settle our potential liabilities for this site by agreeing to perform the remaining remediation required by the EPA.  The form of the agreement is a consent decree, which has been entered by the court.  The parties to the settlement have entered into a participation agreement, which makes us liable for approximately eight percent of the remediation and related costs.  The remediation is complete, and we believe our share of the future operation and maintenance costs of the site is not material.  There are additional potential liabilities related to the site, but these cannot be quantified, and we have no reason at this time to believe that they will be material.
One of our subsidiaries has been ordered by the California Regional Water Quality Control Board (“CRWQCB”) to develop a testing plan for a site known as Campus 1000 Fremont in Alhambra, California.  This site was formerly owned and operated by certain of our subsidiaries.  It is presently owned by an unrelated party, which has received an order to test the property.  We have also been advised that one or more of our subsidiaries is likely to be named by the EPA as a PRP for the San Gabriel Valley, Area 3, Superfund site, which includes this property.  Testing has been completed at the property but no contaminants of concern were detected.  In discussions with CRWQCB staff, we were advised of their intent to issue us a “no further action” letter but it has not yet been received.  Based on the test results, we would contest any potential liability.  We have no knowledge at this time of the potential cost of any remediation, who else will be named as PRPs, and whether in fact any of our subsidiaries is a responsible party.  The subsidiaries in question do not own any operating assets and have limited ability to respond to any liabilities.
Resolutions of other claims by the EPA, the involved state agency or PRPs are at various stages of investigation.  These investigations involve determinations of:
§
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 number 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 statement of financial position or 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)


Retained risk
Overview —Our hull and machinery and excess liability insurance program is comprised of commercial market and captive insurance policies that we renew annually on May 1.  We periodically evaluate our insurance limits and self-insured retentions.  As of June 30, 2013, the insured value of our drilling rig fleet was approximately $27.3 billion, excluding our rigs under construction.
We generally do not carry commercial market insurance coverage for loss of revenues, unless it is contractually required, or for losses resulting from physical damage to our fleet caused by named windstorms in the U.S. Gulf of Mexico, including liability for wreck removal expenses . We have elected to self-insure operators extra expense coverage for ADTI.  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 .
Hull and machinery coverage —At June 30, 2013, under the hull and machinery program, we generally maintained a $125 million per occurrence deductible, limited to a maximum of $200 million per policy period.  Subject to the same shared deductible, we also have coverage in an amount equal to 50 percent of a rig’s insured value for combined costs incurred to mitigate damage to a rig and wreck removal.  Any excess wreck removal costs are generally covered to the extent of our remaining excess liability coverage.
Excess liability coverage —At June 30, 2013, we carried $820 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 collision liability claims and (2) separate $5 million per occurrence deductibles on crew personal injury claims and on other third-party non - crew claims.  Through our wholly owned captive insurance company, we have retained the risk of the primary $50 million excess liability coverage.  In addition, we generally retain the risk for any liability losses in excess of $870 million.
Other insurance coverage —At June 30, 2013, we also carried $100 million of additional insurance that generally covers expenses that would otherwise be assumed by the well owner, such as costs to control the well, redrill expenses and pollution from the well.  This additional insurance provides coverage for such expenses in circumstances in which we may have legal or contractual liability arising from our gross negligence or willful misconduct .
Letters of credit and surety bonds
At June 30, 2013 and December 31, 2012, we had outstanding letters of credit totaling $552 million and $522 million, respectively, issued under various committed and uncommitted credit lines provided by several banks to guarantee various contract bidding, performance activities and customs obligations, including letters of credit totaling $102 million and $113 million, respectively, that we agreed to retain in support of the operations for Shelf Drilling (see Note 7—Discontinued Operations).
As is customary in the contract drilling business, we also have various surety bonds in place that secure customs obligations relating to the importation of our rigs and certain performance and other obligations.  At June 30, 2013 and December 31, 2012, we had outstanding surety bonds totaling $8 million and $11 million, respectively .
Note 14—Redeemable Noncontrolling Interest
Through February 29, 2012, Quantum Pacific Management Limited (“Quantum”) had the unilateral right, pursuant to a put option agreement, to exchange its 50 percent interest in TPDI for our shares or cash, at its election, at an amount based on an appraisal of the fair value of the drillships that are owned by TPDI, subject to certain adjustments.  Accordingly, we presented Quantum’s interest as redeemable noncontrolling interest on our consolidated balance sheets until Quantum exercised its rights under the put option agreement.
On February 29, 2012, Quantum exercised its rights under the put option agreement to exchange its interest in TPDI for our shares or cash, at its election.  As a result of the exercised option, we reclassified the carrying amount of Quantum’s interest to other current liabilities and, based on the redemption value as of that date, we adjusted the balance to its estimated fair value at the time of the exercise with a corresponding adjustment of $106 million to retained earnings within shareholders’ equity.  We estimated the fair value of Quantum’s interest using significant other observable inputs, representative of a Level 2 fair value measurement, including indications of market values of the drilling units owned by TPDI.

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TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Changes in redeemable noncontrolling interest were as follows (in millions):
Six months ended
June 3 0,
2012
Redeemable noncontrolling interest
Balance, beginning of period
$
116
Net income attributable to noncontrolling interest
13
Fair value adjustment to redeemable noncontrolling interest
106
Reclassification to accumulated other comprehensive loss
17
Reclassification to other current liabilities
(252
)
Balance, end of period
$
—

On March 29, 2012, Quantum elected to exchange its interest in TPDI for our shares, net of Quantum’s share of TPDI’s indebtedness, as defined in the put option agreement.  Quantum had the right, prior to settlement of this transaction, to change its election to cash, net of Quantum’s share of TPDI’s indebtedness.
Through settlement of the exchange transaction on May 31, 2012, we measured the carrying amount of Quantum’s interest at its estimated fair value resulting in a cumulative adjustment of $25 million to increase the liability with corresponding adjustments to other expense on our condensed consolidated statement of operations.  On May 31, 2012, we issued 8,695,351 shares to Quantum in a non-cash exchange for its interest in TPDI to satisfy our obligation, resulting in an adjustment of $134 million and $233 million to shares and additional paid-in capital, respectively.  The adjustment included the extinguishment of $148 million of TPDI Notes payable to Quantum and accrued and unpaid interest of $16 million.  As a result of this transaction, TPDI became our wholly owned subsidiary.

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TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Note 15—Shareholders’ Equity
Distribution of qualifying additional paid - in capital —In May 2013, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid - in capital in the form of a U.S. dollar denominated dividend of $2 . 24 per outstanding share, payable in four installments of $0.56 per outstanding share, subject to certain limitations.  In May 2013, we recognized a liability of $816 million for the distribution payable, recorded in other current liabilities, with a corresponding entry to additional paid-in capital.  On June 19, 2013, we paid the first installment in the aggregate amount of $204 million to shareholders of record and directors and employees holding unvested deferred units as of May 31, 2013.  At June 30, 2013, the carrying amount of the unpaid distribution payable was $612 million.
In May 2011, at our annual general meeting, our shareholders approved the distribution of additional paid - in capital in the form of a U.S. dollar denominated dividend of $3.16 per outstanding share, payable in four equal installments of $0.79 per outstanding share, subject to certain limitations.  On March 21, 2012, we paid the final installment in the aggregate amount of $278 million to shareholders of record and directors and employees holding unvested deferred units as of February 24, 2012 .
Shares held by subsidiary —One of our subsidiaries holds our shares for future use to satisfy our obligations to deliver shares in connection with awards granted under our incentive plans or other rights to acquire our shares.  At June 30, 2013 and December 31, 2012, our subsidiary held 10.6 million and 11.5 million shares, respectively.
Accumulated other comprehensive loss —For the three and six months ended June 30, 2013 and 2012, the changes in accumulated other comprehensive loss, presented net of tax, were as follows (in millions):
Three months ended June 30, 2013
Three months ended June 30, 2012
Defined benefit pension plans
Derivative instruments
Marketable securities
Total
Defined benefit pension plans
Derivative instruments
Marketable securities
Total
Balance, beginning of period
$
(533
)
$
(7
)
$
—
$
(540
)
$
(517
)
$
(12
)
$
(2
)
$
(531
)
Other comprehensive income (loss) before reclassifications
84
(1
)
—
83
1
(2
)
—
(1
)
Reclassifications to net income
12
11
—
23
10
6
—
16
Other comprehensive income, net
96
10
—
106
11
4
—
15
Balance, end of period
$
(437
)
$
3
$
—
$
(434
)
$
(506
)
$
(8
)
$
(2
)
$
(516
)

Six months ended June 30, 2013
Six months ended June 30, 2012
Defined benefit pension plans
Derivative instruments
Marketable securities
Total
Defined benefit pension plans
Derivative instruments
Marketable securities
Total
Balance, beginning of period
$
(511
)
$
(10
)
$
—
$
(521
)
$
(501
)
$
7
$
(2
)
$
(496)
Reclassification from redeemable noncontrolling interest
—
—
—
—
—
(17
)
—
(17
)
Other comprehensive income (loss) before reclassifications
49
(5
)
—
44
(27
)
(1
)
—
(28
)
Reclassifications to net income
25
18
—
43
22
3
—
25
Other comprehensive income (loss), net
74
13
—
87
(5
)
(15
)
—
(20
)
Balance, end of period
$
(437
)
$
3
$
—
$
(434
)
$
(506
)
$
(8
)
$
(2
)
$
(516
)


-32-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)


Significant reclassifications from accumulated other comprehensive income to net income included the following (in millions):
Statement of operations
Three months ended
June 30,
Six months ended
June 30,
classification
2013
2012
2013
2012
Defined benefit pension plans
Actuarial losses
$
14
$
11
$
28
$
22
Prior service costs
(1
)
(1
)
(1
)
(1
)
Settlements and curtailments
—
—
—
2
Total amortization, before income taxes
Net periodic benefit costs (a)
13
10
27
23
Income tax benefit
Income tax expense
(1
)
—
(2
)
(1
)
Total amortization, net of income taxes
$
12
$
10
$
25
$
22
____________________________________
(a)
We recognize the amortization of accumulated other comprehensive income components related to defined benefit pension plans in net periodic benefit costs.  In the three and six months ended June 30, 2013, the amortization components of our net periodic benefit costs were $10 million and $21 million, recorded in operating and maintenance costs, and $3 million and $6 million, recorded in general and administrative costs, respectively.  In the three and six months ended June 30, 2012, the amortization components of our net periodic benefit costs were $8 million and $17 million, recorded in operating and maintenance costs, and $2 million and $6 million, recorded in general and administrative costs, respectively.  See Note 12—Postemployment Benefit Plans.

Note 16—Financial Instruments
The carrying amounts and fair values of our financial instruments were as follows (in millions):
June 30, 2013
December 31, 2012
Carrying
amount
Fair
value
Carrying
amount
Fair
value
Cash and cash equivalents
$
3,357
$
3,357
$
5,134
$
5,134
Notes and other loans receivable
103
103
142
142
Preference shares
—
—
196
196
Restricted cash investments
695
729
857
903
Long-term debt, including current maturities
10,621
11,630
12,268
13,899
Long-term debt of consolidated variable interest entities, including current maturities
178
178
191
191
Derivative instruments, assets
—
—
8
8
Derivative instruments, liabilities
—
—
15
15

We estimated the fair value of each class of financial instruments, for which estimating fair value is practicable, by applying the following methods and assumptions.
Cash and cash equivalents —The carrying amount of cash and cash equivalents represents the historical cost, plus accrued interest, which approximates fair value because of the short maturities of those instruments.  We measured the estimated fair value of our cash equivalents using significant other observable inputs, representative of a Level 2 fair value measurement, including the net asset values of the investments.  At June 30, 2013 and December 31, 2012, the aggregate carrying amount of our cash equivalents was $2.5 billion and $4.2 billion, respectively.
Notes and other loans receivable —We hold certain notes and other loans receivable, which originated in connection with certain asset dispositions and supplier advances.  The carrying amount represents the amortized cost of our investments, which approximates the estimated fair value.  We measured the estimated fair value using significant unobservable inputs, representative of a Level 3 fair value measurement, including the credit ratings of the borrowers.  At June 30, 2013, the aggregate carrying amount of our notes receivable and other loans receivable was $103 million, including $6 million and $97 million recorded in other current assets and other assets, respectively.  At December 31, 2012, the aggregate carrying amount of our notes receivable and other loans receivable was $142 million, including $35 million and $107 million recorded in other current assets and other assets, respectively.
Preference shares —We held preference shares of one of Shelf Drilling’s parent companies.  The carrying amount of the preference shares represents the historical cost of our investment, as the preference shares do not have a readily determinable fair value.  We measured the estimated fair value of the Shelf Drilling preference shares using significant unobservable inputs, representative of a Level 3 fair value measurement, including the credit ratings and financial position of the investee.  At December 31, 2012, the aggregate carrying amount of the preference shares, excluding the balance associated with the embedded derivatives, was $196 million recorded in other assets.  In June 2013, we sold the preference shares to an unaffiliated party for cash proceeds of $185 million.

-33-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Restricted cash investments —The carrying amount of the Aker Restricted Cash Investments represents the amortized cost of our investment.  We measured the estimated fair value of the Aker Restricted Investments using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads of the instruments.  At June 30, 2013 and December 31, 2012, the aggregate carrying amount of the Aker Restricted Cash Investments was $661 million and $797 million, respectively.  At June 30, 2013 and December 31, 2012, the estimated fair value of the Aker Restricted Cash Investments was $695 million and $843 million, respectively.
The carrying amount of the restricted cash investments for the TPDI Credit Facilities, the ADDCL Credit Facilities and other obligations approximates fair value due to the short term nature of the instruments in which the restricted cash investments are held.  At June 30, 2013, the aggregate carrying amount of the restricted cash investments for the ADDCL Credit Facilities and other obligations was $34 million.  At December 31, 2012, the aggregate carrying amount of the restricted cash investments for the TPDI Credit Facilities, the ADDCL Credit Facilities and other obligations was $60 million.
Debt —We measured the estimated fair value of our fixed - rate debt using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads for the instruments.  At June 30, 2013 and December 31, 2012, the aggregate carrying amount of our fixed-rate debt was $10.6 billion and $11.7 billion, respectively.  At June 30, 2013 and December 31, 2012, the aggregate estimated fair value of our fixed-rate debt was $11.6 billion and $13.3 billion, respectively.
The carrying amount of our variable-rate debt approximates fair value because the terms of those debt instruments include short-term interest rates and exclude penalties for prepayment.  We measured the estimated fair value of our variable-rate debt using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads for the instruments.  At June 30, 2013, we did not have any variable-rate debt.  At December 31, 2012, the aggregate carrying amount of our variable-rate debt was $579 million.
Debt of consolidated variable interest entities —The carrying amount of the variable-rate debt of our consolidated variable interest entities approximates fair value because the terms of those debt instruments include short-term interest rates and exclude penalties for prepayments.  We measured the estimated fair value of the debt of our consolidated variable interest entities using significant other observable inputs, representative of a Level 2 fair value measurement, including the terms and credit spreads of the instruments.  At June 30, 2013 and December 31, 2012, the aggregate carrying amount of the variable-rate debt of our consolidated variable interest entities was $178 million and $191 million, respectively.
Derivative instruments —The carrying amount of our derivative instruments represents the estimated fair value.  We measured the estimated fair value using significant other observable inputs, representative of a Level 2 fair value measurement, including the interest rates and terms of the instruments.
Note 17—Condensed Consolidating Financial Information
Transocean Inc., a wholly owned subsidiary of Transocean Ltd., is the issuer of certain notes and debentures, which have been guaranteed by Transocean Ltd.  Transocean Ltd.’s guarantee of debt securities of Transocean Inc. is full and unconditional.  Transocean Ltd. is not subject to any significant restrictions on its ability to obtain funds by dividends, loans or capital distributions from its consolidated subsidiaries .
The following tables present condensed consolidating financial information for (a) Transocean Ltd. (the “Parent Guarantor”), (b) Transocean Inc. (the “Subsidiary Issuer”), and (c) the other direct and indirect wholly owned and partially owned subsidiaries of the Parent Guarantor, none of which guarantee any indebtedness of the Subsidiary Issuer (the “Other Subsidiaries”).  The tables include the consolidating adjustments necessary to present the condensed financial statements on a consolidated basis .

-34-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)


The condensed consolidating financial information may not necessarily be indicative of the results of operations, financial position or cash flows had the subsidiaries operated as independent entities (in millions):
Three months ended June 30, 2013
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Operating revenues
$
—
$
—
$
2,403
$
(6
)
$
2,397
Cost and expenses
17
1
1,744
(6
)
1,756
Loss on impairment
—
—
(37
)
—
(37
)
Loss on disposal of assets, net
—
—
(2
)
—
(2
)
Operating income (loss)
(17
)
(1
)
620
—
602
Other income (expense), net
Interest expense, net
(3
)
(129
)
(3
)
—
(135
)
Equity in earnings
327
469
—
(796
)
—
Other, net
—
(5
)
(11
)
—
(16
)
324
335
(14
)
(796
)
(151
)
Income from continuing operations before income tax expense
307
334
606
(796
)
451
Income tax expense
—
—
130
—
130
Income from continuing operations
307
334
476
(796
)
321
Gain (loss) from discontinued operations, net of tax
—
(25
)
15
—
(10
)
Net Income
307
309
491
(796
)
311
Net income attributable to noncontrolling interest
—
—
4
—
4
Net income attributable to controlling interest
307
309
487
(796
)
307
Other comprehensive income before income taxes
—
93
14
—
107
Income taxes related to other comprehensive loss
—
—
(1
)
—
(1
)
Other comprehensive income, net  of income taxes
—
93
13
—
106
Total comprehensive income
307
402
504
(796
)
417
Total comprehensive income attributable to noncontrolling interest
—
—
4
—
4
Total comprehensive income attributable to controlling interest
$
307
$
402
$
500
$
(796
)
$
413

Three months ended June 30, 2012
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Operating revenues
$
—
$
—
$
2,335
$
(6
)
$
2,329
Cost and expenses
21
1
2,448
(6
)
2,464
Loss on impairment
—
—
—
—
—
Loss on disposal of assets, net
—
—
(7
)
—
(7
)
Operating loss
(21
)
(1
)
(120
)
—
(142
)
Other income (expense), net
Interest expense, net
(4
)
(139
)
(27
)
—
(170
)
Equity in earnings
(279
)
(186
)
—
465
—
Other, net
—
18
(24
)
—
(6
)
(283
)
(307
)
(51
)
465
(176
)
Loss from continuing operations before income tax expense
(304
)
(308
)
(171
)
465
(318
)
Income tax benefit
—
—
(15
)
—
(15
)
Loss from continuing operations
(304
)
(308
)
(156
)
465
(303
)
Loss from discontinued operations, net of tax
—
—
—
—
—
Net loss
(304
)
(308
)
(156
)
465
(303
)
Net income attributable to noncontrolling interest
—
—
1
—
1
Net loss attributable to controlling interest
(304
)
(308
)
(157
)
465
(304
)
Other comprehensive income before income taxes
1
7
6
—
14
Income taxes related to other comprehensive loss
—
—
1
—
1
Other comprehensive income, net of income taxes
1
7
7
—
15
Total comprehensive loss
(303
)
(301
)
(149
)
465
(288
)
Total comprehensive income attributable to noncontrolling interest
—
—
1
—
1
Total comprehensive loss attributable to controlling interest
$
(303
)
$
(301
)
$
(150
)
$
465
$
(289
)

-35-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)




Six months ended June 30, 2013
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Operating revenues
$
—
$
—
$
4,605
$
(11
)
$
4,594
Cost and expenses
26
5
3,453
(11
)
3,473
Loss on impairment
—
—
(37
)
—
(37
)
Loss on disposal of assets, net
—
—
(9
)
—
(9
)
Operating income (loss)
(26
)
(5
)
1,106
—
1,075
Other income (expense), net
Interest expense, net
(6
)
(266
)
(3
)
—
(275
)
Equity in earnings
660
941
—
(1,601
)
—
Other, net
—
5
(22
)
—
(17
)
654
680
(25
)
(1,601
)
(292
)
Income from continuing operations before income tax expense
628
675
1,081
(1,601
)
783
Income tax expense
—
—
149
—
149
Income from continuing operations
628
675
932
(1,601
)
634
Gain (loss) from discontinued operations, net of tax
—
(55
)
45
—
(10
)
Net Income
628
620
977
(1,601
)
624
Net loss attributable to noncontrolling interest
—
—
(4
)
—
(4
)
Net income attributable to controlling interest
628
620
981
(1,601
)
628
Other comprehensive income (loss) before income taxes
(6
)
72
22
—
88
Income taxes related to other comprehensive loss
—
—
—
—
—
Other comprehensive income (loss), net  of income taxes
(6
)
72
22
—
88
Total comprehensive income
622
692
999
(1,601
)
712
Total comprehensive loss attributable to noncontrolling interest
—
—
(3
)
—
(3
)
Total comprehensive income attributable to controlling interest
$
622
$
692
$
1,002
$
(1,601
)
$
715

Six months ended June 30, 2012
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Operating revenues
$
—
$
—
$
4,450
$
(11
)
$
4,439
Cost and expenses
32
2
4,037
(11
)
4,060
Loss on impairment
—
—
(140
)
—
(140
)
Loss on disposal of assets, net
—
—
(10
)
—
(10
)
Operating income (loss)
(32
)
(2
)
263
—
229
Other income (expense), net
Interest expense, net
(7
)
(273
)
(55
)
—
(335
)
Equity in earnings
(255
)
(16
)
—
271
—
Other, net
—
9
(33
)
—
(24
)
(262
)
(280
)
(88
)
271
(359
)
Income (loss) from continuing operations before income tax expense
(294
)
(282
)
175
271
(130
)
Income tax expense
—
—
19
—
19
Income (loss) from continuing operations
(294
)
(282
)
156
271
(149
)
Loss from discontinued operations, net of tax
—
—
(136
)
—
(136
)
Net income (loss)
(294
)
(282
)
20
271
(285
)
Net income attributable to noncontrolling interest
—
—
9
—
9
Net income (loss) attributable to controlling interest
(294
)
(282
)
11
271
(294
)
Other comprehensive income (loss) before income taxes
(4
)
—
3
—
(1
)
Income taxes related to other comprehensive loss
—
—
(2
)
—
(2
)
Other comprehensive income (loss), net of income taxes
(4
)
—
1
—
(3
)
Total comprehensive income (loss)
(298
)
(282
)
21
271
(288
)
Total comprehensive income attributable to noncontrolling interest
—
—
9
—
9
Total comprehensive income (loss) attributable to controlling interest
$
(298
)
$
(282
)
$
12
$
271
$
(297
)

-36-

TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



June 30, 2013
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Assets
Cash and cash equivalents
$
1
$
1,692
$
1,664
$
—
$
3,357
Other current assets
8
2,298
3,514
(2,311
)
3,509
Total current assets
9
3,990
5,178
(2,311
)
6,866
Property and equipment, net
—
—
21,056
—
21,056
Goodwill
—
—
2,987
—
2,987
Investment in affiliates
17,142
28,684
—
(45,826
)
—
Other assets
—
1,993
18,586
(19,273
)
1,306
Total assets
17,151
34,667
47,807
(67,410
)
32,215
Liabilities and equity
Debt due within one year
—
—
191
—
191
Other current liabilities
629
473
4,813
(2,311
)
3,604
Total current liabilities
629
473
5,004
(2,311
)
3,795
Long-term debt
801
17,734
11,346
(19,273
)
10,608
Other long-term liabilities
39
365
1,744
—
2,148
Total long-term liabilities
840
18,099
13,090
(19,273
)
12,756
Commitments and contingencies
Total equity
15,682
16,095
29,713
(45,826
)
15,664
Total liabilities and equity
$
17,151
$
34,667
$
47,807
$
(67,410
)
$
32,215

December 31, 2012
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Assets
Cash and cash equivalents
$
24
$
3,155
$
1,955
$
—
$
5,134
Other current assets
7
1,901
3,852
(2,247
)
3,513
Total current assets
31
5,056
5,807
(2,247
)
8,647
Property and equipment, net
—
—
20,880
—
20,880
Goodwill
—
—
2,987
—
2,987
Investment in affiliates
16,354
27,933
—
(44,287
)
—
Other assets
—
1,804
18,244
(18,307
)
1,741
Total assets
16,385
34,793
47,918
(64,841
)
34,255
Liabilities and equity
Debt due within one year
—
564
803
—
1,367
Other current liabilities
13
632
5,698
(2,247
)
4,096
Total current liabilities
13
1,196
6,501
(2,247
)
5,463
Long-term debt
594
17,772
11,033
(18,307
)
11,092
Other long-term liabilities
33
454
1,483
—
1,970
Total long-term liabilities
627
18,226
12,516
(18,307
)
13,062
Commitments and contingencies
Total equity
15,745
15,371
28,901
(44,287
)
15,730
Total liabilities and equity
$
16,385
$
34,793
$
47,918
$
(64,841
)
$
34,255

-37-
TRANSOCEAN LTD. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—continued
(Unaudited)



Six months ended June 30, 2013
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Cash flows from operating activities
$
(26
)
$
(340
)
$
888
$
—
$
522
Cash flows from investing activities
Capital expenditures
—
—
(840
)
—
(840
)
Proceeds from disposal of assets, net
—
—
4
—
4
Proceeds from disposal of discontinued operations, net
—
—
63
—
63
Proceeds from sale of preference shares
—
185
—
—
185
Investing activities with affiliates, net
—
(700
)
(204
)
904
—
Other, net
—
—
12
—
12
Net cash used in investing activities
—
(515
)
(965
)
904
(576
)
Cash flows from financing activities
Repayments of debt
—
(562
)
(1,034
)
—
(1,596
)
Proceeds from restricted cash investments
—
—
206
—
206
Deposits to restricted cash investments
—
—
(104
)
—
(104
)
Distribution of qualifying additional paid-in capital
(204
)
—
—
—
(204
)
Financing activities with affiliates, net
207
(33
)
730
(904
)
—
Other, net
—
(13
)
(12
)
—
(25
)
Net cash provided by (used in) financing activities
3
(608
)
(214
)
(904
)
(1,723
)
Net decrease in cash and cash equivalents
(23
)
(1,463
)
(291
)
—
(1,777
)
Cash and cash equivalents at beginning of period
24
3,155
1,955
—
5,134
Cash and cash equivalents at end of period
$
1
$
1,692
$
1,664
$
—
$
3,357

Six months ended June 30, 2012
Parent
Guarantor
Subsidiary
Issuer
Other
Subsidiaries
Consolidating
adjustments
Consolidated
Cash flows from operating activities
$
(31
)
$
(570
)
$
1,600
$
—
$
999
Cash flows from investing activities
Capital expenditures
—
—
(445
)
—
(445
)
Capital expenditures for discontinued operations
—
—
(51
)
—
(51
)
Proceeds from disposal of assets, net
—
—
8
—
8
Proceeds from disposal of assets in discontinued operations, net
—
—
194
—
194
Investing activities with affiliates, net
—
(1,816
)
(2,269
)
4,085
—
Other, net
—
19
6
—
25
Net cash used in investing activities
(1,797
)
(2,557
)
4,085
(269
)
Cash flows from financing activities
Change in short-term borrowings, net
—
—
(260
)
—
(260
)
Repayments of debt
—
(30
)
(290
)
—
(320
)
Proceeds from restricted cash investments
—
—
192
—
192
Deposits to restricted cash investments
—
—
(116
)
—
(116
)
Distribution of qualifying additional paid-in capital
(278
)
—
—
—
(278
)
Financing activities with affiliates, net
325
1,819
1,941
(4,085
)
—
Other, net
—
(9
)
8
—
(1
)
Net cash provided by (used in) financing activities
47
1,780
1,475
(4,085
)
(783
)
Net increase (decrease) in cash and cash equivalents
16
(587
)
518
—
(53
)
Cash and cash equivalents at beginning of period
3
2,793
1,221
—
4,017
Cash and cash equivalents at end of period
$
19
$
2,206
$
1,739
$
—
$
3,964


-38-

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, claims, settlement and related matters,
§
the impact of the Brazil Frade field incident and related matters,
§
our results of operations and cash flow from operations, including revenues and expenses,
§
the offshore drilling market, including the impact of enhanced regulations in the jurisdictions in which we operate, supply and demand, utilization rates, dayrates, customer drilling programs, commodity prices, stacking of rigs, reactivation of rigs, effects of new rigs on the market and effects of declines in commodity prices and 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,
§
liquidity and adequacy of cash flows for our obligations,
§
debt levels, including impacts of a financial and economic downturn,
§
uses of excess cash, including the payment of dividends and other distributions and debt retirement,
§
newbuild, upgrade, shipyard and other capital projects, including completion, delivery and commencement of operation dates, expected downtime and lost revenue, the level of expected capital expenditures and the timing and cost of completion of capital projects,
§
the cost and timing of acquisitions and the proceeds and timing of dispositions,
§
the results and timing of our organizational efficiency initiative, including related costs and expenses,
§
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 United States (“U.S.”),
§
legal and regulatory matters, including results and effects of legal proceedings and governmental audits and assessments, outcomes and effects of internal and governmental investigations, customs and environmental matters,
§
insurance matters, including adequacy of insurance, renewal of insurance, insurance proceeds and cash investments of our wholly owned captive insurance company,
§
effects of accounting changes and adoption of accounting policies, and
§
investments in recruitment, retention and personnel development initiatives, pension plan and other postretirement benefit plan contributions, the timing of severance payments and benefit payments.
Forward - looking statements in this quarterly report are identifiable by use of the following words and other similar expressions:
§ “anticipates”
§ “could”
§ “forecasts”
§ “might”
§ “projects”
§ “believes”
§ “estimates”
§ “intends”
§ “plans”
§ “scheduled”
§ “budgets”
§ “expects”
§ “may”
§ “predicts”
§ “should”
Such statements are subject to numerous risks, uncertainties and assumptions, including, but not limited to:
§
those described under “Item 1A. Risk Factors” included in our annual report on Form 10-K for the year ended December 31, 2012, and those described under “Item 1A. Risk Factors” in Part II of this report,
§
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,
§
operational performance,
§
the impact of regulatory changes,
§
the cancellation of contracts currently included in our reported contract backlog,
§
shipyard, construction and other delays,
§
increased political and civil unrest,
§
the results of the upcoming annual general meeting of our shareholders,
§
the effect and results of litigation, regulatory matters, settlements, audits, assessments and contingencies, and
§
other factors discussed in this quarterly report and in our other filings with the U.S. Securities and Exchange Commission (“SEC”), which are available free of charge on the SEC website at www.sec.gov .
The foregoing risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements.  Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated.  All subsequent written and oral forward - looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties.  You should not place undue reliance on forward - looking statements.  Each forward - looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward - looking statements, except as required by law .

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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.  As of July 30, 2013, we owned or had partial ownership interests in and operated 80 mobile offshore drilling units associated with our continuing operations.  As of July 30, 2013, our fleet consisted of 46 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 23 Midwater Floaters, and 11 High-Specification Jackups.  At July 30, 2013, we also had six Ultra-Deepwater drillships and one High-Specification Jackup under construction or under contract to be constructed.
We have two operating segments: (1) contract drilling services and (2) drilling management services.  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 specialize in technically demanding regions of the offshore drilling business with a particular focus on deepwater and harsh environment drilling services.  We believe our drilling fleet is one of the most versatile fleets in the world, consisting of floaters and high-specification jackups used in support of offshore drilling activities and offshore support services on a worldwide basis .
Our contract drilling 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.
In November 2012, in connection with our efforts to dispose of non-strategic assets and to reduce our exposure to low-specification drilling units, we completed the sale of 38 drilling units to Shelf Drilling Holdings, Ltd. (together with its affiliates, “Shelf Drilling”).  See Notes to Condensed Consolidated Financial Statements—Note 7—Discontinued Operations.
Our drilling management services segment 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.  We provide drilling management services outside of the U.S. through Applied Drilling Technology Inc., our wholly owned subsidiary, and ADT International, a division of one of our United Kingdom (“U.K.”) subsidiaries (together, “ADTI”) .
Significant Events
Distribution of qualifying additional paid-in capital —In May 2013, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid - in capital in the form of a U.S. dollar denominated dividend of $2 . 24 per outstanding share, payable in four installments, subject to certain limitations.  In May 2013, we recognized a liability of $816 million for the distribution payable , recorded in other current liabilities, with a corresponding entry to additional paid-in capital.  On June 19, 2013, we paid the first installment in the aggregate amount of $204 million to shareholders of record and holders of participating shares as of May 31, 2013.  See “—Liquidity and Capital Resources—Sources and uses of liquidity”.
Organizational efficiency initiative —During the six months ended June 30, 2013, we committed to a plan to improve the organizational efficiency of our shore-based support activities worldwide.  We believe this organizational efficiency initiative will result in our achieving significant annualized savings in future periods associated with the streamlining of certain shore-based business functions and processes and the elimination of certain processes, programs and tasks that we do not consider central to supporting our core business.  See “—Outlook—Organizational efficiency initiative.”
Macondo well incident —On January 3, 2013, we reached an agreement with the U.S. Department of Justice (the “DOJ”) to resolve certain outstanding civil and potential criminal charges against us arising from the Macondo well incident . As part of this resolution, we agreed to pay $1.4 billion in fines, recoveries and penalties, plus interest, in scheduled payments over a five-year period through 2017.  See “—Contingencies—Macondo well incident.”
Debt repayment —In June 2013, we repaid the $735 million of borrowings outstanding under the TPDI Credit Facilities and terminated the TPDI Credit Facilities.
On March 6, 2013, we redeemed the FRN Aker Drilling ASA Senior Unsecured Callable Bond Issue 2011/2016 (the “FRN Callable Bonds”) and the 11% Aker Drilling ASA Senior Unsecured Callable Bond Issue 2011/2016 (the “11% Callable Bonds,” and together with the FRN Callable Bonds, the “Callable Bonds”), with the aggregate outstanding principal amounts of NOK 940 million and NOK 560 million, equivalent to $164 million and $98 million, respectively, using an exchange rate of NOK 5.73 to $1.00.  In connection with the redemption, we made an aggregate cash payment of NOK 1,567 million, equivalent to $273 million.

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On February 7, 2013, we redeemed the remaining $62 million aggregate principal amount of the Series C Convertible Senior Notes for an aggregate cash payment of $62 million.
During the six months ended June 30, 2013, we repaid the outstanding $250 million and $500 million aggregate principal amount of the 5% Notes due February 2013 and the 5.25% Senior Notes due March 2013, respectively, as of the stated maturity dates.
See “—Liquidity and Capital Resources—Sources and uses of liquidity.”
Fleet expansion —During the six months ended June 30, 2013, we completed construction of the High-Specification Jackups Transocean Andaman and Transocean Siam Driller , which have commenced operations under their contracts.  See “—Liquidity and Capital Resources—Sources and uses of liquidity.”
Dispositions —Subsequent to June 30, 2013, in connection with our efforts to dispose of non-strategic assets, we entered into agreements to sell the Deepwater Floaters Sedco 709 and Transocean Richardson and the Midwater Floaters C. Kirk Rhein, Jr. and Sedco 703 .  See "—Liquidity and Capital Resources—Drilling fleet."
Shelf Drilling preference shares —In June 2013, we completed the sale of the Shelf Drilling preference shares and received cash proceeds of $185 million and recognized a loss of $10 million associated with the sale.
Discontinued operations —During the six months ended June 30, 2013, we completed the sales of D.R. Stewart , GSF Adriatic VIII and Interocean III along with related equipment.  In connection with the sales of these assets, we received aggregate cash proceeds of $63 million, and we recognized an aggregate net gain of $15 million.  See “—Operating Results—Discontinued operations.”
Outlook
Drilling market —We expect the commodity pricing underlying the exploration and production programs of our customers to continue to support contracting opportunities for all asset classes within our drilling fleet in the year ending December 31, 2013.  As of July 17, 2013, the contract backlog for our continuing operations was $27.3 billion compared to $28.5 billion as of April 18, 2013.
Following the Macondo well incident, the U.S. government implemented enhanced regulations related to offshore drilling in the U.S. Gulf of Mexico, which require operators to submit applications for new drilling permits that demonstrate compliance with such enhanced regulations.  The enhanced regulations require independent third-party inspection, certification of well design and well control equipment and emergency response plans in the event of a blowout, among other requirements.  The voluntary application by some of our customers of such third-party inspections and certifications of well control equipment operating outside the U.S. Gulf of Mexico has caused and may continue to cause us to experience additional out of service time and incur additional maintenance costs.  We have entered into a consent decree with the DOJ that also requires us to undertake certain inspections and certifications beyond current legal standards.  Although the enhanced regulations and additional maintenance requirements have affected our revenues, costs and out of service time, we are unable to predict, with certainty, the magnitude with which these matters will continue to impact our operations.
Fleet status —As of July 17 , 2013, uncommitted fleet rates for the remainder of 2013, 2014, 2015, 2016 and 2017 were as follows:
2013
2014
2015
2016
2017
Uncommitted fleet rate (a)
High-Specification Floaters
10
%
34
%
62
%
75
%
84
%
Midwater Floaters
28
%
38
%
61
%
93
%
100
%
High-Specification Jackups
17
%
35
%
61
%
78
%
83
%
____________________________________
(a)
The uncommitted fleet rate is defined as the number of uncommitted days divided by the total number of available rig calendar days in the measurement period, expressed as a percentage.  An uncommitted day is defined as a calendar day during which a rig is idle or stacked, is not contracted to a customer and is not committed to a shipyard.
As of July 17, 2013, we had seven existing contracts associated with our continuing operations that had fixed - price or capped options to extend the contract terms that are exercisable, at the customer’s discretion, any time through their expiration dates.  Customers are more likely to exercise fixed-price options when dayrates are higher on new contracts relative to existing contracts, and customers are less likely to exercise fixed-price options when dayrates are lower on new contracts relative to existing contracts.  Given current market conditions, we are uncertain whether these options will be exercised by our customers in 2013.  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.

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High - Specification Floaters —During the second quarter of 2013, 19 contracts for Ultra-Deepwater Floaters were entered into worldwide, including four contracts and one extension of an existing contract for our fleet.  Our Ultra-Deepwater Floater fleet has three units with remaining availability in 2013.  We expect continued customer demand for the Ultra-Deepwater Fleet to support high rig utilization rates and provide opportunities to absorb the near-term supply in 2013.  The Deepwater Floater fleet rig utilization rate for the industry improved slightly during the second quarter of 2013 with 11 contracts entered into worldwide, including two contracts for our Deepwater Floater fleet.  Our Deepwater Floater fleet has four units with remaining availability in 2013.  The pace of tendering continues to be steady, and we are in active discussions with our customers for certain units that are available in 2013.  As of July 17, 2013, we had 38 of our 46 High-Specification Floaters contracted through the end of 2013.  Although we believe continued exploration successes in the major deepwater offshore provinces and the emerging markets will generate additional demand and support our long - term positive outlook for our High-Specification Floater fleet, we expect to see a flattening of dayrates and more competition for term opportunities in the short term.
Midwater Floaters —Customer demand for our Midwater Floater fleet, which includes 23 semisubmersible rigs, has continued to increase in the U.K. and Norway with multiple customers interested in available rigs.  We entered into four contracts for our Midwater Floater fleet in the second quarter of 2013.  Based on the customer demand, we continue to believe that we could have new opportunities to extend the contracts on our active fleet available in 2013 and 2014 and return one currently idle Midwater Floater to work in the U.K.  The tendering pace and expected demand outside of the U.K. and Norway has slowed, notably in Brazil, which could have an impact on global utilization and dayrates for this asset class in 2013.
High-Specification Jackups —Our High-Specification Jackup fleet continues to benefit from the interest of our customers, evidenced by one drilling contract signed in the second quarter of 2013.  We believe that the currently high rig utilization rates will continue to prevail and increased tendering and contracting activity to continue through 2013 and into 2014.  As of July 17, 2013, two of our existing 11 High-Specification Jackups had availability in 2013.
Operating results —We expect our total revenues for the year ending December 31, 2013 to be higher than our total revenues for the year ended December 31, 2012, primarily due to increased dayrates, fewer expected out of service and idle days and increased drilling activity associated with our four newbuild High-Specification Jackups placed or to be placed into service in 2012 and 2013.  We are unable to predict, with certainty, the full impact that the enhanced regulations and other matters, described under “—Drilling market”, will have on our operations for the year ending December 31, 2013 and beyond.
After adjusting for loss contingencies recognized in the year ended December 31, 2012, we expect our total operating and maintenance expenses for the year ending December 31, 2013 to be higher than our total operating and maintenance expenses for the year ended December 31, 2012, primarily due to higher costs and expenses for normal inflationary trends for personnel, maintenance and other operating costs, increased shipyard costs and increased drilling activity associated with our four newbuild High-Specification Jackups placed or to be placed into service in 2012 and 2013.  Our projected operating and maintenance expenses for the year ending December 31, 2013 are subject to change and could be affected by actual activity levels, changes in shipyard timing, rig reactivations, duration of organizational efficiency initiative, the enhanced regulations and other matters described under “—Drilling market”, the Macondo well incident and related contingencies, exchange rates and cost inflation above expectations, as well as other factors.
Although we are unable to estimate the full direct and indirect effect that the Macondo well incident will have on our business, the incident has had and could continue to have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows.  See “—Contingencies—Macondo well incident.”
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.  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 unfavorable changes to actual or anticipated dayrates or other impairment indicators, we may be required to recognize losses in future periods as a result of impairments of the carrying amount of one or more of our asset groups.  At June 30, 2013, the carrying amount of our property and equipment was $21.1 billion, representing 65 percent of our total assets.  See “—Critical Accounting Policies and Estimates.”
Organizational efficiency initiative —During the six months ended June 30, 2013, we committed to a plan to improve the organizational efficiency of our shore-based support activities worldwide.  We believe this organizational efficiency initiative will result in our achieving significant annualized savings in future periods associated with the streamlining of certain shore-based business functions and processes and the elimination of certain processes, programs and tasks that we do not consider central to supporting our core business.  We have identified certain shore-based positions that will be eliminated as a result of the initiative.  We do not expect to realize a material benefit from the organizational efficiency initiative in the year ending December 31, 2013, as any reduction in costs is expected to be at least partially offset by restructuring costs and expenses recognized in the period.
In connection with this initiative, we established certain one-time termination benefit plans for shore-based employees in the U.S. and the U.K. and for shore-based expatriate resident employees worldwide that were or are expected to be involuntarily terminated during the period from May 2013 through December 31, 2014.  In the three and six months ended June 30, 2013, we recognized $10 million of expense associated with severance-related costs under these one-time termination benefit plans.

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Additionally, in the three and six months ended June 30, 2013, we recognized $10 million of costs associated with previously established compensatory plans that offer end of service arrangements and the accelerated recognition for share-based compensation costs under our long-term incentive plan.  In connection with our organizational efficiency initiative, in the second half of the year ending December 31, 2013, we expect to incur approximately $30 million of incremental costs associated with one-time termination benefit plans, other severance-related compensation, accelerated share-based compensation under our long-term incentive plan and the termination of executory agreements related to closing certain shore-based facilities.  We could recognize additional costs associated with our organizational efficiency initiative as we implement further restructuring activities in the years ending December 31, 2013 and 2014.
Performance and Other Key Indicators
Contract backlog —The contract backlog for our contract drilling services segment was as follows:
July 17,
2013
April 18,
2013
February 14,
2013
Contract backlog (a)
(in millions)
High-Specification Floaters
Ultra-Deepwater Floaters
$
18,788
$
19,201
$
19,144
Deepwater Floaters
1,758
1,970
2,127
Harsh Environment Floaters
1,563
1,968
1,942
Total High-Specification Floaters
22,109
23,139
23,213
Midwater Floaters
3,862
3,895
4,145
High-Specification Jackups
1,306
1,445
1,486
Total
$
27,277
$
28,479
$
28,844
____________________________________
(a)
Contract backlog is defined as the maximum contractual operating dayrate multiplied by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions, which are not expected to be significant to our contract drilling revenues.
The contract backlog represents the maximum contract drilling revenues that can be earned considering the contractual operating dayrate in effect during the firm contract period and represents the basis for the maximum revenues in our revenue efficiency measurement.  To determine maximum revenues for purposes of calculating revenue efficiency, however, we include the revenues earned for mobilization, demobilization and contract preparation, which are excluded from the amounts presented for contract backlog.
Our contract backlog includes only firm commitments for our contract drilling services segment, which are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution.  Our contract backlog includes amounts associated with our newbuild units that are currently under construction.  The contractual operating dayrate may be higher than the actual dayrate we ultimately receive or an alternative contractual dayrate, such as a waiting-on-weather rate, repair rate, standby rate or force majeure rate, may apply under certain circumstances.  The contractual operating dayrate may also be higher than the actual dayrate we ultimately receive because of a number of factors, including rig downtime or suspension of operations.  In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.
Average daily revenue —The average daily revenue for our contract drilling services segment was as follows:
Three months ended
June 30,
2013
March 31,
2013
June 30,
2012
Average daily revenue (a)
High - Specification Floaters
Ultra - Deepwater Floaters
$
507,600
$
457,800
$
493,200
Deepwater Floaters
351,800
327,600
353,300
Harsh Environment Floaters
447,500
454,400
424,500
Total High - Specification Floaters
464,200
429,900
448,600
Midwater Floaters
301,100
291,800
265,700
High - Specification Jackups
165,800
163,000
132,900
Total fleet average daily revenue
382,900
361,200
371,000
____________________________________
(a)
Average daily revenue is defined as contract drilling revenues earned per operating day.  An operating day is defined as a calendar day during which a rig is contracted to earn a dayrate during the firm contract period after commencement of operations.

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Our average daily revenue fluctuates relative to market conditions and revenue efficiency.  Our total fleet average daily revenue is also affected by the mix of rig classes being operated, as Midwater Floaters and High-Specification Jackups are typically contracted at lower dayrates compared to High-Specification Floaters.  We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We remove rigs from the calculation upon disposal or classification as held for sale.
Revenue efficiency —The revenue efficiency rates for our contract drilling services segment were as follows:
Three months ended
June 30,
2013
March 31,
2013
June 30,
2012
Revenue efficiency (a)
High - Specification Floaters
Ultra - Deepwater Floaters
91
%
84
%
92
%
Deepwater Floaters
92
%
86
%
95
%
Harsh Environment Floaters
98
%
98
%
98
%
Total High - Specification Floaters
92
%
86
%
94
%
Midwater Floaters
95
%
92
%
88
%
High - Specification Jackups
99
%
96
%
94
%
Total fleet average revenue efficiency
93
%
88
%
93
%
____________________________________
(a)
Revenue efficiency is defined as actual contract drilling revenues for the measurement period divided by the maximum revenue calculated for the measurement period, expressed as a percentage.  Maximum revenue is defined as the greatest amount of contract drilling revenues the drilling unit could earn for the measurement period, excluding amounts related to incentive provisions.

Our revenue efficiency rate varies due to revenues earned under alternative contractual dayrates, such as a waiting-on-weather rate, repair rate, standby rate , force majeure rate or zero rate, that may apply under certain circumstances.  We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We exclude rigs that are not operating under contract, such as those that are stacked.
Rig utilization —The rig utilization rates for our contract drilling services segment were as follows:
Three months ended
June 30,
2013
March 31,
2013
June 30,
2012
Rig utilization (a)
High - Specification Floaters
Ultra - Deepwater Floaters
96
%
94
%
94
%
Deepwater Floaters
64
%
62
%
64
%
Harsh Environment Floaters
100
%
99
%
98
%
Total High - Specification Floaters
88
%
86
%
85
%
Midwater Floaters
56
%
65
%
58
%
High - Specification Jackups
100
%
92
%
88
%
Total fleet average utilization
80
%
80
%
77
%
____________________________________
(a)
Rig utilization is defined as the total number of operating days divided by the total number of available rig calendar days in the measurement period, expressed as a percentage.
Our rig utilization declines as a result of idle and stacked rigs and during shipyard and mobilization periods to the extent these rigs are not earning revenues . We include newbuilds in the calculation when the rigs commence operations upon acceptance by the customer.  We remove rigs from the calculation upon disposal or classification as held for sale.

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Operating Results
Three months ended June 30, 2013 compared to three months ended June 30, 2012
The following is an analysis of our operating results.  See “—Performance and Other Key Indicators” for a definition of operating days, average daily revenue, revenue efficiency and rig utilization.
Three months ended June 30,
2013
2012
Change
% Change
(In millions, except day amounts and percentages)
Operating days
6,043
5,829
214
4
%
Average daily revenue
$
382,900
$
371,000
$
11,900
3
%
Revenue efficiency
93
%
93
%
Rig utilization
80
%
77
%
Contract drilling revenues
$
2,321
$
2,174
$
147
7
%
Other revenues
76
155
(79
)
(51
)%
2,397
2,329
68
3
%
Operating and maintenance expense
(1,393
)
(2,105
)
712
(34
)%
Depreciation
(286
)
(280
)
(6
)
2
%
General and administrative expense
(77
)
(79
)
2
(3
)%
Loss on impairment
(37
)
—
(37
)
n/m
Loss on disposal of assets, net
(2
)
(7
)
5
(71
)%
Operating income (loss)
602
(142
)
744
n/m
Other income (expense), net
Interest income
11
13
(2
)
(15
)%
Interest expense, net of amounts capitalized
(146
)
(183
)
37
(20
)%
Other, net
(16
)
(6
)
(10
)
n/m
Income (loss) from continuing operations before income tax expense
451
(318
)
769
n/m
Income tax benefit (expense)
(130
)
15
(145
)
n/m
Income (loss) from continuing operations
321
(303
)
624
n/m
Loss from discontinued operations, net of tax
(10
)
—
(10
)
n/m
Net income (loss)
311
(303
)
614
n/m
Net income attributable to noncontrolling interest
4
1
3
n/m
Net income (loss) attributable to controlling interest
$
307
$
(304
)
$
611
n/m
____________________________________
“n/m” means not meaningful
Operating revenues —Contract drilling revenues increased for the three months ended June 30, 2013 compared to the three months ended June 30, 2012 primarily due to the following:  (a) approximately $90 million of increased revenues due to improved dayrates, (b) approximately $70 million of increased revenues due to greater rig utilization caused by less time dedicated to shipyard projects, (c) approximately $25 million of increased revenues associated with our newbuild High-Specification Jackups that commenced operations in the year ended December 31, 2012 and the six months ended June 30, 2013 and (d) approximately $10 million of increased revenues due to improved revenue efficiency in the three months ended June 30, 2013.  These increases were partially offset by approximately $45 million of decreased revenues due to reduced rig utilization caused by increased rig idle time in the three months ended June 30, 2013 compared to the three months ended June 30, 2012.
Other revenues decreased for the three months ended June 30, 2013 compared to the three months ended June 30, 2012, primarily due to reduced activity of our drilling management services.

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Costs and expenses —Excluding the loss of $750 million associated with contingencies related to the Macondo well incident recognized in the three months ended June 30, 2012, operating and maintenance expense increased for the three months ended June 30, 2013 compared to the three months ended June 30, 2012 primarily due to the following: (a) approximately $80 million of increased costs and expenses due to greater rig utilization and (b) approximately $15 million of increased costs and expenses associated with our newbuild High-Specification Jackups that commenced operations in the year ended December 31, 2012 and the six months ended June 30, 2013.  These increases were partially offset by approximately $80 million of decreased costs and expenses associated with reduced activity of our drilling management services.
In the three months ended June 3 0 , 2013, we recognized an aggregate loss of $37 million associated with the impairment of the Deepwater Floater Sedco 709 and the Midwater Floaters C. Kirk Rhein, Jr. and Sedco 703, all of which were classified as assets held for sale at the time of impairment.
Other income and expense —Interest expense, net of amounts capitalized, decreased in the three months ended June 30, 2013 compared to the three months ended June 30, 2012, primarily due to $45 million of decreased interest expense associated with debt repaid or repurchased subsequent to the three months ended June 30, 2012, partially offset by $12 million of increased interest expense associated with debt issued subsequent to the three months ended June 30, 2012.
In the three months ended June 30, 2013, we recognized $16 million in other expense, net primarily due to the following: (a) a loss of $10 million associated with the sale of the Shelf Drilling preference shares, (b) a loss of $9 million associated with the termination of the interest rate swaps related to the TPDI Credit Facilities and (c) a loss of $1 million associated with the repayment of borrowings under and the termination of the TPDI Credit Facilities.
Income tax expense —We operate internationally and provide for income taxes based on the tax laws and rates in the countries in which we operate and earn income.  At June 30, 2013 and 2012, the annual effective tax rates were 23.5 percent and 28.3 percent, respectively, based on income from continuing operations before income taxes, after excluding certain items, such as losses on impairment, and gains and losses on certain asset disposals.  The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits.  For the three months ended June 30, 2013 and 2012, the effect of the various discrete period tax items was a net tax expense of $11 million and a net tax benefit of $141 million, respectively.  For the three months ended June 30, 2013 and 2012, these discrete tax items, coupled with the excluded income and expense items noted above, resulted in effective tax rates of 28.8 percent and 4.7 percent, respectively, based on income from continuing operations before income taxes .
The relationship between our provision for or benefit from income taxes and our income before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures.  Generally, our annual marginal tax rate is lower than our annual effective tax rate.  Consequently, our income tax expense does not change proportionally with our income before income taxes.  Significant decreases in our income before income taxes typically lead to higher effective tax rates, while significant increases in income before income taxes can lead to lower effective tax rates, subject to the other factors impacting income tax expense noted above.  With respect to the annual effective tax rate calculation for the three months ended June 30, 2013, a significant portion of our income tax expense was generated in countries in which income taxes are imposed on gross revenues, with the most significant of these countries being Angola, India, Nigeria, Indonesia, and Congo.  Conversely, the most significant countries in which we incurred income taxes during this period that were based on income before income tax include Norway, the U.K., Switzerland, Brazil and the U.S .
Our rig operating structures further complicate our tax calculations, especially in instances where we have more than one operating structure for the particular taxing jurisdiction and, thus, more than one method of calculating taxes depending on the operating structure utilized by the rig under the contract.  For example, two rigs operating in the same country could generate significantly different provisions for income taxes if they are owned by two different subsidiaries that are subject to differing tax laws and regulations in the respective country of incorporation.

-46-


Six months ended June 30, 2013 compared to six months ended June 30, 2012
The following is an analysis of our operating results.  See “—Performance and Other Key Indicators” for a definition of operating days, average daily revenue, revenue efficiency and rig utilization.
Six months ended June 30,
2013
2012
Change
% Change
(In millions, except day amounts and percentages)
Operating days
11,958
11,417
541
5
%
Average daily revenue
$
372,200
$
364,900
$
7,300
2
%
Revenue efficiency
91
%
91
%
Rig utilization
80
%
76
%
Contract drilling revenues
$
4,466
$
4,188
$
278
7
%
Other revenues
128
251
(123
)
(49
)%
4,594
4,439
155
3
%
Operating and maintenance expense
(2,768
)
(3,347
)
579
(17
)%
Depreciation
(561
)
(565
)
4
(1
)%
General and administrative expense
(144
)
(148
)
4
(3
)%
Loss on impairment
(37
)
(140
)
103
(74
)%
Loss on disposal of assets, net
(9
)
(10
)
1
(10
)%
Operating income
1,075
229
846
n/m
Other income (expense), net
Interest income
28
28
—
n/m
Interest expense, net of amounts capitalized
(303
)
(363
)
60
(17
)%
Other, net
(17
)
(24
)
7
(29
)%
Income (loss) from continuing operations before income tax expense
783
(130
)
913
n/m
Income tax expense
(149
)
(19
)
(130
)
n/m
Income (loss) from continuing operations
634
(149
)
783
n/m
Loss from discontinued operations, net of tax
(10
)
(136
)
126
(93
)%
Net income (loss)
624
(285
)
909
n/m
Net income (loss) attributable to noncontrolling interest
(4
)
9
(13
)
n/m
Net income (loss) attributable to controlling interest
$
628
$
(294
)
$
922
n/m
____________________________________
“n/m” means not meaningful
Operating revenues —Contract drilling revenues increased for the six months ended June 30, 2013 compared to the six months ended June 30, 2012 primarily due to the following: (a) approximately $300 million of increased revenues due to greater rig utilization caused by less time dedicated to shipyard projects and rig certifications, (b) approximately $80 million of increased revenues due to improved dayrates and (c) approximately $40 million of increased revenues associated with our newbuild High-Specification Jackups that commenced operations in the year ended December 31, 2012 and the six months ended June 30, 2013.  This increase was partially offset by (a) approximately $110 million of decreased revenues due to reduced rig utilization caused by increased rig idle time in the six months ended June 30, 2013 and (b) approximately $20 million of decreased contract drilling revenues due to lower revenue efficiency in the six months ended June 30, 2013, compared to the six months ended June 30, 2012.
Other revenues decreased for the six months ended June 30, 2013 compared to the six months ended June 30, 2012, primarily due to reduced activity of our drilling management services.
Costs and expenses —Excluding the loss of $750 million associated with contingencies related to the Macondo well incident recognized in the six months ended June 30, 2012, operating and maintenance expense increased for the six months ended June 3 0 , 2013 compared to the six months ended June 30, 2012 primarily due to the following: (a) approximately $180 million of increased costs and expenses due to greater rig utilization and (b) approximately $25 million of increased costs and expenses associated with our newbuild High-Specification Jackups that commenced operations in the year ended December 31, 2012 and the six months ended June 30, 2013.  These increases were partially offset by approximately $110 million of decreased costs and expenses associated with reduced activity of our drilling management services.

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In the six months ended June 3 0 , 2013, we recognized an aggregate loss of $37 million associated with the impairment of the Deepwater Floater Sedco 709 and the Midwater Floaters C. Kirk Rhein, Jr. and Sedco 703 , all of which were classified as assets held for sale at the time of impairment.
Other income and expense —Interest expense, net of amounts capitalized, decreased in the six months ended June 30, 2013 compared to the six months ended June 30, 2012, primarily due to $72 million of decreased interest expense associated with debt repaid or repurchased subsequent to the three months ended June 30, 2012, and $12 million of increased capitalized interest associated with our newbuild construction program, partially offset by $25 million of increased interest expense associated with debt issued subsequent to June 30, 2012.
In the six months ended June 30, 2013, we recognized $17 million in other expense, net primarily related to the following: (a) a loss of $10 million associated with the sale of the Shelf Drilling preference shares, (b) a loss of $9 million associated with the termination of the interest rate swaps related to the TPDI Credit Facilities and (c) a loss of $2 million associated with the redemption of the FRN Callable Bonds and the repayment of borrowings under and the termination of the TDPI Credit Facilities .
Income tax expense —We operate internationally and provide for income taxes based on the tax laws and rates in the countries in which we operate and earn income.  At June 30, 2013 and 2012, the annual effective tax rates were 21.6 percent and 24.6 percent, respectively, based on income from continuing operations before income taxes, after excluding certain items, such as losses on impairment, and gains and losses on certain asset disposals.  The tax effect, if any, of the excluded items as well as settlements of prior year tax liabilities and changes in prior year tax estimates are all treated as discrete period tax expenses or benefits.  For the six months ended June 30, 2013 and 2012, the effect of the various discrete period tax items was a net tax benefit of $22 million and $168 million, respectively.  For the six months ended June 30, 2013, these discrete tax items, coupled with the excluded income and expense items noted above, resulted in effective tax rates of 19.0 percent based on income from continuing operations before income taxes.  For the six months ended June 30, 2012, including the effect of various discrete period tax items noted above, tax expense was $19 million, compared to a loss from continuing operations before income tax of $130 million, including the income and expense items noted above .
The relationship between our provision for or benefit from income taxes and our income before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures.  Generally, our annual marginal tax rate is lower than our annual effective tax rate.  Consequently, our income tax expense does not change proportionally with our income before income taxes.  Significant decreases in our income before income taxes typically lead to higher effective tax rates, while significant increases in income before income taxes can lead to lower effective tax rates, subject to the other factors impacting income tax expense noted above.  With respect to the annual effective tax rate calculation for the six months ended June 30, 2013, a significant portion of our income tax expense was generated in countries in which income taxes are imposed on gross revenues, with the most significant of these countries being Angola, India, Nigeria, Indonesia, and Congo.  Conversely, the most significant countries in which we incurred income taxes during this period that were based on income before income tax include Norway, the U.K., Switzerland, Brazil and the U.S .
Our rig operating structures further complicate our tax calculations, especially in instances where we have more than one operating structure for the particular taxing jurisdiction and, thus, more than one method of calculating taxes depending on the operating structure utilized by the rig under the contract.  For example, two rigs operating in the same country could generate significantly different provisions for income taxes if they are owned by two different subsidiaries that are subject to differing tax laws and regulations in the respective country of incorporation.
Discontinued operations
Standard Jackup and swamp barge contract drilling services —In September 2012, in connection with our efforts to dispose of non-strategic assets and to reduce our exposure to low-specification drilling units, we committed to a plan to discontinue operations associated with the Standard Jackup and swamp barge asset groups.  In November 2012, we completed the sale of 38 drilling units to Shelf Drilling.
For a transition period following the completion of the sale transactions, we agreed to continue to operate a substantial portion of the Standard Jackups under operating agreements with Shelf Drilling and to provide certain other transition services to Shelf Drilling.  Under the operating agreements, we have agreed to remit the collections from our customers under the associated drilling contracts to Shelf Drilling, and Shelf Drilling has agreed to reimburse us for our direct costs and expenses incurred while operating the Standard Jackups on behalf of Shelf Drilling with certain exceptions.  The cost to us for providing such operating and transition services, including allocated indirect costs, may exceed the amounts we receive from Shelf Drilling for providing such services.  As of July 30 , 2013, we operated 22 Standard Jackups under operating agreements with Shelf Drilling.
In the three and six months ended June 30, 2012, we recognized aggregate losses of $12 million and $29 million, respectively, associated with the impairment of the Standard Jackups GSF Adriatic II and GSF Rig 136 , which were classified as assets held for sale at the time of impairment.

-48-


In the six months ended June 30, 2013, we recognized an aggregate net gain of $15 million associated with the disposal of the Standard Jackups D.R. Stewart , GSF Adriatic VIII and Interocean III and related equipment.  In the three and six months ended June 30, 2012, we recognized an aggregate net gain of $64 million associated with the disposal of the Standard Jackups GSF Adriatic II , Roger W. Mowell , Transocean Nordic and Transocean Shelf Explorer and related equipment.
U.S. Gulf of Mexico drilling management services —In March 2012, we announced our intent to discontinue drilling management operations in the shallow waters of the U.S. Gulf of Mexico, a component of our drilling management services operating segment, upon completion of our then existing contracts.  In the six months ended June 3 0 , 2012 we recognized losses of $31 million and $39 million associated with impairment of the customer relationships and trade name intangible assets, respectively, for this component of our drilling management services operating segment.
See Notes to Condensed Consolidated Financial Statements—Note 7—Discontinued Operations.
Liquidity and Capital Resources
Sources and uses of cash
At June 30, 2013, we had $3.4 billion in cash and cash equivalents.  At any given time, we may require a significant portion of our cash on hand for working capital and other needs related to the operation of our business.  We currently estimate this amount to be approximately $1.5 billion.  As a result, this portion of cash is not generally available to us for other uses.
For the six months ended June 30, 2013, our primary sources of cash were our cash flows from operating activities, proceeds from asset disposals, proceeds from the sale of the Shelf Drilling preference shares and proceeds from restricted cash investments, net.  Our primary uses of cash were capital expenditures, primarily associated with our newbuild projects, the first installment of our distribution of qualifying additional paid-in capital to shareholders and repayments of debt.
Six months ended
June 30,
2013
2012
Change
(In millions)
Cash flows from operating activities
Net income
$
624
$
(285
)
$
909
Depreciation
561
700
(139
)
Loss on impairment
37
245
(208
)
Gain on disposal of assets, net
(9
)
(61
)
52
Other non-cash items, net
20
26
(6
)
Changes in operating assets and liabilities, net
(711
)
374
(1,085
)
$
522
$
999
$
(477
)

Net cash provided by operating activities decreased primarily due to an aggregate cash payment of $560 million for the initial installments required under our Macondo well incident settlement obligations.  In the six months ended June 30, 2012, net income and the changes in operating assets and liabilities include a non-cash loss of $750 million for the recognition of loss contingencies associated with the Macondo well incident.

-49-

Six months ended
June 30,
2013
2012
Change
(In millions)
Cash flows from investing activities
Capital expenditures
$
(840
)
$
(496
)
$
(344
)
Proceeds from disposal of assets, net
67
202
(135
)
Proceeds from sale of preference shares
185
—
185
Other, net
12
25
(13
)
$
(576
)
$
(269
)
$
(307
)

Net cash used in investing activities increased primarily due to an increase in capital expenditures associated with our major construction and other shipyard projects and a reduction in proceeds from disposal of assets.  The increased proceeds from the sale of the Shelf Drilling preference shares partially offset these increased uses of cash.
Six months ended
June 30,
2013
2012
Change
(In millions)
Cash flows from financing activities
Changes in short-term borrowings, net
$
—
$
(260
)
$
260
Repayments of debt
(1,596
)
(320
)
(1,276
)
Proceeds from restricted cash investments
206
192
14
Deposits to restricted cash investments
(104
)
(116
)
12
Distribution of qualifying additional paid-in capital
(204
)
(278
)
74
Other, net
(25
)
(1
)
(24
)
$
(1,723
)
$
(783
)
$
(940
)

Net cash used in financing activities increased primarily due to an increase in cash used to repay or repurchase debt during the six months ended June 30, 2013 compared to the six months ended June 30, 2012.

-50-

Drilling fleet
From time to time, we review possible acquisitions of businesses and drilling rigs and may make significant future capital commitments for such purposes.  We may also consider investments related to major rig upgrades or new rig construction.  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 .
In the six months ended June 30, 2013, our capital expenditures, including capitalized interest of $37 million, were $840 million, substantially all of which related to our contract drilling services segment.  The following table presents the historical and projected capital expenditures and other capital additions, including capitalized interest, for our recently completed and ongoing major construction projects conducted during the six months ended June 30, 2013:
Total costs through December 31, 2012
Total costs
for the six months ended
June 30,
2013
Expected costs
for the remainder of
2013
Estimated
costs
thereafter
Total estimated
costs
at completion
(In millions)
Ultra-Deepwater Floater TBN1 (a)
$
139
$
84
$
81
$
536
$
840
Deepwater Asgard (b)
186
24
526
84
820
Deepwater Invictus (b)
179
25
65
521
790
Ultra-Deepwater Floater TBN4 (a)
76
3
57
649
785
Ultra-Deepwater Floater TBN3 (a)
76
4
58
647
785
Ultra-Deepwater Floater TBN2 (a)
128
82
72
498
780
Transocean Ao Thai (c)
152
13
90
—
255
Transocean Andaman (d)
160
82
—
—
242
Transocean Siam Driller (d)
162
74
—
—
236
Total
$
1,258
$
391
$
949
$
2,935
$
5,533
____________________________________
(a)
Our four newbuild Ultra Deepwater drillships, under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, are expected to commence operations in the fourth quarter of 2015, the second quarter of 2016, the fourth quarter of 2016 and the first quarter of 2017.
(b)
Deepwater Asgard and Deepwater Invictus , two Ultra-Deepwater drillships under construction at the Daewoo Shipbuilding & Marine Engineering Co. Ltd. shipyard in Korea, are expected to commence operations in the first quarter of 2014 and third quarter of 2014, respectively.  Total costs through June 30, 2013 include construction work in progress acquired in connection with our acquisition of Aker Drilling with an aggregate estimated fair value of $272 million.
(c)
Transocean Ao Thai , a Keppel FELS Super B class design High-Specification Jackup under construction at Keppel FELS’ yard in Singapore, is expected to commence operations in the fourth quarter of 2013.
(d)
Transocean Siam Driller and Transocean Andaman , two Keppel FELS Super B class design High-Specification Jackups, commenced operations in March 2013 and May 2013, respectively.  The accumulated construction costs of these rigs are no longer included in construction work in progress, as the construction projects had been completed as of June 30, 2013.
For the full year ending December 31, 2013, we expect total capital expenditures to be approximately $2 . 4 billion, approximately $1.3 billion of which is associated with our major construction projects.  The ultimate amount of our capital expenditures is partly dependent upon financial market conditions, the actual level of operational and contracting activity, the costs associated with the new regulatory environment and customer requested capital improvements and equipment for which the customer agrees to reimburse us .
As with any major shipyard project that takes place over an extended period of time, the actual costs, the timing of expenditures and the project completion date may vary from estimates based on numerous factors, including actual contract terms, weather, exchange rates, shipyard labor conditions, availability of suppliers to recertify equipment and the market demand for components and resources required for drilling unit construction .
We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales.  We also have available credit under the Primary Revolving Credit Facilities and may utilize other commercial bank or capital market financings.  Economic conditions could impact the availability of these sources of funding.
Dispositions —From time to time, we may also review the possible disposition of drilling units.  Subsequent to June 30, 2013, in connection with our efforts to dispose of non-strategic assets, we entered into agreements to sell the Deepwater Floaters Sedco 709 and Transocean Richardson and the Midwater Floaters C. Kirk Rhein, Jr. and Sedco 703 along with related equipment.

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Sources and uses of liquidity
Overview —We expect to use existing cash balances, internally generated cash flows, borrowings under bank credit agreements and proceeds from the disposal of assets to fulfill anticipated obligations , such as scheduled debt maturities or other payments, repayment of debt due within one year, capital expenditures, shareholder-approved distributions, payments of our settlement obligations under the Consent Decree and the Plea Agreement and working capital and other needs in our operations . Subject in each case to then existing market conditions and to our then expected liquidity needs, among other factors, we may continue to use a portion of our internally generated cash flows and proceeds from asset sales to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings . At any given time, we may require a significant portion of our cash on hand for working capital and other needs related to the operation of our business.  We currently estimate this amount to be approximately $1.5 billion.  As a result, this portion of cash is not generally available to us for other uses.  From time to time, we may also use borrowings under bank credit agreements to maintain liquidity for short-term cash needs.
In May 2013, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid - in capital in the form of a U.S. dollar denominated dividend of $2 . 24 per outstanding share, payable in four installments, subject to certain limitations. See “—Distribution of qualifying additional paid-in capital.”
On January 3, 2013, we announced a resolution with the DOJ of certain civil and criminal claims, which has been subsequently approved by the courts (see “—Consent Decree obligations” and “—Plea Agreement obligations”).  However, we are unable to predict the ultimate outcome of the investigations of the Macondo well incident and the DOJ lawsuits related to other civil claims that were not addressed in our resolution with the DOJ.  We can give no assurance that the ongoing matters arising out of the Macondo well incident will not adversely affect our liquidity in the future.
Our access to debt and equity markets may be limited due to a variety of events, including , among others, credit rating agency downgrades of our debt ratings, potential liability related to the Macondo well incident, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry.  Uncertainty related to our potential liabilities from the Macondo well incident has 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.  An economic downturn could have an impact on the lenders participating in our credit facilities or on our customers, causing them to fail to meet their obligations to us.  Uncertainty related to our potential liabilities from the Macondo well incident has 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 .
Primary Revolving Credit Facilities —We have a $2.0 billion five-year revolving credit facility, established under a bank credit agreement dated November 1, 2011, as amended, that is scheduled to expire on November 1, 2016 (the “Five-Year Revolving Credit Facility”).  We also have a $900 million three-year secured revolving credit facility, established under a bank credit agreement dated October 25, 2012, that is scheduled to expire on October 25, 2015 (the “Three-Year Secured Revolving Credit Facility” and, together with the Five-Year Revolving Credit Facility, the “Primary Revolving Credit Facilities”).  The Five - Year Revolving Credit Facility includes a $1.0 billion sublimit for the issuance of letters of credit, and borrowings under the Five - Year Revolving Credit Facility are guaranteed by Transocean Ltd . Borrowings under the Three-Year Secured Revolving Credit Facility are secured by Deepwater Champion, Discoverer Americas and Discoverer Inspiration and are guaranteed by Transocean Ltd. and Transocean Inc.
Among other things, the Primary Revolving Credit Facilities include limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets.  The Primary Revolving Credit Facilities also include a covenant imposing a maximum debt to tangible capitalization ratio of 0.6 to 1.0.  As of June 30, 2013, our debt to tangible capitalization ratio, as defined, was 0. 4 to 1.0.  In order to borrow under the Primary Revolving Credit Facilities or have letters of credit issued under the Five-Year Revolving Credit Facility, we must, at the time of the borrowing request, not be in default under the bank credit agreements and make certain representations and warranties, including with respect to compliance with laws and solvency, to the lenders, but we are not required to make any representation to the lenders as to the absence of a material adverse effect.  In order to borrow under the Three-Year Secured Revolving Credit Facility, we must also, at the time of the borrowing request, satisfy a collateral maintenance test.  Commitments and borrowings under the Three-Year Secured Revolving Credit Facility are subject to mandatory reductions and prepayments, respectively, if a mortgaged rig is sold, an event of loss with respect to a mortgaged rig occurs, a collateral maintenance test is not satisfied or certain other events occur . Repayment of borrowings under the Primary Revolving Credit Facilities is subject to acceleration upon the occurrence of an event of default.  We are also subject to various covenants under the indentures pursuant to which our public debt was issued, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in certain merger, consolidation or reorganization transactions.  A default under our public debt indentures, our bank credit agreements, our capital lease contract or any other debt owed to unaffiliated entities that exceeds $125 million could trigger a default under the Primary Revolving Credit Facilities and, if not waived by the lenders, could cause us to lose access to the Primary Revolving Credit Facilities and result in the foreclosure of the liens securing the Three-Year Secured Revolving Credit Facility .

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Our commitment fee and lending margin under the Primary Revolving Credit Facilities are subject to change based on the credit rating of our non-credit enhanced senior unsecured long-term debt (“Debt Rating”).  For the Five-Year Revolving Credit Facility , if our Debt Rating falls below investment grade, the commitment fee will increase from 0.275 percent to 0.325 percent and the lending margin will increase from 1.625 percent to 2.0 percent.  For the Three-Year Secured Revolving Credit Facility, if our Debt Rating falls below investment grade, the commitment fee will increase from 0.375 percent to 0.50 percent and the lending margin will increase from 2.0 percent to 2.5 percent .
At July 30, 2013, we had no borrowings outstanding , we had $24 million in letters of credit issued, and we had $2.0 billion of available borrowing capacity under the Five-Year Revolving Credit Facility.  At July 30 2013, we had no borrowings outstanding, and we had $900 million of available borrowing capacity under the Three-Year Secured Revolving Credit Facility .
ADDCL Credit Facilities —Angola Deepwater Drilling Company Limited (“ADDCL”) has a senior secured credit facility, comprised of Tranche A for $215 million and Tranche C for $399 million, under a bank credit agreement that is scheduled to expire in December 2017 (the “ADDCL Primary Loan Facility”).  Unaffiliated financial institutions provide the commitment for and borrowings under Tranche A, and one of our subsidiaries provides the commitment for Tranche C.  Tranche A bears interest at London Interbank Offered Rate (“LIBOR”) plus the applicable margin of 0.725 percent.  Tranche A requires semi-annual installments of principal and interest.  Borrowings under the ADDCL Primary Loan Facility are secured by the Ultra-Deepwater Floater Discoverer Luanda. 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 July 30, 2013, borrowings of $149 million were outstanding under Tranche A at a weighted-average interest rate of 1.1 percent.  At July 30, 2013, borrowings of $399 million were outstanding under Tranche C, and eliminated in consolidation.
ADDCL also has a $90 million secondary credit facility, established under a bank credit agreement that is scheduled to expire in December 2015 (the “ADDCL Secondary Loan Facility” and together with the ADDCL Primary Loan Facility, the “ADDCL Credit Facilities”).  One of our subsidiaries provides 65 percent of the total commitment under the ADDCL Secondary Loan Facility.  Borrowings under the ADDCL Secondary Loan Facility bear interest at LIBOR plus the applicable margin, ranging from 3.125 percent to 5.125 percent, depending on certain milestones.  Borrowings under the ADDCL Secondary Loan Facility are payable in full in December 2015 and may be prepaid in whole or in part without premium or penalty.  Repayment of borrowings under the ADDCL Secondary Loan Facility is subject to acceleration by the unaffiliated financial institution upon the occurrence of certain events of default, including if our Debt Rating falls below investment grade.  In addition, if our Debt Rating falls below investment grade, ADDCL would be required to obtain insurance from a source other than our wholly owned captive insurance company within 10 business days.  At July 30, 2013, borrowings of $80 million were outstanding under the ADDCL Secondary Loan Facility, of which $52 million was provided by one of our subsidiaries and eliminated in consolidation.  The weighted-average interest rate on July 30, 2013 was 3.4 percent.
ADDCL is required to maintain certain cash balances in restricted accounts for the payment of the scheduled installments on the ADDCL Credit Facilities.  At July 30, 2013, ADDCL had restricted cash investments of $22 million.
Eksportfinans Loans — We have outstanding borrowings under the Loan Agreement dated September 12, 2008 (“Eksportfinans Loan A”) and outstanding borrowings under the Loan Agreement dated November 18, 2008 (“Eksportfinans Loan B,” and together with Eksportfinans Loan A, the “Eksportfinans Loans”), which were established to finance the construction and delivery of Transocean Spitsbergen and Transocean Barents .  Eksportfinans Loan A and Eksportfinans Loan B bear interest at a fixed rate of 4.15 percent and require semi-annual installments of principal and interest through September 2017 and January 2018, respectively.  At July 30, 2013, borrowings of $315 million and $314 million were outstanding under Eksportfinans Loan A and Eksportfinans Loan B, respectively.
The Eksportfinans Loans require cash collateral to remain on deposit at a certain financial institution through expiration (the “Aker Restricted Cash Investments”).  The Aker Restricted Cash Investments bear interest at a fixed rate of 4.15 percent with semi-annual installments that correspond with those of the Eksportfinans Loans.  At July 30, 2013, the aggregate balance of the Aker Restricted Cash Investments was $629 million.
Debt repayments —We had a $1.265 billion secured credit facility, comprised of a $1.0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, established under a bank credit agreement that was scheduled to expire in March 2015 (the “TPDI Credit Facilities”).  One of our subsidiaries participated in the term loan with an aggregate commitment of $595 million.  In June 2013, we repaid the $735 million of borrowings outstanding under the TPDI Credit Facilities, of which $367 million was paid to one of our subsidiaries and eliminated in consolidation.  Upon repayment of all borrowings, we terminated the TPDI Credit Facilities.
During the six months ended June 3 0 , 2013, we also repaid the outstanding $250 million and $500 million aggregate principal amount of the 5% Notes due February 2013 and the 5.25% Senior Notes due March 2013, respectively, as of the stated maturity dates.

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Debt redemptions —Holders of the Series C Convertible Senior Notes had the right to require us to repurchase all or any portion of such holders’ notes on December 14, 2012.  As a result, in December 2012, we were required to repurchase an aggregate principal amount of $1.7 billion of our Series C Convertible Senior Notes for an aggregate cash payment of $1.7 billion.  On February 7, 2013, we redeemed the remaining aggregate principal amount of $62 million of our Series C Convertible Senior Notes for an aggregate cash payment of $62 million.
In connection with our acquisition of Aker Drilling, we assumed the obligations related to the Callable Bonds, issued on February 21, 2011, which are publicly traded on the Oslo Stock Exchange.  The FRN Callable Bonds and the 11% Callable Bonds are denominated in Norwegian kroner in the aggregate principal amounts of NOK 940 million and NOK 560 million, respectively.  On March 6, 2013, we redeemed the FRN Callable Bonds and the 11% Callable Bonds with aggregate outstanding principal amounts of NOK 940 million and NOK 560 million, equivalent to $164 million and $98 million, respectively, using an exchange rate of NOK 5.73 to $1.00.  In connection with the redemption, we made an aggregate cash payment of NOK 1,567 million, equivalent to $273 million.
Capital lease contract — Petrobras 10000 is held by one of our subsidiaries under a capital lease contract that requires scheduled monthly payments of $6 million through its stated maturity on August 4, 2029, at which time our subsidiary will have the right and obligation to acquire Petrobras 10000 from the lessor for one dollar.  Upon the occurrence of certain termination events, our subsidiary is also required to purchase Petrobras 10000 and pay a termination amount determined by a formula based upon the total cost of the drillship.  The capital lease contract includes limitations on creating liens on Petrobras 10000 and requires our subsidiary to make certain representations in connection with each monthly payment, including with respect to the absence of pending or threatened litigation or other proceedings against our subsidiary or any of its affiliates, which, if determined adversely, could have a material adverse effect on our subsidiary’s ability to perform its obligations under the capital lease contract.  Additionally, Transocean Inc. has guaranteed the obligations under the capital lease contract, and Transocean Inc. is required to maintain an adjusted net worth, as defined, of at least $5.0 billion as of the end of each fiscal quarter.  In the event Transocean Inc. does not satisfy this covenant at the end of any fiscal quarter, it is required to deposit the deficit amount, determined as the difference between $5.0 billion and the adjusted net worth for such fiscal quarter, into an escrow account for the benefit of the lessor.  At July 30, 2013, $646 million was outstanding under the capital lease contract.
Plea Agreement obligations —Pursuant to a cooperation guilty plea agreement by and among the DOJ and certain of our affiliates (the “Plea Agreement”), which was accepted by the court on February 14, 2013, we agreed to pay a criminal fine of $100 million and to consent to the entry of an order requiring us to pay a total of $150 million to the National Fish & Wildlife Foundation , and $150 million to the National Academy of Sciences.  In the three months ended June 30, 2013, we made an aggregate cash payment of $160 million in satisfaction of amounts due under the Plea Agreement, including $100 million for the payment of the criminal fine, $58 million for the initial payment to the National Fish and Wildlife Foundation and $2 million for the initial payment to the National Academy of Sciences.  At July 30, 2013, the remaining balance of our Plea Agreement obligations was $240 million, payable as follows:  (a) $92 million payable to the National Fish and Wildlife Foundation, $53 million of which is due on or before February 14, 2014 and $39 million of which is due on or before February 13, 2015 and (b) $148 million payable to the National Academy of Sciences, $7 million of which is due on or before February 14, 2014, $21 million of which is due on or before February 13, 2015, $60 million of which is due on or before February 12, 2016 and $60 million of which is due on or before February 14, 2017 .
Consent Decree obligations —Pursuant to a civil consent decree by and among the DOJ and certain of our affiliates (the “Consent Decree”), which was approved by the court on February 19, 2013, we agreed to pay a civil penalty totaling $1.0 billion, plus interest at a rate of 2.15 percent.  On March 15, 2013, we paid our initial installment of $404 million, including interest.  At July 30, 2013, the remaining balance of our Consent Decree obligations was $600 million, payable as follows:  (a) $400 million, plus interest, on or before February 19, 2014; and (b) $200 million, plus interest, on or before February 19, 2015 .
Distribution of qualifying additional paid-in capital —In May 2013, at our annual general meeting, our shareholders approved the distribution of qualifying additional paid - in capital in the form of a U.S. dollar denominated dividend of $2 . 24 per outstanding share, payable in four installments, subject to certain limitations.  In May 2013, we recognized a liability of $816 million for the distribution payable , recorded in other current liabilities, with a corresponding entry to additional paid-in capital.  On June 19, 2013, we paid the first installment in the aggregate amount of $204 million to shareholders of record and directors and employees holding unvested deferred units as of May 31, 2013.  At June 30, 2013, the carrying amount of the unpaid distribution payable was $612 million, which we expect to pay in three installments in September 2013, December 2013 and March 2014 .
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 $3.8 billion at an exchange rate as of the close of trading on July 30, 2013 of $1.00 to CHF 0.93.  On February 12, 2010, our board of directors authorized our management to implement the share repurchase program.  We intend to fund any repurchases using available cash balances and cash from operating activities.  On May 24, 2013, we received approval from the Swiss authorities for the continuation of the share repurchase program for a further three-year repurchase period through May 23, 2016.  In the six months ended June 3 0 , 2013, we did not purchase shares under our share repurchase program.

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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 amount and duration of our contract backlog, general market conditions, debt rating considerations and other factors, that we should retain cash, reduce debt, make capital investments or acquisitions or otherwise use cash for general corporate purposes, and consequently , repurchase fewer or no additional shares under this program.  Decisions regarding the amount, if any , and timing of any share repurchases would be made from time to time based upon these factors.
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 if 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 July 30, 2013, Transocean Inc., our wholly owned subsidiary, held as treasury shares approximately three percent of our issued shares.  At the annual general meeting in May 2009, the shareholders approved the release of CHF 3.5 billion of additional paid-in capital to other reserves, or freely available reserves as presented on our Swiss statutory balance sheet, to create the freely available reserve necessary for the CHF 3.5 billion share repurchase program for the purpose of the cancellation of shares (the “Currently Approved Program”).  At the May 2011 annual general meeting, our shareholders approved the reallocation of CHF 3.2 billion, which is the remaining amount authorized under the share repurchase program, from free reserve to legal reserve, reserve from capital contributions.  This amount will continue to be available for Swiss federal withholding tax-free share repurchases.  We may only repurchase shares to the extent freely distributable reserves are available.  Our board of directors could, to the extent freely distributable reserves are available, authorize the repurchase of additional shares for purposes other than cancellation, such as to retain treasury shares for use in satisfying our obligations in connection with incentive plans or other rights to acquire our shares.  Based on the current amount of shares held as treasury shares, approximately seven percent of our issued shares could be repurchased for purposes of retention as additional treasury shares.  Although our board of directors has not approved such a share repurchase program for the purpose of retaining repurchased shares as treasury shares, if it did so, any such shares repurchased would be in addition to any shares repurchased under the Currently Approved Program.
Contractual obligations — As of June 30, 2013, 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, 2012, except as noted below.
For the twelve months ending June 30 ,
Total
2014
2015 - 2016
2017 - 2018
Thereafter
(in millions)
Contractual obligations
Debt
$
9,968
$
140
$
1,380
$
3,241
$
5,207
Debt of consolidated variable interest entities
178
30
93
55
—
Interest on debt (a)
5,816
564
1,092
885
3,275
Plea Agreement obligations
240
60
120
60
—
Consent Decree obligations (b)
615
411
204
—
—
Distribution of qualifying additional paid-in capital
612
612
—
—
—
Total (c)
$
17,429
$
1,817
$
2,889
$
4,241
$
8,482
____________________________________
(a)
Includes interest on consolidated debt.
(b)
Includes interest on Consent Decree obligations.
(c)
As of June 30, 2013, our unrecognized tax benefits related to uncertain tax positions, net of prepayments, represented a liability of $555 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, and we have excluded this amount from the contractual obligations presented in the table above.  See Notes to Condensed Consolidated Financial Statements—Note 6—Income Taxes.
In April 2013, we contributed $59 million to our U.S. defined benefit pension plans in anticipation of future funding requirements.  In the six months ended June 30, 2013, we contributed $20 million toward the minimum funding requirement of $36 million for our non-U.S. defined benefit plans for the year ending December 31, 2013.

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Commercial commitments —As of June 30, 2013, 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, 2012, except as noted below.
For the twelve months ending June 30,
Total
2014
2015 - 2016
2017 - 2018
Thereafter
(in millions)
Other commercial commitments
Standby letters of credit
$
552
$
443
$
102
$
7
$
—

Derivative instruments
Our board of directors has approved policies and procedures for derivative instruments that require the approval of our Chief Financial Officer prior to entering into any derivative instruments.  From time to time, we may enter into a variety of derivative instruments in connection with the management of our exposure to fluctuations in interest rates and currency exchange rates.  We do not enter into derivative transactions for speculative purposes; however, we may enter into certain transactions that do not meet the criteria for hedge accounting.  See Notes to Condensed Consolidated Financial Statements—Note 11—Derivatives and Hedging.
Contingencies
Except as noted in this report, including in our Notes to Condensed Consolidated Financial Statements—Note 13—Commitments and Contingencies and in Note 6—Income Taxes, there have been no material changes to those actions, claims and other matters pending as discussed in Notes to Consolidated Financial Statements—Note 17—Commitments and Contingencies and “Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident” in our annual report on Form 10-K for the year ended December 31, 2012.  As of June 30, 2013, we were also involved in a number of lawsuits which have arisen in the ordinary course of our business and for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated financial position, results of operations or cash flows.  We can provide no assurance that our expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.
Macondo well incident
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. (together with its affiliates, “BP”).  The rig was declared a total loss.
Although we are unable to estimate the full direct and indirect effect that the Macondo well incident will have on our business, the incident has had and could continue to have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows.  In the three years ended December 31, 2012, we estimate that the Macondo well incident had a direct and indirect effect of greater than $1. 0 billion in lost revenues and incremental costs and expenses associated with extended shipyard projects and increased downtime, both as a result of complying with the enhanced regulations and our customers’ requirements.  We also lost approximately $1.1 billion of contract backlog associated with the termination of the Deepwater Horizon contract in April 2010 resulting from the loss of the rig and the termination of another drilling contract in December 2011 resulting from the previously mentioned increased downtime.  We have recognized an aggregate liability of $1 . 9 billion for our settlement obligations with the DOJ and for estimated loss contingencies associated with the Macondo well incident that we believe are probable and for which a reasonable estimate can be made.  Additionally, in the three years ended December 31, 2012, we incurred cumulative incremental costs, primarily associated with legal expenses for lawsuits and investigations, in the amount of $372 million.  In the six months ended June 30, 2013, we incurred $130 million of such costs and additional loss contingencies.  Collectively, the lost contract backlog from the incident and from the termination in December 2011, the lost revenues and incremental costs and expenses and other losses have had an effect of greater than $4 .5 billion.
We have recognized a liability for estimated loss contingencies associated with litigation and investigations resulting from the incident that we believe are probable and for which a reasonable estimate can be made.  At June 30, 2013 and December 31, 2012, the liability for estimated loss contingencies that we believe are probable and for which a reasonable estimate can be made was $454 million and $1.9 billion, respectively, recorded in other current liabilities.  The litigation and investigations also give rise to certain loss contingencies that we believe are either reasonably possible or probable but for which we do not believe a reasonable estimate can be made.  Although we have not recognized a liability for such loss contingencies, these contingencies could increase the liabilities we ultimately recognize.
We have also recognized an asset associated with the portion of our estimated losses, primarily related to the personal injury and fatality claims of our crew and vendors, that we believe is probable of recovery from insurance.  Although we have available policy limits that could result in additional amounts recoverable from insurance, recovery of such additional amounts is not probable and we are not currently able to estimate such amounts.  Our estimates involve a significant amount of judgment.  As a result of new information or future developments, we may adjust our estimated loss contingencies arising out of the Macondo well incident or our estimated recoveries from insurance, and the resulting losses could have a material adverse effect on our consolidated statement of financial position, results of operations and cash flows.  At June 30, 2013 and December 31, 2012, the insurance recoverable asset related to estimated losses primarily for additional personal injury and fatality claims of our crew and vendors that we believe are probable of recovery from insurance was $66 million and $153 million, respectively, recorded in other assets.

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Many of the Macondo well related claims are pending in the U.S. District Court, Eastern District of Louisiana (the “MDL Court”).  In March 2012, BP and the Plaintiff’s Steering Committee (the “PSC”) announced that they had agreed to a partial settlement related primarily to private party environmental and economic loss claims as well as response effort related claims (the “BP/PSC Settlement”).  The BP/PSC Settlement agreement provides that (a) to the extent permitted by law, BP will assign to the settlement class certain of BP’s claims, rights and recoveries against us for damages with protections such that the settlement class is barred from collecting any amounts from us unless it is finally determined that we cannot recover such amounts from BP, and (b) the settlement class releases all claims for compensatory damages against us but purports to retain claims for punitive damages against us.  On December 21, 2012, the MDL Court granted final approval of the economic and property damage class settlement between BP and the PSC.  In December 2012, in response to the settlements, we filed three motions seeking partial summary judgment on various claims, including punitive damages claims.  If successful, these motions would eliminate or reduce our exposure to punitive damages.  The MDL Court has not ruled on these motions.
The first phase of the trial commenced on February 25, 2013, and the presentation of evidence for that phase was completed on April 17, 2013.  The trial addressed fault issues that had not previously been disposed of or resolved by settlement, summary judgment or stipulation and that may properly be tried by the MDL Court without a jury, including negligence, gross negligence, or other bases of liability of the various defendants with respect to the issues, and limitation of liability issues.  On June 21, 2013, pursuant to the MDL Court’s order, the parties filed post-trial briefs and proposed findings of fact and conclusions of law.  The parties submitted reply briefs on July 12, 2013.
The MDL Court has scheduled a trial date of September 30, 2013 for the second phase of the trial, which will address conduct related to stopping the release of hydrocarbons between April 22, 2010 and approximately September 19, 2010 and seek to quantify the cumulative discharge of oil caused by the release.
We can provide no assurance as to the outcome of the trial, as to the timing of any upcoming phase of trial, that we will not enter into additional settlement as to some or all of the matters related to the Macondo well incident, including those to be determined at a trial, or the timing or terms of any such settlement.  See Notes to Condensed Consolidated Financial Statements—Note 13—Commitments and Contingencies.
Insurance matters
Our hull and machinery and excess liability insurance program is comprised of commercial market and captive insurance policies that we renew annually on May 1.  We periodically evaluate our insurance limits and self - insured retentions.  As of June 30, 2013, the insured value of our drilling rig fleet was approximately $27.3 billion, excluding our rigs under construction.
We generally do not carry commercial market insurance coverage for loss of revenues, unless it is contractually required, or for losses resulting from physical damage to our fleet caused by named windstorms in the U.S. Gulf of Mexico, including liability for wreck removal expenses . We have elected to self-insure operators extra expense coverage for ADTI.  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 .
See Notes to Condensed Consolidated Financial Statements—Note 13—Commitments and Contingencies.
Tax matters
We are a Swiss corporation, and we operate through our various subsidiaries in a number of countries throughout the world.  Our provision for income taxes is based on the tax laws and rates applicable in the jurisdictions in which we operate and earn income.  The relationship between our provision for or benefit from income taxes and our income or loss before income taxes can vary significantly from period to period considering, among other factors, (a) the overall level of income before income taxes, (b) changes in the blend of income that is taxed based on gross revenues rather than income before taxes, (c) rig movements between taxing jurisdictions and (d) our rig operating structures.  Generally, our annual marginal tax rate is lower than our annual effective tax rate.
We conduct operations through our various subsidiaries in a number of countries throughout the world.  Each country has its own tax regimes with varying nominal rates, deductions and tax attributes.  From time to time, we may identify changes to previously evaluated tax positions that could result in adjustments to our recorded assets and liabilities.  Although we are unable to predict the outcome of these changes, we do not expect the effect, if any, resulting from these adjustments to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.
We file federal and local tax returns in several jurisdictions throughout the world.  Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments.  We are defending our tax positions in those jurisdictions.  We are also defending against tax-related claims in courts, including our ongoing criminal trial in Norway.

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While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated statement of financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows .
See Notes to Condensed Consolidated Financial Statements—Note 6—Income Taxes.
Regulatory matters
For a discussion of regulatory matters, 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, 2012 .
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.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements.  This discussion should be read in conjunction with disclosures included in the notes to our condensed consolidated financial statements related to estimates, contingencies and other accounting policies.  Significant accounting policies are discussed in Note 2 to our condensed consolidated financial statements in this quarterly report on Form 10-Q and in Note 2 to our consolidated financial statements in our annual report on Form 10-K for the year ended December 31, 2012 .
To prepare financial statements, we are required to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures of contingent assets and liabilities.  On an ongoing basis, we evaluate our estimates, including those related to our discontinued operations, allowance for doubtful accounts, materials and supplies obsolescence, investments, property and equipment, goodwill, income taxes, defined benefit pension plans and other postretirement employee benefits, contingent liabilities and share-based compensation.  These estimates require significant judgments, assumptions and estimates.  We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources.  Actual results may differ from these estimates.
For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2012.  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 six months ended June 30, 2013, there have been no material changes to the types of judgments, assumptions and estimates upon which our critical accounting estimates are based.
New Accounting Pronouncements
For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our condensed consolidated financial statements, see Notes to Condensed Consolidated Financial Statements—Note 3—New Accounting Pronouncements in this quarterly report on Form 10-Q and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2012.

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Quantitative and Qualitative Disclosures About Market Risk
Overview —We are exposed to interest rate risk and currency exchange rate risk, primarily associated with our restricted cash investments and our consolidated long - term and short - term debt.  For our restricted cash investments and debt instruments, the following table presents the principal cash flows and related weighted-average interest rates by contractual maturity date.  The information is stated in U.S dollar equivalents.  The instruments are denominated in either U.S. dollars or Norwegian kroner, as indicated.  The following table presents information for the twelve-month periods ending June 3 0 (in millions, except interest rate percentages):
Scheduled Maturity Date (a)
2014
2015
2016
2017
2018
Thereafter
Total
Fair Value
Restricted cash investments
Fixed rate (NOK)
$
139
$
140
$
140
$
140
$
105
$
—
$
664
$
695
Average interest rate
4.15
%
4.15
%
4.15
%
4.15
%
4.15
%
—
%
Debt
Fixed rate (USD)
$
21
$
23
$
1,124
$
1,027
$
2,025
$
5,731
$
9,951
$
10,936
Average interest rate
7.76
%
7.76
%
5.01
%
5.12
%
4.90
%
6.50
%
Fixed rate (NOK)
$
139
$
140
$
140
$
140
$
105
$
—
$
664
$
695
Average interest rate
4.15
%
4.15
%
4.15
%
4.15
%
4.15
%
—
%
Debt of consolidated variable interest entities
Variable rate (USD)
$
29
$
31
$
62
$
36
$
20
$
—
$
178
$
178
Average interest rate
1.14
%
1.14
%
2.17
%
1.14
%
1.14
%
—
%
____________________________________
(a)
Expected maturity amounts are based on the face value of debt.

Interest rate risk —At June 30, 2013 and December 31, 2012, the aggregate principal amount of our consolidated variable-rate debt was approximately $178 million and $1.1 billion, which represented two percent and nine percent of the aggregate principal amount of our total consolidated debt, respectively, including the effect of our hedging activities.  At June 30, 2013, our consolidated variable-rate debt consisted of borrowings under the ADDCL Credit Facilities.  At December 31, 2012, our consolidated variable-rate debt, excluding the effect of our hedging activities, consisted of the FRN Callable Bonds and borrowings under the ADDCL Credit Facilities and the TPDI Credit Facilities.  Based upon variable-rate debt amounts outstanding as of June 30, 2013 and December 31, 2012, a hypothetical one percentage point change in annual interest rates would result in a corresponding change in annual interest expense of approximately $2 million and $11 million, respectively.
At June 30, 2013 and December 31, 2012, the fair value of our consolidated debt was $11.8 billion and $14.1 billion, respectively.  During the six months ended June 30, 2013, the fair value of our consolidated debt decreased by $2.3 billion due to the repayment or redemption of $1.4 billion aggregate principal amount of debt and a decrease of  $8 00 million in the market valuation of our outstanding consolidated debt.
Currency exchange rate risk —At June 30, 2013, we had NOK 4.0 billion aggregate principal amount of debt obligations, all of which are secured by a corresponding amount of restricted cash investments that are also denominated in Norwegian kroner.  These corresponding restricted cash investments form an economic hedge of our exposure to currency exchange rate risk associated with these debt obligations.
For a discussion of our currency exchange rate risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our annual report on Form 10-K for the year ended December 31, 2012.  With the exception of the foregoing, there have been no material changes to these previously reported matters during the six months ended June 30, 2013 .
Controls and Procedures
Disclosure controls and procedures —We carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 (the “Exchange Act”) Rules 13a-15 and 15d-15, were effective, as of June 30, 2013, to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the U.S. Securities and Exchange Commission’s rules and forms.

Internal controls over financial reporting —There were no changes to our internal controls during the quarter ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II. OTHER INFORMATION
Legal Proceedings
We have certain actions, claims and other matters pending as discussed and reported in Notes to Condensed Consolidated Financial Statements Note 13—Commitments and Contingencies and “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident” in this quarterly report on Form 10-Q and Notes to Consolidated Financial Statements Note 17—Commitments and Contingencies and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident” and “Item 3. Legal Proceedings” in our annual report on Form 10-K for the year ended December 31, 2012.  We are also involved in various tax matters as described in Notes to Condensed Consolidated Financial Statements Note 6—Income Taxes, in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Tax matters” in this quarterly report on Form 10-Q and in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Tax matters” in our annual report Form 10-K for the year ended December 31, 2012.  As of June 30, 2013, 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 referred to above or of any such other pending or threatened litigation or legal proceedings.  There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.
Risk Factors
Except as disclosed below, there have been no material changes from the risk factors as previously disclosed in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2012.
A change in tax laws, treaties or regulations, or their interpretation, of any country in which we have operations, are incorporated or are resident could result in a higher tax rate on our worldwide earnings, which could result in a significant negative impact on our earnings and cash flows from operations.
We operate worldwide through our various subsidiaries.  Consequently, we are subject to changes in applicable tax laws, treaties or regulations in the jurisdictions in which we operate, which could include laws or policies directed toward companies organized in jurisdictions with low tax rates. A material change in the tax laws or policies, or their interpretation, of any country in which we have significant operations, or in which we are incorporated or resident, could result in a higher effective tax rate on our worldwide earnings and such change could be significant to our financial results.
Tax legislative proposals intending to eliminate some perceived tax advantages of companies that have legal domiciles outside the U.S., but have certain U.S. connections, have repeatedly been introduced in the U.S. Congress.  Recent examples include, but are not limited to, legislative proposals that would broaden the circumstances in which a non - U.S. company would be considered a U.S. resident, including the use of “management and control” provisions to determine corporate residency, and proposals that could override certain tax treaties and limit treaty benefits on certain payments by U.S. subsidiaries to non - U.S. affiliates.  Additionally, the U.S. Congress has repeatedly introduced a proposal which would disallow any deduction for otherwise tax deductible payments relating to any incident resulting in the discharge of oil into navigable waters, such as the Macondo well incident.  Any material change in tax laws or policies, or their interpretation, resulting from such legislative proposals or inquiries could result in a higher effective tax rate on our worldwide earnings and such change could have a material adverse effect on our statement of financial position, results of operations and cash flows.
In May 2013, in response to certain guidance and demands from both the European Union and the Organisation for Economic Co - operation and Development, Switzerland announced its willingness to consider the abolishment of certain cantonal tax privileges to the extent such provisions treat Swiss and non - Swiss income differently and other significant changes to existing tax laws and practices.  These issues, plus other tax legislative matters, are expected to be considered by Switzerland during the next 12 to 18 months.  Switzerland’s implementation of any material change in tax laws or policies or its adoption of new interpretations of existing tax laws and rulings could result in a higher effective tax rate on our worldwide earnings and such change could have a material adverse effect on our statement of financial position, results of operations and cash flows.

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Recent developments in Swiss corporate governance may affect our ability to attract and retain top executives.
In March 2013, Swiss voters approved a ballot initiative, the so-called “Minder Initiative,” as a result of which the Swiss Federal Constitution was amended.  The legislation implementing the constitutional amendment will be applicable to listed Swiss companies, like our company.  In June 2013, a draft of the ordinance implementing the constitutional amendment was made public.  We expect that the definitive implementing ordinance will enter into effect on January 1, 2014, subject to an extended transition period for some of its requirements, and, among other things, require a binding shareholder “say on pay” vote with respect to the compensation of members of our executive management and board of directors generally prohibit the making of severance, advance, transaction premiums and similar payments to members of our executive management and board of directors require the declassification of our Board of Directors and require our articles of association to specify various compensation-related matters.  The implementing ordinance is expected to include criminal penalties against directors and executive officers in case of noncompliance with its requirements.  Uncertainty around the implementation and interpretation of the provisions of the implementing ordinance may negatively affect our ability to attract and retain executive officers and members of our board of directors.
Our ongoing organizational efficiency initiative may affect our ability to manage our business and our operational results and could result in the loss of key personnel.
We are currently undertaking an organizational efficiency initiative to improve our cost structure and streamline certain shore-based business functions and processes.  The organizational efficiency initiative includes a reduction in our workforce as well as the elimination of certain processes, programs and tasks we do not consider to be central to supporting our core business.  As we make adjustments to our workforce, we may incur additional expenses that delay or limit any benefit of a more efficient workforce structure.  Additionally, the implementation of the organizational efficiency initiative may strain or limit our management and our administrative, technical, operational and financial personnel and may not result in the anticipated improvement in our overall cost structure or the streamlining of our shore-based business functions and processes.  If we fail to manage the organizational efficiency initiative changes effectively, it could adversely affect our ability to manage our business and operational results and could result in the loss of key personnel.
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)
April 2013
745
$
49.27
—
$
3,440
May 2013
4,100
$
54.11
—
$
3,440
June 2013
238
$
51.12
—
$
3,440
Total
5,083
$
53.26
—
$
3,440
____________________________________
(1)
Total number of shares purchased in the second quarter of 2013 consists of 5,083 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 $3.7 billion at an exchange rate as of June 30, 2013 of USD 1.00 to CHF 0.95.  On February 12, 2010, our board of directors authorized our management to implement the share repurchase program.  On May 24, 2013, we received approval from the Swiss authority for the continuation of the share repurchase program for a further three-year repurchase period through May 23, 2016.  We may decide, based upon our ongoing capital requirements, the price of our shares, matters relating to the Macondo well incident, regulatory and tax considerations, cash flow generation, the amount and duration of our contract backlog, general market conditions, debt rating considerations and other factors, that we should retain cash, reduce debt, make capital investments or acquisitions or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no additional shares under this program.  Decisions regarding the amount, if any, and timing of any share repurchases would be made from time to time based upon these factors.  Through June 30, 2013, we have repurchased a total of 2,863,267 of our shares under this share repurchase program at a total cost of $240 million, equivalent to an average cost of $83.74 per share.  See “—Sources and uses of liquidity.”
Mine Safety Disclosures
Not applicable.

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Exhibits
(a)           Exhibits
The following exhibits are filed in connection with this Report:
Number
Description
*
10.1
Consulting Agreement with Gregory L. Cauthen effective as of April 25, 2013 (incorporated by reference to Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on April 26, 2013)
*
10.2
First Amendment to Long-Term Incentive Plan of Transocean Ltd. (as amended and restated as of February 12, 2009) (incorporated by reference to Exhibit 10.1 to Transocean Ltd.’s Current Report on Form 8-K (Commission File No. 000-53533) filed on May 22, 2013)
*
10.3
First Amendment to Employment Agreement with Allen M. Katz effective as of July 1, 2013 (incorporated by reference to Exhibit 10.55 to Transocean Ltd.’s Annual Report on Form 10-K (Commission File No. 000-53533) for the year ended December 31, 2012)
†
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.
*
Compensation plan or arrangement.



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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 August 7, 2013 .

TRANSOCEAN LTD.



By: /s/ Esa Ikäheimonen__________________________________
Esa Ikäheimonen
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)



By: /s/ David Tonnel_____________________________________
David Tonnel
Senior Vice President, Finance and Controller
(Principal Accounting Officer)


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