second-quarter results

Transocean Ltd. ( RIG )

BLANDONNET INTERNATIONAL BUSINESS CENTERVERNIER, V8, 121441−58−792−92

10−QQuarterly report pursuant to sections 13 or 15(d)Filed on 8/4/2010 Filed Period 6/30/2010

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 _________________________

FORM 10-Q (Mark one)

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

For the quarterly period ended June 30, 2010

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)

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

Chemin de Blandonnet 10 Vernier, Switzerland

1214

(Address of principal executive offices) (Zip Code)

+41 (22) 930-9000 (Registrant’s telephone number, including area code)

_________________________

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

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

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

As of July 27, 2010, 318,993,839 shares were outstanding.

TRANSOCEAN LTD. INDEX TO FORM 10-Q

QUARTER ENDED JUNE 30, 2010

PART I. FINANCIAL INFORMATION Page

Item 1. Financial Statements (Unaudited)

Condensed Consolidated Statements of Operations 1

Condensed Consolidated Statements of Comprehensive Income 2

Condensed Consolidated Balance Sheets 3

Condensed Consolidated Statements of Equity 4

Condensed Consolidated Statements of Cash Flows 5

Notes to Condensed Consolidated Financial Statements 6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 24

Item 3. Quantitative and Qualitative Disclosures About Market Risk 49

Item 4. Controls and Procedures 50

PART II. OTHER INFORMATION

Item 1. Legal Proceedings 51

Item 1A. Risk Factors 51

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 55

Item 6. Exhibits 55

See accompanying notes. - 1 -

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements TRANSOCEAN LTD. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (In millions, except per share data)

(Unaudited)

Three months ended June 30, Six months ended June 30,

2010 2009 2010 2009

Operating revenues

Contract drilling revenues $ 2,290 $ 2,625 $ 4,731 $ 5,459 Contract drilling intangible revenues 29 75 62 179 Other revenues 186 182 314 362

2,505 2,882 5,107 6,000 Costs and expenses

Operating and maintenance 1,358 1,277 2,554 2,448 Depreciation, depletion and amortization 400 360 801 715 General and administrative 58 53 121 109

1,816 1,690 3,476 3,272 Loss on impairment — (67 ) (2 ) (288 ) Gain (loss) on disposal of assets, net 268 (4 ) 254 — Operating income 957 1,121 1,883 2,440 Other income (expense), net

Interest income 5 1 10 2 Interest expense, net of amounts capitalized (141 ) (114 ) (273 ) (250 ) Gain (loss) on retirement of debt — (8 ) 2 (10 ) Other, net (3 ) (8 ) 10 —

(139 ) (129 ) (251 ) (258 ) Income before income tax expense 818 992 1,632 2,182 Income tax expense 98 184 227 435 Net income 720 808 1,405 1,747 Net income (loss) attributable to noncontrolling interest 5 2 13 (1 ) Net income attributable to controlling interest $ 715 $ 806 $ 1,392 $ 1,748

Earnings per share

Basic $ 2.23 $ 2.50 $ 4.32 $ 5.43 Diluted $ 2.22 $ 2.49 $ 4.31 $ 5.42

Weighted average shares outstanding

Basic 319 320 320 320 Diluted 320 321 321 321

TRANSOCEAN LTD. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions) (Unaudited)



2010 2009 2010 2009

Net income $ 720 $ 808 $ 1,405 $ 1,747 Other comprehensive income (loss) before income taxes

Unrecognized components of net periodic benefit cost — — (10 ) (39 ) Recognized components of net periodic benefit cost 3 5 9 9 Unrealized gain (loss) on derivative instruments (11 ) 10 (17 ) 9 Other, net (3 ) 1 (3 ) —

Other comprehensive income (loss) before income taxes (11 ) 16 (21 ) (21 ) Income taxes related to other comprehensive income (loss) (1 ) (6 ) (1 ) 3 Other comprehensive income (loss), net of income taxes (12 ) 10 (22 ) (18 ) Total comprehensive income 708 818 1,383 1,729 Total comprehensive income (loss) attributable to noncontrolling interest (9 ) 13 (8 ) 10 Total comprehensive income attributable to controlling interest $ 717 $ 805 $ 1,391 $ 1,719

TRANSOCEAN LTD. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share data)


June 30,

2010 December 31,

2009

(Unaudited)

Assets Cash and cash equivalents $ 2,888 $ 1,130 Accounts receivable, net of allowance for doubtful accounts

of $41 and $65 at June 30, 2010 and December 31, 2009, respectively 2,254 2,385 Materials and supplies, net of allowance for obsolescence

of $66 at June 30, 2010 and December 31, 2009 467 462 Deferred income taxes, net 121 104 Assets held for sale — 186 Other current assets 184 209

Total current assets 5,914 4,476 Property and equipment 27,377 27,383 Property and equipment of consolidated variable interest entities 2,179 1,968 Less accumulated depreciation 7,034 6,333

Property and equipment, net 22,522 23,018 Goodwill 8,132 8,134 Other assets 984 808

Total assets $ 37,552 $ 36,436

Liabilities and equity Accounts payable $ 968 $ 780 Accrued income taxes 154 240 Debt due within one year 1,580 1,568 Debt of consolidated variable interest entities due within one year 82 300 Other current liabilities 1,884 730

Total current liabilities 4,668 3,618 Long-term debt 8,862 8,966 Long-term debt of consolidated variable interest entities 902 883 Deferred income taxes, net 710 726 Other long-term liabilities 1,683 1,684

Total long-term liabilities 12,157 12,259 Commitments and contingencies Shares, CHF 15.00 par value, 502,852,947 authorized, 167,617,649 conditionally authorized,

335,235,298 issued at June 30, 2010 and December 31, 2009; 318,916,207 and 321,223,882 outstanding at June 30, 2010 and December 31, 2009, respectively 4,479 4,472

Additional paid-in capital 6,421 7,407 Treasury shares, at cost, 2,863,267 and none held at June 30, 2010 and December 31, 2009, respectively (240 ) — Retained earnings 10,400 9,008 Accumulated other comprehensive loss (336 ) (335 )

Total controlling interest shareholders’ equity 20,724 20,552 Noncontrolling interest 3 7

Total equity 20,727 20,559 Total liabilities and equity $ 37,552 $ 36,436

TRANSOCEAN LTD. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF EQUITY



Six months ended June 30, 2010 2009 Shares outstanding

Balance, beginning of period 321 319

Issuance of shares under share-based compensation plans 1 2

Purchases of shares held in treasury (3 ) —

Balance, end of period 319 321

Shares Balance, beginning of period $ 4,472 $ 4,444

Issuance of shares under share-based compensation plans 7 24

Balance, end of period $ 4,479 $ 4,468

Additional paid-in capital Balance, beginning of period $ 7,407 $ 7,313

Share-based compensation expense 53 43

Issuance of shares under share-based compensation plans (9 ) 16

Obligation for cash distribution (1,024 ) —

Repurchases of convertible senior notes — 16

Changes in ownership of noncontrolling interest and other, net (6 ) —


Treasury shares, at cost Balance, beginning of period $ — $ —


Balance, end of period $ (240 ) $ —

Retained earnings Balance, beginning of period $ 9,008 $ 5,827

Net income attributable to controlling interest 1,392 1,748


Accumulated other comprehensive loss Balance, beginning of period $ (335 ) $ (420 )

Other comprehensive loss attributable to controlling interest (1 ) (29 )

Balance, end of period $ (336 ) $ (449 )

Total controlling interest shareholders’ equity Balance, beginning of period $ 20,552 $ 17,164

Total comprehensive income attributable to controlling interest 1,391 1,719





Repurchases of convertible senior notes — 16



Total noncontrolling interest

Balance, beginning of period $ 7 $ 3

Net income (loss) attributable to noncontrolling interest 13 (1 )

Other comprehensive income (loss) attributable to noncontrolling interest (21 ) 11

Changes in ownership of noncontrolling interest 4 —

Balance, end of period $ 3 $ 13

Total equity

Balance, beginning of period $ 20,559 $ 17,167

Total comprehensive income 1,383 1,729





Repurchases of convertible notes — 16



TRANSOCEAN LTD. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS




2010 2009 2010 2009

Cash flows from operating activities Net income $ 720 $ 808 $ 1,405 $ 1,747 Adjustments to reconcile net income to net cash provided by operating

activities Amortization of drilling contract intangibles (29 ) (75 ) (62 ) (179 ) Depreciation, depletion and amortization 400 360 801 715 Share-based compensation expense 18 24 53 43 Excess tax benefit from share-based compensation plans (1 ) — (1 ) (1 ) (Gain) loss on disposal of assets, net (268 ) 4 (254 ) — Loss on impairment — 67 2 288 (Gain) loss on retirement of debt — 8 (2 ) 10 Amortization of debt issue costs, discounts and premiums, net 51 57 100 109 Deferred income taxes (12 ) 20 (34 ) 26 Other, net (6 ) 14 (1 ) 23 Deferred revenue, net 7 49 158 43 Deferred expenses, net (23 ) (37 ) (37 ) (35 ) Changes in operating assets and liabilities 412 277 313 228

Net cash provided by operating activities 1,269 1,576 2,441 3,017 Cash flows from investing activities

Capital expenditures (300 ) (947 ) (679 ) (1,655 ) Proceeds from disposal of assets, net 10 — 51 8 Proceeds from insurance recoveries for loss of drilling unit 560 — 560 — Proceeds from payments on notes receivable 11 — 21 — Proceeds from short-term investments — 172 5 393 Purchases of short-term investments — (234 ) — (234 ) Joint ventures and other investments, net (1 ) — (1 ) —

Net cash provided by (used in) investing activities 280 (1,009 ) (43 ) (1,488 ) Cash flows from financing activities

Change in short-term borrowings, net (46 ) (476 ) (177 ) (500 ) Proceeds from debt — 231 54 319 Repayments of debt (22 ) (708 ) (275 ) (1,410 ) Payments for warrant exercises, net — (13 ) — (13 ) Purchases of shares held in treasury (180 ) — (240 ) — Proceeds from (taxes paid for) share-based compensation plans, net 3 5 (1 ) 22 Excess tax benefit from share-based compensation plans 1 — 1 1 Other, net (3 ) (1 ) (2 ) (4 )

Net cash used in financing activities (247 ) (962 ) (640 ) (1,585 ) Net increase (decrease) in cash and cash equivalents 1,302 (395 ) 1,758 (56 ) Cash and cash equivalents at beginning of period 1,586 1,302 1,130 963 Cash and cash equivalents at end of period $ 2,888 $ 907 $ 2,888 $ 907

TRANSOCEAN LTD. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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Note 1—Nature of Business Transocean Ltd. (together with its subsidiaries and predecessors, unless the context requires otherwise, “Transocean,” the

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

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

Note 2—Significant Accounting Policies Basis of presentation—We have prepared our accompanying condensed consolidated financial statements without audit in

accordance with accounting principles generally accepted in the United States (“U.S.”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the U.S. Securities and Exchange Commission (“SEC”). Pursuant to such rules and regulations, these financial statements do not include all disclosures required by accounting principles generally accepted in the U.S. for complete financial statements. The condensed consolidated financial statements reflect all adjustments, which are, in the opinion of management, necessary for a fair presentation of financial position, results of operations and cash flows for the interim periods. Such adjustments are considered to be of a normal recurring nature unless otherwise identified. Operating results for the three and six months ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010 or for any future period. The accompanying condensed consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2009.

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

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

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

TRANSOCEAN LTD. AND SUBSIDIARIES NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(Unaudited)

- 7 -

Share-based compensation—Share-based compensation expense was $18 million and $53 million for the three and six months ended June 30, 2010, respectively. Share-based compensation expense was $24 million and $43 million for the three and six months ended June 30, 2009, respectively.

Capitalized interest—We capitalize interest costs for qualifying construction and upgrade projects. We capitalized interest costs on construction work in progress of $19 million and $47 million for the three and six months ended June 30, 2010, respectively. We capitalized interest costs on construction work in progress of $49 million and $95 million for the three and six months ended June 30, 2009, respectively.

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

Subsequent events—We evaluate subsequent events through the time of our filing on the date we issue our financial statements. See Note 15—Subsequent Events.

Note 3—New Accounting Pronouncements

Recently adopted accounting standards

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

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

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

Recently issued accounting standards

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


(Unaudited)

- 8 -

Note 4—Variable Interest Entities Consolidated variable interest entities—TPDI and ADDCL, two joint venture companies in which we hold interests, were

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

June 30, 2010 December 31, 2009

Assets Liabilities Net carrying

amount Assets Liabilities Net carrying

amount

Variable interest entity TPDI $ 1,600 $ 806 $ 794 $ 1,500 $ 763 $ 737 ADDCL 825 319 506 582 482 100

Total $ 2,425 $ 1,125 $ 1,300 $ 2,082 $ 1,245 $ 837

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

In connection with the sale, we accepted payment in the form of cash and two notes receivable, which are secured by the drilling units, with an aggregate principal amount of $165 million. The notes receivable have stated interest rates of 9 percent and are payable in scheduled quarterly installments of principal and interest through maturity in January 2015. We have also committed to provide ADL with a working capital loan, which is also secured by the drilling units, with a maximum borrowing amount of $35 million. Additionally, we continue to operate GSF Arctic IV under a short-term bareboat charter with ADL through October 2010. At June 30, 2010, the notes receivable and working capital loan receivable represented aggregate carrying amounts of $120 million and $1 million, respectively, which together represents our maximum exposure to loss.

Note 5—Impairments Goodwill—During the six months ended June 30, 2010, we recognized a loss on impairment of goodwill associated with our oil

and gas properties in the amount of $2 million ($0.01 per diluted share), which had no tax effect. The carrying amount of goodwill associated with our oil and gas properties reporting unit was $2 million at December 31, 2009.

Definite-lived intangible assets—During the six months ended June 30, 2009, we determined that the customer relationships intangible asset associated with our drilling management services was impaired due to market conditions in that reporting unit resulting from the global economic downturn and continued pressure on commodity prices. We estimated the fair value of the customer relationships intangible asset using the excess earnings method, a generally accepted valuation methodology that applies the income approach. Our valuation required us to project the future performance of the drilling management services unit based on unobservable inputs that require significant judgment for which there is little or no market data, including assumptions for future commodity prices, projected demand for our services, rig availability and dayrates. As a result of our impairment testing, we determined that the carrying amount of the asset exceeded its fair value and recognized a loss on impairment of $9 million ($0.03 per diluted share), which had no tax effect, during the three and six months ended June 30, 2009. The carrying amount of the customer relationship intangible asset associated with our drilling management services, recorded in other assets on our condensed consolidated balance sheets, was $62 million and $64 million at June 30, 2010 and December 31, 2009, respectively.

Assets held for sale—During the six months ended June 30, 2009, we determined that GSF Arctic II and GSF Arctic IV, both previously classified as assets held for sale, were impaired due to the global economic downturn and pressure on commodity prices, both of which have had an adverse effect on our industry. We estimated the fair values of these rigs based on an exchange price that would be received for the assets in the principal or most advantageous market for the assets in an orderly transaction between market


(Unaudited)

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participants as of the measurement date and considering our undertakings to the Office of Fair Trading in the U.K. (“OFT”) that required the sale of the rigs with certain limitations and in a limited amount of time. We based our estimates on unobservable inputs that require significant judgment, for which there is little or no market data, including non-binding price quotes from unaffiliated parties, considering the then-current market conditions and restrictions imposed by the OFT. As a result of our evaluation, we recognized losses on impairment of $58 million ($0.18 per diluted share) and $279 million ($0.87 per diluted share), which had no tax effect, for the three and six months ended June 30, 2009, respectively. The carrying amount of assets held for sale was $186 million at December 31, 2009, and these assets were sold in the six months ended June 30, 2010. See Note 8—Drilling Fleet.

Note 6—Income Taxes Overview—Transocean Ltd., a holding company and Swiss resident, is exempt from cantonal and communal income tax in

Switzerland, but is subject to Swiss federal income tax. At the federal level, qualifying net dividend income and net capital gains on the sale of qualifying investments in subsidiaries are exempt from Swiss federal income tax. Consequently, Transocean Ltd. expects dividends from its subsidiaries and capital gains from sales of investments in its subsidiaries to be exempt from Swiss federal income tax.

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

Our estimated annual effective tax rates for the six months ended June 30, 2010 and June 30, 2009 were 15.5 percent and 15.4 percent, respectively. These rates were based on projected annual income before income taxes for each period after adjusting for certain items, such as impairment losses, the gain resulting from the insurance recoveries on the loss of Deepwater Horizon and various other discrete items.

We record a valuation allowance for deferred tax assets, including those resulting from net operating losses, when it is more likely than not that we will not realize some or all of the benefit from the deferred tax assets. At June 30, 2010 and December 31, 2009, the valuation allowance for non-current deferred tax assets was $70 million and $69 million, respectively.

Tax returns—We file federal and local tax returns in several jurisdictions throughout the world. With few exceptions, we are no longer subject to examinations of our U.S. and non-U.S. tax matters for years prior to 1999. For the six months ended June 30, 2010 and June 30, 2009, the amount of current tax benefit recognized from the settlement of disputes with tax authorities and from the expiration of statutes of limitations was insignificant.

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 30,

2010 December 31,

2009 Unrecognized tax benefits, excluding interest and penalties $ 457 $ 460 Interest and penalties 209 200

Unrecognized tax benefits, including interest and penalties $ 666 $ 660

Our tax returns in the other major jurisdictions in which we operate are generally subject to examination for periods ranging from three to six years. We have agreed to extensions beyond the statute of limitations in three major jurisdictions for up to 15 years. Tax authorities in certain jurisdictions are examining our tax returns and in some cases have issued assessments. We are defending our tax positions in those jurisdictions. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate liability to have a material adverse effect on our consolidated statement of financial position, or results of operations, although it may have a material adverse effect on our consolidated cash flows.

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

In May 2010, we received an assessment from the U.S. tax authorities related to our 2006 and 2007 U.S. federal income tax returns. 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.


(Unaudited)

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These two items would result in net adjustments of approximately $278 million of additional taxes, exclusive of interest. An unfavorable outcome on these adjustments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe our returns are materially correct as filed, and we intend to continue to vigorously defend against all such claims.

In addition, the assessment included adjustments related to a series of restructuring transactions that occurred between 2001 and 2004. These restructuring transactions ultimately resulted in the disposition of our interests in our former subsidiary TODCO in 2004 and 2005. The authorities are disputing the amount of capital losses resulting from the disposition of TODCO. We utilized a portion of the capital losses to offset capital gains on the 2006, 2007, 2008 and 2009 tax returns. The majority of the capital losses expired on December 31, 2009. The adjustments would also impact the amount of certain net operating losses and other carryovers into 2006 and later years. The authorities are also contesting the characterization of certain amounts of income received in 2006 and 2007 as capital gain and thus the availability of the capital gain for offset by the capital loss. Claims with respect to our U.S. federal income tax returns for 2006 through 2009 could result in net tax adjustments of approximately $320 million. An unfavorable outcome on these potential adjustments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe that our tax returns are materially correct as filed, and we intend to vigorously defend against any potential claims.

The assessment also included certain claims with respect to withholding taxes and certain other items resulting in net tax adjustments of approximately $182 million, exclusive of interest. In addition, the tax authorities assessed penalties associated with the various tax adjustments in the aggregate amount of approximately $92 million, exclusive of interest. We believe that our tax returns are materially correct as filed, and we intend to vigorously defend against any potential claims.

Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 2001 and 2002 as well as the actions of certain of our former external advisors on these transactions. The authorities issued tax assessments of (a) approximately $241 million plus interest, related to certain restructuring transactions, (b) approximately $105 million plus interest, related to the migration of a subsidiary that was previously subject to tax in Norway, (c) approximately $63 million plus interest, related to a 2001 dividend payment and (d) approximately $6 million plus interest, related to certain foreign exchange deductions and dividend withholding tax. We have filed or expect to file appeals to these tax assessments. We may be required to provide some form of financial security, in an amount up to $898 million, including interest and penalties, for these assessed amounts as this dispute is appealed and addressed by the Norwegian courts. The authorities have indicated that they plan to seek penalties of 60 percent on all matters. For these matters, we believe our returns are materially correct as filed, and we have and will continue to respond to all information requests from the Norwegian authorities. We intend to vigorously contest any assertions by the Norwegian authorities in connection with the various transactions being investigated.

During the six months ended June 30, 2010, our long-term liability for unrecognized tax benefits related to these Norwegian tax issues decreased $12 million to $169 million due to the accrual of interest being offset by favorable exchange rate fluctuations. An unfavorable outcome on these Norwegian civil tax matters could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate resolution of these matters to have a material adverse effect on our consolidated financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows.

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

Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. The Brazilian tax authorities have issued tax assessments totaling $109 million, plus a 75 percent penalty of $82 million and $102 million of interest through June 30, 2010. An unfavorable outcome on these proposed assessments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008, and we are currently engaged in the appeals process.


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Note 7—Earnings Per Share The reconciliation of the numerator and denominator used for the computation of basic and diluted earnings per share is as

follows (in millions, except per share data):


2010 2009 2010 2009 Basic Diluted Basic Diluted Basic Diluted Basic Diluted

Numerator for earnings per share Net income attributable to controlling interest $ 715 $ 715 $ 806 $ 806 $ 1,392 $ 1,392 $ 1,748 $ 1,748 Undistributed earnings allocable to participating securities (4 ) (5 ) (5 ) (5 ) (8 ) (8 ) (10 ) (10 )

Net income available to shareholders $ 711 $ 710 $ 801 $ 801 $ 1,384 $ 1,384 $ 1,738 $ 1,738

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

Weighted-average shares for per share calculation 319 320 320 321 320 321 320 321

Earnings per share $ 2.23 $ 2.22 $ 2.50 $ 2.49 $ 4.32 $ 4.31 $ 5.43 $ 5.42

For the three and six months ended June 30, 2010, 2.3 million and 1.6 million share-based awards, respectively, were excluded from the calculation since the effect would have been anti-dilutive. For the three and six months ended June 30, 2009, 1.9 million and 2.9 million share-based awards, respectively, were excluded from the calculation since the effect would have been anti-dilutive.

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

Note 8—Drilling Fleet Expansion—Construction work in progress, recorded in property and equipment, was $2.6 billion and $3.7 billion at June 30,

2010 and December 31, 2009, respectively. The following table presents actual capital expenditures and other capital additions, including capitalized interest, for our remaining major construction projects (in millions):

Six months ended

June 30, 2010

Through December 31,

2009 Total costs

Discoverer Luanda (a) $ 160 $ 535 $ 695

Deepwater Champion (b) 56 527 583

Discoverer India 50 541 591

Dhirubhai Deepwater KG2 (c) (d) 33 641 674

Discover Inspiration (c) 7 667 674 Capitalized interest 47 183 230

Mobilization costs 36 19 55

Total $ 389 $ 3,113 $ 3,502

__________________________

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

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

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

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


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

Dispositions—During the six months ended June 30, 2010, we completed the sale of two Midwater Floaters, GSF Arctic II and GSF Arctic IV. In connection with the sale, we received net cash proceeds of $38 million and non-cash proceeds in the form of two notes receivable in the aggregate amount of $165 million. The notes receivable, which are secured by the drilling units, have stated interest rates of 9 percent and are payable in scheduled quarterly installments of principal and interest through maturity in January 2015. We estimated the fair values of the notes receivable based on unobservable inputs that require significant judgment, for which there is little or no market data, including the credit rating of the buyer. We continue to operate GSF Arctic IV under a short-term bareboat charter with the new owner of the vessel through October 2010. As a result of the sale, we recognized a loss on disposal of assets in the amount of $15 million ($0.04 per diluted share), which had no tax effect for the six months ended June 30, 2010. For the three and six months ended June 30, 2010, we recognized gains on disposal of other unrelated assets in the amounts of $1 million and $2 million, respectively.

During the six months ended June 30, 2009, we received net proceeds of $8 million in connection with our sale of Sedco 135-D and disposals of other unrelated property and equipment, and these disposals had no net effect on income taxes or net income. During the three months ended June 30, 2009, we recognized a loss on disposal of assets of $4 million ($0.01 per diluted share), which had no tax effect.

Deepwater Horizon—On April 22, 2010, the Ultra-Deepwater Floater Deepwater Horizon sank after a blowout of the Macondo well caused a fire and explosion on the rig. The rig had an insured value of $560 million, which was not subject to a deductible, and our insurance underwriters have declared the vessel a total loss. During the three months ended June 30, 2010, we received $560 million in cash proceeds from insurance recoveries related to the loss of the drilling unit and, for the three and six months ended June 30, 2010, we recognized a gain on the loss of the rig in the amount of $267 million ($0.83 per diluted share), which had no tax effect. See Note 12—Contingencies.


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Note 9—Debt Our debt, net of unamortized discounts, premiums and fair value adjustments, was comprised of the following (in millions):

June 30, 2010 December 31, 2009

Transocean Ltd. and

subsidiaries

Consolidated variable interest entities

Consolidated total

Transocean Ltd. and

subsidiaries


Consolidated total

ODL Loan Facility $ 10 $ — $ 10 $ 10 $ — $ 10 Commercial paper program (a) 104 — 104 281 — 281 6.625% Notes due April 2011 (a) 168 — 168 170 — 170 5% Notes due February 2013 254 — 254 247 — 247 5.25% Senior Notes due March 2013 (a) 509 — 509 496 — 496 TPDI Credit Facilities due March 2015 — 595 595 — 581 581 ADDCL Credit Facilities due August 2017 — 241 241 — 454 454 TPDI Notes due October 2019 — 148 148 — 148 148 6.00% Senior Notes due March 2018 (a) 997 — 997 997 — 997 7.375% Senior Notes due April 2018 (a) 247 — 247 247 — 247 Capital lease obligation due July 2026 — — — 15 — 15 8% Debentures due April 2027 (a) 57 — 57 57 — 57 7.45% Notes due April 2027 (a) 96 — 96 96 — 96 7% Senior Notes due June 2028 312 — 312 313 — 313 Capital lease contract due August 2029 703 — 703 711 — 711 7.5% Notes due April 2031 (a) 598 — 598 598 — 598 1.625% Series A Convertible Senior Notes due December 2037 (a) 1,281 — 1,281 1,261 — 1,261 1.50% Series B Convertible Senior Notes due December 2037 (a) 2,093 — 2,093 2,057 — 2,057 1.50% Series C Convertible Senior Notes due December 2037 (a) 2,014 — 2,014 1,979 — 1,979 6.80% Senior Notes due March 2038 (a) 999 — 999 999 — 999

Total debt 10,442 984 11,426 10,534 1,183 11,717 Less debt due within one year

ODL Loan Facility 10 — 10 10 — 10 Commercial paper program (a) 104 — 104 281 — 281 6.625% Notes due April 2011 (a) 168 — 168 — — — TPDI Credit Facilities due March 2015 — 70 70 — 52 52 ADDCL Credit Facilities due August 2017 — 12 12 — 248 248 Capital lease contract due August 2029 17 — 17 16 — 16 1.625% Series A Convertible Senior Notes due December 2037 (a) 1,281 — 1,281 1,261 — 1,261

Total debt due within one year 1,580 82 1,662 1,568 300 1,868

Total long-term debt $ 8,862 $ 902 $ 9,764 $ 8,966 $ 883 $ 9,849 __________________________

(a) Transocean Inc., a wholly owned subsidiary of Transocean Ltd., is the issuer of the notes and debentures, which have been guaranteed by Transocean Ltd. Transocean Ltd. has also guaranteed borrowings under the commercial paper program and the Five-Year Revolving Credit Facility. Transocean Ltd. has no independent assets or operations, its guarantee of debt securities of Transocean Inc. is full and unconditional and its only other subsidiaries not owned indirectly through Transocean Inc. are minor. Transocean Ltd. is not subject to any significant restrictions on its ability to obtain funds from its consolidated subsidiaries or entities accounted for under the equity method by dividends, loans or return of capital distributions.


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

Transocean Ltd.

and subsidiaries


Consolidated total

Twelve months ending June 30, 2011 $ 1,595 $ 82 $ 1,677 2012 2,218 96 2,314 2013 2,969 98 3,067 2014 21 99 120 2015 23 346 369 Thereafter 3,909 263 4,172

Total debt, excluding unamortized discounts, premiums and fair value adjustments 10,735 984 11,719

Total unamortized discounts, premiums and fair value adjustments (293 ) — (293 ) Total debt $ 10,442 $ 984 $ 11,426

Commercial paper program—We maintain a commercial paper program, which is supported by the Five-Year Revolving Credit Facility, under which we may issue privately placed, unsecured commercial paper notes for general corporate purposes up to a maximum aggregate outstanding amount of $1.5 billion. At June 30, 2010, $104 million in commercial paper was outstanding at a weighted-average interest rate of 0.5 percent, excluding commissions.

Five-Year Revolving Credit Facility—We have a $2.0 billion, five-year revolving credit facility under the Five-Year Revolving Credit Facility Agreement dated November 27, 2007, as amended (the “Five-Year Revolving Credit Facility”). Throughout the term of the Five-Year Revolving Credit Facility, we pay a facility fee on the daily amount of the underlying commitment, whether used or unused, which ranges from 0.10 percent to 0.30 percent and was 0.15 percent at June 30, 2010. At June 30, 2010, we had $81 million in letters of credit issued and outstanding and no borrowings outstanding under the Five-Year Revolving Credit Facility.

TPDI Credit Facilities—TPDI has a bank credit agreement for a $1.265 billion secured credit facility (the “TPDI Credit Facilities”) comprised of a $1.0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, which was established to finance the construction of and is secured by Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the secured term loan with an aggregate commitment of $595 million. At June 30, 2010, $1.2 billion was outstanding under the TPDI Credit Facilities, of which $577 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate on June 30, 2010 was 2.1 percent. See Note 10—Derivatives and Hedging.

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

TPDI Notes—TPDI has issued promissory notes (the “TPDI Notes”) payable to its two shareholders, Pacific Drilling and one of our subsidiaries, which have maturities through October 2019. At June 30, 2010, the aggregate outstanding principal amount was $296 million, of which $148 million was due to one of our subsidiaries and has been eliminated in consolidation. The weighted-average interest rate on June 30, 2010 was 2.4 percent.

ADDCL Credit Facilities—ADDCL has a senior secured bank credit agreement for a credit facility (the “ADDCL Primary Loan Facility”) comprised of Tranche A, Tranche B and Tranche C for $215 million, $270 million and $399 million, respectively, which was established to finance the construction of and is secured by Discoverer Luanda. Unaffiliated financial institutions provide the commitment for and the borrowings under Tranche A. One of our subsidiaries provides the commitment for and the borrowings under Tranche C. In March 2010, ADDCL terminated Tranche B, having repaid borrowings of $235 million under Tranche B using borrowings under Tranche C. At June 30, 2010, $215 million was outstanding under Tranche A at a weighted-average interest rate of 0.8 percent. At June 30, 2010, $399 million was outstanding under Tranche C, which was eliminated in consolidation.

Additionally, ADDCL has a secondary bank credit agreement for a $90 million credit facility (the “ADDCL Secondary Loan Facility”), for which one of our subsidiaries provides 65 percent of the total commitment. At June 30, 2010, $75 million was outstanding under the ADDCL Secondary Loan Facility, of which $49 million was provided by one of our subsidiaries and has been eliminated in consolidation. The weighted-average interest rate on June 30, 2010 was 3.7 percent.


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

1.625% Series A, 1.50% Series B and 1.50% Series C Convertible Senior Notes—The carrying amounts of the liability components of the Convertible Senior Notes were as follows (in millions):

June 30, 2010 December 31, 2009

Principal amount

Unamortized discount

Carrying amount

Principal amount

Unamortized discount

Carrying amount

Carrying amount of liability component Series A Convertible Senior Notes due 2037 $ 1,299 $ (18 ) $ 1,281 $ 1,299 $ (38 ) $ 1,261 Series B Convertible Senior Notes due 2037 2,200 (107 ) 2,093 2,200 (143 ) 2,057 Series C Convertible Senior Notes due 2037 2,200 (186 ) 2,014 2,200 (221 ) 1,979

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

June 30,

2010 December 31,

2009

Carrying amount of equity component Series A Convertible Senior Notes due 2037 $ 215 $ 215 Series B Convertible Senior Notes due 2037 275 275 Series C Convertible Senior Notes due 2037 352 352

Including the amortization of the unamortized discount, the effective interest rates were 4.88 percent for the Series A Notes, 5.08 percent for the Series B Notes, and 5.28 percent for the Series C Notes. At June 30, 2010, the remaining period over which the discount will be amortized was less than a year for the Series A Notes, 1.5 years for the Series B Notes and 2.5 years for the Series C Notes. Interest expense, excluding amortization of debt issue costs, was as follows (in millions):

Three months ended

June 30, Six months ended

June 30,

2010 2009 2010 2009

Interest expense

Series A Convertible Senior Notes due 2037 $ 15 $ 22 $ 30 $ 47 Series B Convertible Senior Notes due 2037 26 25 52 50 Series C Convertible Senior Notes due 2037 26 25 52 50

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

During the six months ended June 30, 2010, we did not repurchase any of the Convertible Senior Notes. During the six months ended June 30, 2009, we repurchased an aggregate principal amount of $440 million of the 1.625% Series A Notes for an aggregate cash payment of $410 million. During the three and six months ended June 30, 2009, respectively, we recognized a loss on retirement of $8 million ($0.03 per diluted share), with no tax effect, and $10 million ($0.03 per diluted share), with no tax effect, associated with the debt component of the 1.625% Series A Notes and recorded additional paid-in capital of $10 million and $16 million associated with the equity component of the 1.625% Series A Notes.

Note 10—Derivatives and Hedging Cash flow hedges—TPDI has entered into interest rate swaps, which have been designated and have qualified as a cash flow

hedge, to reduce the variability of cash interest payments associated with the variable-rate borrowings under the TPDI Credit Facilities. The aggregate notional amount corresponds with the aggregate outstanding amount of the borrowings under the TPDI Credit Facilities. As of June 30, 2010, the aggregate notional amount was $1.2 billion, of which $577 million was attributable to the intercompany borrowings provided by one of our subsidiaries and the related balances have been eliminated in consolidation. At June 30, 2010, the weighted-average variable interest rate associated with the interest rate swaps was 0.3 percent, and the weighted-average fixed interest rate was 2.3 percent. At June 30, 2010, the interest rate swaps represented a liability measured at a fair value of $13 million, recorded in


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other long-term liabilities, with a corresponding increase to accumulated other comprehensive loss. At December 31, 2009, the interest rate swaps represented an asset measured at a fair value of $5 million, recorded in other assets, and a liability measured at a fair value of less than $1 million, recorded in other long-term liabilities, with a corresponding net decrease to accumulated other comprehensive loss. The amount associated with the ineffective portion of the cash flow hedges was less than $1 million, recorded in interest expense for the three and six months ended June 30, 2010. There was no ineffectiveness for the three and six months ended June 30, 2009.

Fair value hedges—Two of our wholly owned subsidiaries have entered into interest rate swaps, which are designated and have qualified as fair value hedges, to reduce our exposure to changes in the fair values of the 5.25% Senior Notes and the 5.00% Notes. The interest rate swaps have aggregate notional amounts of $500 million and $250 million, respectively, equal to the face values of the hedged instruments and have stated maturities that coincide with those of the hedged instruments. We have determined that the hedging relationships qualify for, and we have applied, the shortcut method of accounting, under which the interest rate swaps are considered to have no ineffectiveness and no ongoing assessment of effectiveness is required. At June 30, 2010, the weighted-average variable interest rate on the interest rate swaps was 3.7 percent, and the fixed interest rates matched those of the underlying debt instruments. At June 30, 2010, the interest rate swaps represented an asset measured at fair value of $14 million, recorded in other assets, with a corresponding increase to the carrying amounts of the underlying debt instruments. At December 31, 2009, the interest rate swaps represented a liability measured at a fair value of $4 million, recorded in other long-term liabilities, with a corresponding decrease to the carrying amount of the underlying debt instrument.

Note 11—Postemployment Benefit Plans Defined benefit pension plans and other postretirement employee benefit plans—We have several defined benefit

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

Three months ended June 30, 2010 Three months ended June 30, 2009

U.S.

Plans Non-U.S.

Plans OPEB Plans Total

U.S. Plans

Non-U.S. Plans

OPEB Plans Total

Net periodic benefit costs Service cost $ 11 $ 4 $ 1 $ 16 $ 11 $ 4 $ 1 $ 16 Interest cost 14 5 — 19 13 4 — 17 Expected return on plan assets (15 ) (3 ) — (18 ) (14 ) (4 ) — (18 ) Settlements and curtailments 2 — — 2 — — — — Actuarial losses, net 3 1 — 4 5 — — 5 Prior service cost, net (1 ) — — (1 ) (1 ) 1 — —

Net periodic benefit costs $ 14 $ 7 $ 1 $ 22 $ 14 $ 5 $ 1 $ 20

Funding contributions $ 49 $ 4 $ 1 $ 54 $ 45 $ — $ 1 $ 46

Six months ended June 30, 2010 Six months ended June 30, 2009

U.S.

Plans Non-U.S.

Plans OPEB Plans Total

U.S. Plans

Non-U.S. Plans

OPEB Plans Total

Net periodic benefit costs Service cost $ 21 $ 10 $ 1 $ 32 $ 22 $ 8 $ 1 $ 31 Interest cost 27 8 1 36 25 8 1 34 Expected return on plan assets (29 ) (8 ) — (37 ) (27 ) (7 ) — (34 ) Settlements and curtailments 2 1 — 3 2 — — 2 Actuarial losses, net 7 4 — 11 9 — — 9 Prior service cost, net (1 ) — (1 ) (2 ) (1 ) 1 — —

Net periodic benefit costs $ 27 $ 15 $ 1 $ 43 $ 30 $ 10 $ 2 $ 42

Funding contributions $ 51 $ 8 $ 3 $ 62 $ 47 $ 1 $ 2 $ 50


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Severance plan—Following our merger with GlobalSantaFe in 2007, we established a plan to consolidate operations and administrative functions and identified 377 employees that were involuntarily terminated pursuant to this plan. We recognized $5 million and $8 million of severance expense, recorded in either operating and maintenance expense or general and administrative expense and paid $13 million and $9 million in severance payments under this plan in the six months ended June 30, 2010 and June 30, 2009, respectively. No additional expense will be recognized under the severance plan, which expired in January 2010. The liability associated with the severance plan, recorded in other current liabilities, was $9 million and $17 million at June 30, 2010 and December 31, 2009, respectively. Since the severance plan’s inception in 2007, we have paid $66 million in termination benefits under the plan.

Note 12—Contingencies

Macondo well incident

Overview—On April 22, 2010, the Ultra-Deepwater Floater Deepwater Horizon sank after a blowout of the Macondo well caused a fire and explosion on the rig. Eleven persons have been 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. (“BP”).

As we continue to investigate the cause or causes of the incident, we are evaluating its consequences. Although we cannot predict the final outcome or estimate the reasonably possible range of loss with certainty, as of June 30, 2010, we have recognized a liability of approximately $80 million, recorded in other current liabilities on our condensed consolidated balance sheet based on estimated losses related to the incident that we believe are probable and for which a reasonable estimate can be made. We believe that a portion of this liability may be recoverable from insurance. New information or future developments could require us to adjust our disclosures and our estimated liabilities and insurance recoveries. See “—Retained risk” and “—Contractual indemnity.”

Litigation—As of June 30, 2010, 206 actions or claims have been filed against Transocean entities, along with other unaffiliated defendants, in state and federal courts. Additionally, government agencies have initiated investigations into the Macondo well incident. We have categorized below the nature of the legal actions or claims. We are evaluating all claims and intend to vigorously defend any claims and pursue any and all defenses available. In addition, we believe we are entitled to contractual defense and indemnity for all wrongful death and personal injury claims made by non-employees and third-party subcontractors’ employees as well as all liabilities for pollution or contamination, other than for pollution or contamination originating on or above the surface of the water. See “—Contractual indemnity.”

Wrongful death and personal injury—Since April 2010, we and one or more of our subsidiaries have been named, along with other unaffiliated defendants, in eight complaints that were filed in state and federal courts in Louisiana and Texas involving multiple plaintiffs that allege wrongful death and other personal injuries arising out of the Macondo well incident. The complaints generally allege negligence and seek awards of unspecified economic damages and punitive damages. BP p.l.c., MI-SWACO and Weatherford Ltd. have, based on contractual arrangements, also made indemnity demands upon us with respect to personal injury and wrongful death claims asserted by our employees or representatives of our employees against these entities. See “—Contractual indemnity.”

Economic loss—Since April 2010, we and one or more of our subsidiaries have been named, along with other unaffiliated defendants, in 50 individual complaints as well as 139 putative class-action complaints filed in the federal and state courts in Louisiana, Texas, Mississippi, Alabama, Georgia, Kentucky, South Carolina, Tennessee, Colorado and possibly other courts. The complaints generally allege, among other things, potential economic losses as a result of environmental pollution arising out of the Macondo well incident and are based primarily on the Oil Pollution Act of 1990 (“OPA”) and state OPA analogues. See “—Environmental matters.” One complaint also alleges a violation of the Racketeer Influenced and Corrupt Organizations Act. The plaintiffs are generally seeking awards of unspecified economic, compensatory and punitive damages, as well as injunctive relief. See “—Contractual indemnity.”

Federal securities claims—Since April 2010, three federal securities law class actions have been filed naming us and certain of our officers and directors as defendants, two of which were filed in the United States District Court, Southern District of New York, and one of which was filed in the United States District Court, Eastern District of Louisiana. These actions generally allege violations of Section 10(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 10b5 promulgated under the Exchange Act and Section 20(a) of the Exchange Act in connection with the Macondo well incident. The plaintiffs are generally seeking awards of unspecified economic damages, including damages resulting from the recent decline in our stock price.

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


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

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

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

Other federal statutes—Several of the claimants have made assertions under other statutes, including the Clean Water Act, the Endangered Species Act, the Migratory Bird Treaty Act and the Clean Air Act.

State environmental laws—As of June 30, 2010, claims have been asserted by private claimants under state environmental statutes in Florida, Louisiana and Mississippi. As described below, the only claim currently asserted by a state government is pending in Louisiana.

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

By letter dated May 5, 2010, the Attorneys General of the five Gulf Coast states of Alabama, Florida, Louisiana, Mississippi and Texas informed us that they intend to seek recovery of pollution clean up costs and related damages arising from the Macondo well incident. In addition, by letter dated June 21, 2010, the Attorneys General of the 11 Atlantic Coast states of Connecticut, Delaware, Georgia, Maine, Maryland, Massachusetts, New Hampshire, New York, North Carolina, Rhode Island and South Carolina informed us that their states have not sustained any damage from the Macondo well incident but they would like assurances that we will be responsible financially if damages are sustained. We responded to each letter from the Attorneys General and indicated that we intend to fulfill our obligations as a responsible party for any discharge of oil from Deepwater Horizon on or above the surface of the water, and we assume that the operator will similarly fulfill its obligations under OPA for the ongoing discharge from the undersea well.

Wreck removal—We may be requested to remove the diesel fuel from the wreckage, if it is present, as well as various forms of debris from Deepwater Horizon. We have insurance coverage for wreck removal for up to 25 percent of Deepwater Horizon’s insured value, or $140 million, with any excess wreck removal liability, generally covered to the extent of our excess liability coverage.

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


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employees, invitees and the employees of our subcontractors while the operator agreed to defend, release and indemnify us for personal injury and death of its employees, invitees and the employees of its other subcontractors (other than us). We have also agreed to defend, release and indemnify the operator for damages to the rig and equipment, including salvage or removal costs.

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

Other legal proceedings

Asbestos litigation—In 2004, several of our subsidiaries were named, along with numerous other unaffiliated defendants, in 21 complaints filed on behalf of 769 plaintiffs in the Circuit Courts of the State of Mississippi and which claimed injuries arising out of exposure to asbestos allegedly contained in drilling mud during these plaintiffs’ employment in drilling activities between 1965 and 1986. A Special Master, appointed to administer these cases pre-trial, subsequently required that each individual plaintiff file a separate lawsuit, and the original 21 multi-plaintiff complaints were then dismissed by the Circuit Courts. The amended complaints resulted in one of our subsidiaries being named as a direct defendant in seven cases. We have or may have an indirect interest in an additional 17 cases. The complaints generally allege that the defendants used or manufactured asbestos-containing products in connection with drilling operations and have included allegations of negligence, products liability, strict liability and claims allowed under the Jones Act and general maritime law. The plaintiffs generally seek awards of unspecified compensatory and punitive damages. In each of these cases, the complaints have named other unaffiliated defendant companies, including companies that allegedly manufactured the drilling-related products that contained asbestos. None of the cases in which one of our subsidiaries is a named defendant has been scheduled for trial in 2010, and the preliminary information available on these claims is not sufficient to determine if there is an identifiable period for alleged exposure to asbestos, whether any asbestos exposure in fact occurred, the vessels potentially involved in the claims, or the basis on which the plaintiffs would support claims that their injuries were related to exposure to asbestos. However, the initial evidence available would suggest that we would have significant defenses to liability and damages. In 2009, two cases that were part of the original 2004 multi-plaintiff suits went to trial in Mississippi against unaffiliated defendant companies which allegedly manufactured drilling-related products containing asbestos. We were not a defendant in either of these cases. One of the cases resulted in a substantial jury verdict in favor of the plaintiff, and this verdict was subsequently vacated by the trial judge on the basis that the plaintiff failed to meet its burden of proof. While the court’s decision is consistent with our general evaluation of the strength of these cases, it has not been reviewed on appeal. The second case resulted in a verdict completely in favor of the defendants. There have been no other trials involving any of the parties to the original 21 complaints. We intend to defend these lawsuits vigorously, although there can be no assurance as to the ultimate outcome. We historically have maintained broad liability insurance, although we are not certain whether insurance will cover the liabilities, if any, arising out of these claims. Based on our evaluation of the exposure to date, we do not expect the liability, if any, resulting from these claims to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

One of our subsidiaries was involved in lawsuits arising out of the subsidiary’s involvement in the design, construction and refurbishment of major industrial complexes. The operating assets of the subsidiary were sold and its operations discontinued in 1989, and the subsidiary has no remaining assets other than the insurance policies involved in its litigation, fundings from settlements with insurers, assigned rights from insurers and “coverage-in-place” settlement agreements with insurers, and funds received from the cancellation of certain insurance policies. The subsidiary has been named as a defendant, along with numerous other companies, in lawsuits alleging personal injury as a result of exposure to asbestos. As of June 30, 2010, the subsidiary was a defendant in approximately 1,062 lawsuits. Some of these lawsuits include multiple plaintiffs and we estimate that there are approximately 2,569 plaintiffs in these lawsuits. For many of these lawsuits, we have not been provided with sufficient information from the plaintiffs to determine whether all or some of the plaintiffs have claims against the subsidiary, the basis of any such claims, or the nature of their alleged injuries. The first of the asbestos-related lawsuits was filed against this subsidiary in 1990. Through June 30, 2010, the amounts expended to resolve claims, including both attorneys’ fees and expenses and settlement costs, have not been material, and all deductibles with respect to the primary insurance have been satisfied. The subsidiary continues to be named as a defendant in additional lawsuits, and we cannot predict the number of additional cases in which it may be named a defendant nor can we predict the potential costs to resolve such additional cases or to resolve the pending cases. However, the subsidiary has in excess of $1 billion in insurance limits potentially available to the subsidiary. Although not all of the policies may be fully available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient funding from settlements and claims payments from insurers, assigned rights from insurers and “coverage-in-place” settlement agreements with insurers to respond to these claims. While we cannot predict or provide assurance as to the final outcome of these matters, we do not believe that the current value of the claims where we have been identified will have a material impact on our consolidated statement of financial position, results of operations or cash flows.


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Rio de Janeiro tax assessment—In the third quarter of 2006, we received tax assessments of approximately $164 million from the state tax authorities of Rio de Janeiro in Brazil against one of our Brazilian subsidiaries for taxes on equipment imported into the state in connection with our operations. The assessments resulted from a preliminary finding by these authorities that our subsidiary’s record keeping practices were deficient. We currently believe that the substantial majority of these assessments are without merit. We filed an initial response with the Rio de Janeiro tax authorities on September 9, 2006 refuting these additional tax assessments. In September 2007, we received confirmation from the state tax authorities that they believe the additional tax assessments are valid, and as a result, we filed an appeal on September 27, 2007 to the state Taxpayer’s Council contesting these assessments. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect it to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

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

Other matters—We are involved in various tax matters and various regulatory matters. We are also involved in lawsuits relating to damage claims arising out of hurricanes Katrina and Rita, all of which are insured and which are not material to us. In addition, as of June 30, 2010, we were involved in a number of other lawsuits, including a dispute for municipal tax payments in Brazil and a dispute involving customs procedures in India, neither of which is material to us, and all of which have arisen in the ordinary course of our business. We do not expect the liability, if any, resulting from these other matters to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of the litigation matters specifically described above or of any such other pending or threatened litigation. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Other environmental matters

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

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

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

Resolutions of other claims by the EPA, the involved state agency or PRPs are at various stages of investigation. These investigations involve determinations of:

the actual responsibility attributed to us and the other PRPs at the site; appropriate investigatory or remedial actions; and allocation of the costs of such activities among the PRPs and other site users.


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Our ultimate financial responsibility in connection with those sites may depend on many factors, including:

the volume and nature of material, if any, contributed to the site for which we are responsible; the numbers of other PRPs and their financial viability; and the remediation methods and technology to be used.

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

Contamination litigation

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

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

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

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

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

Retained risk

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

Under the hull and machinery program, we generally maintain a $125 million per occurrence deductible, limited to a maximum of $250 million per policy period. Subject to the same shared deductible, we also have coverage for costs incurred to mitigate damage to a rig up to an amount equal to 25 percent of a rig’s insured value. Also subject to the same shared deductible, we have coverage for


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wreck removal for an amount up to 25 percent of a rig’s insured value, with any excess generally covered to the extent of our excess liability coverage described below. However, the shared deductible is $0 in the event of a total loss or a constructive total loss of a drilling unit.

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

We also carry $100 million of additional insurance that generally covers expenses that would otherwise be assumed by the well owner, such as costs to control the well, redrill expenses and pollution from the well. This additional insurance provides coverage for such expenses in circumstances in which we have legal or contractual liability arising from our gross negligence or willful misconduct. As of June 30, 2010, the insured value of our drilling rig fleet was approximately $36.9 billion in the aggregate, excluding rigs under construction.

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

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

Letters of credit and surety bonds

We had letters of credit outstanding totaling $479 million and $567 million at June 30, 2010 and December 31, 2009, respectively. These letters of credit guarantee various contract bidding and performance activities under various committed and uncommitted credit lines provided by several banks. In April 2010, we had a letter of credit issued in the amount of $60 million on behalf of TPDI to satisfy its liquidity requirements under the TPDI Credit Facilities, which is included in the total as of June 30, 2010 (see Note 9—Debt).

As is customary in the contract drilling business, we also have various surety bonds in place that secure customs obligations relating to the importation of our rigs and certain performance and other obligations. Surety bonds outstanding totaled $24 million and $31 million at June 30, 2010 and December 31, 2009, respectively.

Note 13—Equity Shares held by subsidiary—In December 2008, we issued 16 million of our shares to one of our subsidiaries for future use to

satisfy our obligations to deliver shares in connection with awards granted under our incentive plans or other rights to acquire our shares. At June 30, 2010 and December 31, 2009, our subsidiary held 13,455,824 shares and 14,011,416 shares, respectively.

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 U.S. $3.2 billion, using an exchange rate of USD 1.00 to CHF 1.08 as of the close of trading on June 30, 2010. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program.

During the three months ended June 30, 2010, following the authorization by our board of directors, we repurchased 2,146,267 of our shares under our share repurchase program for an aggregate purchase price of CHF 193 million, equivalent to $180 million. During the six months ended June 30, 2010, following the authorization by our board of directors, we repurchased 2,863,267 of our shares under our share repurchase program for an aggregate purchase price of CHF 257 million, equivalent to $240 million. At June 30, 2010, we held 2,863,267 treasury shares purchased under our share repurchase program, recorded at cost.

Distribution—In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.19, using an exchange rate of USD 1.00 to CHF 1.08 as of the close of trading on June 30, 2010. We expect the cash distribution to be calculated and paid in four quarterly installments. Under Swiss law, upon satisfaction of all legal requirements, we must submit an application to the commercial register in the Canton of Zug to register the applicable par value reduction.


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

Note 14—Fair Value of Financial Instruments We estimate the fair value of each class of financial instruments, for which estimating fair value is practicable, by applying the

following methods and assumptions:

Cash and cash equivalents—The carrying amount approximates fair value because of the short maturities of those instruments.

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

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

Notes receivable and working capital loan receivable—The carrying amount represents the estimated fair value, measured using unobservable inputs that require significant judgment, for which there is little or no market data, including the credit rating of the borrower. At June 30, 2010, the aggregate carrying amount of our notes receivable and working capital loan receivable was $121 million, including $10 million and $111 million recorded in other current assets and other assets, respectively. We did not hold notes receivable as of December 31, 2009.

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

June 30, 2010 December 31, 2009

Carrying amount

Fair value

Carrying amount

Fair value

Long-term debt, including current maturities $ 10,442 $ 9,751 $ 10,534 $ 11,218 Long-term debt of consolidated variable interest entities, including current maturities 984 997 1,183 1,178

Derivative instruments—The carrying amount of our derivative instruments represents the estimated fair value, measured using direct or indirect observable inputs, including quoted prices or other market data for similar assets or liabilities in active markets or identical assets or liabilities in less active markets. At June 30, 2010, the carrying amounts of our derivative instruments were $14 million and $13 million recorded in other assets and other long-term liabilities, respectively, on our condensed consolidated balance sheets. At December 31, 2009, the carrying amounts of our derivative instruments were $5 million and $5 million recorded in other assets and other long-term liabilities, respectively, on our condensed consolidated balance sheets.

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

Forward-Looking Information The statements included in this quarterly report regarding future financial performance and results of operations and other

statements that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements in this quarterly report include, but are not limited to, statements about the following subjects:

the impact of the Macondo well incident and related matters, the offshore drilling market, including the impact of the drilling moratorium in the United States (“U.S.”) Gulf of Mexico, supply and

demand, utilization rates, dayrates, customer drilling programs, commodity prices, stacking of rigs, reactivation of rigs, effects of new rigs on the market and effects of declines in commodity prices and the downturn in the global economy or market outlook for our various geographical operating sectors and classes of rigs,

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

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

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

our results of operations and cash flow from operations, including revenues and expenses, uses of excess cash, including the payment of dividends and other distributions, debt retirement and share repurchases under our share

repurchase program, the cost and timing of acquisitions and the proceeds and timing of dispositions, tax matters, including our effective tax rate, changes in tax laws, treaties and regulations, tax assessments and liabilities for tax issues,

including those associated with our activities in Brazil, Norway and the U.S., legal and regulatory matters, including results and effects of legal proceedings and governmental audits and assessments, outcomes and

effects of internal and governmental investigations, customs and environmental matters, insurance matters, including adequacy of insurance, renewal of insurance, insurance proceeds and cash investments of our wholly owned

captive insurance company, debt levels, including impacts of the financial and economic downturn, effects of accounting changes and adoption of accounting policies, and investments in recruitment, retention and personnel development initiatives, pension plan and other postretirement benefit plan

contributions, the timing of severance payments and benefit payments.

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

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

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

those described under “Item 1A. Risk Factors” included herein and in our annual report on Form 10-K for the year ended December 31, 2009,

the adequacy of and access to sources of liquidity, our inability to obtain contracts for our rigs that do not have contracts, the cancellation of contracts currently included in our reported contract backlog, the effect and results of litigation, tax audits and contingencies, and other factors discussed in this quarterly report and in our other filings with the U.S. Securities and Exchange Commission (“SEC”), which

are available free of charge on the SEC website at www.sec.gov.

The foregoing risks and uncertainties are beyond our ability to control, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary materially from those indicated.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law.

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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 15, 2010, we owned, had partial ownership interests in or operated 139 mobile offshore drilling units. As of this date, our fleet consisted of 45 High-Specification Floaters (Ultra-Deepwater, Deepwater and Harsh Environment semisubmersibles and drillships), 26 Midwater Floaters, 10 High-Specification Jackups, 55 Standard Jackups and three Other Rigs. In addition, we had three Ultra-Deepwater Floaters under construction.

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

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

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

Significant Events Macondo well incident—On April 22, 2010, the Ultra-Deepwater Floater Deepwater Horizon sank after a blowout of the

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

Fleet expansion—In the six months ended June 30, 2010, we completed construction of three Ultra-Deepwater newbuilds and each has commenced its respective contract. See “—Outlook.”

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

Share repurchase program—As of June 30, 2010, we had repurchased a total of 2,863,267 of our shares under our share repurchase program for an aggregate purchase price of CHF 257 million, equivalent to $240 million. We have agreed not to repurchase any additional shares under our share repurchase program without 30 days written notice to the U.S. Department of Justice (the “DOJ”). See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

Distribution—In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.19, using an exchange rate of USD 1.00 to CHF 1.08 as of the close of trading on June 30, 2010. We expect the cash distribution to be calculated and paid in four quarterly installments, following registration with the commercial register of the Canton of Zug. At June 30, 2010, the carrying amount of the unpaid distribution payable was $1.0 billion. See “—Liquidity and Capital Resources—Sources and Uses of Liquidity.”

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Outlook Drilling market—We expect market utilization to remain steady over the next few quarters for the jackup and midwater floater

markets due to continued stability in oil and gas prices. Additionally, we expect this stability to result in contracting opportunities for all classes within our drilling fleet during 2010. However, considering the potential impact of the uncontracted capacity in 2010 and 2011 from newbuilds and existing units in the market, coupled with the uncertainties of the drilling moratorium in the U.S. Gulf of Mexico, we cannot be certain of projections for utilization for our High-Specification Floater fleet. Consequently, we do not believe that the increased tendering activity that we are currently experiencing will foster a corresponding increase in dayrates in the near term.

As of July 15, 2010, our contract backlog had declined to $27.6 billion. As of April 13, 2010, our contract backlog was $28.6 billion, as adjusted for the $590 million lost backlog associated with the Deepwater Horizon drilling contract. The depletion of backlog from drilling activity was partially offset by the execution of new contracts with approximately $1.4 billion of associated backlog during the second quarter of 2010. Although we are currently engaged in advanced discussions with customers on several additional opportunities, our backlog may continue to decline if we are unable to obtain new contracts for our rigs that sufficiently replace existing backlog as it is consumed over time or if any contracts are terminated.

On May 30, 2010, the U.S. government implemented a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. This initial moratorium has been challenged in the U.S. courts; on July 12, 2010, the U.S. government implemented a revised drilling moratorium that is scheduled to be in effect until November 30, 2010. The U.S. government, however, may elect to shorten or extend the duration of the moratorium. We have 14 rigs under contract in the U.S. Gulf of Mexico, and we are unable to predict, with certainty, the full impact that the moratorium will have on our operations. The backlog associated with the contracts relating to these rigs was approximately $7.6 billion as of July 15, 2010, of which $2.1 billion could be lost if our customers are legally permitted to and choose to exercise their termination rights under certain contracts. Our customers may elect to move rigs to locations outside of the U.S. Gulf of Mexico, perform activities permitted under the moratorium or attempt to terminate our contracts pursuant to their respective force majeure provisions.

Several customers have either declared force majeure or indicated that they may declare force majeure under their respective contracts. We do not believe that a force majeure event exists as a result of the drilling moratorium under the drilling contracts for the rigs in the U.S. Gulf of Mexico, and we are working closely with our customers to assess each situation. If an actual force majeure event occurs, as determined under the applicable drilling contract, these agreements generally allow for a period of 30 to 60 days during which the rig will earn a force majeure rate, which is generally between 85 percent and 100 percent of the contracted dayrate. Following this period, and in some cases subject to a notice or waiting period, either we or the customer may terminate the contract. In some contracts, we have the right to further extend the contract for a period of time by electing to continue the contract at a zero dayrate, thereby retaining the backlog associated with the contract for possible recognition in a later period. Some drilling contracts for rigs in the U.S. Gulf of Mexico include early termination provisions that require the payment of the contractual dayrate for the remaining term of the contract upon termination for force majeure either in a lump sum or over an extended term. We have, in some instances, negotiated, and may continue to negotiate, special standby rates with some of our customers under our drilling contracts for rigs in the U.S. Gulf of Mexico. These special standby rates are lower than the regular contract dayrate and apply during periods when the customer is prevented from performing drilling operations. For every day on special standby rate, the contract term of the applicable contract is extended by an equal number of days.

Fleet status—The uncommitted fleet rate is the number of uncommitted days as a percentage of the total number of available rig calendar days in the period. As of July 15, 2010, the uncommitted fleet rates for the remainder of 2010, 2011, 2012 and 2013 are as follows:

2010 2011 2012 2013 Uncommitted fleet rate High-Specification Floaters 8 % 20 % 36 % 48 % Midwater Floaters 30 % 60 % 80 % 95 % High-Specification Jackups 46 % 52 % 81 % 100 % Standard Jackups 52 % 72 % 87 % 95 %

We have 11 existing contracts with fixed-price or capped options, and given current market conditions, we expect that a number of these options will not be exercised by our customers in 2010. Well-in-progress or similar provisions of our existing contracts may delay the start of higher dayrates in subsequent contracts, and some of the delays could be significant.

High-Specification Floaters—Our Ultra-Deepwater Floater fleet is fully contracted for 2010, and we are in advanced discussions with customers to contract the two remaining Ultra-Deepwater Floaters with availability in 2011. We recently extended a Deepwater Floater available in 2010 for a four-month period and expect to contract the remaining active and available 2010 Deepwater Floater. Recent subletting of our High-Specification Floater fleet has had minimal impact on our operations in 2010 thus far, but we cannot be certain of the impact on our operations in 2011 and beyond. As of July 15, 2010, we had 43 of our 48 current and future High-Specification

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Floaters contracted through the end of 2010, with 36, including all of our newbuilds, contracted beyond 2011. These 43 units also include all of our Ultra-Deepwater Floaters. We believe the continued exploration successes in the deepwater offshore provinces will foster significant demand and should support our long-term positive outlook for our High-Specification Floater fleet.

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

High-Specification Jackups—The High-Specification Jackup fleet is experiencing rising utilization and dayrates, and we expect this fleet to remain attractive to customers throughout 2010. Tendering activity has remained steady during the second quarter of 2010, which has resulted in extensions of several existing contracts. As of July 15, 2010, we had three of our 10 High-Specification Jackups stacked. Although we have two High-Specification Jackups completing their current contracts in the third quarter of 2010, the continued increase in tendering activity could result in the extension of some of these contracts.

Standard Jackups—Considering the number of units currently stacked, and the number of newbuild units expected to enter the market without customer contracts and the absence of a corresponding increase in customer demand, we expect near-term dayrates for our Standard Jackup fleet to remain flat or slightly decrease as contracts are renewed or completed. As of July 15, 2010, we had 22 of our 55 Standard Jackups stacked. We expect a few more of our Standard Jackups to be stacked in the second half of 2010.

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

Three months ended

June 30, Six months ended

June 30,

2010 2009 Change 2010 2009 Change

Performance indicators Average daily revenue (a)(b) $ 284,200 $ 255,900 $ 28,300 $ 291,300 $ 256,200 $ 35,100 Utilization (b)(c) 64 % 84 % n/a 65 % 87 % n/a

Statement of operations data Operating revenues $ 2,505 $ 2,882 $ (377 ) $ 5,107 $ 6,000 $ (893 ) Operating and maintenance expense 1,358 1,277 81 2,554 2,448 106 Operating income 957 1,121 (164 ) 1,883 2,440 (557 ) Net income attributable to controlling interest 715 806 (91 ) 1,392 1,748 (356 )

June 30,

2010 December 31,

2009 Change

Balance sheet data Cash and cash equivalents $ 2,888 $ 1,130 $ 1,758 Total assets 37,552 36,436 1,116 Total debt 11,426 11,717 (291 )

__________________________ “n/a” means not applicable.

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

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

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

Resulting from the market pressures experienced in the six months ended June 30, 2010, our revenues declined relative to those recognized in the six months ended June 30, 2009. The decline was primarily due to lower utilization, mostly related to 36 stacked and idle rigs as of June 30, 2010, as compared to 18 stacked and idle rigs during the same period in 2009. This decline was partially offset by revenues from the commencement of operations of our newbuild rigs. The lower utilization also resulted in a decrease in our operating and maintenance expenses compared to the prior year period, which was more than offset by increased operating and maintenance

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expenses associated with the commencement of operations of our newbuild rigs, increased maintenance and shipyard expenses and costs associated with the Macondo well incident, primarily related to insurance deductibles. As of June 30, 2010, we had reduced our total debt compared to December 31, 2009, primarily due to net repayments under our commercial paper program (see “—Liquidity and Capital Resources—Sources and Uses of Liquidity”).

For the year ending December 31, 2010, we expect our total revenues to decline compared to our total revenues for the year ended December 31, 2009. We expect this reduction to result from reduced drilling activity associated with stacked and idle rigs, lost revenues from the Deepwater Horizon contract termination and reduced operating activity associated with our integrated services. However, we expect the decrease in revenues to be partially offset by a full year of drilling operations of our five newbuilds delivered in 2009, the commencement of drilling operations of four additional newbuilds in 2010, and increased activity in our other operations segment. We are unable to ascertain, with certainty, the effect the moratorium will have on our operations in the U.S. Gulf of Mexico in 2010.

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

Although we are currently unable to estimate the full impact of the Macondo well incident on our business, the incident could ultimately have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows. We expect an increase of approximately $180 million in operating and maintenance expenses in 2010 comprised primarily of approximately $70 million of insurance deductibles, approximately $30 million of higher insurance premiums, approximately $36 million of additional legal expenses related to lawsuits and investigations, net of insurance recoveries, and approximately $44 million of additional costs primarily related to our internal investigation of the Macondo well incident, including consultant costs, travel costs and other miscellaneous costs. See “—Contingencies—Insurance matters” and “Part II. Other Information, Item 1A. Risk Factors.”

At June 30, 2010, the carrying amount of our property and equipment was $22.5 billion, representing 60 percent of our total assets, and the carrying amount of our goodwill was $8.1 billion, representing 22 percent of our total assets. In accordance with our critical accounting policies, we review our property and equipment for impairment when events or changes in circumstances indicate that the carrying amounts of our assets held and used may not be recoverable, and we conduct impairment testing for our goodwill when events and circumstances indicate that the fair value of a reporting unit falls below its carrying amount. If we are unable to secure new or extended contracts for our active units or the reactivation of any of our stacked units, or if we experience further declines in actual or anticipated dayrates, especially those in our Standard Jackup fleet, we may be required to recognize losses on impairment of the carrying amount of one or more of our asset groups. Additionally, we may be required to recognize losses on impairment of goodwill if we determine that the fair value of our contract drilling services reporting unit declines below its carrying amount. See “—Critical Accounting Policies and Estimates” and “Part II. Other Information, Item 1A. Risk Factors.”

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Performance and Other Key Indicators

Contract backlog—The following table presents our contract backlog, including firm commitments only, for our contract drilling services segment as of July 15, 2010, March 31, 2010 and June 30, 2009. Firm commitments are represented by signed drilling contracts or, in some cases, by other definitive agreements awaiting contract execution. Our contract backlog is calculated by multiplying the full contractual operating dayrate by the number of days remaining in the firm contract period, excluding revenues for mobilization, demobilization and contract preparation or other incentive provisions, which are not expected to be significant to our contract drilling revenues. The contractual operating dayrate may be higher than certain other rates included in the contract, such as a waiting-on-weather rate, repair rate, standby rate or force majeure rate. In certain contracts, the dayrate may be reduced to zero if, for example, repairs extend beyond a stated period of time.

July 15,

2010 March 31,

2010 June 30,

2009

Contract backlog (in millions) High-Specification Floaters $ 22,969 $ 24,293 $ 27,022 Midwater Floaters 2,767 2,933 4,272 High-Specification Jackups 391 315 356 Standard Jackups 1,374 1,323 2,234 Other Rigs 62 72 91

Total $ 27,563 $ 28,936 $ 33,975

We have 14 rigs under contract in the U.S. Gulf of Mexico. The backlog associated with the contracts relating to these rigs was approximately $7.6 billion as of July 15, 2010, of which $2.1 billion could be lost if our customers are legally permitted to and choose to exercise their termination rights under certain contracts. The backlog associated with the Deepwater Horizon drilling contract represented approximately $590 million of the High-Specification Floaters backlog and total backlog for March 31, 2010 and June 30, 2009. Although the rig was operating under a contract which was to extend through September 2013, the total loss of the rig resulted in an automatic termination of the agreement.

Fleet average daily revenue—The following table presents the average daily revenue for our contract drilling services segment for each of the quarters ended June 30, 2010, March 31, 2010 and June 30, 2009. See “—Outlook—Key measures” for a definition of average daily revenue.

Three months ended

June 30,

2010 March 31,

2010 June 30,

2009

Average daily revenue High-Specification Floaters

Ultra-Deepwater Floaters $ 482,100 $ 486,000 $ 450,500 Deepwater Floaters 395,800 383,800 339,600 Harsh Environment Floaters 428,500 400,100 374,500

Total High-Specification Floaters 447,800 443,200 397,600 Midwater Floaters 319,000 331,600 302,700 High-Specification Jackups 146,100 166,000 161,400 Standard Jackups 117,100 133,100 149,200 Other Rigs 72,000 72,700 48,300

Total fleet average daily revenue 284,200 298,300 255,900

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Fleet utilization—The following table presents the utilization rates for our contract drilling services segment for each of the quarters ended June 30, 2010, March 31, 2010 and June 30, 2009. See “—Outlook—Key measures” for a definition of utilization.

Three months ended

June 30,

2010 March 31,

2010 June 30,

2009

Utilization High-Specification Floaters

Ultra-Deepwater Floaters 76 % 88 % 91 % Deepwater Floaters 66 % 71 % 82 % Harsh Environment Floaters 85 % 98 % 93 %

Total High-Specification Floaters 74 % 83 % 88 % Midwater Floaters 69 % 67 % 84 % High-Specification Jackups 70 % 63 % 87 % Standard Jackups 53 % 53 % 82 % Other Rigs 50 % 50 % 59 %

Total fleet average utilization 64 % 66 % 84 %

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Operating Results

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

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

Three months ended June 30,

2010 2009 Change % Change

(In millions, except day amounts and percentages)

Revenue earning days 8,057 10,261 (2,204 ) (21) % Utilization 64 % 84 % n/a n/m Average daily revenue $ 284,200 $ 255,900 $ 28,300 11 %

Contract drilling revenues $ 2,290 $ 2,625 $ (335 ) (13) % Contract drilling intangible revenues 29 75 (46 ) (61) % Other revenues 186 182 4 2 % 2,505 2,882 (377 ) (13) % Operating and maintenance expense 1,358 1,277 81 6 % Depreciation, depletion and amortization 400 360 40 11 % General and administrative expense 58 53 5 9 % 1,816 1,690 126 7 % Loss on impairment — (67 ) 67 n/m Gain (loss) on disposal of assets, net 268 (4 ) 272 n/m Operating income 957 1,121 (164 ) (15) % Other income (expense), net

Interest income 5 1 4 n/m Interest expense, net of amounts capitalized (141 ) (114 ) (27 ) 24 % Gain (loss) on retirement of debt — (8 ) 8 n/m Other, net (3 ) (8 ) 5 63 %

Income before income taxes 818 992 (174 ) (18) % Income tax expense 98 184 (86 ) (47) % Net income 720 808 (88 ) (11) % Net income attributable to noncontrolling interest 5 2 3 n/m Net income attributable to controlling interest $ 715 $ 806 $ (91 ) (11) %

__________________________ “n/a” means not applicable

“n/m” means not meaningful

Operating revenues—Contract drilling revenues decreased $335 million for the three months ended June 30, 2010 compared to revenues for the three months ended June 30, 2009, primarily due to lower utilization and partially offset by higher average daily revenue. The lower utilization during the three months ended June 30, 2010, as compared to the three months ended June 30, 2009, was primarily due to (a) approximately $345 million in reduced drilling activity as 36 rigs were stacked or idle at June 30, 2010, compared to 18 rigs that were stacked or idle, including one held for sale, at June 30, 2009, (b) approximately $170 million due to higher out-of-service time for shipyard, mobilization, maintenance and repair projects in the three months ended June 30, 2010, as compared to the same period in 2009, (c) approximately $40 million due to the loss of revenues associated with the Deepwater Horizon contract and (d) approximately $25 million due to rig sales or rigs in which we sold our interest. These decreases were partially offset by revenues of approximately $270 million associated with our newbuilds, which commenced operations during 2009 and 2010. Our average daily revenue increases as we stack rigs in our Midwater Floater fleet and jackup fleets, since rigs in these classes are typically contracted at lower dayrates compared to those in our High-Specification Floater fleet.

Contract drilling intangible revenues declined $46 million for the three months ended June 30, 2010, compared to the three months ended June 30, 2009, due to the timing of the contracts with which they were associated. Contract drilling intangible revenues represent the amortization of the fair value of drilling contracts in effect at the time of our merger with GlobalSantaFe Corporation (“GlobalSantaFe”). We recognize contract drilling intangible revenues over the respective contract period using the straight-line method of amortization.

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Costs and expenses—Operating and maintenance expenses increased $81 million, or six percent, for the three months ended June 30, 2010 compared to the three months ended June 30, 2009. The increase was due to (a) approximately $80 million of expenses primarily related to insurance deductibles and legal costs associated with the Macondo well incident, (b) approximately $75 million of expenses due to our newbuilds, which commenced operations during 2009 and 2010 and (c) approximately $60 million of expenses due to increased activity in our other operations segment. These increases were partially offset by an approximate $115 million reduction resulting from lower utilization and approximately $30 million due to reduced activity in our integrated services operations.

Depreciation, depletion and amortization increased for the three months ended June 30, 2010, primarily due to $39 million of additional expense related to the commencement of operations of seven newbuilds subsequent to June 30, 2009.

During the three months ended June 30, 2009, GSF Arctic II and GSF Arctic IV, both previously classified as assets held for sale, were impaired due to the global economic downturn and pressure on commodity prices, both of which have had an adverse effect on our industry. We recognized a $58 million loss on impairment of these rigs during the three months ended June 30, 2009. We also recognized a $9 million loss on impairment of the customer relationships intangible asset associated with our drilling management services during the three months ended June 30, 2009 with no comparable activity during the three months ended June 30, 2010.

During the three months ended June 30, 2010, we recognized a net gain on disposal of assets of $268 million, including a $267 million gain on the loss of Deepwater Horizon, which resulted from insurance recoveries received during the three months ended June 30, 2010 that exceeded the carrying amount of the rig at the date of the incident. During the three months ended June 30, 2009, we recognized a net loss on disposal of other unrelated assets of $4 million.

The increase in interest expense for the three months ended June 30, 2010 was primarily attributable to a $30 million reduction of capitalized interest, compared to the three months ended June 30, 2009, and $14 million of interest expense associated with the Petrobras 10000 capital lease. Partially offsetting the increase was $18 million associated with debt repaid or repurchased subsequent to June 30, 2009.

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. There is little to no expected relationship between the provision for income taxes and income before income taxes considering, among other factors, (a) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (b) rig movements between taxing jurisdictions and (c) our rig operating structures. The estimated annual effective tax rates at June 30, 2010 and 2009 were 15.5 percent and 15.4 percent, respectively, based on projected 2010 and 2009 annual income before income taxes, after excluding certain items, such as losses on impairment, the gain resulting from insurance recoveries on the loss of Deepwater Horizon and prior period adjustments. 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, 2010, the impact of the various discrete period tax items was a net tax expense of $6 million, resulting in a tax rate of 12.0 percent on income before income tax expense. For the three months ended June 30, 2009, the impact of the various discrete items was a net expense of $16 million, resulting in a tax rate of 18.5 percent on income before income tax expense.

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Six months ended June 30, 2010 compared to six months ended June 30, 2009

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

Six months ended June 30,

2010 2009 Change % Change

(In millions, except day amounts and percentages)

Revenue earning days 16,241 21,311 (5,070 ) (24) % Utilization 65 % 87 % n/a n/m Average daily revenue $ 291,300 $ 256,200 $ 35,100 14 %

Contract drilling revenues $ 4,731 $ 5,459 $ (728 ) (13) % Contract drilling intangible revenues 62 179 (117 ) (65) % Other revenues 314 362 (48 ) (13) % 5,107 6,000 (893 ) (15) % Operating and maintenance expense 2,554 2,448 106 4 % Depreciation, depletion and amortization 801 715 86 12 % General and administrative expense 121 109 12 11 % 3,476 1,690 126 6 % Loss on impairment (2 (288 ) 286 (99) Gain on disposal of assets, net 254 — 254 n/m Operating income 1,883 2,440 (557 ) (23) % Other income (expense), net

Interest income 10 2 8 n/m Interest expense, net of amounts capitalized (273 ) (250 ) (23 ) 9 % Gain (loss) on retirement of debt 2 (10 ) 12 n/m Other, net 10 — 10 n/m %

Income before income taxes 1,632 2,182 (550 ) (25) % Income tax expense 227 435 (208 ) (48) % Net income 1,405 1,747 (342 ) (20) % Net income (loss) attributable to noncontrolling interest 13 (1 ) 14 n/m Net income attributable to controlling interest $ 1,392 $ 1,748 $ (356 ) (20) %

____________________ “n/a” means not applicable

“n/m” means not meaningful

Operating revenues—Contract drilling revenues decreased $728 million for the six months ended June 30, 2010 compared to the six months ended June 30, 2009 primarily due to lower utilization and partially offset by higher average daily revenue. The lower utilization during the six months ended June 30, 2010, as compared to the six months ended June 30, 2009, was primarily due to (a) approximately $780 million in reduced drilling activity as 36 rigs were stacked or idle at June 30, 2010 compared to 18 rigs that were stacked or idle, including one held for sale, at June 30, 2009, (b) approximately $375 million due to higher out-of-service time for shipyard, mobilization, maintenance and repair projects in the six months ended June 30, 2010, as compared to the same period in 2009 and (c) approximately $40 million due to the loss of revenues associated with the Deepwater Horizon contract. This reduced activity was partially offset by revenue of approximately $480 million associated with our newbuilds, which commenced operations during 2009 and 2010. Our average daily revenue increases as we stack rigs in our Midwater Floater fleet and jackup fleets, since rigs in these classes are typically contracted at lower dayrates compared to those in our High-Specification Floater fleet.

Contract drilling intangible revenues declined $117 million for the six months ended June 30, 2010, compared to the six months ended June 30, 2009, due to timing of the contracts with which they were associated. Contract drilling intangible revenues represent the amortization of the fair value of drilling contracts in effect at the time of our merger with GlobalSantaFe. We recognize contract drilling intangible revenues over the respective contract period using the straight-line method of amortization.

Other revenues decreased $48 million for the six months ended June 30, 2010 compared to the six months ended June 30, 2009, primarily due to reduced integrated services activity of $57 million and lower reimbursable revenues of $20 million. These decreases were partially offset by increased activity of $36 million associated with our other operations segment.

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Costs and expenses—Operating and maintenance expenses increased $106 million, or four percent for the six months ended June 30, 2010 compared to the six months ended June 30, 2009. The increase was due to (a) approximately $140 million of expenses resulting from our newbuilds, which commenced operations during 2009 and 2010, (b) approximately $80 million of expenses related to insurance deductibles and legal costs associated with the Macondo well incident, (c) approximately $100 million of expenses due to increased shipyard and maintenance expense and (d) approximately $40 million of expenses due to increased activity in our other operations segment. These increases were partially offset by an approximate $205 million reduction of expenses resulting from lower utilization and an approximate $45 million reduction due to our integrated services operations.

Depreciation, depletion and amortization increased primarily due to $63 million of additional expense related to the commencement of operations of seven newbuilds subsequent to June 30, 2009 and $21 million of accelerated depletion of our oil and gas properties during the six months ended June 30, 2010.

During the six months ended June 30, 2009, GSF Arctic II and GSF Arctic IV, both previously classified as assets held for sale, were impaired due to the global economic downturn and pressure on commodity prices, both of which have had an adverse effect on our industry. We recognized a $279 million loss on impairment of these rigs during the six months ended June 30, 2009. We also recognized a $9 million loss on impairment of the customer relationships intangible asset associated with our drilling management services during the six months ended June 30, 2009 with no comparable activity during the six months ended June 30, 2010.

During the six months ended June 30, 2010, we recognized a net gain on disposal of assets of $254 million, including a $267 million gain on the loss of Deepwater Horizon, which resulted from insurance recoveries received during the six months ended June 30, 2010 that exceeded the carrying amount of the rig at the date of the incident. Partially offsetting the gain was a loss of $15 million related to the sale of GSF Arctic II and GSF Arctic IV. There was no comparable activity during the six months ended June 30, 2009.

The increase in interest expense for the six months ended June 30, 2010 was primarily attributable to a $48 million reduction of capitalized interest, compared to the six months ended June 30, 2009, and $28 million of interest expense associated with the Petrobras 10000 capital lease. Partially offsetting the increase was $54 million associated with debt repaid or repurchased subsequent to June 30, 2009.

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. There is little to no expected relationship between the provision for income taxes and income before income taxes considering, among other factors, (a) changes in the blend of income that is taxed based on gross revenues versus income before taxes, (b) rig movements between taxing jurisdictions and (c) our rig operating structures. The estimated annual effective tax rates at June 30, 2010 and 2009 were 15.5 percent and 15.4 percent, respectively, based on projected 2010 and 2009 annual income before income taxes, after excluding certain items, such as losses on impairment, net gains on disposal of assets, the gain on the loss of Deepwater Horizon and prior period adjustments. 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, 2010, the impact of the various discrete period tax items was a net tax expense of $7 million, resulting in a tax rate of 13.9 percent on income before income tax expense. For the six months ended June 30, 2009, the impact of the various discrete items was a net tax expense of $51 million resulting in a tax rate of 19.9 percent on income before income tax expense.

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Liquidity and Capital Resources

Sources and uses of cash

Our primary sources of cash during the six months ended June 30, 2010 were our cash flows from operating activities and the receipt of insurance proceeds of $560 million following the loss on Deepwater Horizon. Our primary uses of cash were capital expenditures (including for newbuild construction), repayments of borrowings under our credit facilities and commercial paper program and repurchases of shares under our share repurchase program. At June 30, 2010, we had $2.9 billion in cash and cash equivalents.

Six months ended June 30, 2010 2009 Change

Cash flows from operating activities (In millions) Net income $ 1,405 $ 1,747 $ (342 )

Amortization of drilling contract intangibles (62 ) (179 ) 117 Depreciation, depletion and amortization 801 715 86 Loss on impairment 2 288 (286 ) Gain on disposal of assets, net (254 ) — (254 ) Other non-cash items 236 218 18 Changes in operating assets and liabilities 313 228 85

$ 2,441 $ 3,017 $ (576 )

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


Cash flows from investing activities (In millions) Capital expenditures $ (679 ) $ (1,655 ) $ 976 Proceeds from disposal of assets, net 51 8 43 Proceeds from insurance recoveries for loss of drilling unit 560 — 560 Proceeds from payments on notes receivable 21 — 21 Proceeds from short-term investments 5 393 (388 ) Purchases of short-term investments — (234 ) 234 Joint ventures and other investments, net (1) — (1 )

$ (43 ) $ (1,488 ) $ 1,445

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

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Cash flows from financing activities (In millions) Change in short-term borrowings, net $ (177 ) $ (500 ) $ 323 Proceeds from debt 54 319 (265 ) Repayments of debt (275 ) (1,410 ) 1,135 Payments for warrant exercise, net — (13 ) 13 Purchases of shares held in treasury (240 ) — (240 ) Proceeds from (taxes paid for) share-based compensation plans, net (1 ) 22 (23 ) Excess tax benefit from share-based compensation plans 1 1 — Other, net (2 ) (4 ) 2

$ (640 ) $ (1,585 ) $ 945

Net cash used in financing activities decreased primarily because of reduced repayments or repurchases of debt and short-term borrowings during the six months ended June 30, 2010 relative to the six months ended June 30, 2009, including repurchases of $440 million aggregate principal amount of our convertible senior notes and the repayment of $1 billion of borrowings under a term loan in the six months ended June 30, 2009 with no comparable activity during the six months ended June 30, 2010. Partially offsetting the reduced repayment and repurchases were decreased borrowings drawn under the TPDI Credit Facilities and ADDCL Credit Facilities in the six months ended June 30, 2010 as we completed construction of the rigs for which those credit facilities were established. Additionally, we repurchased $240 million of our shares in the six months ended June 30, 2010 with no comparable activity in the prior year period.

Drilling fleet expansion and dispositions

Expansion—Capital expenditures, including capitalized interest of $47 million, totaled $679 million during the six months ended June 30, 2010, substantially all of which related to our contract drilling services segment. Having completed five of our 10 newbuild projects in the year ended December 31, 2009, the following table presents the historical and projected capital expenditures and other capital additions, including capitalized interest, for our remaining major construction projects (in millions):

Total costs through June 30,

2010

Expected costs for the remainder of

2010

Estimated costs

thereafter

Total estimated

cost at completion

Discoverer Luanda (a) $ 695 $ 10 $ — $ 705 Discoverer Inspiration (b) 674 4 — 678 Dhirubhai Deepwater KG2 (b) (c) 674 5 — 679 Discoverer India 591 139 — 730 Deepwater Champion (d) 583 167 5 755 Capitalized interest 230 37 16 283 Mobilization costs 55 56 3 114

Total $ 3,502 $ 418 $ 24 $ 3,944

__________________________ (a) The costs for Discoverer Luanda represent 100 percent of expenditures incurred since inception. Angola Deepwater Drilling Company Limited

(“ADDCL”) is responsible for all of these costs. We hold a 65 percent interest in ADDCL, and Angco Cayman Limited holds the remaining 35 percent interest.

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

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

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

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During 2010, we expect capital expenditures to be approximately $1.4 billion, including approximately $777 million of cash capital costs for our major construction and conversion projects. The level of our capital expenditures is partly dependent upon financial market conditions, the actual level of operational and contracting activity and the level of capital expenditures requested by our customers for which they agree to reimburse us.

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

We intend to fund the cash requirements relating to our capital expenditures through available cash balances, cash generated from operations and asset sales. We also have available credit under the Five-Year Revolving Credit Facility (see “—Sources and Uses of Liquidity”) and may utilize other commercial bank or capital market financings. We intend to fund the cash requirements of our joint ventures for capital expenditures in connection with newbuild construction through their respective credit facilities.

From time to time, we review possible acquisitions of businesses and drilling rigs and may, in the future, make significant capital commitments for such purposes. We may also consider investments related to major rig upgrades or new rig construction. Any such acquisition, upgrade or new rig construction could involve the payment by us of a substantial amount of cash or the issuance of a substantial number of additional shares or other securities. During the six months ended June 30, 2010, we acquired GSF Explorer, an asset formerly held under capital lease, in exchange for a cash payment of $15 million, thereby terminating the capital lease obligation.

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

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

Sources and uses of liquidity

Overview—We expect to use existing cash balances, internally generated cash flows, bank credit agreements, proceeds from other debt issuances and proceeds from asset sales to fulfill anticipated obligations such as scheduled debt maturities or other payments, repayment of debt due within one year (including the repurchase of 1.625% Series A Notes at the option of the noteholders), capital expenditures, shareholder-approved distributions and working capital needs. Subject in each case to then existing market conditions and to our then expected liquidity needs, among other factors, we may continue to use a portion of our internally generated cash flows and proceeds from asset sales to reduce debt prior to scheduled maturities through debt repurchases, either in the open market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings. From time to time, we may also use borrowings under bank lines of credit and under our commercial paper program to maintain liquidity for short-term cash needs.

In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.19, using an exchange rate of USD 1.00 to CHF 1.08 as of the close of trading on June 30, 2010. See “—Distribution.” In May 2009, our shareholders approved, and our board of directors subsequently authorized management to implement, a program to repurchase an amount of our shares for cancellation with an aggregate purchase price of up to CHF 3.5 billion, which is equivalent to approximately $3.3 billion at an exchange rate as of the close of business on July 27, 2010 of USD 1.00 to CHF 1.06. See “—Share repurchase program.”

On June 28, 2010, we received a letter from the DOJ asking us to meet with them to discuss our financial responsibilities in connection with the Macondo well incident and requesting that we provide them certain financial and organizational information. The letter also requested that we provide the DOJ advance notice of certain corporate actions involving the transfer of cash or other assets outside the ordinary course of business. After preliminary discussions with the DOJ, we have voluntarily agreed to provide them with 30 days notice prior to repurchasing any additional shares under our share repurchase program and prior to making substantial cash payments out of our U.S. entities, other than in the ordinary course of business. We expect to engage in further discussions with the DOJ in the future. We can give no assurance that the DOJ investigation and other matters arising out of the Macondo well incident will not adversely affect our liquidity in the future.

Our access to debt and equity markets may be limited due to a variety of events, including among others, credit rating agency downgrades of our debt, industry conditions, general economic conditions, market conditions and market perceptions of us and our

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industry. The economic downturn and related financial market instability, as well as uncertainty related to our potential liabilities from the Macondo well incident, have had, and could continue to have, an impact on our business and our financial condition. Our ability to access such markets may be severely restricted at a time when we would like, or need, to access such markets, which could have an impact on our flexibility to react to changing economic and business conditions. The economic downturn could have an impact on the lenders participating in our credit facilities or on our customers, causing them to fail to meet their obligations to us. Uncertainty related to our potential liabilities from the Macondo well incident has impacted our share price and could impact our ability to access capital markets in the future.

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

Bank credit agreements—We have a $2.0 billion five-year revolving credit facility under the Five-Year Revolving Credit Facility Agreement dated November 27, 2007 (the “Five-Year Revolving Credit Facility”). The Five-Year Revolving Credit Facility includes limitations on creating liens, incurring subsidiary debt, transactions with affiliates, sale/leaseback transactions, mergers and the sale of substantially all assets. The Five-Year Revolving Credit Facility also includes a covenant imposing a maximum debt to tangible capitalization ratio of 0.6 to 1.0. As of June 30, 2010, our debt to tangible capitalization ratio was 0.48 to 1.0. In order to borrow under the Five-Year Revolving Credit Facility, we must, at the time of the borrowing request, not be in default under the bank credit agreement and make certain representations and warranties, including with respect to compliance with laws and solvency, to the lenders. We are not required to make any representation to the lenders as to the absence of a material adverse effect. Borrowings under the Five-Year Revolving Credit Facility are subject to acceleration upon the occurrence of an event of default. We are also subject to various covenants under the indentures pursuant to which our public debt was issued, including restrictions on creating liens, engaging in sale/leaseback transactions and engaging in certain merger, consolidation or reorganization transactions. Although credit rating downgrades below investment grade do not constitute an event of default under the Five-Year Revolving Credit Facility, our commitment fee and lending margin are subject to change based on our credit rating. A default under our public debt indentures could trigger a default under the Five-Year Revolving Credit Facility and, if not waived by the lenders, could cause us to lose access to the Five-Year Revolving Credit Facility and the commercial paper program for which it provides liquidity. As of July 27, 2010, we had $81 million in letters of credit issued and outstanding and no borrowings outstanding under the Five-Year Revolving Credit Facility.

Commercial paper program—We maintain a commercial paper program, which is supported by the Five-Year Revolving Credit Facility, under which we may issue privately placed, unsecured commercial paper notes up to a maximum aggregate outstanding amount of $1.5 billion. At July 27, 2010, $105 million in commercial paper was outstanding at a weighted-average interest rate of 0.5 percent, excluding commissions.

TPDI Credit Facilities—TPDI has a bank credit agreement for a $1.265 billion secured credit facility (the “TPDI Credit Facilities”), comprised of a $1.0 billion senior term loan, a $190 million junior term loan and a $75 million revolving credit facility, which was established to finance the construction of and is secured by Dhirubhai Deepwater KG1 and Dhirubhai Deepwater KG2. One of our subsidiaries participates in the term loan with an aggregate commitment of $595 million. The senior term loan requires quarterly payments with a final payment in March 2015. The junior term loan and the revolving credit facility are due in full in March 2015. The TPDI Credit Facilities may be prepaid in whole or in part without premium or penalty. The TPDI Credit Facilities have covenants that require TPDI to maintain a minimum cash balance and available liquidity, a minimum debt service ratio and a maximum leverage ratio. At July 27, 2010, $1.2 billion was outstanding under the TPDI Credit Facilities, of which $577 million was due to one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate on July 27, 2010 was 2.1 percent.

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

TPDI Notes—TPDI has issued promissory notes payable to Pacific Drilling and one of our subsidiaries (the “TPDI Notes”). The TPDI Notes bear interest at London Interbank Offered Rate (“LIBOR”) plus the applicable margin of 2 percent and have maturities through October 2019. As of July 27, 2010, $296 million in promissory notes remained outstanding, $148 million of which was due to one of our subsidiaries and has been eliminated in consolidation. The weighted-average interest rate on July 27, 2010 was 2.4 percent.

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

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July 27, 2010, $215 million was outstanding under Tranche A at a weighted-average interest rate of 0.7 percent. At July 27, 2010, $399 million was outstanding under Tranche C, which was eliminated in consolidation.

Additionally, ADDCL has a secondary bank credit agreement for a $90 million credit facility (the “ADDCL Secondary Loan Facility”), for which one of our subsidiaries provides 65 percent of the total commitment. The facility bears interest at LIBOR plus the applicable margin, ranging from 3.125 percent to 5.125 percent, depending on certain milestones. The ADDCL Secondary Loan Facility is payable in full on the earlier of (1) 90 days after the fifth anniversary of the first well commencement or (2) December 2015, and it may be prepaid in whole or in part without premium or penalty. Borrowings under the ADDCL Secondary Loan Facility are subject to acceleration by the unaffiliated financial institution upon the occurrence of certain events of default, including the occurrence of a credit rating assignment of less than Baa3 or BBB- by Moody’s Investors Service or Standard & Poor’s Ratings Services, respectively, for Transocean Inc.’s long-term, unsecured, unguaranteed and unsubordinated indebtedness. At July 27, 2010, $75 million was outstanding under the ADDCL Secondary Loan Facility, of which $49 million was provided by one of our subsidiaries and was eliminated in consolidation. The weighted-average interest rate on July 27, 2010 was 3.7 percent.

Capital lease contract—Petrobras 10000 is held by one of our subsidiaries under a capital lease contract that requires scheduled monthly payments of $6.0 million through its stated maturity on August 4, 2029, at which time our subsidiary will have the right and obligation to acquire Petrobras 10000 from the lessor for one dollar. Upon the occurrence of certain termination events, our subsidiary is also required to purchase Petrobras 10000 and pay a termination amount determined by a formula based upon the total cost of the drillship. As of July 27, 2010, $702 million was outstanding under the capital lease contract.

The capital lease contract includes limitations on creating liens on Petrobras 10000 and requires our subsidiary to make certain representations in connection with each monthly payment, including with respect to the absence of pending or threatened litigation or other proceedings against our subsidiary or any of its affiliates, which could, if determined adversely, have a material adverse effect on our subsidiary’s ability to perform its obligations under the capital lease contract. Additionally, another subsidiary of ours has guaranteed the obligations under the capital lease contract, and this guarantor subsidiary is required to maintain an adjusted net worth, as defined, of at least $5.0 billion as of the end of each fiscal quarter. In the event the guarantor subsidiary does not satisfy this covenant at the end of any fiscal quarter, it is required to deposit the deficit amount, determined as the difference between $5.0 billion and the adjusted net worth for such fiscal quarter, into an escrow account for the benefit of the lessor.

Convertible Senior Notes—Holders of the 1.625% Series A Notes and 1.50% Series B Notes have the right to require us to repurchase their notes on December 15, 2010 and December 15, 2011, respectively. In addition, holders of any series of the Convertible Senior Notes will have the right to require us to repurchase their notes on December 14, 2012, December 15, 2017, December 15, 2022, December 15, 2027 and December 15, 2032, and upon the occurrence of a fundamental change, at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. As of July 27, 2010, $5.4 billion of the Convertible Senior Notes remained outstanding.

Our 1.625% Series A Convertible Senior Notes due 2037, 1.50% Series B Convertible Senior Notes due 2037 and 1.50% Series C Convertible Senior Notes due 2037 (the “Convertible Senior Notes”), may be converted at a rate of 5.9310 shares per $1,000 note, equivalent to a conversion price of $168.61 per share. Upon conversion, we will deliver, in lieu of shares, cash up to the aggregate principal amount of notes to be converted and shares in respect of the remainder, if any, of our conversion obligation in excess of the aggregate principal amount of the notes being converted. The conversion rate is subject to increase upon the occurrence of certain fundamental changes and adjustment upon certain other corporate events, such as the distribution of cash to our shareholders as described below.

Distribution—In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.19, using an exchange rate of USD 1.00 to CHF 1.08 as of the close of trading on June 30, 2010. We expect the cash distribution to be calculated and paid in four quarterly installments. Under Swiss law, upon satisfaction of all legal requirements, we must submit an application to the commercial register in the Canton of Zug to register the applicable par value reduction. We have submitted to the commercial register of the Canton of Zug our application for registration of the initial installment. The cantonal commercial register is currently reviewing our application, and although we believe that all registration requirements have been met, the Swiss authorities have indicated to us that the process will take longer than customary in light of lawsuits filed in the U.S. and served on the Company in Switzerland. They have indicated that they will seek guidance from the Swiss Federal Office of the Commercial Register on whether the requirements for the registration of the first installment have been met. Given the expected extended review of our application by the Swiss authorities, the payment of the first installment will be delayed. If the Swiss authorities disagree with our view that all registration requirements have been met, our ability to pay the distribution installments could be further delayed or restricted indefinitely. A delay of the first installment will likely also result in a delay of the remaining three installments, which were expected to be paid in October 2010, January 2011 and April 2011, subject to the satisfaction of the applicable Swiss legal requirements.

We intend to fund any installments using our available cash balances and our cash flows from operations. Shareholders are expected to be paid in U.S. dollars, converted using an exchange rate determined by us approximately two business days prior to the payment date, unless shareholders elect to receive the payment in Swiss francs. Distributions to shareholders in the form of a reduction in

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par value of our shares are not subject to the 35 percent Swiss withholding tax. In May 2010, we recognized a distribution payable in the amount of approximately $1.0 billion, recorded in other current liabilities, with a corresponding entry to additional paid-in capital. Upon registration of an installment with the commercial register of the Canton of Zug, we expect to reduce our par value and reclassify from additional paid-in capital to shares the portion of the distribution associated with the respective installment. At June 30, 2010, the carrying amount of the unpaid distribution payable was $1.0 billion.

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 $3.3 billion at an exchange rate as of the close of trading on July 27, 2010 of USD 1.00 to CHF 1.06. On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We intend to fund any repurchases using available cash balances and cash from operating activities. As of July 27, 2010, we have repurchased 2,863,267 of our shares under our share repurchase program for an aggregate purchase price of CHF 257 million, equivalent to $240 million. We have agreed not to repurchase any additional shares under our share repurchase program without 30 days notice to the DOJ. See “—Overview.”

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

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

Under Swiss corporate law, the right of a company and its subsidiaries to repurchase and hold its own shares is limited. A company may repurchase such company’s shares to the extent it has freely distributable reserves as shown on its Swiss statutory balance sheet in the amount of the purchase price and the aggregate par value of all shares held by the company as treasury shares does not exceed 10 percent of the company’s share capital recorded in the Swiss commercial register, whereby for purposes of determining whether the 10 percent threshold has been reached, shares repurchased under a share repurchase program for cancellation purposes authorized by the company’s shareholders are disregarded. As of July 27, 2010, Transocean Inc., our wholly owned subsidiary, held as treasury shares approximately four percent of our issued shares. At the annual general meeting in May 2009, the shareholders approved the release of 3.5 billion Swiss francs of additional paid-in capital to other reserves, or freely available reserves as presented on our Swiss statutory balance sheet, to create the freely available reserve necessary for the 3.5 billion Swiss franc share repurchase program for the purpose of the cancellation of shares (the “Currently Approved Program”). We may only repurchase shares to the extent freely distributable reserves are available. Our board of directors could, to the extent freely distributable reserves are available, authorize the repurchase of additional shares for purposes other than cancellation, such as to retain treasury shares for use in satisfying our obligations in connection with incentive plans or other rights to acquire our shares. Based on the current amount of shares held as treasury shares, approximately six percent of our issued shares could be repurchased for purposes of retention as additional treasury shares. Although our board of directors has not approved such a share repurchase program for the purpose of retaining repurchased shares as treasury shares, if it did so, any such shares repurchased would be in addition to any shares repurchased under the Currently Approved Program.

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

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

As of June 30, 2010, the total liability for unrecognized tax benefit related to uncertain tax positions was $666 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

In May 2010, at our annual general meeting, our shareholders approved a cash distribution in the form of a par value reduction in the aggregate amount of CHF 3.44 per issued share, equal to approximately $3.19, using an exchange rate of USD 1.00 to CHF 1.08 as of the close of trading on June 30, 2010. We expect the cash distribution to be calculated and paid in four quarterly installments, following registration with the commercial register of the Canton of Zug. We expect to pay the four installments within the next 12 months, although due to the uncertainty regarding the extended review by the Swiss authorities, we are unable to estimate, with certainty, the timing of each installment. At June 30, 2010, the carrying amount of the unpaid distribution payable was $1.0 billion. See “—Distribution.”

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

Derivative instruments

We have established policies and procedures for derivative instruments approved by our board of directors that provide for the approval of our Chief Financial Officer prior to entering into any derivative instruments. From time to time, we may enter into a variety of derivative instruments in connection with the management of our exposure to fluctuations in interest rates and foreign exchange rates. We do not enter into derivative transactions for speculative purposes; however, we may enter into certain transactions that do not meet the criteria for hedge accounting. See Notes to Condensed Consolidated Financial Statements—Note 10—Derivatives and Hedging.

Contingencies

Macondo well incident

On April 22, 2010, the Ultra-Deepwater Floater Deepwater Horizon sank after a blowout of the Macondo well caused a fire and explosion on the rig. Eleven persons have been 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. (“BP”).

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

Litigation—As of August 2, 2010, 249 legal actions or claims have been filed against Transocean entities, along with other unaffiliated defendants, in state and federal courts. Additionally, government agencies have initiated investigations into the Macondo well incident. We have categorized below the nature of the legal actions or claims. We are evaluating all claims and intend to pursue any and all defenses available. In addition, we believe we are entitled to contractual defense and indemnity for all wrongful death and personal injury claims made by non-employees and third-party subcontractors’ employees as well as all liabilities for pollution or contamination, other than for pollution or contamination originating on or above the surface of the water. See “—Contractual indemnity.”

Wrongful death and personal injury—Since April 2010, we and one or more of our subsidiaries have been named, along with other unaffiliated defendants, in 12 complaints that were filed in state and federal courts in Louisiana and Texas involving multiple plaintiffs that allege wrongful death and other personal injuries arising out of the Macondo well incident. The complaints generally allege negligence and seek awards of unspecified economic damages and punitive damages. BP p.l.c., MI-SWACO and Weatherford Ltd. have, based on contractual arrangements, also made indemnity demands upon us with respect to personal injury and wrongful death claims asserted by our employees or representatives of our employees against these entities. See “—Contractual indemnity.”

Economic loss—Since April 2010, we and one or more of our subsidiaries have been named, along with other unaffiliated defendants, in 60 individual complaints as well as 160 putative class-action complaints filed in the federal and state courts in Louisiana, Texas, Mississippi, Alabama, Georgia, Kentucky, South Carolina, Tennessee, Colorado and possibly other courts. The complaints generally allege, among other things, potential economic losses as a result of environmental pollution arising out of the Macondo well incident and are based primarily on the Oil Pollution Act of 1990 (“OPA”) and state OPA analogues. See “—Environmental matters.” One complaint also alleges a violation of the Racketeer Influenced and Corrupt Organizations Act. The plaintiffs are generally seeking awards of unspecified economic, compensatory and punitive damages, as well as injunctive relief. See “—Contractual indemnity.”

Federal securities claims—Since April 2010, three federal securities law class actions have been filed naming us and certain of our officers and directors as defendants, two of which were filed in the United States District Court, Southern District of New York, and one of which was filed in the United States District Court, Eastern District of Louisiana. These actions generally allege violations of Section 10(b) of the Securities Exchange Act of 1934 (the “Exchange Act”), Rule 10b5 promulgated under the Exchange Act and Section 20(a) of the Exchange Act in connection with the Macondo well incident. The plaintiffs are generally seeking awards of unspecified economic damages, including damages resulting from the recent decline in our stock price.

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

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

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

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

Other federal statutes—Several of the claimants have made assertions under other statutes, including the Clean Water Act, the Endangered Species Act, the Migratory Bird Treaty Act and the Clean Air Act.

State environmental laws—As of July 27, 2010, claims have been asserted by private claimants under state environmental statutes in Florida, Louisiana and Mississippi. As described below, the only claim currently asserted by a state government is pending in Louisiana.

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

By letter dated May 5, 2010, the Attorneys General of the five Gulf Coast states of Alabama, Florida, Louisiana, Mississippi and Texas informed us that they intend to seek recovery of pollution clean up costs and related damages arising from the Macondo well incident. In addition, by letter dated June 21, 2010, the Attorneys General of the 11 Atlantic Coast states of Connecticut, Delaware, Georgia, Maine, Maryland, Massachusetts, New Hampshire, New York, North Carolina, Rhode Island and South Carolina informed us that their states have not sustained any damage from the Macondo well incident but they would like assurances that we will be responsible financially if damages are sustained. We responded to each letter from the Attorneys General and indicated that we intend to fulfill our obligations as a responsible party for any discharge of oil from Deepwater Horizon on or above the surface of the water, and we assume that the operator will similarly fulfill its obligations under OPA for the ongoing discharge from the undersea well.

Wreck removal—We may be requested to remove the diesel fuel from the wreckage, if it is present, as well as various forms of debris from Deepwater Horizon. We have insurance coverage for wreck removal for up to 25 percent of Deepwater Horizon’s insured value, or $140 million, with any excess wreck removal liability generally covered to the extent of our excess liability coverage.

Contractual indemnity—Under our drilling contract for Deepwater Horizon, the operator has agreed, among other things, to assume full responsibility for and defend, release and indemnify us from any loss, expense, claim, fine, penalty or liability for pollution or contamination, including control and removal thereof, arising out of or connected with operations under the contract other than for pollution or contamination originating on or above the surface of the water from fuels, lubricants, motor oils and hydrocarbons or other specified substances within our control and possession, as to which we agreed to assume responsibility and protect, release and indemnify the operator. Although we do not believe it is applicable to the Macondo well incident, we also agreed to indemnify and defend the operator up to a limit of $15 million for claims for loss or damage to third parties arising from pollution caused by the rig while it is off the drilling location, while the rig is underway or during drive off or drift off of the rig from the drilling location. The operator has also agreed, among other things, (1) to defend, release and indemnify us against loss or damage to the reservoir, and loss of property rights to oil, gas and minerals below the surface of the earth and (2) to defend, release and indemnify us and bear the cost of bringing the well under control in the event of a blowout or other loss of control. We agreed to defend, release and indemnify the operator for personal injury and death of our employees, invitees and the employees of our subcontractors while the operator agreed to defend, release and indemnify us for

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personal injury and death of its employees, invitees and the employees of its other subcontractors (other than us). We have also agreed to defend, release and indemnify the operator for damages to the rig and equipment (including salvage or removal costs). We understand that indemnification agreements are generally in place between the operator and its other subcontractors for their personnel and property.

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

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

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

Excess liability coverage—We carry $950 million of commercial market excess liability coverage, exclusive of deductibles and self-insured retention, noted below, which generally covers offshore risks such as personal injury, third-party property claims and third-party non-crew claims, including wreck removal and pollution. This $950 million excess liability limit is an annual aggregate limit covering the entire Transocean worldwide fleet, including Deepwater Horizon. Prior to the April 20, 2010 Macondo well incident, there were no known incidents or occurrences that would have eroded the $950 million aggregate excess liability limit. We generally retain the risk for any liability losses with respect to the Macondo well incident and any other incidents or occurrences in excess of $1.0 billion. In the case of the Macondo well incident, we expect to pay $65 million in deductible costs prior to any insurance reimbursements from the excess liability insurance. We expect liability costs from the Macondo well incident in excess of the $65 million deductible costs to be covered up to the $950 million excess liability limit.

In May 2010, we received notice from the operator under the drilling contract for Deepwater Horizon maintaining that it believes that it is entitled to additional insured status as provided for under the drilling contract. In response, many of our insurers filed declaratory judgment actions in the Houston Division of the U.S. District Court for the Southern District of Texas in May 2010, seeking a judgment declaring that they have no, or limited, additional-insured obligation to the operator. In the actions, our insurers maintain that, although the drilling contract requires additional insured protection for certain entities related to the operator, the protection is limited to the liabilities assumed by us under the terms of the drilling contract, which includes above land or water surface pollution emanating from substances in our possession, such as fuels, lubricants, motor oils, and bilge. Our insurers maintain that, under the drilling contract, the operator accepted full responsibility and indemnified us for any pollution not assumed by us. Further, our insurers contend that the liabilities the operator currently faces arise from pollution originating from the operator’s well, below the surface and not within the scope of the additional insured protection.

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

Any such claim, if paid to the operator, could limit the amount of coverage otherwise available to us. We can provide no assurances as to the estimated costs, insurance recoveries, or other actions that will result from this incident. See “Part II. Other Information, Item 1A. Risk Factors.”

Other insurance—We also carry $100 million of additional insurance that generally covers expenses that would otherwise be assumed by the well owner, such as costs to control the well, redrill expenses and pollution from the well. This additional insurance provides coverage for such expenses in circumstances in which we have legal or contractual liability arising from our gross negligence or willful misconduct.

Limitation of liability action—At the instruction of our insurers and to preserve our insurance coverage, pursuant to the federal Limitation of a Shipowner’s Liability Act (the “Limitation Act”), we filed a complaint in the Houston Division of the Southern District of Texas

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on May 13, 2010 regarding the casualty of the Deepwater Horizon rig. Under the Limitation Act, a vessel owner is generally liable only for the post-accident value of the vessel and cargo as long as the vessel owner can show that it had no knowledge of or privity of knowledge with entities that were negligent. Claims limited under the Limitation Act include personal injury, wrongful death, and damage to property contained on the rig. Statutory claims that may be asserted by the U.S. government or individuals under OPA, the Parks Systems Resource Protection Act, the National Marine Sanctuaries Act (the “NMSA”), the Rivers and Harbors Act or CERCLA and claims by the U.S. government for fines and penalties under the Clean Water Act, the NMSA, the Marine Mammal Protection Act, the Endangered Species Act, the Shipping Act, the Ports and Waterways Safety Act, the Act to Prevent Pollution from Ships, the Clean Air Act, the Resource Conservation and Recovery Act and the Outer Continental Shelf and Lands Act are not covered by the limitation proceeding. In addition, a number of similar state statutory environmental claims are not covered by the limitation proceeding.

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

The presiding judge issued an order staying all pending applicable claims and directing claimants to file notice of their claims against us with the court no later than November 2010. The order has been amended to address the exclusion of claims made under OPA. Specifically, claims filed under OPA or state OPA analogue statutes enacted to impose liability for the discharge of oil or relating to any removal activities in connection with such a discharge are excluded from the limitation proceeding. If a lawsuit is filed under OPA by another party held responsible for the accident, such as the operator, the action could potentially be included in the limitation proceeding.

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

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

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

U.S. Department of Justice—On June 28, 2010, we received a letter from the DOJ asking us to meet with them to discuss our financial responsibilities in connection with the Macondo well incident and requesting that we provide them certain financial and organizational information. The letter also requested that we provide the DOJ advance notice of certain corporate actions involving the transfer of cash or other assets outside the ordinary course of business. After preliminary discussions with the DOJ, we have voluntarily agreed to provide them with 30 days notice prior to repurchasing any additional shares under our share repurchase program and prior to making substantial cash payments out of our U.S. entities, other than in the ordinary course of business. We expect to engage in further discussions with the DOJ in the future.

Drilling moratorium—On May 30, 2010, the BOE issued a notice to lessees and operators implementing a six-month moratorium on drilling activities with respect to new wells in water depths greater than 500 feet in the U.S. Gulf of Mexico. The notice also stated that the BOE would not consider for the six-month moratorium period drilling permits for wells and related activities for those water depths. In addition, the notice ordered the operators of 33 wells covered by the moratorium that were being drilled to halt drilling and take steps to secure the affected wells. The notice provided for certain exceptions to the moratorium, including, among others, operations necessary to sustain reservoir pressure from production wells and workover operations. Subsequently, on June 22, 2010, a United States District Court in the Eastern District of Louisiana granted a preliminary injunction that effectively lifted the moratorium. The U.S. government appealed the decision to the Fifth Circuit, and the Fifth Circuit upheld the injunction. On July 12, 2010, the U.S. Department of the Interior issued a revised moratorium that is scheduled to end on November 30, 2010 and that applies to deepwater drilling configurations and technologies rather then specific water depths. See “Outlook—Drilling market.”

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On June 8, 2010, the BOE issued a directive to lessees and operators implementing new governmental safety and environmental requirements applicable to both deepwater and shallow water operations. Among other things, this directive requires each operator to conduct a specific review of its operations and to certify to the BOE that it is in compliance with the new requirements and current regulations. This directive also requires operators to submit independent third-party reports on the design and operation of certain pieces of drilling equipment, including blowout preventers and other well control systems, and instructs operators to conduct tests on the functionality of various rig parts and to submit the results of those tests to the BOE. With respect to operations subject to the moratorium, the reports and certifications are required to be provided to the BOE prior to commencement of operations following expiration of the moratorium. We are not certain what requirements these new regulations will impose on us or how our operations will ultimately be impacted.

Insurance matters

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

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

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

Other insurance—We also carry $100 million of additional insurance that generally covers expenses that would otherwise be assumed by the well owner, such as costs to control the well, redrill expenses and pollution from the well. This additional insurance provides coverage for such expenses in circumstances in which we have legal or contractual liability arising from our gross negligence or willful misconduct.

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

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

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

Tax matters

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

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

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

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

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

In addition, the assessment included adjustments related to a series of restructuring transactions that occurred between 2001 and 2004. These restructuring transactions ultimately resulted in the disposition of our interests in our former subsidiary TODCO in 2004 and 2005. The authorities are disputing the amount of capital losses resulting from the disposition of TODCO. We utilized a portion of the capital losses to offset capital gains on the 2006, 2007, 2008 and 2009 tax returns. The majority of the capital losses expired on December 31, 2009. The adjustments would also impact the amount of certain net operating losses and other carryovers into 2006 and later years. The authorities are also contesting the characterization of certain amounts of income received in 2006 and 2007 as capital gain and thus the availability of the capital gain for offset by the capital loss. Claims with respect to our U.S. federal income tax returns for 2006 through 2009 could result in net tax adjustments of approximately $320 million. An unfavorable outcome on these potential adjustments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe that our tax returns are materially correct as filed, and we intend to vigorously defend against any potential claims.

The assessment also included certain claims with respect to withholding taxes and certain other items resulting in net tax adjustments of approximately $182 million, exclusive of interest. In addition, the tax authorities assessed penalties associated with the various tax adjustments in the aggregate amount of approximately $92 million, exclusive of interest. We believe that our tax returns are materially correct as filed, and we intend to vigorously defend against any potential claims.

Norwegian civil tax and criminal authorities are investigating various transactions undertaken by our subsidiaries in 2001 and 2002 as well as the actions of certain of our former external advisors on these transactions. The authorities issued tax assessments of approximately $241 million, plus interest, related to certain restructuring transactions, approximately $105 million, plus interest, related to the migration of a subsidiary that was previously subject to tax in Norway, approximately $63 million, plus interest, related to a 2001 dividend payment, and approximately $6 million, plus interest, related to certain foreign exchange deductions and dividend withholding tax. We have filed or expect to file appeals to these tax assessments. We may be required to provide some form of financial security, in an amount up to $898 million, including interest and penalties, for these assessed amounts as this dispute is appealed and addressed by the Norwegian courts. The authorities have indicated that they plan to seek penalties of 60 percent on all matters. For these matters, we believe our returns are materially correct as filed, and we have and will continue to respond to all information requests from the Norwegian authorities. We intend to vigorously contest any assertions by the Norwegian authorities in connection with the various transactions being investigated.

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During the six months ended June 30, 2010, our long-term liability for unrecognized tax benefits related to these Norwegian tax issues decreased $12 million to $169 million due to the accrual of interest being offset by favorable exchange rate fluctuations. An unfavorable outcome on the Norwegian civil tax matters could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. While we cannot predict or provide assurance as to the final outcome of these proceedings, we do not expect the ultimate resolution of these matters to have a material adverse effect on our consolidated financial position or results of operations, although it may have a material adverse effect on our consolidated cash flows.

Certain of our Brazilian income tax returns for the years 2000 through 2004 are currently under examination. The Brazil tax authorities have issued tax assessments totaling $109 million, plus a 75 percent penalty of $82 million and interest of $102 million through June 30, 2010. An unfavorable outcome on these assessments could result in a material adverse effect on our consolidated financial position, results of operations or cash flows. We believe our returns are materially correct as filed, and we are vigorously contesting these assessments. We filed a protest letter with the Brazilian tax authorities on January 25, 2008, and we are currently engaged in the appeals process.

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

Regulatory matters

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

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

Our internal compliance program has detected a potential violation of U.S. sanctions regulations in connection with the shipment of goods to our operations in Turkmenistan. Goods bound for our rig in Turkmenistan were shipped through Iran by a freight forwarder. Iran is subject to a number of economic regulations, including sanctions administered by OFAC, and comprehensive restrictions on the export and re-export of U.S.-origin items to Iran. Iran has been designated as a state sponsor of terrorism by the U.S. State Department. Failure to comply with applicable laws and regulations relating to sanctions and export restrictions may subject us to criminal sanctions and civil remedies, including fines, denial of export privileges, injunctions or seizures of our assets. We have self-reported the potential violation to OFAC and retained outside counsel who conducted an investigation of the matter and submitted a report to OFAC.

We are continuing to cooperate with the DOJ, SEC and OFAC and are in discussions with the SEC and DOJ with respect to resolution of the matter. There can be no assurance that these discussions will lead to a final settlement. We may still continue to incur significant legal fees and related expenses, and the investigations may continue to involve significant management time. We cannot predict the ultimate outcome of these investigations, the total costs to be incurred in completing the investigations, the potential impact on personnel, the effect of implementing any further measures that may be necessary to ensure full compliance with applicable laws or to

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what extent, if at all, we could be subject to fines, sanctions or other penalties. In response to these investigations, we have implemented measures to strengthen and expand our compliance program and training.

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

Other matters

In addition, from time to time, we receive inquiries from governmental regulatory agencies regarding our operations around the world, including inquiries with respect to various tax, environmental, regulatory and compliance matters. To the extent appropriate under the circumstances, we investigate such matters, respond to such inquiries and cooperate with the regulatory agencies. We recently received an administrative subpoena from OFAC concerning our operations in Myanmar. We are cooperating with OFAC and believe that all of our operations fully comply with applicable laws. Although we are unable to predict the outcome of any of these matters, we do not expect the liability, if any, resulting from these inquiries to have a material adverse effect on our consolidated statement of financial position, results of operations or cash flows.

Critical Accounting Policies and Estimates Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated

financial statements. This discussion should be read in conjunction with disclosures included in the notes to our condensed consolidated financial statements related to estimates, contingencies and new accounting pronouncements. Significant accounting policies are discussed in Note 2 to our condensed consolidated financial statements in this quarterly report on Form 10-Q and in Note 2 to our consolidated financial statements in our annual report on Form 10-K for the year ended December 31, 2009.

The preparation of our financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates, including those related to our allowance for doubtful accounts, materials and supplies obsolescence, investments, property and equipment, goodwill and other intangible assets, income taxes, share-based compensation, defined benefit pension plans and other postretirement benefits and contingent liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our annual report on Form 10-K for the year ended December 31, 2009. These estimates require significant judgments, assumptions and estimates. We have discussed the development, selection and disclosure of these critical accounting policies and estimates with the audit committee of our board of directors. During the six months ended June 30, 2010, there have been no material changes to the judgments, assumptions and estimates, upon which our critical accounting estimates are based.

New Accounting Pronouncements For a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated

financial statements, see Notes to Condensed Consolidated Financial Statements—Note 3—New Accounting Pronouncements.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk We are exposed to interest rate risk, primarily associated with our long-term and short-term debt. For our debt obligations,

including obligations of our consolidated variable interest entities, as of June 30, 2010, the following table presents our scheduled debt maturities in U.S. dollars and related weighted-average stated interest rates for the twelve months ending June 30 (in millions, except interest rate percentages):

Scheduled Maturity Date (a) Fair Value

2011 2012 2013 2014 2015 Thereafter Total 6/30/10

Total debt Fixed rate $ 1,561 $ 2,288 $ 2,289 $ 91 $ 320 $ 3,909 $ 10,458 $ 9,547 Average interest rate 2.2% 1.6% 1.2% 3.6% 2.7% 6.9% 3.5% Variable rate $ 116 $ 26 $ 778 $ 29 $ 49 $ 263 $ 1,261 $ 1,201 Average interest rate 1.0% 1.4% 3.4% 1.4% 1.8% 2.0% 2.5% __________________________ (a) Expected maturity amounts are based on the face value of debt.

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

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

At June 30, 2010, the face value of our variable-rate debt was approximately $1.3 billion, which represented 11 percent of the face value of our total debt, including the effect of our hedging activities. At June 30, 2010, our variable-rate debt, excluding the effect of our hedging activities, primarily consisted of borrowings under the ADDCL Credit Facilities and the TPDI Credit Facilities. At December 31, 2009, the face value of our variable-rate debt was approximately $1.7 billion, which represented 14 percent of the face value of our total debt, including the effect of our hedging activities. At December 31, 2009, our variable-rate debt, excluding the effect of our hedging activities, primarily consisted of notes issued under our commercial paper program and borrowings under the ADDCL Credit Facilities and the TPDI Credit Facilities. Based upon variable-rate debt amounts outstanding as of June 30, 2010 and December 31, 2009, a one percentage point change in annual interest rates would result in a corresponding change in annual interest expense of approximately $13 million and $17 million, respectively.

The fair value of our debt was $10.7 billion and $12.4 billion at June 30, 2010 and December 31, 2009, respectively. The $1.7 billion decrease was primarily due to our repayment of debt during the six months ended June 30, 2010 and changes in market rates for corporate bonds.

A large portion of our cash investments is subject to variable interest rates and would earn commensurately higher rates of return if interest rates increase. Based upon our cash investments as of June 30, 2010 and December 31, 2009, a one percentage point change in interest rates would result in a corresponding change in annual interest income of approximately $29 million and $11 million, respectively.

Foreign Exchange Risk We are exposed to foreign exchange risk associated with our international operations. For a discussion of our foreign exchange

risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our annual report on Form 10-K for the year ended December 31, 2009. There have been no material changes to these previously reported matters during the six months ended June 30, 2010.

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Item 4. Controls and Procedures Disclosure controls and procedures—In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an

evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2010 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act was (1) accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

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

Other matters—In April 2010, we implemented a new global Enterprise Resource Planning (“ERP”) system, a fully integrated software environment, designed to optimize and standardize processes in treasury, accounting, supply chain management, asset management and information technology. Although we are updating our internal controls that have been affected by the ERP implementation, we do not believe that the ERP implementation has had an adverse effect on our internal controls over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings We have certain actions, claims and other matters pending as discussed and reported in Notes to Condensed Consolidated

Financial Statements Note 12—Contingencies and “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contingencies—Macondo well incident.” We are also involved in various tax matters as described in Notes to Condensed Consolidated Financial Statements Note 6—Income Taxes. As of June 30, 2010, we were also involved in a number of lawsuits which have arisen in the ordinary course of our business and for which we do not expect the liability, if any, resulting from these lawsuits to have a material adverse effect on our current consolidated financial position, results of operations or cash flows. We cannot predict with certainty the outcome or effect of any of the matters specifically described above or of any such other pending or threatened litigation or legal proceedings. There can be no assurance that our beliefs or expectations as to the outcome or effect of any lawsuit or other matters will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.

Item 1A. Risk Factors In addition to the risk factors set forth below and the other information set forth in this quarterly report on Form 10-Q, careful

consideration should be given to factors described in “Item 1A. Risk Factors” in our annual report on Form 10-K for the year ended December 31, 2009 that could materially affect our business, financial condition or future results.

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

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

As a result of the incident, our business will be negatively impacted by the loss of revenue from the rig. The backlog associated with the Deepwater Horizon drilling contract was approximately $590 million through the end of the contract term in 2013. We do not carry insurance for loss of revenue. In addition, we expect an increase of approximately $180 million in operating and maintenance expenses in 2010 comprised primarily of approximately $70 million of insurance deductibles, approximately $30 million of higher insurance premiums, approximately $36 million of additional legal expenses related to lawsuits and investigations, net of insurance recoveries, and approximately $44 million of additional costs primarily related to our internal investigation of the Macondo well incident, including consultant costs, travel costs and other miscellaneous costs. The uncertainties and contingencies resulting from the incident could also result in a reduction of our credit ratings by the rating agencies, or have a material adverse effect on our ability to access the debt and equity markets, either of which could ultimately have an adverse impact on our liquidity in the future.

Our relationship with BP p.l.c. and its affiliates (collectively, “BP”), one of which was the operator on the Macondo well, could also be negatively impacted by the Macondo well incident. For 2009, BP was our most significant customer. As of July 15, 2010, the contract backlog associated with our contracts with BP and its affiliates was $3.4 billion.

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

We could experience a material adverse effect on our consolidated statement of financial position, results of operations and cash flows to the extent any of the operator’s indemnification obligations to us are not enforceable or the operator does not indemnify us.

The combined response team was unable to stem the flow of hydrocarbons from the well prior to the sinking of the rig. The resulting spill of hydrocarbons has been the most extensive in U.S. history. According to its public filings, as of June 30, 2010, the operator had already recognized a pre-tax charge of $32.2 billion in relation to the spill, and we expect the operator will continue to incur substantial costs related to the spill for the foreseeable future. As described under “Part I. Item 2. Management’s Discussion and Analysis of Financial

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Condition and Results of Operations—Contingencies—Macondo well incident—Contractual indemnity,” under the drilling contract for Deepwater Horizon, the operator of Deepwater Horizon has agreed to indemnify us with respect to certain matters, and we have agreed to indemnify the operator with respect to certain matters. We could ultimately experience a material adverse effect on our consolidated statement of financial position, results of operations and cash flows to the extent that BP does not honor its indemnification obligations, including by reason of financial or legal restrictions, or our insurance policies do not fully cover these amounts. In response to our demand to BP to honor its indemnity obligations, BP’s outside counsel has stated that BP could not yet determine that it was obligated to defend or indemnify us under the contract and that BP has reserved its rights in that regard. The letter also claims that the operator may not be obligated to defend or indemnify us based on various arguments, including alleged breach of contract and gross negligence or other factors, such as in the event our actions materially increased the risks to, or prejudiced the rights of, BP. The interpretation and enforceability of this contractual indemnity depends upon the specific facts and circumstances involved in this case, as governed by applicable laws. The question may ultimately need to be decided by a court or other proceeding which will need to consider the specific contract language, the facts and applicable laws.

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

The U.S. government has implemented a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. Some operators have claimed that the moratorium is a force majeure event under their drilling contracts that allow them to terminate these contracts. We do not believe that a force majeure event exists and are in discussions with our customers. In some instances, we have negotiated special lower standby dayrates with our customers for rigs in the U.S. Gulf of Mexico for the period in which the moratorium is in effect but have also agreed to extend the terms of these contracts. The moratorium may result in a number of rigs being moved, or becoming available for movement to locations outside of the U.S. Gulf of Mexico, which could potentially reduce dayrates worldwide and negatively affect our ability to contract our rigs that are currently uncontracted or coming off contract. The moratorium may also decrease the demand for drilling services and negatively affect dayrates, which could ultimately have a material adverse affect on our revenue and profitability. There can be no assurance that the moratorium will not be extended beyond the current time period.

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

Many investigations are ongoing in connection with the Macondo well incident, the outcome of which is unknown and could have a material adverse effect on us.

The Departments of Homeland Security and Interior have begun a joint investigation into the cause or causes of the Macondo well incident. The U.S. Coast Guard and the Bureau of Ocean Energy Management, Regulation, and Enforcement share jurisdiction over the investigation into the incident. In connection with the investigation, we have received a subpoena from the Office of Inspector General of the Department of Interior for certain information. In addition, an investigation has been commenced by the Chemical Safety Board, and the President of the United States has established the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling to, among other things, examine the relevant facts and circumstances concerning the cause or causes of the Macondo well incident and develop options for guarding against future oil spills associated with offshore drilling. In addition, we have participated in hearings related to the incident before various committees and subcommittees of the House of Representatives and the Senate of the United States. These hearings may result in changes in laws and regulations, such as the Consolidated Land, Energy, and Aquatic Resources Act of 2010 recently passed by the House of Representatives, that may have a material adverse effect on the level of liability that we expect in connection with the Macondo well incident.

On June 28, 2010, we received a letter from the DOJ asking us to meet with them to discuss our financial responsibilities in connection with the Macondo well incident and requesting that we provide them certain financial and organizational information. The letter also requested that we provide the DOJ advance notice of certain corporate actions involving the transfer of cash or other assets outside the ordinary course of business. After preliminary discussions with the DOJ, we have voluntarily agreed to provide them with 30 days notice prior to repurchasing any additional shares under our share repurchase program and prior to making substantial cash payments out of our U.S. entities, other than in the ordinary course of business. We expect to engage in further discussions with the DOJ in the future.

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We have significant carrying amounts of goodwill and long-lived assets that are subject to impairment testing.

At June 30, 2010, the carrying amount of our property and equipment was $22.5 billion, representing 60 percent of our total assets, and the carrying amount of our goodwill was $8.1 billion, representing 22 percent of our total assets. In accordance with our critical accounting policies, we review our property and equipment for impairment when events or changes in circumstances indicate that carrying amounts of our assets held and used may not be recoverable, and we conduct impairment testing for our goodwill when events and circumstances indicate that the fair value of a reporting unit may have fallen below its carrying amount.

Our industry has historically been cyclical and is impacted by oil and gas price levels and volatility. There have been periods of high demand, short rig supply and high dayrates, followed by periods of low demand, excess rig supply and low dayrates. Changes in commodity prices can have a dramatic effect on rig demand, and periods of excess rig supply intensify the competition in the industry and often result in rigs being idle for long periods of time. We have previously experienced weakness in our Midwater Floater, High Specification Jackup and Standard Jackup markets. Additionally, uncertainties have recently developed, particularly with regard to our High-Specification Floater fleet, as a result of the drilling moratorium in the U.S. Gulf of Mexico. We have idled and stacked rigs in several classes of our fleet, and may in the future, idle or stack additional rigs or enter into lower dayrate contracts in response to market conditions.

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

A change in tax laws, treaties or regulations, or their interpretation, of any country in which we operate 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 and proposals that could override certain tax treaties and limit treaty benefits on certain payments by U.S. subsidiaries to non-U.S. affiliates.

Our company has come under investigation by two U.S. congressional committees, the Senate Finance Committee and the Senate Permanent Subcommittee on Investigations. These committees have launched separate investigations into our tax practices, specifically including but not limited to the U.S. tax implications of our change of jurisdiction of incorporation to the Cayman Islands in 1999 and to Switzerland in 2008. We are cooperating with the committees and responding to their inquiries. The outcome of the investigations is uncertain. A resulting material change in tax laws or policies, or their interpretation, could result in a higher effective tax rate on our worldwide earnings and such change could be significant to our financial results.

A loss of a major tax dispute or a successful tax challenge to our operating structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries 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 are a Swiss corporation that operates through our various subsidiaries in a number of countries throughout the world. Consequently, we are subject to tax laws, treaties and regulations in and between the countries in which we operate. Our income taxes are based upon the applicable tax laws and tax rates in effect in the countries in which we operate and earn income as well as upon our operating structures in these countries.

Our income tax returns are subject to review and examination. We do not recognize the benefit of income tax positions we believe are more likely than not to be disallowed upon challenge by a tax authority. If any tax authority successfully challenges our operational structure, intercompany pricing policies or the taxable presence of our key subsidiaries in certain countries; or if the terms of certain income tax treaties are interpreted in a manner that is adverse to our structure; or if we lose a material tax dispute in any country, particularly in the U.S., Norway or Brazil, our effective tax rate on our worldwide earnings could increase substantially and our earnings

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and cash flows from operations could be materially adversely affected. For example, there is considerable uncertainty as to the activities that constitute being engaged in a trade or business within the U.S. (or maintaining a permanent establishment under an applicable treaty), so we cannot be certain that the IRS will not contend successfully that we or any of our key subsidiaries were or are engaged in a trade or business in the U.S. (or, when applicable, maintained or maintains a permanent establishment in the U.S.). If we or any of our key subsidiaries were considered to have been engaged in a trade or business in the U.S. (when applicable, through a permanent establishment), we could be subject to U.S. corporate income and additional branch profits taxes on the portion of our earnings effectively connected to such U.S. business during the period in which this was considered to have occurred, in which case our effective tax rate on worldwide earnings for that period could increase substantially, and our earnings and cash flows from operations for that period could be adversely affected.

Our company has come under investigation by two U.S. congressional committees, the Senate Finance Committee and the Senate Permanent Subcommittee on Investigations. These committees have launched separate investigations into our tax practices, specifically including but not limited to the U.S. tax implications of our change of jurisdiction of incorporation to the Cayman Islands in 1999 and to Switzerland in 2008. We are cooperating with the committees and responding to their inquiries. The outcome of the investigations is uncertain. A resulting material change in tax laws or policies, or their interpretation, or a successful challenge to our operating structure, could result in a substantially higher effective tax rate on our worldwide earnings and such change could be significant to our financial results.

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

Issuer Purchases of Equity Securities

Period

(a) Total Number of Shares Purchased

(1)

(b) Average Price Paid Per Share

(c) Total Number of Shares Purchased as Part of Publicly

Announced Plans or Programs (2)

(d) Maximum Number (or Approximate Dollar Value)

of Shares that May Yet Be Purchased Under the Plans or

Programs (2) (in millions)

April 2010 1,369,233 $ 87.60 1,369,000 $ 3,020 May 2010 778,198 $ 77.08 777,267 $ 2,960 June 2010 173 $ 47.70 — $ 2,960

Total 2,147,604 $ 83.78 2,146,267 $ 2,960 __________________________ (1) Total number of shares purchased in the second quarter of 2010 includes 1,337 shares withheld by us in satisfaction of withholding taxes due upon

the vesting of restricted shares granted to our employees under our Long-Term Incentive Plan and 2,146,267 shares repurchased under the share repurchase program described in (2) below.

(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 U.S. $3.2 billion at an exchange rate as of the close of trading on June 30, 2010 of USD 1.00 to CHF 1.08). On February 12, 2010, our board of directors authorized our management to implement the share repurchase program. We may decide, based upon our ongoing capital requirements, the price of our shares, matters relating to the Macondo well incident, regulatory and tax considerations, cash flow generation, the relationship between our contract backlog and our debt, general market conditions and other factors, that we should retain cash, reduce debt, make capital investments or otherwise use cash for general corporate purposes, and consequently, repurchase fewer or no shares under this program. Decisions regarding the amount, if any, and timing of any share repurchases would be made from time to time based upon these factors. Through June 30, 2010, we have repurchased a total of 2,863,267 of our shares under this share repurchase program at a total cost of $240 million ($83.74 per share). We have agreed not to repurchase any additional shares under our share repurchase program without 30 days notice to the DOJ. See “Part I. Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Sources and Uses of Liquidity—Overview.”

Item 6. Exhibits (a) Exhibits

The following exhibits are filed in connection with this Report:

Number Description

† 3.1 Articles of Association of Transocean Ltd.

† * 10.1 Drilling Contract between Vastar Resources, Inc. and R&B Falcon Drilling Co. dated December 9, 1998 with respect to the Deepwater Horizon, as amended

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

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

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

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

† 101.INS XBRL Instance Document

† 101.SCH XBRL Taxonomy Extension Schema

† 101.CAL XBRL Taxonomy Extension Calculation Linkbase

† 101.DEF XBRL Taxonomy Extension Definition Linkbase

† 101.LAB XBRL Taxonomy Extension Label Linkbase

† 101.PRE XBRL Taxonomy Extension Presentation Linkbase ____________________ † Filed herewith.

* Compensatory plan or arrangement.

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this

report to be signed on its behalf by the undersigned, thereunto duly authorized, on August 4, 2010.

TRANSOCEAN LTD. By: /s/ Ricardo H. Rosa

Ricardo H. Rosa Senior Vice President and Chief Financial Officer (Principal Financial Officer)

By: /s/ John H. Briscoe

John H. Briscoe Vice President and Controller (Principal Accounting Officer)

Exhibit 31.1

CEO CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Steven L. Newman, certify that: 1. I have reviewed this report on Form 10-Q of Transocean Ltd.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact

necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures

(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be

designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over

financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial

reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the

registrant’s internal control over financial reporting. Dated: August 4, 2010 /s/ Steven L. Newman

Name: Steven L. Newman President and Chief Executive Officer

Exhibit 31.2

CFO CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 I, Ricardo H. Rosa, certify that: 1. I have reviewed this report on Form 10-Q of Transocean Ltd.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact

necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures

(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be

designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the

registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over

financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial

reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the

registrant’s internal control over financial reporting.

Dated: August 4, 2010 /s/ Ricardo H. Rosa Name: Ricardo H. Rosa Senior Vice President and Chief Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b)

OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Steven L. Newman, Chief Executive Officer of Transocean Ltd., a Swiss corporation (the “Company”), hereby certify, to my knowledge, that:

(1) the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: August 4, 2010 /s/ Steven L. Newman Name: Steven L. Newman President and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Transocean Ltd. and will be retained by Transocean Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b)


Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Ricardo H. Rosa, Senior Vice President and Chief Financial Officer of Transocean Ltd., a Swiss corporation (the “Company”), hereby certify, to my knowledge, that:

(1) the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: August 4, 2010 /s/ Ricardo H. Rosa Name: Ricardo H. Rosa Senior Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Transocean Ltd. and will be retained by Transocean Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.

Statuten

von TransoceanLtd.

vom 14. Mai 2010

Articles ofAssociation of

Transocean Ltd.

as of May 14, 2010

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Abschnitt 1:Firma, Sitz, Zweck und Dauer der Gesellschaft

Section 1:Name, Place of Incorporation, Purpose andDuration of the Company

Artikel 1 Article 1Firma, Sitz Unter der Firma

Transocean Ltd.(die Gesellschaft)

besteht eine Aktiengesellschaft mit Sitz inSteinhausen, Kanton Zug, Schweiz.

Name,Place ofIncorporation

Under the name

Transocean Ltd.(the Company)

there exists a corporation with its place ofincorporation in Steinhausen, Canton of Zug,Switzerland.

Zweck Artikel 2 Purpose Article 21 Zweck der Gesellschaft ist der Erwerb, das

Halten, die Verwaltung, die Verwertung und dieV e r ä u s s e r u n g v o n B e t e i l i g u n g e n a nUnternehmen im In− und Ausland, ob direkt oderindirekt, insbesondere an Unternehmen, die imBereich der Erbringung von Dienstleistungen fürOffshore Öl−und Gasbohrungen, einschliesslichManagement Dienstleistungen, Bohringenieurs−u n d B o h r − P r o j e k tManagement−Dienstleistungen für Öl−undG a s b o h r u n g e n , s o w i e v o n Ö l − u n dGas−Exploration und −Produktions-aktivitätentät ig sind, sowie die Finanzierung dieserAktivitäten. Die Gesellschaft kann Grundstückeund gewerbliche Schutzrechte im In− undAusland erwerben, halten, verwalten, belastenund verkaufen.

1 The purpose of the Company is to acquire,hold, manage, exploit and sell, whether directlyor indirectly, participations in businesses inSwitzer land and abroad, in part icular inbusinesses that are involved in offshorecontract drilling services for oil and gas wells,oil and gas drilling management services,drilling engineering services and drilling projectmanagement se rv ices and o i l and gasexploration and production activities, and toprovide f inancing for this purpose. TheCompany may acqu i re , ho ld , manage ,mortgage and sell real estate and intellectualproperty rights in Switzerland and abroad.

2 Die Gesellschaft kann alle Tätigkeiten ausübenund Massnahmen ergreifen, die geeigneterscheinen, den Zweck der Gesellschaft zufördern, oder die mit diesem zusammenhängen.

2 The Company may engage in all types oftransactions and may take all measures thatappear appropriate to promote the purpose ofthe Company or that are related thereto.

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Artikel 3 Article 3Dauer Die Dauer der Gesellschaft ist unbeschränkt. Duration The duration of the Company is unlimited.

Abschnitt 2:Aktienkapital

Section 2:Share Capital

Artikel 4 Article 4Aktienkapital Das Aktienkapital der Gesellschaft beträgt

CHF 5'028'529’470, eingeteilt in 335'235’298 vollliberierte Namenaktien. Jede Namenaktie hateinen Nennwert von CHF 15 (jede Namenaktienachfolgend bezeichnet als Aktie bzw. dieAktien).

ShareCapital

T h e s h a r e c a p i t a l o f t h e C o m p a n y i sCHF 5,028,529,470 and is d iv ided in to335,235,298 fully paid registered shares. Eachregistered share has a par value of CHF 15(each such registered share hereinafter aShare and collectively the Shares).

Artikel 5 Article 5Genehmigtes Kapital 1 Der Verwa l tungsra t i s t e rmäch t ig t , das

Aktienkapital jederzeit bis zum 18. Dezember2010 im Maximalbetrag von CHF 2’514’264’735durch Ausgabe von höchstens 167’617’649vollständig zu liberierenden Aktien mit einemNennwert von je CHF 15 zu erhöhen. EineErhöhung (i) auf dem Weg einer Festübernahmedurch eine Bank, ein Bankenkonsortium oderDritte und eines anschliessenden Angebots and i e b i s h e r i g e n A k t i o n ä r e s o w i e ( i i ) i nTeilbeträgen ist zulässig.

AuthorizedShareCapital

1 The Board of Directors is author ized toincrease the share capital, at any time untilDecember 18, 2010, by a maximum amount ofCHF 2,514,264,735 by issuing a maximum of167,617,649 fully paid up Shares with a parvalue of CHF 15 each. An increase of theshare capital ( i) by means of an offeringunderwri t ten by a f inancial inst i tut ion, asyndicate of financial institutions or anotherthird party or third parties, followed by an offerto the then−exist ing shareholders of theCompany, and (ii) in partial amounts shall bepermissible.

2 Der Verwaltungsrat legt den Zeitpunkt derAusgabe, den Ausgabebetrag, die Art, wie dieneuen Aktien zu liberieren sind, den Beginn derDividendenberechtigung, die Bedingungen fürdie Ausübung der Bezugsrechte sowie dieZuteilung der Bezugsrechte, welche nichtausgeübt wurden, fest . Nicht−ausgeübteBezugsrechte kann der Verwaltungsrat verfallenlassen, oder er kann diese bzw. Aktien, fürwelche Bezugsrechte eingeräumt, aber nichtausgeüb t werden , zu Mark tkond i t i onenplatzieren oder anderweitig im Interesse derGesellschaft verwenden.

2 The Board of Directors shall determine the timeof the issuance, the issue price, the manner inwhich the new Shares have to be paid up, thedate from which the Shares carry the right todividends, the conditions for the exercise of thepreempt ive r igh ts and the a l lo tment o fp reemp t i ve r i gh t s t ha t have no t beenexercised. The Board of Directors may allowthe preemptive rights that have not beenexercised to expire, or it may place such rightsor Shares, the preemptive rights of which havenot been exercised, at market conditions or usethem otherwise in the interest of the Company.

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3 Der Ve rwa l t ungs ra t i s t e rmäch t i g t , d i eBezugsrechte der Aktionäre zu entziehen oderzu beschränken und einzelnen Aktionären oderDritten zuzuweisen:

(a) wenn der Ausgabebetrag derneuen Aktien unter Berücksichtigungdes Marktpreises festgesetzt wird;oder

( b ) f ü r d i e Ü b e r n a h m e v o nUnternehmen, Unternehmensteilenoder Bete i l igungen oder fü r d ieFinanzierung oder Refinanzierungso lcher T ransak t ionen oder d ieF i n a n z i e r u n g v o n n e u e nInvestitionsvorhaben der Gesellschaft;oder

(c) zum Zwecke der Erweiterungdes Aktionärskreises in bestimmtenFinanz− oder Investoren−Märkten, zurB e t e i l i g u n g v o n s t r a t e g i s c h e nPartnern, oder im Zusammenhang mitder Kotierung von neuen Aktien aninländischen oder ausländischenBörsen; oder

( d ) f ü r d i e E i n r ä u m u n g e i n e rMehrzuteilungsoption (Greenshoe) vonbis zu 20% der zu platzierenden oderzu ve r kau fenden Ak t i en an d i eb e t r e f f e n d e n E r s t k ä u f e r o d e rFestübernehmer im Rahmen einerA k t i e n p l a t z i e r u n g o d e r e i n e sAktienverkaufs; oder

( e ) f ü r d i e B e t e i l i g u n g v o nMitgliedern des Verwaltungsrates,Mi tg l ieder der Geschäf ts le i tung,Mitarbeitern, Beauftragten, Beraternoder anderen Personen, die für dieG e s e l l s c h a f t o d e r e i n e i h r e rTochtergesellschaften Leistungenerbringen; oder

(f) wenn ein Aktionär oder eineG r u p p e v o n i n g e m e i n s a m e rAbsprache handelnden Aktionärenmehr als 15% des im Handelsregistereingetragenen Aktienkapitals derGesellschaft auf sich vereinigt hat,ohne den übrigen Aktionären ein vomV e r w a l t u n g s r a t e m p f o h l e n e sÜbernahmeangebot zu unterbreiten;oder zur Abwehr eines unterbreiteten,a n g e d r o h t e n o d e r p o t e n t i e l l e nÜbernahmeangebotes, welches derVerwaltungsrat, nach Konsultation mite i n e m v o n i h m b e i g e z o g e n e nunabhängigen Finanzberater, denA k t i o n ä r e n n i c h t z u r A n n a h m eempfohlen hat, weil der Verwaltungsratdas Übernahmeangebot in finanziellerHinsicht gegenüber den Aktionärennicht als fair beurteilt hat.

3 The Board of Directors is author ized towithdraw or limit the preemptive rights of theshareholders and to allot them to individualshareholders or third parties:

(a) if the issue price of the newShares is determined by reference tothe market price; or

(b ) f o r t he acqu i s i t i on o f anenterprise, part(s) of an enterprise orparticipations, or for the financing orr e f i n a n c i n g o f a n y o f s u c htransactions, or for the financing ofn e w i n v e s t m e n t p l a n s o f t h eCompany; or

(c) for purposes of broadening theshareholder const i tuency of theCompany in certain f inancial orinvestor markets, for purposes of theparticipation of strategic partners, orin connection with the listing of newShares on domestic or foreign stockexchanges; or

(d) for purposes of granting anover−allotment option (Greenshoe) ofup to 20% of the total number ofShares in a placement or sale ofShares to the respect ive in i t ia lpurchaser(s) or underwriter(s); or

(e) for the participation of membersof the Board of Directors, members oft h e e x e c u t i v e m a n a g e m e n t ,employees, contractors, consultantsor other persons performing servicesfor the benefit of the Company or anyof its subsidiaries; or

(f) following a shareholder or agroup of shareholders act ing inc o n c e r t h a v i n g a c c u m u l a t e dshareholdings in excess of 15% ofthe share capital registered in thecommercial register without havingsubmitted to the other shareholders atakeover offer recommended by theBoard of Directors, or for the defenseof an actual, threatened or potentialtakeover bid, in relation to which theBoard of Directors, upon consultationwith an independent financial adviserretained by it, has not recommendedto the shareholders acceptance onthe basis that the Board of Directorshas not found the takeover bid to befinancially fair to the shareholders.

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4 D i e n e u e n A k t i e n u n t e r l i e g e n d e nEintragungs-beschränkungen in das Aktienbuchvon Artikel 7 und 9 dieser Statuten.

4 The new Shares shal l be subject to thelimitations for registration in the share registerpursuant to Articles 7 and 9 of these Articles ofAssociation.

Artikel 6 Article 6Bedingtes Aktienkapital 1 Das Aktienkapital kann sich durch Ausgabe von

höchstens 167’617’649 voll zu liberierendenAk t i en im Nennwer t von j e CHF 15 umhöchstens CHF 2’514’264’735 erhöhen durch:

(a) die Ausübung von Wandel−,Tausch−, Options−, Bezugs− oderähnlichen Rechten auf den Bezug vonAktien (nachfolgend die Rechte ) ,welche Dritten oder Aktionären inVerbindung mit auf nationalen oderinternationalen Kapitalmärkten neuo d e r b e r e i t s b e g e b e n e nAnleihensobligationen, Optionen,W a r r a n t s o d e r a n d e r e nFinanzmarktinstrumenten oder neueno d e r b e r e i t s b e s t e h e n d e nvertraglichen Verpfl ichtungen derG e s e l l s c h a f t , e i n e r i h r e rGruppengesellschaften oder einerderen Rechtsvorgänger eingeräumtwerden (nachfolgend zusammen diem i t R e c h t e n v e r b u n d e n e nObligationen); und/oder

(b) die Ausgabe von Aktien oder mitRechten verbundenen Obligationen anMitgl ieder des Verwaltungsrates,Mi tg l ieder der Geschäf ts le i tung,Arbeitnehmer, Beauftragte, Berateroder anderen Personen, welcheDienstleistungen für die Gesellschaftoder ihre Tochtergesel lschaf tenerbringen.

ConditionalShareCapital

1 The share capital may be increased in anamount not to exceed CHF 2,514,264,735through the issuance of up to 167,617,649 fullypaid−up Shares with a par value of CHF 15 perShare through:

(a) the exercise of conversion,exchange, option, warrant or similarrights for the subscription of Shares(hereinafter the Rights) granted toth i rd part ies or shareholders inconnection with bonds, opt ions,warrants or other securities newly ora l r e a d y i s s u e d i n n a t i o n a l o rinternational capital markets or newor a l ready ex is t ing cont rac tua lobligations by or of the Company,one of its group companies, or any ofthe i r respec t i ve p redecesso rs( h e r e i n a f t e r c o l l e c t i v e l y , t h eRights−Bearing Obligations); and/or

(b) the issuance of Shares orRights−Bearing Obligations grantedto members of the Board of Directors,m e m b e r s o f t h e e x e c u t i v em a n a g e m e n t , e m p l o y e e s ,contractors, consultants or otherpersons providing services to theCompany or its subsidiaries.

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2 Bei der Ausgabe von mit Rechten verbundenenObligationen durch die Gesellschaft, eine ihrerGruppengesel lschaf ten oder e ine derenRechtsvorgänger ist das Bezugsrecht derAktionäre ausgeschlossen. Zum Bezug derneuen Aktien, die bei Ausübung von mit Rechtenverbundenen Obligationen ausgegeben werden,sind die jeweiligen Inhaber der mit Rechtenverbundenen Obligationen berechtigt. DieBedingungen der mit Rechten verbundenenObligationen sind durch den Verwaltungsratfestzulegen.

2 The preemptive rights of the shareholders shallbe excluded in connection with the issuance ofany Rights−Bear ing Obl igat ions by theCompany, one of its group companies, or anyof the i r respect ive predecessors . Thethen−current owners of such Rights−BearingObligations shall be entitled to subscribe for thenew Shares issued upon conversion, exchangeo r e x e r c i s e o f a n y R i g h t s − B e a r i n gO b l i g a t i o n s . T h e c o n d i t i o n s o f t h eR i g h t s − B e a r i n g O b l i g a t i o n s s h a l l b edetermined by the Board of Directors.

3 Der Ve rwa l t ungs ra t i s t e rmäch t i g t , d i eVorwegzeichnungsrechte der Aktionäre imZusammenhang mit der Ausgabe von mitRechten verbundenen Obligationen durch dieG e s e l l s c h a f t o d e r e i n e i h r e rGruppengesellschaften zu beschränken oderaufzuheben, falls (1) die Ausgabe zum Zweckeder Finanzierung oder Refinanzierung derÜ b e r n a h m e v o n U n t e r n e h m e n ,Unternehmenstei len, Betei l igungen oderInvest i t ionen, oder (2 ) d ie Ausgabe aufnationalen oder internationalen Finanzmärktenoder im Rahmen einer Privatplatzierung erfolgt.Wird das Vorwegzeichnungsrecht weder direktnoch indirekt durch den Verwaltungsrat gewährt,gilt Folgendes:

(a) Die mit Rechten verbundenenObl igat ionen sind zu den jewei lsm a r k t ü b l i c h e n B e d i n g u n g e nauszugeben oder einzugehen; und

(b) der Umwandlungs−, Tausch−oder sonstige Ausübungspreis der mitRechten verbundenen Obligationen istu n t e r B e r ü c k s i c h t i g u n g d e sM a r k t p r e i s e s i m Z e i t p u n k t d e rA u s g a b e d e r m i t R e c h t e nv e r b u n d e n e n O b l i g a t i o n e nfestzusetzen; und

(c) die mit Rechten verbundenenObligationen sind höchstens während30 Jahren ab dem jeweiligen Zeitpunktder betreffenden Ausgabe oder desbetreffenden Abschlusses wandel−,tausch− oder ausübbar.

3 The Board of Directors shall be authorized towithdraw or limit the advance subscriptionrights of the shareholders in connection withthe issuance by the Company or one of itsg r o u p c o m p a n i e s o f R i g h t s − B e a r i n gObligations if (1) the issuance is for purposesof financing or refinancing the acquisition of anenterprise, parts of an enterprise, participationsor investments or (2) the issuance occurs innational or international capital markets orthrough a private placement.If the advance subscription rights are neithergranted directly nor indirectly by the Board ofDirectors, the following shall apply:

(a) The Rights−Bearing Obligationsshall be issued or entered into atmarket conditions; and

(b) the conversion, exchange orexercise price of the Rights−BearingO b l i g a t i o n s s h a l l b e s e t w i t hreference to the market conditionsprevailing at the date on which theRights−Bearing Obl igat ions areissued; and

(c) the Rights−Bearing Obligationsmay be converted, exchanged orexercised during a maximum periodof 30 years from the date of therelevant issuance or entry.

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4 Bei der Ausgabe von Aktien oder mit Rechtenverbundenen Obligationen gemäss Artikel6 Absa tz 1 (b ) d ieser S ta tu ten s ind dasB e z u g s r e c h t w i e a u c h d a sVorwegzeichnungsrecht der Aktionäre derGesellschaft ausgeschlossen. Die Ausgabe vonA k t i e n o d e r m i t R e c h t e n v e r b u n d e n e nObligationen an die in Artikel 6 Absatz 1(b)dieser Statuten genannten Personen erfolgtg e m ä s s e i n e m o d e r m e h r e r e nBetei l igungsplänen der Gesel lschaft . DieAusgabe von Aktien an die Artikel 6 Absatz 1(b)dieser Statuten genannten Personen kann zueinem Preis erfolgen, der unter dem Kurs derBörse liegt, an der die Aktien gehandelt werden,muss aber mindestens zum Nennwert erfolgen.

4 T h e p r e e m p t i v e r i g h t s a n d a d v a n c esubscription rights of the shareholders shall beexcluded in connection with the issuance ofany Shares or Rights−Bearing Obligationspursuant to Article 6 para 1(b) of these Articlesof Association. Shares or Rights−BearingObligations shall be issued to any of thepersons referred to in Article 6 para 1(b) ofthese Articles of Association in accordancewith one or more benefit or incentive plans ofthe Company. Shares may be issued to any ofthe persons referred to in Article 6 para 1(b) ofthese Articles of Association at a price lowerthan the current market price quoted on thestock exchange on which the Shares aretraded, but at least at par value.

5 Die neuen Aktien, welche über die Ausübungvon mit Rechten verbundenen Obligationene r w o r b e n w e r d e n , u n t e r l i e g e n d e nEintragungs-beschränkungen in das Aktienbuchgemäss Artikel 7 und 9 dieser Statuten.

5 The new Shares acquired through the exerciseof Rights−Bearing Obligations shall be subjectto the limitations for registration in the shareregister pursuant to Articles 7 and 9 of theseArticles of Association.

Artikel 7 Article 7Aktienbuch, Rechtsausübung,Eintragungsbe−schränkungen,Nominees

1 Die Gesellschaft oder von ihr beauftragte Dritteführen ein Akt ienbuch. Dar in werden dieEigentümer und Nutzniesser der Aktien sowieNominees mit Namen und Vornamen, Wohnort,A d r e s s e u n d S t a a t s a n g e h ö r i g k e i t ( b e ijurist ischen Personen mit Firma und Sitz)eingetragen. Die Gesellschaft oder der von ihrmit der Aktienbuchführung beauftragte Dritte istberechtigt, bei Eintragung im Aktienbuch von derantragstellenden Person einen angemessenenNachweis seiner Berechtigung an den Aktien zuv e r l a n g e n . Ä n d e r t e i n e i m A k t i e n b u c heingetragene Person ihre Adresse, so hat siedies dem Aktienbuchführer mitzuteilen. Solangedies nicht geschehen ist, gelten alle brieflichenMi t te i lungen der Gese l lschaf t an d ie imAkt ienbuch e ingetragenen Personen a lsrechtsgül t ig an die bisher im Akt ienbucheingetragene Adresse erfolgt.

ShareRegister,Exercise ofRights,RestrictionsonRegistration,Nominees

1 The Company shall maintain, itself or through athird party, a share register that l ists thesurname, first name, address and citizenship(in the case of legal entities, the companyname and company seat) of the holders andusufructuaries of the Shares as well as thenominees. The Company or the third partymaintaining the share register on behalf of theCompany shall be entitled to request at thetime of the entry into the share register fromthe Person requesting such entry appropriateevidence of that Person's title to the Shares. Aperson recorded in the share register shallnotify the share registrar of any change inaddress. Until such notification shall haveoccurred, all written communication from theCompany to persons of record shal l bedeemed to have validly been made if sent tothe address recorded in the share register.

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2 Ein Erwerber von Aktien wird auf Gesuch alsAk t ionär m i t S t immrech t im Ak t ienbucheingetragen, vorausgesetzt, dass ein solcherErwerber ausdrücklich erklärt, die Aktien imeigenen Namen und auf eigene Rechnungerworben zu haben. Der Verwaltungsrat kannNominees, welche Aktien im eigenen Namenaber auf fremde Rechnung halten, als Aktionäremit Stimmrecht im Aktienbuch der Gesellschafteintragen. Die an den Aktien wirtschaftlichBerechtigten, welche die Aktien über einenNominee halten, üben Aktionärsrechte mittelbarüber den Nominee aus.

2 An acquirer of Shares shall be recorded uponrequest in the share register as a shareholderwith voting rights; provided, however, that anysuch acquirer expressly declares to haveacquired the Shares in its own name and for itsown account, save that the Board of Directorsmay record nominees who hold Shares in theirown name, but for the account of third parties,as shareholders of record with voting rights inthe share register of the Company. Beneficialowners of Shares who hold Shares through anominee exercise the shareholders' rightsthrough the intermediation of such nominee.

3 Der Verwaltungsrat kann nach Anhörung deseingetragenen Aktionärs dessen Eintragung imAktienbuch als Aktionär mit Stimmrecht mitRückwirkung auf das Datum der Eintragungstreichen, wenn diese durch falsche oderirreführende Angaben zustande gekommen ist.Der Betroffene muss über die Streichung sofortinformiert werden.

3 After hearing the registered shareholderconcerned, the Board of Directors may cancelthe registration of such shareholder as ashareholder with voting rights in the shareregister with retroactive effect as of the date ofregistration, if such registration was madebased on false or misleading information. There levant shareholder shal l be in formedpromptly of the cancellation.

Artikel 8 Article 8Form der Aktien 1 Die Gesel lschaft g ibt Akt ien in Form von

E i n z e l u r k u n d e n , G l o b a l u r k u n d e n o d e rWertrechten aus. Der Gesellschaft steht es imRahmen der gesetzlichen Vorgaben frei, ihre ineiner dieser Formen ausgegebenen Aktienjederzeit und ohne Zustimmung der Aktionäre ine i n e a n d e r e F o r m u m z u w a n d e l n . D i eGesellschaft trägt die Kosten, die bei einersolchen Umwandlung anfallen.

Form ofShares

1 The Company may issue Shares in the form ofindividual certificates, global certificates oruncertificated securities. Subject to applicablelaw, the Company may convert the Sharesfrom one form into another form at any timeand without the approval of the shareholders.The Company shall bear all cost associatedwith any such conversion.

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2 E i n A k t i o n ä r h a t k e i n e n A n s p r u c h a u fU m w a n d l u n g v o n i n b e s t i m m t e r F o r mausgegebenen Aktien in eine andere Form.Jeder Akt ionär kann jedoch jederzei t d ieAusstellung einer Bescheinigung über die voni h m g e m ä s s A k t i e n b u c h g e h a l t e n e nNamenaktien verlangen.

2 A shareholder has no r ight to request aconversion of the Shares from one form intoanother form. Each shareholder may, however,at any time request a written attestation of thenumber of Shares held by it as reflected in theshare register.

3 W e r d e n B u c h e f f e k t e n i m A u f t r a g d e rGesellschaft oder des Aktionärs von einerVerwahrungsstelle, einem Registrar, TransferAgenten, einer Trust Gesellschaft, Bank odereiner ähnlichen Gesellschaft verwaltet (dieVerwahrungsstel le), so setzt Wirksamkeitgegenüber der Gesellschaft voraus, dass dieseBucheffekten und die damit verbundenenRechte unter Mitwirkung der Verwahrungsstelleübertragen oder daran Sicherheiten bestelltwerden.

3 If intermediated securities are administered onbehalf of the Company or a shareholder by anintermediary, registrar, transfer agent, trustc o m p a n y , b a n k o r s i m i l a r e n t i t y ( t h eIntermediary), any transfer or grant of asecur i ty in terest in such in termediatedsecu r i t i es and t he appu r tenan t r i gh t sassociated therewith, in order for such transferor grant of a security interest to be valid againstthe Company, requires the cooperation of theIntermediary.

4 Für den Fall, dass die Gesellschaft beschliesst,Aktienzertifikate zu drucken und auszugeben,müssen die Aktienzertifikate die Unterschrift vonzwei zeichnungsberechtigten Personen tragen.Mindestens eine dieser Personen muss einM i t g l i e d d e s V e r w a l t u n g s r a t e s s e i n .Faksimile−Unterschriften sind erlaubt.

4 If the Company decides to print and delivershare certificates, the share certificates shallbear the signatures of two duly authorizedsignatories of the Company, at least one ofwhich shall be a member of the Board ofDirectors. These signatures may be facsimilesignatures.

Artikel 9 Article 9Rechtsausübung 1 Die Gesellschaft anerkennt nur einen Vertreter

pro Aktie.Exercise ofRights

1 The Company shall only accept onerepresentative per Share.

2 Stimmrechte und die damit verbundenen Rechtekönnen der Gesellschaft gegenüber von einemAktionär, Nutzniesser der Aktien oder Nomineejeweils nur im Umfang ausgeübt werden, wied i e s e r m i t S t i m m r e c h t i m A k t i e n b u c heingetragen ist.

2 Voting rights and appurtenant rights associatedtherewith may be exercised in relation to theCompany by a shareholder, usufructuary ofShares or nominee only to the extent that suchperson is recorded in the share register withthe right to exercise his voting rights.

Abschnitt 3:GesellschaftsorganeA. Generalversammlung

Section 3:Corporate BodiesA. General Meeting of Shareholders

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Artikel 10 Article 10Zuständigkeit Die Generalversammlung ist das oberste Organ

der Gesellschaft.Authority The General Meeting of Shareholders is the

supreme corporate body of the Company.Artikel 11 Article 11

OrdentlicheGeneralver−sammlung

Die ordentliche Generalversammlung findetalljährlich innerhalb von sechs Monaten nachSchluss des Geschäftsjahres statt. Spätestenszwanzig Kalendertage vor der Versammlungs i n d d e r G e s c h ä f t s b e r i c h t u n d d e rR e v i s i o n s b e r i c h t d e n A k t i o n ä r e n a mGesellschaftssitz zur Einsicht aufzulegen. JederAktionär kann verlangen, dass ihm unverzüglicheine Ausfertigung des Geschäftsberichts unddes Revis ionsber ichts ohne Kostenfolgez u g e s a n d t w i r d . D i e i m A k t i e n b u c heingetragenen Aktionäre werden über dieVerfügbarkeit des Geschäftsberichts und desRevisionsberichts durch schriftliche Mitteilungunterrichtet.

AnnualGeneralMeeting

The Annual General Meeting shall be heldeach year within six months after the close ofthe fiscal year of the Company. The AnnualReport and the Auditor's Report shall be madeavailable for inspection by the shareholders atthe registered office of the Company no laterthan twenty calendar days prior to the AnnualGeneral Meeting. Each shareholder is entitledto request prompt delivery of a copy of theAnnual Report and the Auditor's Report free ofcharge. Shareholders of record will be notifiedof the availability of the Annual Report and theAuditor's Report in writing.

Artikel 12 Article 12Ausser−ordentlicheGeneralver-sammlung

1 Ausserordentliche Generalversammlungenfinden in den vom Gesetz vorgesehenen Fällenstatt, insbesondere, wenn der Verwaltungsrat esfür notwendig oder angezeigt erachtet oder dieRevisionsstelle dies verlangt.

ExtraordinaryGeneralMeetings

1 Extraordinary General Meetings shall be heldin the circumstances provided by law, inpa r t i cu la r when deemed necessary o rappropriate by the Board of Directors or if sorequested by the Auditor.

2 Ausserdem muss der Verwaltungsrat eineausserordent l iche Genera lversammlungeinberufen, wenn es eine Generalversammlungso beschliesst oder wenn ein oder mehrereAktionäre, welche zusammen mindestens denz e h n t e n T e i l d e s i m H a n d e l s r e g i s t e reingetragenen Aktienkapitals vertreten, diesverlangen, unter der Voraussetzung, dassfolgende Angaben gemacht werden: (a)(1) dieV e r h a n d l u n g s g e g e n s t ä n d e , s c h r i f t l i c hunterzeichnet von dem/den antragstellendenAktionär(en), (2) die Anträge sowie (3) derNachweis der erforderlichen Anzahl der imAktienbuch eingetragenen Aktien; und (b) dieweiteren Informationen, die von der Gesellschaftnach den Regeln der U.S. Securi t ies andExchange Commission (SEC) in einem sog.P r o x y S t a t e m e n t a u f g e n o m m e n u n dveröffentlicht werden müssen.

2 An Extraordinary General Meeting shall furtherbe convened by the Board of Directors uponr e s o l u t i o n o f a G e n e r a l M e e t i n g o fShareholders or if so requested by one or moreshareholders who, in the aggregate, representat least one−tenth of the share capital recordedin the Commercial Register and who submit(a)(1) a request signed by such shareholder(s)that specifies the item(s) to be included on theagenda, (2) the respective proposals of theshareholders and (3) evidence of the requiredshareholdings recorded in the share registerand (b) such other information as would berequired to be included in a proxy statementpursuant to the rules of the U.S. Securities andExchange Commission (SEC).

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Artikel 13 Article 13Einberufung 1 Die Generalversammlung wird durch den

Verwaltungsrat, nötigenfalls die Revisionsstelle,spätestens 20 Kalendertage vor dem Tag derG e n e r a l v e r s a m m l u n g e i n b e r u f e n . D i eE i n b e r u f u n g e r f o l g t d u r c h e i n m a l i g eBekanntmachung im Publikationsorgan derGesellschaft gemäss Artikel 32 dieser Statuten.Für die Einhaltung der Einberufungsfrist ist derTag der Veröffentlichung der Einberufung imPublikationsorgan massgeblich, wobei der Tagder Veröffentlichung nicht mitzuzählen ist. Die imAktienbuch eingetragenen Aktionäre könnenzudem auf dem ordentlichen Postweg über dieGeneralversammlung informiert werden.

Notice ofShareholders'Meetings

1 Notice of a General Meeting of Shareholdersshall be given by the Board of Directors or, ifnecessary, by the Auditor, no later than twentycalendar days prior to the date of the GeneralMeet ing of Shareholders. Not ice of theGeneral Meeting of Shareholders shall begiven by way of a one−time announcement inthe of f ic ia l means of publ icat ion of theCompany pursuant to Article 32 of theseArticles of Association. The notice period shallbe deemed to have been observed if notice ofthe General Meet ing of Shareholders ispublished in such official means of publication,it being understood that the date of publicationis not to be included for purposes of computingthe notice period. Shareholders of record mayin addition be informed of the General Meetingof Shareholders by ordinary mail.

2 D i e E i n b e r u f u n g m u s s d i eVerhandlungsgegenstände sowie die Anträgedes Verwal tungsra tes und des oder derAktionäre, welche die Durchführung einerGeneralversammlung oder die Traktandierungeines Verhandlungsgegenstandes verlangthaben, und bei Wahlgeschäften die Namen desoder der zur Wahl vorgeschlagenen Kandidatenenthalten.

2 T h e n o t i c e o f a G e n e r a l M e e t i n g o fShareholders shall specify the items on theagenda and the proposals of the Board ofD i rec to rs and the sha reho lde r ( s ) whor e q u e s t e d t h a t a G e n e r a l M e e t i n g o fShareholders be held or an item be included onthe agenda, and, in the event of elections, thename(s) of the candidate(s) that has or havebeen put on the ballot for election.

Artikel 14 Article 14Traktandierung 1 Jeder Aktionär kann die Traktandierung eines

Verhandlungsgegenstandes verlangen. DasTraktandierungsbegehren muss mindestens 30Kalendertage vor dem Jahrestag des sog. ProxyS t a t e m e n t s d e r G e s e l l s c h a f t , d a s i mZusammenhang mit der Generalversammlungim jeweiligen Vorjahr veröffentlicht und gemässden anwendbaren SEC Regeln bei der SECeingereicht wurde, schriftlich unter Angabe desVerhandlungsgegenstandes und der Anträgesowie unter Nachweis der erforderlichen Anzahlim Aktienbuch eingetragenen Aktien eingereichtwerden. Falls das Datum der anstehendenGeneralversammlung mehr als 30 Kalendertagev o r o d e r n a c h d e m J a h r e s t a g d e rvorangegangenen Genera lversammlunga n g e s e t z t w o r d e n i s t , i s t d a sT r a k t a n d i e r u n g s b e g e h r e n s t a t t d e s s e nspätestens 10 Kalendertage nach dem Tageinzureichen, an dem die Gesellschaft dasDatum der Generalversammlung öffentlichbekannt gemacht hat.

Agenda 1 Any shareholder may request that an item beincluded on the agenda of a General Meetingof Shareholders. An inclusion of an item on theagenda must be requested in writing at least 30calendar days prior to the anniversary date ofthe Company's proxy statement in connectionwith the previous year's General Meeting ofShareholders, as filed with the SEC pursuant tothe applicable rules of the SEC, and shallspecify in writing the relevant agenda itemsand proposals, together with evidence of therequired shareholdings recorded in the shareregister; provided, however, that if the date ofthe General Meeting of Shareholders is morethan 30 calendar days before or after suchanniversary date, such request must instead bemade at least by the 10 t h ca lendar dayfollowing the date on which the Company hasmade public disclosure of the date of theGeneral Meeting of Shareholders.

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2 Z u n i c h t g e h ö r i g a n g e k ü n d i g t e nVerhandlungsgegenständen können keineB e s c h l ü s s e g e f a s s t w e r d e n . H i e r v o nausgenommen sind jedoch der Beschluss überden in einer Generalversammlung gestelltenA n t r a g a u f ( i ) E i n b e r u f u n g e i n e rausserordentlichen Generalversammlung sowie(ii) Durchführung einer Sonderprüfung gemässA r t i k e l 6 9 7 a d e s S c h w e i z e r i s c h e nObligationenrechts (OR).

2 No resolution may be passed at a GeneralMeet ing of Shareholders concerning anagenda item in relation to which due notice wasnot given. Proposals made during a GeneralMeeting of Shareholders to (i) convene anExtraordinary General Meeting or (ii) initiate aspecial investigation in accordance witharticle 697a of the Swiss Code of Obligations(CO) are no t sub jec t to the due not icerequirement set forth herein.

3 Zur Stellung von Anträgen im Rahmen derV e r h a n d l u n g s g e g e n s t ä n d e u n d z uVerhandlungen ohne Beschlussfassung bedarfes keiner vorgängigen Ankündigung.

3 No prior notice is required to bring motionsrelated to items already on the agenda or forthe d iscuss ion o f mat te rs on wh ich noresolution is to be taken.

Artikel 15 Article 15Vorsitz derGeneralver−sammlung,Protokoll, Stimmenzähler

1 An der Generalversammlung führt der Präsidentdes Verwa l tungsra tes oder , be i dessenVerhinderung, der Vizepräsident oder eineandere vom Verwaltungsrat bezeichnete Personden Vorsitz.

ActingChair,Minutes,VoteCounters

1 At the General Meeting of Shareholders theChairman of the Board of Directors or, in hisabsence, the Vice−Chairman or any otherperson designated by the Board of Directors,shall take the chair.

2 Der Vorsitzende der Generalversammlungb e s t i m m t d e n P r o t o k o l l f ü h r e r u n d d i eStimmenzähler, die alle nicht Aktionäre seinmüssen. Das Protokoll ist vom Vorsitzenden undvom Protokollführer zu unterzeichnen.

2 The acting chair of the General Meeting ofShareholders shall appoint the secretary andthe vote counters, none of whom need beshareholders. The minutes of the GeneralMeeting of Shareholders shall be signed by theacting chair and the secretary.

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3 Der Vorsitzende der Generalversammlung hatsämtl iche Leitungsbefugnisse, die für dieo r d n u n g s g e m ä s s e D u r c h f ü h r u n g d e rGeneralversammlung nötig und angemessensind.

3 The acting chair of the General Meeting ofShareholders shal l have al l powers andauthority necessary and appropriate to ensurethe orderly conduct of the General Meeting ofShareholders.

Artikel 16 Article 16Recht auf Teilnahme,Vertretung der Aktionäre

Jeder im Aktienbuch eingetragene Aktionär istberechtigt, an der Generalversammlung undderen Beschlüssen teilzunehmen. Ein Aktionärkann sich an der Generalversammlung vertretenlassen, wobei der Vertreter nicht Aktionär seinmuss. Der Verwaltungsrat regelt die Einzelheitenüber die Vertretung und Teilnahme an derGeneralversammlung in Verfahrensvorschriften.

Right toParticipationandRepresentation

Each shareholder recorded in the shareregister is entitled to participate at the GeneralMeeting of Shareholders and in any votetaken. The shareholders may be representedby proxies who need not be shareholders. TheBoard of Directors shall issue the particulars ofthe right to representation and participation atthe General Meet ing of Shareholders inprocedural rules.

Artikel 17 Article 17Stimmrecht Jede Aktie berechtigt zu einer Stimme. Das

Stimmrecht untersteht den Bedingungen vonArtikel 7 und 9 dieser Statuten.

VotingRights

Each Share shall convey the right to onevote. The r ight to vote is subject to theconditions of Articles 7and 9 of these Articles ofAssociation.

Artikel 18 Article 18Beschlüsse und Wahlen 1 Die Generalversammlung fasst Beschlüsse und

entscheidet Wahlen, soweit das Gesetz oderdiese Statuten es nicht anders bestimmen, mitder re lat iven Mehrhei t der abgegebenenAktienstimmen (wobei Enthaltungen, sog. BrokerNonvotes, leere oder ungültige Stimmen für dieBestimmung des Mehrs nicht berücksichtigtwerden).

ResolutionsandElections

1 Unless otherwise required by law or theseArticles of Association, the General Meeting ofShareholders shall take resolutions and decideelections upon a relative majority of the votescast at the General Meeting of Shareholders(whereby abstentions, broker nonvotes, blankor invalid ballots shall be disregarded forpurposes of establishing the majority).

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2 Die Generalversammlung entscheidet über dieWahl von Mitgliedern des Verwaltungsratesnach dem proport ionalen Wahlverfahren,wonach diejenige Person, welche die grössteZahl der abgegebenen Aktienstimmen für einenVerwa l tungs ra tss i t z e rhä l t , a l s f ü r denbetreffenden Verwaltungsratssitz gewählt gilt.Akt ienst immen gegen einen Kandidaten,Stimmenthaltungen, sog. Broker Nonvotes,ungültige oder leere Stimmen haben für dieZwecke d ieses Ar t ike ls 18 Abs. 2 ke ineAuswirkungen auf die Wahl von Mitgliedern desVerwaltungsrates.

2 The General Meeting of Shareholders shalldecide elections of members of the Board ofDirectors upon a plurality of the votes cast atthe General Meeting of Shareholders. Aplurality means that the individual who receivesthe largest number of votes for a board seat iselected to that board seat. Votes against anycandidate, abstentions, broker nonvotes, blankor invalid ballots shall have no impact on theelection of members of the Board of Directorsunder this Article 18 para. 2.

3 Für die Abwahl von amtierenden Mitgliedern desVerwaltungsrates gilt das Mehrheitserfordernisgemäss Ar t i ke l 20 Abs . 2 (e ) sow ie dasPräsenzquorum von Artikel 21 Abs. 1(a).

3 For the removal of a serving member of theBoard of Directors, the voting requirement setforth in Article 20 para. 2(e) and the presencequorum set forth in Article 21 para. 1(a) shallapply.

4 Die Abstimmungen und Wahlen erfolgen offen,es sei denn, dass die Generalversammlungschri f t l iche Abst immung respekt ive Wahlbeschliesst oder der Vorsitzende dies anordnet.Der Vorsitzende kann Abstimmungen undWahlen auch mittels elektronischem Verfahrend u r c h f ü h r e n l a s s e n . E l e k t r o n i s c h eAbstimmungen und Wahlen sind schriftlichenAbstimmen und Wahlen gleichgestellt.

4 Resolutions and elections shall be decided bya show of hands, unless a written ballot isr e s o l v e d b y t h e G e n e r a l M e e t i n g o fShareholders or is ordered by the acting chairof the General Meeting of Shareholders. Theacting chair may also hold resolutions andelect ions by use of an electronic vot ingsystem. Electronic resolutions and electionsshall be considered equal to resolutions andelections taken by way of a written ballot.

5 Der Vorsitzende kann eine offene Wahl oderAbstimmung immer durch eine schriftliche oderelektronische wiederholen lassen, sofern nachs e i n e r M e i n u n g Z w e i f e l a mAbstimmungsergebnis bestehen. In diesem Fallgilt die vorausgegangene offene Wahl oderAbstimmung als nicht geschehen.

5 T h e c h a i r o f t h e G e n e r a l M e e t i n g o fShareholders may at any time order that anelection or resolution decided by a show ofhands be repeated by way of a written orelectronic ballot if he considers the vote to bein doubt. The resolution or election previouslyheld by a show of hands shall then be deemedto have not taken place.

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Artikel 19 Article 19Befugnisse derGeneralver−sammlung

Der Genera lversammlung s ind fo lgendeGeschäfte vorbehalten:

(a) Die Festsetzung und Änderungdieser Statuten;

(b) die Wahl der Mitgl ieder desV e r w a l t u n g s r a t e s u n d d e rRevisionsstelle;

( c ) d i e G e n e h m i g u n g d e sJ a h r e s b e r i c h t e s u n d d e rKonzernrechnung;

( d ) d i e G e n e h m i g u n g d e rJ a h r e s r e c h n u n g s o w i e d i eB e s c h l u s s f a s s u n g ü b e r d i eVerwendung des Bilanzgewinnes,insbesondere die Festsetzung derDividende;

(e) die Entlastung der Mitglieder desVerwaltungsrates;

( f ) d i e G e n e h m i g u n g e i n e sZusammensch lusses m i t e inemNahestehenden Aktionär (gemäss derDefinition dieser Begriffe in Artikel 35dieser Statuten); und

(g) die Beschlussfassung über dieG e g e n s t ä n d e , d i e d e rGenera lversammlung durch dasGesetz oder die Statuten vorbehaltensind oder ihr, vorbehältlich Artikel 716aO R , d u r c h d e n V e r w a l t u n g s r a tvorgelegt werden.

Powers ofthe GeneralMeeting ofShareholders

The fo l l ow ing powers sha l l be ves tedexc lus i ve l y i n t he Genera l Mee t ing o fShareholders:

(a) The adoption and amendmentof these Articles of Association;

(b) the election of the members ofthe Board o f D i rec tors and theAuditor;

(c) the approval of the AnnualR e p o r t a n d t h e C o n s o l i d a t e dFinancial Statements;

(d) the approval of the AnnualStatutory Financial Statements of theCompany and the resolution on theallocation of profit shown on theAnnual Statutory Balance Sheet, inparticular the determination of anydividend;

(e) the discharge from liability oft h e m e m b e r s o f t h e B o a r d o fDirectors;

(f) the approval of a BusinessCombinat ion wi th an InterestedShareholder (as each such term isdefined in Article 35 of these Articlesof Association); and

(g) the adoption of resolutions onmatters that are reserved to theGeneral Meeting of Shareholders bylaw, these Articles of Association or,subject to article 716a CO, that aresubmitted to the General Meeting ofSha reho lde rs by t he Boa rd o fDirectors.

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Artikel 20 Article 20Besonderes Quorum 1 Ein Beschluss der Generalversammlung, der

m i n d e s t e n s z w e i D r i t t e l d e r a n d e rGeneralversammlung vertretenen Stimmen undd i e a b s o l u t e M e h r h e i t d e r a n d e rG e n e r a l v e r s a m m l u n g v e r t r e t e n e nAk t iennennwer te au f s i ch ve re in ig t , i s terforderlich für:

(a) Die Ergänzung oder Änderungdes Gesellschaftszweckes gemässArtikel 2 dieser Statuten;

(b) die Einführung und Abschaffungvon Stimmrechtsaktien;

( c ) d i e B e s c h r ä n k u n g d e rÜbertragbarkeit der Aktien und dieA u f h e b u n g e i n e r s o l c h eBeschränkung;

(d) die Beschränkung der Ausübungdes Stimmrechts und die Aufhebungeiner solchen Beschränkung;

(e) eine genehmigte oder bedingteKapitalerhöhung;

( f ) d ie Kapi ta lerhöhung ( i ) ausEigenkapital, (ii) gegen Sacheinlageoder zwecks Sachübernahme oder (iii)d ie Gewährung von besonderenVorteilen;

( g ) d i e E i n s c h r ä n k u n g o d e rAufhebung des Bezugsrechts;

(h) die Verlegung des Sitzes derGesellschaft;

(i) die Umwandlung von Namen− inInhaberaktien und umgekehrt; und

(j) die Auflösung der Gesellschaft.

SpecialVote

1 The approval of at least two−thirds of the votesand the absolute majority of the par value ofShares, each as represented at a GeneralMeeting of Shareholders, shall be required forresolutions with respect to:

(a) The amendment or modificationof the purpose of the Company asdescribed in Article 2 of these Articlesof Association;

(b) the creation and thecancelation of shares with privilegedvoting rights;

(c) the restriction on thetransferability of Shares and thecancelation of such restriction;

(d) the restriction on the exercise ofthe right to vote and the cancelationof such restriction;

(e) an authorized or conditionalincrease in share capital;

(f) an increase in share capital (i)through the conversion of capitalsurplus, (ii) through contribution inkind or for purposes of an acquisitionof assets, or (iii) the granting ofspecial privileges;

(g) the limitation on or withdrawalof preemptive rights;

(h) the relocation of the registeredoffice of the Company;

(i) the conversion of registeredshares into bearer shares and viceversa; and

(j) the dissolution of the Company.

2 Ein Beschluss der Generalversammlung, dermindestens zwei Drittel aller stimmberechtigtenAktien auf sich vereinigt, ist erforderlich für:

2 The approval of at least two−thirds of theShares entitled to vote shall be required for:

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(a) Jede Änderung von Artikel 14Abs. 1 dieser Statuten;

(a) Any change to Article 14para. 1 of these Articles ofAssociation;

(b) jede Änderung von Artikel 18dieser Statuten;

(b) any change to Article 18 ofthese Articles of Association;

(c) jede Änderung dieses Artikels 20Abs. 2;

(c) any change to this Article 20para. 2;

(d)jede Änderung von Artikel 21, 22,2 3 o d e r 2 4 d i e s e rStatuten; und

(d)any change to Article 21, 22, 23or 24 of these Articles ofAssociation; and

(e)die Abwahl eines amtierendenM i t g l i e d s d e sVerwaltungsrates.

(e)a resolution with respect to theremova l o f a serv ingmember of the Board ofDirectors.

3 Z u s ä t z l i c h z u e t w a i g e n g e s e t z l i c hbestehenden Zustimmungserfordernissen istein Beschluss der Generalversammlung miteiner Mehrheit, die mindestens die Summevon: (i) zwei Drittel aller stimmberechtigtenA k t i e n ; z u z ü g l i c h ( i i ) e i n e r Z a h l v o nstimmberechtigten Aktien, die einem Drittelder von Nahestehenden Aktionären (wie inA r t i k e l 3 5 d i e s e r S t a t u t e n d e f i n i e r t )gehaltenen Aktienstimmen entspricht, auf sichv e r e i n i g t , e r f o r d e r l i c h f ü r ( 1 ) j e d e nZusammenschluss der Gesellschaft mit einemNahestehenden Aktionär innerhalb einesZeitraumes von drei Jahren, seitdem diesePerson zu einem Nahestehenden Aktionärwurde, (2) jede Änderung von Artikel 19(f)dieser Statuten oder (3) jede Änderung vonA r t i k e l 2 0 A b s . 3 d i e s e r S t a t u t e n( e i n s c h l i e s s l i c h d e r d a z u g e h ö r i g e nDefinitionen in Artikel 35 dieser Statuten). Dasi m v o r a n g e h e n d e n S a t z a u f g e s t e l l t eZustimmungserfordernis ist jedoch nichtanwendbar falls:

3 In addition to any approval that may berequired under applicable law, the approvalof a majority at least equal to the sum of: (i)two−thirds of the Shares entitled to vote;plus (ii) a number of Shares entitled to votethat is equal to one−third of the number ofShares held by Interested Shareholders (asdefined in Article 35 of these Articles ofAssociat ion), shal l be required for theCompany to (1) engage in any BusinessCombination with an Interested Shareholderfor a period of three years following the timethat such Person became an InterestedShareholder, (2) amend Article 19(f) of theseArticles of Association or (3) amend thisArt ic le 20 para. 3 of these Art ic les ofAssociation (including any of the definitionspertaining thereto as set forth in Article 35 ofthese Articles of Association); provided,however, that the approval requirement inthe preceding sentence shall not apply if:

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(a) der Verwaltungsrat, bevor diesePerson zu einem NahestehendenA k t i o n ä r w u r d e , e n t w e d e r d e nZusammenschluss oder eine andereTransaktion genehmigte, als Folged e r e r d i e s e P e r s o n z u e i n e mNahestehenden Aktionär wurde;

(a) Prior to such time that suchP e r s o n b e c a m e a n I n t e r e s t e dShareholder, the Board of Directorsa p p r o v e d e i t h e r t h e B u s i n e s sCombination or the transaction whichresulted in such Person becoming anInterested Shareholder;

(b) nach Vollzug der Transaktion,als Folge derer diese Person zu einemNahestehenden Aktionär wurde, derNahestehende Aktionär mindestens85% der unmittelbar vor Beginn derbetreffenden Transaktion allgemeinstimmberechtigten Aktien hält, wobeizur Best immung der Anzah l derallgemein stimmberechtigten Aktien(nicht jedoch zur Bestimmung derdurch den Nahestehenden Aktionärgehaltenen Aktien) folgende Aktiennicht zu berücksichtigen sind: Aktien,(x) welche von Personen gehaltenwerden, die sowohl Verwaltungsrats−wie Geschäftsleitungsmitglieder sind,u n d ( y ) w e l c h e f ü rMitarbeiteraktienpläne reserviert sind,s o w e i t d i e d i e s e n P l ä n e nunterworfenen Mitarbeiter nicht dasRecht haben, unter Wahrung derV e r t r a u l i c h k e i t d a r ü b e r z uentscheiden, ob Akt ien, d ie dembetreffenden Mitarbeiteraktienplanunterstehen, in einem Übernahme−oder Austauschangebot angedientwerden sollen oder nicht;

(b) upon consummation of thetransaction which resulted in suchPerson becoming an InterestedS h a r e h o l d e r , t h e I n t e r e s t e dShareholder Owned at least 85% ofthe Shares generally entitled to votea t t h e t i m e t h e t r a n s a c t i o ncommenced, excluding for purposesof determin ing such number o fShares then in issue (but not forpurposes of determining the SharesO w n e d b y t h e I n t e r e s t e dShareholder), those Shares Owned( x ) b y P e r s o n s w h o a r e b o t hmembers of the Board of Directorsand officers of the Company and (y)by employee share plans in whichemployee participants do not havethe right to determine confidentiallywhether Shares held subject to theplan will be tendered in a tender orexchange offer;

( c ) e i n e P e r s o nunbeabsicht ig terweise zu e inemNahestehenden Aktionär wird und(x) das Eigentum an einer genügendenAnzahl Aktien sobald als möglichveräussert, so dass sie nicht mehrlänger als Nahestehender Aktionärqualifiziert und (y) zu keinem Zeitpunktw ä h r e n d d e r d r e i d e mZusammenschluss zwischen derGese l lschaf t und d ieser Personunmittelbar vorangehenden Jahren alsNahestehender Aktionär gegoltenhätte, ausgenommen aufgrund desu n b e a b s i c h t i g t e n E r w e r b s d e rEigentümerschaft.

( c ) a P e r s o n b e c o m e s a nInterested Shareholder inadvertentlyand (x ) as soon as prac t icab led i ves t s i t se l f o f Owne rsh ip o fsufficient Shares so that such Personc e a s e s t o b e a n I n t e r e s t e dShareholder and (y) would not, at anytime within the three−year periodimmediately pr ior to a BusinessCombination between the Companyand such Person, have been anInterested Shareholder but for theinadvertent acquisition of Ownership;

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(d ) der Zusammensch luss vorVollzug oder Verzicht auf und nachöffentlicher Bekanntgabe oder dernach diesem Abschnitt erforderlichenMitteilung (was auch immer frühere r f o l g t ) e i n e ( r ) b e a b s i c h t i g t e nTransakt ion vorgeschlagen wird,welche (i) eine der Transaktionen imSinne des zweiten Satzes diesesArtikels 20 Abs. 3(d) darstellt; (ii) mitoder von einer Person abgeschlossenwird, d ie entweder während denl e t z t e n d r e i J a h r e n k e i nNahestehender Aktionär war oder zueinem Nahestehenden Aktionär mitd e r G e n e h m i g u n g d e sVerwaltungsrates wurde; und (iii) vone i n e r M e h r h e i t d e r d a n n z u m a la m t i e r e n d e n M i t g l i e d e r d e sVerwaltungsrates (aber mindestense i n e m ) g e n e h m i g t o d e r n i c h tabgelehnt wird, die entweder bereitsVerwaltungsratsmitglieder waren,bevor in den drei vorangehendenJahren irgendeine Person zu einemNahestehenden Aktionär wurde, oderdie auf Empfehlung einer Mehrheitsolcher Verwaltungsratsmitglieder alsd e r e n N a c h f o l g e r z u r W a h lv o r g e s c h l a g e n w u r d e n . D i e i mvorangehenden Satz erwähntenbeabsichtigen Transaktionen sind auffolgende beschränkt: (x) eine Fusiono d e r a n d e r e F o r m d e sZusammenschlusses der Gesellschaft(mit Ausnahme einer Fusion, welchek e i n e G e n e h m i g u n g d u r c h d i eGeneralversammlung der Gesellschaftvoraussetzt); (y) ein Verkauf, eineVe rm ie tung ode r Ve rpach tung ,hypothekar ische Belastung oderandere Verpfändung, Übertragungoder andere Verfügung (ob in eineroder mehre ren T ransak t ionen) ,einschl iessl ich im Rahmen einesTauschs, von Vermögenswerten derGesellschaft oder einer direkten oderindirekten Tochtergesellschaft, die zurM e h r h e i t v o n d e r G e s e l l s c h a f tgehalten wird (jedoch nicht an einedirekt oder indirekt zu 100% gehalteneKonzerngesel lschaft oder an dieG e s e l l s c h a f t ) , s o w e i t d i e s eVermögenswerte einen Marktwert von50% oder mehr entweder des aufkonsolidierter Basis aggregiertenMarktwertes aller Vermögenswerte derGesellschaft oder des aggregiertenMarktwertes aller dann ausgegebenenAktien haben, unabhängig davon, obeine dieser Transaktionen Teil einerAuflösung der Gesellschaft ist odernicht; oder (z) ein vorgeschlagenesÜbernahme− oder Umtauschangebotfür 50% oder mehr der ausstehendenStimmrechte der Gesellschaft. DieGesellschaft muss NahestehendenA k t i o n ä r e n s o w i e d e n ü b r i g e nAktionären den Vollzug einer der unter(x) oder (y) des zweiten Satzes diesesAr t ike ls 20 Abs. 3(d) erwähntenT r a n s a k t i o n e n m i n d e s t e n s 2 0Kalendertage vorher mitteilen.

(d) the Business Combination isproposed prior to the consummationor abandonment of and subsequentt o t h e e a r l i e r o f t h e p u b l i cannouncement or the notice requiredhereunder of a proposed transactionwhich ( i ) const i tutes one of thetransactions described in the secondsentence of this Article 20 para. 3(d);(ii) is with or by a person who eitherwas not an Interested Shareholderduring the previous three years orw h o b e c a m e a n I n t e r e s t e dShareholder with the approval of theBoard o f D i rec to rs ; and ( i i i ) i sapproved o r no t opposed by amajority of the members of the Boardof Directors then in office (but notless than one) who were Directorsprior to any person becoming anInterested Shareholder during thep r e v i o u s t h r e e y e a r s o r w e r erecommended for election to succeedsuch Directors by a majority of suchDirectors. The proposed transactionsreferred to in the preceding sentencea r e l i m i t e d t o ( x ) a m e r g e r o rconso l i da t i on o f t he Company(except for a merger in respect ofwhich no vote of the Company’sshareholders is required); (y) a sale,lease, exchange, mortgage, pledge,transfer or other disposition (in onet r a n s a c t i o n o r a s e r i e s o ftransactions), whether as part of adissolution or otherwise, of assets ofthe Company or of any direct orindirect majority−Owned subsidiary ofthe Company (other than to anydirect or indi rect whol ly Ownedsubsidiary or to the Company) havingan aggregate market value equal to50% or more of either that aggregatemarket value of all of the assets ofthe Company de te rm ined on aconsolidated basis or the aggregatemarket value of all the issued shares;or (z) a proposed tender or exchangeoffer for 50% or more of the votingshares then in issue. The Companyshall give not less than 20 days'notice to all Interested Shareholdersas well as to the other shareholdersprior to the consummation of any ofthe transactions described in clause(x) or (y) of the second sentence ofthis Article 20 para. 3(d).

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Artikel 21 Article 21Präsenzquorum 1 Die nachfolgend aufgeführten Angelegenheiten

erfordern zum Zeitpunkt der Konstituierung derGeneralversammlung ein Präsenzquorum vonAktionären oder deren Vertretern, welchemindestens zwei Drittel des im Handelsregistereingetragenen Aktienkapitals vertreten, damitdie Generalversammlung beschlussfähig ist:

(a)Die Beschlussfassung über dieAbwahl eines amtierendenVerwaltungsrats-mitglieds;und

(b)die Beschlussfassung, diesenArtikel 21 oder Artikel 18,19(f) , 20, 22, 23 oder 24dieser Statuten zu ergänzen,z u ä n d e r n , n i c h tanzuwenden oder ausserKraft zu setzen.

PresenceQuorum

1 The matters set forth below require that aquorum of shareholders of record holding inperson or by proxy at least two−thirds of theshare capital recorded in the CommercialRegister are present at the time when theGeneral Meeting of Shareholders proceedsto business:

(a)the adoption of a resolution tor e m o v e a s e r v i n gDirector; and

(b)the adoption of a resolution toamend, vary, suspendthe operation of, disapplyor cancel this Article 21or Articles 18, 19(f), 20,22, 23 or 24 of theseArticles of Association.

2 Jede andere Beschlussfassung oder Wahl setztzu ihrer Gültigkeit voraus, dass zum Zeitpunktder Konstituierung der Generalversammlungzumindest die Mehrheit aller stimmberechtigtenAktien anwesend ist. Die Aktionäre können mitder Behandlung der Traktanden fortfahren,selbst wenn Aktionäre nach Bekanntgabe desQ u o r u m s d u r c h d e n V o r s i t z e n d e n d i eGeneralversammlung verlassen und damitweniger als das geforderte Präsenzquorum ander Generalversammlung verbleibt.

2 The adoption of any other resolution or electionrequires that at least a majority of all theShares entitled to vote be represented at thet i m e w h e n t h e G e n e r a l M e e t i n g o fShareholders proceeds to business. Theshareholders present at a General Meeting ofShareholders may cont inue to t ransactb u s i n e s s , d e s p i t e t h e w i t h d r a w a l o fshareholders from such General Meeting ofShareholders following announcement of thepresence quorum at that meeting.

B. Verwaltungsrat B. Board of DirectorsArtikel 22 Article 22

Anzahl der Verwaltungs−räte Der Verwaltungsrat besteht aus mindestenszwei und höchstens 14 Mitgliedern.

Number ofDirectors

The Board of Directors shall consist of no lessthan two and no more than 14 members.

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Artikel 23 Article 23Amtsdauer 1 D i e V e r w a l t u n g s r ä t e w e r d e n v o m

Verwaltungsrat in drei Klassen aufgeteilt, welcheals Klasse I, Klasse II und Klasse III bezeichnetw e r d e n . A n j e d e r o r d e n t l i c h e nG e n e r a l v e r s a m m l u n g s o l l j e d e K l a s s eVerwaltungsräte, deren Amtsdauer abläuft, füreine Amtsdauer von drei Jahren bzw. bis zurWahl eines Nachfolgers in sein Amt gewähltwerden. Der Verwaltungsrat legt die Reihenfolgeder Wiederwahl fest, wobei die erste Amtszeite iner Klasse von Verwal tungsräten auchweniger als drei Jahre betragen kann. Für dieZwecke dieser Bestimmung ist unter einem Jahrder Zeitabschnitt zwischen zwei ordentlichenGeneralversammlungen zu verstehen.

Term ofOffice

1The Board of Directors shall divide its membersinto three classes, designated Class I, Class IIand Class I I I . At each Annual Genera lMeeting, each class of the members of theBoard of Directors whose term shall thenexpire shall be elected to hold office for athree−year term or until the election of theirrespective successor in office. The Board ofDirectors shall establish the order of rotation,whereby the first term of office of members of aparticular Class may be less than three years.For purposes of this provision, one year shallmean the period between two Annual GeneralMeetings of Shareholders.

2 Wenn ein Verwaltungsratsmitglied vor Ablaufseiner Amtsdauer aus welchen Gründen auchimmer ersetzt wird, endet die Amtsdauer des ans e i n e r S t e l l e g e w ä h l t e n n e u e nVerwaltungsratsmitgliedes mit dem Ende derAmtsdauer seines Vorgängers.

2 If, before the expiration of his term of office, aDirector should be replaced for whateverreason, the term of office of the newly electedmember of the Board of Directors shall expirea t t he end o f t he t e rm o f o f f i ce o f h i spredecessor.

Artikel 24 Article 24Organisation desVerwaltungs−rates,Entschädigung

1 Der Verwaltungsrat wählt aus seiner Mitte einenVorsitzenden. Er kann einen oder mehrereVizepräsidenten wählen. Er bestellt weiter einenS e k r e t ä r , w e l c h e r n i c h t M i t g l i e d d e sVerwaltungsrates sein muss. Der Verwaltungsratregelt unter Vorbehalt der Bestimmungen desGesetzes und dieser Statuten die Einzelheitens e i n e r O r g a n i s a t i o n i n e i n e mOrganisationsreglement.

Organizationof theBoard,Remuneration

1 The Board of Directors shall elect from amongits members a Chairman. It may elect one ormore Vice−Chairmen. It shall further appoint aSecretary, who need not be a member of theBoard of Directors. Subject to applicable lawand these Articles of Association, the Board ofDirectors shall establish the particulars of itsorganization in organizational regulations.

2 Die Mitglieder des Verwaltungsrates habenAnspruch auf Ersatz ihrer im Interesse derGesellschaft aufgewendeten Auslagen sowie aufe ine ih re r Tä t igke i t und Veran twor tungen tsp rechende En tschäd igung , d ie de rVerwaltungsrat auf Antrag eines Ausschussesdes Verwaltungsrates festlegt.

2 The members of the Board of Directors shall beentitled to reimbursement of all expensesincurred in the interest of the Company, as wellas remuneration for their services that isappropriate in view of their functions andr e s p o n s i b i l i t i e s . T h e a m o u n t o f t h eremuneration shall be determined by the Boardof Directors upon recommendat ion by acommittee of the Board of Directors.

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3 Soweit gesetzlich zulässig, hält die Gesellschaftak tue l l e und ehema l i ge M i tg l i ede r desVerwaltungsrates und der Geschäftsleitungs o w i e d e r e n E r b e n , K o n k u r s − o d e rNachlassmassen aus Gesellschaftsmitteln fürSchäden, Verluste und Kosten aus drohenden,hängigen oder abgeschlossenen Klagen,Verfahren oder Untersuchungen zivil−, straf−oder verwaltungsrechtlicher oder anderer Naturschadlos, welche ihnen oder ihren Erben,Konkurs− oder Nachlassmassen entstehenaufgrund von tatsächlichen oder behauptetenH a n d l u n g e n , Z u s t i m m u n g e n o d e rUnterlassungen im Zusammenhang mit derAusübung ihrer Pflichten oder behauptetenPflichten oder aufgrund der Tatsache, dass sieMi tg l ied des Verwal tungsra tes oder derGeschäftsleitung der Gesellschaft sind oderwaren oder auf Aufforderung der Gesellschafta l s M i tg l i ed des Verwa l tungs ra tes , de rGeschäftsleitung oder als Arbeitnehmer oderAgent eines anderen Unternehmens, eineranderen Gesellschaft, einer nicht−rechtsfähigenPersonengesellschaft oder eines Trusts sindoder waren. Diese Pflicht zur Schadloshaltungbesteht nicht, soweit in einem endgültigen, nichtweiterziehbaren Entscheid eines zuständigenG e r i c h t s b z w . e i n e r z u s t ä n d i g e nVerwaltungsbehörde entschieden worden ist,dass eine der genannten Personen ihre Pflichtenals Mitglied des Verwaltungsrates oder derGeschäftsleitung absichtlich oder grobfahrlässigverletzt hat.

3 The Company shal l indemni fy and holdharmless, to the fullest extent permitted by law,the existing and former members of the Boardof Directors and officers, and their heirs,executors and administrators, out of the assetso f t h e C o m p a n y f r o m a n d a g a i n s t a l lthreatened, pending or completed actions, suitsor proceedings – whether civi l , cr iminal,administrative or investigative – and all costs,charges, losses, damages and expenses whichthey or any of them, their heirs, executors oradministrators, shall or may incur or sustain byor by reason of any act done or alleged to bedone, concurred or alleged to be concurred inor omitted or alleged to be omitted in or aboutthe execution of their duty, or alleged duty, orby reason of the fact that he is or was amember of the Board of Director or officer ofthe Company, or while serving as a member ofthe Board of Director or officer of the Companyis or was serv ing a t the request o f theCompany as a director, officer, employee oragent of another corporation, partnership, jointventure, trust or other enterprise; provided,however, that this indemnity shall not extend toany matter in which any of said persons isfound, in a final judgment or decree of a courtor governmental or administrative authority ofcompetent jurisdiction not subject to appeal, tohave committed an intentional or grosslynegligent breach of his statutory duties as amember of the Board of Director or officer.

4 Ohne den vorangehenden Absatz 3 diesesArtikels 24 einzuschränken, bevorschusst dieGesellschaft Mitgliedern des Verwaltungsratesund der Geschäf ts le i tung Ger ichts− undAnwaltskosten. Die Gesellschaft kann solcheV o r s c h ü s s e z u r ü c k f o r d e r n , w e n n e i nzuständiges Gericht oder eine zuständigeVerwaltungsbehörde in einem endgültigen, nichtweiterziehbaren Urteil bzw. Entscheid zumSchluss kommt, dass eine der genanntenPersonen ihre Pf l ichten a ls Mi tg l ied desVerwaltungsrates oder der Geschäftsleitungabsichtlich oder grobfahrlässig verletzt hat.

4 Without limiting the foregoing paragraph 3 ofthis Article 24, the Company shall advancecourt costs and attorneys' fees to the existingand former members of the Board of Directorsand officers. The Company may howeverrecover such advanced costs if any of saidpersons is found, in a final judgment or decreeof a court or governmental or administrativeauthority of competent jurisdiction not subjectto appeal, to have committed an intentional orgrossly negligent breach of his statutory dutiesas a Director of officer.

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Artikel 25 Article 25Befugnisse desVerwaltungs−rates

1 Der Verwaltungsrat hat die in Artikel 716a ORstatuierten unübertragbaren und unentziehbarenAufgaben, insbesondere:

(a)die Oberleitung der Gesellschaftund die Erteilung der nötigenWeisungen;

(b)die Festlegung der Organisation;und

(c)die Oberaufsicht über die mit derGeschäftsführung betrautenPersonen, namentl ich imHinblick auf die Befolgungd e r G e s e t z e , S t a t u t e n ,Reglemente und Weisungen.

SpecificPowers ofthe Board

1 The Board of Directors has the non−delegableand inalienable duties as specified in Article716a CO, in particular:

(a)the ultimate direction of thebusiness of the Companyand the issuance of therequired directives;

( b ) t h e d e t e r m i n a t i o n o f t h eo r g a n i z a t i o n o f t h eCompany; and

(c)the ultimate supervision of thepersons entrusted withmanagement duties, inparticular with regard tocompl iance wi th law,t h e s e A r t i c l e s o fAssociation, regulationsand directives.

2 Der Verwaltungsrat kann überdies in allenAngelegenheiten Beschluss fassen, die nichtn a c h G e s e t z o d e r S t a t u t e n d e rGeneralversammlung zugeteilt sind.

2 In addition, the Board of Directors may passresolutions with respect to all matters that arenot reserved to the General Meet ing ofShareholders by law or under these Articles ofAssociation.

3 Der Verwaltungsrat kann Beteiligungspläne derGesellschaft der Generalversammlung zurGenehmigung vorlegen.

3 The Board of Directors may submit benefit orincentive plans of the Company to the GeneralMeeting of Shareholders for approval.

Artikel 26 Article 26Übertragung von Befugnissen Der Verwaltungsrat kann unter Vorbehalt von

Artikel 25 Abs. 1 dieser Statuten sowie derVorschriften des OR die Geschäftsführung nachMassgabe eines Organisationsreglements ganzoder teilweise an eines oder mehrere seinerMitglieder, an einen oder mehrere Ausschüssedes Verwaltungsrates oder an Dritte übertragen.

Delegationof Powers

Subject to Article 25 para. 1 of these Articles ofAssociation and the applicable provisions ofthe CO, the Board of Directors may delegatethe management of the Company in whole or inpart to individual directors, one or morecommittees of the Board of Directors or topersons other than Directors pursuant toorganizational regulations.

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Artikel 27 Article 27Sitzungen des Verwaltungsrats 1 Sofern das vom Verwaltungsrat erlassene

Organisationsreglement nichts anderes festlegt,i s t zu r gü l t igen Besch luss fassung überG e s c h ä f t e d e s V e r w a l t u n g s r a t e s d i eAnwesenheit einer Mehrheit der Mitglieder desgesamten Verwaltungsrates notwendig. KeinPräsenzquo rum i s t e r f o rde r l i ch f ü r d i eS t a t u t e n a n p a s s u n g s − u n dFeststellungsbeschlüsse des Verwaltungsratesim Zusammenhang mit Kapitalerhöhungen.

Meeting ofthe Boardof Directors

1 Except as otherwise set forth in organizationalregulations of the Board of Directors, thea t tendance quo rum necessa ry f o r t hetransaction of the business of the Board ofDirectors shall be a majority of the whole Boardof Directors. No attendance quorum shall berequired for resolut ions of the Board ofDirectors providing for the confirmation of acapital increase or for the amendment of theArticles of Association in connection therewith.

2 Der Verwaltungsrat fasst seine Beschlüsse mite iner Mehrhei t der von den anwesendenVerwaltungsräten abgegebenen Stimmen,vorausgesetzt, das Präsenzquorum von Absatz1 dieses Artikels 27 ist erfüllt. Der Vorsitzendeh a t b e i S t i m m e n g l e i c h h e i t k e i n e nStichentscheid.

2 T h e B o a r d o f D i r e c t o r s s h a l l p a s s i t sresolutions with the majority of the votes castby the Directors present at a meeting at whichthe attendance quorum of para. 1 of thisArticle 27 is satisfied. The Chairman shallhave no casting vote.

Artikel 28 Article 28Zeichnungs−berechtigung D i e r e c h t s v e r b i n d l i c h e V e r t r e t u n g d e r

G e s e l l s c h a f t d u r c h M i t g l i e d e r d e sVerwaltungsrates und durch Dritte wird in einemOrganisationsreglement festgelegt.

SignaturePower

The due and val id representat ion of theCompany by members o f the Board o fDirectors and other persons shall be set forth inorganizational regulations.

C. Revisionsstelle C. AuditorArtikel 29 Article 29

Amtsdauer, Befugnisse undPflichten

1 D i e R e v i s i o n s s t e l l e w i r d v o n d e rGeneralversammlung gewählt und es obliegenihr die vom Gesetz zugewiesenen Befugnisseund Pflichten.

Term,Powersand Duties

1 The Auditor shall be elected by the GeneralMeeting of Shareholders and shall have thepowers and duties vested in it by law.

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2 Die Amtsdauer der Revisionsstelle beträgt einJahr, beginnend am Tage der Wahl an einerordentlichen Generalversammlung und endenda m T a g e d e r n ä c h s t e n o r d e n t l i c h e nGeneralversammlung.

2 The term of office of the Auditor shall be oneyear, commencing on the day of election at anAnnual General Meeting of Shareholders andterminating on the day of the next AnnualGeneral Meeting of Shareholders.

Abschnitt 4:Jahresrechnung, Konzernrechnung undGewinnverteilung

Section 4:Annual Statutory Financial Statements,Consolidated Financial Statements and ProfitAllocation

Artikel 30 Article 30Geschäftsjahr Der Verwaltungsrat legt das Geschäftsjahr fest. Fiscal Year The Board of Directors determines the fiscal

year.Artikel 31 Article 31

Verteilung des Bilanzgewinns,Reserven

1 Ü b e r d e n B i l a n z g e w i n n v e r f ü g t d i eG e n e r a l v e r s a m m l u n g i m R a h m e n d e ranwendbaren gesetzlichen Vorschriften. DerVerwaltungsrat unterbreitet ihr seine Vorschläge.

Allocationof ProfitShown onthe AnnualStatutoryBalanceSheet,Reserves

1 The profit shown on the Annual StatutoryBalance Sheet shal l be al located by theG e n e r a l M e e t i n g o f S h a r e h o l d e r s i naccordance with applicable law. The Board ofDirectors shall submit its proposals to theGeneral Meeting of Shareholders.

2 Neben der gesetzlichen Reserve können weitereReserven geschaffen werden.

2 Further reserves may be taken in addition tothe reserves required by law.

3 Dividenden, welche nicht innerhalb von fünfJahren nach ihrem Auszahlungsdatum bezogenwerden, fallen an die Gesellschaft und werden ind ie a l lgemeinen gesetz l i chen Reservenverbucht.

3 Dividends that have not been collected withinfive years after their payment date shall enureto the Company and be al located to thegeneral statutory reserves.

Abschnitt 5:Auflösung und Liquidation

Section 5:Winding−up and Liquidation

Artikel 32 Article 32Auflösung und Liquidation 1 Die Generalversammlung kann jederzeit die

Auflösung und Liquidation der Gesellschaft nachMassgabe der gesetzlichen und statutarischenVorschriften beschliessen.

Winding−upandLiquidation

1 The General Meeting of Shareholders may atany t ime resolve on the winding−up andl iquidat ion of the Company pursuant toapplicable law and the provisions set forth inthese Articles of Association.

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2 Die Liquidation wird durch den Verwaltungsratdurchgeführ t , sofern s ie n icht durch d ieGeneralversammlung anderen Personenübertragen wird.

2 The liquidation shall be effected by the Boardof Directors, unless the General Meeting ofShareholders shall appoint other persons asliquidators.

3 Die Liquidation der Gesellschaft erfolgt nachMassgabe der gesetzlichen Vorschriften.

3 The l iquidation of the Company shal l bee f f e c t u a t e d p u r s u a n t t o t h e s t a t u t o r yprovisions.

4 Nach erfolgter Tilgung der Schulden wird dasVermögen unter die Aktionäre nach Massgabeder eingezahlten Beträge verteilt, soweit dieseStatuten nichts anderes vorsehen.

4 Upon discharge of all liabilities, the assets ofthe Company shal l be distr ibuted to theshareholders pursuant to the amounts paid in,unless these Articles of Association provideotherwise.

Abschnitt 6:Bekanntmachungen, Mitteilungen

Section 6:Announcements, Communications

Artikel 33 Article 33Bekannt−machungen,Mitteilungen

1 Publikationsorgan der Gesellschaft ist dasSchweizerische Handelsamtsblatt.

Announcements,Communications

1 The official means of publication of theCompany shall be the Swiss Official Gazette ofCommerce.

2 Soweit keine individuelle Benachrichtigungd u r c h d a s G e s e t z , b ö r s e n g e s e t z l i c h eBestimmungen oder diese Statuten verlangtwird, gelten sämtliche Mitteilungen an dieAkt ionäre a ls gül t ig er fo lgt , wenn s ie imSchweizerischen Handelsamtsblatt veröffentlichtworden sind. Schriftliche Bekanntmachungender Gesellschaft an die Aktionäre werden aufdem ordentlichen Postweg an die letzte imAktienbuch verzeichnete Adresse des Aktionärsoder des bevo l lmächt ig ten Empfängersgeschickt. Finanzinstitute, welche Aktien fürwirtschaftlich Berechtigte halten und als solchesim Aktienbuch eingetragen sind, gelten alsbevollmächtigte Empfänger.

2 To the extent that individual notification is notrequired by law, stock exchange regulations ort h e s e A r t i c l e s o f A s s o c i a t i o n , a l lcommunications to the shareholders shall bedeemed valid if published in the Swiss OfficialG a z e t t e o f C o m m e r c e . W r i t t e ncommunicat ions by the Company to i tsshareholders shall be sent by ordinary mail tothe las t address o f the shareho lder o rauthorized recipient recorded in the shareregister. Financial institutions holding Sharesfor beneficial owners and recorded in suchcapacity in the share register shall be deemedto be authorized recipients.

Abschnitt 7:Verbindlicher Originaltext

Section 7:Original Language

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Artikel 34 Article 34Verbindlicher Originaltext Falls sich zwischen der deutschen und

englischen Fassung dieser Statuten Differenzenergeben, hat die deutsche Fassung Vorrang.

OriginalLanguage

In the event of deviations between the Germanand English version of these Articles ofAssociation, the German text shall prevail.

Abschnitt 8:Definitionen

Section 8:Definitions

Artikel 35 Article 35Aktie(n) 1 Der Begriff Aktie(n) hat die in Artikel 4 dieser

Statuten aufgeführte Bedeutung.Share(s) 1 The term Share(s) has the meaning assigned

to it in Article 4 of these Articles of Association.Eigentümer 2 Eigentümer(in), unter Einschluss der Begriffe

Eigentum, halten, gehalten, Eigentümerschaftoder ähnl icher Begr i f fe , bedeutet , wennverwendet mit Bezug auf Aktien, jede Person,welche allein oder zusammen mit oder überN a h e s t e h e n d e G e s e l l s c h a f t e n o d e rNahestehende Personen:

Owner 2 Owner, including the terms Own, Owned andOwnership when used with respect to anyShares means a Person that individually orw i th o r th rough any o f i t s A f f i l i a tes o rAssociates:

(a) wirtschaftliche Eigentümerindieser Aktien ist, ob direkt oderindirekt;

(a) beneficially Owns such Shares,directly or indirectly;

(b) (1) das Recht hat, aufgrundeines Vertrags, einer Absprache odereiner anderen Vereinbarung, odera u f g r u n d d e r A u s ü b u n g e i n e sWandel−, Tausch−, Bezugs− oderOptionsrechts oder anderweitig Aktienzu erwerben (unabhängig davon, obdieses Recht sofort ausübbar ist odernu r nach e ine r gew issen Ze i t ) ;vorausgesetzt, dass eine Person nichtals Eigentümerin derjenigen Aktiengelten sol l , die im Rahmen einesÜbernahme− oder Umtauschangebots,das diese Person oder eine dieserPerson Nahestehende Gesellschaftoder Nahestehende Person eingeleitethat, angedient werden, bis dieseA k t i e n z u m K a u f o d e r T a u s c hakzeptiert werden; oder (2) das Rechthat, die Stimmrechte dieser Aktienau fg rund e ines Ve r t rags , e i ne rA b s p r a c h e o d e r e i n e r a n d e r e nV e r e i n b a r u n g a u s z u ü b e n ;vorausgesetzt, dass eine Person nichtals Eigentümerin von Aktien gilt infolged e s R e c h t s , d a s S t i m m r e c h tauszuüben, soweit der diesbezüglicheVertrag, die diesbezügliche Abspracheoder d ie d iesbezüg l iche andereVereinbarung nur aufgrund einerwiderruflichen Vollmacht (proxy) oderZustimmung zustande gekommen ist,und diese Vollmacht (proxy) oderZustimmung in Erwiderung auf eine an10 oder mehr Personen gemachtediesbezügliche Aufforderung ergangenist; oder

(b) has (1) the right to acquire suchSha res (whe the r such r i gh t i sexercisable immediately or only afterthe passage of time) pursuant to anya g r e e m e n t , a r r a n g e m e n t o runderstanding, or upon the exerciseof conversion rights, exchange rights,warrants or options, or otherwise;provided, however, that a Personshall not be deemed the Owner ofShares tendered pursuant to a tenderor exchange offer made by suchPerson or any of such Person'sAffiliates or Associates until suchtendered Shares are accepted forpurchase or exchange; or (2) theright to vote such Shares pursuant toany agreement, arrangement orunderstanding; provided, however,that a Person shall not be deemedthe Owner of any Shares because ofsuch Person's right to vote suchS h a r e s i f t h e a g r e e m e n t ,arrangement or understanding tovote such Shares arises solely from arevocable proxy or consent given inresponse to a proxy or consentsol ic i tat ion made to 10 or morePersons; or

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( c ) zwecks Erwerbs , Ha l tens ,Stimmrechtsausübung (mit Ausnahmeder Stimmrechtsausübung aufgrundeiner widerruflichen Vollmacht (proxy)o d e r Z u s t i m m u n g w i e i nArtikel 35 Abs. 2(b)(ii)(2) umschrieben)oder Veräusserung dieser Aktien miteiner anderen Person in einen Vertrag,eine Absprache oder eine andereVereinbarung getreten ist, die direktoder indirekt entweder selbst oderüber ihr Nahestehende Gesellschafteno d e r N a h e s t e h e n d e P e r s o n e nwirtschaftlich Eigentümerin dieserAktien ist.

( c ) h a s a n y a g r e e m e n t ,arrangement or understanding for thepurpose of acquiring, holding, voting( e x c e p t v o t i n g p u r s u a n t t o arevocab le p roxy o r consent asd e s c r i b e d i nAr t i c le 35 para . 2 (b) ( i i ) (2 ) ) , o rdisposing of such Shares with anyother Person that beneficially Owns,or whose Affil iates or Associatesbeneficially Own, directly or indirectly,such Shares.

Gesellschaft 3 Der Begriff Gesellschaft hat die in Artikel 1dieser Statuten aufgeführte Bedeutung.

Company 3 The term Company has the meaningassigned to it in Article 1 of these Articles ofAssociation.

Kontrolle 4 K o n t r o l l e , e i n s c h l i e s s l i c h d i e B e g r i f f ekontrol l ierend, kontrol l ier t von und untergemeinsamer Kontrol le mit , bedeutet dieMögl ichke i t , d i rek t oder ind i rek t auf d ieGeschäftsführung und die Geschäftspolitik einerPerson Einfluss zu nehmen, sei es aufgrund desHaltens von Stimmrechten, eines Vertrags oderauf andere Weise. Eine Person, welche 20%o d e r m e h r d e r a u s g e g e b e n e n o d e ra u s s t e h e n d e n S t i m m r e c h t e e i n e rK a p i t a l g e s e l l s c h a f t , r e c h t s − o d e rnicht−rechtsfähigen Personengesellschaft odereines anderen Rechtsträgers hält, hat mangelsNachweises des Gegenteils unter Anwendungdes Bewe ismasses de r überw iegendenW a h r s c h e i n l i c h k e i t d e r B e w e i s m i t t e lvermutungsweise Kontrolle über einen solchenRechtsträger. Ungeachtet des Voranstehendengilt diese Vermutung der Kontrolle nicht, wenneine Person in Treu und Glauben und nicht zurUmgehung dieser Bestimmung Stimmrechte alsStellvertreter (agent), Bank, Börsenmakler(broker), Nominee, Depotbank (custodian) oderTreuhänder (trustee) für einen oder mehrereEigentümer häl t , d ie für s ich a l le in oderzusammen als Gruppe keine Kontrolle über denbetreffenden Rechtsträger haben.

Control 4 Control , including the terms control l ing,controlled by and under common control with,means the possession, direct or indirect, of thepower to direct or cause the direction of themanagement and policies of a Person, whetherthrough the Ownership of voting shares, bycontract, or otherwise. A Person who is theOwner of 20% or more of the issued oroutstanding voting shares of any corporation,partnership, unincorporated association orother entity shall be presumed to have controlof such entity, in the absence of proof by apreponderance of the evidence to the contrary.Notwithstanding the foregoing, a presumptionof control shall not apply where such Personholds voting shares, in good faith and not forthe purpose of circumventing this provision, asan agent, bank, broker, nominee, custodian ortrustee for one or more Owners who do notindividually or as a group have control of suchentity.

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Nahestehender Aktionär 5 Nahestehender Aktionär bedeutet jede Person(unter Ausschluss der Gesellschaft oder jederdirekten oder indirekten Tochtergesellschaft, diezur Mehrheit von der Gesellschaft gehaltenwird), (i) die Eigentümerin von 15% oder mehrder ausgegebenen Aktien ist, oder (ii) die alsNahestehende Gesellschaft oder NahestehendePerson anzusehen ist und irgendwann in dendrei unmittelbar vorangehenden Jahren vor demZeitpunkt, zu dem bestimmt werden muss, obdiese Person ein Nahestehender Aktionär ist,E i g e n t ü m e r i n v o n 1 5 % o d e r m e h r d e rausgegebenen Stimmrechte gewesen ist,ebenso wie jede Nahestehende Gesellschaftund Nahestehende Person dieser Person;vorausgesetzt, dass eine Person nicht alsNahestehender Aktionär gilt, die aufgrund vonH a n d l u n g e n , d i e a u s s c h l i e s s l i c h d e rGesellschaft zuzurechnen sind, Eigentümerinv o n A k t i e n i n Ü b e r s c h r e i t u n g d e r15%−Beschränkung ist; wobei jedoch jedesolche Person dann als Nahestehender Aktionärgilt, falls sie später zusätzliche Aktien erwirbt,ausser dieser Erwerb erfolgt aufgrund vonweiteren Gesellschaftshandlungen, die wederd i rek t noch i nd i rek t von d iese r Pe rsonbeeinflusst werden. Zur Bestimmung, ob einePerson ein Nahestehender Aktionär ist, sind diea ls ausgegeben ge l tenden Akt ien un terEinschluss der von dieser Person gehaltenenAktien (unter Anwendung des Begriffs "gehalten"wie in Artikel 35 Abs. 2 dieser Statuten definiert)zu berechnen, jedoch unter Ausschluss vonnichtausgegebenen Aktien, die aufgrund einesVertrags, einer Absprache oder einer anderenVereinbarung, oder aufgrund der Ausübungeines Wandel−, Bezugs− oder Optionsrechtsoder anderweitig ausgegeben werden können;

InterestedShareholder

5 Interested Shareholder means any Person(other than the Company or any direct orindirect majority−Owned subsidiary of theCompany) (i) that is the Owner of 15% or moreof the issued Shares of the Company or (ii) thatis an Affiliate or Associate of the Company andwas the Owner of 15% or more of the issuedShares at any time within the three−year periodimmediately prior to the date on which it issought to be determined whether such Personis an Interested Shareholder, and also theAffil iates and Associates of such Person;provided, however, that the term InterestedShareholder shall not include any Personwhose Ownership of Shares in excess of the15% limitation is the result of action takensolely by the Company; provided that suchPerson shall be an Interested Shareholder ifthereafter such Person acquires additionalShares, except as a result of further corporateaction not caused, directly or indirectly, by suchPerson. For the purpose of determiningwhether a Person is an Interested Shareholder,the Shares deemed to be in issue shall includeShares deemed to be Owned by the Person(through the application of the definition ofOwner in Article 35 para. 2 of these Articles ofAssociation) but shall not include any otherunissued Shares which may be issuablepursuant to any agreement, arrangement orunderstanding, or upon exercise of conversionrights, warrants or options, or otherwise.

Nahestehende Gesellschaft 6 Nahestehende Gesellschaft bedeutet jedePerson, die direkt oder indirekt über eine odermehrere Mittelspersonen eine andere Personkontrolliert, von einer anderen Person kontrolliertwird, oder unter gemeineinsamer Kontrolle miteiner anderen Person steht.

Affiliate 6 Affi l iate means a Person that directly, orindirectly through one or more intermediaries,controls, or is control led by, or is undercommon control with, another Person.

Nahestehende Person 7 Nahes tehende Pe rson bedeu te t , wennverwendet zur Bezeichnung einer Beziehung zueiner Person, (i) jede Kapitalgesellschaft,r e c h t s − o d e r n i c h t − r e c h t s f ä h i g ePersonengese l l scha f t oder e in andererRechtsträger, von welcher diese Person Mitglieddes Leitungs− oder Verwaltungsorgans, derGeschäftsleitung oder Gesellschafter ist odervon welcher diese Person, direkt oder indirekt,E igentümer in von 20% oder mehr e inerKategorie von Aktien oder anderer Anteilsrechteist, die ein Stimmrecht vermitteln, (ii) jedesTreuhandvermögen (Trust) oder jede andereVermögenseinhei t , an der d iese Personwirtschaftlich einen Anteil von 20% oder mehrhält oder in Bezug auf welche diese Person alsV e r w a l t e r ( t r u s t e e ) o d e r i n ä h n l i c htreuhändischer Funktion tätig ist, und (iii) jederVerwandte, Ehe− oder Lebenspartner dieserPerson, oder jede Verwandte des Ehe− oderLebenspartners, jeweils soweit diese dengleichen Wohnsitz haben wie diese Person.

Associate 7 Associate, when used to indicate a relationshipwith any Person, means (i) any corporation,partnership, unincorporated association orother entity of which such Person is a director,officer or partner or is, directly or indirectly, theOwner of 20% or more of any class of votingshares, (ii) any trust or other estate in whichsuch Person has at least a 20% beneficialinterest or as to which such Person serves astrustee or in a similar fiduciary capacity, and(iii) any relative or spouse of such Person, orany relative of such spouse, who has the sameresidence as such Person.

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OR 8 Der Begriff OR hat die in Artikel 14 Abs. 2 dieserStatuten aufgeführte Bedeutung.

CO 8 The term CO has the meaning assigned to it inArticle 14 para. 2 of these Articles ofAssociation.

Person 9 Person bedeutet jede natür l iche Person,K a p i t a l g e s e l l s c h a f t , r e c h t s − o d e rnicht−rechtsfähige Personengesellschaft oderjeder andere Rechtsträger;

Person 9 Person means any individual, corporation,partnership, unincorporated association orother entity.

Rechte 10Der Begriff Rechte hat die in Artikel 6 Abs. 1dieser Statuten aufgeführte Bedeutung.

Rights 10The term Rights has the meaning assigned to itin Ar t ic le 6 para. 1 o f these Ar t ic les o fAssociation.

Mit Rechten verbundenenObligationen

11D e r B e g r i f f m i t R e c h t e n v e r b u n d e n e nObligationen hat die in Artikel 6 Abs. 1 dieserStatuten aufgeführte Bedeutung.

Rights−BearingObligations

11The term Rights−Bearing Obligations has themeaning assigned to it in Article 6 para. 1 ofthese Articles of Association.

SEC 12Der Begriff SEC hat die in Artikel 12 Abs. 2dieser Statuten aufgeführte Bedeutung.

SEC 12The term SEC has the meaning assigned to itin Art ic le 12 para. 2 of these Art ic les ofAssociation.

Transfer Agent 13D e r B e g r i f f T r a n s f e r A g e n t h a t d i e i nArtikel 8 Abs. 3 dieser Statuten aufgeführteBedeutung.

TransferAgent

13The term Transfer Agent has the meaningassigned to it in Article 8 para. 3 of theseArticles of Association.

Zusammen-schluss 14Zusammenschluss bedeutet, wenn im Rahmendieser Statuten in Bezug auf die Gesellschaftoder e inen Nahestehenden Akt ionär derGesellschaft verwendet:

BusinessCombination

14Business Combination, when used in theseArticles of Association in reference to theCompany and any Interested Shareholder ofthe Company, means:

(a) Jede Fusion oder andere Formd e s Z u s a m m e n s c h l u s s e s d e rGesellschaft oder einer direkten oderindirekten Tochtergesellschaft, die zurM e h r h e i t v o n d e r G e s e l l s c h a f tg e h a l t e n w i r d , m i t ( 1 ) d e mNahestehenden Aktionär oder (2) eineranderen Kapitalgesellschaft, rechts−o d e r n i c h t − r e c h t s f ä h i g e nPersonengesellschaft oder einemanderen Rechtsträger, soweit dieseF u s i o n o d e r a n d e r e F o r m d e sZusammensch lusses durch denNahestehenden Aktionär verursachtworden ist und als Folge dieser Fusiono d e r a n d e r e n F o r m d e sZusammenschlusses Artikel 19(f) undArt ikel 20 Abs. 3 dieser Statuten(sowie jede der dazu gehör igenDefinition in Artikel 35 dieser Statuten)o d e r i m W e s e n t l i c h e n g l e i c h eBestimmungen wie Artikel 19(f), Artikel20 Abs. 3 (und die dazugehörigenDef in i t ionen in Ar t ike l 35 d ieserS ta tu ten au f den über lebendenRechtsträger) nicht anwendbar sind;

(a) Any merger or consolidation ofthe Company or any direct or indirectmajority−Owned subsidiary of theCompany with (1) the InterestedShareholder or (2) with any otherc o r p o r a t i o n , p a r t n e r s h i p ,unincorporated association or otherentity if the merger or consolidation iscaused by the Interested Shareholderand as a result of such merger orconso l ida t ion Ar t i c le 19( f ) andArticle 20 para. 3 of these Articles ofAssociation (including the relevantdefinit ions in Art icle 35 of theseArticles of Association pertainingthereto) or a provision substantiallythe same as such Article 19(f) andArt icle 20 para. 3 ( including therelevant definitions in Article 35) arenot applicable to the surviving entity;

(b) jeder Verkauf, Vermietung oderV e r p a c h t u n g , h y p o t h e k a r i s c h eBelastung oder andere Verpfändung,Übertragung oder andere Verfügung( o b i n e i n e r o d e r m e h r e r e nTransaktionen), einschliesslich imR a h m e n e i n e s T a u s c h s , v o nVermögenswerten der Gesellschaftoder einer direkten oder indirektenTochtergesellschaft, die zur Mehrheitvon der Gesellschaft gehalten wird, ane inen Nahes tehenden Ak t i onä r(ausser soweit der Zuerwerb untereiner der genannten Transaktionenproportional als Aktionär erfolgt),soweit diese Vermögenswerte einenM a r k t w e r t v o n 1 0 % o d e r m e h rentweder des auf konsolidierter Basisagg reg ie r ten Mark twer tes a l l e rVermögenswerte der Gesellschaftoder des aggregierten Marktwertesal ler dann ausgegebenen Akt ienhaben, unabhängig davon, ob eined ieser Transak t ionen Te i l e inerAuflösung der Gesellschaft ist odernicht;

(b) any sale, lease, exchange,mortgage, pledge, transfer or otherdisposition (in one transaction or aser ies o f t ransact ions) , exceptproportionately as a shareholder, toor with the Interested Shareholder,whether as part of a dissolution orotherwise, of assets of the Companyo r o f a n y d i r e c t o r i n d i r e c tmajority−Owned subsidiary of theCompany which assets have anaggregate market value equal to 10%or more of ei ther the aggregatemarket value of all the assets of theC o m p a n y d e t e r m i n e d o n aconsolidated basis or the aggregatemarket value of all the Shares then inissue;

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(c) jede Transaktion, die dazu führt,dass die Gesellschaft oder eine direkteoder indirekte Tochtergesellschaft, diezur Mehrheit von der Gesellschaftg e h a l t e n w i r d , A k t i e n o d e rTochtergesellschafts−Aktien an denNahestehenden Aktionär ausgibt oderüberträgt, es sei denn (1) aufgrund derAusübung, des Tauschs oder derW a n d l u n g v o nFinanzmarktinstrumenten, die in Aktienoder Ak t ien e iner d i rek ten oderindirekten Tochtergesellschaft, die zurM e h r h e i t v o n d e r G e s e l l s c h a f tgehalten wird, ausgeübt, getauschtoder gewandel t werden können,vorausgesetz t , d ie bet ref fendenFinanzmarktinstrumente waren zumZeitpunkt, in dem der NahestehendeAktionär zu einem solchem wurde,bereits ausgegeben; (2) als Dividendeoder Ausschüttung an alle Aktionäre,oder aufgrund der Ausübung, desTauschs oder der Wandlung vonFinanzmarktinstrumenten, die in Aktienoder Ak t ien e iner d i rek ten oderindirekten Tochtergesellschaft, die zurM e h r h e i t v o n d e r G e s e l l s c h a f tgehalten wird, ausgeübt, getauschtoder gewandel t werden können,v o r a u s g e s e t z t , d i e s eFinanzinst rumente werden a l lenAktionäre anteilsmässig ausgegeben,nachdem der Nahestehende Aktionärzu einem solchem wurde; (3) gemässe i n e m U m t a u s c h a n g e b o t d e rG e s e l l s c h a f t , A k t i e n v o n a l l e nA k t i o n ä r e n z u d e n g l e i c h e nBedingungen zu erwerben; oder(4) aufgrund der Ausgabe oder derÜbertragung von Aktien durch dieGesellschaft; vorausgesetzt, dass inkeinem der unter (2) bis (4) genanntenFällen der proportionale Anteil desNahestehenden Aktionärs an denAktien erhöht werden darf;

(c) any transaction which results inthe issuance or t ransfer by theCompany or by any direct or indirectmajority−Owned subsidiary of theCompany of any Shares or shares ofsuch subsidiary to the InterestedShareholder, except (1) pursuant tothe exercise, exchange or conversiono f s e c u r i t i e s e x e r c i s a b l e f o r ,exchangeable for or convertible intoShares or the shares of a direct orindirect majority−Owned subsidiary ofthe Company which securities werein issue prior to the time that theInterested Shareholder became such;( 2 ) p u r s u a n t t o a d i v i d e n d o rdistribution paid or made, or theexercise, exchange or conversion ofs e c u r i t i e s e x e r c i s a b l e f o r ,exchangeable for or convertible intoShares or the shares of a direct orindirect majority−Owned subsidiary ofthe Company which secur i ty isd i s t r i b u t e d , p r o r a t a , t o a l lshareholders subsequent to the timethe Interested Shareholder becamesuch; (3) pursuant to an exchangeoffer by the Company to purchaseShares made on the same terms toall holders of said Shares; or (4) anyissuance or transfer of Shares by theCompany; provided, however, that inno case under (2)–(4) above shallthere be an increase in the InterestedShareholder's proportionate interestin the Shares;

(d) jede Transaktion, in welche dieGesellschaft oder eine direkte oderindirekte Tochtergesellschaft, die zurM e h r h e i t v o n d e r G e s e l l s c h a f tgehalten wird, involviert ist, und diedirekt oder indirekt dazu führt, dassder proport ionale Antei l der vomNahestehenden Aktionär gehaltenenA k t i e n , i n A k t i e n w a n d e l b a r eO b l i g a t i o n e n o d e rTochtergesellschafts−Aktien erhöhtwird, ausser eine solche Erhöhung istnur unwesentlich und die Folge einesSpitzenausgleichs für Fraktionen odere i n e s R ü c k k a u f s o d e r e i n e rRücknahme von Ak t i en , sowe i tdiese(r) weder direkt noch indirektdurch den Nahestehenden Aktionärverursacht wurde; oder

(d) any transaction involving theCompany or any direct or indirectmajority−Owned subsidiary of theCompany which has the ef fect ,directly or indirectly, of increasing theproportionate interest in the Shares,or securit ies convertible into theShares, or in the shares of any suchsubsidiary which is Owned by theInterested Shareholder, except as aresult of immaterial changes due tofractional share adjustments or as aresult of any purchase or redemptionof any Shares not caused, directly ori n d i r e c t l y , b y t h e I n t e r e s t e dShareholder; or

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(e) jede d i rekte oder ind i rekteGewährung von Darlehen, Vorschüssen,G a r a n t i e n , B ü r g s c h a f t e n , o d e rgarant ieähnl icher Verpf l ichtungen,Pfändern oder anderen f inanziel lenBegünstigungen (mit Ausnahme einers o l c h e n , d i e g e m ä s s d e nUnterabschn i t ten (a ) – (d ) d iesesArtikels 35 Abs. 14 ausdrücklich erlaubtist sowie einer solchen, die proportionalan alle Aktionäre erfolgt) durch die oderüber die Gesellschaft oder eine direkteoder indirekte Tochtergesellschaft, diezur Mehrhei t von der Gesel lschaf tgehalten wird, an den NahestehendenAktionär.

(e) any receipt by the InterestedShareholder of the benefit, directly orindirectly (except proportionately as ashareholder), of any loans, advances,g u a r a n t e e s , p l e d g e s o r o t h e rfinancial benefits (other than thoseexpressly permitted in subsections(a)–(d) of this Article 35 para. 14)provided by or through the Companyo r a n y d i r e c t o r i n d i r e c tmajority−Owned subsidiary of theCompany.

Abschnitt 9:Übergangsbestimmungen

Section 9:Transitional Provisions

Artikel 36 Article 36Sacheinlage D i e G e s e l l s c h a f t ü b e r n i m m t b e i d e r

Kapi-talerhöhung vom 19. Dezember 2008 vonder Transocean Inc. in Grand Cayman, CaymanI s l a n d s ( T r a n s o c e a n I n c . ) , g e m ä s sSacheinlagevertrag per 18. Dezember 2008(Sacheinlagevertrag) 319’228’632 Akt ien(ordinary shares) der Transocean Inc. DieseAktien werden zu einem Übernahmewert voni n s g e s a m t C H F 1 6 ' 4 7 6 ' 1 0 7 ' 9 6 1 . 8 0übernommen. Als Gegenlei-stung für dieseSacheinlage gibt d ie Gesel lschaft e inemUmtauschagenten, handelnd auf Rechnung derAktionäre der Transocean Inc. im Zeitpunktu n m i t t e l b a r v o r V o l l z u g d e sSacheinlagevertrages und im Namen und aufRechnung der Transocean Inc., insgesamt335'228’632 voll einbezahlte Aktien mit einemNennwert von insgesamt CHF 5'028'429’480aus. Die Gesell-schaft weist die Diffe-renzz w i s c h e n d e m t o t a l e n N e n n w e r t d e raus-gegebenen Aktien und dem Übernahmewertde r Sache in lage im Gesamtbe t rag vonCHF 11'447'678'481.80 den Reserven derGesellschaft zu.

Contributionin Kind

In connection with the capital increase ofDecember 19, 2008, and in accordance withthe contr ibut ion in kind agreement as ofDecember 18, 2008 (the Contribution in KindA g r e e m e n t ) , t h e C o m p a n y a c q u i r e s319,228,632 ordinary shares of TransoceanInc . , G rand Cayman , Cayman I s l ands(Transocean Inc.). The shares of TransoceanInc. are acquired for a total value of CHF16,476,107,961.80. As consideration for thiscontr ibut ion, the Company issues to anexchange agent, acting for the account of theholders of ordinary shares of Transocean Inc.outstanding immediately prior to the completionof the Contribution in Kind Agreement and inthe name and the account of Transocean Inc, atotal of 335,228,632 fully paid Shares with atotal par value of CHF 5,028,429,480. Thedifference between the aggregate par value ofthe issued Shares and the total value ofCHF 11,447,678,481.80 is allocated to thereserves of the Company.

____________________

Zug, 14. Mai 2010 Zug, May 14, 2010

Exhibit 10.1

DRILLING CONTRACT

between

VASTAR RESOURCES, INC.

and

R&B FALCON DRILLING CO.

DATED DECEMBER 9, 1998

for

“RBS-8D”

“Deepwater Horizon” CONTRACT NO. 980249

D-1-87.1

DISTRIBUTION:

Houston Legal Files - Signed Original

Houston Distribution (2)

Vern Buzard

DRILLING CONTRACT

RBS-8D

SEMISUBMERSIBLE DRILLING UNIT


AND

R&B FALCON DRILLNG CO.

CONTRACT NO. 980249 DATE: DECEMBER 9, 1998

TABLE OF CONTENTS

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ARTICLE 1- TERM 2ARTICLE 2- DAYRATES 4ARTICLE 3- PERSONNEL AND PAYMENTS 7ARTICLE 4- OTHER PAYMENTS 8ARTICLE 5- DRILLING UNIT MODIFICATIONS 9ARTICLE 6- OTHER REIMBURSEMENTS 9ARTICLE 7- MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES TO BE FURNISHED BY CONTRACTOR 10ARTICLE 8- MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES TO BE FURNISHED BY COMPANY 11ARTICLE 9- PAYMENTS 11ARTICLE 10- PAYMENT OF CLAIMS 12ARTICLE 11- TAXES AND FEES 13ARTICLE 12- COMPANY’S RIGHT TO QUESTION INVOICES AND AUDIT 14ARTICLE 13- DEPTH 14ARTICLE 14- DRILLING UNIT 14ARTICLE 15- PERFORMANCE OF DRILLING OPERATIONS 16ARTICLE 16- INSPECTION OF MATERIALS 18ARTICLE 17- SAFETY 18ARTICLE 18- PERFORMANCE OF THE WORK 19ARTICLE 19- RECORDS TO BE FURNISHED BY CONTRACTOR 21ARTICLE 20- INSURANCE 22ARTICLE 21- INDEMNITY FOR PERSONAL INJURY OR DEATH 22ARTICLE 22- RESPONSIBILITY FOR LOSS OF OR DAMAGE TO THE EQUIPMENT 22ARTICLE 23- LOSS OF HOLE OR RESERVOIR 24ARTICLE 24- POLLUTION 25ARTICLE 25- INDEMNITY OBLIGATION 26ARTICLE 26- LAWS, RULES, AND REGULATIONS 27ARTICLE 27- TERMINATION 28ARTICLE 28- FORCE MAJEURE 29ARTICLE 29- CONFIDENTIAL INFORMATION, LICENSE AND PATENT INDEMNITY 30ARTICLE 30- ASSIGNMENT OF CONTRACT 32ARTICLE 31- INGRESS AND EGRESS OF LOCATION 33ARTICLE 32- COMPANY POLICIES 33ARTICLE 33- NOTICES 34ARTICLE 34- CONSEQUENTIAL DAMAGES 35ARTICLE 35- WAIVERS AND ENTIRE CONTRACT 35

TABLE OF CONTENTS (cont.)

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EXHIBIT A: Dayrates Tab AEXHIBIT B-1: Drilling Unit Specifications Tab BEXHIBIT B-2: Material Equipment List Tab BEXHIBIT B-3: Consumable Material and Equipment List Tab BEXHIBIT C: Insurance Requirements Tab CEXHIBIT D: Safety, Health, and Environmental Management System Tab DEXHIBIT E: Termination Payment Schedule Tab EEXHIBIT F-1: Rig Manning Tab FEXHIBIT F-2: Cost of Additional Personnel Tab FEXHIBIT G: Vessel/Equipment Performance/Acceptance Test Tab GEXHIBIT H: Project Execution Plan Tab H

DRILLING CONTRACT

THIS CONTRACT (“CONTRACT”) is made and entered into this 9th day of December, 1998, by and between Vastar Resources, Inc., a Delaware Corporation, hereinafter referred to as “COMPANY” and R&B Falcon Drilling Co., (“CONTRACTOR”), and shall be effective upon execution by both COMPANY and CONTRACTOR (the date when so effective, shall be referred to herein as the (“Effective Date”). COMPANY and CONTRACTOR are sometimes herein individually referred to as a “Party” and collectively referred to as the “Parties.” RECITALS Whereas CONTRACTOR shall cause to be built, a semisubmersible drilling unit, “Drilling Unit”. Whereas COMPANY desires to engage the services of CONTRACTOR, its Drilling Unit, and its equipment and all necessary crews for drilling, completing, testing, and remedial operations and support operations on a well or wells in the federal waters of the Gulf of Mexico, hereinafter referred to as “Operations” or “Work”. Whereas this CONTRACT and the attached exhibits establishes the terms and conditions contained in this document entitled “DRILLING CONTRACT” and the attached exhibits:

NOW, THEREFORE, COMPANY and CONTRACTOR, for and in consideration of the mutual covenants and agreements contained herein and good and valuable consideration paid by COMPANY to CONTRACTOR, the receipt and sufficiency of which are acknowledged by CONTRACTOR, the Parties hereby agree as follows:

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Exhibit A: Dayrates

Exhibit B-1: Drilling Unit Specifications

Exhibit B-2: Material Equipment List

Exhibit B-3: Consumable Material and Equipment List

Exhibit C: Insurance Requirements

Exhibit D: Safety, Health, and Environmental Management System

Exhibit E: Termination Payment Schedules

Exhibit F-1: Rig Manning

Exhibit F-2: Cost of Additional Personnel

Exhibit G: Vessel/Equipment Performance/Acceptance Test

Exhibit H: Project Execution Plan

ARTICLE 1 TERM 1.1 EFFECTIVE DATE AND DURATION 1.1.1 This CONTRACT shall remain in full force and effect for three (3) years (the “Initial Contract Term”). The Initial Contract Term shall begin on the Commencement Date. The term of this CONTRACT from its Effective Date through its Initial Contract Term and all Extension Periods shall be herein referred to as the “Contract Period.”

1.1.2 With a three (3) year Initial Contract Term, COMPANY has the option (the “Extension Option”) to extend this CONTRACT for five (5) consecutive one (1) year periods (each such extension period shall be herein referred to as an “Extension Period”) beginning at the end of the Initial Contract Term. Each Extension Option must be exercised by COMPANY by written notice to CONTRACTOR nine (9) months before the end of the Initial Contract Term or the previous Extension Period, as the case may be. This CONTRACT, as it may have been amended as of the date on which COMPANY exercises any Extension Option, shall be extended for one (1) year with further Extension Options available to COMPANY, as provided herein and the various rates shall be mutually agreed in writing. COMPANY shall also have the option within twenty-four (24) months of the Effective Date to exercise any of the one-year options at the three (3) year rate. In addition, this CONTRACT may be extended for any additional period by any other method or manner as the Parties may mutually agree in writing. 1.1.3 COMPANY has the option from the Effective Date up to and including one (1) year after the Commencement Date, to convert this CONTRACT to a five (5) year term (“5 Year Option”). If the 5-Year Option is exercised within six (6) months from the Effective Date, then the five (5) year rate in Exhibit A shall apply. If the 5 Year Option is exercised from six (6) months of the Effective Date to one (1) year from the Effective Date, then the five (5) year rate in Exhibit A plus five thousand dollars ($5,000.00) shall apply. If the 5 Year Option is exercised from one (1) year after the Effective Date to the Commencement Date, then the five (5) year rate in Exhibit A plus seven thousand five hundred dollars ($7,500.00) shall apply. If the option is exercised from the Commencement Date to the end of the first contract year, the five (5) year rate in Exhibit A plus ten thousand dollars ($10,000.00) shall apply from that date forward and any portion of the first contract year shall become part of the five (5) year commitment. 1.1.4 If COMPANY exercises the 5 Year Option, then COMPANY has the option, (the “Extension Option”) under the five (5) year Initial Contract Term to extend this CONTRACT for three (3) consecutive one (1) year periods (each such extension period shall be herein referred to as an “Extension Period”) beginning at the end of the Initial Contract Term. Each Extension Option must be exercised by COMPANY by written notice to CONTRACTOR at least nine (9) months before the end of the Initial Contract Term or the previous Extension Period, as the case may be. This CONTRACT, as it may have been amended as of the date on which CONTRACTOR exercises any Extension Option, shall be extended for one (1) year with further Extension Options available to COMPANY as provided herein and the various rates shall be

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mutually agreed in writing. In addition, this CONTRACT may be extended for any additional period by any other method or as the Parties may mutually agree in writing. 1.1.5 If the Initial Contract Term or any Extension Period of this CONTRACT expires while COMPANY has work in progress on any well or any other operations conducted with respect to a well with the objective of satisfying the well producibility criteria of 30 C.F.R. § 250.11 (1988), then COMPANY shall have the right to have the work in progress on such well or operation completed to COMPANY’S satisfaction under the terms and provisions of this CONTRACT and the term of this CONTRACT shall be deemed to be extended for the period of time required to complete such work. 1.2 COMMENCEMENT DATE

“Commencement Date” means the date and hour that the last of the following conditions has been satisfied: (i) all requirements in Exhibit G and all governmental and regulatory certifications and inspections required of the CONTRACTOR have been obtained, (ii) CONTRACTOR’S full crew is aboard, (iii) the Drilling Unit has cleared customs and other formalities, (iv) the Drilling Unit and CONTRACTOR’S full crew is in all respects ready to commence and sustain continued drilling operations during the Contract Period and (v) the Drilling Unit has arrived at the COMPANY’S first location or an alternative location, if requested by COMPANY. The Parties shall cooperate in the loading of any COMPANY’S drilling equipment and materials to minimize any delay in the Commencement Date. In the event that, despite the Parties’ best efforts, the loading of COMPANY’S drilling equipment and materials cause a delay in the Commencement Date the CONTRACTOR shall be paid at the Standby and Moving Rate for any such delay. Notwithstanding the foregoing, however, COMPANY may require or allow the Drilling Unit to commence Work at an earlier date in which case such earlier date shall be the Commencement Date and in such event any of the above requirements for the Commencement Date which have not been satisfied shall be deemed satisfied. The Parties agree that delivery of the Drilling Unit to the U.S. Gulf of Mexico is desired to occur twenty seven (27) months from the Effective Date, with COMPANY agreeing to take delivery as much as three (3) months sooner (“Delivery Date”).

If the Drilling Unit is not delivered to the Gulf of Mexico by thirty (30) months from the Effective Date, then COMPANY shall invoice CONTRACTOR every thirty (30) thirty days after the start of the late delivery charges a sum calculated at a rate of five thousand dollars ($5,000.00) per day during the first six (6) months of the late delivery and then at a rate of ten thousand dollars ($10,000.00) per day for each day until the Drilling Unit is delivered to the Gulf of Mexico with the total amount of such payment not to exceed one million five hundred thousand dollars ($1,500,000.00) for the late delivery of the Drilling Unit.

1.3 COMPLETION OF CONTRACT

1.3.1 Upon completion of this CONTRACT, if CONTRACTOR has no other Work for the Drilling Unit, COMPANY shall provide for tow, if required, of the Drilling Unit to, and securing

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in, the anchorage area at Galveston, Texas, or a mutually agreed point of no greater distance from its location of the last Work under this CONTRACT and at applicable dayrates. 1.3.2 Subject to Article 27.4, upon completion of this CONTRACT, if CONTRACTOR has other Work for the Drilling Unit, COMPANY shall have no further responsibility hereunder when all of COMPANY’S equipment has been offloaded, the well secured, and the Drilling Unit is ready to get underway.

ARTICLE 2 DAYRATES 2.1 GENERAL COMPANY shall pay CONTRACTOR for work performed, services rendered, and materials, equipment, supplies, and personnel furnished by CONTRACTOR at the rates specified in Exhibit A. The period of time for which each rate shall be applicable shall be computed from and to the nearest half (1/2) hour. Subject to Article 2.3, the rates as specified in Exhibit A shall apply during the entire Initial Contract Term. The rates are based on CONTRACTOR’S operations being conducted on a seven (7) day week and a twenty-four (24) hour work day.

2.2 DAYRATES

Each of the dayrate classifications is as follows:

2.2.1 Moving Rate

a) From the moment operations are commenced to release the first mooring line or move the Drilling Unit off location at a drilling location and until the Drilling Unit is properly positioned at COMPANY’S next drilling location, and the Drilling Unit is ready to commence operations.

b) From the moment operations are commenced to release the first mooring line or move the Drilling Unit off

location at COMPANY’S final drilling location hereunder until this Contract terminates.

2.2.2 Operating Rate commences at the time of the Commencement Date, time the Drilling Unit is, properly positioned, anchors tested, if any, at drilling draft at the location to be drilled and the Drilling Unit is ready to commence operations and continues until CONTRACTOR has completed operations at the location and the Drilling Unit has been released by COMPANY to move to the next location pursuant to Article 2.2.1(a). 2.2.3 Stand-by Rate with Crews applies while the Drilling Unit is on location with full crews waiting for COMPANY’S orders, and shall be payable during any period of time when CONTRACTOR’S crew is aboard the Drilling Unit and drilling, testing or completion operations hereunder are suspended, as a result of COMPANY’S instructions, COMPANY’S failure to issue

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instructions, the mechanical failure of COMPANY’S items, or the failure of COMPANY to timely provide COMPANY’S items or furnish those services set forth in Exhibit B-3. 2.2.4 Stand-by Rate without Crews applies while the Drilling Unit is on location without crews. This rate shall commence seventy-two (72) hours after notification by COMPANY to CONTRACTOR to release crews. 2.2.5(a) Mechanical Downtime applies in the event operations during the term of this CONTRACT are shut down (“Mechanical Downtime”) for inspection, repair or replacement of any surface or subsurface equipment including, but not limited to CONTRACTOR’S items described in Exhibit B, including station keeping equipment, mooring equipment, anchors, chains, shackles, pendent lines, buoys, the riser, slip joint, choke and kill lines, flexible hoses, hydraulic hoses, guidelines, subsea BOP, and BOP control system. CONTRACTOR shall be allowed a maximum of twenty-four (24) hours per calendar month Mechanical Downtime with a maximum accumulation of twelve (12) days; thereafter the dayrate reduces to zero (0). Mechanical Downtime shall commence immediately upon suspension of well operations and shall continue until completion of the inspection, repair or replacement of the equipment and operations are at the point in well operations prior to suspension. If COMPANY elects to proceed with an alternative operation, then Mechanical Downtime shall cease at the point in well operations where the alternative operation commences. Article 2.2.5(a) shall not apply to the time required to repair or replace CONTRACTOR’S choke manifolds, blowout preventors, and drill string, if the damage or destruction to the equipment is caused by exposure to unusually corrosive or otherwise destructive elements not normally encountered which are introduced into the drilling fluid from subsurface formations or the use of corrosive additives in the fluid. Article 2.2.5(a) shall not apply to normal maintenance, including, without limitation, cutting and/or slipping the drill line, which time shall be limited to 1 hour plus up to thirty (30) minutes per day (fifteen (15) hours per month maximum) for top drive maintenance. Any mobilization and/or demobilization and associated cost required to repair the Drilling Unit under Article 2.2.5(a) will be at CONTRACTOR’S expense. CONTRACTOR shall not be entitled to any compensation for Mechanical Downtime allowance not consumed during this CONTRACT. 2.2.5(b) Performance Downtime applies in the event operations during the term of this CONTRACT are shut down (“Performance Downtime”) for the following reasons (i) CONTRACTOR, CONTRACTOR’S Personnel (as hereinafter defined), or the Drilling Unit should be incapable, incompetent, negligent, unreliable, or consistently poor in performance of the Work, (ii) the equipment listed in Exhibit B is incapable of being operated at the rated specifications in Exhibit B for sustained operation or (iii) CONTRACTOR fails to fulfill any of its obligations under this Contract. In the event of COMPANY’S dissatisfaction with any items identified in (i), (ii) and (iii), Performance Downtime shall commence when COMPANY provides CONTRACTOR with written notice as to the circumstances of its dissatisfaction and work in progress is suspended and shall continue based on the following remedies. If work in progress is suspended, then Article 2.2.5(a) shall apply. CONTRACTOR shall be allowed five (5) days, from the written notice, to commence good faith efforts to remedy such circumstances. During the remedy period, the Operating Rate shall be reduced to the Standby-rate Without

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Crews. In the event such circumstances are not remedied to COMPANY’S satisfaction within thirty (30) days, from the written notice, the Operating Rate shall be reduced to zero (0) dollars. 2.2.6 Hurricane Evacuation Rate applies when all of the crews have been transported to shore. This rate shall include the cost of room and board for all of CONTRACTOR’S personnel including catering personnel and any other of CONTRACTOR’S subcontractor personnel. If COMPANY elects to release CONTRACTOR’S crew, then the Standby Rate Without Crew shall be applicable from the time CONTRACTOR is notified by COMPANY until the CONTRACTOR’S crew returns to the Drilling Unit. 2.2.7 Stack Rate applies when the Drilling Unit has arrived and secured at the nearest safe harbor or stack location in the Gulf of Mexico as designated by CONTRACTOR. The Moving Rate shall apply immediately before the Stack Rate commences. The Stack Rate will continue until the unit is ready to get underway at which time the Moving Rate shall apply, or until the CONTRACT expires pursuant to Article 1. 2.3 ADJUSTMENTS IN DAYRATES 2.3.1 The dayrates set forth in Exhibit A shall remain unadjusted during the Initial Contract Term of this CONTRACT, except for rate changes as described in Article 2.3.2, Article 3, Article 4, Article 5, Article 6, and Article 30.3. 2.3.2 The dayrates set forth in Exhibit A shall be revised to reflect the change in costs from the Effective Date if the costs of any of the items hereafter listed shall vary in an amount equal to or greater than five percent (5%) from the costs thereof not earlier than the Commencement Date and not more frequent than one (1) year after the date of any revision pursuant to this Article 2.3.2.

a. Labor costs, including all benefits, of CONTRACTOR’S personnel listed in Exhibit F; b. CONTRACTOR’S cost of catering; c. CONTRACTOR’S cost of spare parts and supplies vary and that the parties shall use the United States

Department of Labor’s Producer Price Index Commodity Code No. 1191.02 - Oil Field and Gas Field Drilling Machinery - to determine what extent a price variance has occurred in said spare parts and supplies.

d. Cost of insurance not based solely on CONTRACTOR’S loss or claim record. CONTRACTOR must show documented proof for any dayrate adjustments due to changes in CONTRACTOR’S cost of labor, insurance or catering. CONTRACTOR shall provide COMPANY with the base figures for the items specified in Article 2.3.2a.,b.,c., and d., thirty (30) days after the Effective Date. Base figures from which such revisions (either upward or downward) will be determined for the items in this Article 2.3.2 shall be provided by CONTRACTOR sixty (60) days prior to the estimated Commencement Date. These base figures

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shall be agreed upon by both parties and approved in writing by COMPANY prior to the Commencement Date. 2.3.3 If, at the request of COMPANY, it becomes necessary for CONTRACTOR to change the work schedule of its personnel or change the location of its Homeport or area of operations, which impacts the CONTRACTOR’S actual cost, the daily rates set out in Appendix A shall be adjusted accordingly, with appropriate back up data. 2.3.4 CONTRACTOR shall be responsible for costs and expenses incurred by CONTRACTOR in complying with any law, regulation, or ruling of a government, governmental agency, or regulatory authority having jurisdiction over the operations of the Drilling Unit to the extent that the law, regulation, or ruling has changed or been imposed subsequent to the Commencement Date. Where compliance with the changed law, regulation, or ruling results in modifications of the Drilling Unit or the purchase of equipment which change CONTRACTOR’S cost, the dayrates shall be adjusted with the additional direct cost and expenses amortized over the life of the Drilling Unit. The increased dayrates shall become effective upon completion of the modifications, and the Drilling Unit commences operations. CONTRACTOR shall be solely responsible for mobilization and demobilization and associated cost; during such time the dayrate shall be zero (0) dollars. ARTICLE 3 PERSONNEL AND PAYMENTS 3.1 PERSONNEL CLASSIFICATIONS, NUMBERS AND REPRESENTATION 3.1.1 CONTRACTOR shall furnish, at its sole expense, personnel in the numbers and classifications as set forth in Exhibit F. 3.1.2 During any period of time that CONTRACTOR fails to provide on the Drilling Unit the numbers or classifications of personnel specified in Exhibit F, the rate being paid the CONTRACTOR shall be reduced by the overtime hourly rate for the absent crew member(s) as specified in Exhibit F. This reduced rate shall commence on the second day of the crew shortage. 3.1.3 The number of personnel to be furnished by CONTRACTOR under the terms hereof as specified in Exhibit F may be increased or decreased by mutual consent of COMPANY and CONTRACTOR, in which case the rates set forth in Article 2 shall be increased or decreased by an amount equal to the change in CONTRACTOR’S cost. 3.1.4 CONTRACTOR represents that all of CONTRACTOR’S personnel shall be fully qualified, trained, competent, able bodied and fit for their respective assignments and shall have complied with all necessary laws and regulations in connection therewith. The minimum standard for qualification and training is set forth in Exhibit F. CONTRACTOR shall be able to communicate verbally and in writing by means of a common language at all times.

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3.2 OVERTIME COMPENSATION 3.2.1 COMPANY shall pay CONTRACTOR for overtime work of personnel employed by CONTRACTOR who are required to work in excess of their regularly scheduled hours, when requested by COMPANY, at the rates specified in Exhibit F. 3.2.2 In the event the departure of the crews from the drilling site is delayed more than two (2) hours after the normal scheduled departure time due to delays in the transportation schedule which are not caused by the negligence or fault of CONTRACTOR, COMPANY shall pay CONTRACTOR for time in excess of two (2) hours at the hourly overtime rate for each employee as specified in Exhibit F. 3.2.3 In the event that the time of transportation of crews between the Drilling Unit and the shorebase or between the shorebase and Drilling Unit is in excess of two (2) hours for each one-way trip, which are not the result of the negligence or other fault of CONTRACTOR, COMPANY shall pay CONTRACTOR for time in excess of two (2) hours for each trip at the hourly overtime rate for each employee as specified in Exhibit F. ARTICLE 4 OTHER PAYMENTS 4.1 CHANGE IN HOMEPORT OF OPERATIONS The Homeport of operations for the Drilling Unit under this CONTRACT is any Gulf of Mexico port between and inclusive of Corpus Christi, TX and Pascagoula, MS. 4.2 EXCESS MEALS AND LODGINGS COMPANY shall pay CONTRACTOR for the cost of meals and lodging for COMPANY’S personnel and subcontractors (other than CONTRACTOR) that are in excess of ten (10) people per day calculated over a period of one (1) calendar month at CONTRACTOR’S actual cost. 4.3 ANCHOR HANDLING AND TOWING VESSEL CHARGES COMPANY shall pay all anchor handling and towing vessel charges if required, for movement of the Drilling Unit. 4.4 OTHER CHARGES COMPANY shall pay CONTRACTOR for other charges as per Article 6, Article 7, and Article 8.

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ARTICLE 5 DRILLING UNIT MODIFICATIONS 5.1 PRE-COMMENCEMENT Any modification to the Drilling Unit before the Commencement Date shall be pursuant to Exhibit H. 5.1.1 POST-COMMENCEMENT DATE Any modification to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In the event the Drilling Unit is taken out of service or placed into shelter or harbor for COMPANY requested modifications, the rate that shall be payable per day, or pro rata for any part of a day during which such activity occurs shall be Standby Rate, which shall be payable for the period of time beginning when the Drilling Unit ceases operations to move off the drilling or well location until it moves back to location and commences full operations; provided, however, that if the Drilling Unit has changed locations, CONTRACTOR shall be credited at the Moving Rate for the time that would otherwise have been spent moving to the new location. In such case, the related modification costs and harbor expenses including, but not limited to, customs or other duties or imposts, harbor tugs if required, demurrage, wharfage, harbor and port fees and dues, landing, pilotage, lighterage, stevedoring, customs agent fees, anchor handling, any tow in and out, fuel, and canal charges, if applicable will be paid by COMPANY in a mutually agreed adjustment to the daily rates ARTICLE 6 OTHER REIMBURSEMENTS 6.1 LICENSES AND PERMITS CONTRACTOR shall be responsible for all licenses, permits, or other authorization which are required to be obtained by CONTRACTOR subsequent to the Commencement Date. COMPANY agrees to reimburse CONTRACTOR for all cost associated with licenses, permits or other authorization which are required to be obtained by CONTRACTOR should COMPANY designate a location outside the federal waters of the Gulf of Mexico. COMPANY will obtain any required licenses, permits or authorizations which are required to be obtained by COMPANY.

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ARTICLE 7 MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES TO BE FURNISHED BY CONTRACTOR 7.1 MATERIALS, SUPPLIES, EQUIPMENT, & SERVICES 7.1.1 CONTRACTOR shall furnish and maintain at its sole expense all items designated in Exhibit B under the heading FURNISHED BY CONTRACTOR. Any additional items not specifically mentioned elsewhere in this CONTRACT and found necessary to perform work shall be furnished by COMPANY at its sole expense. 7.1.2 All items of equipment, materials, supplies, services, and service personnel required for operations hereunder that are to be FURNISHED BY CONTRACTOR as specified in Exhibit B may be furnished by COMPANY upon the mutual consent of COMPANY and CONTRACTOR and billed to CONTRACTOR at actual invoice cost less all cash discounts obtained by COMPANY plus a five (5) percent handling charge plus applicable taxes if taxes are applied to the cost reimbursement. A copy of invoice(s) for equipment, materials, supplies, services, and service personnel shall accompany COMPANY’S invoice to CONTRACTOR and must have the signature of CONTRACTOR’S representative for reimbursement to COMPANY. 7.1.3 All items of equipment, materials, supplies, services, and service personnel required for operations hereunder that are to be FURNISHED BY CONTRACTOR AND REIMBURSED BY COMPANY as specified in Exhibit B are to be billed to COMPANY at actual invoice cost less all cash discounts obtained by CONTRACTOR plus a five (5) percent handling charge. A copy of invoice(s) for equipment, materials, supplies, services, and service personnel shall accompany CONTRACTOR’S invoice to COMPANY and must have the signature of COMPANY’S representative’s for reimbursement to CONTRACTOR. 7.1.4 Any equipment, materials, or supplies purchased by COMPANY for the account of CONTRACTOR pursuant to Articles 7.1.2 and 7.1.3. above shall thereafter become the property of COMPANY unless agreed to by the Parties. 7.1.5 CONTRACTOR shall provide at CONTRACTOR’S expense a drill pipe and drill collar inspection in accordance with API-IADC Standards prior to the Commencement Date. All of the drill pipe and drill collars shall be new. The costs of subsequent drill pipe and drill collar inspections during the term of this CONTRACT shall be borne by the COMPANY or CONTRACTOR as provided in Exhibit B.

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ARTICLE 8 MATERIALS, SUPPLIES, EQUIPMENT, AND SERVICES TO BE FURNISHED BY COMPANY 8.1 MATERIALS, SUPPLIES, EQUIPMENT, & SERVICES 8.1.1 COMPANY shall furnish and maintain at its sole expense all items designated in Exhibit B hereof under the heading “FURNISHED BY VASTAR”. 8.1.2 All items of equipment, materials, supplies, services, and service personnel required for operations hereunder that are to be “FURNISHED BY VASTAR” as specified in Exhibit B may be furnished by CONTRACTOR upon the mutual consent of COMPANY and CONTRACTOR and billed to COMPANY at actual invoice cost less all cash discounts obtained by CONTRACTOR plus a five (5) percent handling charge plus applicable tax gross up if taxes are applied to the cost reimbursement. A copy of invoice(s) for equipment, materials, supplies, services, and service personnel shall accompany CONTRACTOR’S invoice to COMPANY and must have COMPANY’S representative’s signature for reimbursement to CONTRACTOR. 8.1.3 Any equipment, materials, or supplies purchased by CONTRACTOR for the account of COMPANY pursuant to Article 8.1.2 above shall thereafter become the property of COMPANY. ARTICLE 9 PAYMENTS 9.1 TIME OF PAYMENT COMPANY shall make payments under this CONTRACT in U.S. currency in accordance with the terms of Article 2, Article 3, Article 4, Article 5, Article 6, Article 7, and Article 8 of this CONTRACT, on or before the last working day of the month following the receipt of a valid invoice form CONTRACTOR if received within five (5) calendar days after the month being invoiced If COMPANY receives an invoice after five (5) calendar days from the end of the month being invoiced then the payment will be due twenty (20) working days after receipt of the invoice. Thereafter, valid and undisputed amounts remaining due and unpaid shall earn simple interest at the rate of one and one-half percent (1 1/2%) per month. Should COMPANY question any item of an invoice, COMPANY may withhold payment of the amount in question, without interest, until the matter is resolved between the Parties, but COMPANY shall pay promptly the amount not in question. COMPANY shall have the right to set off any undisputed and liquidated amount payable by COMPANY to CONTRACTOR under this CONTRACT or under any instrument executed in connection herewith against any amount payable by CONTRACTOR to COMPANY under this CONTRACT. 9.2 IDENTIFICATION OF CHARGES All invoices must reference charges by block name and number and well number (e.g., Viosca Knoll Blk. 1001 No. 1). OCS numbers or state numbers are not acceptable references.

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9.3 PLACE OF INVOICE PRESENTATION Invoices, accompanied by copies of the original vouchers or such records, receipts, or other evidence as may be requested by COMPANY to support the invoices rendered, shall be sent to COMPANY’S office in Houston, Texas at the address below on or before the tenth (10th) of each month next succeeding the month during which the Work was performed or the expense incurred. The invoices to COMPANY should be directed as follows:

Vastar Resources, Inc. P.O. Box 219275 Houston, TX 77218-9275 ATTN: DRILLING INVOICES

9.4 PLACE OF PAYMENT

All payments shall be directed to CONTRACTOR as follows: Wells Fargo Bank 1000 Louisiana Houston, TX 77002 Account Number ABA Number SWIFT Number

ARTICLE 10 PAYMENT OF CLAIMS 10.1 CLAIMS CONTRACTOR shall pay all claims for equipment, labor, materials, services, and supplies to be furnished by it hereunder and shall allow no lien or charge resulting from such claims to be fixed upon any well lease or other property of COMPANY. CONTRACTOR shall protect, release, defend, indemnify, and hold harmless COMPANY from and against all such claims and liens. COMPANY may, at its option, pay and discharge any (i) amounts secured by such liens or (ii) overdue charges for CONTRACTOR’S equipment, labor, materials, services, and supplies under this CONTRACT and may thereupon deduct the amount or amounts so paid by COMPANY from any sums due, or which thereafter become due, to CONTRACTOR hereunder. 10.2 NOTICE OF CLAIMS CONTRACTOR shall promptly give COMPANY notice in writing of any claim made or proceeding commenced against CONTRACTOR for which CONTRACTOR claims to be entitled to indemnification under this CONTRACT. CONTRACTOR shall confer with COMPANY concerning the defense of any such claim proceeding, shall permit COMPANY to be represented by counsel in defense thereof, and shall not effect settlement of, nor compromise, any such claim or proceeding without COMPANY’S written consent.

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COMPANY shall promptly give CONTRACTOR notice in writing of any claim made or proceeding commenced against COMPANY for which COMPANY claims to be entitled to indemnification under this CONTRACT. COMPANY shall confer with CONTRACTOR concerning the defense of any such claim proceeding, shall permit COMPANY to be represented by counsel in defense thereof, and shall not effect settlement of, nor compromise, any such claim or proceeding without CONTRACTOR’S written consent. ARTICLE 11 TAXES AND FEES 11.1 TAXES AND FEES ON DRILLING UNIT, CREW, AND OPERATIONS CONTRACTOR shall be responsible for, pay, and protect, release, defend, indemnify and hold harmless COMPANY from all taxes, including, income taxes of whatsoever kind, and any addition, penalty, interest, or similar item imposed with respect to such taxes, levies, customs charges, duties, fees, or other charges of whatsoever kind without contribution or indemnity from COMPANY whatsoever which may be levied by any national, territorial possession, state, provincial, local, or municipal government, authority, or other agency having jurisdiction over the Operating Area on, in connection with, or related to the Drilling Unit, its crew, its equipment, and any and all materials, equipment, or operations in performance of this CONTRACT. Notwithstanding any other provision of this CONTRACT, COMPANY shall bear ultimate liability for any end user taxes such as, but not limited to, value added taxes and sales taxes imposed on COMPANY or which CONTRACTOR is required by law to collect. COMPANY and CONTRACTOR will make payments in accordance with the laws and regulations governing these taxes. 11.2 PAYROLL TAXES CONTRACTOR shall make all necessary reports and pay all taxes, licenses, and fees levied or assessed on CONTRACTOR in connection with or incident to the performance of this CONTRACT by any governmental agency having jurisdiction over the Operating Area for unemployment compensation insurance, old age benefits, social security, or any other taxes upon the wages or salaries paid by CONTRACTOR, its agents, employees, and representatives. CONTRACTOR shall require the same agreement of, and be liable for any breach of the agreement by, any of its subcontractors. 11.3 TAXES PAID BY COMPANY CONTRACTOR shall reimburse COMPANY on demand for all the taxes or governmental charges, state or federal, outlined in Articles 11.1 and 11.2, which COMPANY may be required or deems necessary to pay on account of CONTRACTOR or its employees or subcontractors. At its election, COMPANY is authorized to deduct all sums so paid for the taxes and governmental charges from any money due CONTRACTOR hereunder and provide official tax receipts within sixty (60) days.

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ARTICLE 12 COMPANY’S RIGHT TO QUESTION INVOICES AND AUDIT 12.1 QUESTION INVOICES Payment of any invoice shall not prejudice the right of COMPANY to question the propriety of any charges therein, provided that COMPANY, within four (4) years after the date of the invoice in question, shall deliver to CONTRACTOR written notice of objections to any item or items, the propriety of which it questions, specifying the reasons for the objections. Should COMPANY so notify CONTRACTOR, adjustments shall be made as the propriety or impropriety of the item may be mutually determined. 12.2 AUDIT CONTRACTOR shall maintain a complete and correct set of records pertaining to all aspects of this CONTRACT, including the performance hereof by CONTRACTOR. If any payment provided for hereunder is to be made on the basis of CONTRACTOR’S cost, COMPANY shall have the Drilling Unit to inspect and audit any and all records relating to the cost any time during the term of this CONTRACT and up to a period of four (4) years after the recorded date of the record in question, provided that CONTRACTOR shall have the right to exclude any trade secrets, formulas, or processes from the inspection and audit. Should the results of any audit so require, the Parties will make appropriate adjustments or payments. ARTICLE 13 DEPTH 13.1 DEPTH The depth of each well to be drilled hereunder will be specified by COMPANY, which COMPANY may amend from time to time. The depth so specified is hereinafter referred to as the “Contract Depth”, subject to the right of COMPANY to direct, at any time, a stoppage of Work at a lesser depth. ARTICLE 14 DRILLING UNIT 14.1 REPRESENTATION OF DRILLING UNIT The Drilling Unit shall be fully equipped as specified in Exhibit B and shall meet the requirements of Exhibit G, and shall be adequate to drill and complete wells in the Operating Area to the depths as specified in Article 14.2 hereof and in water depths as specified in Article l4.3. CONTRACTOR represents that the Drilling Unit satisfies all requirements of Articles 14.1.1, 14.4 and 14.6, and is capable of operating to its full capacity as rated by the

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manufacturer. CONTRACTOR shall maintain the Drilling Unit at optimal operating condition, in accordance with good oilfield practices throughout the duration of the CONTRACT. 14.1.1 CONTRACTOR represents that (i) the Drilling Unit and related equipment shall be in a condition to permit its continuous and efficient operation during the Contract Period, subject to required periods of maintenance, repair, drydocking and inspection by regulatory bodies and classification societies, (ii) it will diligently perform the Work in a good workmanlike manner consistent with applicable industry standards and practices, (iii) it will use sound technical principles where applicable, (iv) it will perform the Work in compliance with this Contract, (v) it will furnish material and equipment in good condition to sufficiently meet the applicable CONTRACT requirements and good oilfield practices and (vi) where mutually agreed, it will furnish used material and equipment, fit for the intended use. CONTRACTOR shall bear any cost incurred in placing the Drilling Unit in a condition to function continuously and efficiently during the entire Contract Period. CONTRACTOR agrees to ensure that the Drilling Unit and all equipment and materials furnished by CONTRACTOR are adequately maintained and in such condition as to permit their continuous and efficient operation. CONTRACTOR shall appropriately protect and secure all COMPANY’S equipment and materials placed in its care. CONTRACTOR also agrees to carry out visual inspection on, and make available to COMPANY to test any of CONTRACTOR’S equipment in the manner prescribed by COMPANY. Notwithstanding the foregoing, CONTRACTOR shall carry out, at CONTRACTOR’S expense, a full and detailed inspection of its drill pipe, drill collars, bottom hole assemblies and other down-hole and surface drilling equipment in accordance with Exhibit B prior to commencing the Work. COMPANY reserves the right to ensure that such inspection is carried out satisfactorily and, accordingly, shall have access to all related inspection reports. CONTRACTOR shall give COMPANY three weeks notice of inspection in order that COMPANY may have a third person witness the inspections to ensure they are carried out in accordance with Exhibit G. 14.1.2 COMPANY shall have the right before the Commencement Date to inspect and reject for sound reasons any part of the Drilling Unit not meeting the requirements of this Contract; provided, however, such right shall not in any way relieve CONTRACTOR of its own obligations, including, without limitation, the obligation to inspect and maintain the Drilling Unit and related equipment in efficient operating condition. COMPANY shall have access and the right to review all commissioning, testing, and acceptance documents pertaining to the Drilling Unit. Unless waived by COMPANY, the Commencement Date shall not occur prior to the date on which CONTRACTOR has satisfactorily remedied any defect. 14.2 MAXIMUM DRILLING DEPTH RATING CONTRACTOR represents that the Drilling Unit is mechanically capable of drilling wells to the depth specified in Exhibit B-1. 14.3 MAXIMUM WATER DEPTH RATING CONTRACTOR represents that the Drilling Unit is mechanically capable of drilling wells in water depths and during environmental conditions, as specified in Exhibit B-I.

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14.4 TECHNOLOGY CONTRACTOR and COMPANY agree to explore the latest technologies, including riserless drilling, in an effort to incorporate same into the construction and operation of the Drilling Unit. CONTRACTOR shall make such technology available to COMPANY as soon as CONTRACTOR has the right to install and use such technology on its commercial drilling units, subject to any existing third party contracts as of the Commencement Date. Such installation shall be done pursuant to Article 5. 14.5 APPLICABLE LAWS Subject to Article 2.3.4, CONTRACTOR represents that during the Contract Period, the Drilling Unit is outfitted, conformed, and equipped to meet all applicable laws, rules, requirements, and regulations promulgated by the U.S. Coast Guard, the U.S. Environmental Protection Agency, the United States of America Department of the Interior as well as any other agency, bureau, or department of the U.S. federal, territorial possession, state, municipal, or local governments, any political subdivisions thereof, having jurisdiction over the operations in U. S. federal waters. 14.6 SAFETY OF PORT COMPANY does not and shall not be deemed to warrant the safety of any port, place, berth, dock, anchorage, location, or submarine line and shall be under no liability in respect thereof, except as specifically provided for under Article 31. 14.7 OPERATING AREA The Drilling Unit shall be capable of operating year around in the federal waters of the U. S. Gulf of Mexico. Additionally, the Drilling Unit will be designed to allow for operations in other areas of U. S. federal waters, offshore West Africa and the United Kingdom and other areas of the world, all subject to modifications and outfitting required by the controlling jurisdictions of each different operating area and to the operating limits set forth in Exhibit “G”. ARTICLE 15 PERFORMANCE OF DRILLING OPERATIONS 15.1 OPERATIONS OF DRILLING UNIT CONTRACTOR shall be solely responsible for the operation of the Drilling Unit, including, without limitation, supervising moving operations, and the positioning of the Drilling Unit on drilling locations as required by COMPANY, as well as such operations on board the Drilling Unit as may be necessary or desirable for the safety of the Drilling Unit. 15.2 PREVENTION OF FIRE AND BLOWOUTS CONTRACTOR shall maintain well control equipment in accordance with good oilfield practices at all times and shall use all reasonable means to control and prevent fire and blowouts and to protect the hole and all other property of the COMPANY. CONTRACTOR shall use the blowout prevention equipment specified in Exhibit B hereof on all strings of casing unless otherwise directed by COMPANY. CONTRACTOR shall pressure test the blowout prevention

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devices as often as instructed by COMPANY, usually once every seven (7) days, and shall function test the blowout prevention devices by opening and closing to assure operating condition at each trip for a bit change. CONTRACTOR shall record the results of all the tests on the Daily Drilling Report Form defined in Section 19.1 hereof. CONTRACTOR shall use kelly sub protectors and drill pipe protectors. In any event, CONTRACTOR, at a minimum, shall use, test, and maintain blowout prevention equipment in accordance with all applicable governmental rules, regulations, and orders then in effect. 15.3 DEVIATION OF THE HOLE CONTRACTOR shall use precaution in accordance with good oilfield practices in the Area of Operations, to drill a hole which will not deviate excessively from the limits specified by COMPANY. CONTRACTOR shall run angle and directional measuring devices acceptable to, and at the intervals directed by COMPANY. CONTRACTOR shall record the results of the deviation survey on the Daily Drilling Report Form. 15.4 DRILL PIPE MEASUREMENT CONTRACTOR shall measure the total length of drill pipe in service with a steel tape before setting casing or liner, before logging, after reaching final depth, and whenever requested by COMPANY and shall promptly enter all the measurements on the Daily Drilling Report Form. 15.5 CASING PROGRAM The casing program shall be as specified by COMPANY. 15.6 MUD PROGRAM CONTRACTOR shall use all reasonable care to make and maintain drilling mud having weight, viscosity, water loss, and other characteristics to satisfy the requirements as specified by COMPANY. CONTRACTOR shall exercise due diligence to prevent the well from blowing out, and to enable the efficient drilling, logging, and testing of all formations without caving or formation contamination. While drilling, CONTRACTOR shall test drilling mud for weight, viscosity, water loss, and other necessary characteristics as instructed by COMPANY and shall record the results of the tests and the material volume usage on the Daily Drilling Report Form. 15.7 COMPLETION OR ABANDONMENT OF WELLS CONTRACTOR shall perform all work necessary to tube, equip, and complete or abandon each well in the manner specified by COMPANY. 15.8 SAMPLES CONTRACTOR shall save and preserve for COMPANY samples of formations penetrated, and properly prepare and label COMPANY’S containers. COMPANY shall designate the sampling frequency. 15.9 CORING CONTRACTOR shall core at the depths which COMPANY shall specify and shall deliver all cores in COMPANY’S containers, properly labeled, to COMPANY and shall not allow any third

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person access to the cores or to the samples referred to in Article 15.8, or to any core or sample data, without COMPANY’S consent. 15.10 FORMATION TESTS If during the course of drilling CONTRACTOR encounters evidence of oil or gas, or other hydrocarbon substances, then CONTRACTOR shall immediately notify COMPANY, and should COMPANY desire a test to determine the productivity of any formation so encountered then, CONTRACTOR shall make such a test if it is feasible under existing conditions. 15.11 ANCHOR HANDLING AND TOWING COMPANY shall supply any required anchor handling and towing vessels to move the Drilling Unit between locations. ARTICLE 16 INSPECTION OF MATERIALS 16.1 INSPECTION BY CONTRACTOR CONTRACTOR shall carefully perform a visual inspection of all materials and appliances furnished by COMPANY when delivered into CONTRACTOR’S possession and shall notify COMPANY’S representative of any apparent defects so that COMPANY may replace the defective materials or appliances. Upon the termination of this CONTRACT, CONTRACTOR shall return to COMPANY all materials and appliances received by CONTRACTOR from COMPANY or purchased by CONTRACTOR for COMPANY’S account then in CONTRACTOR’S possession. 16.2 INSPECTION BY COMPANY Excluding the Drilling Unit and its major equipment, COMPANY shall have the right to inspect and reject, for any valid cause, any items furnished by CONTRACTOR in Exhibit B-3. CONTRACTOR at its sole cost, risk and expense shall replace and/or repair the rejected items, or replace them with items free of defects. ARTICLE 17 SAFETY 17.1 GENERAL CONTRACTOR shall have the primary responsibility for the safety of all its operations, shall take all measures necessary or proper to protect the personnel and facilities and, in addition, shall observe all safety rules and regulations of any governmental agency having jurisdiction over operations conducted hereunder. CONTRACTOR shall place the highest priority on safety while performing the work. CONTRACTOR shall also observe all of COMPANY’S safety rules and guidelines as set forth in “Safety and Health Manual” of Vastar Resources, Inc., and the requirements contained in Exhibit D. The CONTRACTOR may also have its own safety manual

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and when CONTRACTOR’S and COMPANY’S safety manuals conflict, CONTRACTOR’S safety manual shall control. 17.2 UNDER TOW At all times during movement of the Drilling Unit between locations, CONTRACTOR shall have full responsibility for control of the Drilling Unit and shall have final authority regarding the safety and operation of the Drilling Unit, associated equipment, and personnel on board. 17.3 SAFETY EQUIPMENT CONTRACTOR shall furnish any needed personal protection equipment that CONTRACTOR’S personnel may require in order to safely perform CONTRACTOR’S obligations under this CONTRACT. 17.4 EMERGENCY EVACUATION PLAN The CONTRACTOR shall furnish COMPANY with information regarding the Emergency Evacuation Plan (“EEP”) for the CONTRACTOR’S Drilling Unit. The information supplied shall include station bills, a list of fire fighting equipment, list of emergency crafts onboard, and all other information required to describe the EEP in order to meet federal regulations in 46 C.F.R. 109 for MODU’s. The COMPANY shall submit as part of the COMPANY’S EEP, information and/or data as required by 33 C.F.R. 146.2 10. ARTICLE 18 PERFORMANCE OF THE WORK 18.1 INDEPENDENT CONTRACTOR RELATIONSHIP In performing the work set forth in this CONTRACT, CONTRACTOR shall act at all times as an independent contractor. Unless otherwise mutually agreed, CONTRACTOR shall not make any commitment or incur any charges or expense in the name of COMPANY. CONTRACTOR expressly agrees, acknowledges and stipulates that neither this CONTRACT nor the performance of CONTRACTOR’S obligations or duties hereunder shall ever result in CONTRACTOR, or anyone employed by CONTRACTOR, being i) an employee, agent, servant, or representative of COMPANY, or ii) entitled to any benefits from COMPANY, including without limitation, pension, profit sharing or accident, health, medical, life or disability insurance benefits or coverage, to which employees of COMPANY may be entitled. The sole and only compensation to which CONTRACTOR shall be entitled to under this CONTRACT are the payments provided for herein. COMPANY shall have no direction or control of CONTRACTOR or its employees and agents except in the results to be obtained. The actual performance and superintendence of all work hereunder shall be by CONTRACTOR, but the work shall meet the approval of COMPANY and be subject to the general right of inspection herein provided in order for COMPANY to secure the satisfactory completion of the work. 18.2 COMPANY’S REPRESENTATIVE COMPANY shall be entitled to designate a representative(s), who shall at all times have complete access to the Drilling Unit for the purpose of observing or inspecting operations

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performed by CONTRACTOR in order to determine whether, in COMPANY’S sole opinion, CONTRACTOR has complied with the terms and conditions of this CONTRACT. The representative(s) shall be empowered to act for COMPANY in all matters relating to CONTRACTOR’S daily performance of the work. CONTRACTOR shall cooperate at all times with and render reasonable assistance to the representative(s) of COMPANY or representative(s) of any of COMPANY’S other contractor(s). 18.3 DISCIPLINE CONTRACTOR shall maintain at all times strict discipline and good order among its employees. Should COMPANY determine, for just cause, that the conduct of any of CONTRACTOR’S personnel is detrimental to COMPANY’S interest, COMPANY shall notify CONTRACTOR in writing of the reasons for requesting removal of such personnel and CONTRACTOR shall replace the personnel at CONTRACTOR’S expense. 18.4 TAKEOVER BY COMPANY In the event that CONTRACTOR shall fail to take proper steps to supply properly skilled workmen or tools, machinery or appliances for the performance of the work on any well hereunder, or shall otherwise neglect or willfully discontinue or delay commencement of the work to be performed on any such well, for a period of five (5) consecutive days after notice by COMPANY, then COMPANY shall have the right, by giving CONTRACTOR notice of its intention to do so, to take possession of the well, and the supervision and control of the drilling equipment and tools, machinery and appliances of CONTRACTOR and drill the well to completion or otherwise complete the work on said well. CONTRACTOR shall continue to have custody of and be solely responsible for its Drilling Unit and the locating and maintaining of it, and COMPANY or its representatives shall have supervision and control of such facilities only to the extent of the drilling or other operations involved. Following any such taking of possession by COMPANY, whether COMPANY is successful or unsuccessful in completing the well, or restoring same to production, the actual incremental cost directly related to the assumed operations to COMPANY (with no allowance to CONTRACTOR, other than dayrate, for the use of its drilling equipment and tools, machinery and appliances), shall be deducted from the applicable dayrate during such period and the balance, if any, paid to CONTRACTOR. COMPANY shall be liable for the return of such drilling equipment and tools, machinery and appliances to CONTRACTOR in as good condition as when received, natural wear and weathering, accidental loss or breakage excepted. COMPANY SHALL INDEMNIFY, DEFEND AND HOLD CONTRACTOR HARMLESS FROM AND AGAINST ANY AND ALL LOSS, COST, CLAIM OR CAUSE OF ACTION ARISING DIRECTLY OR INDIRECTLY FROM COMPANY’S SUPERVISION OF CONTRACTOR’S DRILLING EQUIPMENT AND TOOLS DURING THAT PERIOD OF TIME IN WHICH COMPANY HAS TAKEN OVER SUPERVISION AND CONTROL OF CONTRACTOR’S DRILLING EQUIPMENT AND TOOLS. THE LIABILITY PROVISIONS HEREOF AND CONTRACTOR’S INDEMNITY OBLIGATIONS HEREUNDER SHALL REMAIN IN FULL FORCE AND EFFECT AS TO ANY AND ALL DAMAGE, LOSS, COST, CLAIM OR CAUSE OF ACTION

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ARISING DIRECTLY OR INDIRECTLY PRIOR TO COMPANY’S TAKEOVER OF CONTRACTOR’S DRILLING EQUIPMENT AND TOOLS OR AFTER SUCH DRILLING EQUIPMENT AND TOOLS ARE RETURNED TO THE POSSESSION OF CONTRACTOR. During such a takeover, COMPANY shall obtain insurance coverage with the same coverages as the insurance required to be carried by CONTRACTOR, naming CONTRACTOR and endorsed to waive subrogation. 18.5 CHANGE OF SUPERVISORY PERSONNEL CONTRACTOR shall notify OPERATOR of any proposed change in supervisory personnel prior to the proposed change. ARTICLE 19 RECORDS TO BE FURNISHED BY CONTRACTOR 19.1 DAILY DRILLING REPORTS CONTRACTOR shall keep and furnish to COMPANY one (1) copy of the Daily Drilling Report Form showing the depth of the hole, formation penetrated, and any other data required by COMPANY or governmental authority. CONTRACTOR shall supply the report on the standard API-IADC Report Form. When CONTRACTOR prepares such form, it shall be referred to as the “Daily Drilling Report Form”.

19.2 ACCIDENT REPORTS CONTRACTOR shall report to COMPANY, as soon as possible, all accidents or occurrences resulting in injuries to CONTRACTOR’S employees or to any third parties, as well as any damage to property of third persons, arising out of or during the course of operations of CONTRACTOR or its subcontractors. CONTRACTOR shall furnish COMPANY with a copy of all reports made by CONTRACTOR to its insurer or to others as requested by COMPANY of the accidents and occurrences. 19.3 DELIVERY TICKETS CONTRACTOR shall furnish to COMPANY delivery tickets covering any materials or supplies furnished to CONTRACTOR by vendors for which COMPANY is obligated to reimburse CONTRACTOR. These shall be turned in to COMPANY’S representative as received with the Daily Drilling Report Form. The quantity, description, and condition of materials and supplies so furnished shall be verified and checked by CONTRACTOR. The delivery tickets shall be properly certified as to receipt by CONTRACTOR and must have COMPANY’S representative’s signature for reimbursement to CONTRACTOR. 19.4 LOGS CONTRACTOR shall diligently maintain navigational logs, equipment maintenance, and testing logs, and such other logs and documentation designated by COMPANY. Any maintained log or documentation shall not create any additional burden on CONTRACTOR that is not already required elsewhere in this CONTRACT. CONTRACTOR shall provide a copy of any log upon COMPANY’S request.

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ARTICLE 20 INSURANCE 20.1 INSURANCE Without limiting the indemnity obligation or liabilities of CONTRACTOR or its insurer, at all times during the term of this CONTRACT, CONTRACTOR shall maintain insurance covering the operations to be performed under this CONTRACT as set forth in Exhibit C. ARTICLE 21 INDEMNITY FOR PERSONAL INJURY OR DEATH 21.1 CONTRACTOR’S PERSONNEL CONTRACTOR SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS COMPANY FROM AND AGAINST ALL CLAIMS, DEMANDS AND CAUSES OF ACTION ASSERTED BY CONTRACTOR, CONTRACTOR’S SUBSIDIARIES AND AFFILIATED COMPANIES, CONTRACTORS OF ANY SUCH PARTIES, AND THEIR RESPECTIVE OFFICERS, DIRECTORS, AGENTS, INVITEES, EMPLOYEES AND ANY OF THEIR RELATIVES FOR PERSONAL INJURY (INCLUDING BODILY INJURY), ILLNESS, OR DEATH, THAT ARISE OUT OF OR ARE RELATED TO WORK PERFORMED HEREUNDER. 21.2 COMPANY’S PERSONNEL COMPANY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS CONTRACTOR FROM AND AGAINST ALL CLAIMS, DEMANDS AND CAUSES OF ACTION ASSERTED BY COMPANY, COMPANY’S SUBSIDIARIES, CO-OWNERS AND JOINT VENTURERS (IF ANY), CONTRACTORS OF ANY SUCH PARTIES (EXCEPT CONTRACTOR, AS SET FORTH IN ARTICLE 21.1 HEREOF), AND THEIR RESPECTIVE OFFICERS, DIRECTORS, AGENTS, INVITEES, EMPLOYEES AND ANY OF THEIR RELATIVES FOR PERSONAL INJURY (INCLUDING BODILY INJURY), ILLNESS, OR DEATH, THAT ARISE OUT OF OR ARE RELATED TO WORK PERFORMED HEREUNDER. ARTICLE 22 RESPONSIBILITY FOR LOSS OF OR DAMAGE TO THE EQUIPMENT 22.1 CONTRACTOR’S DRILLING UNIT EXCEPT AS SPECIFICALLY PROVIDED FOR IN ARTICLE 22.3, CONTRACTOR SHALL ASSUME ALL RISK OF LOSS OF OR DAMAGE TO AND SHALL PROTECT,

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RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS COMPANY FROM AND AGAINST ANY AND ALL CLAIMS FOR LOSS OF OR DAMAGE TO (INCLUDING SALVAGE OR REMOVAL COSTS) ITS DRILLING UNIT AND EQUIPMENT. FOR PURPOSES OF THIS ARTICLE 22, ALL EQUIPMENT BELONGING TO CONTRACTOR’S PARENT, SUBSIDIARIES, AFFILIATES, SUBCONTRACTORS, PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS SHALL BE CONSIDERED TO BE CONTRACTOR’S EQUIPMENT. 22.2 USE OF CONTRACTOR’S EQUIPMENT COMPANY shall have unrestricted right to use all of CONTRACTOR’S equipment provided under this CONTRACT during such times as COMPANY or both COMPANY and CONTRACTOR are engaged in bringing a well being drilled under this CONTRACT under control, provided however, that such use, in CONTRACTOR’S sole opinion, does not endanger CONTRACTOR’S personnel or the Drilling Unit. 22.3 CONTRACTOR’S IN HOLE-EQUIPMENT COMPANY SHALL ASSUME ALL RISK OF LOSS OF OR DAMAGE TO CONTRACTOR’S IN-HOLE, SUBSEA AND MOORING EQUIPMENT WHEN THE EQUIPMENT IS IN THE HOLE OR IN USE BELOW THE SURFACE OF THE WATER TO THE EXTENT CONTRACTOR’S INSURANCE DOES NOT COMPENSATE CONTRACTOR, REGARDLESS OF WHEN OR HOW THE DESTRUCTION OR DAMAGE OCCURS, UNLESS SAID LOSS OF OR DAMAGE IS A RESULT OF CONTRACTOR’S SOLE NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT, IN WHICH CASE CONTRACTOR IS SOLELY RESPONSIBLE FOR ALL LOSS OF OR DAMAGE. FOR PURPOSES OF THIS SECTION 22.3, ALL EQUIPMENT BELONGING TO CONTRACTOR’S SUBCONTRACTORS, PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS SHALL BE CONSIDERED TO BE CONTRACTOR’S EQUIPMENT. COMPANY’S RESPONSIBILITY FOR LOSS OF CONTRACTOR’S INHOLE, SUBSEA AND MOORING EQUIPMENT IS LIMITED TO CONTRACTOR’S CIF REPLACEMENT COST LESS DEPRECIATION AT THE RATE OF THREE-FOURTHS OF ONE PERCENT (0.75%) PER MONTH OF USE UNDER THIS CONTRACT. COMPANY SHALL ASSUME THE RISK OF LOSS FOR AND PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS CONTRACTOR FOR DAMAGE TO OR DESTRUCTION OF CONTRACTOR’S CHOKE MANIFOLDS, BLOWOUT PREVENTORS, AND DRILL STRING CAUSED BY EXPOSURE TO UNUSUALLY CORROSIVE OR OTHERWISE DESTRUCTIVE ELEMENTS NOT NORMALLY ENCOUNTERED WHICH ARE INTRODUCED INTO THE DRILLING FLUID FROM SUBSURFACE FORMATIONS OR THE USE OF CORROSIVE ADDITIVES IN THE FLUID, UNLESS SAID LOSS OF OR DAMAGE IS A RESULT OF CONTRACTOR’S NEGLIGENCE, GROSS NEGLIGENCE OR WILLFUL MISCONDUCT IN WHICH CASE CONTRACTOR IS SOLELY RESPONSIBLE FOR ALL LOSS OR DAMAGE.

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22.4 COMPANY’S EQUIPMENT COMPANY SHALL ASSUME THE RISK OF LOSS FOR AND PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FROM AND AGAINST ANY AND ALL CLAIMS FOR LOSS OF OR DAMAGE TO COMPANY’S EQUIPMENT AND PROPERTY. FOR THE PURPOSE OF THIS ARTICLE 22 ONLY, ALL EQUIPMENT AND PROPERTY BELONGING TO COMPANY’S PARENT, SUBSIDIARIES, AFFILIATES, CONTRACTORS (OTHER THAN CONTRACTOR) SUBCONTRACTORS, PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS SHALL BE CONSIDERED TO BE COMPANY’S EQUIPMENT. 22.5 RESPONSIBILITY DURING MOBILIZATION FROM KOREA CONTRACTOR SHALL ASSUME FULL RESPONSIBILITY FOR AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS COMPANY AND ITS’ JOINT OWNERS HARMLESS FROM AND AGAINST ANY LOSS, CLAIM, DAMAGE, FINE, PENALTY, DEMAND OR LIABILITY, FOR POLLUTION OR PROPERTY DAMAGE, WITHOUT MONETARY LIMITATIONS, MADE BY ANY ENTITY OR PERSON WHILE THE DRILLING UNIT IS MOBILIZING FROM KOREA TO THE GULF OF MEXICO PRIOR TO THE COMMENCMENT DATE. ARTICLE 23 LOSS OF HOLE OR RESERVOIR 23.1 LOSS OR DAMAGE TO THE HOLE SHOULD THE HOLE BE LOST OR DAMAGED, THE LOSS OR DAMAGE WILL BE BORNE BY COMPANY AND COMPANY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FROM AND AGAINST ALL CLAIMS FOR LOSS OF OR DAMAGE TO THE HOLE. NOTWITHSTANDING THE PREVIOUS SENTENCE, IF THE HOLE IS LOST OR DAMAGED DUE TO CONTRACTOR’S NEGLIGENCE, GROSS NEGLIGENCE, WILLFUL MISCONDUCT OR ITS AGENTS’, OR SUBCONTRACTORS OR THEIR FAILURE TO COMPLY WITH COMPANY’S INSTRUCTIONS, THEN AS CONTRACTOR’S SOLE LIABILITY, CONTRACTOR SHALL BE OBLIGATED AT COMPANY’S ELECTION TO REDRILL THE HOLE TO THE POINT AT WHICH THE HOLE WAS LOST AT EIGHTY PERCENT (80%) OF THE OPERATING RATE BUT OTHERWISE SUBJECT TO THIS DRILLING CONTRACT. 23.2 COST OF CONTROL OF BLOWOUT OR CRATER IN THE EVENT ANY WELL BEING DRILLED HEREUNDER SHALL BLOWOUT, CRATER OR CONTROL BE LOST FROM ANY CAUSE, COMPANY SHALL BEAR THE ENTIRE COST AND EXPENSE OF KILLING THE WELL OR OF OTHERWISE BRINGING THE WELL UNDER CONTROL AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FROM AND

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AGAINST ALL CLAIMS, SUITS, DEMANDS, AND CAUSES OF ACTION FOR COSTS ACTUALLY INCURRED IN CONTROLLING THE WELL. 23.3 UNDERGROUND DAMAGE COMPANY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS CONTRACTOR FOR ANY AND ALL CLAIMS ON ACCOUNT OF (I) INJURY TO, DESTRUCTION OF, LOSS, OR IMPAIRMENT OF ANY PROPERTY RIGHT IN OR TO OIL, GAS, OR OTHER MINERAL SUBSTANCES OR WATER, IF AT THE TIME OF THE ACT OR OMISSION CAUSING THE INJURY, DESTRUCTION, LOSS, OR IMPAIRMENT, THE SUBSTANCE HAD NOT BEEN REDUCED TO PHYSICAL POSSESSION ABOVE THE SURFACE OF THE EARTH, OR (II) ANY LOSS OR DAMAGE TO ANY FORMATION, STRATA, OR RESERVOIR BENEATH THE SURFACE OF THE EARTH. ARTICLE 24 POLLUTION 24.1 CONTRACTOR RESPONSIBILITY CONTRACTOR SHALL ASSUME FULL RESPONSIBILITY FOR AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD COMPANY AND ITS JOINT OWNERS HARMLESS FROM AND AGAINST ANY LOSS, DAMAGE, EXPENSE, CLAIM, FINE, PENALTY, DEMAND, OR LIABILITY FOR POLLUTION OR CONTAMINATION, INCLUDING CONTROL AND REMOVAL THEREOF, ORIGINATING ON OR ABOVE THE SURFACE OF THE LAND OR WATER, FROM SPILLS, LEAKS, OR DISCHARGES OF FUELS, LUBRICANTS, MOTOR OILS, PIPE DOPE, PAINTS, SOLVENTS, BALLAST, AIR EMISSIONS, BILGE SLUDGE, GARBAGE, OR ANY OTHER LIQUID OR SOLID WHATSOEVER IN POSSESSION AND CONTROL OF CONTRACTOR AND WITHOUT REGARD TO NEGLIGENCE OF ANY PARTY OR PARTIES AND SPECIFICALLY WITHOUT REGARD TO WHETHER THE SPILL, LEAK, OR DISCHARGE IS CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE OR OTHER FAULT OF COMPANY, ITS CONTRACTORS, (OTHER THAN CONTRACTOR) PARTNERS, JOINT VENTURERS, EMPLOYEES, OR AGENTS. IN ADDITION TO THE ABOVE, CONTRACTOR TO A LIMIT OF FIFTEEN MILLION DOLLARES (US$ 15,000,000.00) PER OCCURANCE, SHALL RELEASE INDEMNIFY AND DEFEND COMPANY FOR CLAIMS FOR LOSS OR DAMAGE TO THIRD PARTIES ARISING FROM POLLUTION IN ANY WAY CAUSED BY THE DRILLING UNIT WHILE IT IS OFF THE DRILLING LOCATION, WHILE UNDERWAY OR DURING DRIVE OFF OR DRIFT OFF FROM THE DRILLING LOCATION. 24.2 COMPANY RESPONSIBILITY COMPANY SHALL ASSUME FULL RESPONSIBILITY FOR AND SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD CONTRACTOR HARMLESS FROM AND AGAINST ANY LOSS, DAMAGE, EXPENSE, CLAIM, FINE, PENALTY,

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DEMAND, OR LIABILITY FOR POLLUTION OR CONTAMINATION, INCLUDING CONTROL AND REMOVAL THEREOF, ARISING OUT OF OR CONNECTED WITH OPERATIONS UNDER THIS CONTRACT HEREUNDER AND NOT ASSUMED BY CONTRACTOR IN ARTICLE 24.1 ABOVE, WITHOUT REGARD FOR NEGLIGENCE OF ANY PARTY OR PARTIES AND SPECIFICALLY WITHOUT REGARD FOR WHETHER THE POLLUTION OR CONTAMINATION IS CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE OR FAULT OF CONTRACTOR. 24.3 CLEAN UP OPERATIONS Initiation of clean up operations by either Party shall not be an admission or assumption of liability by such initiating Party or Parties. ARTICLE 25 INDEMNITY OBLIGATION 25.1 INDEMNITY OBLIGATION EXCEPT TO THE EXTENT ANY SUCH OBLIGATION IS SPECIFICALLY LIMITED TO CERTAIN CAUSES ELSEWHERE IN THIS CONTRACT, THE PARTIES INTEND AND AGREE THAT THE PHRASE “SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY AND HOLD HARMLESS” MEANS THAT THE INDEMNIFYING PARTY SHALL PROTECT, RELEASE, DEFEND, INDEMNIFY, AND HOLD HARMLESS THE INDEMNIFIED PARTY OR PARTIES FROM AND AGAINST ANY AND ALL CLAIMS, DEMANDS, CAUSES OF ACTION, DAMAGES, COSTS, EXPENSES (INCLUDING REASONABLE ATTORNEYS FEES), JUDGMENTS AND AWARDS OF ANY KIND OR CHARACTER, WITHOUT LIMIT AND WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF, INCLUDING PREEXISTING CONDITIONS, WHETHER SUCH CONDITIONS BE PATENT OR LATENT, THE UNSEAWORTHINESS OF ANY VESSEL OR VESSELS (INCLUDING THE DRILLING UNIT), BREACH OF REPRESENTATION OR WARRANTY, EXPRESSED OR IMPLIED, BREACH OF CONTRACT, STRICT LIABILITY, TORT, OR THE NEGLIGENCE OF ANY PERSON OR PERSONS, INCLUDING THAT OF THE INDEMNIFIED PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, ACTIVE, PASSIVE OR GROSS OR ANY OTHER THEORY OF LEGAL LIABILITY AND WITHOUT REGARD TO WHETHER THE CLAIM AGAINST THE INDEMNITEE IS THE RESULT OF AN INDEMNIFICATION AGREEMENT WITH A THIRD PARTY. 25.2 BENEFIT OF INDEMNITIES TO THE EXTENT A PARTY IS ENTITLED TO INDEMNIFICATION IN ARTICLES 21, 22, 23, AND 24, SUCH PARTY’S PARENT, SUBSIDIARIES, AFFILIATES, CO-OWNERS AND JOINT VENTURERS (IF ANY), AND THEIR RESPECTIVE OFFICERS, DIRECTORS, AGENTS AND EMPLOYEES, THE DRILLING UNIT AND ITS LEGAL AND BENEFICAL OWNERS, IN REM OR IN PERSONAM SHALL ALSO BE ENTITLED TO SUCH INDEMNIFICATION AND DEFENSE THEREUNDER. ANY

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SUCH PERSON SO ENTITLED TO INDEMNIFICATION AND DEFENSE UNDER THIS ARTICLE 25.2 ARE HEREINAFTER REFERRED TO AS AN “EXTENDED BENEFICIARY OF INDEMNIFICATIONS.

25.3 Third Party Beneficiaries Except as otherwise specifically agreed nothing in this Contract shall be construed or applied so as to permit any person or entity not a direct signatory party hereto (except for a successor or permitted assignee of such direct signatory party) to enforce or seek damages against either signatory party hereto for any breach of this Contract. The definition of CONTRACTOR and COMPANY herein shall not be construed to enable or entitle any person or entity other than the signatory parties hereto or a successor or permitted assignee of such a signatory party to directly sue or seek relief against the other signatory party hereto except to the extent that any Extended Beneficiary of Indemnification (as defined in Article 25.2) shall be expressly permitted to enforce such rights of indemnification against the indemnitor. Except for any EXTENDED BENEFICIARY OF INDEMNIFICATION, no persons or entities are intended to be or become third party beneficiaries of this contract. ARTICLE 26 LAWS, RULES, AND REGULATIONS 26.1 LAWS, RULES AND REGULATIONS CONTRACTOR and COMPANY shall comply with all governmental laws, rules, and regulations or orders which are now or hereafter shall become applicable to its operations covered by this CONTRACT or arising out of the performance of such operations.

26.2 EQUAL OPPORTUNITY CLAUSE To the extent applicable and in connection with the performance of work under this CONTRACT, CONTRACTOR agrees to comply with the following Equal Employment Opportunity and/or Affirmative Action requirements and all other similar requirements as the same are enacted or become applicable to the CONTRACT: Section 202 of Executive Order 11246, as amended by Executive Order 11375, relating to equal employment opportunities, the implementing rules and regulations of the Secretary of Labor and all contract clauses and requirements which are applicable and set forth therein are incorporated herein by specific reference. In particular, CONTRACTOR hereby certifies that it does not maintain segregated facilities. In making this certification, CONTRACTOR incorporates each and all of the provisions of the approved form of certification contained in 41 C.F.R. Section 60-1.8(b) the same as if such provisions were fully set forth herein and signed by CONTRACTOR. Sections 503 and 504 of the Rehabilitation Act of 1973 and Title IV of the Vietnam Era Veterans Readjustment Assistance Act of 1974 relating to employment and advancement of employment of qualified handicapped individuals, disabled veterans and veterans of the Vietnam Era, the implementing rules and regulations of the Secretary of Labor and all contract clauses and requirements which are applicable and set forth therein are incorporated herein by specific reference pursuant to 41 C.F.R. Section 60-741.22 and 41 C.F.R. Section 60-250.22.

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26.3 CERTIFICATE OF FINANCIAL RESPONSIBILITY COMPANY, in cooperation with the CONTRACTOR, shall obtain, at COMPANY’S expense, and maintain evidence of a Certificate of Financial Responsibility from the U.S. Coast Guard covering the Drilling Unit as required by 33 C.F.R. Part 135 and the Outer Continental Shelf Lands Act of 1978. COMPANY will file for the certificate before the well is spud and will coordinate the filing with COMPANY. A copy of filed certificate shall be furnished to CONTRACTOR prior to spud and CONTRACTOR must maintain a copy on the Drilling Unit. ARTICLE 27 TERMINATION 27.1 TERMINATION BY COMPANY 27.1.1 COMPANY shall have the option to terminate this CONTRACT subject only to (i) payment of amounts earned by CONTRACTOR before termination, and demobilization of the Drilling Unit pursuant to Article 1.3 and (ii) payment of the Lump Sum set forth in Exhibit E. Terminating pursuant to Article 27.1.1 does not limit any other right of termination which COMPANY may have. The termination shall not affect any right or obligation which accrued prior to the termination. 27.1.2 In the event the shipyard where the Drilling Unit is being constructed fails or is unable to deliver the Drilling Unit within the time limits and operational specifications of its contract with CONTRACTOR such that CONTRACTOR has the ability to terminate the construction contract, CONTRACTOR shall so advise COMPANY in writing. If COMPANY desires to accept the Drilling Unit with later delivery or reduced operational specifications, then COMPANY shall so notify CONTRACTOR within a reasonable time following COMPANY’S receipt of notice under this Article, and upon timely receipt of notice by CONTRACTOR, CONTRACTOR shall not terminate the construction contract and this CONTRACT shall be suitably amended to reflect the later delivery and the reduced operational specifications in Exhibit G, with all other terms and conditions remaining in full force and effect. If such later delivery or reduced operational specifications result in a claim by CONTRACTOR against the Drilling Unit constructor, any net savings to CONTRACTOR as a result of such claim shall be credited to COMPANY against CONTRACTOR’S invoices or remitted to COMPANY as COMPANY shall direct. If COMPANY does not desire to accept the Drilling Unit with such later delivery or reduced operational specifications, then COMPANY shall so notify CONTRACTOR within a reasonable time following COMPANY’S receipt of notice under this Article, and upon timely receipt of such notice by CONTRACTOR, this CONTRACT shall terminate and COMPANY shall have no obligations under Exhibit E.

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27.2 TERMINATION BY CONTRACTOR CONTRACTOR may cancel this CONTRACT for non-payment of its invoices for services under this CONTRACT, except for portions of the invoices which COMPANY may dispute in good faith. However, CONTRACTOR may cancel under this Article no sooner than one hundred and twenty (120) days after payment was due and only after giving ninety (90) days notice thereof, during which period COMPANY shall have the opportunity to correct the breach. 27.3 LOSS OF DRILLING UNIT In the event of actual or constructive total loss of the Drilling Unit (as determined by CONTRACTOR’S underwriters), termination shall be immediate with neither CONTRACTOR nor CONTRACTOR’S underwriters having any recourse against COMPANY, or obligations pursuant to Exhibit E, except for CONTRACTOR’S claim to amounts CONTRACTOR earned up to the date of such loss. Contractor shall be responsible for any removal or salvage costs. 27.4 PROVISION AFTER EXPIRATION OF CONTRACT Notwithstanding the termination of this CONTRACT, COMPANY and CONTRACTOR shall continue to be bound by the provisions of this CONTRACT that reasonably require some action or forbearance after the expiration of the term of this CONTRACT. ARTICLE 28 FORCE MAJEURE 28.1 FORCE MAJEURE The term Force Majeure as used in this Article 28 shall mean acts of God, adverse sea or weather conditions beyond the design operating perimeters of the Drilling Unit including wind, sea and current, earthquakes, flood, war, civil disturbances, strikes, lockouts or other industrial disturbances by persons other than employees of CONTRACTOR, governmentally imposed rules, regulations or moratoriums or any other cause whatsoever, whether similar or dissimilar to the causes herein enumerated, not within the reasonable control of either Party which, through the exercise of due diligence said party is unable to foresee or overcome. In no event shall the term Force Majeure include normal, reasonably foreseeable, or reasonably avoidable operational delays or strikes, lockouts or other industrial disturbances by employees of CONTRACTOR. In the event that either Party hereto is rendered unable, wholly or in part, by Force Majeure to carry out its obligations under this CONTRACT, it is agreed that such Party shall give notice and details of the Force Majeure in writing to the other Party as promptly as possible after its occurrence. In such cases, the obligations of the Party giving the notice shall be suspended during the continuance of any inability so caused, except that COMPANY shall be obligated to pay to CONTRACTOR the applicable Dayrates. Should a condition of Force Majeure continue for more than thirty (30) consecutive days, this CONTRACT may be immediately terminated at the option of COMPANY by delivering written notice thereof to CONTRACTOR. Except for its obligation to make payments of monies hereunder, neither Party to this CONTRACT shall be considered in default in performance of such obligations hereunder to the

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extent that the performance of such obligations, or any of them is delayed or prevented by Force Majeure. ARTICLE 29 CONFIDENTIAL INFORMATION, LICENSE AND PATENT INDEMNITY 29.1 CONFIDENTIAL INFORMATION 29.1.1 CONTRACTOR agrees to hold in confidence, and not disclose to any third party or use for any purpose other than performance of the work, all or any part of the well information (including the location and type of operations performed), logs, cores, core data, cuttings, maps, data, plans, reports, manuscripts, procedures, schedules, drawings, specifications, results, models, computer programs, or any product which is: a) received or ascertained by CONTRACTOR directly or indirectly from COMPANY, its licensors or other contractors; or b) otherwise acquired by CONTRACTOR, its employees, representatives, or subcontractors in connection with, as a result of, or incident to performance of the work (“INFORMATION”). CONTRACTOR shall secure prior written agreements from its subcontractors, and suppliers who will be engaged in the performance of the Work, or may be exposed to INFORMATION ensuring their compliance with the provisions of Article 29. Nothing herein contained should preclude CONTRACTOR from providing INFORMATION required by any governmental authority. 29.1.2 CONTRACTOR shall not use COMPANY’S name or COMPANY’S affiliate’s name in any promotional materials, or make any publicity release regarding the Work or INFORMATION hereunder except as may be required by law, regulation or rule of any governmental entity or stock exchange without first obtaining the written approval of COMPANY. 29.1.3 CONTRACTOR agrees to comply with all the laws and regulations governing the export of INFORMATION from the United States. 29.1.4 Any other warranty, representation, limitation, or indemnification provision of this CONTRACT shall not affect the obligations of Article 29. 29.1.5 All INFORMATION, whether completed or not, shall be the property of COMPANY for its copying, use, modification, distribution, or disclosure without accounting, in whatever way COMPANY may determine, notwithstanding copyright or other restrictive legends placed thereon by CONTRACTOR, its employees, its subcontractors, or its suppliers. All INFORMATION shall be turned over to COMPANY promptly at COMPANY’S request or at the termination of operations. 29.2.2 CONTRACTOR agrees to grant, and hereby grants to COMPANY an irrevocable, paid up, nonexclusive worldwide license to make, use, sell, copy, modify, disclose, distribute, and license under any and all patent, copyright, trade secret and other proprietary rights owned or controlled by CONTRACTOR, its parent or subsidiaries, to the extent needed for making, using,

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selling, or licensing equipment, materials, or other goods according to INFORMATION supplied by CONTRACTOR or to produce, copy, distribute, and use copyrighted materials based on using such INFORMATION. 29.3 PATENT INDEMNITIES 29.3.1 CONTRACTOR SHALL PROTECT, DEFEND, INDEMNIFY AND HOLD HARMLESS COMPANY AGAINST LOSS OR DAMAGE ARISING OUT OF ANY CLAIM OR SUIT FOR MISAPPROPRIATION OF TRADE SECRET OR FOR PATENT, COPYRIGHT OR OTHER PROPRIETARY RIGHT INFRINGEMENT ARISING OUT OF INCIDENT TO OR IN CONNECTION WITH (A) PERFORMANCE OF THE WORK BY CONTRACTOR, OR (B) COMPANY’S POSSESSION, USE OR SALE OF GOODS, EQUIPMENT OR MATERIALS FURNISHED BY CONTRACTOR, OR (C) COMPANY’S PRODUCTION OF COPYRIGHTED WORKS INCORPORATING OR PREPARED ACCORDING TO DOCUMENTS OR OTHER TANGIBLE MATERIALS FURNISHED BY CONTRACTOR, AND COMPANY’S POSSESSION, MODIFICATION, USE, SALE, DISTRIBUTION, COPYING OR LICENSING OF SUCH DOCUMENTS, MATERIALS OR WORKS. COMPANY shall promptly notify CONTRACTOR of any such claim or suit and afford CONTRACTOR an opportunity at CONTRACTOR’S expense to undertake the defense of any such suit, provided that COMPANY, at its election, may join in such defense at its expense. If CONTRACTOR refuses or fails to defend such suit, CONTRACTOR shall reimburse COMPANY in full for COMPANY’S costs and expenses in the defense of such suit including attorneys’ fees. CONTRACTOR shall pay promptly any judgments or decrees which may be entered against COMPANY in such suit, and in the event of the grant of injunctive relief, CONTRACTOR shall provide non-violating INFORMATION, equipment, and/or material equal in value and efficiency and failing so to do, shall pay COMPANY all damages suffered by reason of such failure. 29.3.2 COMPANY SHALL PROTECT, DEFEND, INDEMNIFY AND HOLD HARMLESS CONTRACTOR AGAINST LOSS OR DAMAGE ARISING OUT OF ANY CLAIM OR SUIT FOR MISAPPROPRIATION OF TRADE SECRET OR FOR PATENT, COPYRIGHT OR OTHER PROPRIETARY RIGHT INFRINGEMENT ARISING OUT OF INCIDENT TO OR IN CONNECTION WITH (A) CONTRACTOR”S POSSESSION, USE OF EQUIPMENT OR MATERIALS FURNISHED BY COMPANY IN ACCORDANCE WITH EXHIBIT B-3, OR (B) CONTRACTOR’S PRODUCTION OF COPYRIGHTED WORKS INCORPORATING OR PREPARED ACCORDING TO DOCUMENTS OR OTHER TANGIBLE MATERIALS FURNISHED BY COMPANY, AND CONTRACTOR’S POSSESSION, MODIFICATION, USE, SALE, DISTRIBUTION, COPYING OR LICENSING OF SUCH DOCUMENTS, MATERIALS OR WORKS. CONTRACTOR shall promptly notify COMPANY of any such claim or suit and afford COMPANY an opportunity at COMPANY’S expense to undertake the defense of any such suit, provided that CONTRACTOR, at its election, may join in such defense at its expense. If COMPANY refuses or fails to defend such suit, COMPANY shall reimburse CONTRACTOR in full for CONTRACTOR”S costs and expenses in the defense of such suit including attorneys’ fees. COMPANY shall pay promptly any judgments or decrees entered against CONTRACTOR in such suit.

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ARTICLE 30 ASSIGNMENT OF CONTRACT 30.1 ASSIGNMENT BY CONTRACTOR CONTRACTOR shall not sublease or assign this CONTRACT, other than to its parent company or an affiliate or subsidiary thereof, without first obtaining the written consent of COMPANY. Such consent shall not be unreasonably withheld. COMPANY may require CONTRACTOR or its parent, subsidiaries or affiliates to issue a performance guarantee in a mutually agreeable form. 30.2 ASSIGNMENT BY COMPANY 30.2.1 COMPANY shall have the right to assign this CONTRACT to Atlantic Richfield Company, its divisions, subsidiaries (whether wholly or partially owned by Atlantic Richfield Company) and affiliates. CONTRACTOR shall look exclusively to the assignee of COMPANY for any matter during the period of assignment in the event of any such assignment by COMPANY. The time the Drilling Unit is operating for the assignee shall count towards the Contract Period. 30.2.2 Subject to Article 30.2.1, COMPANY shall have the right to assign its rights and obligations hereunder, in whole or in part, to third persons for wells within the Gulf of Mexico, with written consent of CONTRACTOR, and such consent shall not be unreasonably withheld. In the event of any such assignment under this Article 30.2.2 to a third party with CONTRACTOR’S written consent, COMPANY shall thereafter have no liability for any matter or operations hereunder and shall have no further responsibility to CONTRACTOR or other person hereunder during the time the right is assigned. CONTRACTOR shall look exclusively to the assignee of COMPANY for any matter during the period of assignment in the event of any such assignment by COMPANY. The time the Drilling Unit is operating for the assignee shall count toward the Contract Period. 30.2.3 COMPANY shall have the right to assign its rights and obligations hereunder, in whole or in part, to third parties for wells within the Gulf of Mexico, without the consent of CONTRACTOR. In the event of any such assignment under this Article 30.2.3, COMPANY shall provide written notice to CONTRACTOR prior to the use of the Drilling Unit on behalf of the assignee. In the event of such an assignment, COMPANY shall remain fully liable and responsible to CONTRACTOR for complete performance of all terms, conditions, and obligations imposed by this CONTRACT. The time the Drilling Unit is operating for the assignee shall count toward the Contract Period. 30.3 ASSIGNMENT OUTSIDE OF OPERATING AREA In the event any assignment being contemplated under the provisions of this Article 30 is to involve operations outside of the Operating Area (as defined in Article 14.6), the dayrates provided for herein shall be adjusted to reflect any documented increases or decreases in CONTRACTOR’S cost of operations, including but not limited to taxes and fees in Article 11.

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ARTICLE 31 INGRESS AND EGRESS OF LOCATION 31.1 INGRESS AND EGRESS OF LOCATION 31.1.1 COMPANY shall provide CONTRACTOR with rights of ingress and egress to the well location and provide any related drilling permits or licenses for the performance by CONTRACTOR of all Work. 31.1.2 COMPANY makes no warranty or representation, express or implied, and hereby disclaims all such warranties or representations as to any conditions with respect to any port, place, dock, anchorage, access route, location, or submarine line relating to the Work, except at the well location. ARTICLE 32 COMPANY’S POLICIES 32.1 UNAUTHORIZED PERSONS ON JOB SITES Only (i) CONTRACTOR’S authorized employees or subcontractors, (ii) other authorized employees and persons, including invitees, authorized by COMPANY, or (iii) representatives of governmental agencies will be permitted to enter any job site where Work is to be performed under this CONTRACT. CONTRACTOR is obligated to take such steps as are reasonably necessary to prevent unauthorized persons from entering a job site. 32.2 DRUGS, FIREARMS, AND SEARCHES CONTRACTOR shall abide by and help enforce COMPANY’S policy regarding drugs, firearms, and alcohol. The policy is as follows: The use, possession, or transportation of firearms, alcoholic beverages, illegal drugs, narcotics, or other controlled or dangerous substances, and unauthorized drugs for which a person does not have a current prescription, while on COMPANY’S Premises is prohibited. The term “COMPANY’S Premises” is used in its broadest sense to include all work locations, buildings, structures, installations, Drilling Unit, and all other facilities, both onshore and offshore, including the point of embarkation and debarkation for all boats, planes, and helicopters owned or controlled by COMPANY or one of its affiliated companies or otherwise being utilized for COMPANY’S business for transportation of persons to and from these facilities. To ensure compliance with this policy, COMPANY may require CONTRACTOR, upon written request, to conduct unannounced periodic inspections of all individuals and their personal effects while on COMPANY’S Premises. Violation of this policy or refusal to submit to an inspection by COMPANY’S or CONTRACTOR’S personnel could result in disciplinary action up to and including discharge will be cause for immediate removal of the individual from COMPANY’S Premises.

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ARTICLE 33 NOTICES 33.1 NOTICES Any notice provided or permitted to be given under this CONTRACT shall be in writing, and may be served by personal delivery or by depositing same in the mail, addressed to the Party to be notified, postage prepaid, and registered or certified with a return receipt requested. Notice deposited in the mail in the manner described above shall be deemed to have been given and received on the date of the delivery as shown on the return receipt. Notice served in any other manner shall be deemed to have been given and received only if and when actually received by the addressee (except that notice given by telecopier shall be deemed given and received upon receipt only if received during normal business hours and if received other than during normal business hours shall be deemed received as of the opening of business on the next Business Day (for purposes of this CONTRACT, the term “Business Day”) shall mean any day except a Saturday, Sunday or other day on which commercial banks in Houston, Texas are required or authorized by law to be closed). For purposes of notice, the addresses of the Parties shall be as follows: 33.2 FOR COMPANY

Vastar Resources, Inc. 15375 Memorial Drive Houston, TX 77079 ATTN: Don Weisinger FAX: (281) 584-6810 or 6670 TELEPHONE: (281) 584-6021

33.3 FOR CONTRACTOR

R&B Falcon Drilling Co. 901 Threadneedle Houston, TX 77079-2911 ATTN: President FAX: (281)496-4363 TELPHONE: (281)496-5000

33.4 ORAL NOTICES Notices may be given orally only with respect to minor questions involved in the immediate drilling of any well concerned.

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ARTICLE 34 CONSEQUENTIAL DAMAGES 34.1 CONSEQUENTIAL DAMAGES Neither Party shall be liable to the other for incidental special, indirect, statutory, exemplary, punitive, or consequential damages suffered by such party resulting from or arising out of this CONTRACT, including, without limitation, loss of profits, or business interruptions however they may be caused. ARTICLE 35 WAIVERS AND ENTIRE CONTRACT 35.1 WAIVERS None of the terms and conditions of this CONTRACT shall be deemed waived by either Party unless the waiver is executed in writing and then only by the duly authorized agents or representative of that Party. The failure of either Party to execute any right of termination shall not act as a waiver of any right of that Party provided hereunder. No waiver of the provisions of this CONTRACT shall be deemed or shall constitute a waiver of any other provisions hereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided. 35.2 ENTIRE CONTRACT This CONTRACT, including all exhibits attached hereto and made a part hereof by this reference, constitute the entire agreement between the Parties with respect to the subject matter hereof and thereof and supersede all prior agreements, understandings, negotiations, discussions and commitments, whether oral or written with respect to same. The right of either Party to require strict adherence to the terms hereof and performance hereunder will not be affected by any previous waiver of course of dealing. Neither this CONTRACT nor any supplement, amendment, alteration, modification, or waiver will be binding on a Party unless signed by duly authorized agents or representatives of CONTRACTOR and COMPANY, or in the case of termination, by the duly authorized agents or representatives of the Party seeking termination. In the event of conflict between the terms and conditions of the text of this CONTRACT and those in any of the Exhibits, the terms and conditions of the text of this CONTRACT shall prevail. 35.3 GOVERNING LAW This CONTRACT shall be construed and the relations between the parties determined in accordance with the General Maritime Law of the United States of America, not including, however, any of its conflicts of law rules which would direct or refer to the laws of another jurisdiction.

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35.4 ARBITRATION Any controversy or claim arising out of or relating to this CONTRACT, or the breach thereof, which cannot be resolved satisfactorily between the parties, shall be settled by arbitration in Houston, Texas, in accordance with the rules of the American Arbitration Association Commercial Disputes. If no agreement can be reached by the Parties on discovery disputes, then the Federal Rules of Civil Procedure shall govern and judgement upon the award rendered by the arbitrator(s) may be entered in any court of competent jurisdiction. IN WITNESS WHEREOF, the parties hereto have executed this CONTRACT on the 9th day of December, 1998.

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R&B Falcon Drilling Co.

Vastar Resources, Inc. BY: /s/ Paul B. Loyd, Jr. By /s/ Charles D. Davidson

Paul B. Loyd, Jr.

Charles D. Davidson TITLE: Attorney-in-Fact

TITLE: President and CEO

(Chairman R&B Falcon Corporation)

EXHIBIT A

DAYRATES

1

RATES PER 24 HOUR DAY

Three (3) Year Option Five (5) Year Option

Operating Rate $199,950.00 per day $189,200.00 per day Moving Rate

$199,950.00 per day

$189,200.00 per day Standby Rate With Crews

$199,950.00 per day

$189,200.00 per day Standby Rate Without Crews $199,950.00 per day less

documented cost savings$189,200.00 per day less documented cost savings

Stack Rate With Crews

$199,950.00 per day less documented cost savings


Stack Rate Without Crews



Equipment Repair Rate

$ -0- per day

$ -0- per day Hurricane Evacuation Rate Standby Rates without crews plus

documented expenses of evacuated crew

Standby Rates without crews plus documented expenses of evacuated crew

EXHIBIT B-1

Drilling Unit Specifications

GENERAL DESCRIPTION, DIMENSIONS & CRITERIA

General Description The RBS8D is a 5th generation, harsh environment, dynamically positioned semi-submersible, suitable for worldwide operations in up to 10,000’ water depth. The vessel has twin “dog-bone”-shaped lower hulls, four (4) columns, canted in the transverse plane, each with a Column Outer Belt (COB) at the drilling draft, two (2) transverse horizontal, four (4) diagonal horizontal braces, and a watertight rectangular box-type upper hull. Designed for harsh environments, the vessel features variable deck & column loads (per 1.2.4 of this document), very low motions, and high specification drilling systems, with machinery spaces and two-level quarters for 130 personnel. Eight 5.5 MW azimuth thrusters plus six 7 MW engines provide reliable and redundant DPS-3 station keeping ability. Principal Dimensions

1

Metric Units

U.S. Units

Overall Structure

Length (overall)

120.7 m

396.00 ft.

Breadth (overall)

78.0 m

255.91 ft.

Upper Hull

Length 81.5 m 267.40 ft.Breadth

61.0 m

200.13 ft.

Depth

8.5 m

27.89 ft.

Main Deck

Length 84.1 m 275.93 ft.Breadth

61.0 m

200.13 ft.

Pontoons (two each)

Length

114.0 m

373.96 ft.

Breadth (amidship)

13.4 m

43.96 ft.

Breadth (ends)

16.5 m

54.13 ft.

Depth 9.10 m 29.86 ft.Corner Radius

3.00 m

9.84 ft.

Transverse Distance (c. to c.) 61.5 m 201.77 ft.

2

Columns (four each)

Horizontal Section (Lx B)

17.0 m x l6.5 m (@ WL) 55.8 ft. x 54.l ft.

14.0 m x 16.5 m (bottom) 45.93 ft. x 54.13 ft.

Corner Radius 3.00 m 9.84 ft.

Vertical Height

23.9 m 78.41 ft.

Longitudinal Distance (c. to c.)

60.0 m 196.85 ft.

Transverse Distance (c. to c.) at Top

46.00 m 150.92 ft.

at Bottom

61.5 m 201.77 ft.

Transverse Braces (two each)

Length

45.0 m 147.64 ft.

Breadth 6.0 m 19.68 ft.

Depth

3.00 m 9.84 ft.

Corner Radius

0.60 m 1.97 ft.

Longitudinal Distance (c. to c.)

68.0 m 223.10 ft.

Centerline Elevation

1.5 m 4.92 ft.

Diagonal Braces (four each)

Diameter 3.0 m 9.84 ft.

Centerline Elevation

1.5 m 4.92 ft.

Elevations

Drill Floor

46.0 m 150.92 ft.

Main Deck (at sides) 41.5 m 136.15 ft.

Second Deck

38.0 m 124.67 ft.

Third Deck (Inner bottom Top) 34.5 m 113.19 ft.

Upper Hull Bottom

33.0 m 108.27 ft.

Lower Hull Top

9.1 m 29.86 ft.

Draft

Operating Condition (G.O.M.) 23.00 m 75.46 ft.

Severe Storm Condition (G.O.M.)

16.50 m 54.13 ft.

Transit Condition 8.80 m 28.87 ft.

Storage Capacities

(subject to adjustments)

(*) Note: Pontoon Brine Storage and SWB are interchangeable 3

Metric Units U.S. Units

Pipe Racks

871 m 9,376 ft

Riser (90’ joints)

3,048.5 m 10,000 ft

Total Open Deck

2,005 m 21,578 ft

Bulk Cement

232 m 8,205 ft

Bulk Barite 387 m 13,675 ft

Cement Day Tank

62 m 2,200 ft

Barite Day Tank 68 m 2,400 ft

Total Bulk Storage

750 m 26,480 ft

Sack Storage

10,000 Sx 10,000 Sx

Drilling Mud Deck

750 m 4,434 bbl.

Drilling Mud (Column)

908 m 5,710 bbl.

Base Oil 480 m 3,019 bbl

Column Brine Storage

480 m 3,019 bbl.

Pontoon Brine Storage *) 3,975 m 25,000 bbl.

DW-Col.

1,736 m 10,918 bbl.

DW-pontoons

1424 m 8,956 bbl.

Fuel Oil

3,468 m 21,811 bbl

Potable Water

644 m 4,050 bbl

Helicopter Fuel TBD TBD

Refrigeration Storage

45 m 484 ft.

Dry Storage 60 m 646 ft.

SWB — pontoons *)

16,308 m 102,565 bbl

Quarters

130 Persons 130 Persons

Heliport

S-61, Super Puma S-61, Super Puma

2 2

2 2

3 3

3 3

3 3

3 3

3 3

3 3 3 3

3 3 3 3

3

2 2

2 2

3

GULF OF MEXICO

METOCEAN DESIGN CRITERIA *)

*) Metocean Design Criteria in the DP mode relate to drilling conditions with all engines (6 x 7.0 MW power) on line and any one thruster down.

4

OPERATION

(DP Mode)SURVIVAL

(transit / future moored)Condition

Drilling

Moored Vessel

Item

10 Year Eddy + 10 year Tropical

Storm

20Year Tropical + 10 Year Eddy (API Criteria)

100 Year Tropical Storm

(ABS/API)Wind (1 hour)

26.1 m/s (50.8 kn)

30.5 rn/s (59.2 kn)

44.9 m/s (87.2 kn)

Wind (1 min.)

30.9 m/s (60 kn)

36.0 m/s (70 kn)

53.1 m/s (103 kn)

Wind (3 sec.)

35.8 m/s (69.5 kn)

41.7 m/s (81.0 kn)

61.7 m/s (120 kn)

Wave Hgt. Significant

7.9 m (26.0 ft)

9.4 m (31.0 ft) 12.5 m (41.0 ft)

Peak Period

(PMS)

12.0 sec. 15.0 sec.

Wave Height Maximum 14.7 m (48.2 ft)

17.5 m (57.3 ft)

22.0 m (72.2 ft)

Current:

Surface 1.8 m/s, (3.5 kn) 1.8 m/s, (3.5 kn) 1.0 m/s (1.9 kn)

100 ft.

1.7 m/s, (3.4 kn)

1.7 m/s, (3.4 kn)

200 ft.

1.2 m/s (2.4 kn)

1.2 m/s (2.4 kn)

400 ft.

1.0 M/s (2.0 kn)

1.0 m/s (2.0 kn)

1000 ft.

0.5 m/s (1.0 kn)

0.5 m/s (1.0 kn)

2000 ft. 0.3 m/s (0.5 kn) 0.3 m/s (0.5 kn)

Seafloor

0.1 m/s, (0.1 kn)

0.1 m/s, (0.1 kn)

1.2.4 Variable Drilling Loads (VDL) DP Mode — No Mooring

Future Mooring + Thruster Assist

Notes: 1) Variable Drilling Load computation is based on a derrick height of 170 ft. Derrick extension beyond 170 ft will impact max. VDL. 2) Mooring equipment weight of 1,784 MT is included in transit VDL + pontoon load; alternatively, field transit may be conducted at column draft.

5

Item Division OperationCondition

KG (m)(Operating)

Survival Condition

Transit

Condition Remark

MT (m) MT

MT

Light Ship

22,325

26.15

22,325

22,325

VDL (Variable Dlg. Loads) Upper Hull & Abv. 5,596 37.40 5,596

(note 1)

Columns 2,057 22.85 2,057

VDL Total (Dk. + Col.) 7,653 33.49 7,653

7,450

Pontoon Loads: Drill Water, Potable Water, Water, Fuel Oil, Lube Oil, and Ballast Water

17,530

5.57

10,722

2,984

Displacement (MT)

47,509 19.68 40,700

32,759

Item Division OperationCondition

KG (m)(Operating)

Survival Condition

Transit

Condition Remark

MT (m) MT

MT

Light Ship

22,325

26.15

22,325

22,325

Mooring Load

2,135

22.00

2,135

1,784

VDL (Variable Dlg. Loads) Upper Hull & Abv. 5,596 37.40 5,596

(note 1)

Columns

2,057

22.85

2,057

VDL Total (Dk. + Col.)

7,653

33.49

7,653

5,696

(note 2)Pontoon Loads: Drill Water, Potable Water, Water, Fuel Oil, Lube Oil, and Ballast Water

15,395 5.55 8,587

2,984

Displacement (MT)

47,509

20.49

40,700

32,759

Classification Society

American Bureau of Shipping A1 “Column Stabilized Drilling Unit”, CDS, (P), DPS-3

Rules and Regulations

• SOLAS, 74 Convention, 78 Protocol with Amendments through 1997

1988 Amendments to the 1974 SOLAS Convention concerning Radio Communications for the Global Maritime Distress and Safety System (GMDSS)

• API /AISC • OCIMF • US Coast Guard Requirements • MARPOL 73 COW, Regulation 13F, etc., (Annexes I, IV, & V) (Oil) IOPP, with the Protocol 1978, and amendments to Annex I

and Annex V of 1992. (refer to section 053 Damage stability)

• IMO Resolutions A.468(XII), “Code on Noise Levels Onboard Ships”, 1981, and USCG NVIC 12-82 as well • IMO Resolution A.574(XIV), “Recommendations on General Requirements for Electric Navigational Aids”

• IMO MSC/circ. 403, “Draft Guidelines on Navigation Bridge Visibility except field of vision (blind sector). • IMO MODU Code, 1989 with amendments of 1991 (ABS Statement-of-Fact). • 1966 Loadline Conference and all amendments and IMO Resolutions A.513 (XIII) and A.514 (XIII) • International Convention on Tonnage Measurement of Ships, 1969, as amended by IMO Resolution A.493 (XII) and

Resolution A.494 (XII). • 1972 International Prevention of Collision at sea Convention, including amendments of 1981, 1987, and 1989 • 1988 Amendments to the 1974 SOLAS Convention concerning Radio Communications for the Global Maritime Distress

and Safety System (GMDSS) • International Electro Technical Commission (IEC) Publication No. 60092 for electrical installation of ships. • International Electro Technical Commission (IEC) Publication No. 61892 for Mobile and Fixed Offshore Units - electrical

installations, • U.S.C.G. Regulations for Marine Sanitation Devices (CFR title 33-Part 159)

Registration

The Vessel shall be registered under USA Flag.

6

The estimated Light Ship weight is 22,325 metric tons, the estimated Light Ship VCG is 26.15m above baseline. The approximate breakdown is as follows:

7

Item M. Tonnes L. Tons HSW

13,603

13,390

BFE

3,433

3,379

OFE

4,619

4,547

<SUBTOTAL>

<21,655> <21,316> OTHERS 220 218MARGIN

450

443

TOTAL 22,325 21,977

EXHIBIT B-2

MATERIAL EQUIPMENT LIST

TABLE OF CONTENTS

1

SECTION A - UNIT SPECIFICATIONS Al Main Dimensions/Technical Description A2 Storage Capacities A3 Propulsion/Thrusters A4 Operational Capabilities A5 Variable Loading A6 Environmental Limits A7 Mooring System A8 Marine Loading Hoses A9 Cranes, Hoists, and Materials Handling A10 Helicopter Landing Deck A11 Auxiliary Equipment SECTION B - GENERAL RIG SPECIFICATIONSB1 Derrick and Substructure B2 Drawworks and Associated Equipment B3 Derrick Hoisting Equipment B4 Rotating System SECTION C - POWER SUPPLY SYSTEMS C1 Rig Power Plant C2 Emergency Generator C3 Primary Electric Motors SECTION D - DRILLSTRING EQUIPMENT D1 Tubulars D2 Handling Tools D3 Fishing Equipment SECTION E - WELL CONTROL/SUBSEA EQUIPMENTEl Lower Riser Diverter Assembly E2 Primary BOP Stack E3 Primary Lower Marine Riser Package E4 Annular Gas Handler E5 Secondary Lower Marine Riser Package E6 Primary Marine Riser System E7 Secondary Marine Riser System E8 Diverter BOP E9 Subsea Support System El0 BOP Control System E11 Subsea Control System E12 Acoustic Emergency BOP Control System E13 Subsea Auxiliary Equipment

2

E14 Choke Manifold E15 Hydraulic BOP Test Pump E16 Wellhead Running/Retrieving/Testing Tools SECTION F - MUD SYSTEM/BULK SYSTEM Fl High Pressure Mud SystemF2 Low Pressure Mud System F3 Bulk System SECTION G - CASING/CEMENTING EQUIPMENTG1 Casing Equipment G2 Cement Equipment SECTION H - INSTRUMENTATION/COMMUNICATIONH1 Drilling Instrumentation at Driller’s PositionH2 Drilling Parameter Recorder H3 Instrumentation at Choke Manifold H4 Standpipe Pressure Gauge H5 Deviation Equipment H6 Calibrated Pressure Gauges H7 Rig Communication System H8 Environmental Instrumentation H9 Additional MODU Specific InstrumentationH10 Radio Equipment SECTION I - PRODUCTION TEST EQUIPMENT11 Burners 12 Burner Booms 13 Lines Required on Burner Booms 14 Sprinkler System 15 Fixed Lines for Well Tesing 16 Power Requirement SECTION J - WORKOVER TOOLS SECTION K - ACCOMMODATION K1 Offices K2 Living Quarters SECTION L - SAFETY EQUIPMENT L1 General Safety Equipment L2 Gas Detection L3 Fire Fighting Equipment L4 Breathing Apparatus L5 Emergency First Aid Equipment L6 Helideck Rescue Equipment L7 Rig Safety Store L8 Emergency Warning Alarms L9 Survival Equipment

3

SECTION M - POLLUTION PREVENTION EQUIPMENTMl Sewage Treatment M2 Garbage Compaction M3 Garbage Disposal/Grinder SECTION N - THIRD PARTY EQUIPMENT (SPACE PROVIDED)

SECTIONS

4

A. UNIT SPECIFICATIONS

GENERAL

Unit Name :

RBS8-DRig Type :

SEMISUBMERSIBLEUnit/design/shape

IHI - RBF ExplorationUnit flag :

UNITED STATESUnit classification :

ABSIMO Certification (yes/no) :

YESWhich code version :

1989 as ammended 1991Year of construction :

2,000Construction yard :

HYUNDAIType of Positioning system (anchor/dp/c :

DPS-3

A.1 MAIN DIMENSIONS/TECHNICAL

DESCRIPTION

Weight (light ship) lt:

21,977Overall width ft:

255.9Overall length ft:

396Main deck width ft:

200.1Main deck length ft: 275.9Main deck depth ft:

27.9Number of main columns/diameter No x ft:

4 x 55.8 x 54.1 (WL) 45.9 x 54.1 (Bottom)Number of small columns/diameter No x ft

0Drilling draft/related displacement ft - lt:

75.5 / 46,767Transit draft/related displacement ft - lt:

28.9 / 32,247Survival draft/related displacement ft - lt:

54 / 40,064Moon pool dimensions ft x ft: 21 X 93Maximum opening through spider deck ft - lt:

N/APontoon length ft - lt:

374Pontoon breadth (ends / middle)

54.1 / 44.0Pontoon height ft - lt:

29.9Accommodation for maximum no. of persons :

130

A.2 STORAGE CAPACITIES Fuel bbls:

21,811Drilling water bbls:

19,874Potable water bbl:

4050Active liquid mud (see F.2) bbl:

4434 (100%)Mud processing tank (see F.2) bbl:

450 (100%)Reserve liquid mud (see F.2) bbl:

5710 (100%)Bulk bentonite/barite (see F.3) cu ft: 13,675 (100%)Bulk cement (see F.3) cu ft:

11000 (100%)Sack storage No. or ft2:

10000 sxsPipe racks area ft2:

9,376Load bearing capacity lb/ft2:

500Riser racks area ft:

10,000Load bearing capacity lb/ft2:

300Miscellaneous storage area ft2: See DrawingBrine storage (Column) bbls:

3019 (100%)

5

Brine storage (Pontoon) bbls:

25,000 (100%)Base oil mud storage bbls:

3019 (100%)Ballast system bbls:

102,565

A.3 PROPULSION/THRUSTERS

Thrusters\Type (azimuth/in line) :

AZIMUTH - FULL 360Quantity :

8Location (aft, opposite corners, 4 corners :

FOUR CORNERSDriven by electric motor (yes/no) :

YES - VARIABLE SPEED DRIVE Make/type :

KamewaPower output (HP ea) :

6633Propeller type (fixed/variable pitch) :

FIXEDNozzled (yes/no) :

YESThruster power (HP total) :

53064

DP SYSTEM :

Class III Dynamic Positioning System in accordance with ABS DPS-3 requirements and recommendations. System to consist of a main triple redundant dynamic positioning system and shall accept inputs from the team selected and proven state of the art Acoustic Positioning System, two differential GPS (DGPS) based on correction signal inputs from different sources, (3) three gyrocompass, (3) three vertical reference units with redundant feeds to the DP system, and three wind sensors, as well as operator input and input from the ERA (Electrical Riser Angle) system. The system shall be powered from a redundant UPS. A single dynamic positioning system of similar design as the main DP system, will accept inputs from the APS, the two DGPS’s, the ERA system, one gyrocompass, one vertical reference unit, and one wind sensor. The system contains the Power Management System and is interfaced with the Integrated Alarm and Control System. The system shall be powered from a dedicated UPS.

Position reference :

HYDRO ACOUSTIC & GLOBAL POSITIONING

Integrated Alarm And Control System:

The IACS will operate as the Sys.Control and Data acquisition sys. for the MODU. The IACS will perform several different functions including: Power Management Sys., Machinery Monitoring and Control, Manual Thruster Control and Autopilot, Dynamic Positioning Control, Ballast / Bunker Monitoring and Control, Bulk Storage Sys. Monitoring and Control.

A.4 OPERATIONAL CAPABILITIES

Maximum designed water depth capability ft:

10000Outfitted max. water depth capability ft:

8000Normal min. water depth cpability ft:

250Drilling depth capability (rated) ft:

30000Transit speed towed (historical avg) knots: 4.5

6

Transit speed self propelled (historical avg) knots:

7.5 A.5 VARIABLE LOADING (VL)

Transit VL mt

See B-1Drilling VL mt

See B-1Survival VL mt

See B-1 A.6 ENVIRONMENTAL LIMITS

Drilling (including station keeping)

See Exhibit B-1

Air gap ft:

32.8Sign. Wave Height ft:

26Max. wave height ft:

48.2Spec. peak period sec:

PMSMax. wind velocity knots: 60 ( 1 min.)Max. current velocity knots:

See B-1Max. heave ft:

N/AMax. pitch degrees:

N/AMax. roll degrees:

N/ASurvival (excluding station keeping)

Air gap ft:

54.2Sig. Wave height ft: 41Max. wave height ft:

72.2Spec. peak period sec:

15Max. wind velocity knots:

103 ( 1 min.)Max. current velocity knots:

1.9Max. heave ft:

N/AMax. pitch degrees:

N/AMax. roll degrees: N/ATransit (field move)

Air gap ft:

79.4Max. wave height ft:

30-40Max. wave period sec:

8-12Max. wind velocity knots:

60-70Max. current velocity knots:

2-3Max. heave ft: N/AMax. pitch degrees:

N/AMax. roll degrees:

N/A A.7 MOORING SYSTEM

MOD’S REQ’D FOR THE FUTURE INSTALLATION OF OPERATOR FURNISHED CHAIN WINDLASSES WILL BE PERFORMED DURING THE CONSTRUCTION PHASE AT THE SHIPYARD INCLUDING FOUNDATIONS / PRIMARY PIPING & WIRING.

A.7.1 ANCHOR WINCHES

Quantity no.:

N/AMake

Type (electric/hydraulic/diesel) :Rated pull mt

Speed low gear ft/m:

7

Test load :

Control locations (local/remote/both) :

Emergency release (type/location) :

A.7.2 FAIRLEADS

Foundations to be installed in shipyard Quantity no:

Make :

Free rotating range degrees:

A.7.3 ANCHORS

Company SuppliedA.7.3.1 ANCHORS - Primary

Company SuppliedA.7.3.2 ANCHORS - Spare

Company Supplied A.7.4 ANCHOR LINES

Company Supplied to be installed at later dateA.7.5 ANCHOR LINE RUNNING / RETRIE’ N/AA.7.5.1 PENNANT LINES

N/AA.7.5.2 ANCHOR BUOYS

N/AA.7.5.3 CHASER

N/A A.7.6 TOWING GEAR

Towing bridle size inches:

Installation of a tow bridle will be evaluated by the team.Hook-up system :Rating lt:

Power required for infield tow bollard pull lt:

N/APower required for ocean tow bollard pull lt:

N/ASpare bridle yes/no:

yes

A.7.7 SUPPLY VESSEL MOORING LINES :

Quantity no.: 4System mt:

TO BE EVALUATED BY TEAM Rating lt:

TBA

A.8 MARINE LOADING HOSES

Location of loading manifolds (port/stbd :

BOTH

A.8.1 POTABLE WATER HOSE Quantity no.:

2 x 150’Size inch:

3Make/Type :

TBAColor coding yes/no:

YESMake/Type/Connection

TBA

A.8.2 DRILLING WATER HOSE Quantity no.:


4Make/Type :


YESMake/Type connection :

TBA

A.8.3 GAS OIL HOSE Quantity no.:


4

8

Make/Type :


yesMake/Type connection :

TBAPRESSURE RATING p.s.i

150 wp

A.8.4 MUD CHEMICAL HOSE

Quantity no.:


5Make/Type :



TBA

A.8.5 CEMENT HOSE

Quantity no.:

2 x 150’Size inch: 5Make/ Type :



TBA

A.8.6 BASE OIL HOSE

Quantity no.:

2 x 150’Size inch: 4Make/Type :



TBAPressure Rating

150 psi wp

A.8.7 BRINE HOSE

Quantity no.: 2 x 150’Size inch:

4Make/Type :



TBA A. 9 CRANES, HOISTS, AND MATERIALS HANDLING

A. 9.1 CRANES, REVOLVING, MAIN

Quantity no.:

2Specification (API, etc.)

ABS /US-DENMake :

LIEBHERRType :

PEDESTALLocation (stbd, port, aft, frwd) :

PORT & STBDMaximum rated capacity (main hook) mt 100Maximum rated capacity (whip hook) mt

15Boom length ft:

150Line length (no Boom ft:

1893Main Hoist ft:

1920Whip line ft:

475Maximum capacity and hoisting speeds

Radius Metric

Main Hoist Platform Lift 4 lines Meters

Tons

6.6

92

9

10

92

11

92

15

84.7

20

71.8

25

62.8

30

55.6

35

47.2

40

39.7

45

33.8

48

31.1

No Load

Radius

MetricMain Hoist Seastate Lift 4 lines Meters

Tons

6.6 51.5

10

46

11

44.8

15

40.7

20

36.8

25

33.5

30

30.6

35 26.4

40

22.4

45

19.4

48

18

No load

Radius

MetricMain Hoist Platform Lift 2 lines Meters Tons

6.6

50

10

50

11

50

15

50

20

50

25

50

30 50

35

47.2

40

39.7

45

33.8

48

31.1

No load

Radius

MetricMain Hoist Seastate Lift 2 lines Meters

Tons

6.6

31.9

10

31.9

11

31.9

15

31.9

20 31.9

25

31.9

30

30.6

10

35

26.4

40

22.4

45

19.4

48

18

No Load

Radius

Metric

Meters

TonsWhip Line Platform Lift

51

15

Seastate lift

51

10

No Load

Hook load indicator automatically corrected for boom angle yes/no:

YESAlarm (audible, visual, both) : BOTHAutomatic brake yes/no:

YESSafety latch on hooks yes/no:

YESCrown saver (limit switch) yes/no:

YESBoom illumination yes/no:

YESBaskets for personnel transfer no.:

2

A. 9.2 CRANES, REVOLVING, SECONDARYQuantity no.:

1Specification (API, etc.) :

APIMake :

OUT REACHType :

KNUCKLEBOOMLocation (stbd, port, aft, frwd) :

FORWARDMaximum rated capacity (main hook) lt:

3.57Maximum rated capacity (whip hook) lt: N/ABoom length ft:

68Line length (nominal) ft:

N/A

A. 9.3 FORKLIFTS

Quantity no.:

1Make/Type :

TBARated capacity lt: TBAExplosion proof yes/no:

YES

A. 9.4 MONORAIL OVERHEAD CRANES

Quantity no.:

1Make :

MARITIME HYDRAULICS Type :

GANTRY TYPERated capacity mt 36Location :

AFT RISER DECK

A. 9.5 BOP HANDLING SYSTEM

Make/Type

HYDRALIFT BRIDGE CRANE Rated capacity (5 Ram Stack =551,300 lbs (250mt)) 310 T

BOP CARRIER

Make/Type

Hydralift “C” Cart complete with false rotary deck.Rated Capacity

310 Tons

11

A. 9.6 AIR HOISTS/DERRICK WINCHES

A. 9.6.1 RIG FLOOR WINCHES (Non man-riding)

Quantity no.:

4Make :

INGERSAL RANDType :

HYDRAULICRated capacity st:

5.5Wire diameter inch:

0.75Automatic brakes yes/no:

YESOverload protection yes/no:

NOAutomatic spooling yes/no:

YES

A. 9.6.2 MONKEY BOARD WORK WINCH

Quantity no.:

1Make : IRType :

Rated capacity st:

0.25Wire diameter yes/no:

3/8”Automatic brakes yes/no:

YESOverload protection yes/no:

NO

A. 9.6.3 RIG FLOOR “MAN-RIDING” WINCHQuantity no.:

2Make :

Ingersoll RandType :

HydraulicRated capacity st:

0.25Wire diameter/non-twist wire inch:

3/8”Automatic brakes yes/no:

YesOverload protection yes/no: NoAutomatic spooling yes/no:

YesCertified for man-riding yes/no:

Yes

A. 9.6.4 UTILITY WINCH (i.e. Deck Winch)

N/A A. 9.6.5 CELLAR DECK WINCH

Quantity no.: 4Make :

Ingersoll RandType :

AirRated capacity st:

5.5Wire diameter inch:

.75Automatic brakes yes/no:

NoOverload protection yes/no:

NoAutomatic spooling yes/no: YesMan -riding :

2

A.10 HELICOPTER LANDING DECK

Location

PORT/FWD. MAIN DECK Dimensions ft. x ft.:

72.8 X 72.8Perimeter safety net yes/no:

YESLoad capacity lt: 9.15

12

Designed for helicopter type :

SIKORSKY S-61Tie down points yes/no:

YESCovered by foam fire system (See L.36) yes/no:

YES A.10.1 HELICOPTER REFUELING SYSTEM

Fuel storage capacity U.S. gals:

1440Jettisonable yes/no:

NOFuel transport containers qty:

2Volume (ea) :

720Covered by foam fire system (See L.3.5) yes/no:

YES A.11 AUXILIARY EQUIPMENT

A.11.1 WATER DISTILLATION

Quantity no.: 4Make/Type

Alfa Laval or equivalentCapacity (each/total) cu. ft./day:

26 Metric Ton each (Depending on engine utilization) A.11.2 BROILERS

N/A A.11.3 AIR CONDITIONING

Quantity no.: 5Make/Type :

Capacity (total system) tons:

A.11.4 ELECTRIC WELDING SETS

Quantity no.:

3Current capacity amp:

400Make/Type : Lincoln S-7046 SAE 400

A.11.5 HIGH PRESSURE CLEANER Quantity no.:

1Make/Type : WeatherfordElectric/pneumatic :

ElectricMax delivered pressure psi:

2700Ring Main yes/no

YesOutlets Number

6 B. GENERAL RIG SPECIFICATIONS

B.1 DERRICK AND SUBSTRUCTURE

B.1.1. DERRICK/MAST

Make/Type :

DRECORated for wind speed:

With full set back knots:

100With no set back knots:

100Height ft:

210 estimated. Final height to be evaluated by Dreco.Dimensions of base ft x ft:

48X48Dimensions of crown ft x ft: 18x18Gross nominal capacity st.:

1250Maximum Number of lines no.:

14

13

Ladders with safety cages and rests yes/no:

yesPlatform for crown sheave access yes/no:

yesCounter balance, system for rig tongs and pipe spinning tong yes/no:

yesLighting system explosion proof yes/no: yes

(adjustable fingers on the right hand side can have any one of the casing below racked back at any one time, but not all)

Unit is capable of field transiting with 238 stands of drillpipe without exceeding rated design loads of derrick.

Make/Type : VarcoRacking platform total capacity with 5-1 ft:

31,000 (nominal)Fixed Fingers (on left side of derrick) - u ft: 20000 (nominal)Adjustable fingers (on right side) - 7” Ca ft:

11000 (nominal)or

Adjustable fingers (on right side) - 9-5/8 ft:

11000 (nominal)or

Adjustable fingers (on right side) - 13-3/ ft: 9500 (nominal)Racking platform capacity of 8” - 9” DC no.:

8

Auxiliary Derrick (Moonpool)

Make / Type

DrecoCapacity

300 Tons

B.1.3 AUTOMATIC PIPE RACKER

Make/Type :

2 - Varco PRS-6 Pipe Rackers

Pipe racker on forward side to be capable of handling 20”, 16”, 13-3/8”, 11-3/4”, 9-7/8”, 7-5/8”, and 7” casing

B.1.4 CASING STABBING BOARD

Make/Type :

Dreco / Hyd.Adjustable from/to height above R/table ft/ft: Adjustable Casing Stabbing Basket - 45’ reach

Auxiliary Pipe Handler (Moonpool)

Make / Type

National

B.1.5 SUBSTRUCTURE

Make/Type :

H.H.IHeight ft :

14.75’Width ft:

80Length ft: 71Setback capacity st:

1000Hookload st

1000Simultaneous setback-hookload capacity st:

2000Tensioner capacity st

1750Clear height below R/table beams (from ft:

29.5

B.1.6 WEATHER PROOFING

Rig floor windbreaks height ft:

10Derrickman windbreaks height ft:

15

14

B.1.7 DERRICK TV CAMERA SYSTEM

Camera located at :

Monkey Board/ CrownMake/Type : ColorZoom/Pan/Tilt-function yes/no:

yesMonitor located at : Driller’s House

B.2 DRAWWORKS AND ASSOCIATED EQUIPMENT

B.2.1 DRAWWORKS

Make/Type : Dreco/HitecDrum type :

Lebus Grooving, 2” drill line Spinning cathead type : Refer D 2.1.7Breakout cathead type :

N/ACrown block safety device :

YESMake :

Model :

Rated input power continuous hp: 6900Rated input power maximum hp:

8400Drum Diameter inches: 73.5Maximum line pull 14 lines st:

1000Maximum line pull 12 Lines

Maximum line pull 10 lines st:

600Maximum line pull 8 lines st:

Independent fresh water cooling system for

drawworks yes/no:

yes B.2.2 DRAWWORKS POWER

Number of electric motors no.:

8Make :

General ElectricModel :

GEB 22A1Output power continuous hp: 1150Output power intermittent (max.) hp:

1400 B.2.3 AUXILIARY BRAKE

Make :

HitecModel :

Regenerative AC braking,Independent back-up system type :

Failsafe disc brakes B.2.4 SANDLINE

NA B.2.5 AUTOMATIC DRILLER

Make/Type :

Hitec

AUXILIARY DRAWWORKS (Moonpool)

Make / Type

National / ACLift Capacity

300 TonsInput HP

1,000

15

B.3 DERRICK HOISTING EQUIPMENT

B.3.1 CROWN BLOCK

Make/Type :

DrecoRated capacity st: 1000No. of sheaves no.:

7Sheave diameter inches:

72Sheave grooved for line size inches:

2 AUXILIARY CROWN BLOCK (Moonpool)

Make / Type

DrecoRated Capacity

300 Tons B.3.2 TRAVELING BLOCK

Make/Type :

DrecoRated capacity st:

1000No. of sheaves no.: 7Sheave diameter inches:

72Sheave grooved for line size inch: 2

AUXILIARY TRAVELING BLOCK

Make / Type

DrecoRated Capacity

300 Tons

B.3.3 HOOK

N/AMake/Type :

Rated capacity st:

Complete with spring assembly/hook loc yes/no:

B.3.4 SWIVEL

Make/Type : NoneRated capacity st:

Test/working pressure psi/psi:

Gooseneck and washpipe minimum ID > yes/no:

Left hand pin connection size inches:

Access fitting for wireline entry on top o yes/no:

B.3.5 DRILLING LINE

Diameter inch:

2”Type : 6 x 26 EIPS, IWRCLength (original) ft:

12500Support frame for drum/cover yes/no:

yesDrilling line drum power driven yes/no:

yesSpare reel drilling line yes/no:

noLocation (rig, shore, etc.) :

B.3.6 ANCHOR DEAD LINE

Make/Type :

DrecoWeight sensor yes/no:

yes B.3.7 DRILL STRING MOTION COMPENSATOR

Make/Type :

Hitec ASA Active Heave Comp. Stroke ft:

14.5

16

Capacity - compensated st:

500Capacity - locked st:

1000 B.3.8 BLOCK GUIDANCE SYSTEM

Make/Type : DRECO B.3.9 RETRACTION SYSTEM FOR TRAVELING BLOCK

Make/Type :

Varco/Retrac. Dolly B.4 ROTATING SYSTEM

B.4.1 ROTARY TABLE

Make/Type :

VarcoMaximum opening inches:

60Rated capacity st:

1000Static load capacity st:

1000Rotating load capacity st @ rpm: TBATwo speed gearbox yes/no:

NoMax RPM @t Max Torque RPM/ Ft lbs 17/48000Emergency chain drive yes/no:

noDriven by an independent electric motor yes/no:

No Electric motor type/make :

Hydraulic x 4Maximum continuous torque ft/lbs:

48000Drip pan/mud collection system yes/no: yes

B 4.2 ROTARY TABLE ADAPTER BUSHING

Size “ 60 1/2 x 49 1/2Quanity :

1Size “ 49 1/2 x 37 1/2Quanty :

B.4.3 MASTER BUSHING

Make/Type : Varco MPCHSize inch:

37-1/2Inset Bushings #’s

3,2,1 B.4.4 KELLY BUSHING

B.4.5 TOP DRIVE

Make : National or Varco Type (electric/hydraulic) :

ElectricRated capacity st:

1000 or 750 (if 750 parking system to be supplied)Test/working pressure psi/psi:

11250 / 7500Remote operated kelly cock yes/no:

YESIf driven by electric motor

Make/Type :

GE GEB-20ACOutput power hp: 1150Output torque ft lbs:

Per Manufacturers ratingMax Torque @ Max RPM Ft lb/s RPM

Per Manufacturers ratingTwo speed gearbox yes/no:

NoMaximum rotary speed rpm:

270Cooling system type :

AIR

17

B.4.6 TOP DRIVE MAKEOUT/BREAKOUT SYSTEM

Make :

National or VarcoModel :

Type :

HYDRAULICMax. breakout torque that can be applied ft/lbs: 100000

B.4.7 RAISED BACKUP SYSTEM

Make :

VarcoModel :

RBS 4Torque rating : 100,000 Ft LbVertical Travel :

10 FtPipe range : 4 3/4” to 8 1/4”

C. POWER SUPPLY SYSTEMS

C.1 RIG POWER PLANT

C.1.1 DIESEL ENGINES


18V32Maximum continuous power hp:

7290At rotation speed of rpm:

720Equipped with spark arrestors yes/no:

YESMufflers installed yes/no: YESTotal fuel consumption, drilling (average bbl/day: Av 375. Estimate only, based on GOM weather and will vary

depending on operations C.1.2 DC - GENERATOR Type:

N/A C.1.3 AC-GENERATOR


TBAContinuous power kw: 7000At rotation speed of rpm:

720Output volts volts:

42,000 kwQuantity no.:

Make/Type :

Continuous power kw:

At rotation speed of rpm:

Output volts volts:

C.1.4 VARIABLE FREQUENCY DRIVES

Number of Inverters no.:

19 INVERTERSMake/Type :

TBAMaximum continuous power (total) kw:

15130 KWOutput volts volts:

0-600AC C.1.5 TRANSFORMER SYSTEM

Quantity no.:

8 THRUSTER TRANSFORMERS Make/Type :

TBAContinuous power (each) KVA:

5000 KVA

18

Output volts volts:

2300Frequency Hz:

60Quantity no.: 6 DRILLING TRANSFORMERS Make/Type :

TBAContinuous power (each) KVA: 2500Output volts volts:

600Frequency Hz:

60 C.1.6 EMERGENCY SHUTDOWN

Emer. shutdown switches for complete power sys.

CENTRAL CONTROL ROOM (AC and DC), located at the following points :

RIG FLOOR

ENGINE CONTROL ROOM C.1.7 AUXILIARY POWER SUPPLY

Power supply for a mud logging unit yes/no:

YESPower supply available:

Output volts volts: 480Frequency Hz:

60Current amps: 100Phase single/three

THREE C.1.8 COMPRESSED AIR SYSTEMS

Air Compressors - High Pressure:

Quantity no: 2Make :

HamworthyModel : w1234Rated capacity cu ft/hr:

65 cfmWorking press psi:

5000Prime mover (electric/diesel) hp:

ElectricalContinuous power hp:

60Air dryers

Quantity no.:

2Make/Type : Hamworthy Regenerative Tower (Dual) Rated Capacity cu ft/min:

Air Compressors - Medium Pressure (rig air):

Quantity no:

3Make :

Gardner DenverModel :

EGQSP Rotary ScrewRated capacity cu ft/hr:

750 SCFMWorking press psi: 125 psiPrime mover (electric/diesel) hp:

ElectricContinuous power hp:

200Air dryers

Quantity no.:

3Make/Type :

Dessicant Domnick Hunter / DX110 HeatlessRated Capacity cu ft/min:

1080 scfmAir Compressors - Low Pressure (bulk air):

None - Reducing Stations Quantity no:

2Make :

KimrayModel :

Reducing Valve / Back Pressure Valve ABY / AAU 3”Rated capacity cu ft/hr:

10,600 EachWorking press psi:

60

19

C.2 EMERGENCY GENERATOR - Emergency Generator not required due to power system design C.2.1 ENGINE AUXILIARY POWER PLANT

C.2.1 ENGINE

Data, for Anchored ver.may change for RBS8-DQuantity

no.:

1Make/Type

:

CATERPILLAR 3508BMaximum output kw: 500At rotation speed

rpm:

1200Starting methods (automatic, manual, air : AUTOMATICMax. angle of operation

degrees:

22.5 PER ABS

C.2.2 AC-GENERATOR

Quantity

no.:

1Make/Type : CATERPILLAR SR4Maximum output

kw:

500At rotation speed rpm: 1200Output volts

volts:

480Capable of back-feeding to main bus

yes/no:

YES - TO 480V BUS

C.3 PRIMARY ELECTRIC MOTORS

C.3.1 PROPULSION MOTORS

Type:

See Thruster Motors C.3.2 THRUSTER MOTORS

Quantity

no.:

8Type (AC/DC)

:

TBAPower of each

MW

5.5Total power MW

D. DRILLSTRING EQUIPMENT

D.1 TUBULARS

D.1.1 KELLIES

D.1.2 TOP DRIVE SAVER SUBS

Quantity no.: 2Connection type

:

HT 55API classification

:

8 CProtector

yes/no:

NoQuantity

no.:

2Connection type

:

4 1/2 IFAPI classification

:

8 CProtector yes/no: No

20

D.1.3 DRILL PIPE

Drill pipe OD

inch:

5.5Grade : S135Total length

ft:

22000Range : 3Weight

lbs/ft:

21.9 NonimalTensile yield strength Premium

lbs:

621000Internally plastic coated

yes/no:

Yes,TK-34Tool joint OD/ID

inch/inch:

71 /4” x 4” provisionalMake up torque Ftt/lbs 46300Tool joint pin length

inch:

10Tapered shoulder tool joints degree: 18Connection type

:

HT 55Type of hardfacing

:

Armacor MAPI classification

:

PREMIUMThread protectors

yes/no:

YesDrill pipe OD inch: 5Grade

:

S-135Total length ft: 8000Range

:

3Weight

lbs/ft:

19.5 NominalTensile yield strength Premium

lbs


yes/no:

Yes TK-34Tool joint OD/ID inch/inch: 6 5/8” x 3 1 1/6”make up Torque

Ft/lbs

32900Tool joint pin length inch: 9”Tapered shoulder tool joints

degree:

18Connection type

:

4 1/2 “IFType of hardfacing

:


:

PREMIUMThread protectors yes/no: YesDrill pipe OD

inch:

5.5Grade : S-135Total length

ft:

8000Range

:

3Weight

lbs/ft:

38Tensile yield s Premium

lbs


yes/no:

YesTool Joint OD/ID

inch/inch:

7 1/8 x 3 3/4 ProvisionalTool joint pin length inch: 10Tapered shoulder tool joints

degree:

18Connection type

:

HT 55Type of hardfacing

:


:

PremiumThread protectors

yes/no:

Yes D.1.4 DRILL PIPE PUP JOINTS ( Integral)

O.D

5.5”Grade/Yield

:

4145 H Equiv. To 120K

21

Tool joint OD/ID

inch/inch:

7 1/4 x 3 3/4 ”Weight

LB/FT

40Connection type

HT-55Stress relief pin groove

:

NoBoreback on box : NoInternally plastic coated

yes/no:

NoThread protectors

yes/no:

Yes,Length

ft:

10Quantity

no:

1Length ft: 15Quantity

no:


1O.D

:

5”Grade/ Yield

:

4145 H equiv to 120 KTool joint OD/ID

inch/inch:

6 5/8” x 2 3/4 ”Grade : 4145 H Equiv. To 120KWeight

LB/FT

TBAConnection type

4 1/2” IFStress relief pin groove

:

YesBoreback on box

:

YesInternally plastic coated

yes/no:

NoThread protectors

yes/no:

YesLength ft: 10Quantity

no:


no:

2Length

ft:

20Quantity

1Thread protectors

yes/no:

yes D.1.5 DRILL PIPE PUP JOINT:

Size:

N/A D 1.6 HEAVY WEIGHT DRILL PIPE (Integral)

Quantity

no.:

30Nominal size OD

inch:

5”Weight

lbs/ft:

49.1 NonimalRange

:

2Tool joint OD

inch:

6 5/8”Tool joint ID inch: 3 1/16”Pin Stress relief groove

yes/no

yesBox , Bore back

yes/no

yesType of hardfacing

:

Pinnchrome ( team to review) Internally plastic coated

yes/no:

NoConnection type

:

4 1/2 IFThread protectors

yes/no:

Yes, Bale typeQuantity no.: 30Nominal size OD

inch:

5 1/2”Weight

lbs/ft:

58” NonimalRange

:

2

22

Tool joint OD

inch:

7 1/4”Tool joint ID

inch:

3 3/4”Pin Stress relief groove yes/no NoBox , Bore back

yes/no

NoType of hardfacing : Pinnchrome ( Team to review) Internally plastic coated

yes/no:

NoConnection type

:

HT 55Thread protectors

yes/no:

yes, Bale type

D.1.7 DRILL COLLARS

Quantity

no.:

15OD body inches: 9.5ID body

inches:

3”Nominal Length of each joint

ft:

31.5 NominalDrill collar body (slick/spiral)

:

SPIRALRecess for “zip” elevator

yes/no:

yesRecess for slips yes/no: yesStress relief pin groove

yes/no:

YESBoreback on box yes/no: YESB.S.R

2.72Connection type

:

7 5/8”regThread protectors

yes/no:

yes, Bale typeQuantity

no.:

15OD body inches: 8 1/4”ID body

inches:

2 13/16”Nominal Length of each joint ft: 31.5 Ft NomimalDrill collar body (slick/spiral)

:

SPIRALRecess for “zip” elevator

yes/no:

yesRecess for slips

yes/no:

yesStress relief pin groove

yes/no:

YESBoreback on box yes/no: YESB.S.R.

2.93Connection type yes/no: 6 5/8” regThread protectors

yes/no:

yes, Bale typeQuantity

no.:

30OD body

inches:

6 1/2ID body

inches:

2 1/2”Nominal Length of each joint

ft:

31.5 Ft NominalDrill collar body (slick/spiral)

:

SPIRALRecess for “zip” elevator yes/no: YESRecess for slips

yes/no:

YESStress relief pin groove

yes/no:

YESBoreback on box

yes/no:

YESB.S.R

2.73Connection type

yes/no:

4 ” IFThread protectors

yes/no:

yes, Bale type

D.1.8 SHORT DRILL COLLARS

Company SuppliedD.1.9 NON-MAGNETIC DRILL COLLARS

Company SuppliedD.1.10 CORE BARRELS

Company Supplied

23

D.1.11 STABILIZERS

Company SuppliedD.1.12 ROLLER REAMERS

Company SuppliedD.1.13 SHOCK ABSORBERS (Damping Sub)

Company SuppliedD.1.14 DRILLING JARS

Company Supplied D.1.15 INSIDE BOP VALVE

Quantity

no.:

2Make

:

SMF (provisional)OD

inch:

TBAConnection type : HT 55Working pressure rating

psi:

15000Quantity no.: 2Make

:

SMF (provisional)OD

inch:

6 5/8”Connection Type

4 1/2 IFWorking Pressure

psi

15000

D.1.16 FULL OPENING SAFETY VALVE

Quanty

2Make

:

SMF ( provisional)O.D/ I.D

no.:

TBA ( Team to review & advise ) Connection type

:

HT 55Working Pressure

15000Quanty

2Make

:

SMF ( provisional)O.D/ I.D no.: 6 5/8” / 2 13/16”Connection type

:

4 1/2 IFWorking Pressure

15000

D.1.17 CIRCULATION HEAD

N/A D.1.18 TOP DRIVE VALVES

Upper

Quantity

no.:

2Make/Type

:

VarcoWorking pressure

psi:

15000Max. OD body

inch:

TBAMin. ID body

inch:

TBAConnection type

:

7 5/8 RegLower

Quantity

no.:

2Make/Type

:

VarcoWorking pressure

psi:

15000Max. OD body

inch:

TBAMin. ID body

inch:

TBAConnection type

:

7 5/8 Reg D.1.19 CIRCULATION SUBS

Company SuppliedD.1.20 CUP TYPE TESTERS

Company SuppliedD.1.21 PLUG TYPE TESTERS

Company SuppliedD.1.22 DROP-IN VALVES

Company Supplied

24

D.1.23 NEAR-BIT SUBS (Box-Box)

Quantity

no.:

2OD size inch: 9 1/2”ID size

inch:

3”Top connection inch: 7 5/8 RegBoreback

Yes/No

YesBSR

:

2.25. - 3Bottom connection

inch:

7 5/8 REGBoreback

Yes/No

NoBored for float valve yes/no: yesFloat size

inch:

5F-6RQuantity no.: 2OD size

inch:

9 1/2”ID size

inch:

2 13/16”Top connection

inch:

7 5/8 REGBoreback

Yes/No

YesBSR : 2.25 - 3Bottom connection

inch:

6 5/8 REGBoreback Yes/No NoBored for float valve

yes/no:

YESFloat size

inch:

5F-6RQuantity

no.:

2OD size

inch:

8 1/4”ID size inch: 2 13/16”Top connection

inch:

6 5/8 RegBoreback Yes/No YesBSR

:

2.25 - 3Bottom connection

inch:

6 5/8 RegBoreback

Yes/No

NoBored for float valve

yes/no:

YESFloat size inch: 5F-6RQuantity

no.:

2OD inch: 6 1 /2ID

inch:

2 1/2”Top connection

inch:

4 1/2 XHBoreback

Yes/No

YesBSR

:

2.25 - 3Bottom connection

inch:

4 1/2 RegBoreback

Yes/No

NoBored for float valve yes/no: YESFloat size

inch:

4 R D.1.24 CROSSOVER SUBS

Quantity

no.:

2OD size

inch:

8 1/4” x 9 1/2”Top connection size

inch:

6 5/8 REGType (pin/box) : BOXI.D

:

2 13/16”B.S.R

:

2.25 - 3Boreback

Yes/No

YesBottom connection size

inch:

7 5/8 REGType (pin/box)

:

PIN

25

I.D :

3”B.S.R :

2.25 - 3Relief Groove Yes/No

YesQuantity no.:

2OD size inch:

7 1/4” x 8 1/4”Top connection size inch:

HT 55Type (pin/box) :

BOXID inch:

3”B.S.R :

2.25 - 3Boreback Yes/No

NoBottom connection size inch:

6 5/8 RegType (pin/box) :

PINI.D :

3”B.S.R :

2.25 - 3Relief Groove Yes/No YesQuantity no.:

2OD inch:

7 1/4” x 6 1/2”Top connection size inch:

HT 55Type (pin/box) :

BOXID inch:

2 1/2”B.S.R :

2.25 - 3Boreback Yes/No NoBottom connection size inch:

4 1/2 XH (NC 46)Type (pin/box) :

PINI.D :

2 1/2”B.S.R :


YesQuantity no.:

2OD size inch: 6 1/2” x 8 1/2”Top connection size inch:

4 IF (NC 46)Type (pin/box) :

BOXID inch:

2 1/2”B.S.R :


YesBottom connection inch:

6 5/8 RegType (pin/box) : PINID inch:

2 1/2”B.S.R :


YesQuantity no.:

2OD size inch:

7 1/4 x 6 5/8Top connection size inch:

HT55Type (pin/box) : BoxID size inch:

2 13/16”B.S.R :


NoBottom connection size inch:

4 1/2 IF (NC 50)Type (pin/box) :

PinID size inch:

2 13/16”B.S.R : 2.25 - 3Relief Groove: Yes/No

YesQuantity no.:

2

26

OD size inch:


4 1/2 IF (NC 50)Type (pin/box) :

BoxID size inch:

2 1/2”B.S.R :


YesBottom connection size inch:

4 IF (NC 46)Type (pin/box) :

PinID size inch:

2 1/2”B.S.R :


YesQuantity no.:

2OD size inch:


4 1/2 IFType (pin/box) : BoxID size inch:

2 13/16”B.S.R :


YESBottom connection size inch:


PinID size inch:

2 13/16”B.S.R : 2.25 - 3Relief Groove Yes/No

Yes D 1.25 STABBING SUBS - Approximately 9” long

Quantity no.:

1OD size inch:

9.5ID size inch:

3Top connection size inch: HT 55Type (pin/box) :

BoxBottom connection size inch:


PINQuantity no.:

1OD size inch:

9.5Top connection size inch:

4 1/2 IFType (pin/box) : BoxID size inch:

3Bottom connection size inch:


PINQuantity no.:

1OD size inch:

8.25ID size inch:

2 13 /16Top connection size inch: HT 55Type (pin/box) :

BOXBottom connection size inch:

6 5/8 REGType (pin/box) :

PINQuantity no.:

1OD size inch:

6.5ID size inch:

2.8125Top connection size inch: HT 55Type (pin/box) :

BOXBottom connection size inch:

4 IF

27

Type (pin/box) :

PIN D.1.26 PUMP IN / TESTING SUBS

Quantity Pin/Box

1Connection

HT 55 BoxUnion type

2” 1502 FemaleQuantity

1Connection Pin/Box

HT 55 PinUnion Type


1Connection Pin/Box

4 1/2 IF BoxUnion type


1Connection Pin/Box

4 1/2 IF PinUnion type 2” 1502 FemaleQuantity

1Connection Pin/Box

7 5/8 Reg PinUnion Type

2” 1502 Female D 1.27. SIDE ENTRY SUBS

Quantity

1Top Connection Box/Pin HT 55 BoxLower connection

HT 55 PinOutlet size and type


1Top Connection Box/Pin

4 1/2 IF BoxLower connection

4 1/2 IF PinOutlet size and type

2” 1502 Female

D.1.28 DRILLING BUMPER SUBS

Company SuppliedD.1.29 HOLE OPENERS

Company SuppliedD.1.30 UNDERREAMERS

Company Supplied D.2 HANDLING TOOLS

D.2.1 DRILL PIPE ELEVATORS

Quantity :

2Make :

VarcoModel st:

BX 475Drill Collars inserts 150 Ton

6 1/2” , 8 1/4” , 9 1/2”Casing inserts 350 Ton “

Company SuppliedDrill pipe Inserts 500 Ton

5 , 5 1/2”Elevators 750 Ton 5”, 5-1/2”BOP handling elevators st:

1000 Refer E 6.10

D.2.2 DRILL COLLAR ELEVATORS

Size inch:

N/AQuantity no.:

Make :

Model :Rated capacity st:

28

Size inch:

N/AQuantity no.:

Make :

Model :

Rated capacity st:

Size inch:

N/AQuantity no.:

Make :

Model :

Rated capacity st:

Size inch:

N/AQuantity no.:

Make :

Model :

Rated capacity st: D.2.3 TUBING ELEVATORS Type:

Company Supplied D.2.4 DRILL PIPE HAND SLIPS

Size inch

5 1/2 ”Quantity no.:

1Make/Type : VARCO / SDXLSize inch

5Quantity no.:

1Make/Type :

VARCO / SDXL D.2.5 POWER SLIPS

Make/Type

Varco PS 30Quantity 1Slip assembly 20” to 18 5/8”

1Slip Assmebly 16 ” to 6 5/8

1Slip Assembly 2 3/8 to 10 3/4”

1Insert carriers Drillpipe :

5 ”, 5 1/2” ,Insert Carriers Drill collars

6 1/2, 8 1/4,9 1/2Insert carriers Casing

Company suppliedDie sets for 13 3/8” 9 5/8 & 7” carriers Company supplied

MOUSEHOLE SLIPS

Varco 18” Power Slips. D.2.6 DRILL COLLAR SLIPS

Size inch:

9.5Quantity no.:

1Make/Type : VARCO / DCS-LSize inch:

8.25Quantity no.:

1Make/Type :

VARCO / DCS-LSize inch:

6.1/2Quantity no.:

1Make/Type :

VARCO / DCS-R

D.2.7 DRILL COLLAR SAFETY CLAMPS

Quantity no.:

1

29

Model

MP-LRange :

19 3/8” to 4 1/2 “ D.2.8 TUBING SLIPS :

Company SuppliedD.2.9 TUBING SPIDER :

Company SuppliedD.2.10 DRILL COLLAR LIFTSUBS :

As neededD.2.11 DC LIFTING PLUGS :

n/a D.2.12 BIT BREAKER

Quantity no.:

1For bit size inch:

26Quantity no.:

1For bit size inch:

17.1/2”Quantity no.:

1For bit size inch: 14 3/4”Quantity no.:

1For bit size inch:

12. 1/4Quantity no.:

1For bit size inch:

8.1/2

D.2.13. GAUGE RINGS

Sizes 26, 17 1/2, 14 3/4, 12 1/4, 8 1/2 D.2.14 ELEVATOR LINKS

Quantity of sets no.:

1Make/Type :

VARCOSize inch:

3.5Length ft:

11Rated capacity st: 500Quantity of sets no.:

1Make/Type :

VARCOSize inch:

4 3/4”Length ft:


750Quantity of sets no.:

1Make/Type : VARCOSize inch:

4 3/4”Length ft:


1000

D.2.15 DRILL PIPE SPINNER Type:

Varco SSW-40 D.2.16 MUD SAVER BUCKET

Make :

DrecoSize inch:

9 3/4 to 3 1/2”Operation :

Remote from DWS D.2.17 EZY TORGUE

Make/Type :

VarcoMaximum linepull lb: 31000Quantity

2

30

D.2.18 ROTARY RIG TONGS

Quantity no.:

2Make/Type :

Varco HT 100Size range (max OD/min OD) inch/inch:

17 to 4Torque rating ft lbs:

Max 100,000, reduces depending on size Quantity no.:

2Make/Type :

Varco HT 50Size range (max OD/min OD) :

17 1/4 to 20”Torque rating Ft/lb:

50000

D.2.19 TUBING TONGS (MANUAL)

D.2.20 TUBING TONGS (POWER)

D.2.21 IRON ROUGHNECK

Make/Type : VARCO / AR3200Size range (max OD/min OD) Drill Coll inch/inch:

4 “ to - 9 1/2”Size range (max OD/min OD) Drillpipe

3 1/2” to 6 5/8

D.3 FISHING EQUIPMENT

D.3.1 OVERSHOTS


F.STop sub connection type :

6 5/8 RegOvershot OD inch:

11 3/4”Max catch size inch:

9 1/2”To catch size Spiral grapple inch:

9.1/2

9 3/8,8 1/2,8 3/8,8 1/4,8 1/8,7 1/4,7 1/8,7, 6 7/8, 6 5/8,6To catch size Basket grapple inch: 1/2, 6 3/8, 5 1/2, 5Control rings

For above grapplesExtension sub length ft:

2.5Lipped guide (oversize, regular) “:

113/4,15, 21Quantity no.:

1Make/Type :

TBA S.H Series 150Top sub connection type :

4 IFOvershot OD inch: 8.3/8Max catch size inch:

7 1/4”To catch size Spiral grapple inch:

7 1/4, 7 1/8, 7, 6 7/8,To catch size Basket grapple inch:

6 5/8, 6 1/2, 6 3/8, 5 1/2, 5Control rings

For above grapplesExtension sub length ft:

2.5Lipped guide (oversize, regular) :

8 3/8, 11,

D.3.2 HYDRAULIC FISHING JAR

Company SuppliedD.3.3 JAR INTENSIFIER

Company SuppliedD.3.4 SURFACE JAR

Company Supplied D.3.5 FISHING BUMPERSUBS

Quantity no.:

1Make/Type : TBAOD body inch:

8Min.ID inch:

3.5

31

Stroke inch:

20Connection type :

6 5/8 RegQuantity no.:

1Make/Type :

TBAOD body inch:

6.25Min. ID inch:

2.25Stroke inch:

20Connection type :

4 IF

D.3.6 SAFETY JOINTS

Company SuppliedD.3.7 JUNK BASKETS (REVERSE CIRC.)

Company SuppliedD.3.8 JUNK SUBS

Company SuppliedQuantity no.:

1Make/Type :

TBAFor hole size inch: 17.5Boot OD inch:

12.875Connection type :

7 5/8 RegQuantity no.:

1Make/Type :

TBAFor hole size inch:

12.25Boot OD inch:

9.625Connection type : 6 5/8 RegQuantity no.:

1Make/Type :

TBAFor hole size inch:

8.5Boot OD inch:

6.625Connection type :

4 1/2 Reg

D.3.9 FLAT BOTTOM JUNK MILL Company Supplied D.3.10 MAGNET FISHING TOOL

Quantity no.:

1Make/Type :

TBA/ Flush guide OD body inch:

16Hole size inch:

17.5Connection type : 6 5/8 reg

D.3.11 TAPER TAPS

Company SuppliedD.3.12 DIE COLLARS

Company Supplied

E. WELL CONTROL/SUBSEA EQUIPMENT

E.1 LOWER RISER DIVERTER ASSY N/A E.2 PRIMARY BOP STACK (from bottom to top)

Stack complete with:

guide frame yes/no:

YES pick up attachment yes/no:

YES transport base yes/no:

YESSize (bore) inch:

18.75Working pressure psi:

15000H2S service yes/no: YES

32

E.2.1 ALTERNATE HYDRAULIC CONNECT N/A

E.2.2 HYDRAULIC WELLHEAD CONNECTOR

Size inch:

18-3/4”Make/Type :

Vetco SD H-4Working pressure psi:

15000Hot tap for underwater intervention ROV yes/no:

YESSpare connector same type yes/no:

NOHydrate seal yes/no:

Yes (1 oring & 1 Lip seal Option as STD.)Glycol Injection ( ROV) yes/no:

yes (4 x 1” Npt @ 90 deg increments Pilot Operated check Valve, close function Yes/No:

Yes

E.2.3 RAM TYPE PREVENTERS

Preventers:

Quantity no.: 5Bore size inch:

18.3/4”Working Pressure psi:

15000Make :

CAMERON or equivalentModel :

TYPE T1Type (single/double) :

Double x2 , Single x 1Stack Configuration :

Al, A2, CL, SSCSR BSR,VBR,VBR,LFPR,CH Ram locks yes/no:

YESPreventer connection type - top :

CX18 (BX-164 Option Available) Preventer connection type - bottom :

CX18 (BX-164 Option Available) Side oultlets yes/no:

YESSize inch:

3.1/16Connection type :

No. 6 CAMERON CLAMP AX GROOVESuper/Shear rams: Less than or equal to 13-5/8” Quantity no.:

1 setBlind/Shear rams:

Quantity no.:

1 setVariable rams:

Quantity no.:

1 setSize range (max/min) inch/inch:

Customer to adviseQuantity no.: 1 setSize range (max/min) inch-inch:

Customer to advisePipe rams:

Quantity no.:

1 setSize inch:

Customer to advse

E.2.4 STACK CONFIGURATION

(Blind/Shear/Pipe/Variable) Upper Shear ra Cavity 5

SSCSR (Less than or equal to 13-5/8”) Lower shear ra Cavity 4 :

BSRMiddle Upper Cavity 3 :

VBRMiddle Lower Cavity 2 :

VBRLower rams Cavity 1 :

LFPRPosition of side outlets - kill

Upper : Below BSR (Cavity #4)Lower :

Below LFPR (Cavity #1)

33

Position of side outlets - choke

LMRP

Below upper Annular (Al)Stack

Below Top VBR (Cavity #3) Stack :

Below Bottom VBR (Cavity #2)

E.2.5 ANNULAR TYPE PREVENTER ON STACK

Size inch:

n/aWorking pressure psi:

n/aMake/Type :

n/a

E.2.6 MANDREL

Make/Type :

Cameron 18-3/4 10 HCSize inch:

18.75

E.2.7 FAIL-SAFE HYDRAULIC VALVES (Kill and Choke)

Quantity on each side outlet no.:

2Size (ID) inch:

42430Make/Type :

Cameron MCSWorking pressure psi:

15000Solid block yes/no:

YES

E.2.8 SUBSEA ACCUMULATORS

(See also E.7.1 - Surface Accummulator Unit)

Quantity no.:

17 ( team to evaluate)Useful capacity per accumulator (w/o prUS gallons :

13.1Bottle working pressure psi:

5000 (team to evaluate)

E.2.9 HYDRAULIC CONTROL POD/RECEPTACLESQuantity no.:

2Redundancy %:

100Color Coded yes/no:

YESRemote regulation of operating pressure for

functions requiring lower operating press yes/no:

YESSpare control pod yes/no:

NODeadman system yes/no: YESPressure & tempreture Sensor’s LMRP yes/no:

YES

E.3 PRIMARY LOWER MARINE RISER PACKAGE

(From Bottom To Top)

E.3.1 HYDRAULIC CONNECTOR

Make/Type :

Cameron 18-3/4-10 HC or equivalent Size inch: 18.75Working pressure psi:

10000Hot tap for underwater intervention yes/no:

YESSpare connector same type yes/no:

NO

E.3.2 ANNULAR TYPE PREVENTER (LMRP)

Size inch:

18-3/4”Qty. no: 2Working pressure psi:

10000Make/Type (2*70.5=141” Total Heigl :

CAMERON TYPE DL

34

E.3.3 FLEX JOINT

Make/Type :

Oil States 18-3/4”Size inch:

21Max deflection degrees:

20 (10 from vertical)

E.3.4 RISER ADAPTER

Make/Type :

Vetco HMF-class HSize inch:

21

E.3.5 CONNECTION LINES TO RISER

Type (rigid loops, coflexip, etc.) Make:

COFLEXIP

Size:

3-1/16

WP:

15,000 psi

Collapse Psi

12,7l0psi

E.3.6 RISER CENTRALIZER

Hydralift E.4 ANNULAR GAS HANDLER

Make / Type

Supplied by Company at later date. Hard piping and control functions to be supplied by Contractor

Rating

1,500 psiNumber Outlets 2Number Valves

4

E.5 SECONDARY LOWER MARINE RISER P N/A

E.6 PRIMARY MARINE RISER SYSTEM

E.6.1 MARINE RISER JOINTS To be designed for 10,000’ wd

Make/Model :

Vetco or equivalent (HMF-class H) OD inch

To be determined by final riser analysis ID inch

To be determined by final riser analysis Wall thickness inch:

To be determined by final riser analysis Average length of each joint ft:

90

62,311 for 5k buoancy, 54,424 for 3k buoancy, 31,620 Weight of one complete joint (in air) Ibs: for 3/4” Slick, 36,900 1” slick Quantity no.:

Sufficient for 8,000 ft. water depth Pipe material grade:

API 5L Grade X80 Mod.Minimum yield strength psi:

80KSIType riser connectors :

HMF- class HDogs no.:

To be determined by final riser analysis Pup joints: Quantity no.:

1Length ft:

45.0’Quantity no.:

1Length ft:

37.5’Quantity no.:

1Length ft:

30.0’Quantity no.: 1Length ft:

22.5’

35

Quantity no.:

1Length ft:

15’

E.6.2 TELESCOPIC JOINT

Make/Type :

VetcoSize (ID) inch:

19.25Stroke ft:

65Double Seals yes/no:

YESWorking pressure psi

500Spare telescoping joint yes/no:

noLocation :

N/ARotating support ring for riser tensioners type:

Vetco SDCConnection points no.:

6

E.6.3 KILL/CHOKE LINES Quantity no.:

2Outside diameter inch:

6.5Inside diameter inch:


15000LMRP Isolation valves YES/NO

YES. Fail Close

E.6.4 BOOSTER LINES (If Fitted) Quantity no.:

1Outside diameter inch:

4.5Inside diameter inch:


6000LMRP Isolation valve YES/NO

YES

E.6.5 HYDRAULIC SUPPLY LINES Quantity no.:

1Outside Diameter inch:

3.5Inside Diameter inch:


5000

E.6.6 UPPER BALL (FLEX) JOINT

Make/Type : Oilstates Diverter 3Size inch:

21-1/4Maximum deflection deg.:

30 (15 from vertical)Spare upper ball (flex) joint yes/no.:

NO

E.6.7 BUOYANCY MODULES (If Fitted)

Make :

To be determined by riser analysis Quantity of buoyed riser joints no.: To be determined by riser analysis OD of buoyed riser joints inch:

To be determined by riser analysis Length of each module ft:

To be determined by riser analysis Volume of each module ft3:

To be determined by riser analysis Buoyancy in seawater st/ft3:

To be determined by riser analysis Rated water depth ft:

To be determined by riser analysis Make :

To be determined by riser analysis Quantity of buoyed riser joints no.: To be determined by riser analysis OD of buoyed riser joints inch:

To be determined by riser analysis

36

Length of each module ft:

To be determined by riser analysis Volume of each module ft3:

To be determined by riser analysis Buoyancy in seawater st/ft3:

To be determined by riser analysis Rated water depth ft:

To be determined by riser analysis

E.6.8 MARINE RISER SPIDER

Make/Type :

VETCO / HYDRAULIC

E.6.9 Marine Riser Gimbal

Make/Type :

VETCO

E.6.10 RISER HANDLING TOOLS

Tool, riser lifting no.:

31000 ton Solid Body Elevators no :

1 set ( team to evaluate)Type : HMF- Class hTorque Wrenches :

2 - dual speed

E.6.11 RISER TEST TOOLS

Quantity no.:

2Type :

HMF- Class H Hydraulic Test Tool

E.6.12 INSTRUMENTED RISER JT : N/A

E.7 SECONDARY MARINE RISER :

N/A

E.8 DIVERTER BOP

(For installation in fixed bell nipple)

Make/Type :

Hydril 60Max Bore Size inch: 21-1/4Working pressure psi:

500Number of diverter outlets no.:

2Outlet OD inch:

14Insert packer size ID inch:

N/A CSOElement type. :

Nitrile rubberRunning from diverter to :

Overboard , port/ starb./ Poorboy MGS

E.8.1 DIVERTER FLOWLINE

Quantity no.:

1I.D of flowline inch:

16” NominalValve types :

Diverter SleeveSize inch:

16Working pressure psi:

500Control valve type (air/hydraulic/etc.) : HYDRAULICRemote controlled from location:

DRILLERS WORKSTATION

E.8.2 DIVERTER CONTROL PANELS

Driller’s panel

Make :

CAMERON OR EQUIVALENT Model :

MULTIPLEXLocation : DRILLERS WORKSTATION Locking/unclocking control yes/no:

YES

37

Remote panel

Make

: CAMERONModel

: MULTIPLEXLocation

: CONTROL ROOMLocking/unclocking control yes/no : YES

E.9 SUBSEA SUPPORT SYSTEM

E.9.1 RISER TENSIONERS

Ability To Skid Tensioners From Well CenterlineQuantity no.: 6Make/Type :

HYDRALIFT - INLINE Capacity each tensioner st: 800 kipsMaximum stroke ft:

50Wireline size inch:

N/A (9” ROD)Line travel ft:

N/A (9” ROD)Independent air compressors yes/no:

YESIndependent air drying unit yes/no: YESRiser Recoil System yes/no:

yes E.9.2 GUIDELINE SYSTEM

N/AE.9.3 REMOTE GUIDELINE REPL. TOOL

N/AE.9.4 REMOTE GUIDELINE CUTTING TOOL

N/AE.9.5 POD LINE TENSIONERS

TURN DOWN SHEAVE’S COMPLETE WITH STORM LOOP WITHIN MOONPOOL INCLUDED WITHIN DESIGN LAYOUT

E.9.6 TENSIONER/COMPENSATOR AIR PRESSURE VESSELS

Quantity no.:

30Total capacity ft3:

2747Rated working pressure psi:

3000Pressure relief valve installed yes/no: YES

E.10 BOP CONTROL SYSTEM

Cameron or equivalent Mux system including: 2 each remote control panels, one located in driller’s house and one in the control room, both panels incorporate full function and monitoring system for BOP’s and diverter system. 1 each pod test stand and Mux system analyzer consisting of test stand and portable computer test set. 2 each Mux cable reels complete with 11,000’ of Multiplex cable, one reel blue and one reel yellow for functioning yellow and blue pods plus one spare. 2 each stack mounted pods, complete with subsea electronics

E.10.1 SURFACE ACCUMULATOR UNIT

(See also E.2.8 & E.4.8 - Subsea Accumulators)

Make : CAMERON or equivalent Model/Type :

MUXLocation :

ACCUMULATOR ROOM Soluble oil reservoir capacity US gallons:

300Oil/water mix.capacity US gals/min:

838Glycol reservoir capacity US gallons:

1000

38

No. of bottles installed no.:

38 team to evaluate bottles required for 10,000’Useful cap. per accum. (w/o pre-charge)US gallons :

40Bottle working pressure psi: 5000Control manifold model :

MULTIPLEXRegulator type : PRESSURE SWITCH / RELIEF VALVESTotal useful accumulator volume (surface and stack)

Equals all preventer opening and closing yes/no:

YESPlus percent additional volume %:

50 E.10.2 ACCUMULATOR HYDRAULIC PUMPS

Electric Driven

Quantity no.: 2Power source :

From BUS AMake :

US MotorsModel :

Each driven by motor of power hp:

100Flow rate of each pump US gals/min: 26At minimum operating pressure psi:

5000Secondary

Quantity no.:

1 Power source :

From BUS BMake :

US MotorsModel :

Each driven by motor of power hp: 100Flow rate of each pump US gals/min:

26At minimum operating pressure psi: 5000

E.10.3 DRILLER’S CONTROL PANEL

Graphic control panel at driller’s position showing subsea functions with controls for the following functions of the BOP stack Location. Driller Work Station. Boost Line Control Valve yes/no:

YESMarine riser connector yes/no: YESAll annular type BOP’s yes/no:

YESAll ram type BOP’s yes/no:

YESLock for ram type BOPs yes/no:

YESWellhead and LMRP connector yes/no:

YESInner and outer kill and choke line valve: yes/no:

YESLow acc. pressure warning yes/no:

YESLow reservoir level warning yes/no: YESLow rig air pressure warning yes/no:

YESPressure regulator for annular yes/no:

YESFlowmeter yes/no:

YESQuantity of pressure gauges no.:

7+Emergency push button for automatic riser disconnection :

YES Other control functions yes/no:

YESControl panel make : CAMERONControl panel model :

MULTIPLEX

39

E.10.4 REMOTE CONTROL PANELS

Ability to operate main closing unit valv yes/no:

NOQuantity no.: 2Make/Model :

CAMERON / MULTIPLEX Locations : DRILLERS WORK STATION & CONTROL ROOMOperating System Routing (Direct/via Primary Control

Panel) :

DIRECT DUAL BUS E.11 SUBSEA CONTROL SYSTEM

E.11.1 HOSE REELS

Quantity no.: 2 Bop Control (MUX)Location :

MOONPOOLMake/Type :

CAMERONMaximum storage length each ft:

11000Drive motor type :

AIRQuantity no.: 1 HOTLINELocation :

MOONPOOLMake/Type : SYNFLEX (KEVLAR) Maximum storage length each ft:

11,000Drive motor type :

AIR E.11.2 POD HOSE

E.11.3 POD HOSE MANIFOLD

Make/Model : NONESurface test stump yes/no:

YES E.11.4 SURFACE TEST POD yes/no:

N/A E.12 ACOUSTIC EMER. BOP CONTROL SYS : N/A E.13 SUBSEA AUXILARY EQUIPMENT

E.13.1 HOLE POSITION INDICATOR

Make/Type :

SimradQuantity of monitors no.:

2 (Blue pod / Yellow pod) Monitor location :

Drillers Work stationMonitor location :

Control RoomRecorder yes/no: no

E.13.2 RISER ANGLE INDICATOR

Make/Type :

To be incorporated into Mux system Quantity of monitors no.:

2 (Blue pod / Yellow pod) Monitor location :

Drillers Work stationMonitor location :

Control RoomRecorder yes/no: noLocation

Flex joint neck E.13.3 SLOPE INDICATORS

Make :

RECAN

40

Quantity no.:

3Provision for installation on

BOP yes/no: YESPin Connector yes/no:

NOOther : LOWER STACK, LMRP & RISER

E.13.5 ROV System

Power and foundations supplied E.14 CHOKE MANIFOLD

Per Drawing # D-233669 E.14.1 CHOKE MANIFOLD (For Instrumentation, see H.3)

Make : CONTROL FLOWMinimum ID inch:

3-1/16Maximum WP psi:

15000H2S service yes/no:

YESQuantity of fixed chokes no.:

n/aMake : n/aModel :

n/aSize (ID) inch: n/aQuantity of adjustable chokes no.:

n/aMake :

n/aModel :

n/aSize (ID) inch:

n/aQuantity of power chokes no.: 3 ( team to evaluate)Make :

CONTROL FLOWModel : 15000Size (ID) inch:

2 Team to evaluatePower choke remote control panel yes/no:

YESMake :

Houston DigitalModel :

CPU 27” MONITOR AND MANUAL HYD. BACK-UP.Location : DRILLERS WORKSTATION / CHOKE MANIFOLDGlycol injection yes/no:

NO E.14.2 FLEXIBLE CHOKE AND KILL LINES (Connecting Riser to Drilling Unit)

Quantity no.:

2Make/Type :

CoflexipID inch:

3 ( team to review)Working pressure/test pressure psi/psi:

15000 / 22500Quantity no.:

n/aMake/Type : n/aID inch:

n/aWorking pressure/test pressure psi/psi:

n/a E.15 BOP TESTING EQUIPMENT

E.15.1 HYDRAULIC BOP TEST PUMP

Make : SHAFFERModel/Type :

ELECTRO HYDRAULIC VARIABLE SPEED 5 GPMPressure rating psi:

22500

41

Chart recorder yes/no:

0-5000 0-30000

E.15.2 BOP TEST STUMP

Quantity no.:

1Test pressure psi: 15000Type :

VETCO / CAMERON Size :

18.75Connected to deck (welded/bolted) :

BOLTED E.16 WELLHEAD RUNNING/RETRIEVING/TESTING TOOLS (RT/RRT/TT) E.16.1 RT’s FOR CASING INSTALLATION

Company SuppliedE.16.2 RRT’s FOR CASING INSTALLATION

Company SuppliedE.16.3 MISCELLANEOUS TOOLS

Company SuppliedE.16.4 DP HANG-OFF SUBS

Company SuppliedE.16.5 MINI HOSE BUNDLE FOR HYD. R. TOOLS

Company Supplied E.16.6 EMERGENCY BOP RECOVER yes/no:

yesMake/type : CAMERON

F.1 HIGH PRESSURE MUD SYSTEM

System working pressure psi:

7500System test pressure psi:

11250Built to which design standard : ANSI, API

F.1.1 MUD PUMPS

Quantity no.:

4Make :

NationalModel :

14P-220Type (Triplex/Duplex) :

TriplexLiner sizes available inch: 5” - 9”Mud pump drive motors no.:

2Motor type : ACContinuous power rating per motor hp:

1150Fluid end type:

Two pieceMaximum working pressure psi:

7500Test pressure psi:

11250Pump stroke counter type:

HitecSupercharging pump type:

HalcoDriven by motor of power bp: 100Discharge/Suction line ID inch/inch

5” / 10”M.P. Pulsation Dampener type:

White RockSoft Pump :

I systemReset Relief Valve type:

TBAWorking flowrate per pump at 90% of max spm

Maximum SPM :

105 SPM @ 100%

42

F.1.2 TRANSFER PUMPS/MIXING PUMPS (centrifugal)

Treatment pumps (Desilter/Desander)

Quantity

4Make

HalcoModel

2500Drive motor type

ElectricPower output

100 hpImpeller

14”Impeller speed

1200 rpmPacking type

Mechanical sealMixing Pumps

Quantity no.: 2Make :

HalcoModel :


Electric /BeltPower output hp:

100Impeller : 14”Impeller speed RPM:

1200Packing type ; Mechanical sealShearing Pumps

Quantity no.:

2Make :

HalcoModel :

T 6550Drive motor type : Electric /BeltPower output hp:

100Impeller : Shearing typeImpeller speed RPM:

1800Packing type ;

Mechanical sealCharging Pumps

Quantity no.:

4Make : HalcoModel :

2500Drive motor type : Electric /BeltPower output hp:

100Impeller :

14”Impeller speed RPM:

1200Packing type ;

Mechanical sealColumn Transfer

Quantity no.:

4Make : HalcoModel :


Electric /BeltPower output hp:

125Impeller :

12Impeller speed RPM:

1800Packing type ;

Mechanical seal F.1.3 BOOSTER PUMP

Quantity no.:

Rig Mud pumpMake/Type :

Pumping capacity (each) US gals/min:

43

Drive motor type :

Power output hp:

F.1.4 STANDPIPE MANIFOLD

Quantity of standpipes no.: 2 @ 7500 psi wpStandpipes ID inch:

5H-Type standpipe manifold yes/no:

yesKill line outlet yes/no:

yesFill-up/bleed-off line outlet yes/no:

yesOutlets (total) no.: 4ID inch:

5 & 3Type connections : WecoDimensions OD x ID inch x inch:

6 x 5Design standard :

ANSI, API

F.1.5 ROTARY HOSES

Quantity no.: 2 @ 7500 psi wpMake/Type :

BeattieID x length inch x ft: 4 x 88Snubbing lines yes/no:

yes F.1.6 CEMENTING HOSE

Type (i.e. Coflexip) :

BeattieLength ft: 85ID inch:

3Working pressure psi: 15000

F.1.7 CHIKSAN STEEL HOSES

Integral non-screwed yes/no:

yesMake/type :

TBA / 1502ID Nonimal inch: 2”Section length ft:

Quantity no.:

Section length ft:

Quantity no.:

Sweep swivels, make/type :

Nom. size ID inch:

Fittings, non-screwed type yes/no:

YesSuitable for H2S service yes/no:

F.2 LOW PRESSURE MID SYSTEM

F.2.1 MUD TANKS

Quantity no.:

15Column Tanks

Quanity :

4Capacity 85%

4600Surface Tanks

44

Quanity

10Capacity 85%

4000Capacity, tank No. 1 bbls: 460Type (active/reserve) :

ActiveCapacity, tank No. 2 bbls: 460Type (active/reserve) :

ActiveCapacity, tank No. 3 bbls:

460Type (active/reserve) :


650Type (active/reserve) : ActiveCapacity, tank No. 5 bbls:

650Type (active/reserve) : ActiveCapacity, tank No. 6 bbls:




ChemicalCapacity, tank No. 8 bbls: 160Type (active/reserve) :

ChemicalCapacity, tank No. 9 bbls: 160Type (active/reserve) :

ChemicalCapacity, tank No. 10 bbls:


ChemicalMixer in each tank yes/no:

YesMud guns in each tank yes/no: Yes

F.2.2 PROCESSING TANKS

Quantity no.:

6Total capacity (@ 100%) bbls:

450Capacity Sand Trap tank bbls:

75Capacity degasser tank bbls:

75Capacity desander tank bbls: 75Capacity desilter tank bbls:

75Capacity desilter tank bbls: 75Capacity treated mud tank bbls:

75 F.2.3 PILL/SLUG TANK

Capacity (@ 100%) bbls:

150Mud agitator yes/no:

yesMud guns yes/no:

yes F.2.4 TRIP TANK

Capacity (@ 100%) bbls:

100 2 x 50Capacity/foot bbls/ft:

TBALevel indicator yes/no:

yesElectric pump make

Halco x 2Model/type :

Cent.Motor output hp: 30Facility for casing fill-up yes/no:

noAlarm and strip chart recorder (See H.1.;11) yes/no:

Yes

45

F.2.5 STRIPPING TANK

Capacity (@100%) bbls:

10 ApproxCapacity/foot bbls/ft: TBAEqualizing facility with triptank yes/no:

YesTransfer pump yes/no: NoAlarm and strip chart recorder (See H.1. yes/no:

Yes F.2.6 CHEMICAL MIXING TANK

Separate mixing tank above for mixing causticCapacity bbls:

See F.2.1 Tks. 7- 10Chemical mixer type :

F.2.7 SHALE SHAKERS

Primary:

Quantity no.:

7Make/Model :

Brandt/LCM-2D CSType :

Linear Motion/ Cascading Driven by no. of electric motors no.: 3Design flowrate bbl/min:

Depending on Mud Characteristics Cascading:

Quantity no.:

See AboveMake/Model :

Type :

Driven by no. of electric motors no.:

Design flowrate bbl/min:

F.2.8 DESANDER

Quantity no.:

Desander cones over one cascading shale shakerMake/Model :

BrandtType :

Number of cones x sizes no. x inch:

6 X 12” w/ discharge overboard Type/size centrifugal pump :

Driven by electric motor of hp:

Is pump dedicated to desander yes/no:

Max. flowrate bbl/min:

F.2.9 DESILTER

Quantity no.:

Desilter cones over one cascading shale shakerMake/Model :

BrandtType :

Number of cones x sizes no. x inch: 40 X 4” W/ discharge over shaker or overboardType/size centrifugal pump :


Is pump dedicated to desilter yes/no:


F.2.10 MUD CLEANER

Quantity no.: N/AMake/Model :

Type :

Number of cones x sizes no. x inch:

46

Type/size centrifugal pump :


Is pump dedicated to mud cleaner yes/no:


Inlet and outlet for centrifuge to be provided

F.2.11 MUD/GAS SEPARATOR (Poor Boy)

Shall be capable to direct flow from flowline to MGSMake/Type :

SwacoGas discharge line ID inch:

12” nominalGas discharge location, primary

TopCan discharge be tied into burner system yes/no:

noMud seal height :

20Calculated gas throughput mmscf:

20Dimensions OAL 41.5 ft. X 6 ft.

F.2.12 DEGASSER

Quanty

2Make/Type :

Burgess/1500Capacity :

1000 GPM x 2Type/size centrifugal pump :

N/ADriven by electric motor of power hp: N/ADischarge line running to :

6”Vacuum pump make :

InternalType :

F.2.13 MUD AGITATORS

Quantity no.:

6Make/Model : PhiladelphiaDriven by motor of power hp

15Located in tanks (See F.2.1 for tank numbers)

8, 9, & 10Quantity no.:

3Make/Model :

PhiladelphiaDriven by motor of power hp


Shaker TanksQuantity no.: 4Make/Model :



1, 2, 3, & 4Quantity no.:

3Make/Model :


40Located in tanks (See F.2.1 for tank numbers) 5, 6, & 7

F.2.14 MUD CENTRIFUGE

Quantity no.:

Power and space for 2 F.2.15 MUD HOPPER

Quantity no.:

2Make/Model : Halco

47

Feed pump make/model :

Mixing pumps F.2.16 SHEARING HOPPERS

Quantity no.:

2Make/Model :

Halco/105-15Feed pump make/model :

Mixing pumps F.2.17 DECK HOPPER

Quantity no.:

1Make/Model :

HalcoFeed pump make/model :

Mixing pumps

F.3 BULK SYSTEM

F.3.1 BARITE/BENTONITE SILOS

Quantity no.: 5Capacity of each silo C.F.:

2500Locations :

ColumnsType weight loadcell :

HydraulicManufacturer :

Martin DeckerPressure rating

65Relief valve(s) installed yes/no:

yes F.3.2 BARITE DAY TANKS

Quantity

2Capacity of each silo C.F:

1200Locations :

MoonpoolType weight loadcell :


Martin DeckerPressure rating psi: 65Relief valve(s) installed yes/no:

yes F.3.3 SURGE TANK FOR BARITE

Quantity no.:

2Capacity of each tank It:

70Type weight loadcell :

HydraulicManufacturer : Martin DeckerPressure rating psi:


yes

F.3.4 CEMENT SILOS

Quantity


2800Locations : ColumnsType weight loadcell :


Martin DeckerPressure rating psi:


yesSeparate mud/cement loading facilities yes/no:

yesDischarge line for cement independent from

48

barite/bentonite discharge line yes/no:

Yes F.3.5 CEMENT DAY TANKS

Quantity


1100Locations :

Cement RoomType weight loadcell :


Martin DeckerPressure rating psi:


yes F.3.6 SURGE TANK FOR CEMENT

Third party F.3.7 BULK TRANSFER SYSTEM (See also C.1.8 - Compressed Air Systems)

Independent air system for the silos and surge tanks consisting of a high-volume low-pressure compressor and air drier yes/no: noAir reduced from main air supply through pressure regulators yes/no: yesSeparate volume tank and drier yes/no:

no G. CASING/CEMENTING EQUIPMENT

Company SuppliedG.1 CASING EQUIPMENT

Company SuppliedG.1.1 API CASING DRIFT

Company SuppliedG.1.2 CLAMP-ON CSG THREAD PROT’S

Company Supplied G.1.3 CASING ELEVATOR

Manufacturer

Company SuppliedType Capacity st:

Inserts for inch:

G.1.3 SIDE DOOR CASING ELEVATOR

Company SuppliedG.1.4 SINGLE JOINT CASING ELEVATOR

Company SuppliedG.1.5 SLIP TYPE ELEVATOR/SPIDERS

Quantity no.:

Company Supplied G.1.6 CASING SLIPS (Hand)

Quantity no.:

Company SuppliedMake/Type :

For OD casing inch:

Quantity no.:

Make/Type :For OD casing inch:

Quantity no.:

Make/Type :

For OD casing inch:

G.1.7 CASING BOWLS

Quantity no.: Company Supplied

49

Make/Type :

For OD casing (max/min) inch/inch:

Quantity no.:

Make/Type :


Quantity no.:

Make/Type :


G.1.8 CASING TONGS

Company SuppliedG.1.9 POWER CASING TONGS

Company SuppliedG.1.10 POWER UNIT FOR CASING AND TUBING TONGS

Quantity no.:

1 Central Hydraulic unitDriven by electric motor yes/no:

YES G.1.11 CASING CIRCULATING HEAD (Swedge)

Company SuppliedG.1.12 CASING SPEARS (Internal)

Company SuppliedG.1.13 CASING CUTTERS (Internal)

Company SuppliedG.1.14 CROSSOVER CASING TO DRILL PIPE

Company SuppliedG.1.15 CASING SCRAPERS

Company Supplied G.2 CEMENTING EQUIPMENT G.2.1 CEMENT UNIT

Company Supplied G.2.2 CEMENTING MANIFOLD

Discharge manifold working pressure psi:

15000Cement pump discharge lines min. ID inch:

3 NonimalCement pump discharge lines working p psi:

15000 G.2.3 CEMENT KELLY

N/AG.2.4 CEMENTING TUBING

N/A H. INSTRUMENTATION/COMMUNICATION

H.1 DRILLING INSTRUMENTATION AT DRILLER’S POSITION H.1.1 WEIGHT INDICATOR

Make/Type :

HITEC SMART DRILLING INSTRUMENTATIONSensor type :

ELECTRONIC DEADEND Calibrated for number of lines strung (6, 8, 10, 12, etc.) no.:

USER SELECTABLE H.1.2 STANDPIPE PRESSURE GAUGES

Quantity no.:

TBAMake/Type : HITEC SMART DRILLING INSTRUMENTATIONPressure range (maximum) psi:

TBA H.1.3 CHOKE MANIFOLD PRESSURE GAUGE

Quantity no.:

2Make/Type

HITEC SMART DRILLING INSTRUMENTATIONPressure range (maximum) psi:

0 - 15,000

50

H.1.4 ROTARY SPEED TACHOMETER

Make/Type :

HITEC SMART DRILLING INSTRUMENTATIONCapacity range (maximum) rpm:

0 - 200 H.1.5 ROTARY TORQUE INDICATOR :

HITEC SMART DRILLING INSTRUMENTATION H.1.6 MOTION COMPENSATOR INSTRUMENTS

Make/Type :

HITEC SMART DRILLING INSTRUMENTATIONHook position indicator yes/no:

YESLock/unlock indicator yes/no:

YES H.1.7 PUMP STROKE COUNTERS

Make/Type :

HITEC SMART DRILLING INSTRUMENTATIONOne pump stroke indicator and one cumulative pump stroke counter for each pump. yes/no:

YES H.1.8 TONG TORQUE INDICATOR

Make/Type :

Capacity range (maximum) ft lbs:

H.1.9 PIT VOLUME TOTALIZER

Make/Model : HITEC SMART DRILLING INSTRUMENTATIONFloats in active mud tanks yes/no:

YESFloats in reserve mud tanks yes/no:

YESLoss/Gain indicator yes/no:

YESAlarm (audio and visual) yes/no:

YES H.1.10 MUD FLOW INDICATOR

Make/Model : HITEC SMART DRILLING INSTRUMENTATIONHigh/low alarm (audio and visual) yes/no:

YES H.1.11 TRIP TANK INDICATOR

Make/Model :

HITEC SMART DRILLING INSTRUMENTATIONChart recorder yes/no:

DATA LOGGINGAlarm yes/no:

YES H.1.12 GENERAL ALARM SYS. yes/no:

YES H.1.13 AUTOMATIC DRILLER

Make/Type :

HITEC SMART DRILLING INSTRUMENTATION H.1.14 REMOTE CHOKE CONTROL UNIT (See E.14.1)

Make/Model : Houston Digital H.2 DRILLING PARAMETER RECORDER

Quantity no.:

USER DEFINED ELECT. DATA ACQUISITIONLocation - 1 :

DRILLERS HOUSELocation - 2 :

Make/Type :

HITEC SMART DRILLING INSTRUMENTATIONQuantity of pens no.: USER DEFINED ELECT. DATA ACQUISITIONParameter recorded :

” Parameter recorded :


”

51

Parameter recorded :





” H.3 INSTRUMENTATION AT CHOKE MANIFOLD

H.3.1 STANDPIPE PRESSURE GAUGE

Make/Type :

Strain gaugePressure range (maximum) psi:

0-10,000 H.3.2 CHOKE MANIFOLD PRESSURE GAUGE

Make/Type :

Strain gaugePressure range psi: 0-15,000H.3.1 and H.3.2 combined on one panel yes/no:

yesVisible from choke operating position yes/no:

yes H.4 STANDPIPE PRESSURE GAUGE

Strain GaugesMake/Type :

OTECOPressure range psi:

0-10,000Visible from driller’s position yes/no: No

H.5 DEVIATION EQUIPMENT

H.5.1 MEASURING DEVICE

Quantity no.:

1Make/Type :

TotcoDeviation range degree: 0 - 8 / 0-12

H.5.2 WIRELINE WINCH

Make/Model :

MatheyWire length (nominal) ft:

25000Depth counter yes/no:

yesWire size inch:

3/16Pull indicator Ibs: yes

H.6 CALIBRATED PRESS. GAUGES :

Strain Gauges H.7 RIG COMMUNICATION SYSTEM

H.7.1 TELEPHONE SYSTEM

No. of stations no.: 120Make/Type :

Mitel ExchangeExplosion proof yes/no:

AS REQ’D.No. of stations no.:

Make/Type :

Explosion proof yes/no:

H.7.2 PUBLIC ADDRESS SYSTEM

Can be combined with above yes/no:

YES

52

Make/Type :

AkustaExplosion proof yes/no:

AS REQ’D. H.7.3 DRILL FLOOR - DERRICKMAN’S TALKBACK (For Intercom System)

No. of stations no.:

14Location :

DWS - 2 / PHSLocation :

CCR / ECRLocation

:

FLOOR, ROV, CP AREA, MONKEY BD., MP ROOM, MOONPOOL, SHAKERS, CROWN

Make/Type :

AKUSTAExplosion proof yes/no:

AS REQ’D. H.7.4 HAND-HELD VHF RADIOS

Quantity

12 MIN.Make/Type Earmark VOX 130

H.8 ENVIRONMENTAL INSTRUMENTATION

H.8.1 TEMPERATURE INDICATORS

Air temperature

YesMake/Model

KongsbergSea water temperature TBAMake/Model :

TBARecorder yes/no:

Yes H.8.2 BAROMETRIC PRESSURE yes/no:

YesMake/Model

KongsbergRecorder

Yes H.8.3 HUMIDITY SENSING INDICATOR

YesMake/Model

KongsbergRecorder

No H.8.4 WIND SPEED/DIRECTION

Yes - QTY. 2Make/Model

KongsbergRecorder Yes

H.8.5 WAVE PROFILE RECORDER

No H.9 ADDITIONAL MODULE SPECIFIC INSTRUMENTATION H.9.1 ROLL, PITCH AND HEAVE INDICATOR

Make/Type KongsbergRecorder

H.9.2 GYRO COMPASS

Make/Model

C. Plath / Navagat XLocated at

CCR ELECT. SPACE H.9.3 ECHO SOUNDER Yes

Make/Model

SkipperLocated at

Bridge

53

Recorder

No H.9.4 CURRENT INDICATOR

Doppler Current ProfilerMake/Model

TBALocated at

Lower Hull PenetrationRecorder

TBA H.9.5 WEATHER FACSIMILE RECOI

YesMake/Model :

JRC / JAX - 9ALocated at :

Radio RoomRecorder yes/no:

Yes H.9.6 RADAR YES

YesQuantity 1

1Make/Model Norcontrol / Databridge 2000 BL Located at

BridgeBandwidth cm:

X-BandQuantity no.:

1Make/Model :

Norcontrol / Databridge 2000 BL Located at :

BridgeBandwidth cm:

S-Band H.10 RADIO EQUIPMENT

H.10.1 SSB TRANSCEIVER

Quantity

1Make/Model

Sailor / RE2100Power watts:

600Frequency ranges hz: 100 khz - 30 MHz(Synthesized/crystal) :

SynthesizedFacsimile capable

NoTelex capable

N/A H.10.2 E.P.I.R.B’s

Quantity

2Make/Model : COSPAS / SARSAT / TRON 30S MK II

H.10.3 VHF RADIO TELEPHONE

Quantity

5Make/Model

Norcontrol - Sailor / RT 2048 W/ DSC Power watts:

25 WChannels

H.10.4 VHF RADIO TRANSCEIVER

Quantity no.:

3Make/Model :

Norcontrol - Sailor / RT 2048 Power watts:

25 W H.10.5 RADIO BEACON TRANSM

Quantity 1Make/Model :

Southern Avionics / SA 100 Power watts:

100 W

54

H.10.6 AEORNAUTICAL VHF TRANS

Quantity

1Make/Model :

JotronPower watts:

40 W PEPFrequency range hz:

118 - 137(Synthesized/crystal) :

H.10.7 WATCH RECEIVER

Quantity

1Make/Model :

Sailor / R501Frequency khz:

2182 H.10.8 SCRAMBLER

Quantity no.:

NoMake/Model :

H.10.9 TELEX

Quantity no.:

N/AMake/Model :

H.10.10 SATELLITE COMM. SYS

Make/Model : NERA / C-10-0 / NERA / H2095 BType :

Type B / Type C Facsimile link

YesTelex link

YesTelephone link

Data Link (9.6 K bits / Message TerminalOther capabilities :

1. PRODUCTION TEST EQUIPMENT 1.1 BURNERS

N/A1.2 BURNER BOOMS

Foundations Only1.3 LINES ON BURNER BOOMS

N/A 1.3.1 OIL LINE

OD inch:

4”Working pressure psi: 1480 psiConnection type at burner end :

Suitable to connect to well test equipmentH2S yes/no:

YesPressure gauge connection at barge end inch:

Provided by well test company 1.3.2 GAS LINE

OD inch:

3”Working pressure psi: 1480 psiExtended beyond burner by ft:

Provided by well test company Connection type at burner end type:

Suitable to connect to well test equipmentH2S yes/no:

YesPressure gauge connection at barge end inch:

Provided by well test company 1.3.3 WATER LINE

OD inch: Seawater - 1-1/2”Working pressure psi:

285 psi

55

Connection type at burner end type:

Suitable to connect to well test equipment Pressure gauge connection at barge end inch:

Provided by well test company I.3.4 AIR LINE

OD inch: 4”Working pressure psi:

285 psiConnection type at burner end type:

Suitable to connect to well test equipment Pressure gauge connection at barge end inch:

Provided by well test company I.3.5 PILOT GASLINE

ID inch:

Provided by well test company Working pressure psi:

Connection type at burner end type:

Pressure gauge connection at rig end inch:

I.4 SPRINKLER SYSTEM

Sufficient to give protection to rig and personnel against heat radiation damage from the b yes/no: Provided by well test company

1.5 FIXED LINES FOR WELL TESTING

1.5.1 DRILL FLOOR TO SEPARATOR AREA

Type (Screwed/welded, both)

Tested and certified flexible flowlines provided by well

:

test co. for connecting from rig floor to well test equip. 1.5.2 SEPARATOR AREA TO BOTH BURNER BOOMS

Type (screwed/welded, both.) :

WeldedQuantity no.:

2 ea. / one oil / one gasSize OD inch:

3” Gas / 4” OilWorking pressure psi: 1480 psiConnection type at separator type:

Suitable for connecting to well test companyConnection type at boom type: As aboveNumber of valves/lines no.:

Provided by well test company Size of valves inch:

Provided by well test company H2S yes/no:

YesValves installed near separator area for switching gas to

either burner. yes/no:

Yes I.53 MUD PUMPS TO 2-BURNER : N/A I.5.4 RIG AIR SYSTEM TO BOTH BURNER BOOMS

Type (screwed/welded, both) :

WeldedQuantity no.:

1 ea. Port and StarboardSize OD inch:

4”Working pressure psi:

Non-return valves fitted yes/no: Yes I.5.5 OIL STORAGE TANK TO OVERBOARD


Provided by well test company Quantity no.:

Size ID inch:

56

Working pressure psi:

Height above water level ft:

Connection type at separator area type:

I.5.6 SEPARATOR TO VENTSTACK OF RIG


No vent from separator. Relief to flair Quantity no.:

Size ID inch:

Working pressure psi:

Connection type at separator area type:

I.6 AUXILIARY POWER AVAILABILITY

I.6.1 FOR FIELD LABORATORY

Quantity kw

2 - 480 volt boxesVolts v:

Frequency hz:

I.6.2 FOR CRUDE TRANSFER PUMP

Quantity kw:

Yes, as abovevolts v:

Frequency hz:

I.6.3 FOR ELECTRIC HEATERS

Quantity kw:

Yes, as aboveVolts v:

Frequency hz:

J. WORKOVER TOOLS

Company SuppliedK. ACCOMMODATION

K.1 OFFICES

K.1.1 CO. REP.’S OFFICE

Quantity

3Complete with desk, filing cabinet(s) and other necessary furniture

YESUnrestricted view to drill floor

NO(CCTV MONITOR) K.1.2 CONT. REP.’S OFFICE

Quantity

3Unrestricted view to drill floor

NO(CCTV MONITOR) K.1.3 RADIO ROOM

YESQuantity

1 K.1.4 HOSPITAL ROOM

Number of beds/bunks

2 BedsWash basin

YESMedical cabinet

YESDangerous drugs locker

YES

57

K.1.5 MUD LABORATORY AND FACILITIES

Separate room yes/no:

YESEquippped with:

Mud balance yes/no:

YESMarsh funnel yes/no: YESFiltration kit yes/no:

YESSand content kit yes/no:

YESStopwatch yes/no:

YES K.2 LIVING QUARTERS

K.2.1 TOTAL PERSONS ACCOMODATED

Quantity

130 K.2.2 ACCOMODATION FOR COMPANY’S PERSONNEL

Total quantity

60Quantity of single bed rooms

2C/W attached toilet

YESQuantity of two bed rooms


YESQuantity of four bed rooms

0C/W attached toilet N/A

K.2.3 ACCOMODATION FOR CONTRACTOR’S PERSONNEL

Total quantity

70Quantity of single bed rooms


YESQuantity of two bed rooms


YESQuantity of four bed rooms

OC/W attached toilet N/A

K.2.4 GALLEY

Quantity

1 K.2.5 MESS SEATING CAPACITY

Main mess

60Aux. mess

N/A K.2.6 MEETING ROOMS

Quantity

1 K.2.7 RECREATION ROOMS

Quantity

2Recreation facilities:

YESTV

YESVCR

YESPool Table

NOPing Pong Table

YESComputer

NOOther

DARTS/CARDS/READING

58

K.2.8 OTHER ROOMS

Laundry

1 + 2 In change room for dirty clothes Dry food store

1Refrigerator

3Change Rooms

4Prayer Room

NOCinema

NOWorkout/Weight Room

YES L. SAFETY EQUIPMENT

L.1 GENERAL SAFETY EQUIPMENT

L.1.1 GENERAL PERSONNEL PROTECTIVE GEAR

Safety bats (contractor only/everyone/not supplied :

CONTACTOR ONLYSafety boots (contractor only/everyone/not supplied :

CONTACTOR ONLYSafety clothing (contractor only/everyone/not supplied :

CONTACTOR ONLYEar protection (contractor only/everyone/not supplied : EVERYONERubber gloves (contractor only/everyone/not supplied :

CONTACTOR ONLYRubber aprons (contractor only/everyone/not supplied : CONTACTOR ONLYFullface visors (contractor only/everyone/not supplied :

CONTACTOR ONLYEye shields (for grinding machines, etc.)

(Contractor only/everyone/not supplied :

CONTRACTOR ONLYDust masks (contractor only/everyone/not supplied :

CONTACTOR ONLYRubber gloves - elbow length for chemical handling


CONTACTOR ONLYExplosion proof handtorches c/w batteries


CONTACTOR ONLYSafety belts c/w lines (contractor only/everyone/not

supplied :

CONTRACTOR ONLY

L.1.2 EYE WASH STATIONS

Quantity no.:

3Make/model : TBALocated at pot water

MUD PROCESS ROOMLocated at piping

DRILL FLOORLocated at :

MUD MIXING ROOM L.1.3 DERRICK SAFETY EQUIPMENT

Derrick escape chute (rem chute) no.: N/A

Make/Type :

Derrick safety belts no.:

2 W/ INERTIA REELMake/Type :

TBA L.1.4 DERRICK CLIMBING ASSISTANT

Make/Type

L.1.5 FRESH AIR BLOWERS (Bug Blowers)

Quantity :

3Make/Type :

Located at :

Rig FloorLocated at :

59

L.2 GAS/FIRE/SMOKE DETECTION

L.2.1 H2S MONITORING SYSTEM

Make/Type :

TBASampling points at:

Bellnipple yes/no:

YESDrillfloor yes/no:

YESShale shaker yes/no:

YESMud tanks yes/no:

YESVentilation system into living quarters yes/no: YESOther :

YESGeneral alarm yes/no:

Alarm types (audible, visual, both) at:

Driller’s console :

BOTHEngine room :

BOTHMud room :

BOTHLiving quarters each level : AUDIBLECentral area each structural level :

BOTHOther : BOTHCentral alarm panel yes/no:

YESLocated at :

CCR L.2.2 COMBUSTIBLE GAS MONITORING SYSTEM

Make/Type : Simrad Integrated Alarm and Control SystemSampling points at: yes/no:

Bellnipple yes/no: YESDrill floor yes/no:

YESShale Shaker yes/no:

YESMud tanks yes/no:

YESVentilation system into living quarters yes/no:

YESOther : YESGeneral alarm yes/no:

Alarm types (audible, visual, both) at:

Driller’s console :

BOTHOther :

BOTH

YES L.2.3 H2S DETECTORS (Portable)

Quantity no.:

TBAMake/Type :

Phials for H2S: measuring range

from 1 to 20 ppm no.:


L.2.4 CO2 GAS DETECTORS (Portable)

Quantity no.:

TBAMake/Type :

Phials for CO2: measuring range



om 250-3000 ppm no:

L.2.5 EXPLOSIMETERS

Quantity no.: TBAMake/Type :

60

L.2.6 FIRE/SMOKE DETECTORS IN ACCOMODATION

Make/type :

THERMALFire detection yes/no: YESSmoke detection yes/no:

YESCentral alarm panel yes/no: YESLocation :

CCR L.3 FIRE FIGHTING EQUIPMENT

L.3.1 FIRE PUMPS

Quantity no.:

2Make/Model : PattersonType :

CENTRIFUGALOutput US gals/min:

550All offtake points supplied by each pump yes/no:

YESLocation of pumps :

AUX. MACHINE ROOM PORT Location of pumps : AUX. MACHINE ROOM FWD. Fire fighting water delivery conforms to yes/no:

YESMODU spec version :

L 3.2 HYDRANTS AND HOSES

Hydrants positioned such that any point may be reached

by a single hose length from two separate hydrants yes/no:

YESQuantity of hydrants no.: 48Hose connections/hydrant no.:

46 X 1Hose max. diam. inch: 2.5” ODLength ft:

50’ L.3.3 PORTABLE FIRE EXTINGUISHERS

Quantity (total) no.:

70Type 1- CO2 no./lbs: 2 @ 4

no./lbs:

37 @ 15

no./lbs: 2 @ 150Type 2 - Dry chemical no./lbs:

17 @ 5

no./lbs:

9 @ 10

no./lbs:

3 @ 50Type 3 - Foam no./lbs:

0

no./lbs:

0

no./lbs:

0Mounted adjacent to access ways and escape routes yes/no: yes

L.3.4 FIRE BLANKETS

Location :

RIG FLOOR, GALLEY, HELICOPTER BOXQuantity no.:

3 L.3.5 FIXED FOAM SYSTEM

Automatically injected into fixed fire water system at central point with remote manual control yes/no:

YESMake/Type :

PattersonQuantity foam stored on site GALLONS

700 GPM

61

Inductor tube yes/no:

YESFoam nozzles no.:

4Located at : HELIPORT -3 TURRET MOUNTED Located at :

HELIPORT -1 HOSE REELS Located at :

L.3.6 HELIDECK FOAM SYSTEM

Dedicated system adequate for at least 10 minutes fire fighting at the rate quoted in the IMO MODU code yes/no:

YES IMO MODU code version : TBAMake/Type :

DOOLYQuantity of monitors no.: 3Foam type :

TBARate US gals/min:

350 gal. min. each L.3.7 FIXED FIRE EXTINGUISHING SYSTEM

Protected spaces

Engine room, type (Halon/CO2)

CO2Paint locker, type (Halon/CO2)

CO2Emergency generator, type (Halon/CO2)

CO2SCR room, type (Halon/CO2)

CO2Other (specify location & type)

CO2 IN MUD PUMP ROOM Alarms (audible, visual or both) :

Automatic shutting of mechanical ventilation in protected spaces yes/no:

YESRemote manual release located at :

Remote manual release located at :

Remote manual release located at :

L.3.8 MANUAL WATER DELUGE SYSTEM yes/no:

YESProtected spaces : DRILL FLOOR, LIFEBOATS Protected spaces :

LIFERAFTS, MOONPOOL Water supplied from fire main line yes/no: YES MAIN SALT WATER RING

L.3.9 WATER SPRINKLER SYSTEM IN ACCOMODATION

Automatic yes/no:

YESWorking pressure psi:

130Pressurized tank capacity ft3:

53.47 L.4 BREATHING APPARATUS : TBA L.5 EMERGENCY FIRST AID EQUIPMENT

L.5.1 FIRST AID KITS

Quantity no.:

TBA L.5.2 BURN KITS

Quantity no.:

TBA L.5.3 RESUSCITATORS

Quantity no.:

TBA

62

Charged (spare) oxygen cylinders no.:

L.5.4 STRETCHERS

Quantity no.:

TBAType :

Located at :

L.6 HELIDECK RESCUE EQUIPMENT

L.6.1 STORAGE BOXES

Quantity no.:

TBAConstruction material : FIBERGLASSMax height open inch:

TBA

L.6.2 EQUIPMENT

Aircraft axe yes/no:

YESLarge firemans rescue axe yes/no: YESCrowbar yes/no:

YESHeavy duty hacksaw yes/no: YESSpare blades yes/no:

YESGrapnel hook yes/no:

NOLength of wire rope attached ft:

Quick release knife yes/no:

YESBolt croppers yes/no: YES

L.7 RIG SAFETY STORE

Equipment to repair, recharge and restock

R&BF will carry all spares necessary to ensure an efficient and safe operation.

L.8 EMERGENCY WARNING ALARMS

Approved system to give warning of different emergencies yes/no:

YES L.9 SURVIVAL EQUIPMENT

L.9.1 LIFEBOATS

Make/Type :

TBAQuantity no.:

2Capacity person/craft:

65Locations (fore, apt, port, stbd) : 2 FOREFire protection yes/no:

YESRadios yes/no:

YESFlares yes/no:

YESFood yes/no:

YESFirst aid kits yes/no:

YESMaker/Type :

TBAQuantity no.: 2Capacity person/craft:

65Locations (fore, apt, port, stbd) :

AFTFire protection yes/no:

YESRadios yes/no:

YESFlares yes/no:

YES

63

Food yes/no:


YES L.9.2 LIFERAFTS

Make/Type : TBAQuantity no.:

3Capacity person/craft:

30Davit launched yes/no:

YES & FLOAT FREELocations (fore, apt, port, stbd) :

FOREFire protection yes/no:

Radios yes/no:

TBAFlares yes/no: YESFood yes/no:


YESMake/Type :

TBAQuantity no.:

2Capacity person/craft: 30Davit launched yes/no:

YESLocations (fore, apt, port, stbd) : AFTFire protection yes/no:

Radios yes/no:

TBAFlares yes/no:

YESFood yes/no:

YESFirst aid kits yes/no: YES

L.9.3 RESCUE BOAT

Make/Type :

Port Fwd lifeboat is designated as a rescue boatEngine power hp:

L.9.4 LIFE JACKETS

Make/Type

TBAQuantity no.:

163 L.9.5 LIFE BUOYS

Make/Type :

TBAQuantity no.:

10 L.9.6 WORK VESTS

Make/Type :

TBAQuantity no: 25

L.9.7 ESCAPE LADDERS/NETS

Make/Type :

PERMANENT LADDERS Quantity no.:

4, 1 PER CORNER COL. L.9.8 DISTRESS SIGNALS

Type : TBAQuantity no.:

1 SET M. POLLUTION PREVENTION EQUIPMENT

M.1 SEWAGE TREATMENT

64

Make/Model :

HAMMWORTHY (USCG APPROVED) System type :

BIOLOGICALConforms to (Marpol annex IV, etc.) : YES

M.2 GARBAGE COMPACTION

Make/Model :

To be providedSystem type :

Conforms to (Marpol annex IV, etc.) :

Make/Model :

System type :


M.3 GARBAGE DISPOSAL/GRINDER

Make/Model :

To be providedSystem type :


N.1 THIRD PARTY EQUIPMENT

Mud Loggers (available sq feet)

555 sq. ft.MWD / LWD (available sq feet)

555 sq. ft.Cement Unit (available sq. feet)

1,087 sq. ft.ROV (available sq. feet)

1184 sq. ft.Electric Log (available sq. feet)

895 sq. ft.

EXHIBIT B-3

MATERIAL, SUPPLIES AND SERVICES

Category I

Furnished by CONTRACTOR, paid by CONTRACTOR

1

Categories: I. Furnished by CONTRACTOR, paid by CONTRACTOR.

II. Furnished by COMPANY, paid by COMPANY.

III. Furnished by CONTRACTOR, paid by COMPANY.

1.1 Fuel storage.

1.2 Lube oils and greases.

1.3 Tool joint lubricant for CONTRACTOR’S drill string.

1.4 Replacement screens on shale shaker for screen sizes 84 mesh and coarser.

1.5 Replacement screens for mud cleaner(s) for screen sizes 150 mesh and coarser.

1.6 Initial set of rig hoses for receiving or discharge of liquid and bulk consumables from workboats.

1.7

Initial installation and utility provision for AC drive cementing unit and cement mixing pumps in shipyard. (rental only - as provided in Rental Agreement).

1.8

Initial installation for ROV unit and installation of ROV cursor system. Provision of utilities for electric motor generator for ROV main power.

1.9 Welding services with welder in CONTRACTOR’S crew (overtime not included).

1.10

Except as otherwise provided in Exhibit “B-2” herein rig and equipment maintenance, running supplies, spares and replacement parts, and services for continuous operation of CONTRACTOR’S equipment.

1.11 Towing bridle and replacement of same from Drilling Unit to towing vessel(s) during all rig moves.

1.12 Supply vessel mooring system at Drilling Unit.

1.13

Labor on the Drilling Unit to load and unload all CONTRACTOR’S and COMPANY’S equipment, materials and supplies between supply vessels and Drilling Unit.

1.14 CONTRACTOR’S Shore Base.

1.15

Medical doctor on notice in the Operating Area for emergency treatment of CONTRACTOR’S personnel injured aboard the Drilling Unit.

1.16

Meals, bunk and accommodations, including medical services, on board Drilling Unit for all CONTRACTOR’S personnel and an average of ten (10) COMPANY and COMPANY third party personnel per day.

1.17 Personnel for Drilling Unit and shore base as set out in Exhibit “F”.

1.18 Disposal of all liquids and other waste generated by CONTRACTOR including drum disposal.

2

1.19

Complement of personal protective equipment required to handle completion brines and synthetic base mud for those crew members with potential exposure.

1.20

Blowout preventers, choke and kill lines, ring gaskets, controls, handling, testing tools and spare parts as required set out in Exhibit “B-2”.

1.21

Wellhead connector and spare parts as required in Exhibit “B-2” to adapt CONTRACTOR’S BOP stack to COMPANY’S wellhead.

1.22

All other well control equipment components and replacement parts, including failsafe valves, riser, choke and kill lines and choke manifold. All replacement parts shall be Original Manufacturer’s Equipment.

1.23

Initial set of ram packer elements, annular elements, top seals, related equipment as required in Exhibit “B-2” CONTRACTOR’S BOP EQUIPMENT. All elements, packers, seals and related rubber goods shall be Original Manufacturer’s Equipment and oil mud compatible.

1.24 Manifolding and piping as required to flare burners for oil, gas, water and air.

1.25

CONTRACTOR shall conduct a drillpipe inspection on all drillpipe, drill collars, subs, rotary and handling tools prior to spudding the first well under this CONTRACT. A specified inspection including all optional inspections as specified by API-RP7G, such as; Transverse Defect inspection using induction coils and a magnetic particle inspection of tube ends, couplings, and verification of defects found by gamma ray wall thickness inspection. Drillpipe must satisfy criteria as new or premium drillpipe to be used on COMPANY’S wells.

1.26

CONTRACTOR shall conduct an inspection on all drillpipe after every 100,000’ drilled or 1500 rotating hours (whichever is less). Inspection type will satisfy criteria spelled out in API-IADC specified inspection for used drillpipe. Inspection will include all operational inspections in same API criteria along with magnetic particle for tube ends and couplings. Drillpipe must satisfy criteria as new or premium drillpipe to be used on COMPANY’S wells.

1.27

CONTRACTOR shall conduct an inspection on topdrive valves and subs, all drill collars, subs and related bottom hole assembly components every 250 rotating hours. All bottom hole assembly components shall meet a bending strength ratio of 2.25 to 3.00.

1.28 Living Quarters to accommodate 130 personnel minimum. Must have separate facilities for up to 10 women.

1.29

Three COMPANY designated offices. One for COMPANY’S drilling supervisors, one for COMPANY’S third partys and one for COMPANY’S geologists. All offices complete with intercom system, television, VCR’s, surge suppression for up to 4 computers, 2 desks and file cabinets.

1.30 All equipment shall comply with MMS regulations.

1.31

Spare parts inventory for surface and subsurface BOP equipment as per CONTRACTOR BOP EQUIPMENT LIST, Exhibit B-2. Spare parts inventory list to be provided to and agreed by COMPANY.

1.32

Supply labor required to test, service, and maintain, all surface, and subsurface BOP and well control equipment and tools including COMPANY’S wellhead running tools.

1.33 Mud pump liners and pistons for two (2) sizes as specified by COMPANY.

1.34

Fishing tools to include overshots, grapples, and crossover subs required to catch all contractor supplied drill string and bottom hole assembly components

3

listed in Exhibit “B-2”.

1.35 Diver services and equipment as required by CONTRACTOR.

1.36 Mud bucket for each size of CONTRACTOR supplied drill pipe.

1.37 Outside pipe wipers for each size of CONTRACTOR supplied drill pipe.

1.38 Pressure washer for rig floor and maintaining same.

1.39 Mud vacuum system for rig floor clean up and maintenance.

1.40

Space and utilities for the following COMPANY’S third party equipment: electric wireline logging unit, MWD/LWD logging unit, mud logging unit and two (2) centrifuges.

1.41 Space or accommodation for COMPANY’S warehouse.

Category II

Furnished by COMPANY, paid by COMPANY

2.1

Thread compound for COMPANY’S connectors and casing.2.2

Potable and fresh water for drilling, cementing and wash down of CONTRACTOR’S equipment and for personnel use but with respect to the latter only in excess of the capacity of the distillation unit.

2.3 Diesel fuel.

2.4 Drill sites, location surveys, marker buoys.

2.5 All permits and licenses required for the drilling site and to permit access thereto and egress therefrom.

2.6 Weather forecast service.

2.7 Stabilizers, including sleeves and spare parts and maintenance.

2.8 Core heads, core catchers and coring service charges.

2.9

Drilling bits, bit breakers (not supplied per Exhibit B-2), underreamers, hole openers, shock subs, wall scrapers, and other down hole tools, plus maintenance and repairs.

2.10 Water based mud, chemicals and additives.

2.11 Synthetic oil base mud, oil emulsion and other special drilling and completion fluids for completing wells.

2.12 Mud engineering services, and other mud supervision.

2.13 Mud centrifuge.

2.14 Pumping and blowing of bulk materials from work boats to Drilling Unit and between workboats and dock storage facilities.

2.15

All completion and production equipment, including hangers, packers, liners, floats, centralizers, scratchers, casing shoes, float collars, wellheads, spacer spools, Christmas trees including ring gaskets, valves, well connections and all necessary tools and equipment for installation.

2.16 Wellhead running retrieving, handling and testing tools.

2.17 Cementing unit and cement mixing pumps.

2.18 Cement and cement services, including special rental charge.

2.19 Electric logging unit, services and related tools.

2.20 Gun perforating and related services.

2.21 Mud logging unit and related services.

4

2.22 Whipstocks, directional drilling tools and services.

2.23

All surface and down hole survey equipment and services, except for drift indicators and slick line unit as described in Exhibit “B-2”.

2.24 Drill stem, formation testing tools and services.

2.25 Test tanks and accessories for production testing.

2.26

Well test burner equipment, burners, separators, flow meters, any other well testing equipment, including installation costs and well testing services.

2.27 All permanent or special installations and services, including services for controlling blowouts and fires.

2.28 Diver, ROV services and equipment as required by COMPANY.

2.29 Additional welding services required by COMPANY.

2.30 Spare parts and operating supplies for COMPANY’S tools and equipment.

2.31

All transportation required for CONTRACTOR’S and COMPANY’S equipment, supplies, drilling and potable water and personnel between shore and Drilling Unit.

2.32 Transportation from base of operations to Drilling Unit by sea, air and/or helicopter.

2.33 Anchor handling vessels and crews to deploy and recover mooring system at COMPANY’S drilling location.

2.34

Dock and dockside facilities, including cranes and trucks, labor equipment for loading and unloading CONTRACTOR’S and COMPANY’S equipment, materials and supplies at COMPANY’S shore base, port charges, pilot fees, canal fees, wharfage, agent fees and related costs for movement of equipment and material at COMPANY’S shore base and dock facilities.

2.35

Any radio equipment required by COMPANY in excess of those described in Exhibit “B-2”, and maintenance of such radio equipment.

2.36 All radio permits and licenses for COMPANY’S radios.

2.37 Disposal of all liquid and other waste generated by COMPANY including drum disposal.

2.38 Disposal of cuttings, mud materials from the well, if required.

2.39

Wellhead, wellhead gasket, wear bushing and bore protectors. All other gaskets and bore protectors for CONTRACTOR’S account.

2.40 Casing and or tubing tools and crews not listed in Exhibit “B-2”.

2.41 All casing, tubing and accessories.

2.42 Casing cutting tools.

2.43 Drill pipe, drill collars and accessories other than that furnished by CONTRACTOR listed in Exhibit “B-2”.

Category III

Furnished by CONTRACTOR, paid by COMPANY

5

3.1 Special safety equipment required other than as described in Exhibit “D”.

3.2 Replacement screens on shale shakers for screen sizes finer than 84 mesh.

3.3 Replacement screens on mud cleaners for screen sizes finer than 150 mesh.

3.4 Welding consumables for welding COMPANY furnished equipment.

3.5 Additional off tour labor authorized by COMPANY for mixing cement, moving mud materials, COMPANY’S tubulars, etc.

3.6 Overtime beyond normal work schedule and extra CONTRACTOR personnel requested by COMPANY.

3.7 Replacement of CONTRACTOR supplied supply vessel mooring system ropes.

3.8

Replacement set of ram packer elements, top seals and annular elements. All elements, packers, seals and related rubber goods shall be Original Equipment Manufacturer equipment and oil mud compatible.

3.9 Replacement of CONTRACTOR supplied hoses for receiving and discharge of liquid and bulk consumables from workboats.

3.10

Meals and accommodations on board the Drilling Unit for COMPANY and COMPANY’S third party personnel in excess of an average of ten (10) per day calculated over a period of one (1) calendar month will be billed at CONTRACTOR’S actual cost.

EXHIBIT C

INSURANCE REQUIREMENTS

1. The insurance required to be carried by CONTRACTOR under this Contract is as follows:

a. Workers’ Compensation as may be required by the laws of the jurisdictions which the work is performed, including occupational disease. If the performance of the CONTRACT requires the use of watercraft or is performed over water, CONTRACTOR shall provide coverage for liability under the U.S. Longshoreman’s and Harbor Workers Compensation Act, the Outer Continental Shelf Lands Act, and liability for admiralty benefits and damages under the Jones Act, Death on the High Seas Act, and general maritime laws on all employees except members of crews of vessels if crew liabilities are covered under Protection and Indemnity Insurance, and shall further provide that a claim “in rem”, or against the Drilling Unit, shall be treated as a claim against the employer.

b. Employer’s Liability Insurance with limits not less than $10,000,000 per occurrence covering injury or death to any

employee. c. Comprehensive General Liability Insurance, including contractual liability insuring the indemnity agreement as set forth in

the Contract and products-completed operations coverage with a combined single limit of not less than $10,000,000 covering bodily injury, sickness, death and property damage. This insurance shall provide that a claim “in rem” or against the Drilling Unit be treated as a claim against the insured.

d. Comprehensive Automobile Liability Insurance including contractual liability, insuring owned, non-owned, hired, and all

vehicles used by CONTRACTOR with a combined single limit of not less than $10,000,000 applicable to bodily injury, sickness, or death and loss of or damage to property in any one occurrence.

e. Watercraft Insurance: If the performance of this CONTRACT requires the use of watercraft to be provided by

CONTRACTOR, CONTRACTOR shall carry or require the owners of the watercraft to carry: (1) Hull and Machinery (including Collision Liability) insurance, subject to the American Institute Hull Clauses or equivalent, in an amount not less than the stated value of the watercraft (any language in this policy which limits the coverage of an insured who is not an owner or who is not entitled to limitation of liability shall not apply to the extent the owner has assumed liability for the loss); (2) Protection and Indemnity Insurance, in an amount not less than the stated value of the watercraft or $5,000,000, whichever is greater (any language in this policy which limits the coverage of an insured who is not an owner or who is not entitled to limitation of liability shall not apply to the extent the owner has assumed liability for the loss); and (3) in respect to all chartered vessels, Marine Operator’s Charterer’s Legal Liability insurance with limits of not less that $5,000,000.

1

f. Aircraft Insurance: If the performance of this Contract requires the use of aircraft provided by CONTRACTOR,

CONTRACTOR shall carry, or require the owners of the aircraft to carry: (1) All Risks Hull insurance in an amount equal to the replacement value of the aircraft, and (2) Bodily Injury Liability, including Passenger Liability of not less than $2,000,000 per passenger seat in any one occurrence and $25,000,000 property damage in any one occurrence.

g. All Risks Hull and Machinery/Physical Damage Insurance, includingCollision Liability, blowout and cratering coverage, in an

amount equal to full value of the CONTRACTOR’S Drilling Unit and other equipment employed, including CONTRACTOR’S associated equipment and non-floating items normally situated in the ocean, such as blowout preventers, riser systems, anchors, anchor chains, and/or cable, pendant wires and pendant buoys. This coverage shall include at least $5,000,000 for costs or expenses of the removal of the wreck or debris of the Drilling Unit.

h. Protection and Indemnity Insurance on the Drilling Unit owned and/or operated by the CONTRACTOR in an amount of not

less than the full value of the Drilling Unit or Five Million Dollars ($5,000,000), whichever is greater. This coverage may exclude liability to CONTRACTOR’S employees and members of the crew of the insured drilling unit provided the insurance set forth in Sections “a and b” hereof is warranted to remain in full force and effect during the term of this Contract. (Any language in this policy which limits the coverage of an insured who is not an owner or who is not entitled to limitations of liability shall not apply to the extent the owner has assumed liability for the loss.)

i. Pollution Liability Insurance on the vessel, in accordance with the terms of entry provided by the CONTRACTOR’S P&I

Club (as required by the Oil Pollution Act of 1990 OPA 90).

2. All the insurance shall be carried by CONTRACTOR at CONTRACTOR’S expense with an insurance company or companies authorized to do business in the jurisdictions where the work is to be performed and satisfactory to Vastar. CONTRACTOR shall furnish certificates of insurance to Vastar evidencing the insurance required hereunder and, upon request, Vastar may examine true copies of the actual policies. Each certificate shall provide that the insurance is in full force and effect and that it shall not be canceled or materially changed without thirty (30) days (seven (7) days with respect to war risks, prior written notice to Vastar. All certificates must contain reference to endorsements (i.e., Additional Insured, Waiver of Subrogation, etc.) as required herein.

3. Vastar, its subsidiaries and affiliated companies, co-owners, and joint venturers, if any, and their employees, officers, and agents

shall be named as additional insureds in each of CONTRACTOR’S policies, except Workers’ Compensation for liabilities assumed by CONTRACTOR under the terms of this Contract.

2

4. All CONTRACTOR’S insurance policies shall be endorsed to provide that underwriters and insurance companies of

CONTRACTOR shall not have any right of subrogation against Vastar, its subsidiaries, co-owners and joint venturers, if any, and their agents, employees, officers, invitees, servants, contractors, subcontractors, insurers, and underwriters.

5. Any coverage provided to Vastar by the CONTRACTOR’S insurance under this CONTRACT is primary insurance and shall not

be considered contributory insurance with any insurance policies of Vastar, its subsidiaries, co-owners and joint venturers, if any.. 6. All policies shall be endorsed to provide that there will be no recourse against Vastar for payment of premium. 7. CONTRACTOR shall require all its subcontractors to carry adequate insurance coverage during the term they are engaged in

performing any work hereunder. Subcontractors shall furnish Vastar acceptable evidence of insurance upon its request. 8. Except where specifically provided for in this Contract any and all deductibles in the required insurance policies shall be assumed

by, for the account of, and at CONTRACTOR’S sole risk. 9. In the event the premium for war, expropriation, nationalization and non re-exportation risks insurance for the CONTRACTOR’S

Drilling Unit increases as a result of the importation of the Drilling Unit into a specific Area of Operations, CONTRACTOR shall notify Vastar of the increase in premium prior to payment by CONTRACTOR, and Vastar, at its sole option shall, within 48 hours of being given such notice either agree to reimburse CONTRACTOR for the documented increase in premium or allow the Drilling Unit to depart the Area of Operations for safe harbor once the well in progress is made safe.

3

EXHIBIT D

SAFETY, HEALTH, AND ENVIRONMENT MANAGEMENT SYSTEM

CONTRACTOR agrees in addition to CONTRACTOR’S Safety, Health and Environment program and COMPANY’S Safety, Health and Environment Manual (“SHE Manual”). to develop a “RIG SITE SAFETY MANAGEMENT SYSTEM”. The system shall contain provisions for self-monitoring and accountability. The Rig Site Safety Management System shall, at a minimum, address the following items: 1. Safety and job planning meetings. 2. Training drills to verify viability of all response plans and to develop personnel. 3. A “Work Permit System” to include the following:

a. Hotwork outside safe welding areas, b. Confined Space Entry, c. Working on High Pressure Lines, d. Pumping of Hazardous Materials, e. Maintenance of Life Boats, f. Bypassing or repairs to “Critical Safety Systems,” g. Handling of radioactive sources and explosives, h. Any work involving Dynamic Positioning system equipment, i. Work on or near remote start equipment, and j. Crane offload or backload lifts from workboat greater than 15 tons.

CONTRACTOR shall ensure that: 1. All chemicals received and shipped from the Drilling Unit are properly labeled, container undamaged, and a MSDS sheet

accompanies product shipment. CONTRACTOR shall be responsible for the proper disposition of CONTRACTOR’S generated waste such as, but not limited to; lube oils, motor oils, antifreeze, batteries, tires, rubber products, junk iron, drill line, etc.

2. An inventory of all hazardous materials and chemicals is maintained on the Drilling Unit. 3. All radioactive sources and explosives shall be stored in appropriate and approved magazines. 4. All source containers are to be locked and stored in a safe area away from normal operations, living quarters and passage

ways. 5. All personal protective equipment is identified and required to be used with each work activity.

1

6. CONTRACTOR will provide a Readiness Checklist for the following critical operations including, but not limited to, such

as; Drill floor pre-tour, DP pre-tour, hydrocarbon transfer, lifesaving equipment, monthly Drilling Unit inspection, radioactive and explosives usage.

7. CONTRACTOR shall have in place a Safety Observation Program. 8. CONTRACTOR shall perform; pre-tour safety and weekly safety meetings, fire, abandon, man overboard and helicopter

crash drills. Scenario drill records are to filed on location and be available for review by COMPANY’S personnel and regulatory bodies.

9. CONTRACTOR shall provide a designated firefighting team and equipment complete with back-up firefighting team. 10. CONTRACTOR and COMPANY will work together to incorporate an individual safety incentive program to be combined

with safety and rig personnel performance and mutually agreed upon at a later date. 11. CONTRACTOR shall have an active Alcohol and Drug Screening Program. CONTRACTOR agrees to conduct periodic

searches and testing for such substances. CONTRACTOR’S personnel who are considered to be safety sensitive personnel under the Department of Transportation regulations shall be subject to and in compliance with the U.S. Coast Guard regulations with respect to drug and alcohol testing as set forth in 46 CFR Parts 4 and 16, and 49 CFR Part 40.

12. CONTRACTOR shall ensure that all its employees receive Hazardous Materials training and how to use OSHA Form 20,

known as Materials Safety Data Sheets, which permits employee reporting on toxic substances. 13. CONTRACTOR shall maintain current records of training and certification of personnel for the following: Hazcom, Well

Control, Ballast Control, Crane Operations, Hotwork Firewatch Training, Welding, and Electrical. CONTRACTOR is required to maintain a Training Matrix Schedule for each position.

14. CONTRACTOR shall insure that Drilling Unit housekeeping, cleanliness and personal hygiene meets requirements of

COMPANY’S SHE manual. 15. CONTRACTOR shall have on location at all times at least two (2) personnel trained in oil spill containment and hazardous

materials handling and clean up. 16. CONTRACTOR shall immediately report to COMPANY’S representative, regardless of quantity, all environmentally

sensitive spills such as, but not limited to, hydrocarbons or toxic materials. 2

17. CONTRACTOR to have an updated Spill Contingency Plan on site at all times. 18. CONTRACTOR shall immediately report to COMPANY’S representative and maintain records of the following: all

incidents including but not limited to near misses, first aids, recordable accidents, lost time injuries, illnesses, spills, pollution, incidents involving hazardous and explosive materials, property and equipment damage.

19. CONTRACTOR shall maintain a daily Personnel on Board list to include personnel name, company and position. 20. During hurricane season, CONTRACTOR shall keep an updated Hurricane Evacuation Procedure complete with operational

times to: secure the well, recover the riser/BOP’s, secure the rig and offload all non essential or all personnel if required. CONTRACTOR SAFETY REPORTING: CONTRACTOR shall provide to the COMPANY’S Safety, Health and Environmental Representative a completed accident investigation report within twenty-four hours of each occurrence designated in Exhibit D-18 above. CONTRACTOR shall submit additional information each month concerning safety performance of CONTRACTOR’S employees in connection with the work performed hereunder. The following is a breakdown of the information that shall be submitted on or before the tenth day of each month for the previous month’s safety performance. 1. Total man hours worked (month / YTD) 2. Total lost time accidents (month / YTD) 3. Total lost time days (month / YTD) 4. Total recordable accidents (month / YTD) 5. Total first aid cases (month / YTD) 6. Total cost equipment / property damage (month / YTD) 7. Any safety or health inspections, warnings, notices or asserted violations issued by any governmental agencies This information should be mailed or telecopied to: SHE Representative Vastar Resources, Inc. 15375 Memorial Drive Houston, Texas 77079 Telephone: 281/584-6100 FAX: 281/584-6810

3

SAFETY MANUAL RECEIPT ACKNOWLEDGMENT

Attached to the Drilling Contract between Vastar Resources, Inc.. and R&B Falcon Drilling Co. dated as of December 9, 1998. Ron Tafery a duly authorized representative of Contractor and on behalf of Contractor hereby acknowledges receipt of the “Safety and Health Manual” of Vastar Resources, Inc. Contractor agrees that they have or agree to become familiar with said Safety and Health Manual and shall, to the extent not inconsistent with Contractor’s manual, policy and procedures, comply and cause Contractor’s employees, agents and others under Contractor’s control entering upon Vastar Resources’ premises in the performance of work or services or in connection therewith to comply with the applicable standards contained in the Safety and Health Manual of Vastar Resources, Inc. Vastar is not required by Contractor to police Contractor’s compliance with any safety, health, and environmental rules, laws, regulations or orders and Contractor’s agreement to comply therewith shall not impose any obligation on the part of Vastar under such rules, laws regulations or orders. Contractor: R&B Falcon Drilling Co.

4

Name: Ron Tafery

Title: Vice President

Signature: /s/ Ron Tafery

Date: December 9, 1998

EXHIBIT E

TERMINATION PAYMENT SCHEDULE

Termination Pursuant to Article 27 Should COMPANY terminate the CONTRACT pursuant to Article 27.1, COMPANY shall pay CONTRACTOR a Lump Sum Payment as liquidated damages and not as a penalty, within ninety (90) days of termination calculated as follows: Lump Sum equals Operating Rate less eighty (80)% of the documented operating costs times the number of days remaining under the Contract Term discounted to present value using the annual prime rate of interest as posted by CitiBank N.A. on the first day of the month in which Company terminates the Contract. During the remaining Contract Period, CONTRACTOR shall make a good faith effort to market the Drilling Unit. Should CONTRACTOR be successful, CONTRACTOR shall refund to COMPANY any funds actually received or accrued from any other entity for the use of the Drilling Unit as follows:

1

(1) The repayment will be reduced by the eighty percent (80%) of the fixed cost not already paid by COMPANY.

(2)

The repayment will be reduced by an amount equal to five percent (5%) as an incentive for CONTRATOR to actively market the Drilling Unit.

(3)

Repayments by CONTRACTOR to COMPANY shall never exceed Contract Rate.

EXHIBIT F-1

CREW COMPLEMENT

1

Drill Crew Total

On Board

Remarks Drilling Rig Supt

2

1

Toolpusher 4

2

Driller 4 2

Asst. Driller 8

4

Pumpman 4 2

Floorman 12

6

Maintenance Supervisor (Electrical) 2

1

Electrician 4

2

Assistant Electrician 2

1

Electronic Technician 4 2

Mechanic 4

2

Assistant Mechanic 2 1

Welder 2

1

Sub Sea Engineer 2

1

Assistant Sub Sea 2

1

Crane Operator 4

2

Roustabout 16 8

RTSC 2

1

Medic 2 1

Materialsman 4

2

Captain/OIM

2

1

Chief Officer 2

1

D.P. Operator 4 2

Assist. D.P. Operator 4

2

A.B. Seaman/Painters 6 3

Chief Engineer 2

1

First Engineer 2

1

2 Engineer 4

2

Oiler/Motorman 4

2

Boatswain 2 1

Galley As Needed

Total: 118

59

a) Galley crew ratio of one to every 10 persons on board.

b) A mutually agreed pre-commencement manning schedule shall be attached.

c)

Contractor may, with Company approval, reduce the marine crew manning based upon Coast Guard requirements, when available.

nd

EXHIBIT F-2

COST OF ADDITIONAL PERSONNEL

1

Title

Total

OnDrilling

Rig

RegularHourly Rate ($)

OvertimeRate with Burden

Daily RatePer Man (w/

Burden)

Drilling Rig Supt

2

1

34.83

75.76

831.81

Toolpusher 4 2 30.48

66.29 736.47Driller

4

2

25.69

55.88

637.43

Asst. Driller

8

4

17.85

38.83

465.29

Pumpman

4

2

13.50

29.36

369.78

Floorman

12

6

13.00

28.28

358.80

Maintenance Supervisor (Electrical) 2 1 26.12

56.81 641.12Electrician

4

2

21.77

47.36

551.36

Assistant Electrician 2 1 16.50

35.89 435.65Electronic Technician

4

2

22.86

49.72

575.30

Mechanic

4

2

21.77

47.36

551.36

Assistant Mechanic

2

1

16.50

35.89

435.65

Welder

2

1

15.75

34.26

419.18

Sub Sea Engineer 2 1 25.44

55.33 631.95Assistant Sub Sea

2

1

21.77

47.36

551.36

Crane Operator 4 2 16.55

36.00 436.75Roustabout

16

8

11.00

23.93

314.88

RTSC

2

1

17.85

38.83

465.29

Medic

2

1

15.67

34.09

417.42

Materialsman

4

2

15.02

32.67

398.00

Captain/OIM

2

1

35.70

77.65

850.88

Chief Officer 2 1 26.12

56.81 641.12D.P. Operator

4

2

29.17

63.45

707.86

Assist. D.P. Operator

4

2

22.64

49.24

570.47

A.B. Seaman/Painters

6

3

11.00

23.93

314.88

Chief Engineer

2

1

28.30

61.55

688.79

First Engineer 2 1 22.64

49.24 570.472 Engineer

4

2

19.59

42.62

503.50

Oiler/Motorman 4 2 14.00

30.45 380.76Boatswain

2

1

17.42

37.89

455.85

Galley

As Needed

Total:

118

59

nd

RBS8-D REPORTING ORGANIZATION CHART

EXHIBIT G

VESSEL / EQUIPMENT PERFORMANCE / ACCEPTANCE

VESSEL TESTS / ACCEPTANCE CONTRACTOR and COMPANY agree that the Drilling Unit must satisfy various sea worthy type certifications, including but not limited to, U.S. Coast Guard, ABS, and certifications pertinent to the flag the vessel will be registered under. CONTRACTOR shall supply COMPANY with a copy of these certificates witnessed or approved by any regulatory body. CONTRACTOR shall provide OPERATOR with a preliminary copy of the Drilling Unit’s Operations Manual as soon as it is available, prior to the Commencement Date and a final signed, dated and approved by ABS, as soon as received. Additional vessel and equipment function/acceptance test criteria shall be developed and mutually agreed by CONTRACTOR and COMPANY and provided by the CONTRACTOR as a condition of delivery of the vessel. These shall include, but not be limited to: vessel, equipment acceptance, seatrials, full scale recoil test, dynamic position system (DP) / power systems failure mode effect analysis (FMEA) and fault tree analysis and a blowout preventer (BOP) multiplex control system (Mux) System FMEA and fault tree analysis. In principle, Shipyard Sea Trials shall be conducted as specified in the Shipyard Specifications, Chapter 18, Test and Trials. Additional test may be required upon arrival in the Gulf of Mexico, as mutually agreed. The project managers of the Parties agree to provide the following:

1

• Vessel / equipment acceptance / seatrials procedures: one (1) month prior to delivery• DP/power systems FMEA and fault tree analysis: two (2) month after final design• BOP mux control system FMEA and fault tree analysis: two (2) month after final design

EXHIBIT H

PROJECT EXECUTION PLAN

Construction and operation of the Drilling Unit (RBS8D) represents a major financial commitment to the Parties. Additionally, the Drilling Unit will be an integral part of COMPANY’S long range business plan for oil and gas exploration in the deepwater’s of the Gulf of Mexico. Any change in cost, delivery or operability relating to the Drilling Unit could have a substantial impact on COMPANY’S plan, therefore, COMPANY must be notified immediately of any changes that would effect these items. To help mitigate the risk, a mutually agreed Project Execution Plan will be developed to insure the Drilling Unit is delivered on time, within budget, is outfitted and will operate in accordance with this CONTRACT. To ensure that the latest technology is incorporated and maximum performance achieved, representatives from third party suppliers shall also be included. As a minimum, The Project Execution Plan will address the following items in appropriate detail:

Without limiting CONTRACTOR’S obligations under this CONTRACT, COMPANY will provide representatives to monitor the design and construction of the Drilling Unit. Any changes to the Drilling Unit that would effect the Dayrate, delivery or operability will require an amendment to the CONTRACT as set forth in Article 35.2. All changes to the design or specifications set forth in this CONTRACT require the Company Project Manager approval. The project manager of the Parties agree to have a mutually agreed Project Execution Plan finalized by February 1, 1999.

1

• Project Goals/Operating Principles • Project Organization

• Roles/Responsibilities/Accountabilities • Project Description/Schedule/Milestones • Overall Assurance Plan • Safety • Interface Coordination Plan (Communication)• Quality Plan • Document Control • Approval Process • Change Control Procedures • Management of Change • Meeting/Presentation Schedule • Risk Management Register • Cost Control

April 13, 1999 Vastar Resources, Inc. 15375 Memorial Drive Houston, TX 77079 Attention: Mr. Don Weisinger Re: Drilling Contract dated December 08, 1998 between Vastar Resources, Inc. and R&B Falcon Drilling Co. for the Drilling Unit “RBS-8D” - Effective Date Establishment of Base Figures in accordance with Article 2.3.2 of the Contract Gentlemen: Pursuant to Article 2.3.2, we wish to advise that our base figures for the 4 items are as follows:

As the United States Department of Labor has not yet published the final December, 1998 index for Code No. 1191.02 “Oil Field and Gas Field Drilling Machinery”, the above base index of 133.8 is still officially classified as preliminary and may be subject to change. The final index will be published in early May 1999. We shall write to you again at this time either to confirm 133.8 as the final figure or to advise the new figure. In any event, we felt it best not to further delay the submission to you of the other base figures due to the 4 month time lag in the publication of Government economic statistics. Whilst writing, we wish to bring to your attention the following errors in Exhibit F-2 “Cost of Additional Personnel”:

We shall go ahead and formally change Exhibit F-2 to show the correct rates and revised corresponding extension figures upon receipt of your agreement to the above.

R&B Falcon Corporation 901 Threadneedle • Houston, Texas 77079 • (281) 496-5000 www.rbfalcon.com

a. Labor (all inclusive) U.S.$21,420 \ Day b. Catering U.S.$2,364 \ Day c. Spare Parts & Supplies PPI Code No. 1191.02 Base = 133.8 (Preliminary - December, 1998) - d. Insurance U.S.$2,660 \ Day

Title Hrly Rate Shown Correct Hrly Rate

Drilling Rig Supt $ 34.83 Should be $ 35.70

Captain/OIM $ 35.70

Should be

$ 34.83

Chief Officer $ 26.12 Should be $ 27.43

D. P. Operator $ 29.17

Should be

$ 23.08

Assist D. P. Operator $ 22.64

Should be

$ 20.90

Sincerely yours,

R&B Falcon Drilling Co.

/s/ W.L. Ellis W.L. Ellis

Regional Operations Manager

Contract Budget Request

RBS8-D Vastar Resources, Inc. / Gull of Mexico Expatriate Rig Payroll

Exchange Rate: US $1.00 =1 U.S. $ [03PAY]

Total Per Employee Budgeted

Budgeted

Annual

Regular

Regular

Regular Regular

Payroll/

Payroll

On Board Total Work Monthly Monthly Monthly

Annual Calenday PerRig-based

Expats Expats

Days

Base

Travel Pay

Total Total

Day

Work Day

Asst. Superintendent* 1.00 2.00 182.50 8,000 8,000 96,000 263 526

Toolpusher 2.00 4.00 182.50 7,000 7,000 84,000 230 460

Tourpusher 0 0

Barge Engineer* 6,000 6,000 72.000

Asst. Barge Engineer* 4,800 4,800 57,600

Maintenance Supervisor* 1.00 2.00 182.50 6,000 6,000 72,000 197 395

Driller 2.00 4.00 182.50 5,900 5,900 70,800 194 388

Alternate Driller 4.00 8.00 182.50 5,000 5,000 60,000 164 329

Alternate Driller Trainee 0 0

Derrickman 3,330 3,330 39,960

Pumpman 2.00 4.00 182.50 3,101 250 3,351 40,212 110 220

Motorman 3,215 3,215 38,580

Welder 1.00 2.00 182.50 3,617 3,617 43,404 119 238

Crane Operator 2.00 4.00 182.50 3,800 3,800 45,600 125 250

Heavy Lift Crane Operator** 0 0

Barge Captain 0 0

Asst. Barge Captain 0 0

Control Room Operator* 4,500 4,500 54,000

Asst. Control Room Operator* 3,600 3,600 43,200

Mechanic 2.00 4.00 182.50 5,000 5,000 60,000 164 329

Asst. Mechanic 1.00 2.00 182.50 3,790 3,790 45,480 125 249

Mechanic Helper 0 0

Electronic Technician* 2.00 4.00 182.50 5,250 5,250 63,000 173 345

Electrician 2.00 4.00 182.50 5,000 5,000 60,000 164 329

Asst. Electrician 1.00 2.00 182.50 3,790 3,790 45,480 125 249

Electrician Helper 0 0

Subsea Engineer* 1.00 2.00 182.50 7,000 7,000 84,000 230 460

Asst. Subsea Engineer* 1.00 2.00 182.50 5,000 5,000 60,000 164 329

Materialsman 0 0

Storekeeper 2.00 4.00 182.50 3,450 3,450 41,400 113 227

Medic 1.00 2.00 182.50 3,450 3,450 41,400 113 227

Radio Operator 3,101 3,101 37,212

Floorman 6.00 12.00 182.50 2,986 250 3,236 38,832 106 213

Lead Roustabout 0 0

Roustabout 8.00 16.00 182.50 2,526 250 2,776 33,312 91 183

Paint Foreman 0 0

Painter 2,124 2,124 25,488

Captain/Master*** 1.00 2.00 182.50 8,000 8,000 96,000 263 526

Chief Officer*** 1.00 2.00 182.50 6,300 6,300 75,600 207 414

First Officer*** 5,300 5,300 63,600

Second Officer*** 4,800 4,800 57,600

Third Officer*** 4,200 4,200 50,400

Chief Engineer*** 1.00 2.00 182.50 6,500 6,500 78,000 214 427

First Engineer*** 1.00 2.00 182.50 6,000 6,000 72,000 197 395

Second Engineer*** 2.00 4.00 182.50 5,200 5,200 62,400 171 342

Bosun*** 1.00 2.00 182.50 4,000 4,000 48,000 132 263

Deck Supervisor*** 4,000 4,000 48,000

D.P. Operator*** 2.00 4.00 182.50 5,300 5,300 63,000 174 348

Asst. D.P. Operator*** 2.00 4.00 182.50 4,800 4,800 57,600 158 316

Oiler*** 2.00 4.00 182.50 3,215 250 3,465 41,580 114 228

Able Seaman*** 3.00 6.00 182.50 2,526 250 2,776 33,312 91 183

Rig Safety & Training Coordinator 1.00 2.00 182.50 4,100 4,100 49,200 135 270

Other 0 0

Total 59.00 118.00 Overtime Wages Total 0

OIM Premium ($4,800 if applicable) 4.800

Total Annual Expatriate Payroll 6,257,544

Total Per Day Expatriate Payroll 17,144 (Posts to Rig Payroll)

* Semisubmersibles Only

** Super Tenders Only Total Payroll Burden Per Day 20% 3,429 (Posts to Payroll Burden)


RBS8-D / Vastar Resources, Inc. / Gulf of Mexico Expatriate Training Costs

Exchange Rate: US $1.00 =1 U.S. $ [09XPTTRN]

Employee Name

Employee Position

Name of School

School

Location

# ofDays

TrainingWages

Per Day

OutsideTuition

InternationalAirfare

Domestic/ Charter

Hotel

Per Day

MealsPer Day

Other

T.B.A.

Various Well Control

10

75

2,500

300

100

35

20

T.B.A. Various

Cyberchair

10

75

2,500

300 100

35

20

T.B.A. Various

Varco 10 75 2,500 300

100 35 20T.B.A.

Various PM

10

75

2,500

300

100

35

20

T.B.A. Various

GE

10

75

2,500

300 100

35

20

T.B.A. Various

Burgess

10

75

2,500

300 100

35

20

T.B.A. Various

Brandt

10

75

2,500

300 100

35

20

T.B.A. Various

Fire Fighting

10

75

2,500

300 100

35

20

T.B.A. Various

Sea Survival

10

75

2,500

300 100

35

20

T.B.A. Various

Wartslia 10 75 2,500 300

100 35 20T.B.A.

Various Kamewa

10

75

2,500

300

100

35

20

T.B.A. Various

Simrad

10

75

2,500

300 100

35

20

T.B.A. Various

High Voltage

10

75

2,500

300 100

35

20

T.B.A. Various

Alborg 10 75 2,500 300

100 35 20T.B.A.

Various Bridge Mgn

10

75

2,500

300

100

35

20

T.B.A. Various

Radar

10

75

2,500

300 100

35

20

T.B.A. Various

GMDSS

10

75

2,500

300 100

35

20

T.B.A. Various

HLO

10

75

2,500

300 100

35

20

T.B.A. Various

Crane Ops

10

75

2,500

300 100

35

20

T.B.A. Various

AWC

10

75

2,500

300 100

35

20

T.B.A. Various

STOP / H2S 10 75 2,500 300

100 35 20T.B.A.

Various EPT

10

75

2,500

300

100

35

20

T.B.A. Various

DGPS

10

75

2,500

300 100

35

20

230

1,725

57,500

6,900

0 2,300

805

460

Total Training Wages

17,250

Total Outside Tuition 57,500

Total Training Travel

38,410

Total Training Costs

113,160

Per Day Training Costs

310 (Posts to Training Costs)


RBS8-D / Vastar Resources, Inc. / Gulf of Mexico Expatriate Operational Travel

Crew Change Commuter Travel

Exchange Rate: US $1.00 =1 U.S. $ [15EXTRAV]

Annual Cost Per Trip

Total

Round

Airport of Origin

Total Personnel

Roundtrips Per Emp.

International

Airfare

Domestic/Charter

Hotel

Meals

Other

Annual costs

CommuterSchedule

TripsPer Year

East Coast 12

8.69 300 75 35 20

44,840 7x7 26.07

West Coast 12

8.69

300

75

35

20 44,840

14x14

13.04

North Central 12

8.69

200

75

35

20 34,412

21x21

8.69

Texas 12

8.69

100

75

35

20 23,984

28x28

6.52

Louisana 12

8.69 100 75 35 20

23,984 35x35 5.21

Mississippi 12

8.69

100

75

35

20 23,984

42x42

4.35

Other 4

0 56x56

3.26

0 14x7

17.38

0 21x14 10.43

0 28x14

8.69

0 56x28

4.35

0 112x56 2.17

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

Expatriate Commuters

76 Total Annual Expatriate Commuter Travel

196.046

Expat Cost / Man / Calendar Day

7.07

Total Annual Expatriate Operationl Travel

196,046

Total Per Day Expatriate Operational Travel 537

(Posts to Operational Travel)


RBS8-D / Vastar Resources, Inc. / Gulf of Mexico Catering

NOTE: AVG OPERATOR ON BOARD = ACTUAL AVERAGE OPERATOR/THIRD PARTY PERSONNEL ON BOARD. MANUAL INPUT REQUIRED. OPERATOR RECHARGE = AUTOMATIC CALCULATION. NET OPERATOR CATERING = CONTRACT SPECIFIED NUMBER OF OPERATOR/THIRD PARTY PERSONNEL TO PROVIDE CATERING. MANUAL INPUT REQUIRED.

Exchange Rate: US $1.00 =1 U.S. $ [12CAT]

Category Personnel

On Board

MandayRate

Total/Day Per

Category

AnnualCatering

Costs Expatriate

59.00

34.26

2,021 737,789

TCN

0.00

34.26

0 0

National

0.00

34.26

0 0

Total Regular Crews 59.00 2,021 737,789

AVG OPERATOR ON BOARD

30.00

34.26

1,028 375,147

OPERATOR RECHARGE

(20.00) (34.26) (685) (250,098) NET OPERATOR CATERING

10.00

Office Staff 0.00

34.26

0

0

Crew Change

0.00 34.26

0

0

Other Mandays

0.00 34.26

0

0

Total Other Mandays

0.00

0

0

Other Annual Amounts

0

Other Annual Amounts 0

Total Annual Catering Cost

862,838

Daily Personnel On Board

89.00

Total Per Day Catering Cost

2,364 (Posts to Catering)

Data extracted on: April 12, 1999 (10:20 AM) Producer Price Index-Commodities Series Catalog: Series ID : wpu119102 Not Seasonally Adjusted Group : Machinery and equipment Item : Oil field and gas field drilling machinery Base Date : 8200 Data:

P: Preliminary. All indexes are subject to revision four months after original publication.

http://146.142.4.24/cgi-bin/srgatc

Year Jan

Feb Mar

Apr May

Jun

Jul

Aug

Sep

Oct Nov

Dec

Ann

1989 96.9

97.1 97.2 97.1

97.6 97.6 97.6 98.4 98.6 99.3 99.5 99.5 98.0

1990 99.6

99.6 99.2

99.2 99.3

99.9

100.2

101.5

105.8

106.2 106.6

106.6

102.0

1991 106.7

107.7 108.7

108.8 110.0

110.0

110.0

110.0

110.0

110.0 110.1

110.1

109.3

1992 110.1

110.1 110.1

110.1 110.2

110.4

110.6

110.6

110.6

110.8 112.4

112.5

110.7

1993 112.8

112.9 113.3

112.1 112.0

112.2

112.3

112.3

113.4

113.4 113.4

114.6

112.9

1994 114.6

114.6 114.6 114.6

114.7 114.9 115.4 115.4 115.9 117.8 117.8 117.8 115.7

1995 118.3

118.6 119.2

119.2 119.3

119.6

120.4

120.4

120.4

122.0 122.2

122.2

120.1

1996 124.0

124.0 124.0 124.3

124.2 124.8 125.3 125.3 125.3 126.2 126.6 127.1 125.1

1997 127.7

127.9 128.6

129.1 129.2

129.3

129.3

129.5

129.7

130.3 131.4

132.0

129.5

1998 133.1

132.9 133.1

133.0 133.0

133.0

132.9

132.9

132.9

133.6 133.6

133.8 (P) 133.2(P)1999

134.0 (P) 133.9 (P) 133.9 (P)

Data Home Page

BLS Home Page

Continued/......

To: John Luedtke Date: August 3, 1998 From: Robert B. Carvell

Subject: Estimated Annual Premium

RBS-8 M

Effective 15 March 1998

CONFIDENTIAL I. Coverage:

All Risk Hull & Machinery

Insured Value:

$325,000,000

Deductible:

$250,000 Per Occurrence

NET ANNUAL PREMIUM:

$528,996.80 II. Coverage:

Loss of Hire

Daily Indemnity: $189,000

Policy Limits:

180 Days

Deductible Period

21 Days

NET ANNUAL PREMIUM

$232,867 III. Coverage: Primary Marine Protection & Indemnity

Policy Limits:

$1,000,000 Per Occurrence

Deductible: $100,000 Per Occurrence

NET ANNUAL PREMIUM (U.S. WATERS)

$182,000.00

NET ANNUAL PREMIUM (FOREIGN WATERS)

$ 78,000.00 IV. Coverage:

Excess Liability

Policy Limits: $400,000,000

Deductible:

XS of Primary Marine P&I

NET ANNUAL PREMIUM $6,795.00

Memo

V. Coverage:

Contingent Energy Exploration & Development

Policy Limits:

$100,000,000

Deductible $250,000 Per Occurrence

NET ANNUAL PREMIUM

$704.76 VI. U.S. Brokers:

Aon Risk Services, Inc.

ANNUAL FEE

$19,379.85 TOTAL ANNUAL PREMIUM: (U.S. Waters) $970,743.41

(Foreign Waters)

$866,743.41

July 24, 2001 Vastar Resources, Inc 15375 Memorial Drive Houston, TX 77079

Dear Mr. Weisinger, Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“R&B”) and Vastar Resources, Inc. (“Vastar”). Upon Commencement Date of the Contract, Vastar has requested and R&B agrees to provide two additional (2) Deck Foremen, four (4) Assistant Pumphands, four (4) Solid Control Technicians and four (4) Roustabouts in addition to those specified to be provided in Exhibit F-2 of the Contract, for operations on the semi-submersible Deepwater Horizon. Exhibit F-2 shall be amended, effective as of June 26, 2001 to provide for these additional personnel, at cost to be paid by Vastar based upon the following rates, subject to the labor cost escalations set forth therein:

Above rates are exclusive of a $65.00 per manday cost of training and transportation. Vastar reserves the right to elect to release one or all of the above additional personnel upon thirty (30) days written notice to R&B. R&B may, if at that time R&B deems such personnel necessary for its operations, elect to retain such personnel at its own cost.

Mike Roth MARKETING MANAGER NAR

R & B FALCON DRILLNG CO. 311 BROADFIELD BLVD., SUITE 400 HOUSTON, TEXAS 77084

Attn: Mr. Don Weisinger Re: Vastar Resources Inc. (“Vastar”) & R & B Falcon Drilling Company (“R &B”)

Drilling Contract — RBS-8D — Deepwater Horizon (“Rig”) (hereinafter referred to as the “Contract”) Deepwater Horizon Contract Amendment — Additional Personnel

Title

Total

OnRig

Overtime Rate(per person per

hour) with Burden

Daily Rate (per person) with Burden

Total Day Rate

with Burden

Asst. Pumpman

4

2

$ 27.18

$ 368.30 $ 736.60

Solid Control Tech

4

2

$ 27.18

$ 368.30 $ 736.60

Deck Foreman

2

1

$ 38.14

$ 478.93 $ 478.93

Roustabout

4

2

$ 23.08

$ 332.89 $ 665.78

TOTAL ADDITIONAL PERSONNEL

14

7 $ 2,617.91

PHONE: 281-647-8518 FAX: 281-647-8754 EMAIL:[email protected]

Except as expressly amended herein, the terms and conditions of the Contract shall remain in full force and effect as originally executed. If the above and foregoing sets forth your understanding of the agreement between R&B and Vastar, please sign both originals in the space provided below and return one fully executed original agreement to the undersigned. Sincerely, R & B Falcon Drilling Co.

AGREED AND ACCEPTED THIS 26 DAY OF JULY, 2001 VASTAR RESOURCES INC.


Deepwater Horizon Contract Amendment – Additional Personnel June 26, 2001TSF File #01-063

/s/ Mike Roth Mike Roth

SIGNED /s/ Don Weisinger

PRINTED Don Weisinger

TITLE Drilling Team Leader

December 12, 2001 BP America Production Company Attn: Don Weisinger 501 WestLake Park Blvd. Houston, TX 77079

Dear Mr. Weisinger, In accordance with Article 2 – Dayrates, Section 2.3 – Adjustment in Dayrates, we have recently completed an analysis of the costs of the Deepwater Horizon. To assist in clarification of position titles as related to the merger between R&B Falcon and Transocean, we have amended Exhibit F-1 – Crew Compliment and Exhibit F-2 – Cost of Additional Personnel. Both amended exhibits are attached and titled, Exhibit F-1a and Exhibit F-2a, which are the original Exhibit F-1 and F-2 with the only revisions made are position title changes as per the Naming Conventions of the merged company and will supercede the originals. Cost analysis for the Deepwater Horizon has been calculated based on the contract and the Establishment of Base Figures letter dated April 13, 1999. All costs have been reviewed and adjusted relative to the Contract Section 2.3.2 a) Labour Costs, b) Catering Costs, c) Spare Parts/Supplies Element, and d) Insurance Element. Please find the attached documents to substantiate our escalations including the Basis for Cost Escalations spreadsheet, Personnel List with rates, and the Bureau of Labor Statistics Data printout. The attached Basis for Cost Escalation Spreadsheet specifies the base rates, the new totals after this escalation and the variance column indicates the increase or decrease as appropriate per section. Payments of such adjustments shall be deemed to be effective beginning on the date the rig commenced operations, September 18, 2001. R&B shall issue an invoice for this retroactive adjustment and BP shall pay this invoice in accordance with the billing and payment procedures in the Contract. In accordance with the terms of the referenced contract, the parties agree to the following new dayrate changes under this letter of agreement:

TERRY BONNO

R & B FALCON DRILLING COMPANY SR. MARKETING REPRESENTATIVE

311 BROADFIELD BLVD., SUITE 400

HOUSTON, TEXAS 77084

Reference: Drilling Contract No. 980249 between Vastar Resources Inc. , predecessor in interest to BP America Production Company (“BP”) and R&B Falcon Drilling Company (“R&B”) dated December 9, 1998 for RBS-8D (now known as the Deepwater Horizon), as amended (the “Contract”)

Subject: Letter of Agreement for Cost Escalation and Naming Convention Adjustments

2.3.2a The Base Labor cost adjustment will be an increase of $6,876 from the baseline of $21,420 with a new total of $28,296. Labor will also increase by $239 on the additional personnel to a new total of $2,613.

2.3.2b Contractor’s cost of catering has decreased by ($541) to a new total of $2,067 under the baseline of $2,608.

PHONE: 281-675-8848 FAX: 281-647-8754

EMAIL:[email protected]

Except as expressly provided herein, the terms and conditions of the Contract shall remain in full force and effect. Each party represents that this letter agreement has been validly executed and delivered, and has been duly authorized by all action necessary for the authorization therefore. In summary, the following changes are effective as follows:

If the above and foregoing sets forth your understanding of the agreement between R&B and BP, please sign both originals in the space provided below and return one fully executed original agreement to the undersigned. If you have any questions, please contact the undersigned or John Keeton at Transocean’s Park Ten Office 281-647-8500.

AGREED AND ACCEPTED THIS 13th DAY OF JUNE, 2002 BP AMERICA PRODUCTION COMPANY

2

BP America Production Company

Deepwater Horizon Contract - Cost Escalation

TSF File #01-063

2.3.2c Based on the initial base Spare Parts/Supplies Element of $12,692, there will be an increase of $1,159 to a new baseline of $13,851.

2.3.2d The insurance element has decreased by $861 over the baseline figure of $2,660 and the new Total Base Insurance Cost will

be $1,799.

Paragraph 2.3.2a

$ 6,876

Paragraph

2.3.2a 239

(additional personnel)Paragraph

2.3.2b (541)

Paragraph

2.3.2c 1,159

Paragraph 2.3.2d

(861)

Total

$ 6,872

Sincerely,

/s/ Terry Bonno

Terry Bonno

Sr. Marketing Representative

On Behalf of R & B Falcon Drilling Co.

SIGNED /s/ R. Kevin Guerre

PRINTED R. Kevin Guerre

TITLE TL - SCM

EXHIBIT F-1a

CREW COMPLEMENT

1

Drill Crew Total On Board

Drilling Rig Supt/OIM

2 1

Toolpusher

4 2

Driller

4 2

Asst. Driller

8 4

Pumphand 4 2

Floorhand Roughneek

12 6

Maintenance Electrical Supervisor (Electrical) 2 1

Chief Electrician

4 2

Assistant Electrician

2 1

Chief Electronic Technician

4 2

Chief Mechanic

4 2

Assistant Mechanic

2 1

Welder

2 1

Sub Sea Supervisor Engineer 2 1

Assistant Sub Sea

2 1

Crane Operator

4 2

Roustabout

16 8

Rig Safety & Training Coordinator Officer

2 1

Medic

2 1

Materialsman Materials Coordinator

4 2

Captain Master/OIM

2 1

Chief Mate Officer

2 1

D. P. Operator

4 2

Assist. D.P. Operator

4 2

A.B. Seaman/Painters

6 3

Chief Engineer

2 1

First Asst. Engineer 2 1

2 Asst. Engineer

4 2

Motorhand

4 2

Beatswain Bosun

2 1

Galley

As Needed

Tota1:

118 59

a) Galley crew ratio of one to every 10 persons on board.b) A mutually agreed pre-commencement manning schedule shall be attached.c) Contractor may, with Company approval, reduce the marine crew manning based upon Coast Guard requirements, when

available.

Contract No. 980249

nd

BASIS FOR COST ESCALATIONS

DEEPWATER HORIZON As of September 1, 2001

1

Per Baseline

Costs Plus 2001

July 24, 2001 Letter

Sept. 2001

Variance

Base Labor Cost:

Labor & Burden (per schedule)

$ 20,573

25,476

4,903

Training & Transportation Costs

847

2,820

1,973

Total Base Labor Cost $ 21,420 $ 28,296 $ 6,876Percentage Increase

32% Additional Crew Increase per agreement dated July 24, 2001


2,163

2,278

115

Training & Transportation Costs $ 211 335 124Total Additional Personnel Cost $ 2,374 $ 2,613 $ 239Percentage Increase

10% Base Catering Cost:

59 Combined Personnel @ $ 27.20

$ 2,021

$ 1,605

(417)7 Additional Personnel @ $ 27.20 $ 244 $ 190 (53)10 Company Personnel @ $ 27.20

$ 343

$ 272

(71)Total Base Catering Costs $ 2,608 $ 2,067 $ (541)Percentage Increase

-21% Base Insurance Cost

$ 2,660 $ 1,799 $ (861)Percentage Increase

-32% Base Repair and Maintenance Cost

$ 12,692

$ 13,851

$ 1,159

Percentage Increase

9% Total Baseline Operating Costs

$ 41,754

$ 48,626

$ 6,872

Horizon Cost Escalations

DEEPWATER HORIZON

Adjusted Base Labor as of September 1, 2001

A B C D

Gulf of Mexico Crew Complement

GOM Base Labor w/Burden GOM Overtime Rates

No. of Personnel Daily Rate Total Daily

Daily HourlyJOB

On Assigned

(per person) On Board Rate Rate

CODE Board

To Rig JOB CLASSIFICATION

w/ Burden*

Cost** w/ Burden**

w/ Burden**

1

2 Offshore Installation Manager

930.23

855.23 Salaried

2

4

Toolpusher

761.90

1,373.80 Salaried

2

4

Driller

650.87

1,151.74 650.12

54.18

4

8 Assistant Driller

493.35

1,673.41 462.88

38.57

2

4 Pumphand

408.82

667.65 362.40

30.20

10

20 Floorhand

395.57

3,205.71 346.65

28.89

10

20 Roustabout 353.97 2,789.67

297.20 24.77

1

2 Welder

475.62

400.62 441.80

36.82

2

4 Crane Operator 493.35 836.70

462.88 38.57

2

4 Chief Mechanic

581.84

1,013.67 568.06

47.34

1

2 Mechanic

471.20

396.20 436.55

36.38

2

4 Motor Operator

395.97

641.93 347.12

28.93

1

2 Electrical Supervisor

663.46

588.46 Salaried

2

4

Chief Electrician 581.84 1,013.67 568.06 47.34

1

2

Electrician

471.20

396.20 436.55

36.38

2

4 Chief Electronic Technician 590.67 1,031.34

578.56 48.21

1

2 Senior Sub Sea Supervisor

768.23

693.23 Salaried

1

2

Assistant Sub Sea Supervisor

546.43

471.43 525.97

43.83

2

4 Materials Coordinator

435.79

721.58 394.46

32.87

1

2 Master

810.10

735.10 Salaried

1

2

Chief Mate 675.99 600.99 679.98 56.66

1

2

Chief Engineer

751.42

676.42 Salaried

1

2

1st Assist. Engineer 634.12 559.12 630.21 52.52

2

4

2nd Assist. Engineer

599.57

1,049.14 589.14

49.10

2

4 Dynamic Position Operator

546.43

942.86 525.97

43.83

2

4 Assistant Dynamic Position Operator

457.95

765.89 420.79

35.07

1

2 Deck Pusher

512.80

437.80 486.00

40.50

1

2 Bosun 457.95 382.95

420.79 35.07

3

6 Able Bodied Seaman

413.70

1,016.11 368.20

30.68

1

2 Rig & Safety Training Technician* 466.78 391.78

431.29 35.94

1

2 Rig Medic/Clerk 348.23 273.23

290.38 24.20

66

132 Total Base Labor Costs = $ 27,753.63

* Does include catering, transportation, or training expense.

** Does NOT include catering transportation, or training expense.

Notes: 1) The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short.

2) The figures in column “B” are the product of multiplying the number of “on board” personnel by the “Daily Rate

w/ Burden” in column “A”. The Sum of column “B” is the “Total Base Labor Cost” per day.

3) The figures in columns “C” and “D” are the basis for charging the Operator for overtime hours worked at the request of the Operator.

Data extracted on: June 13, 2002 (10:18 AM) Producer Price Index-Commodities Series Catalog: Series ID : wpu119102 Not Seasonally Adjusted Group : Machinery and equipment Item : Oil field and gas field drilling machinery Base Date : 8200 Data :

Preliminary. All indexes are subject to revision four months after original publication.

Bureau of Labor Statistics Data

Bureau of Labor Statistics U.S. Department of Labor

Home • Programs & Surveys • Get Detailed Statistics • Topics A-Z • Glossary • What’s New

Year Jan

Feb Mar

Apr May Jun Jul Aug Sep Oct

Nov Dec Ann1992

110.1 110.1

110.1 110.1

110.2

110.4

110.6

110.6

110.6

110.8 112.4

112.5

110.7

1993 112.8

112.9 113.3

112.1 112.0

112.2

112.3

112.3

113.4

113.4 113.4

114.6

112.9

1994 114.6

114.6 114.6

114.6 114.7 114.9 115.4 115.4 115.9 117.8

117.8 117.8 115.71995

118.3 118.6

119.2 119.2

119.3

119.6

120.4

120.4

120.4

122.0 122.2

122.2

120.1

1996 124.0

124.0 124.0

124.3 124.2 124.8 125.3 125.3 125.3 126.2

126.6 127.1 125.11997

127.7 127.9

128.6 129.1

129.2

129.3

129.3

129.5

129.7

130.3 131.4

132.0

129.5

1998 133.1

132.9 133.1

133.0 133.0

133.0

132.9

132.9

132.9

133.6 133.6

133.6

133.1

1999 133.8

133.7 133.7

133.9 133.9

134.0

134.0

133.7

133.7

133.7 134.4

134.6

133.9

2000 134.9

136.3 136.3

136.3 136.5

136.5

136.5

136.6

136.7

138.7 138.7

138.7

136.9

2001 143.5

143.9 144.0

144.0 144.0 145.5 145.6 145.8 145.7 146.1

146.1 146.1 145.02002

146.2 146.0 (P) 146.7 (P) 146.7 (P) 146.5 (P)

[ILLEGIBLE]& Security Statement • Accessibility Information

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Bureau of Labor Statistics Phone: (202) 691-5200 Square Building

Fax-on-demand: (202) 691-6325 2 Massachusetts Ave., NE

Data questions: [email protected], DC 20212-0001

Technical (web) questions: [email protected]

Other comments: [email protected]

CONFIDENTIAL

The following annual premiums have been established for the Deepwater Horizon and are effective September 1, 2001:

Memo

To:

Terry Bonno Date: December 6, 2001

From:

James Mitchell, Director of Risk Management

Subject:

Estimated Annual Premium – Deepwater Horizon

Coverage: Insured Value: Deductible: NET ANNUAL PREMIUM:

All Risk Hull & Machinery $350,000,000 ($5MM/$7.5MM/$7.5MM/$10MM aggregate layers) $470,329

Coverage: Policy Limits: Deductible: NET ANNUAL PREMIUM (US WATERS): NET ANNUAL PREMIUM (FOREIGN WATERS):

Primary Marine Protection & Indemnity $1,000,000 per occurrence $250,000 Per Occurrence $125,352 $53,796


Excess Liability $452,000,000 XS of Primary Marine P&I $26,334

U.S. BROKERS: ANNUAL FEE

McGriff Seibels & Williams, Inc. $34,454

TOTAL ANNUAL PREMIUM: (U.S. WATERS) $656,469 TOTAL ANNUAL PREMIUM: (FOREIGN WATERS) $584,913

Summary Escalations and baselines provide for increases in labor costs, catering costs, increases in the cost of repairs and maintenance and insurance premiums. All increases must exceed 5% and can be addressed as early as the Commencement Date and then only annually there after.

Rig Name Contractor & No.

Effective Date

CommenceDate

DurationMos. &

LastUpdate/

Reoccurrence

Timing Reoccurrence

ConditionHorizon(2) Vastar (BP) 01-063

Dec. 8, 1998 Sept. 1, 2001

Annually

=> 5%

12/8/98

Baselines9/1/01Costs

A. Baseline Labor

$ 21,420

$ 28,296

32.10% $ 6,876

Addtl Personnel

$ 2,374

$ 2,613

$ 239

Total Labor

$ 23,794 $ 30,909 $ 7,115

B. Catering

$ 2,608

$ 2,067

$ -541

C. Cost of R&M $ 12,692 $ 13,851 $ 1,159BLS Indices

133.6

145.8

9.13%

D. Insurance Premiums

$ 2,660

1,799.00

$ -861

$ 41,754 $ 48,626 $ 6,872

16%

April 23, 2002 Vastar Resources, Inc. C/O BP America Inc. 15375 Memorial Drive Houston, TX 77079 Attn: Mr. Mike Stefanov Reference: Deepwater Horizon Letter Agreement — Additional Personnel for Mad Dog Project CONTRACTOR-5121-

2002-005 Dear Mr. Stefanov, Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”) and Vastar Resources, Inc. (“Company”), as amended. Company has requested and Company and Contractor agree that CONTRACTOR will provide one (1) additional OIM and one (1) additional Sr. Toolpusher to work on the Mad Dog Project. The OIM and the Sr. Toolpusher will be shorebased and work at CONTRACTOR’s Park 10 office and at COMPANY’s offices as required to support the Mad Dog Project on an even rotating schedule. Work will commence on or about May 15, 2002 with an expected duration of approximately three (3) months. CONTRACTOR shall invoice COMPANY at the rate of US$1,200 (one thousand two hundred) per day with CONTRACTOR being responsible for all costs for lodging, food, transportation and CONTRACTOR required training. The OIM and Sr. Toolpusher will be available for work seven days a week on an even rotating schedule and COMPANY shall be billed for the full seven days each week. CONTRACTOR will supply supporting documentation with each monthly invoice as evidence of days available for work. COMPANY reserves the right to release the services of the OIM and Sr. Toolpusher at anytime upon thirty (30) days prior written notice to CONTRACTOR. COMPANY and CONTRACTOR will document when the OIM and Sr. Toolpusher are released from duty for services on this special Mad Dog Project assignment, thus ending the applicability of this contract amendment. All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect. If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our file.

R & B FALCON DRILLNG CO.

1311 BROADFIELD BLVD., SUITE 400 HOUSTON, TEXAS 77084

JOHN KEETON RIG MANAGER


We appreciate this opportunity to be of service to BP. If you have questions, please contact Terry Bonno for commercial concerns at 832-587-8848 or myself for technical concerns at 832-587-8533.

/ks AGREED AND ACCEPTED THIS 24 DAY OF APRIL, 2002 VASTAR RESOURCES INC.

2

VASTAR RESOURCES INC

Deepwater Horizon Letter Agreement - Additional Personnel

CONTRACTOR File #01-063

Sincerely,

/s/ John Keeton

John Keeton

R & B Falcon Drilling Co.

SIGNED /s/ Allen Cook

PRINTED Allen Cook

TITLE MD Well Delivery TL

June 3, 2002 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Jon Sprague

Mr. Charles Taylor

Reference: Deepwater Horizon Letter Agreement — Additional Personnel for Deepwater Horizon CONTRACTOR-5121-2002-006

Gentlemen: Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended. Company and CONTRACTOR have recently discussed and agreed that the current manning level on the Deepwater Horizon is not sufficient to produce the potential operating efficiency levels for this type of Drilling Unit. In addition, recent feedback from the crew provided clear evidence that the crews feel that there are insufficient personnel to conduct simultaneous operations. In a recent survey of crewing levels on similar Drilling Units in our fleet the following results were obtained:

Based on these findings and our experience on these Drilling Units, CONTRACTOR suggests the following additional personnel to be added to the Deepwater Horizon on a semi-permanent basis to afford both companies the opportunity to conduct simultaneous operations. Upon execution of this Letter Agreement by COMPANY and CONTRACTOR, CONTRACTOR agrees to provide two (2) additional Toolpushers, four (4) Floorhands, four (4) Crane Operators and eight (8) Roustabouts in addition to those specified to be provided in Exhibit F-2 of the Contract as amended, for operation on the semi-submersible Deepwater Horizon. Exhibit F-2 shall be amended to provide for these additional personnel, at cost to be paid by COMPANY based upon the following rates (as per the Escalation Letter Agreement dated December 12, 2001), subject to the cost escalations set forth therein:

In addition, COMPANY requests that one (1) additional Driller and welder per crew be added during the upcoming

R & B FALCON DRILLNG CO.

1311 BROADFIELD BLVD., SUITE 400 HOUSTON, TEXAS 77084

TERRY BONNO

SR. MARKETING REPRESENTATIVE

Horizon Nautilus

Marianas

Crew Total 72

88

96

Title Total

OnRig

Overtime Rate (perperson per hour)

with Burden

Daily Rate (per person) with

Burden

Total Day Ratewith Burden

Toolpusher 2

1

N/A

$ 761.90 $ 761.90

Floorhand 4

2

$ 28.89

$ 395.57 $ 791.14

Crane Operator 4

2 $ 38.57 $ 493.35 $ 986.70

Roustabout 8

4

$ 24.77

$ 353.97 $ 1,415.88


18 9

$ 3,955.62


twenty-one day batch setting exercise on Atlantis as follows:

COMPANY reserves the right to release the services of the additional personnel at anytime upon thirty (30) days prior written notice to CONTRACTOR. All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect. If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our file. We appreciate this opportunity to be of service to BP. If you have questions, please contact me for commercial concerns at 832-587-8848 or John Keeton for technical concerns at 832-587-8533.

/ks AGREED AND ACCEFTED THIS 10 DAY OF JUNE, 2002 BP AMERICA PRODUCTION COMPANY

2

VASTAR RESOURCES INC

Deepwater Horizon Letter Agreement - Additional Personnel

CONTRACTOR File #01-063

Title Total

OnRig

Overtime Rate (perperson per hour)

with Burden

Daily Rate (per person) with

Burden

Total Day Ratewith Burden

Driller 2

1

$ 54.18

$ 650.87 $ 650.87

Welder 2

1

$ 36.82

$ 475.62 $ 475.62


4 2

$ 1,126.49

Sincerely,

/s/ Terry Bonno

Terry Bonno R & B Falcon Drilling Co.

SIGNED /s/ R Kevin Guerre

PRINTED R Kevin Guerre

TITLE TL-SCM

th

TERRY BONNO SR MARKETING REPRESENTATIVE June 12, 2002 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Don Weisinger

Gentlemen: Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”) and Vastar Resources, Inc. (“Vastar”), predecessor in interest to BP America Production Company (“Company”), as amended. Company and Contractor have recently discussed and agreed to provide a Cameron 3-1/2” X 6-5/8” Variable Bore Rams (“Equipment”) for use on the Deepwater Horizon. This Letter Agreement outlines the terms and conditions to provide the Equipment as follows: 1. The Equipment is limited to the following components

2. Company has authorized Contractor to purchase Equipment and has agreed to a dayrate reimbursement fee of $125.00 per

day to be paid over the remainder of the Contract on the Deepwater Horizon. Dayrate reimbursement fee shall commence on June 13, 2002.

3. If the Contract is terminated prior to September 18, 2004, Company shall reimburse Contractor via a lump sum payment of

$125.00 per day times the days remaining in contract after termination date. Such payment shall be due within thirty days after presentation of an invoice to Company.

4. The Equipment provided under this agreement shall become part of Contractor’s equipment and incorporated into Exhibit B-

2 of the Contract. All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect.


Reference: Deepwater Horizon Letter Agreement – Cameron Variable Bore Rams Deepwater Horizon

CONTRACTOR-5121-2002-007

Description

Quantity Variable Bore Ram 18-3/4” 15M BOP, 3-1/2” X 6-5/8” OD Pipe, API

16A, ABS and DNV Certification

2 Ram Wear Pad, Right Side 18-3/4” BOP

2 Ram Wear Pad, Left Side 18-3/4” BOP

2 Screw, Ram Wear Pads

8


VASTAR RESOURCES, INC. Deepwater Horizon Letter Agreement – Variable Bore Rams CONTRACTOR File #01-063 If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our file. We appreciate this opportunity to be of service to BP. If you have questions, please contact me for commercial concerns at 832-587-8848 or John Keeton for technical concerns at 832-587-8533.

/ks AGREED AND ACCEPTED THIS 20 DAY OF JUNE, 2002 BP AMERICA PRODUCTION COMPANY

2

Sincerely,

/s/ Terry Bonno

Terry Bonno


SIGNED /s/ Jerry R Rhoads

PRINTED Jerry R Rhoads

TITLE Contracts Specialist

th

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE August 26, 2002 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads

Gentlemen: Reference is made for all purposes to that certain Offshore Drilling/Workover/Completion Contract dated December 9, 1998 (“Contract”), by and between R&B Falcon Drilling Co. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended. This is to document the recent agreement between our Mr. Doug Halkett and your Mr. Jon Sprague with respect to the cost of re-drilling the GC74344 well as a result of the recent “lost hole” incident. Due to the special circumstances involved in the recent event in which the hole was lost while running 20” casing, the parties agree that, by way of compromise and in order to avoid further disputes with respect to the obligations under the Contract with respect to such event, commencing as of 13:00 August 15, 2002, Contractor shall be obligated at Company’s election to re-drill the hole, and Company shall pay ninety percent (90%) of the applicable Operating Rate, until such time as the depth at which the hole was lost is reached, but otherwise all subject to the terms and conditions of the Contract. Once we reach the depth at which the hole was lost, the parties agree that the applicable Operating Rate shall control per the Contract. All other terms and conditions of the referenced Contract, as amended, shall remain in full force and effect. If the above sets forth your understanding of the agreement, please sign both originals in the space provided below and return one (1) fully signed original to us for our files. We appreciate this opportunity to be of service to BP. If you have questions, please contact me at 832-587-8506 or John Keeton at 832-587-8533.


Reference: Deepwater Horizon Letter Agreement -


Yours very truly,

/s/ Christopher S. Young Christopher S. Young



BP America Production Company. Deepwater Horizon Letter Agreement CONTRACTOR File #01-063 /ks AGREED AND ACCEPTED THIS 16 DAY OF SEPTEMBER, 2002 BP AMERICA PRODUCTION COMPANY

2




th

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE September 18, 2002 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads

Dear Mr. Rhoads, This letter will serve as our agreement to add another Deck Pusher to the crew complement of the Deepwater Horizon. Upon execution of this Letter Agreement by Company, Contractor agrees to provide one (1) Deck Pusher onboard the Deepwater Horizon in addition to those specified to be specified to be provided in Exhibit F-2 of the Contract as amended. Since we added the Deck Pusher in August, Exhibit F-l of the Contract shall be amended, as of August 1, 2002 to provide for the following additional personnel:

Therefore, the amended crew complement shall show two (2) Deck Pushers “On Board” and four (4) “Assigned to Rig”. The amended crew complement is attached. In summary, all rates in the Contract shall increase by $512.80 per day effective August 1, 2002. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

R&B FALCON DRILLING COMPANY 1311 BROADFIELD, SUITE 400 HOUSTON, TX 77084

Re:

Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject: Letter of Agreement for adding Deck Pusher


Title On Board

Assignedto Rig

Daily Rate perPerson w/ Burden

Hourly OvertimeRate w/Burden

Deck Pusher 1

2

$ 512.80 $ 40.50

Sincerely,

/s/ Christopher S. Young

Christopher S. Young

Sr. Marketing Representative On Behalf of R & B Falcon Drilling Co.

PHONE: (832) 587 8506 FAX: (832) 587 8754 EMAIL:[email protected]

2

BP

Horizon – Escalation 2002

TSF File #01-063

AGREED AND ACCEPTED THIS 2ND DAY OF DECEMBER, 2002 BP AMERICA PRODUCTION COMPANY SIGNED /s/ Jerry R Rhoads



DEEPWATER HORIZON

Adjusted Base Labor as of September 18, 2002

3

A B C D

Gulf of Mexico Crew Complement

GOM Base Labor w/Burden GOM Overtime Rates

No. of Personnel Daily Rate Total Daily

Daily HourlyJOB

On Assigned

(per person) On Board Rate Rate

CODE Board


w/ Burden*

Cost* * w/ Burden* *

w/ Burden* *

1883

1

2 Offshore Installation Manager

930.23

855.23 Salaried

1276

3

6 Toolpusher

761.90

2,060.70 Salaried

1295

2

4 Driller

650.87

1,151.74 650.12

54.18

1302

4

8 Assistant Driller

493.35

1,673.41 462.88

38.57

1845

2

4 Pumphand

408.82

667.65 362.40

30.20

1296

12

24 Floorhand

395.57

3,846.86 346.65

28.89

1297

14

28 Roustabout 353.97 3,905.54

297.20 24.77799

1

2

Welder

475.02

400.02 441.00

36.82

1289

4

8 Crane Operator 493.35 1,673.41

462.88 38.571381

2

4

Chief Mechanic

581.84

1,013.67 568.06

47.34

1286

1

2 Mechanic

471.20

396.20 436.55

36.38

1305

2

4 Motor Operator

395.97

641.93 347.12

28.93

1355

1


663.46

588.46 Salaried

1345

2

4 Chief Electrician 581.84 1,013.67

568.06 47.341280

1

2

Electrician

471.20

396.20 436.55

36.38

1387

2

4 Chief Electronic Technician 590.67 1,031.34

578.56 48.211388

1

2

Senior Sub Sea Supervisor

768.23

693.23 Salaried

1372

1

2 Assistant Sub Sea Supervisor

546.43

471.43 525.97

43.83

394

2

4 Materials Coordinator

435.79

721.58 394.46

32.87

1668

1

2 Master

810.10

735.10 Salaried

1299

1

2 Chief Mate 675.99 600.99

679.98 56.661539

1

2

Chief Engineer

751.42

676.42 Salaried

0

1

2 1st Assist. Engineer 634.12 559.12

630.21 52.520

2

4

2nd Assist. Engineer

599.57

1,049.14 589.14

49.10

1688

2

4 Dynamic Position Operator

546.43

942.86 525.97

43.83

1323

2

4

Assistant Dynamic Position Operator

457.95

765.89 420.79

35.07

1238

2

4 Deck Pusher 512.80 875.60

486.00 40.501298

1

2

Bosun

457.95

382.95 420.79

35.07

1300

3

6 Able Bodied Seaman 413.70 1,016.11

368.20 30.681608

1

2

Rig & Safety Training Technician*

466.78

391.78 431.29

35.94

1677

1

2 Rig Medic/Clerk 351.73 276.73

294.53 24.54

76

152 Total Base Labor Costs =

$ 31,475.54

*

Does include catering, transportation, or training expense.

* *

Does NOT include catering transportation, or training expense.

Notes: 1)

The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short.

2)

The figures in column “B” are the product of multiplying the number of “on board” personnel by the “Daily Rate w/ Burden” in column “A”. The Sum of column “B” is the “Total Base Labor Cost” per day.

3)

The figures in columns “C” and “D” are the basis for charging the Operator for overtime hours worked at the request of the Operator.

AGREEMENT FOR ASSIGNMENT OF DRILLING CONTRACT

This Agreement (“Agreement”) is entered into this 14 day of October, 2002 between R&B FALCON DRILLING CO. (hereinafter “RBFDC”), an Oklahoma corporation having an office at Park Ten Centre, 1311 Broadfield Boulevard, Suite 400, Houston, Texas 77084 and TRANSOCEAN HOLDINGS INC. (hereinafter “THI”), a Delaware corporation, having an office at 4 Greenway Plaza, Houston, Texas 77046. RBFDC and THI may hereinafter sometimes be referred to individually as “Party” and collectively as “Parties”. WHEREAS, RBFDC is a party to that drilling contract No. 980249 of December 9, 1998 with VASTAR RESOURCES, INC. (hereinafter “VASTAR”), now succeeded in interest by BP AMERICA PRODUCTION COMPANY (hereinafter “BP”), pertaining to the mobile offshore drilling unit “DEEPWATER HORIZON” (hereinafter “RIG”), as amended to date (hereinafter “Drilling Contract”); and, WHEREAS, RBFDC wishes to assign the Drilling Contract to THI and THI is willing to accept said assignment. NOW THEREFORE, for Ten Dollars (US$10.00) and other good and valuable consideration including the mutual covenants and agreements contained in this Agreement, the Parties agree as follows: 1.0 Effective at midnight October 31, 2002, RBFDC assigns to THI all of RBFDC’s rights and obligations under the Drilling

Contract, and THI accepts the assignment and agrees to assume and perform all the said obligations under the Drilling Contract.

2.0 RBFDC agrees to notify and provide reasonably requested documentation to the other party to the Drilling Contract to effect the assignment.

3.0 Written notice to a Party under this Agreement will be considered to be properly served if received at the Party’s address

appearing above by personal delivery or registered mail. 4.0 Any failure by a Party to enforce the terms of this Agreement or to exercise any rights will not constitute a waiver of those

terms or rights, nor will it constitute any precedence.

5.0 This Agreement is to be governed by and construed in accordance with the governing law provisions of the Drilling Contract.

IN WITNESS WHEREOF, the Parties execute this Agreement as of the date first above written.

R&B FALCON DRILLING CO.

TRANSOCEAN HOLDINGS INC. By: /s/ Jean P. Cahuzac

By: /s/ Eric B. BrownName: Jean P. Cahuzac

Name: Eric B. BrownTitle: Vice President


CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE November 1, 2002 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 (“Contract”) by and between R&B Falcon Drilling Company

predecessor in interest to Transocean Holdings, Inc,(“Contractor or TODDI”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Dear Randy, This letter is to document the agreement between Transocean Offshore Deepwater Drilling Inc. (TODDI) and Company for the rental of 18,000 feet of 6 5/8” R-3 drill pipe for use on the Deepwater Horizon. Company and TODDI hereby agree to the following terms and conditions:

1. TODDI shall purchase the following pipe and rent it to Company over the remaining term of the Contract referenced above. Specifications of the pipe are as follows:

* Changes from Grant Prideco quote 30726

2. Tooljoints (Pin & Box) shall be manufactured long enough to provide for a minimum of two full recuts and still have sufficient tong space excluding proud hardbanded area. Company’s coating, hardbanding and make & break specifications are attached and made a part of this Agreement.

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC. 1311 BROADFIELD, SUITE 400 HOUSTON, TX 77084

Subject: Letter of Agreement for 6 5/8” Drill Pipe Rental


Footage 18,000

Joints 439

Pipe OD 6 5/8”

Connection 6 5/8 FH

Weight 34.01

OD 8 / ”

Grade S-135

ID 4 / ”

Upset IEU

Pin Tong 10”

Range 3

Box Tong 13”

Internal Coating TK 34 XT* Hardfacing Pin

None Inspection

Truscope AS

Hardfacing Box Armacor M

Delivery

16 weeks*

Make & Break & 95% wall included

PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL:[email protected]

1 41 4

3. The rental rate will be approximately $3,000/day assuming that 18 months will be remaining on the contract at time of pipe

delivery and that the total cost of the pipe is approximately $1.29 million. The exact calculation will be made when the pipe is delivered and the total cost (based on good footage) and the remaining number of days in the term are known. The total rental amount to be recovered will be calculated at 1.27418155 times the total cost of the pipe. The total cost of the pipe will include inspection and transportation.

4. The rental rate shall begin upon delivery of the pipe to TODDI following acceptance in accordance with Company’s QA/QC

specifications and inspection criteria. These specifications and criteria are made a part of this Agreement. The rental rate shall cease when the total rental paid equals 1.27418155 times the final cost of the pipe. The rental agreement will continue as long the Contract is in force however the rental rate will be zero after the total rental paid equals 1.27418155 times the final cost of the pipe.

5. Contractor shall furnish all handling equipment required for this pipe during the term of the rental at no cost to Company. 6. Initial inspection is included in the cost of the pipe. Company reserves the right to re-inspect the pipe at Company’s cost.

Company will be responsible for all inspections during the term of the rental. 7. The pipe shall be treated as Contractor’s in-hole equipment per Article 22.3 of the Contract except for the cost of inspections. 8. During the term of the rental, Company will have the option of moving the pipe to another Transocean Rig at Company’s

option and expense. If you are in agreement with the above, please sign in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service. Sincerely,

AGREED AND ACCEPTED THIS 3RD DAY OF FEBRUARY, 2003 BP AMERICA PRODUCTION COMPANY







B P DEIP

INTERNAL PLASTIC

COATING OF DRILL PIPE

AND WORKSTRINGS

INTERNAL PLASTIC COATING OF

Procedure: BP-DEIP-IPC001 Revision: 1

DRILL PIPE AND WORKSTRINGS

Date: 6/6/02 Page: 1 Of: 7

Approved By:

Date:

1.0 Scope.

1.1 This procedure details the BP GoM requirements for internal plastic coating of both new and used drill pipe, workstrings and pup joints. Additionally, this procedure details the BP GoM minimum requirements for used internal plastic coatings.

1.2 This procedure includes a visual examination of all threaded connections after internal blasting at final inspection.

All workstring tubing, and workstring tubing pup joints will be full length drifted at final inspection. 2.0 Referenced Documents.

2.1 The following documents are used as references for establishing this procedure.

2.1.1 NACE TM-01-70 2.1.2 NACE TM-03-89 2.1.3 BP GoM OCTG Inspection Procedures and Requirements. 2.1.4 The Coating Contractor’s Standard Operating Procedures manual for the application and inspection of

internal coatings. 3.0 Contractors Internal Coating Operating Procedures And Equipment Capabilities.

3.1 The coating Contractor shall provide to BP for approval, complete standard operating procedures and equipment capabilities applicable to the individual pieces of equipment utilized for this process. The procedures will be of sufficient detail to enable the operator to perform required setup, calibration and adjustments to the equipment for preparation, application and inspection of the coatings.

4.0 Requirements For Material And Equipment.

4.1 All material, equipment, tools and supplies furnished by the Contractor shall be of good quality and adequate design, shall be maintained in good condition during use, shall conform to the requirements described in the Contractor’s Specifications and Standard Operating Procedures and shall be subject to BP’s approval.

5.0 Preparation.

5.1 Thread protectors shall be removed cleaned and stored until they are re-applied after final inspection. 5.2 All threaded connections shall be cleaned with steam cleaners, soapy water, varsol or other mineral spirits. 5.3 The material will then be visually examined internally for obvious defects, such as ridges or rough surfaces that

would limit the coat-ability of the material. Rejected lengths will be identified, marked, segregated from the prime material and BP will be notified. No attempt will be made to coat these lengths until corrections have been made. Material with uncorrectable damage will be classified as “not suitable for coating” (NSC).

5.4 The material will undergo a thermal cleaning by prebaking the material at 600° – 800° F (pipe temperature) for a

minimum period of 2 hours or as agreed to by BP. Longer prebake periods may be required depending upon the characteristics of the material being processed.

5.5 In order to insure that the proper oven temperatures are maintained, the BP QA/QC Inspector will be given a copy of

the heat charts. These heat charts will be included with the BP QA/QC Inspector’s final job report. Additionally, at BP’s request the contractor will satisfactorily demonstrate to the BP QA/QC Inspector that the surface temperature of the pipe meets but does not exceed the established temperature limitations during the thermal cleaning, regardless of the method by which the material is heated (i.e., conveyor system or batch ovens).

5.6 After thermal cleaning is completed, the material will be internally blasted “to white metal” with an abrasive

material to thoroughly clean and roughen the metal surface in order to form a suitable anchor pattern for coating.

Note: “White metal” blast cleaning is defined by NACE as follows: “White metal blasting cleaning is a method of preparing steel surfaces which, when viewed without magnification, shall be free of all visible oil, grease, dirt, drilling mud, cement, mill scale, rust, paint and coatings.” All surfaces blasted to “white metal” will be inspected visually from both ends, without magnification, using visual comparators to insure proper surface preparation to NACE TM-01-70.

5.7 The abrasive blasting operation will be repeated until the proper “white metal” surface condition is achieved. 5.8 The Material must be dry before abrasive blasting begins. 5.9 The compressed air used for abrasive blasting shall be free of water and oil. At the beginning of each shift the

operator will verify this. The operator will partially open the air supply at the blast station and hold a clean cloth or blotter against the airflow. If any oil or water is found, the system must be cleaned or dried prior to abrasive cleaning. Air pressure will be provided at 85 to 110 P.S.I. as measured at the blast plot.

5.10 The abrasive materials used for cleaning will be coarse Flintabrasive, Garnet, or other abrasive material meeting the

Contractor’s specifications. Prior to the start of the job, the Contractor shall present, blast material specifications and quality control procedures for abrasive materials, to BP for acceptance.

5.11 Prior to abrasive blasting, the material shall have protector masks installed to protect threads, seal areas and

shoulders from damage. 5.12 After abrasive blasting, the material shall be thoroughly cleaned with dry, oil free compressed air to remove abrasive

blasting material and other foreign material from the surface area. 5.13 The Contractor will conduct tests on both ends of the first 10 blasted pieces to establish that the anchor profile depth

and appearance are satisfactory. Thereafter, tests will be conducted on both ends of every twenty-fifth piece. The test must be conducted with Testex Coarse Press-O-Film or equivalent and measured with the appropriate gauge. These tests will be conducted after full length blasting but before end blasting. Acceptable anchor profile depth will be verified to the Contractor’s Specifications. At BP’s request the BP QA/QC Inspector shall witness these tests, maintain the test results and include them with the final job report.

5.14 After the material is blasted and the anchor profile depth and appearance tests are completed, the material will be

visually inspected to determine coat-ability. The material will be classified “not suitable for coating” (NSC), if, in the opinion of the Contractors representative or the BP QA/QC Inspector, the surface condition of the material would preclude application of coatings to the material in accordance with the Contractors Specifications. The Contractor must, however, make every reasonable effort to blast the surface of the material to a coat-able condition. The NSC material will be identified, marked and segregated from the coat-able material and BP shall be notified. If it is determined by the Contractor or the BP QA/QC Inspector that a second blast attempt on the NSC joint would possibly result in a coat-able piece, a second blast attempt, of at least two (2) passes, will be made.

6.0 Internal Plastic Coating Application.

6.1 Application of the coating material, as designated by BP, will be performed so that the required film thickness and coating properties are attained.

6.2 Coating, mixing, and thinning will be controlled in accordance with the Contractor’s Standard Operating

Procedures. These procedures will specify the coating material handling requirements, mixing methods, and general equipment settings necessary for a quality application.

6.3 Individual coats should produce a uniform continuous coverage of the internal surface. When additional coats are

required to meet specifications, those additional processes will be the decision and responsibility of the Contractor. 6.4 Prior to coating, the material shall be properly masked to protect the threads, seal areas and shoulders from coating

overspray or damage. 6.5 When required, a sample from each batch of liquid coating will be taken. This sample will be sealed with tape,

properly labeled with the batch number, job number and well charges. At BP’s request the BP QA/QC Inspector shall witness this process and initial each sample. The sample will be retained by the Contractor for subsequent evaluation, as directed, by BP.

6.6 Different coating batches will not be mixed on individual lengths of material. 6.7 The coating batch number(s) applicable to each BP order must be documented by the Contractor and retained in a

permanent job file. At BP’s request the BP QA/QC Inspector will verify the coating batch(s) utilized and include them in the final job report.

6.8 The shelf life of the batch(s) utilized on the BP material will be verified and documented by the Contractor. If the

age of the coating exceeds the manufacturer’s suggested shelf life, it will not be applied to the BP material. At BP’s request the BP QA/QC inspector will verify the shelf life of the batch(s) utilized and include them in the final job report.

6.9 The first coat of coating shall be applied as soon as possible after blasting. In no case shall coating be delayed more

than one (1) hour without reblasting. If the event a rust bloom or visual oxidation occurs before the application of the first coat, the material must be re-blasted.

6.10 Coating thickness and number of coats shall be in accordance with the Contractor’s coating specifications and

provide a dry film thickness (DFT) as specified by the Contractor.

6.11 Coating intermediate and final bake temperatures and times shall be in accordance with the Contractor’s coating

specifications. Intermediate baking will be performed at 250° – 350° F for periods of 45 minutes to 1-1/2 hours depending on coating, material size and weight. Final baking will be done at temperatures of 400° – 500° F for periods of 1-4 hours depending on coating, material size and weight. The staging of temperatures during final bake is permitted. In order to insure that proper oven temperatures are maintained the BP QA/QC Inspector will be given a copy of the heat charts. These heat charts will be included with the BP QA/QC Inspector’s final job report. Additionally, at BP’s request the Contractor shall satisfactorily demonstrate to the BP QA/QC Inspector that the surface temperature of the material meets but does not exceed the established temperature limitations for both the intermediate and final bakes regardless of the method by which the material is heated (i.e., conveyor system or batch ovens).

6.12 Minor irregularities in individual coats may be repaired to meet specifications anytime prior to final bake at the

option of the Contractor. Repairs of this nature are limited to the end area of material where thickness of repairs can be measured. Minor surface irregularities that are within the coating thickness specifications will be considered acceptable. Runs, sags, blobs, filled threads and/or blisters will be rejected.

6.13 The Contractor will conduct a sufficient number of visual and film thickness checks on the material in order to

assure conformity to final product specifications. 7.0 Final Inspection.

7.1 After the final bake, the BP QA/QC Inspector shall conduct, at random, a dry film thickness test and visual inspection of the coated material. In addition to obvious defects such as blobs, blisters, etc., the visual inspection will verify that the final coating color is within the Contractors specifications. The color of the coating should be uniform throughout the entire length of the material.

7.2 The color of finished baked coatings is variable. The Contractor will maintain coating color standards at the coating

facility. The coating color standards will be used to determine the acceptable finished color of all thermoset coatings. Lengths that contain coating color within the standard range of the coating color standards will be considered acceptable. After each final bake, the color will be verified with the proper comparator. The BP QA/QC Inspector shall witness the coating color inspection process.

7.3 The material shall be visually inspected from each end with sufficient light to detect any coating anomalies. The

material will be sufficiently rotated during the visual inspection to inspect the entire inside area of the material. The material must be in a single layer for the inspection. Material will not be stacked during the final inspection. The final product should be free of runs, sags, and blisters. Surface roughness or surface irregularities will not be considered cause for rejection provided that the coating thickness is within specification.

7.4 The dry film thickness of the material will be measured on both ends of the material with a MIKROTEST DFG

magnetic thickness gauge. The calibration of the thickness gauge will be conducted at the beginning of each shift or every eight hours, whichever comes first, and must be witnessed by the BP QA/QC Inspector. Material with coating thickness outside of the specified ranges (specified by the Contractor) will be rejected and reprocessed.

BP requires the average Dry Film Thickness to be .5 mils greater than the Contractor’s specified minimum Dry Film Thickness and .5 mils less than the Contractor’s specified maximum Dry Film Thickness. However, if any Dry Film Thickness measurement of the coating is not within this range, three additional Dry Film Thickness measurements must be taken. These measurements will be taken at 90°, 180°, and 270° and an average of the four readings will then be computed. If this average falls in the Contractor’s specified Dry Film Thickness range that end of the piece is acceptable and if this average falls out of the Contractor’s specified Dry Film Thickness range the whole piece is rejected.

7.5 Coatings on the face of the pipe ends are exempted from the standard minimum coating thickness requirements.

8.0 Holiday Testing.

8.1 Holiday testing will be performed per NACE Standard TM-03-84 on each length of pipe coated with thin film holiday free internal coating. The testing will be performed utilizing a “Tinker-Rasor” type M-1 holiday tester or equivalent, which is calibrated at the beginning of each shift or when requested by the BP QA/QC Inspector. All calibrations and testing must be witnessed by the BP QA/QC Inspector. The procedure for holiday testing of the material is as follows:

• A 2” thick cellulose sponge probe head saturated with selected electrolyte and detergent will be employed. • The sponge will be large enough to insure a 360° contact throughout the length of the pipe. The sponge will

be replaced when worn. • A constant potential of 67.5 volts DC will be maintained between the sponge probe and the body of the

tube during testing. The negative lead shall be connected to the pipe and the positive lead shall have continuity to the sponge. The tester alarm shall be activated before the testing of each joint to insure that continuity exists between the tube body and the holiday tester.

• The sponge probe will be moved through the pipe at a rate of 60 fpm +5%. • Each length of pipe will be holiday tested once at the Contractor’s facility. Thin film coatings will be

defined as holiday free when the electrical resistance between the wet sponge and the tube body is at no point less than 80,000 ohms.

• The holiday test will be performed in both directions while running the wet sponge in and out of the tube. • All thin film corrosion coatings for both new and used pipe will be holiday free and will be applied and

tested in accordance with the methods outlined above. • The holiday free specifications will apply only while the material is at the Contractor’s coating facility. • All coated pipe that is rejected shall be reprocessed according to surface preparation, application, and

inspection procedures as outlined in this specification. Those coated lengths not meeting holiday specifications after being coated a second time are to be classified as NSC. Any length that Contractor or BP determines to be unsuitable for coating (NSC) due to internal surface defects (e.g., slivers, pitting, etc.) will be set aside. This pipe will be reprocessed only upon instructions from BP.

9.0 Full Length Drifting.

9.1 After final inspection, each length will be full length drifted with a plastic or wooden drift mandrel meeting the applicable API specifications for coated material with the exception of drill pipe products, which do not require full length drifting.

10.0 Visual Thread Inspection.

10.1 After final inspection and full length drifting, is completed, the threads and sealing surfaces shall be visually inspected in accordance with the procedure BP-DEIP-P004. Thread compound, as specified by BP, will be applied to all threaded surfaces and the proper clean dry thread protectors installed.

11.1 Marking and Stenciling.

11.1 The Contractor will re-apply inspection bands and stencils as instructed by BP. Further, a clear mill varnish, acceptable to BP, will be applied to the outer surface of the material to prevent corrosion.

12.1 Documentation, Records And Reporting.

12.1 At the end of the job, the Contractor will provide BP the following documents:

• Prebake Heat Charts. • Testex Coarse Press-O-Film test strips. • Coating Batch number(s). • Intermediate Bake Heat Charts. • Final Bake Heat Charts. • Final report, stating the piece quantity, Prime and rejects (including NSC), along with the footage’s. The

reason for rejection must be reported.

• Individual pipe tally sheets indicating “threads off’ footage.

12.2 Documentation, records and reporting requirements as listed in BP-DEIP-P005 shall apply. 13.0 Health, Safety And Environmental.

13.1 Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply. 14.0 Visual Inspection Of Used Internal Plastic Coatings.

15.1

BP DEIP

HARDBANDING OF

DRILL PIPE TOOLJOINTS

HEAVY WEIGHT DRILL PIPE

AND DRILL COLLARS

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HARDBANDING OF DRILL PIPE TOOLJOINTS,

Procedure: BP-DEIP-P002 Revision: 0

HEAVYWEIGHT DRILL PIPE AND DRILL COLLARS

Date: 7/2/902

Approved By:

Date:

1.0 Scope.

1.1 This procedure details the BP GoM requirements for the hardbanding of drill pipe tooljoints (loose or attached), heavyweight drill pipe and drill collars. It is applicable to new or used non-hardbanded material and material which requires re-hardbanding.

1.2 The application of proud wear resistant alloy hardfacing bands onto tooljoints, heavyweight drill pipe and drill

collars significantly reduces external wear and casing wear. 2.0 Referenced Documents.

2.1 The following documents were used as reference for establishing this procedure.

2.1.1 Part 1 BP Drill-string Hardbanding Specification for General Release (4/6/2000). 2.1.2 ISO 9002 Quality Systems – Model for quality assurance in production and installation. 2.1.3 ISO 9003 Quality Systems – Model for quality assurance in final inspection and test. 2.1.4 API Q1 – Specification for Quality Programs. 2.1.5 ASME IX – ASME Boiler and Pressure Vessel Code. Welding and Brazing Qualifications. 2.1.6 ASTM E 709 – Standard Guide for Magnetic Particle Examination. 2.1.7 ASTM E 165 – Standard Test Method for Liquid Penetrant Examination. 2.1.8 API Specification 7 - Rotary Drill Stem Elements. 2.1.9 API Recommended Practice 7G - Drill Stem Design and Operating Limits.

3.0 Quality Assurance.

3.1 The Applicator shall operate a Quality Assurance organization responsible for formulating and implementing a Quality System, which insures that the requirements of this procedure are met.

3.2 The Applicator’s Ouality System shall be based on ISO 9002 and ISO 9003 or API Q1. Particular attention is drawn

to Section 4.8.2 in ISO 9002 and Section 3.12 in API Q1 concerning Special Processes. Hardbanding and the associated practices are considered to be Special Processes and shall be qualified strictly in accordance with the requirements of this procedure.

3.3 The effectiveness of the Applicator’s Quality System will be subject to monitoring by BP and may be audited

following and agreed period of notice. 4.0 Hardbandinq Types.

4.1 There are two basic types or categories of hardbanding for drill pipe tooljoints, heavyweight drill pipe and drill collars utilized in the Oil Industry today. These comprise weld overlays that consist of wear resistant alloys that do not contain tungsten carbide granules and weld overlays consisting of tungsten carbide granules within a metallic substrate (normally a low carbon steel). In this procedure these types will be referred to as “Wear Resistant Alloy Overlays” and “Tungsten Carbide Overlays”.

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4.2 Wear Resistant Alloy Overlays. These materials are hard alloys containing no solid particles. Therefore, unlike

tungsten carbide overlays, there is no possibility of hard particles standing proud or becoming exposed from a softer matrix and producing severe abrasive wear of the casing. Wear resistant alloy overlays are required when applying hardfacing for BP GoM and are strongly recommended verses tungsten carbide overlays in all cases.

4.3 Tungsten Carbide Overlays. These consist of granules of tungsten carbide in a steel matrix. The use of tungsten

carbide overlays is not permitted when applying hardfacing for BP GoM on drill pipe tooljoints, heavyweight drill pipe or drill collars. The use of drill pipe with tungsten carbide overlays is not permitted without the express consent of the responsible BP Engineer. Since heavyweight drill pipe and drill collars are used in open-hole sections the majority of time while drilling, BP GoM may accept tungsten carbide overlays on these items. However, if tungsten carbide overlays are used on heavyweight drill pipe or drill collars BP GoM reserves the right to examine the hardfacing for acceptance on a case, by case basis.

5.0 Welding Issues.

5.1 Welding Processes. Hardbanding shall be deposited by the use of a mechanized GMAW welding technique using a solid wire or cored wire consumable. Self shielded or open arc welding techniques may also be used. Other techniques for the deposition of hardbanding may be proposed for consideration by BP.

The hardbanding shall be applied as individual circumferential weld beads laid side by side to achieve the specified width of hardbanding. The as welded surface shall be smooth and the adjacent beads shall be deposited with sufficient overlap to avoid the formation of inter-bead troughs or valleys. High crowns or severe ridges must also be avoided.

5.2 Preheat And Interpass Temperature. A minimum preheat temperature of 400°F shall be achieved through the full

thickness of the component prior to the start of hardbanding or application of mild steel (butter-pass) and this temperature shall be maintained as the minimum interpass temperature throughout the welding process. The maximum interpass temperature for the application of hardbanding or mild steel shall be 650°F.

5.3 Post Weld Thermal Regime. Immediately on completion of welding, the component shall be subjected to one of

the following alternative thermal regimes:

5.3.1 The temperature of the internal and external surface of the component shall be measured and if necessary the component shall be heated such that a temperature of 650°F is attained through the full thickness. The component shall then be allowed to slow cool to ambient temperature while fully wrapped in an insulating blanket or specially constructed insulating can. The components shall be kept under cover and shall not be exposed to any wind, drafts or rain during the cooling period.

5.3.2 The component shall be placed in an oven and maintained at a temperature of 400°F for a minimum period

of two (2) hours prior to slow cooling under insulation, as detailed in section 5.3.1 above.

5.4 Welding Parameters. The welding parameters employed for hardbanding should be based on those recommended by the consumable manufacturer. However, it should be noted that these parameter values are often provided for guidance only and Applicators should undertake sufficient welding procedure development work to insure that they have established a stable welding condition prior to welding procedure qualification.

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5.5 Welding Procedures (WPS). All welding procedures associated with the application of hardbanding or mild steel

shall be qualified in accordance with ASME IX, QW 216, QW 453 and the requirements of this procedure. Production welding equipment shall be employed for the welding procedure qualification.

Individual welding procedures shall be qualified by the Applicator for:

• The application of flush and proud hardbanding. A separate WPS is required for each type of hard metal

consumable. • The application of mild steel. • The application of mild steel (butter-pass), flush and proud hardbanding on re-hardbanded components. A

separate WPS is required for each type of hard metal consumable.

The application of mild steel and hardbanding on re-hardbanded components may be qualified in a single procedure. The welding procedure specification (WPS) and procedure qualification record (PQR) shall be submitted to BP GoM for approval prior to the commencement of any production welding. These documents shall be prepared in the ASME format with supplementary pages as necessary to provide a full and detailed description of the hardbanding procedure.

5.6 Welding Procedure Qualification (PQR). All welding procedure qualifications shall be performed on a 4145H

tubular material, preferred size of 6 5/8” OD and 2 / ” ID, representing a typical drill collar. The manufacturer’s certificate, including full details of heat treatment, mechanical testing results and chemical analysis, for this material and the welding consumable shall be included in the PQR documentation. All relevant welding parameters shall be monitored and recorded during the production of the test weld and reported in the PQR.

The hardbanding shall be allowed to stand at ambient temperature for a minimum of forty-eight (48) hours prior to the examination detailed in Note 3, QW 453. The acceptance criteria for this examination shall be as detailed in section 10.0 of this procedure. Subsequent to the above an ultrasonic examination of the hardbanding and parent metal interface shall be performed to demonstrate freedom from lack of fusion or any under bead cracking. The surface of the hardbanding shall be prepared for this examination by machining or grinding. Testing shall examine the full width of the hardbanding at five equally spaced locations around the circumference. Following the above ultrasonic examination the Rockwell hardness of each band of hardfacing shall be measured at each of the five locations and each hardness reading shall meet the published recommendations of the consumable supplier. Two coupons shall be cut and prepared for examination as detailed in Note 8, QW 453 except that only one surface on each need be polished and etched. These coupons shall be taken at least 90° apart. A macrograph shall be taken of each prepared surface and included in the PQR. Additionally, three (3) vertical hardness traverses shall be made across the fusion boundary from the weld deposit into the heat-affected zone of the 4145H material. These measurements shall be made using a Vickers indenter with either a 5kg or 10kg load. A full chemical analysis shall be performed in accordance with Note 9, QW 453.

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5.7 Manufacturing Reference Standards. Subsequent to the testing detailed in Section 5.6 above the remainder of the

welding procedure qualification test piece shall be retained by the Applicator to act as a reference standard during production.

5.8 Welder/Machine Operators Performance Qualification. Working in accordance with a qualified WPS each

hardbanding welder/machine operator shall manufacture a test piece as detailed in section 5.6 in order to demonstrate his ability. The test piece shall be subjected to the examination detailed in Note 3, QW 453 and meet the criteria outlined in section 10.0 of this procedure. Each welder/machine operator performing a successful welding procedure qualification test shall be deemed to have completed a satisfactory performance test.

The Applicator’s Quality Assurance department shall maintain a record of each welder/machine operator’s qualification and working experience. A welder/machine operators qualification shall lapse and re-qualification will be required if he/she does not perform hardbanding for a period exceeding three months.

5.9 Production Welding. Production welding shall be undertaken strictly in accordance with the qualified welding

procedures. All welder/machine operators shall be qualified in accordance with section 5.8. A copy of the basic elements of the WPS shall be available for reference at each hardbanding station.

Appropriate shop floor supervision and detailed working procedures shall be available to ensure hardbanding is deposited to this Specification at all times. Regular monitoring and recording of preheat temperatures, welding set up, welding parameters and the post weld thermal regime shall form an integral part of these procedures. All production records shall be retained within the Applicator’s Quality System archives.

6.0 Hardbandinq Configurations.

6.1 Definitions. When applying new hardbanding and for the purposes of this procedure the following definitions shall apply.

• “Proud” hardbanding is an overlay that stands proud from the base material. Tolerances for proud

hardbanding are + 3/32” to + 1/8” as measured from the base material surface. • “Flush” hardbanding is an overlay that is flush with the base material surface. Tolerances for flush

hardbanding are + 1/64” and — 0 as measured from the base material surface.

6.2 Drill Pipe Tooljoints. Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations: • A three (3”) inch wide band on the box tooljoint OD next to the taper. These bands shall be applied proud. • One / ” wide band on the box tooljoint 18° taper. This band shall be applied flush. • Three / ” long fingers 120° apart projecting from the base of the hardbanding on the box tooljoint taper

onto the box upset. Fingers shall be applied flush. • A one and one half (1 / ”) inch wide band on the pin tooljoint OD next to the taper. These bands shall be

applied proud. 5

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Figure 1.1 (Drill Pipe)

6.3 Heavy Weight Drill Pipe. Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations: • One 4” inch wide band on the box and pin tooljoint OD next to the taper. These bands shall be applied

proud. • One 1” wide band on the tapered section of the box tooljoint. This band shall be applied flush. • Two 3” wide bands on each end of the center wear pad. These bands shall be applied proud.

Figure 1.2 (Heavy Weight Drill Pipe)

6.4 Drill Collars With Slip Recess Groove. Hardbanding (Wear Resistant Alloy Overlay) shall be applied in the following locations:

• One, 4” wide band on the box end OD located 1” away from the beginning of the slip recess groove. This

band shall be applied proud. • One, 10” wide band on the drill collar OD located 1” away from the end of the slip recess groove. This

band shall be applied proud.

Figure 1.3 (Drill Collar with Slip Recess Groove)

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6.5 Drill Collars With Slip And Elevator Recess Grooves. Hardbanding (Wear Resistant Alloy Overlay) shall be

applied in the following locations:

• One, 4” wide band on the box end OD located 1” away from the beginning of the slip recess groove. This band shall be applied proud.

• One, 1” wide band on the wear pad OD between the two recess grooves. This band shall be applied proud. • One, 10” wide band on the drill collar OD located 1” away from the end of the slip recess groove. This

band shall be applied proud.

Figure 1.4 (Drill Collar with Slip And Elevator Recess Grooves)

7.0 Pre-Hardbandinq Considerations.

7.1 Mill Slots, Chip Slots and Identification Grooves. Inspect the tooljoints to determine if there are mill slots, chip slots, identification grooves or other machined areas on the tooljoints that will interfere with the application of hardbanding per section 6.2. If machined areas exist and will interfere with the hardbanding application process notify the Material Supplier prior to hardbanding the material and obtain permission to fill the machined areas in with mild steel. The application of mild steel shall meet the requirements outlined in section 5.0 and 9.0.

7.2 Internal Plastic Coating. Inspect the material to determine if it is internally plastic coated. If the material is

internally plastic coated notify the Material Supplier prior to hardbanding the material and inform the Material Supplier that the material will require re-coating after the hardbanding process.

Note: Under no circumstances shall material be filled with water during the hardbanding process to preserve the internal plastic coating.

7.3 Pre-Existing Hardband. Inspect the material to determine it the material has been previously hardbanded. If the

material has been previously hardbanded notify the Material Supplier prior to the hardbanding the material and inform the Material Supplier that the existing hardbanding will have to be removed in accordance with section 9.0 prior to applying the new hardbanding.

Note: Under no circumstances shall new hardband be applied over pre-existing hardband of any type without prior approval by the BP QA/QC Manager.

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8.0 Hardbanding Procedure.

8.1 Machining. When applying proud hardbanding, a groove shall be machined into the surface of the material prior to the application of hardbanding. The groove depth shall be 1/32” (+/-.010”) as measured from the surface of the material. When applying flush hardbanding, a groove shall be machined into the surface of the material prior to the application of hardbanding. The groove depth shall be 3/32” (- 0 + 1/32”) as measured from the surface of the material. When applying flush hardbanded fingers, three, / ” long, / ” wide and 3/32” deep slots shall be ground into the drill pipe box end upset. All groove and slot widths shall equal the intended width of the hardbanding to be applied as defined in section 6.0.

Note: It may be necessary to modify the groove depth on the box taper to achieve a smooth tie in to the three (3) inch band located on the box OD.

8.2 Surface Preparation. Hardbanding shall be deposited onto a machined or ground white metal surface. This surface

shall be free from dirt, drilling mud, cement, paint, rust, cutting fluid, grease etc. Additionally, a two (2) inch band on either side of the machined area shall be thoroughly cleaned and degreased.

8.3 Preheat. Preheat the area requiring hardbanding in accordance with the BP approved WPS (See section 5.0 for more

details). The preheat temperature shall be verified on each area requiring hardbanding on each piece with a calibrated pyrometer or the properly rated temperature sticks. When temperature sticks are used the Applicator shall have at a minimum, temperature sticks rated to the preheat temperature and maximum interpass temperature.

8.4 Hardbanding Application. Apply hardbanding to the material in accordance with the BP approved WPS (See

section 5.0 for more details). 8.5 Interpass Temperature. Monitor the interpass temperature throughout the hardband application process to insure

the minimum and maximum interpass temperatures are maintained in accordance with the BP approved WPS (See section 5.0 for more details). The interpass temperature shall be measured with a calibrated pyrometer or the properly temperature sticks. When temperature sticks are used the Applicator shall have at a minimum, temperature sticks rated to the minimum interpass temperature and maximum interpass temperature.

8.6 Post Weld Thermal Regime / Slow Cooling. Immediately on completion of the hardband application, the material

shall be subjected to a post weld thermal regime in accordance with the BP approved WPS (See section 5.0 for more details).

8.7 Surface Finish. After the material has slow cooled to ambient temperature, remove all weld spatter or protrusions

by grinding, sanding or machining methods. Close control of the hardband welding parameters should result in a good surface finish, such that it is not usually necessary to grind, sand or machine the entire hardbanded surface.

Note: Unless specified by BP, Amorphous type hardfacings do not require post application grinding or sanding to increase the surface hardness of the material.

8.8 Inspection. Perform a dimensional inspection on each hardbanded area to insure the requirements outlined in

section 6.0 have been met.

8.8.1 Perform a visual inspection on each hardbanded area. Acceptance and rejection criteria shall be per section 10.0.

8

3 4 1 2

Note: When required by BP, contrast paint shall be applied to the hardbanding in order to assist the visual examination.

8.8.2 Clean all connections and perform a visual inspection on the threaded and sealing surfaces in accordance

with procedure BP-DEIP-P004. 8.8.3 Perform a bi-directional wet magnetic particle inspection on the HAZ and at least two (2) inches of the

surrounding parent metal around all hardbanded areas. The bi-directional WMPI shall be performed in accordance with procedure BP-DEIP-P002 (the transverse MPI method shall be per section 7.0 and the longitudinal MPI method shall be per section 8.0). Acceptance and rejection criteria shall be per section 10.0.

8.9 Finishing. Blow the material ID out with compressed air to remove any debris. Apply the appropriate thread

compound to all connections as specified by the Material Supplier and install clean dry thread protectors wrench tight. Apply a thin coat of rust inhibitor to the freshly hardbanded, ground, sanded or machined areas.

9.0 Removal of Existing Hardbanding and Application of Mild Steel.

9.1 Removal of Existing Hardbanding. The removal of existing hardbanding shall be performed with pre-approved methods or techniques such as, plasma arc gouging, grinding or machining. When plasma arc gouging techniques are used care shall be taken to minimize the heat input.

9.1.1 After removal of the existing hardbanding with plasma arc gouging techniques, the excavated area shall be

machined smooth to provide a suitable surface for WMPI.

9.2 Inspection. All areas where previous hardbanding has been removed shall be etched with a 5% Nital solution to verify that all of the hardband material has been removed. This process shall be repeated as many times as necessary to insure all previous hardband material has been completely removed.

9.2.1 Perform a bi-directional wet magnetic particle inspection on all areas where hardbanding has been removed

and all areas that have been affected during the removal process. The bi-directional WMPI shall be performed in accordance with procedure BP-DEIP-P002 (the transverse MPI method shall be per section 7.0 and the longitudinal MPI method shall be per section 8.0). Acceptance and rejection criteria shall be per section 10.0.

9.3 Application of Mild Steel. Apply mild steel to the previously excavated areas and/or mill slots, chip slots or

identification grooves if necessary in accordance with the BP approved WPS (See section 5.0 for more details).

9.4 Machining. Machine the areas where mild steel has been applied back to the original OD or taper of the area.

Note: Grooves for new hardbanding as outlined in section 8.1 can be machined in conjunction with the above machining process prior to performing the WMPI detailed in section 9.5.

9.5 Inspection. Perform a bi-directional wet magnetic particle inspection on all areas where mild steel has been applied.

The bi-directional WMPI shall be performed in accordance with procedure BP-DEIP-P002 (the transverse MPI method shall be per section 7.0 and the longitudinal MPI method shall be per section 8.0). Acceptance and rejection criteria shall be per section 10.0.

9

10.0 Acceptance Criteria.

10.1 Mild Steel And Parent Material. Relevant indications on the external or internal surface (including HAZ) of parts shall be removed by grinding or machining, provided that the part still conforms to BP’s, the Manufacturer’s or API acceptance criteria after the removal process.

Note: All areas that have had indications removed shall be re-inspected in accordance with the appropriate MPI method in accordance with procedure BP-DEIP-P002 section 7.0, 8.0 or 9.0 after the removal process to insure complete imperfection removal.

10.2 Wear Resistant Alloy Overlays. These hard wear resistant deposits possess relatively low ductility. Therefore,

weld metal cracking often occurs transverse to the weld bead under the influence of residual stresses. Typically, these cracks may run straight across the weld bead or at an angle between 30° and 45°. Occasionally the cracks will interconnect. This is acceptable as long as the cracks are less than 1/16” wide or have a minimum spacing of / ” apart when the cracks run across the full width of the hardbanded region. If cracks fail to meet this criteria remove the deposit and re-hardband the material in accordance with sections 8.0 and 9.0.

Figure 1.5 (Transverse Cracks)

Figure 1.5 illustrates an acceptable configuration of transverse cracks. Crack widths are less than 1/16” and cracks extending the full width of the hardband deposit are greater than 1/2” apart.

If there are circumferentially running cracks, these are unacceptable where a single continuous crack is greater than 3” long, as they can result in a premature fatigue failure of the material. Additionally, flaking or spalling of the hardband deposit is unacceptable. In such circumstances remove the deposit and re-hardband the material in accordance with sections 8.0 and 9.0.

Figure 1.6 (Circumferential Cracks and Flaking)

Figure 1.5 illustrates unacceptable circumferential cracking and flaking and acceptable circumferential cracking.

10

1 2

Small troughs between individual weld beads are acceptable as long as they are no more than 1/8” wide or 1/16” deep.

Figure 1.7 (Inter-Bead Troughs)

Figure 1.7 illustrates Inter-Bead Troughs. “Troughs” are acceptable if less than 1/8” wide and 1/16” deep.

If any cracking is detected in the HAZ, mild steel or parent material, the hardbanding and cracked areas must be completely removed in accordance with section 9.0, provided that the material still conforms to BP’s, the Manufacturer’s or API acceptance criteria after the removal process. The area shall be re-hardbanded in accordance with section 8.0. If there are surface breaking non-linear defects, such as porosity on the hardband weld beads greater than 1/8” diameter or 1/16” deep, these may be filled using semi-automatic GMAW or SMAW. This type of repair must be performed with a consumable matching the composition of the hardband material and will require a BP approved WPS (See section 5.0 for more details). Note: The acceptance criteria outlined in this section are the minimum requirements BP will accept, regardless of the Hardband Manufacturer’s, Material Supplier or Applicator’s acceptance criteria. However, it is necessary to obtain and review the Hardband Manufacturer’s, Material Supplier and Applicator’s acceptance criteria to insure the material is inspected correctly.

11.0 Documentation, Records and Reporting.

11.1 The Applicator shall submit to BP an inspection record, which will clearly state that the hardbanding has been applied and inspected in accordance with this procedure. The scope and content of this record shall include:

• A reference list of the Applicator’s procedures used in the production of the hardbanding and a copy of the

WPS(s) and PQR(s). • A copy of all NDE reports.

11.2 Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.

11

12.0 General Requirements.

12.1 General requirements as listed in procedure BP-DEIP-P001 shall apply. 13.0 Marking And Stenciling.

13.1 Marking and stenciling requirements as listed in procedure BP-DEIP-P001 shall apply. 14.0 Documentation, Records and Reporting.

14.1 Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply.

15.0 Health, Safety And Environmental.

15.1 Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply.

12

BP DEIP

MAKE AND BREAK OF

DRILL PIPE AND WORKSTRING

TOOLJOINTS

1

MAKE AND BREAK OF DRILL PIPE AND

Procedure: BP-DEIP-MB001 Revision: 0

WORKSTRING TOOLJOINTS

Date: 6/6/02

Approved By:

Date:

1.0 Scope.

1.1 This procedure describes the processes established to make and break new drill pipe and workstring tooljoints, both, affixed or loose.

1.2 Since newly machined connections are susceptible to galling the make and break process is utilized to break in new

connections (tooljoints) by work hardening the connection surface. 2.0 Personnel Qualifications.

2.1 Personnel performing make and break operations must be trained and experienced in the operation of the make and break unit.

3.0 Required Materials & Equipment.

3.1 Hydraulic Make And Break Unit. The make and break unit shall be capable of making up and breaking out two joints of range III drill pipe together to the manufacturers recommended torque value.

3.1.1 The unit shall be equipped with load cells and gauges capable of indicating the torque values obtained in

Ft./Lbs. 3.1.2 Calibration of the load cells and gauges on the make and break unit shall be performed a minimum of once

every six (6) months. The calibration documentation shall be available for review at the job site. 3.1.3 The make and break unit shall be equipped with the properly sized power and backup tongs. 3.1.4 Power and backup tongs will utilize low stress, large contact surface area dies to reduce grip marks.

3.2 Additional Required Equipment. The following equipment shall be available on the job sight and in good working

order: Depth (pit) gauge, files, 50’ metal tally tape, absorbent pad, catch pans, cleaning solvent, cleaning brushes, thread compound, dope brushes, assorted paints and metal markers.

4.0 Make And Break Procedures.

4.1 Remove the thread protectors and stack them off the ground to prevent contamination with dirt, grit, grass etc.

4.2 Visually inspect the condition of the thread compound to insure a thin uniform coat of make-up thread compound has been applied and is not contaminated with dirt, grit, rust, scale etc.

Note: The thread compound must be an approved make-up compound such as ZN-50 or Jet Lube Kopr-Kote. If the thread compound on the connections is not an approved make-up compound (i.e., kendex) it must removed by cleaning the connections with solvent, varsol etc. and drying the connections prior to applying the proper make-up thread compound.

2

4.3 Verify the make and break unit has been set up properly prior to commencing the make and break operation. The

unit must be level and both tongs must be perpendicular to the tooljoints. In addition, the tooljoints shall be centered in the tongs and tong dies shall contact the tooljoints in a uniform fashion to prevent excessive grip marks and slippage.

4.4 Recommended torque values shall be obtained from the drill pipe manufacturer or their published documents prior

to the start up of the make and break operation.

4.5 The make and break process shall consist of and be performed in the order listed below. 1. Make up a box and pin connection to 100% of the specified optimum torque value. Break out the box and pin

connections. 2. Clean both connections and perform visual inspection for damages or excessive grip marks. Repair any minor

damages with a file or emery cloth and apply a thin coating of dry moly lubricant over the repaired connection.

Note: If the connections are damaged beyond minor field repair shut the make and break operation down and contact the responsible BP Inspection Coordinator for further instructions.

3. Provided that the damages are minor or non-existent repeat the operations outlined in step one (1) above two

(2) more times without cleaning the connections. 4. After the third make and break cycle clean both connections and perform visual inspection for damages. Repair

any minor damages with a file or emery cloth and apply a thin coating of dry moly lubricant over the repaired connection.

5. Repeat the operations outlined in steps one (1), two (2), three (3) and four (4) on the next four (4) sets of boxes

and pins. 6. Provided that the damages are minor or non-existent on the first five (5) sets connections the remaining

connections in the order shall be made up to 100% of the specified optimum torque value and broken out three (3) consecutive times without cleaning the connections between make and break cycles.

7. Clean all connections after the final make and break cycle and perform a visual inspection for damages or

excessive grip marks. Repair any minor damages with a file or emery cloth and apply a thin coating of dry moly lubricant over the repaired connection.

8. Allow the connections to dry or dry the connections with compressed air. Apply a thin, uniform film of the

specified thread compound to all connections and install thread protectors wrench tight. 5.0 Visual And Dimensional Inspection.

5.1 Visual and dimensional requirements as listed in procedure BP-DEIP-P004 shall apply. 6.0 General Requirements.

6.1 General requirements as listed in procedure BP-DEIP-P001 shall apply. 7.0 Marking And Stenciling.

7.1 Marking and stenciling requirements as listed in procedure BP-DEIP-P001 shall apply. 3

8.0 Documentation, Records and Reporting.

8.1 Documentation, records and reporting requirements as listed in procedure BP-DEIP-P005 shall apply. 9.0 Health, Safety And Environmental.

9.1 Health, safety and environmental requirements as listed in BP-DEIP-P001 shall apply. 4

January 6, 2003 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Jon Sprague — Atlantis Wells Delivery Leader Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in

interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject: Letter of Agreement for adding Offshore Safety Assistant

CONTRACTOR-5121-2002-011 Dear Mr. Sprague: This letter will confirm our agreement to add additional Transocean personnel to the crew complement of the Deepwater Horizon. Upon execution of this Letter Agreement by Company, Contractor agrees to provide two (2) Offshore Safety Advisors (OSA) on the Deepwater Horizon in addition to those specified to be specified to be provided in Exhibit F-1 of the Contract as amended. Exhibits F-1 and F-2 of the Contract shall be amended, as of January 1, 2003 to provide for the following additional personnel:

Therefore, the amended crew complement shall show one (1) OSA “On Board” and two (2) “Assigned to Rig”. The amended crew complement is attached. In summary, all rates in the Contract shall increase by $930.23 per day effective January 1, 2003. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service. Sincerely,

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE

TRANSOCEAN HOLDINGS INC. 1311 BROADFIELD, SUITE 400 HOUSTON, TX 77084

Title On Board

Assignedto Rig

Daily Rate per Person w/ Burden


Offshore Safety Advisor 1

2

$ 930.23 NA




On Behalf of Transocean Holdings Inc..

PHONE: (832) 587-8506 FAX: (832) 587-8754

EMAIL: [email protected]

BP Horizon – OSA TSF File #01-063 AGREED AND ACCEPTED THIS 27 DAY OF JANUARY, 2003 BP AMERICA PRODUCTION COMPANY

2




th

January 7, 2003 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Jon Sprague — Atlantis Wells Delivery Leader Re: Drilling Contract No. 980249 dated December 9, 1998 (“Contract”) by and between R&B Falcon Drilling Company

predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject: Letter of Agreement for Recycling program — Deepwater Horizon

CONTRACTOR-5121-2002-011 Dear Mr. Sprague: This letter will confirm our agreement that effective, January 1, 2003, the parties desire to amend the Contract in order for Contractor to implement a recycling program on the Deepwater Horizon and that Company shall reimburse Contractor for the costs and charges associated with this Service as detailed in Attachment 1, which is attached hereto and made a part of this Letter Agreement. Except as expressly amended herein, the terms and conditions of the Contract, as previously amended, will remain in effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

AGREED AND ACCEPTED THIS 7 DAY OF FEBRUARY, 2003 BP AMERICA PRODUCTION COMPANY

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE


Sincerely,




On Behalf of Transocean Holdings Inc..




PHONE: (832) 587-8506 FAX: (832) 587-8754 EMAIL: [email protected]

th

BP Horizon – OSA TSF File #01-063

ATTACHMENT 1 SCOPE OF WORK AND COMPENSATION

RECYCLING PROGRAM — DEEPWATER HORIZON 1. Scope of Work Company has requested and Contractor has agreed to provide a recycling program covering recyclable waste materials from Contractor’s Deepwater Horizon Drilling Unit (“Rig”). This program will commence on 1/1, 2003 and shall continue for the remaining primary term of the Contract unless terminated by Company by providing written notice thirty (30) days in advance of the termination date. Contractor (or its subcontractor) will provide the following services:

1. Provide a recycling service to reduce and separate the waste on the Rig. 2. Furnish recycling and general waste compactor units to the Rig. 3. Supply storage bins at dock locations for collection of recycled materials. 4. Collect and transport compacted bags of recycled materials from the storage bins. 5. Track and provide totals of the volume of recycled material collected 6. Maintain and repair compactor units as needed. 7. Training of Rig personnel in operating, tagging and delivery of the recycled materials to the storage bins

At the Fourchon dock location, Company shall be responsible for ensuring that properly marked recyclable material received at the dock is placed into the appropriate “Recycle the Gulf” storage bin(s) for collection.

2. Rates

Company shall reimburse Contractor the following fees and costs during the term of this recycling service:

Service Fee $75.00/day

This Service Fee includes:

1. Equipment on the Rig to separate and compact recyclables 2. Storage Bin located at dock location (Fourchon) 3. Pick up and transportation (from Fourchon dock) 4. Employee Training packet 5. Processing service

2

Recycle the Gulf Bags — New

5.5 cuft Tri-2 Bags $ 10.35/each

14 cuft 6 x 2 bags $ 10.15/each

3

Model 4000 Trash Compactor Bags

$ 10.20/each

Processing Fee (per bag of recycled material) $ 1.85/bag

BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in


Subject: Direct Payment of Invoices


Dear Randy, This letter is a formal request for BP to pay invoices related to the Contract referenced above by wire transfer to the following account:

Transocean Holdings Inc Wells Fargo Bank Houston, Texas Beneficiary: Transocean Holdings Inc Account number: ABA Number: SWIFT Number:

Thank you for your cooperation. If you have any questions, please contact John Keeton at (832) 587-8533 or Chris Young at (832) 587-8506. Thank you for the opportunity to be of service.

cc: Craig Duncan

Chris Young

TRANSOCEAN OFFSHORE DEEPWATER DRILLING, INC.4 GREENWAY PLAZA (77046)

POST OFFICE BOX 2765

Gregory L. Cauthen Senior Vice President, Chief Financial Officer and Treasurer

HOUSTON, TEXAS 77252-2765

February 18, 2003

Sincerely,

/s/ Gregory L. Cauthen

Gregory L. Cauthen Senior Vice President, Chief

Financial Officer & Treasurer

February 28, 2003 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in


Subject: Letter of Agreement for Cost Escalation 2003

CONTRACTOR-5121-2002-011 Dear Randy, We performed the “annual” cost analysis for the Deepwater Horizon as of January 1, 2003 in accordance with Article 2.3 “Adjustment in Dayrates” of the Contract referenced above. The following table summarizes the Baseline Cost changes detailed on the attached schedule “Basis for Cost Escalation”:

* According to Article 2.3.2, rates for each item must vary by => 5% before they can be adjusted. Notes: 2.3.2a Base Labor rates did not change but several of our “burdens” did change on January 1. FICA limits increased as well as

pension accruals and some insurance related items. We reduced the utilization bonus. The net result was a slight increase but not the 5% required to trigger an increase. Please note that the total includes all personnel added by letter agreement.

2.3.2b Contractor’s cost of catering has increased from $27.20 per man per day to $31.95, an increase of 17.5%. Please note the

catering cost shown on the accompanying schedule only reflects the crew complement in the contract (77 on board the rig) while we actually have 83.

E-17

TRANSOCEAN HOLDINGS INC. 4 GREENWAY PLAZAHOUSTON, TX 77046

CHRISTOPHER S. YOUNG

SR. MARKETING REPRESENTATIVE

Reference

2001 Baseline Costsplus Previous Agreements

Actual BaselineCosts

@ Jan. 1, 2003Increase/

(Decrease) DayrateIncrease/

(Decrease)2.3.2a Base Labor Costs

$ 36,008 $ 36,139 $ 131

*

2.3.2b Catering Costs $ 2,366

$ 2,780

$ 414

$ 414

2.3.2c Maintenance Element 13,851 13,946 $ 95 *

2.3.2d Insurance $ 1,799

$ 5,137

$ 3,338

$ 3,338

Total $ 54,024/day $ 58,002/day $ 3,752/day


BP Horizon – Escalation 2003 TSF File #01-063 2.3.2c The Maintenance Element of the Baseline Cost increased $95 per day based on the change on the relevant Producer Price

Index. The Index number for December 2002 increased to 146.8 from 145.8 in August of 2001, an increase of .69 %. The Bureau of Labor Statistics Data for the Producer Price Index series ID: WPU119102 is attached. Since the change was less than 5% we did not include it in the rate adjustment.

2.3.2d The insurance element increased $3,338 per day for a 186% increase and accounts for the majority of the overall cost

increase. The cost of the various coverages is broken out on the accompanying schedule. Insurance costs increased dramatically throughout the industry for reasons already discussed. Please note that we lowered the insured value of the rig from $350 million to $320 million and increased the deductible from $500,000 to $10 million to reduce the H&M premium. Without the increased deductible, the premiums would have been significantly higher. Basically, we are self-insured for the first $10 million of coverage. The Marine P&I insurance cost shown on the accompanying schedule reflects a $4,832 per assigned person per year accrual determined by our insurance company for the self-insured $10 million.

The following documents are attached for reference: 1) “Basis for Cost Escalations” schedule; 2) “Adjusted Base Labor as of January 1, 2003”; 3) the Bureau of Labor Statistics Data for the relevant Producer Price Index, and 4) a statement of our annual insurance premiums. In summary, all rates in the Contract shall increase by $3,752 per day effective January 1, 2003. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

AGREED AND ACCEPTED THIS 17 DAY OF APRIL, 2003 BP AMERICA PRODUCTION COMPANY

E-18

2

Sincerely,





SIGNED /s/ J. W. Farnsworth

PRINTED J. W. Farnsworth

TITLE VP Exploration


DEEPWATER HORIZON January 1, 2003

$ Per Day

* Note: The Index did not vary by 5% so the baseline cost and index stays the same as in 2001 ** Note: The 7 Addl Personnel are shown as line items to identify that they were included in the previous (2001) escalation. *** 18 Addtl. Personnel represent all addtl. Personnel added to the crew complement since the original contract.

E-19

3

2001 Baseline

Costs Plus Agreements

2001 BaselineCosts Plus

Subsequent Agreements

January 2003Actual Baseline

CostsActual

Variance

DayrateIncrease

Adjusted2003

Baseline Costs2.3.2a) Base Labor Cost:

Labor & Burden (for original Contract

Crew Complement) $ 25,476

$ 25,476

$ 25,598

$ 122

$ 25,476

Training & Transportation Costs (for

original Contract Crew Complement) $ 2,820

$ 2,820

$ 2,820

$ 0

$ 2,820

** Labor & Burden for 7 Addl Personnel included in 2001 Baseline Calc.

$ 2,278

NA

NA

NA

NA

** Training & Transportation Costs (7 Addl Personnel incl. In 2001)

$ 335

NA

NA

NA

NA

*** Labor & Burden (18 Addl Pers. (incl. 7 added above) @ Jan 2003)

$ 0 $ 6,852 $ 6,860 $ 9 $ 6,852

*** Training & Transportation Costs (18 Addl Personnel - Onboard)

$ 0

$ 860

$ 860

$ 0

$ 860

Total Base Labor Cost $ 30,909

$ 36,008

$ 36,139

$ 131

$ 0

$ 36,008

Percentage Increase 036%*

2.3.2b) Base Catering Cost:

59 Contractor Personnel in Original Contract

$ 1,605

$ 1,605

$ 1,885

$ 280

$ 1,885

** 7 Additional Personnel included in 2001 Baseline Cost Calculation

$ 190 NA NA NA NA

*** 18 Additional Personnel (including the 7 Addtl. Included in 2001)

$ 0

$ 490

$ 576

$ 86

$ 576

10 Company Personnel

$ 272

$ 272

$ 320

$ 48

$ 320

Total Base Catering Costs

$ 2,067

$ 2,366

$ 2,780

$ 414 $ 414

$ 2,780

Percentage Increase

17.5%

2.3.2c) Base Maintenance Element:

$ 13,851 $ 13,851 $ 13,946 $ 95 $ 0 $ 13,851

Percentage Increase

0.69%*

2.3.2d) Base Insurance Cost:

Hull & Machinery

$ 1,289

$ 1,289

$ 2,422

$ 1,133

$ 2,422

Marine P&I $ 343

$ 343

$ 2,039

$ 1,695

$ 2,039

Excess Liability $ 72 $ 72 $ 520 $ 448

$ 520 Brokers Fee

$ 94

$ 94

$ 110

$ 15

$ 110

Oil Pollution $ 0

$ 0

$ 46

$ 46

$ 46

Total Base Insurance Cost: $ 1,799

$ 1,799

$ 5,137

$ 3,338

$ 3,338

$ 5,137

Percentage Increase

185.6%

Total

$ 48,626

$ 54,024

$ 58,002

$ 3,977 $ 3,752

$ 57,776

Total Dayrate Increase = $ 3,752/day

DEEPWATER HORIZON

Adjusted Labor as of January 1, 2003

The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short. This includes all Training, Transportation and Catering costs. The figures in column “B” are the daily cost of all crew members excluding Training, Transportation and Catering costs. The figures in column “C” are the daily cost of overtime excluding Training, Transportation and Catering costs (assuming a daily schedule of 12 hours) The figures in column “D” are the hourly cost of overtime excluding Training, Transportation and Catering costs.

E-20

4

A

B

C

D

GOM Base Labor

GOM Overtime Rates

No. Of Personnel

Daily Rate per

Daily

On Board

Assigned To Rig

JOB CLASSIFICATIONperson (inc.

TT&C)Total Daily on

Board CostOvertime

Rates Hourly

Overtime Rates1

2 OIM 965.59

871.93 824.67 68.721

2 OSA - Horizon

889.04

795.38

748.12

62.34

3 6

Toolpusher 786.15

2,077.48 645.23 53.772

4 Driller

662.47

1,137.62

621.66

51.81

4 8

Assistant Driller

511.05

1,669.57

441.18

36.76

2 4

Pumpman

430.72 674.11

345.42

28.79

12 24

Floorman

386.35

3,901.75

342.26

28.52

14 28

Roustabouts 346.81

3,998.53 295.13 24.591

2 Welder

494.23

400.57

421.13

35.09

4 8

Crane Operator 511.05

1,009.57 441.10 36.762

4 Chief Mechanic

595.17

1,003.03

541.45

45.12

1 2

Mechanic

490.02

396.36

416.11

34.68

2 4

Motor Operator

386.77 651.13

342.76

28.56

1 2

Electrical Supervisor

675.09

581.43

534.17

44.51

2 4

Chief Electrician 595.17

1,003.03 541.45 45.121

2 Electrician

490.02

396.36

416.11

34.68

2 4

Chief Electronic Technician 603.59

1,019.85 551.47 45.961

2 Senior Sub Sea Sup

777.26

683.60

636.35

53.03

1 2

Assistant Subsea

561.53

467.87

501.34

41.78

2 4

Material Co-Ordinator

456.37 725.43

376.00

31.33

1 2

Master

863.11

769.45

722.19

60.18

1 2

Chief Mate 687.71

594.05 651.74 54.311

2 Chief Engineer

803.26

709.59

662.34

55.19

1 2

1st Assistant Engineer 645.65

551.99 601.61 50.132

4 2nd Assistant Engineer

612.00

1,036.68

561.50

46.79

2 4

DP Operator

561.53

935.73

501.34

41.78

2 4

Assistant Dp Operator

477.40 767.49

401.07

33.42

2 4

Deck Pusher

497.81

873.21

475.11

39.59

1 2

Bosun

477.40

383.74

401.07

33.42

3 6

AB Seaman

403.59

1,027.17

362.81

30.23

1 2

RSTT 485.82

392.16 411.10 34.261

2 Medic

385.88

292.22

291.98

24.33

0 0

-

—

—

—

—

0 0

-

— — — —

0 0

-

—

—

—

—

0 0

-

—

— — —

0 0

-

—

—

—

—

0 0

- —

— — —0

0 -

—

—

—

—

0 0

-

—

—

—

—

77 154

Total Labor Costs =

$ 32,458.08

Chris Young Transocean Holdings, Inc. 1311 Broadfield Houston, TX 77083 Re: Annual Premiums for Deepwater Horizon 2003 Chris, Current Insurance as of January 1, 2003:

* Based on Self Insured Accrual of $4,832 per person x 154 people assigned

E-21

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.

BETSY KELLY 4 GREENWAY PLAZAMANAGER-INSURANCE HOUSTON, TX 77046


All Risk Hull & Machinery $ 320,000,000 $10,000,000 $ 883,943

Coverage: Deductible: NET ANNUAL COST:

Primary Marine Protection & Indemnity $10,000,000 per occurrence $ 744,235*


Excess Liability $452,000,000 XS of Primary Marine P & I $ 189,799

Coverage: NET ANNUAL PREMIUM:

Oil Pollution $ 16,820

U.S. Broker: Annual Fee:

McGriff, Seibels & Williams, Inc $ 40,024

(713) 232-7766 FAX (713) 232-7630 TEL [email protected]

Public Data Query

BLS Home | Programs & Surveys | Get Detailed Statistics | Glossary | What’s New | Find It! In DOL

Data extracted on: January 31, 2003 (12:09:59 PM)

Producer Price Index-Commodities Series Id: WPU119102 Not Seasonally Adjusted Group: Machinery and equipment Item: Oil field and gas field drilling machinery Base Date: 8200

(P): Preliminary. All indexes are subject to revision four months after original publication.

Frequently Asked Questions | Freedom of Information Act | Customer Survey Privacy & Security Statement | Linking to Our Site | Accessibility Information

E-22

1

U. S. Department of Labor Bureau of Labor Statistics Bureau of Labor Statistics Data

www.bls.gov Search | A-Z Index

Change

Output From: 1992 To 2002 Go Options:

include graphs NEW! More Formatting Options

Year Jan

Feb Mar

Apr May

Jun

Jul

Aug

Sep

Oct Nov

Dec

Annual

1992 110.1

110.1 110.1

110.1 110.2

110.4

110.6

110.6

110.6

110.8

112.4 112.5

110.7

1993 112.8

112.9 113.3

112.1 112.0

112.2 112.3

112.3

113.4

113.4

113.4 114.6

112.9

1994 114.6

114.6 114.6

114.6 114.7

114.9

115.4

115.4

115.9

117.8

117.8 117.8

115.7

1995 118.3

118.6 119.2

119.2 119.3 119.6 120.4 120.4 120.4 122.0

122.2 122.2 120.1

1996 124.0

124.0 124.0

124.3 124.2

124.8

125.3

125.3

125.3

126.2

126.6 127.1

125.1

1997 127.7

127.9 128.6

129.1 129.2

129.3

129.3

129.5

129.7

130.3

131.4 132.0

129.5

1998 133.1

132.9 133.1

133.0 133.0 133.0 132.9 132.9 132.9 133.6

133.6 133.6 133.1

1999 133.8

133.7 133.7

133.9 133.9

134.0

134.0

133.7

133.7

133.7

134.4 134.6

133.9

2000 134.9

136.3 136.3

136.3 136.5

136.5

136.5

136.6

136.7

138.7

138.7 138.7

136.9

2001 143.5

143.9 144.0

144.0 144.0 145.5 145.6 145.8 145.7 146.1

146.1 146.1 145.0

2002 146.2

146.2 146.6

146.6 146.4

146.4

146.4

146.4

146.8 (P) 146.8 (P) 146.8 (P) 146.8 (P) 146.5 (P)

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE March 3, 2003 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in


Subject: Letter of Agreement for Rental of 6 5/8” HWDP


Dear Randy, This letter is to reflect our agreement to purchase 23 joints of 6 5/8” drill pipe (per Smith’s Quote No. D03-0557) and rent it to BP over the remaining term of the Contract referenced above. The total rental amount will be 1.27418155 times the cost of the pipe. The pipe cost $107,311.56 including inspection. Therefore, the total rental payment will be $136,734.40 over the remaining term of the contract. We received the pipe on March 3, 2003. Therefore, the rental rate will be $242.01 per day starting March 4, 2003 and ending September 18, 2004. If the Contract should be terminated for any reason, BP agrees to pay the difference between $136,734.40 and the total rental paid up to that time. BP will be responsible for all inspections during the term of the rental. The pipe shall be treated as Contractor’s in-hole equipment per Article 22 of the Contract. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

AGREED AND ACCEPTED THIS 14 DAY OF APRIL, 2003 BP AMERICA PRODUCTION COMPANY

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.1311 BROADFIELD, SUITE 400 HOUSTON, TX 77084

Sincerely,







PHONE: (832) 587-8506 FAX: (832) 587-8754


th

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE March 20, 2003 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company (“Contractor”)

and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject: Letter of Agreement for 6 5/8” Drill Pipe Rental dated November 1, 2002

CONTRACTOR-5121-2002-011 Dear Randy, This letter is to document the actual cost and daily rental rate for the 6 5/8” drill pipe referenced in our November 1, 2002 letter agreement. According to the November 1, 2002 Agreement, the total rental amount will be 1.27418155 times the actual cost of the pipe. The pipe cost $1,352,110.27 including trucking and inspection so the total rental payment will be $1,722,833.96 over the remaining term of the contract. Therefore, the daily rental rate will be $3,208.26 per day starting on April 1, 2003 and continuing through September 18, 2004 (537 days). If the contract is terminated for any reason prior to September 18, 2004, BP agrees to pay the difference between $1,722,833.96 and the total rental paid up to the time of termination. BP will be responsible for all inspections during the term of the rental. The pipe shall be treated as Contractor’s in-hole equipment per Article 22 of the Contract. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.


Sincerely,



Sr. Marketing Representative AGREED AND ACCEPTED THIS 14 DAY OF APRIL, 2003

BP AMERICA PRODUCTION COMPANY





th

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE November 1, 2002 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 (“Contract”) by and between R&B Falcon Drilling Company

predecessor in interest to Transocean Holdings, Inc,(“Contractor or TODDI”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject: Letter of Agreement for 6 5/8” Drill Pipe Rental


Dear Randy, This letter is to document the agreement between Transocean Offshore Deepwater Drilling Inc. (TODDI) and Company for the rental of 18,000 feet of 6 5/8” R-3 drill pipe for use on the Deepwater Horizon. Company and TODDI hereby agree to the following terms and conditions:

1. TODDI shall purchase the following pipe and rent it to Company over the remaining term of the Contract referenced above. Specifications of the pipe are as follows:

* Changes from Grant Prideco quote 30726

2. Tooljoints (Pin & Box) shall be manufactured long enough to provide for a minimum of two full recuts and still have sufficient tong space excluding proud hardbanded area. Company’s coating, hardbanding and make & break specifications are attached and made a part of this Agreement.


Footage 18,000 Joints 439 Pipe OD 6 5/8” Connection 6 5/8 FH Weight 34.01 OD 8 / ” Grade S-135 ID 4 / ” Upset IEU Pin Tong 10” Range 3 Box Tong 13” Internal Coating TK34 XT* Hardfacing Pin None Inspection Truscope AS Hardfacing Box Armacor M Delivery 16 weeks*

Make & Break & 95% wall included


1 41 4

3. The rental rate will be approximately $3,000/day assuming that 18 months will be remaining on the contract at time of

pipe delivery and that the total cost of the pipe is approximately $1.29 million. The exact calculation will be made when the pipe is delivered and the total cost (based on good footage) and the remaining number of days in the term are known. The total rental amount to be recovered will be calculated at 1.27418155 times the total cost of the pipe. The total cost of the pipe will include inspection and transportation.

4. The rental rate shall begin upon delivery of the pipe to TODDI following acceptance in accordance with Company’s

QA/QC specifications and inspection criteria. These specifications and criteria are made a part of this Agreement. The rental rate shall cease when the total rental paid equals 1.27418155 times the final cost of the pipe. The rental agreement will continue as long the Contract is in force however the rental rate will be zero after the total rental paid equals 1.27418155 times the final cost of the pipe.

5. Contractor shall furnish all handling equipment required for this pipe during the term of the rental at no cost to

Company. 6. Initial inspection is included in the cost of the pipe. Company reserves the right to re-inspect the pipe at Company’s cost.

Company will be responsible for all inspections during the term of the rental. 7. The pipe shall be treated as Contractor’s in-hole equipment per Article 22.3 of the Contract except for the cost of

inspections. 8. During the term of the rental, Company will have the option of moving the pipe to another Transocean Rig at Company’s

option and expense. If you are in agreement with the above, please sign in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service. Sincerely,

Christopher S. Young Sr. Marketing Representative AGREED AND ACCEPTED THIS 3 DAY OF FEBRUARY, 2003 BP AMERICA PRODUCTION COMPANY





RD

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE November 12, 2003 BP Deepwater Development Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Jon Sprague – Atlantis Wells Delivery Leader Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in


Subject: Letter of Agreement for adding Tool Pusher in BP’s Office


Dear Mr. Sprague: Upon execution of this Letter Agreement by COMPANY, CONTRACTOR agrees to provide one (1) Tool Pusher to work in BP’s offices in addition to those specified in Exhibit F-1 of the Contract as amended. COMPANY has requested and CONTRACTOR agrees that CONTRACTOR will provide one (1) additional Sr. Toolpusher to work in COMPANY’s offices during the Atlantis Project. The Sr. Toolpusher will be shore based and work at COMPANY’s offices as required to support the Atlantis Project on an even rotating schedule. Work will commence on or about December 1, 2003. CONTRACTOR shall invoice COMPANY at the rate of US$786 (Seven Hundred Eighty Six) per day worked and for all documented reasonable and necessary travel costs and living (room and board) expenses (at no mark-up to actual costs). The Sr. Toolpusher will be available for work seven days a week on 14 day on and 14 day off schedule and COMPANY shall be billed monthly for every day available for work during the month. CONTRACTOR will supply supporting documentation with each monthly invoice as evidence of days available for work. COMPANY reserves the right to release the services of the Sr. Toolpusher at anytime upon thirty (30) days prior written notice to CONTRACTOR. COMPANY and CONTRACTOR will document when the Sr. Toolpusher is released from duty for services on this special Atlantis Project assignment, thus ending the applicability of this contract amendment. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.



BP Horizon – TP in BP’s office TSF File #01-063

AGREED AND ACCEPTED THIS 1st DAY OF DECEMBER, 2003 BP DEEPWATER DEVELOPMENT COMPANY

2

Sincerely,




On Behalf of Transocean Holdings Inc.,




CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE February 28, 2004

BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079

Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in



Transocean Ref: 5121-2001063-027

Dear Randy, We performed the “annual” cost analysis for the Deepwater Horizon as of January 1, 2004 in accordance with Article 2.3 “Adjustment in Dayrates” of the Contract referenced above. The following table summarizes the Baseline Cost changes detailed on the attached schedule “Basis for Cost Escalation”:

* According to Article 2.3.2, rates for each item must vary by => 5% before they can be adjusted. Notes: 2.3.2a Base Labor rates changed by the adjustment of the utilization bonus and pension accruals. The net result was a slight increase

but not the 5% required to trigger an increase. 2.3.2b We have changed catering companies on the Horizon which has provided a decrease from $31.95 per man per day to $30.45,

a decrease of 6.3%. Please note the catering cost shown on the accompanying schedule only reflects the crew complement in the contract (77 on board the rig) while we actually have 83.

E-23

TRANSOCEAN HOLDINGS INC. 4 GREENWAY PLAZA HOUSTON, TX 77046

Reference

2003 BaselineCosts plus Previous

Agreements

Actual BaselineCosts

@ Jan. 1, 2003

Increase/ (Decrease)

DayrateIncrease/

(Decrease)

2.3.2a Base Labor Costs $ 36,008

$ 36,099

$ 91 *

2.3.2b Catering Costs $ 2,780 $ 2,650 $ (130) $ (130)

2.3.2c Maintenance Element $ 13,851

$ 14,589

$ 738 $ 738


$ 5,137

0

Total $ 57,776/day

$ 58,475/day

$ 608day


BP Horizon – Escalation 2004 TSF File #01-063

2.3.2c The Maintenance Element of the Baseline Cost increased $738 per day based on the change on the relevant Producer Price

Index. The Index number for December 2003 increased to 153.8 from 145.8 in August of 2001, an increase of 5.33%. The Bureau of Labor Statistics Data for the Producer Price Index series ID: WPU119102 is attached.

2.3.2d Costs of insurance premiums have not changed due to the fact that our Risk Department negotiated a 14 month agreement for

the previous increases. We will keep you advised of any increases regarding insurance. The following documents are attached for reference: 1) “Basis for Cost Escalations” schedule; 2) “Adjusted Base Labor as of January 1, 2004”; and 3) the Bureau of Labor Statistics Data for the relevant Producer Price Index. In summary, the following adjustments will be made:

Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

AGREED AND ACCEPTED THIS 31 DAY OF MARCH, 2004 BP AMERICA PRODUCTION COMPANY

E-24

2

Paragraph 2.3.2b

(130) Paragraph 2.3.2c

738

Total Increase

$ 608 net increase effective January 1, 2004

Sincerely,





SIGNED /s/ Scott Sigurdson

PRINTED Scott Sigurdson

TITLE Wells Manager



$ Per Day

* Note: The Index did not vary by 5% so the baseline cost and index stays the same as in 2003 **Note: The 7 Addl Personnel are included as line items to identify that they were included in the previous escalation. The 18 Addl Personnel includes all personnel added to the contract and these lines indicate the increases on all Addl Personnel.

E-25

Clause No.:


Costs


Costs Variance

Adjusted2004

Baseline Costs

2.3.2a) Base Labor Cost:


$ 25,476

$ 25,626 $ 150

$ 25,476


$ 2,820

$ 3,024 $ 204

$ 2,820

** Labor & Burden (18 Addl Personnel - Onboard)

$ 6,852

$ 6,792 $ -59

$ 6,852

** (Training & Transportation Costs (18 Addl Personnel - Onboard)

$ 860

$ 656 $ -204

$ 860

Total Base Labor Cost

$ 36,008

$ 36,099 $ 91

$ 36,008

Percentage Increase

0.25%*


59 Contractor Personnel

$ 1,885

$ 1,797 $ -88

$ 1,797

** 18 Additional Personnel

$ 576

$ 549 $ -27

$ 549

10 Company Personnel $ 320 $ 305

$ -15 $ 305

Total Base Catering Costs $ 2,780 $ 2,650

$ -130 $ 2,650

Percentage Increase

-6.3%

2.3.2c) Base Maintenance Element: $ 13,851 $ 14,589

$ 738 $ 14,589

Percentage Increase

5.33%


Hull & Machinery

$ 2,422

$ 2,422 $ 0

$ 2,422

Marine P&I $ 2,039 $ 2,039

$ 0 $ 2,039

Excess Liability

$ 520

$ 520 $ 0

$ 521

Brokers Fee

$ 110

$ 110 $ 0

$ 110

Oil Pollution $ 46 $ 46

$ 0 $ 46

Total Base Insurance Cost: $ 5,137 $ 5,137

$ 0 $ 5,137

Percentage Increase

0.0%

Total Baseline Operating Costs

$ 57,776

$ 58,475 $ 608

$ 58,384

Total Dayrate Increase =

$ 608/day

DEEPWATER HORIZON



E-26

A

B

C

D

GOM Base Labor

GOM Overtime Rates

No. of Personnel

Daily Rate per

Daily

On Board

Assigned To

Rig JOB CLASSIFICATION

person (inc.TT&C)

Total Daily onBoard Cost

Overtime Rates

HourlyOvertime Rates

1 2

OIM 958.32 866.16 818.90 68.241

2 OSA - Horizon

868.26

776.10

728.84

60.74

3 6

Toolpusher 793.31 2,103.44 653.89 54.492

4 Driller

659.31

1,134.31

619.69

51.64

4 8

Assistant Driller

508.91

1,667.01

440.42

36.70

2 4

Pumpman

427.86

671.40

343.80

28.65

12 24

Floorman

383.58

3,886.55

340.75

28.40

14 28

Roustabouts 342.07 3,953.17 291.27 24.271

2 Welder

483.29

391.13

409.87

34.16

4 8

Crane Operator 499.66 1,630.00 429.39 35.782

4 Chief Mechanic

591.28

998.23

538.59

44.88

1 2

Mechanic

493.19

401.03

421.68

35.14

2 4

Motor Operator

397.26

675.10

357.04

29.75

1 2


659.31

567.15

519.90

43.32

2 4

Chief Electrician 589.72 995.12 536.74 44.731

2 Electrician

488.44

396.28

416.02

34.67

2 4

Chief Electronic Technician 597.91 1,011.50 546.50 45.541

2 Senior Sub Sea Sup

759.49

667.32

620.07

51.67

1 2

Assistant Subsea

559.02

466.86

500.14

41.68

2 4


451.60

718.88

372.10

31.01

1 2

Master

852.37

760.21

712.95

59.41

1 2

Chief Mate 671.59 579.43 634.32 52.861

2 Chief Engineer

759.56

667.40

620.14

51.68

1 2

1st Assistant Engineer 658.33 566.17 618.52 51.542

4 2nd Assistant Engineer

653.50

1,122.68

612.76

51.06

2 4

DP Operator

561.07

937.81

502.58

41.88

2 4


475.10

765.88

400.11

33.34

2 4

Deck Pusher

491.25

863.09

469.07

39.09

1 2

Bosun

480.83

388.67

406.94

33.91

3 6

AB Seaman

401.43

1,025.18

362.02

30.17

1 2

RSTT 475.10 382.94 400.11 33.341

2 Medic

475.10

382.94

400.11

33.34

0 0

-

—

—

—

—

0 0

- — — — —0

0 -

—

—

—

—

0 0

- — — — —0

0 -

—

—

—

—

0 0

- — — — —0

0 - — —

—

—

77 154

Total Labor Costs = $ 32,419.17

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE April 19, 2004 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads Re: Drilling Contract No. 980249 dated December 9, 1998 (“Contract”) by and between R&B Falcon Drilling Company

predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject: Contract Extension Agreement (“Agreement”)


Dear Randy, This letter will confirm our agreement to extend the Contract under the same terms and conditions except as modified herein: 1) Term:

a) The term of the extension (Extension Period) shall be one (1) year commencing September 18, 2004.

b) Article 1.1.2 of the Contract shall be amended so that there will be no further options to extend the Contract after this Extension Period.

2) Rates:

The dayrates specified in Exhibit “A” shall be amended to the following rates at commencement of the one (1) year Extension Period:

The rates specified above are subject to the following conditions:

TRANSOCEAN HOLDINGS, INC. 1311 BROADFIELD, SUITE 400 HOUSTON, TX 77084

1. Operating Rate

$165,000 /day2.

Moving Rate 165,000

3. Standby w/ crews

165,0004.

Standby w/o crews 165,000, less documented cost savings

5. Stack w/ crews

165,000, less documented cost savings6.

Stack w/o crews 165,000, less documented cost savings

7. Equipment Repair

165,000 subject to article 2.2.5 (A)8.

Hurricane Evacuation 165,000 standby w/o crew plus documented expenses of evacuated crew.


BP Horizon Extension Agreement TSF File #01-063

a) Revised Personnel Complement

Exhibit “F-1” of the Contract shall be amended effective at the commencement of the Extension Period to include the personnel complement attached as Exhibit 1 hereto, which recognizes Contractor’s revised maintenance philosophy and optimized crewing plan. In addition, to provide both parties flexibility to adjust crewing levels as circumstances allow, Company and Contractor agree to the following: As conditions warrant, Contractor, with Company representative’s consent (which shall not be unreasonably withheld), may reduce the number of personnel (for those job classifications listed in the table below) assigned to the rig from the number listed in the table below as “Current Personnel Assigned to Rig” to the number listed in “Revised Personnel Assigned to Rig Per Exhibit 1”. Adjustments within the ranges reflected in the table will not incur a corresponding adjustment in dayrates.

At any time during the Extension Period, if Company determines that any previous reductions to personnel in the classifications listed above do not permit safe and efficient rig operations, Company’s representative may require Contractor to increase the number of personnel assigned to the rig listed in the table above from any reduced level back up to the number listed in the table above as “Current Personnel Assigned to Rig”. Adjustments within the ranges reflected in the table will not incur a corresponding adjustment in dayrates. Should Company require extra permanent rig staff in addition to; 1) the “Current Personnel Assigned to Rig” for the job classifications listed in the table above, or 2) the other job classifications listed in the revised “Exhibit “F-1” Personnel Complement” attached hereto as Exhibit 1, the additional personnel will be added to the personnel complement and the dayrates specified in Attachment “A” of the Contract, as amended, will be adjusted for the increase in expense. Contractor will be responsible, at its sole cost, for any additional personnel required for operation, repair or maintenance of the vessel and the dayrates will not be adjusted to reflect any such increases.

b) Operating Costs:

The rates specified in item (2) hereof are based on the “Basis for Cost Escalations dated January 1, 2004” documented in our February 28, 2004 “Letter of Agreement for Cost Escalation 2004”

2

Job Classification

Revised PersonnelAssigned to Rig Per Exhibit “1”

Current Personnel

Assigned to RigToolpusher

6 8

Derrickman/Floorman/Pumpman 24 28

Crane Operator

6 8

Roustabouts/Lead Roustabouts 22 28

OSA

0 2

as amended for the revised personnel complement set forth in the new Exhibit F-1 per Section 2 a) of this Agreement. The “Revised Basis for Cost Escalations” based on the revised personnel complement set forth in the new Exhibit F-1 per Section 2 a) of this Agreement is attached hcrcto as Exhibit 2. The “Revised Basis for Cost Escalations” in Exhibit 2 shall serve as the baseline for cost adjustments as of the commencement date of the Extension Period. At the commencement of the Extension Period, Article 2.3.2 of the Contract will be amended to read as follows:

Article 2.3.2 Amended: 2.3.2 The dayrates set forth in Exhibit A as amended shall be revised as of the commencement of the Extension Period as defined in the Contract Extension Agreement dated April 14, 2004 (the “Extension Agreement”) to reflect the change in costs from the “Revised Basis for Cost Escalation dated January 1, 2004” (attached as Exhibit 2 to the Extension Agreement) if the costs of any of the items hereafter listed shall vary in an amount equal to or greater than three percent (3%) from the costs thereof.

a. Labor costs, including all benefits, of CONTRACTOR’S personnel listed in Exhibit F; b. CONTRACTOR’S cost of catering; c. CONTRACTOR’S cost of spare parts and supplies vary and that the parties shall use the United States Department

of Labor’s Producer Price Index Commodity Code No. 1191.02 . Oil Field and Gas Field Drilling Machinery to determine what extent a price variance has occurred in said spare parts and supplies.

d. Cost of insurance not based solely on CONTRACTOR’S loss or claim record.

CONTRACTOR must show documented proof for any dayrate adjustments due to changes in CONTRACTOR’S cost of labor, insurance or catering. After any adjustment, the adjusted costs shall be the new basis for cost escalation.

c) Amendments to the Contract:

The Contract contains numerous amendments related to the provision of equipment, personnel, supplies and activities. The Extension Period dayrates specified in 2 above reflect all such amendments except as otherwise noted herein.

i) Equipment Added during the Initial Term per Letter Agreements :

Certain letter amendments to the Contract provided for lump sum payments, rental payments, or formulaic and other increases to the operating rates to permit Contractor’s recovery of certain costs within the Contract’s initial term for purchasing additional equipment. The parties agree that the payment obligations arising under such amendments will expire at the end of the Contract’s initial term as originally contemplated but that any maintenance or removal obligations will continue to the end of the Extension Period. Letter agreements regarding equipment are attached hereto as Exhibit 3.

ii) Amendments Adding Personnel:

The revised personnel complement referenced in item 2(a) of this Agreement incorporates all personnel added to the rig at Company’s expense in previous amendments to the Contract so that there will be no additional rig based personnel billed in addition to the dayrate unless

3

added by Company as set forth in Item 2(a) of this Agreement. The costs related to the November 12, 2003 amendment adding a tool pusher to work in Company’s office are not included in the rates specified in item (2) hereof and Company will remain responsible for the cost.

iii) Other Amendments to the Contract:

Rental equipment (other than the equipment covered in 2.c.i. above) and/or third party services provided by Contractor, if any, are not included in the extension dayrates. The Recycle the Gulf agreement dated January 7, 2003 will continue per the terms of that agreement and the cost is not included in the dayrates specified in item (2) hereof.

d) Drilling Riser

Contractor acknowledges that the Deepwater Horizon is equipped to drill in 10,000 feet of water with the sole exception of adequate length of drilling riser. Company and Contractor agree that during the term of this Agreement, Company may authorize Contractor to use excess riser from the Discoverer Enterprise (or any other Contractor rig that Company may have under contract in the Gulf of Mexico during the time of the requirement) on the Deepwater Horizon to enable the Deepwater Horizon to drill in water depths up to 10,000’. If Company authorizes Contractor to use the excess riser, Contractor shall obtain, a riser analysis confirming that the use of the excess riser in the water depth contemplated meets appropriate safety and operational standards. In the event Contractor is unable to obtain such a confirming analysis, the parties shall promptly meet in good faith to discuss and implement alternatives to meet Company’s need for excess riser use. Once the confirming analysis has been obtained, or an alternative has been agreed to and implemented, Contractor agrees to order any adapters or crossovers required subject to Company’s agreement to reimburse Contractor per Article 8.1.2 of the Contract. Company shall provide adequate written notice before the intended use of the excess riser, in order to enable timely delivery of the required crossovers. Company shall be responsible for all transportation of riser between the rigs.

Except as specifically set forth above, all other terms and conditions of the Contact, as amended to date, shall remain unchanged. Please signify your agreement with this Agreement by signing both originals in the space provided below and return one (1) fully executed original to us for our records.

4

Sincerely,




On Behalf of Transocean Holdings, Inc.

ACCEPTED AND AGREED TO:

By: /s/ ILLEGIBLE

Date: 4/26/04On Behalf of BP America Production Company

EXHIBIT 1

PERSONNEL COMPLEMENT

DEEPWATER HORIZON


5

A

B

C

D

GOM Base Labor

GOM Overtime Rates

No. of Personnel

Daily Rate per

Daily

On Board

Assigned To Rig

JOB CLASSIFICATION

person (inc.TT&C)

Total Daily on Board Cost

Overtime

Rates

HourlyOvertime Rates

1

2

OIM 958.34 866.18

818.92 68.243

6

Toolpusher

793.33

2,103.50

653.91

54.49

2

4

Driller

659.33

1,134.34

619.71

51.64

4

8

Assistant Driller 508.92 1,667.06

440.43 36.702

4

Derrickman

458.73

733.15

380.61

31.72

2

4

Pumpman

427.87

671.41

343.82

28.65

8

16

Floorman

383.59

2,591.11

340.76

28.40

1

2

Maintenance Supervisor

776.45

684.29

637.03

53.09

1

2

Mechanical Supervisor

659.33

567.17

519.91

43.33

2

4

Chief Mechanic

591.29

998.26

538.61

44.88

2

4

Mechanic 493.20 802.09

421.69 35.141

2

Senior Motor Operator

446.45

354.29

365.97

30.50

2

4

Motor Operator

397.26

675.12

357.05

29.75

1

2


659.33

567.17

519.91

43.33

1

2

Chief Electrician

589.74

497.58

536.75

44.73

1

2

Electrician

488.46

396.30

416.03

34.67

1

2


597.92

505.76

546.51

45.54

1

2

Electronic Technician 492.55 400.39

420.91 35.081

2

Senior Sub Sea Sup Dp

759.51

667.34

620.09

51.67

1

2

Subsea Supervisor

634.77

542.61

590.43

49.20

1

2

Master

852.39

760.23

712.97

59.41

1

2

Chief Mate

671.61

579.45

634.35

52.86

1

2

Bosun

480.84

388.68

406.96

33.91

3

6

AB Seaman

401.44

1,025.21

362.03

30.17

2

4

DP Operator 561.08 937.84

502.60 41.882

4


475.11

765.90

400.13

33.34

3

6

Crane Operator

499.67

1,222.54

429.40

35.78

1

2

Deck Pusher

491.26

431.55

469.09

39.09

2

4

Lead Roustabouts

355.34

591.28

307.09

25.59

9

18

Roustabouts

342.08

2,541.39

291.28

24.27

1

2

Welder

483.30

391.14

409.88

34.16

1

2

Senior Materials Co-Ordinator 524.24 432.08

384.82 32.071

2


451.61

359.45

372.12

31.01

1

2

Medic

475.11

382.95

400.13

33.34

1

2

Radio Operator

419.84

327.68

334.25

27.85

1

2

RSTC

516.05

423.89

448.92

37.41

0

0

-

—

—

—

—

0

0

-

—

—

—

—

0

0

- — —

— —0

0

-

—

—

—

—

69

138

Total Labor Costs =

$ 28,986.39

EXHIBIT 2

REVISED BASIS FOR COST ESCALATIONS DEEPWATER HORIZON

January 1, 2004 $ Per Day

6

Clause No.:

Adjusted2004

Baseline Costs



$ 28,986


$ 3,447


$ 32,433



$ 2,101

10 Company Personnel $ 305Total Base Catering Costs

$ 2,406


$ 14,589

Percentage Increase


Hull & Machinery

$ 2,422

Marine P&I $ 2,039Excess Liability

$ 521

Brokers Fee

$ 110

Oil Pollution $ 46Total Base Insurance Cost: $ 5,137


$ 54,565

EXHIBIT 3

2) c) i) Letter Agreements Regarding Equipment:

7

Date: Description:

Amount:Jan. 16, 2004

Riser, Removal, Transportation and Storage NA

Apr. 15, 2002 Test Stump Change

Lump SumApr. 15, 2002

Connector Modification Lump Sum

Jun 12, 2004 Variable Bore Ram

$125/dayNov. 1, 2002 & Mar 20, 2003

“Rental” of 18,000’ of 6 5/8” DP $3,208.26/day

Mar 3, 2003 “Rental” of 6 5/8” HWDP

$2,42.01/day

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE June 25, 2004 BP America Production Company 200 Westlake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads

Mail Code 1089 WL4 Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company (“Contractor”)

and Vastar Resources, Inc. predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the Deepwater Horizon)

Subject: Letter of Agreement for Cap Rock Communication Equipment CONTRACTOR-5121-2002-011

Dear Randy, This letter is to document our agreement for Contractor to contract and install the communications equipment as detailed on the attached Quotation #3630-10100 from Cap Rock Communications dated June 2, 2004 and for Company to pay Contractor a monthly rental amount over the remaining term of the Contract as extended. The rental payment will be $9,975 per month based on the prices shown on the attached quote. The first rental payment will be due and payable when the equipment has been installed. If the contract is terminated for any reason prior to September 18, 2005, Company agrees to pay the rental amount owed up to September 18, 2005 in the form of a lump sum payment. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

AGREED AND ACCEPTED THIS, 28 DAY OF JUNE, 2004 BP AMERICA PRODUCTION COMPANY


Sincerely.






TITLE Contract Specialist

PHONE: (832) 587-8506 FAX: (832) 587-8754


th

Quotation

4400 S. Sam Houston Parkway EastHouston, Texas 77048

832-668-2370 FAX832-668-2388

Customer:

Transocean

Quotation #:

3630-10100Attn:

Niel Svendsen/John Keeton

Date:

6/2/04Address:

1311 Broadfield Blvd. suite 200 Acct. Mgr.

S. NewsteadCity, State, Zip:

Houston, TX 77084

Ref:

HORIZON - VSATPhone/Fax:

832-587-8759 Revision b3

Item

Qty. Description

each ext

single ant.

HARDWARE

1.0

Single stabilized antenna system (dual band)

$ 149,500

Seatel Dual Band 9797 2.4m antenna (configured for Ku-band Linear for GOM) 144 in radome assembly

Ku-band SSPA and Transceiver (16 Watt)

2nd Pwr Supply for C side balancing (No C band RF at this time. To be purchased when needed)

Onshore Assembly, Integration, documentation, testing, and commissioning

2.0

Radome AC unit for Seatel 9797 (pro-longs equipment life) required on C-band systems with 40W or higher RF packages due to the high power and heat generated from the SSPA. AC unit requires a 220V feed at the antenna location

$ 4,600

3.0

The above system is priced as a stand alone single antenna unit. This antenna can be integrated into a dual antenna system (using the Transocean owned 9797 antenna removed from the FI00). Therefore, the switching hardware, engineering, and integration for the dual antenna configuration will be additional to the above equipment cost prior to installation.

$ 5,000

4.0

Delivery

Delivery of this size system is typically 3-5 weeks. Depending on receipt of PO, production schedules, in stock availability, systems may be available on a much shorter scale.

Customer Signature: All prices stated are FOB factory

Prices do not include installation,

PHONE: (832) 587-8506 FAX: (832) 587-8754


CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE October 11, 2004 BP America Production Company 200 Westlake Park Blvd. Houston, TX 77079 Attn: Mr. Randy Rhoads

Mail Code 1089 WL4 Re: Drilling Contract No. 980249 dated December 9, 1998 (as previously amended, “Contract”) by and between R&B Falcon

Drilling Company, predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc., predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the “Deepwater Horizon”)

Subject: Letter Agreement for Conversion of VBR to a Test Ram

CONTRACTOR-5121-2002-011 Dear Randy, When executed by both parties below, this letter will document the agreement between Contractor and Company for Contractor’s conversion (the “Conversion”) of an existing variable bore ram (“VBR”) into a “test ram” on the Deepwater Horizon’s blowout preventer (the “BOP”).

In accordance with Articles 5 and 7 of the Contract, Company shall reimburse Contractor for the cost associated with the Conversion, which is estimated to be $135,000 based on the attached quote/AFE including the five percent (5%) handling fee. Notwithstanding the foregoing, Contractor shall give Company written notice of any increase of more than ten percent (10%) in the above cost estimate and such increase shall be subject to Company’s prior written approval. If installation should require out-of-service time, Company agrees to pay Contractor at the Standby Rate (as defined in the Contract) until operations can be recommenced; provided such out-of-service time shall not exceed a maximum of twenty-four (24) hours. Reimbursement for the Conversion shall be in the form of a lump sum payment due and payable within thirty (30) days of receipt of Contractor’s invoice therefore, which invoice shall be sent after the “test ram” has been installed.

Company acknowledges that the Conversion will reduce the built-in redundancy of the BOP, thereby potentially increasing Contractor’s risk profile and corresponding cost structure. Therefore, after the Conersion is completed, if one of the two remaining VBRs fails to “test” on any well for any mechanical reason (as opposed to abnormal wear or damage caused by operations) and the MMS requires that Contractor pull the BOP to replace the VBR, Company agrees to pay Contractor the Operating Rate (as defined in the Contract) for the time required to pull the BOP, replace the ram, and re-run the BOP; provided, however, if one of the two remaining VBRs fails to “test” a subsequent time on the same well for any mechanical reason, after initially testing subsea, (as opposed to abnormal wear and damage caused by operations) and the MMS requires that Contractor pull the BOP to replace the VBR, the time required to pull the BOP, replace the ram, and re-run the BOP shall be considered Mechanical Downtime (as defined in the Contract).

Except as specifically set forth above, all other terms and conditions of the Contract, as amended to date, shall remain unchanged.


PHONE: (832) 587-8506 FAX: (832) 587-8754


Please indicate your agreement to the terms of this letter by signing in the space provided below and returning an executed copy to us for our files. If you have any further questions, please contact John Keetor. at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

2

Sincerely,

AGREED AND ACCEPTED:

THIS 19 DAY OF October, 2004 BP AMERICA PRODUCTION COMPANY



SIGNED /s/ Jeff Sjurseth Sr. Marketing Representative

PRINTED Jeff SjursethTransocean Holdings, Inc.


th

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE February 20, 2005 BP America Production Company 200 WestLake Park Blvd. Houston, TX 77079

Subject: Letter of Agreement for adding Deck Pushers


Dear Jeff, This letter will serve as our agreement to add another Deck Pusher to the crew complement of the Deepwater Horizon. Upon execution of this Letter Agreement by Company, Contractor agrees to provide one (1) Deck Pusher onboard the Deepwater Horizon in addition to those specified to be provided in Exhibit F-2 of the Contract as amended. Exhibit F-1 of the Contract shall be amended, as of March 1, 2005 to provide for the following additional personnel:

Therefore, the amended crew complement shall show three (2) Deck Pushers “On Board” and four (4) “Assigned to Rig”. The amended crew complement is attached. In summary, all rates in the Contract shall increase by $491.26 per day effective March 1, 2005. Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact John Keeton at (832) 587-8533 or me at (832) 587-8506. Thank you for the opportunity to be of service.

TRANSOCEAN HOLDINGS, INC.1311 BROADFIELD SUITE 400 HOUSTON, TX 77084

Attn: Mr. Jeff Sjurseth Re: Drilling Contract No. 980249 dated December 9, 1998 (as previously amended, “Contract”) by and between R&B Falcon

Drilling Company, predecessor in interest to Transocean Holdings Inc. (“Contractor”) and Vastar Resources, Inc., predecessor in interest to BP America Production Company (“Company”), as amended for RBS-8D (now known as the “Deepwater Horizon”)

Title On Board

Assignedto Rig

Daily Rate perPerson On Board

w/ Burden


Deck Pusher 1

2

$ 491.26

$ 39.09

Sincerely,




PHONE: (832) 587-8506 FAX: (832) 587-8754


BP Horizon TSF File #01-063 AGREED AND ACCEPTED THIS 4 DAY OF MARCH, 2005 BP AMERICA PRODUCTION COMPANY

2

SIGNED /s/ Jeff Sjurseth

PRINTED Jeff Sjurseth


th

CHRISTOPHER S. YOUNG SR. MARKETING REPRESENTATIVE March 31, 2005 BP America Production Company 501 WestLake Park Blvd. Houston, TX 77079


Transocean Ref: 5121-2001063-035

Dear Jeff, We performed the “annual” cost analysis for the Deepwater Horizon as of January 1, 2005 in accordance with Article 2.3 “Adjustment in Dayrates” of the Contract referenced above. The following table summarizes the Baseline Cost changes detailed on the attached schedule “Basis for Cost Escalation”:

* According to the Amended Article 2.3.2 from the Extension letter, rates for each item must vary by => 3% before they can be adjusted.

** The Insurance Base Rate set on April 19, 2004 was overstated by $420 per day. It was calculated based on the personnel complement before taking into account the decrease of personnel stipulated in the Extension Agreement. Current insurance costs reflect the current personnel complement.

E-27

TRANSOCEAN HOLDINGS INC.4 GREENWAY PLAZA HOUSTON, TX 77046

Attn: Mr. Jeff Sjurseth Re: Drilling Contract No. 980249 dated December 9, 1998 by and between R&B Falcon Drilling Company predecessor in


Baseline Costs Dayrate

from Ext. Letter Baseline Costs Increase/ Increase/

Reference Dated April 19, 2004

Jan. 1, 2005

(Decrease) (Decrease)

2.3.2a Base Labor Costs $ 32,433

$ 33,832

$ 1,399 $ 1,399

2.3.2b Catering Costs $ 2,406 $ 2,406 $ 0

*2.3.2c Maintenance Element

$ 14,589

$ 15,338

$ 749 $ 749


$ 4,568

$ (149) $ (149)Correction to 4/19/04 Insurance**

$ (420)

Corrected Total Baseline Costs $ 54,145/day

$ 56,144/day $ 1,999 / day

Total Dayrate Increase $ 1,999 / day


BP Horizon – Escalation 2005 TSF File #01-063 Notes: 2.3.2a Base Labor rates changed due to salary increases in October and November and by the adjustment of the utilization bonus

and pension accruals. The net result is an increase of $1,399 which brings the total Base Labor Cost to $33,832. 2.3.2b Catering cost increased in March 2005 so it will not be included in this escalation. 2.3.2c The Maintenance Element of the Baseline Cost increased $749 per day based on the change on the relevant Producer Price

Index. The Index number for January 2005 increased to 161.7 from 153.8 in December 2003, an increase of 5.14%. The Bureau of Labor Statistics Data for the Producer Price Index series ID: WPU119102 is attached

2.3.2d Insurance cost decreased by $149 (a 3.2% decrease). As stated previously, the April 19 Insurance cost was overstated by

$420 per day. The following documents are attached for reference: 1) “Basis for Cost Escalations” schedule; 2) “Adjusted Base Labor as of January 1, 2004”; and 3) the Bureau of Labor Statistics Data for the relevant Producer Price Index.

In summary, all of the dayrates will increase by $1,999 per day effective January 1, 2005

Except as specifically provided herein, all other terms and conditions of the Contract shall remain in full force and effect. Please indicate your agreement in the space provided below and return one fully executed copy of this letter to me for our files. If you have any questions, please contact me at (832) 587-8506. Thank you for the opportunity to be of service.

AGREED AND ACCEPTED THIS 23 DAY OF MAY, 2005 BP AMERICA PRODUCTION COMPANY

E-28

2

Paragraph 2.3.2a $ 1,399

Paragraph 2.3.2c $ 749

Paragraph 2.3.2d (149)

Total Increase $ 1,999 net increase effective January 1, 2005

Sincerely,





SIGNED /s/ Jeff Sjurseth

PRINTED Jeff Sjurseth


rd



$ Per Day

E-29

3

Baseline

Baseline

Adjusted

Costs Apr

Costs Jan.

Baseline Costs

Clause No.:

2004

1, 2005 Variance

Jan. 1, 2005

2.3.2a) Base Labor Cost: Labor & Burden (per schedule)

$ 28,986

$ 30,386

$ 1,400

$ 30,386


$ 3,447

$ 3,447

$ 0

$ 3,447


$ 32,433

$ 33,832

$ 1,399

$ 33,832

Percentage Increase 4.31%

2.3.2b) Base Catering Cost: 69 Contractor Personnel

$ 2,101

$ 2,101

$ 0

$ 2,101


$ 305

$ 305

$ 0

$ 305


$ 2,406

$ 2,406

$ 0

$ 2,406

Percentage Increase

0%


$ 14,589

$ 15,338

$ 749

$ 15,338

Total Base Matinenance Costs $ 749Percentage Increase

5.14%


Hull & Machinery

$ 2,422

$ 1,710

$ (712) $ 1,710

Marine P&I $ 1,619 $ 2,257 $ 639 $ 2,257Excess Liability

$ 521

$ 464

$ (57) $ 464

Brokers Fee $ 110 $ 110 $ 0 $ 110Oil Pollution

$ 46

$ 26

$ (20) $ 26

Total Base Insurance Cost: $ 4,717 $ 4,568 $ (149) $ 4,568Percentage Increase

-3.2%


$ 54,145

$ 56,144

$ 1,999

$ 56,144

Dayrate Increase $ l,999/day

DEEPWATER HORIZON



E-30

4

A

B

C

D

GOM Base Labor

GOM Overtime Rates

No. of Personnel

Daily Rate per

Daily

On Assigned

person (inc.

Total Daily on

Overtime

Hourly

Board To Rig

JOB CLASSIFICATION TT&C) Board Cost Rates Overtime Rates1

2

OIM 934.65 842.49 794.31 66.193

6

Toolpusher

804.26

2,136.30

663.92

55.33

2

4 Driller 667.33 1,150.34 628.15 52.35

4

8 Assistant Driller

555.14

1,851.91

494.42

41.20

2

4 Derrickhand

488.77

793.22

415.31

34.61

2

4 Pumphand

451.64

718.95

371.05

30.92

8

16 Floorhand

394.60

2,679.21

352.79

29.40

1

2 Maintenance Supervisor 787.12 694.96 646.78 53.90

1

2 Mechanical Supervisor

679.58

587.42

539.24

44.94

2

4 Chief Mechanic 617.56 1,050.79 568.82 47.40

2

4 Mechanic

555.14

925.96

494.42

41.20

1

2 Senior Motor Operator

451.64

359.48

371.05

30.92

2

4 Motor Operator

419.89

720.37

382.92

31.91

1


679.58

587.42

539.24

44.94

1

2 Chief Electrician 617.56 525.40 568.82 47.40

1

2 Electrician

555.14

462.98

494.42

41.20

1

2


617.56

525.40

568.82

47.40

1

2 Electronic Technician

555.14

462.98

494.42

41.20

1

2 Senior Sub Sea Sup Dp

768.16

676.00

627.82

52.32

1

2 Subsea Supervisor

679.58

587.42

642.74

53.56

1

2 Master 864.24 772.08 723.90 60.32

1

2 Chief Mate

696.17

604.01

662.52

55.21

1

2 Bosun 505.36 413.20 435.09 36.26

3

6 AB Seaman

428.18

1,105.44

392.81

32.73

2

4 DP Operator

580.03

975.73

524.08

43.67

2

4 Assistant Dp Operator

507.73

831.14

437.91

36.49

3

6 Crane Operator

505.36

1,239.61

435.09

36.26

1

2 Deck Pusher

511.14

451.44

491.69

40.97

2

4 Lead Roustabouts

365.77

612.12

318.41

26.53

9

18 Roustabouts 355.49 2,662.12 306.17 25.51

1

2 Welder

488.77

396.61

415.31

34.61

1

2

Senior Materials Coordinator

530.25

438.09

389.91

32.49

1

2 Material Coordinator

480.47

388.31

405.42

33.79

1

2 Medic

480.47

388.31

405.42

33.79

1

2 Radio Operator

430.70

338.54

346.09

28.84

1

2 RSTC 521.95 429.79 454.86 37.91

0

0 —

—

—

—

—

0

0 —

—

—

—

—

0

0 — — — — —

0

0 —

—

—

—

—

69

138 Total Labor Costs =

$ 30,385.52

Public Data Query


Data extracted on: March 17, 2005 (2:32:06 PM)

Producer Price Index-Commodities

Series Id: WPU119102 Not Seasonally Adjusted Group: Machinery and equipment Item: Oil field and gas field drilling machinery Base Date: 8200

(P) : Preliminary. All indexes are subject to revision four months after original publication.

Frequently Asked Questions | Freedom of Information Act | Customer Survey Privacy & Security Statement | Linking to Our Site | Accessibility

01-063NAR - Horizon Escalation Jan 2005-cy

E-31

5

U.S. Department of Labor Bureau of Labor Statistics Bureau of Labor Statistics Data

www.bls.gov Search | A-Z Index

Change

Output From: 1995

To: 2005

GOOptions:

include graphs NEW!

More Formatting Options

Year Jan

Feb Mar


Nov Dec Annual

1995 118.3

118.6 119.2

119.2 119.3

119.6

120.4

120.4

120.4

122.0 122.2

122.2

120.1

1996 124.0

124.0 124.0

124.3 124.2

124.8

125.3

125.3

125.3

126.2 126.6

127.1

125.1

1997 127.7

127.9 128.6

129.1 129.2 129.3 129.3 129.5 129.7 130.3

131.4 132.0 129.5

1998 133.1

132.9 133.1

133.0 133.0

133.0

132.9

132.9

132.9

133.6 133.6

133.6

133.1

1999 133.8

133.7 133.7

133.9 133.9 134.0 134.0 133.7 133.7 133.7

134.4 134.6 133.9

2000 134.9

136.3 136.3

136.3 136.5

136.5

136.5

136.6

136.7

138.7 138.7

138.7

136.9

2001 143.5

143.9 144.0

144.0 144.0

145.5

145.6

145.8

145.7

146.1 146.1

146.1

145.0

2002 146.2

146.2 146.6

146.6 146.4

146.4

146.4

146.4

146.7 146.7 146.7

146.5

146.5

2003 149.8

149.8 149.8

151.7 152.3 152.5

152.5

152.5

153.1

153.1 153.1

153.5

152.0

2004 153.8

153.9 154.8

156.4 157.1 157.1 156.6 156.7 156.8 156.4(P) 157.9(P) 159.3(P) 156.4(P)

2005 161.7(P)

U.S. Bureau of Labor Statistics Phone: (202) 691-5200Postal Square Building Fax-on-demand: (202) 691-63252 Massachusetts Ave., NE Data questions: blsdata [email protected], DC 20212-0001 Technical (web) questions: [email protected]

Other comments: [email protected] http://data.bls.gov/PDQ/servlet/SurveyOutputServlet;jsessionid=f0303b9e9b918$3F$3F$ 3/17/2005

Kim Schutts Transocean Offshore Deepwater Drilling Inc. 1311 Broadfield Houston, TX 77083 Re: Annual Premiums

Deepwater Horizon These costs and limits reflect the coverage provided at this time and are subject to change upon renewal.

* Includes the War risk buyback – the deductible is $10,000,000 each occurrence with a one time $40,000,000 additional aggregate deductible.

** Based on SIR accrual of $ 16.36 per person per day assigned to the rig.

Best Regards, Betsy Kelly, CPCU, ARe Manager- Insurance

E-32

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.4 GREENWAY PLAZA HOUSTON, TX 77046

BETSY KELLY MANAGER-INSURANCE

Effective March 1, 2004

Coverage: All Risk Hull & MachineryCarrier: various Underwriters @ Lloyds, led by Limit and

Wellington SyndicatesInsured Value: $ 255,000,000Deductible: $ 10,000,000NET ANNUAL PREMIUM: $ 624,098 Effective December 31, 2004 Coverage: Primary Marine Protection & Indemnity Carrier: various Underwriters @ Lloyds, led by Self Insured Retention: $10,000,000 per occurrenceDEDUCTIBLE ACCRUAL: $ 823,860 Effective March 1, 2004

Coverage: Excess LiabilityCarriers: various Underwriters @ Lloyds, led by Limit and

Wellington SyndicatesLimits: $500,000,000NET ANNUAL PREMIUM: $ 169,347 Effective October 1, 2004

Coverage: Oil PollutionCarrier: Surety coverage – backed by Underwriters @LloydsNET ANNUAL PREMIUM: $ 9,598 Effective December 31, 2004

U.S. Broker: McGriff, Seibels & Williams, Inc Annual Fee: $ 40,180

(713) 232-7766 FAX (713) 232-7630 TEL

[email protected]

Amendment No. 24

to Drilling Contract No. 980249

This Amendment No. 24 is entered into effective as of the 20 day of April, 2005, by and between BP America Production Company (hereinafter referred to as “COMPANY”) and Transocean Holdings, Inc. (hereinafter referred to as “CONTRACTOR”) with a place of business at 1311 Broadfield, Suite 400, Houston, Texas 77084.

W I T N E S S E T H:

WHEREAS, by Drilling Contract No. 980249 made and effective the 9 day of December, 1998, COMPANY and CONTRACTOR entered into that certain Contract for the “Deepwater Horizon” (hereinafter referred to as “CONTRACT”), as previously amended by twenty-three (23) letters of agreement/amendment; and WHEREAS, COMPANY and CONTRACTOR desire to amend the CONTRACT as more particularly set forth herein. NOW THEREFORE, for and in consideration of the mutual covenants and agreements hereinafter provided, COMPANY and CONTRACTOR agree to amend the CONTRACT as follows: 1. Article 1, TERM shall be revised as follows:

The term of this CONTRACT shall be extended for a period of five (5) years commencing on September 18, 2005.

2. A new Article 1.3.3 shall be added to Article 1.3, COMPLETION OF CONTRACT as follows:

1.3.3 Subject to CONTRACTOR’s reasonable approval, COMPANY shall have the right to utilize the drilling services of the Drilling Unit outside of the Gulf of Mexico for subsidiaries, affiliates, or third parties, provided dayrates shall be adjusted to reflect any increases supported by documentation in CONTRACTOR’s cost of operations including but not limited to all operating costs, associated taxes assessed or levied, import/exportation duties and fees, and shorebase and logistical costs as a result of such foreign operation. A separate contract based on this CONTRACT will be executed with country specific provisions relative to the operations in that country. If the Drilling Unit should be outside of the Gulf of Mexico at the end of the term of this CONTRACT, COMPANY shall be responsible for mobilizing the Drilling Unit back to Galveston, Texas, or a point no further distant at the end of the term of the CONTRACT in accordance with 1.3.1 of the CONTRACT.

3. The Operating Rate (and, consequently, all other dayrates except the Equipment Repair Rate) specified in EXHIBIT A, DAYRATES, shall be revised to the amount, and periodically adjusted in accordance with the terms, set forth below.

An Operating Rate of $275,000 per day shall be payable to CONTRACTOR commencing September 18, 2005, through the end of the initial 2 year term of the CONTRACT extension. The rate specified is based on wage scales and current operating expenses as of March 1, 2005. CONTRACTOR shall have the right to adjust the rate for documented changes, if any, in its base operating costs no sooner than the commencement of the first year and then no more often than annually thereafter during the initial 2 year term of the CONTRACT extension. The Operating Rate shall be adjusted to a “Market Rate” at the commencement of year 3 of the CONTRACT extension (i.e., on September 18, 2007) and then at the beginning of every 3 months thereafter, until the end of the term of the CONTRACT. The Market Rate for the 3 month period shall be the average of the actual contracted dayrates, excluding incentive components, then being earned by all Transocean DP 5 generation rigs, including escalations per the contracts, in the US Gulf of Mexico (USGOM) as calculated on the last Friday prior to the commencement of the 3 month period (subject to 3 party audit). Current Transocean DP 5 generation rigs in the USGOM are:

1

th

th

th

rd

th

1. DISCOVERER ENTERPRISE* 2. DISCOVERER SPIRIT 3. DISCOVERER DEEP SEAS 4. DEEPWATER MILLENNIUM 5. CAJUN EXPRESS

Other DP 5 generation rigs that are to be included in the calculation of the Market Rate if they are then drilling in the USGOM are the following:

DEEPWATER PATHFINDER DEEPWATER FRONTIER SEDCO ENERGY SEDCO EXPRESS DEEPWATER EXPEDITION DEEPWATER DISCOVERY

• Idle rigs or idle time shall not be counted in the Market Rate calculation unless the idle rig is under contract in the GOM for a

contract to begin within the 3 month period covered by the rate calculation. Then the Operating Rate of that contract shall be used. A zero rate shall never be used.

• A rig under USGOM contract which is nevertheless idle for the convenience of the Operator or otherwise shall be included in the

rate calculation using the Operating Rate of that contract. • Transocean rigs contracted in the USGOM but which are outside the USGOM for a period of time shall be counted in the average

using their GOM dayrate. • If there are fewer than 4 Transocean Rigs in the average calculation, then the following rigs will be added (when contracted to

COMPANY in the USGOM), in the order listed, to bring the total up to 4 rigs for the calculation***:

a. DEVELOPMENT DRILLER II** b. DEVELOPMENT DRILLER I c. GSF JACK RYAN d. GSF C.R. LUIGS e. OCEAN CONFIDENCE (outfitted to 10,000’)***

• If there are fewer than 4 rigs using the COMPANY contracted rigs on the list above, then the average shall be calculated using 3

rigs.

• If there are fewer than 3 rigs in the pool for calculating the average, the dayrate shall stay at the last calculated rate until the pool increases to at least 3 rigs. COMPANY shall have the right to terminate the CONTRACT by giving 90 days written notice if there are fewer than three rigs in the pool for one continuous year from the first time there were fewer than 3 rigs available for the pool for the average calculation.

*The DISCOVERER ENTERPRISE dayrate shall not be included in the average until it concludes its current contract with COMPANY.

**The DEVELOPMENT DRILLER II dayrate shall not be included in the average until it concludes its initial three (3) year term contract with COMPANY. The Development Driller II shall continue to be excluded from the calculations if any exercised option(s) after the initial three (3) year term limits or caps the dayrate paid during the option period. However, any exercised option period(s) after the initial three (3) year term in which the dayrates are obtained by mutual agreement based on current market rates shall be included in the Market Rate calculation.

*** If COMPANY reimburses Diamond Offshore Company for the 10,000’ upgrade on a “lump sum” basis, then the lump sum paid for the upgrade will be divided out over the firm term of the contract to arrive at a daily sum to be added to the Operating Rate for purposes of calculating the Market Rate. If the Ocean Confidence’s

2

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rate (on any day the average calculation is made) is set by a stipulated or limited rate in an option attached to its current contract, then its rate shall not be included in the average calculation.

Upon reasonable notification, any given Market Rate calculation shall be subject to audit by third party auditors contracted by COMPANY. Errors in any given Market Rate calculation inconsistent with the above shall be adjusted promptly following the issuance of the relevant audit report.

4. Article 27.1, TERMINATION BY COMPANY shall be revised as follows:

Article 27.1.1 which contains provisions for “termination for convenience” shall be deleted in its entirety. 5. A new Item 1.42 shall be added under Category I, Furnished by CONTRACTOR, paid by CONTRACTOR to EXHIBIT B-3,

MATERIAL, SUPPLIES AND SERVICES as follows:

1.42 CONTRACTOR shall provide up to an additional 2,000’ of Vetco type “F” or “H” riser for the DEEPWATER HORIZON upon at least six month’s written notice from COMPANY. The additional riser must be available by a mutually agreed date, provided such date shall not be later than September 17, 2007. CONTRACTOR shall have the right to use the riser on other rigs when not in use on the Horizon so long as it is available to COMPANY upon six months written notice as stated above.

Except as changed by this Amendment No. 24, the CONTRACT as previously amended shall remain in full force and effect.

IN WITNESS WHEREOF, the authorized representatives of the parties hereto have executed this Amendment No. 24 in duplicate originals as of the day and year first above written.

3

BP America Production Company COMPANY By: /s/ David G. Eyton

David G. Eyton


Transocean Holdings, Inc.

CONTRACTOR

By: /s/ Christopher S. Young


Printed Name

Title: Sr. MKTG. Rep.

June 7, 2005 Transocean Holdings, Inc. 1311 Broadfield, Suite 400 Houston, Texas 77084

Dear Mr. Young, Enclosed for execution by Transocean Holdings, Inc. (“Transocean”) are two (2) originals of revised Work Order No. BPR-05-01127 under Drilling Contract No. 980249. This Work Order was revised to indicate that BP will reimburse Transocean for all work required for the provision of a Riser Tensioner Parking System on the “Deepwater Horizon” at actual documented costs plus the 5% handling fee. This revised Work Order supersedes and replaces the original Work Order that was previously sent to you. Therefore, please rescind and destroy the original Work Order dated May 27, 2005. Please have an authorized representative of Transocean sign both originals of the Work Order at the designated signature block and return one (1) original to the attention of M. Mike Jones at the following address:

BP America Production Company 501 WestLake Park Boulevard Houston, Texas 77079

If you have any questions concerning the above, please contact M. Mike Jones 281-366-7696. Best Regards,

Enclosures

BP America Production Company501 WestLake Park BoulevardHouston, Texas 77079

Attention: Mr. Chris Young Subject: Drilling Contract No. 980249

Work Order No. BPR-05-01127

Attention: Mr. M. Mike Jones

Mail Code 25.138, WL1

/s/ Belinda Erdelt

Belinda Erdelt

PSCM Manager — GoM Drilling and Wells

WORK ORDER

This Work Order is subject to the terms and conditions of Drilling Contract No. 980249 between BP America Production Company (“COMPANY”) and Transocean Holdings, Inc. (“CONTRACTOR”), made and effective the 9 day of December, 1998. EXCEPT AS EXPRESSLY PROVIDED HEREIN, NOTHING CONTAINED IN THIS WORK ORDER SHALL BE CONSTRUED AS AN AMENDMENT TO THE TERMS OF THE REFERENCED CONTRACT.

Description/Scope of Work/Additional Terms and Conditions: Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of these guidelines, the separate written agreement will hereinafter be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT. Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain personnel, equipment and materials to perform the services described herein below as required for supporting COMPANY’s drilling operations in the Gulf of Mexico. The scope of work includes the provision of a Riser Tensioner Parking System on the Drilling Unit “Deepwater Horizon.” CONTRACTOR will furnish the materials and perform the labor necessary for fabrication of the said System as per Drawing No. O-IP 1000, Sheets 1 through 3, which are attached hereto and made a part of this Work Order. Also attached to this Work Order are four (4) photographs which show the prescribed location where the System is to be installed on the Drilling Unit. COMPANY shall reimburse CONTRACTOR for all actual documented costs as specified herein plus a 5% handling fee. A breakdown of the costs comprising the Estimated Value of Work Order is as follows:

1

Date: June 7, 2005

Work Order requested by:

George Coltrin

CONTRACTOR:

Transocean Holdings, Inc.1311 Broadfield, Suite 400 Houston, Texas 77084

Work Order No.:

BPR-05-01127 SAP Code:

X2-000P7:RIGUPGRADE Paykey No.:

ZNAXO4UPGR Project Identification:

Transocean “Deepwater Horizon” Upgrades/Modifications, including:

Riser Tensioner Parking System Estimated Value of Work Order:

Not to Exceed $60,000 Expected Start Date:

June 1, 2005 Expected Completion Date:

June 14, 2005

Description Estimated Costs

Labor and Materials to Fabricate $ 24,042

Sandblast and Paint 3,608

Installation on Drilling Unit (includes Labor and Equipment) 26,520

Survey Charge 1,080

Subtotal $ 55,250

Handling Fee @ 5% 2,763

TOTAL ESTIMATED VALUE $ 58,013

or, say, $ 60,000

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Note: CONTRACTOR expects that a few miscellaneous charges will be incurred during performance of the Work. In such event, all miscellaneous charges shall be billed to COMPANY at actual documented cost plus the 5% handling fee. Therefore, for the purpose of preparing this Work Order, the TOTAL costs derived above have been rounded-off to the amount shown.

In addition to the costs identified above, COMPANY and CONTRACTOR agree to share payment of the Dayrate for the Drilling Unit on a 50/50 basis for the first fourteen (14) days of the Work. After fourteen (14) days, CONTRACTOR shall bear all costs of the Drilling Unit.

For Example: If the Work takes 10 days ... COMPANY pays for 5 days of rig time. If the Work takes 14 days ... COMPANY pays for 7 days of rig time. After 14 days, CONTRACTOR pays for all rig time. Thus, COMPANY’s maximum exposure to paying for rig time is 7 days.

Payment of the Dayrate for the Drilling Unit shall also be rotated between the parties on a day-by-day basis. In other words, COMPANY will pay for the first day, CONTRACTOR will pay for the second day, COMPANY will pay for the third day, and so forth. The Estimated Value of Work Order set forth in the heading of this document is based only on the Work as presently defined. CONTRACTOR agrees to keep COMPANY informed on the progress of the Work and to notify COMPANY if the Estimated Value of the Work Order exceeds the specified amount. All of the Work shall be performed in accordance with the terms and conditions of this Work Order and the CONTRACT. Any terms and conditions appearing in other documents furnished by CONTRACTOR shall be of no effect except to confirm the type and quantity of personnel, equipment, materials and whatever else is to be furnished by CONTRACTOR.

2

Forward invoices/statements to:

BP America Production CompanyAttention: Scanning Dept. S646 P.O. Box 22024 Tulsa, OK 74121-2024 Work Order No.: BPR-05-01127 SAP Code: X2-000P7:RIGUPGRADE Paykey No.: ZNAX04UPGR

ACCEPTED BY: /s/ Christopher S. Young

APPROVED BY: /s/ Belinda Erdelt

CONTRACTOR

COMPANY


Belinda Erdelt

Printed Name

Printed Name

Date: 6/13/05

Date: 7-June-05

Notices: Transocean Holdings, Inc. 1311 Broadfield, Suite 400 Houston, Texas 77084 Attention: Chris Young Phone: 832-587-8506 Fax: 832-587-8754 E-Mail: [email protected]

BP America Production Company501 Westlake Park Boulevard Houston, Texas 77079 Attention: Belinda Erdelt Mail Code: 25.136, WL1 Phone: 281-366-7334 Fax: 281-366-4697 E-Mail: [email protected]


Dear Mr. Young, Enclosed for execution by Transocean Holdings, Inc. (“Transocean”) are two (2) originals of revised Work Order No. BPR-05-01120 under Drilling Contract No. 980249. This Work Order was revised to indicate that the cost of welding provided by Transocean for the Fingerboard Upgrade on the “Deepwater Horizon” will be paid separately at actual documented costs plus the 5% handling fee. This revised Work Order supersedes and replaces the original Work Order that was previously sent to you. Therefore, please rescind and destroy the original Work Order dated June 2, 2005. Please have an authorized representative of Transocean sign both originals of the Work Order at the designated signature block and return one (1) original to the attention of M. Mike Jones at the following address:


If you have any questions concerning the above, please contact M. Mike Jones 281-366-7696. Best regards,

Enclosures

BP America Production Company501 WestLake Park Boulevard Houston, Texas 77079


Revised Work Order No. BPR-05-01120



/s/ Belinda Erdelt Belinda Erdelt


WORK ORDER


Description/Scope of Work/Additional Terms and Conditions: Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of these guidelines, the separate written agreement will hereinafter be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT. Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain personnel, equipment and materials to perform the services described herein below as required for supporting COMPANY’s drilling operations on the Kaskida KC 229 #1 Project. The scope of work involves the Fingerboard Upgrade on the Drilling Unit “Deepwater Horizon.” CONTRACTOR will increase the fingerboard on the Drilling Unit by 5 rows in accordance with Varco Quotation No. 27469 Rev 6, dated 08-Feb-05, which is made a part of this Work Order by reference only. This will increase the racking ability by approximately 8,500 ft. The upgrade will benefit COMPANY in several ways as it will allow CONTRACTOR to rack more pipe plus help the Drilling Unit in derrick management of different strings. The

1

Date: June 7, 2005


George Coltrin

CONTRACTOR:

Transocean Holdings, Inc. 1311 Broadfield, Suite 400 Houston, Texas 77084

Work Order No.:


X2-000M6-C:PRSPUD Paykey No.:

ZNAX04KIDA Project Identification:

Kaskida Prospect Exploration Well OCS-G-25792, Keathley Canyon Blk. 292 #1 Fingerboard Upgrade — Deepwater Horizon

Estimated Value of Work Order:

For the Work Actual Documented Cost plus 5% Handling Fee to be $230,659

Hoses, Bolts, Nuts, Etc. Actual Documented Cost plus 5% Handling Fee (per Note 1 on Page 2)

Travel Expenses Actual Documented Cost plus 5% Handling Fee (per Note 2 on Page 2)

Welding by CONTRACTOR Actual Documented Cost plus 5% Handling Fee (per Note 3 on Page 2)

Expected Start Date:

February 1, 2005 Expected Completion Date:

September 1, 2005

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upgrade will also free up casing fingers on the deep wells that CONTRACTOR will drill. Other features of the fingerboard upgrade include, but are not necessarily limited to, the following: • System will provide individual, heavy duty (extended) latches for each stand of pipe. • Latches are sequenced open and closed by an electronic/pneumatic controller mounted in control manifold enclosures at

fingerboard level. • Fingerboard utilizes (IEC/CENELEC) Ex electrical components and is constructed to IEC standards for marine applications. • All hazardous area equipment is certified for Zone 1. • All exterior mounted safe area equipment is designed for marine application. • All hardware is rated for IP 56 min and -20°C to 45°C. • Existing control system will be upgraded to include all necessary pneumatic/hydraulic controls, electrical and communication

hardware. • System is equipped with a Control Tower that includes an all electronic/pneumatic discreet controller mounted in a control

manifold enclosure at fingerboard level. • Engineering of System will include software upgrade for 2 PRS/Fingerboard interfaces to include interfacing with the Hitech

Cyberbase control system. COMPANY shall reimburse CONTRACTOR for all actual documented costs as specified herein plus a 5% handling fee. A breakdown of the costs comprising the Estimated Value of Work Order is as follows:

*Note 1: Not included with installation are all necessary hoses, bolts, nuts and fittings for interfacing with CONTRACTOR supplied Derrick/Mast Fingerboard mounting structure and derrick piping. Therefore, the cost of all such items shall be separately billed to COMPANY and charged at actual documented costs plus the 5% handling fee.

*Note 2: If a Varco Service Engineer is required for installation, then Travel Expenses for the Engineer shall be

separately billed to COMPANY and charged at actual documented costs plus the 5% handling fee. Note 3: In addition to the Work delineated in the Varco Quotation, it is estimated that some welding will be required

by CONTRACTOR. Therefore, the cost of all welding by CONTRACTOR shall be separately billed to COMPANY and charged at actual documented costs plus the 5% handling fee.

The Value of Work Order set forth in the heading of this document is based only on the Work as presently defined. CONTRACTOR agrees to keep COMPANY informed on the progress of the Work and to notify COMPANY if the Value of the Work Order exceeds the specified amount.

All of the Work shall be performed in accordance with the terms and conditions of this Work Order and the CONTRACT. Any terms and conditions appearing in other documents furnished by CONTRACTOR shall be of no

2

Description

Costs

Cost of Varco Quotation No. 27469 Rev 6:

Fingerboard

$ 165,111

Tower, Control, Fingerboard

38,564

Engineering and *Installation 16,000

Subtotal

$ 219,675

Handling Fee @ 5%

10,984

TOTAL ESTIMATED VALUE

$ 230,659

effect except to confirm the type and quantity of personnel, equipment, materials and whatever else is to be furnished by CONTRACTOR.

3


BP America Production Company Attention: Scanning Dept. S646 P.O. Box 22024 Tulsa, OK 74121-2024

Work Order No.: BPR-05-01120

SAP Code: X2-000M6-C:PRSPUD

Paykey No.: ZNAX04KIDA



CONTRACTOR

COMPANY


Belinda Erdelt

Printed Name

Printed Name

Date: 6/13/05

Date: 7-June-05

Notices: Transocean Holdings, Inc. 1311 Broadfield, Suite 400 Houston, Texas 77084

BP America Production Company 501 Westlake Park Boulevard Houston, Texas 77079

Attention: Chris Young

Attention: Belinda Erdelt

Phone: 832-587-8506

Mail Code: 25.136, WL1

Fax: 832-587-8754

Phone: 281-366-7334

E-Mail: [email protected]

Fax: 281-366-4697



Dear Mr. Young, Enclosed for execution by Transocean Holdings, Inc. (“Transocean”) are two (2) originals of revised Work Order No. BPR-05-01102 under Drilling Contract No. 980249. This Work Order was revised to indicate that BP will reimburse Transocean for all work required for the Removal of Pelican Hooks on the “Deepwater Horizon” at actual documented costs plus the 5% handling fee. This revised Work Order supersedes and replaces the original Work Order that was previously sent to you. Therefore, please rescind and destroy the original Work Order dated May 25, 2005. Please have an authorized representative of Transocean sign both originals of the Work Order at the designated signature block and return one (1) original to the attention of M. Mike Jones at the following address:


If you have any questions concerning the above, please contact M. Mike Jones 281-366-7696. Best regards,

Enclosures

BP America Production Company501 WestLake Park Boulevard Houston, Texas 77079


Work Order No. BPR-05-01102



/s/ Belinda Erdelt Belinda Erdelt


WORK ORDER


Description/Scope of Work/Additional Terms and Conditions: Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of these guidelines, the separate written agreement will hereinafter be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT. Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain personnel, equipment and materials to perform the services described herein below as required for supporting COMPANY’s drilling operations on the Blues Image Project, OCS-G-16625, Mississippi Canyon Block 587 Well No. 1, Plug and Abandonment. The scope of work involves the Removal of Pelican Hooks on the Drilling Unit “Deepwater Horizon.” A description of work requirements, schedule and estimated costs based upon installation of the Pelican Hooks is set forth in the INTERMOOR letter, dated May 9, 2005, which is attached hereto and made a part of this Work Order. The estimated cost for the Work described in the said letter is $422,560 but, it is important to point out that such amount does not include the cost of the vessel charter. All costs for the vessel charter are set forth in the INTERMOOR letter, dated May 18, 2005, which is also attached hereto and made a part of this Work Order. Charges for the vessel shall be $8,650 per day during actual performance of the Work, which is inclusive of mobilization and demobilization of the vessel, plus expenses for fuel, lube and commissaries that will be at actual documented costs. INTERMOOR will require a three (3) day minimum notice to secure the vessel prior to its need. It is tentatively planned that the vessel will be used for sixteen (16) days.

1

Date: June 7, 2005


George Coltrin

CONTRACTOR:


Work Order No.:


X2-000H5-E: MOORING Paykey No.:

ZNAX04BLUE Project Identification:

Blues Image Prospect, MC587#1 — P&A

OCS-G-16625

Removal of Pelican Hooks Estimated Value of Work Order:

Not to Exceed $600,000 Expected Start Date:

May 11, 2005 Expected Completion Date:

June 18, 2005

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COMPANY shall reimburse CONTRACTOR for all actual documented costs as specified herein plus a 5% handling fee. A breakdown of the costs comprising the Estimated Value of Work Order is as follows:

* Note: Fuel, Lube and Commissaries will be provided at actual documented costs plus 5%. However, for the purpose of preparing this Work Order, it is estimated that the cost of all such items will be $600/Day.

The Estimated Value of Work Order set forth in the heading of this document is based only on the Work as presently defined. CONTRACTOR agrees to keep COMPANY informed on the progress of the Work and to notify COMPANY if the Estimated Value of the Work Order exceeds the specified amount. All of the Work shall be performed in accordance with the terms and conditions of this Work Order and the CONTRACT. Any terms and conditions appearing in other documents furnished by CONTRACTOR shall be of no effect except to confirm the type and quantity of personnel, equipment, materials and whatever else is to be furnished by CONTRACTOR.

2

Description Estimated Costs

Cost of the Work (except for Vessel Charter)

$ 422,560

Cost of Vessel Charter (16 Days @ $8,650/Day)

138,400

* Cost of Fuel, Lube and Commissaries (16 Days @ $600/Day) 9,600

Subtotal $ 570,560

Handling Fee @ 5%

28,528

TOTAL ESTIMATED VALUE

$ 599,088

or, say,

$ 600,000


BP America Production Company Attention: Scanning Dept. S646 P.O. Box 22024 Tulsa, OK 74121-2024

Work Order No.: BPR-05-0l102

SAP Code: X2-000H5-E:MOORING

Paykey No.: ZNAX04BLUE



CONTRACTOR

COMPANY


Belinda Erdelt

Printed Name

Printed Name

Date: 13-June-2005

Date: 7-June-05

Notices: Transocean Holdings, Inc. 1311 Broadfield, Suite 400 Houston, Texas 77084

BP America Production Company 501 Westlake Park Boulevard Houston, Texas 77079

Attention: Chris Young


Phone: 832-587-8506

Mail Code: 25.136, WL1

Fax: 832-587-8754

Phone: 281-366-7334


Fax: 281-366-4697


Via Email: [email protected] Subject: Deepwater Horizon — Pelican Hook Removal LA Bid No. 05-05-002 Dear Ms. Holst:

As per our conversation, following you will find a description of work requirements, schedule and estimated cost based upon the installation of the Pelican Hooks on the Deepwater Horizon.

The cantilever work platforms and appurtenances for the spider baskets will have to be fabricated. Upon completion of

fabrication a vessel will need to be chartered to carry the equipment and crew from our Amelia facility to the Deepwater Horizon. The vessel will need to be offloaded to the Deepwater Horizon and the equipment will need to be staged at the appropriate location for the removal of the hooks. The rig will need to be deballasted to the point that the pontoons are near the surface. The hooks will be removed by means of arc gouging, and the area will be inspected using magnetic particle for any defects and/or cracks and repair if necessary. The area will be buffed and coated to the Transocean coating specifications. Any other inspection requirements by Transocean will be supplied by Transocean.

The above will apply until all hooks have been removed and all inspections and coatings have been completed. Also, there will be a need to remove some of the handrails and stairs to accommodate the cantilever platforms. Any items

removed will be reinstalled to its correct location and condition. Additional appurtenances above the hooks and at the deck level will need to be removed and will be done with the same

process as above. Accommodations for the crew will be supplied by the vessel standing by. Meals for the personnel will need to be supplied by

the rig. You will see a listing of the personnel on the following cost breakdown. The total will be two (2) crews, to work rotating twelve (12) hour shifts comprised of 34 total people.

Upon completion of the job, all areas will be cleaned and all equipment and appurtenances will be loaded on the vessel and

returned to InterMoor Inc.’s Amelia Facility. As you will see on the following schedule of work, in order for the work to be completed in the prescribed time frame, we

will need to begin preparations for fabrication as soon as possible, ideally May 11 .

May 9, 2005

InterMoor Inc.382 DeGravelle Road P.O. Box 1599 Amelia, Louisiana 70340

Ms. Katy Hoist T: 985.385.3083Transocean Offshore Deepwater Drilling

TF: 800.451.81061311 Broadfield Blvd. Suite 400

F: 985.631.2015Houston, TX 77084

E: [email protected]

W: www.intermoor.com

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InterMoor Inc. thanks you for the opportunity to quote on your Deepwater Horizon job needs. If you have any questions

regarding this matter, or if I can be of further assistance, please feel free to contact me at the above numbers or email me at [email protected].

Thank you, Chuck Minton President InterMoor Inc. Enclosures: Cost Breakdown

Schedule of Work

CM/ca

Total* Estimated Cost of the Project $ 422,560.00

*This total does not include the cost of the vessel charter.

Description Qty.

Unit Cost

Estimated Total CostBased on 12 Day

Operation

Fabrication Cantilever Platforms 2

$31,500.00 Ea. $63,000.00

Rental Equipment 1 Lot

$6,000.00 Day $72,000.00

Project Superintendent 1

$1,800.00 Day $21,600.00

Crew Superintendent 2 $1,440.00 Day Ea.

$17,280.00Offshore Fitter/Welders

12

$780.00 Day Ea. $112,320.00

Welder Helpers 8 $480.00 Day Ea.

$46,080.00Fire Watch Persons

8

$480.00 Day Ea. $46,080.00

Inspector Level II 1

$660.00 Day $7,920.00

Safety Coordinator 2

$720.00 Day Ea. $17,280.00

Vessel Charter 1

Availability Rates Availability Rates

Vessel Mobe and De-Mobe 1 $19,000.00

$19,000.00

Subject: Supply Vessel for Horizon Project LA Bid No. 05-05-011

Dear Ms. Holst:

InterMoor Inc. is pleased to provide at quote per your request on one (1) Supply Vessel to assist in the removal of the Pelican Hooks from the Horizon as follows:

1. 185’ Supply Vessel $8,650.00 per day

Note: This price does not include fuel, lube and commissaries.

2. Qualifications: • Above quote is based on price and availability of vessel. • InterMoor Inc. will require a three (3) day minimum notice to secure the vessel prior to the start/need for the vessel. • This quote is good for thirty (30) days from the date of this letter.

InterMoor Inc. thanks you for the opportunity to quote on the above. If you have any questions regarding this matter or if I can be of further assistance, please feel free to contact me at the above numbers or email at [email protected].

Thank you, Anthony ‘TP’ Palmature Operations InterMoor Inc. Cc: J. Keaton

InterMoor Inc.

382 DeGravelle Road

P.O. Box 1599

Amelia, Louisiana 70340

May 18, 2005

T: 985.385.3083

Katy Holst TF: 800.451.8106Transocean Offshore F: 985.631.2015Houston, TX E: [email protected]: 832-587-8902 W: www.intermoor.comVia Email: [email protected]

WORK ORDER

This Work Order is subject to the terms and conditions of Drilling Contract No. 980249 between BP America Production Company (“COMPANY”) and Transocean Holdings, Inc. (“CONTRACTOR”), made and effective the 9 day of December, 1998, as amended. EXCEPT AS EXPRESSLY PROVIDED HEREIN, NOTHING CONTAINED IN THIS WORK ORDER SHALL BE CONSTRUED AS AN AMENDMENT TO THE TERMS OF THE REFERENCED CONTRACT.

Description/Scope of Work/Additional Terms and Conditions: Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of this, the separate written agreement will be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT. Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain additional equipment and materials described herein below as required for supporting COMPANY’s drilling operations on the Bonsai Well located in the Gulf of Mexico. The Work Order includes the provision of Additional Drill Pipe for the Drilling Unit “Deepwater Horizon”. An additional 1,000’ (23 joints) of 6-5/8” premium grade drill pipe will be furnished by CONTRACTOR in accordance with the following technical specifications:

6 5/8” X 40.5# .625 WALL, 5.375”ID., 95% WALL, RIII S-135 (44.5 +/- 6”) W/6 5/8”FH API + 4” LTS (12 PIN X 14” BOX) (8 1/2” OD X 4 1/4” ID ) TOOL JOINT TK34 INTERNAL PLASTIC COATING, ARMACOR M HARDBANDING APPLIED 3/32” PROUD ON 3” OF BOX OD BEGINING 1/4” TO 3/8” ABOVE ELEVATOR SHOULDER

COMPANY shall pay CONTRACTOR a “Fee” which shall hereinafter be defined as $500/day for the drill pipe. The drill pipe will be required for the duration of the Bonsai Well which is expected to last for a four (4) month time period. Thus, the Estimated Value of Work Order is calculated as follows:

($500/day) (4 months) (30 days/month) = $60,000 1

Date: June 17, 2005 Work Order requested by: George Coltrin

CONTRACTOR: Transocean Holdings, Inc.

1311 Broadfield, Suite 400

Houston, Texas 77084 Work Order No.: BPR-05-01560 Paykey No.: ZNAX04BONS Project Identification: Bonsai Well

Additional Drill Pipe Estimated Value of Work Order: $60,000 Expected Start Date: June 17, 2005 Expected Completion Date: October 17, 2005

th

The Estimated Value of this Work Order as set forth in the heading of this document is based only on the Work as presently defined. If the duration of the Bonsai Well should exceed the estimated four (4) month time period, then COMPANY will provide an extension to this Work Order in the form of a “Change Order.” Regardless of the duration of the Bonsai Well the agreed Fee will be paid until the drill pipe is returned and offloaded at COMPANY’s shore base facility. The Fee shall commence at 00:00 on June 17, 2005, and shall end after the drill pipe has been returned and offloaded at COMPANY’s shore base facility at Fourchon, Louisiana. COMPANY shall also reimburse CONTRACTOR for all costs associated to re-inspect the drill pipe to DS1 Level 5 standards and return to CONTRACTOR’s yard in Amelia, Louisiana, after the Bonsai Well is completed. All inspection, repair and transportation costs, including freight and handling charges associated with movement of the drill pipe, will be for COMPANY’s account regardless of the Estimated Value of Work Order noted hereinabove. The pricing information presented herein shall be firm and fixed for the duration of this Work Order and will serve as the basis of any subsequent price adjustments, if deemed necessary.

All of the Work shall be performed in accordance with the terms and conditions of this Work Order and the CONTRACT as amended.

2

Forward invoices/statements to: BP America Production Company

Attention: Scanning Dept. S646

P.O. Box 22024

Tulsa, OK 74121-2024


Paykey No.: ZNAX04BONS

ACCEPTED BY: /s/ W. Brad James


CONTRACTOR

COMPANY

Marketing Manager - North America

Belinda Erdelt

Printed Name

Printed Name

Date: 9/7/05

Date: 31 Aug 05 Notices: Transocean Holdings, Inc. BP America Production Company


200 Westlake Park Boulevard

Houston, Texas 77084


Attention: Brad James


Phone: 832-587-8537

Mail Code: 624A, WL4

Fax: 832-587-8754

Phone: 281-366-7334


Fax: 281-366-4697


Amendment No. 26


This Amendment No. 26 is entered into effective as of the 18 day of September, 2005, by and between BP America Production Company (hereinafter referred to as “COMPANY”) and Transocean Holdings, Inc. (hereinafter referred to as “CONTRACTOR”) with a place of business at 1311 Broadfield, Suite 400, Houston, Texas 77084.


WHEREAS, by Drilling Contract No. 980249 made and effective the 9 day of December, 1998, COMPANY and CONTRACTOR entered into that certain Contract for the “Deepwater Horizon” (hereinafter referred to as “CONTRACT”), as previously amended by twenty-three (23) letters of agreement/amendments and Amendments No. 24 and Letter of Agreement for Cost Escalation 2005 dated March 31, 2005 (sometimes also known as Amendment No. 25); and WHEREAS, COMPANY and CONTRACTOR desire to amend the CONTRACT in accordance with Article 2.3.2 of said CONTRACT, which Article has been amended per Contract Extension Agreement letter dated April 19, 2004, and subsequently amended per Amendment No. 24 to adjust the dayrates to reflect the change in costs for labor, catering, insurance, spare parts and supplies if the costs of any of the aforesaid items vary by three percent (3%) from the costs thereof. NOW THEREFORE, for and in consideration of the mutual covenants and agreements hereinafter provided, COMPANY and CONTRACTOR agree to amend the CONTRACT as follows: 1. EXHIBIT A, DAYRATES, shall be revised as follows to indicate a $2,526/day increase in the dayrates:

EXHIBIT A

DAYRATES


Note

The following documentation which supports all of the increases reflected above is attached hereto and made a part of this Amendment No. 26:

E-33

1

Operating Rate $277,526.00 per day Moving Rate $277,526.00 per day Standby Rate With Crews $277,526.00 per day Standby Rate Without Crews $277,526.00 per day less documented cost savings Stack Rate With Crews $277,526.00 per day less documented cost savings Stack Rate Without Crews $277,526.00 per day less documented cost savings Equipment Repair Rate $ -0- per day Hurricane Evacuation Rate Standby Rates Without Crews plus documented expenses of

evacuated crew

th

th

• BASIS FOR COST ESCALATIONS, DEEPWATER HORIZON, September 18, 2005 • DEEPWATER HORIZON, Adjusted Labor as of September 18, 2005 • U.S. Department of Labor, Bureau of Labor Statistics, Data extracted on: December 8, 2005, Producer Price Index -

Commodities, Series Id: WPU119102, Group: Machinery and equipment, Item: Oil field and gas field drilling machinery

• Transocean letter from Betsy Kelly, CPCU, ARe, Manager-Insurance, to Kim Schutts, Re: Annual Premiums, Deepwater Horizon

Except as changed by this Amendment No. 26, the CONTRACT as previously amended shall remain in full force and effect. IN WITNESS WHEREOF, the authorized representatives of the parties hereto have executed this Amendment No. 26 in duplicate originals as of the day and year first above written.

E-34

2


COMPANY

By: /s/ David R. Mottashed

David R. Mottashed

Printed Name

Title: PSCM Manager – Offshore GoM


CONTRACTOR

By: /s/ Anton Dibowitz

Anton Dibowitz

Printed Name

Title: Sr. Marketing Representative

5/15/06

BP Horizon – Escalation Sept. 2005 TSF File #01-063

BASIS FOR COST ESCALATIONS DEEPWATER HORIZON

September 18, 2005 $ Per Day

E-35

3

March 1, 2005Baseline Costs

September 18,2005 Baseline

Costs

Variance

AdjustedSept. 2005

Baseline Costs

Clause No.: 2.3.2a) Base Labor Cost:


$ 30,385

$ 33,168

$ 2,783

$ 33,168

Training & Transportation Costs $ 3,447 $ 2,327 $ -1,120 $ 2,327 Total Base Labor Cost $ 33,832 $ 35,495 $ 1,663 $ 35,495 Percentage Increase

5%



$ 2,101

$ 2,146

$ 45

$ 2,101

10 Company Personnel $ 305 $ 311 $ 6 $ 305 Total Base Catering Costs $ 2,406 $ 2,457 $ 51 $ 2,406 Percentage Increase

2%

2.3.2c) Base Maintenance Element: $ 16,030 $ 16,495 $ 465 $ 16,030

Total Base Matinenance Costs

$ 465

Percentage Increase

3%


Hull & Machinery $ 1,710 $ 2,555 $ 844 $ 2,555 Marine P&I

$ 2,257

$ 2,257

$ 0

$ 2,257

Excess Liability $ 464 $ 483 $ 19 $ 483 Brokers Fee

$ 110

$ 110

$ 0

$ 110

Oil Pollution

$ 26

$ 26

$ 0

$ 26

Total Base Insurance Cost:

$ 4,568

$ 5,431

$ 863

$ 5,431

Percentage Increase 19%

Total Baseline Operating Costs $ 56,836 $ 59,878 $ 2,526 $ 59,362

Total Dayrate Increase =

$ 2,526/day

DEEPWATER HORIZON

Adjusted Labor as of September 18, 2005


E-36

4

A

B C

D

GOM Base Labor GOM Overtime Rates

No. of Personnel

Daily Rate per Daily

Hourly

On Board

Assigned To Rig

JOB CLASSIFICATIONperson (inc.

TT&C)Total Daily on

Board Cost

OvertimeRates

OvertimeRates

1 2

OIM 995.17 923.15 878.96 73.25

3 6

Toolpusher

849.75

2,333.20 733.54

61.13

2 4

Driller 700.54 1,257.03 696.48 58.04

4 8

Assistant Driller

576.25

2,016.94 548.34

45.70

2 4

Derrickhand

502.47

860.91 460.40

38.37

2 4

Pumphand

461.44

778.84 411.49

34.29

8 16

Floorhand

414.26

2,896.81 389.73

32.48

1 2

Maintenance Supervisor 831.01 758.99 714.80 59.57

1 2


714.02

642.00 597.81

49.82

2 4

Chief Mechanic 645.30 1,146.56 630.64 52.55

2 4

Mechanic

576.25

1,008.47 548.34

45.70

1 2


461.44

389.42 411.49

34.29

2 4

Motor Operator

442.27

780.23 423.12

35.26

1 2


714.02

642.00 597.81

49.82

1 2


1 2

Electrician

576.25

504.23 548.34

45.70

1 2

Chief Electronic Technician 645.30 573.28 630.64 52.55

1 2

Electronic Technician

576.25

504.23 548.34

45.70

1 2


809.81

737.79 693.59

57.80

1 2

Subsea Supervisor

714.02

642.00 712.55

59.38

1 2

Master

916.59

844.57 800.37

66.70

1 2

Chief Mate 731.23 659.21 733.07 61.09

1 2

Bosun

521.02

449.00 482.51

40.21

3 6

AB Seaman 451.35 1,197.57 433.93 36.16

2 4

DP Operator

603.87

1,063.70 581.26

48.44

2 4


523.78

903.52 485.80

40.48

3 6

Crane Operator

521.02

1,346.99 482.51

40.21

1 2

Deck Pusher

543.28

491.12 543.51

45.29

2 4

Lead Roustabouts

382.30

660.29 351.64

29.30

9 18

Roustabouts

382.30

2,971.29 351.64

29.30

1 2

Welder 502.47 430.45 460.40 38.37

1 2


576.25

504.23 460.04

38.34

1 2

Material Coordinator

493.40

421.38 449.59

37.47

1 2

Medic

493.40

421.38 449.59

37.47

1 2

Radio Operator

438.16

366.14 383.75

31.98

1 2

RSTC

539.56

467.54 504.61

42.05

0 0

—

—

— —

—

0 0

— — — — —

0 0

—

—

— —

—

0 0

—

—

— —

—

69 138

Total Labor Costs =

$ 33,167.73


Data extracted on: December 8, 2005 (11:24:10 AM) Producer Price Index-Commodities



01-063NAR - Horizon Escalation Mar-Sept 2005.doc

E-37 5


U.S. Department of labor Bureau of Labor Statistics Bureau of Labor Statistics Data

www.bls.gov

Search | A-Z Index

Change Output From: 1995 To: 2005 GOOptions:

include graphs NEW! More Formatting Options

Series Id: WPU119102 Not Seasonally Adjusted Group: Machinery and equipment Item: Oil field and gas field drilling machineryBase Date: 8200

year Jan

Feb Mar


Nov Dec Annual1995

118.3 118.6

119.2 119.2

119.3 119.6 120.4 120.4 120.4 122.0 122.2 122.2 120.1

1996 124.0

124.0 124.0

124.3 124.2

124.8

125.3

125.3

125.3

126.2 126.6

127.1

125.1

1997 127.7

127.9 128.6

129.1 129.2 129.3 129.3 129.5 129.7 130 3

131.4 132.0 129.51998

133.1 132.9

133.1 133.0

133.0

133.0

132.9

132.9

132.9

133.6 133.6

133.6

133.1

1999 133.8

133.7 133.7

133.9 133.9

134.0

134.0

133.7

133.7

133.7 134.4

134.6

133.9

2000 134.9

136.3 136.3

136.3 136.5

136.5

136.5

136.6

136.7

138.7 138.7

138.7

136.92001

143.5 143.9

144.0 144.0

144.0

145.5

145.6

145.8

145.7

146.1 146.1

146.1

145.0

2002 146.2

146.2 146.6

146.6 146.4 146.4 146.4 146.4 146.7 146.7

146.7 146.7 146.52003

149.8 149.8

149.8 151.7

152.3

152.5

152.5

152.5

153.1

153.1 153.1

153.5

152.0

2004 153.8

153.9 154.8

156.4 157.1 157.1 156.6 156.7 156.8 157.0

157.9 160.1 156.52005

162.0 163.7

169.0 169.8

171.3

172.0

172.9 (P) 172.9 (P) 173.9 (P) 174.1(P)

U.S. Bureau of Labor Statistics Phone: (202) 691-520Postal Square Building Fax-on-demand: (202) 691-63252 Massachusetts Ave., NE Data questions: [email protected], DC 20212-0001 Technical (web) questions: [email protected]


http://data.bls.gov/PDQ/servlet/SurveyOutputServlet:jessionid=f030b5b34d12$3Fx$3F$

12/8/2005


Deepwater Horizon These costs and limits reflect the coverage provided at this time and are subject to change upon renewal.

* Includes the War risk buyback – the deductible is $10,000,000 each occurrence with a one time $40,000,000 additional aggregate deductible.

** Based on SIR accrual of $ 16.36 per person per day assigned to the rig.

Best Regards, Signed electronically Betsy Kelly, CPCU, ARe Manager- Insurance

E-38

6

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC.

4 GREENWAY PLAZA

BETSY KELLY

MANAGER-INSURANCE HOUSTON, TX 77046

Effective May 1, 2005

Coverage: All Risk Hull & MachineryCarrier: various Underwriters @ Lloyds, led by Limit and Wellington

SyndicatesInsured Value: $ 360,000,000Deductible: $ 10,000,000NET ANNUAL PREMIUM: $ 932,292 Effective December 31, 2004 Coverage: Carrier: Self Insured Retention: DEDUCTIBLE ACCRUAL:

Primary Marine Protection & Indemnity various Underwriters @ Lloyds, led by $10,000,000 per occurrence $ 823,860

Effective May 1, 2005

Coverage: Excess LiabilityCarriers: various Underwriters @ Lloyds, led by Limit and Wellington

SyndicatesLimits: $500,000,000NET ANNUAL PREMIUM: $ 176,374 Effective October 1, 2004

Coverage: Oil PollutionCarrier: Surety coverage – backed by Underwriters @LloydsNET ANNUAL PREMIUM: $ 9,598 Effective December 31, 2004

U.S. Broker: McGriff, Seibels & Williams, Inc Annual Fee: $ 40,180


CHANGE ORDER

NOTHING CONTAINED IN THIS CHANGE ORDER SHALL BE CONSTRUED AS AN AMENDMENT TO THE TERMS OF THE REFERENCED CONTRACT.

1. DESCRIPTION OF CHANGE OF WORK:

Extend the term of Work Order No. BPR-05-01560 to November 30, 2005, to cover drilling operations that are still being performed by Transocean’s “Deepwater Horizon” on the Bonsai Well.

2. COMPENSATION:

Value of this Change Order No. 1 is $22,500. CONTRACTOR will continue to be compensated for provision of the additional drill pipe in accordance with the Fee of $500/day as specified in Work Order No. BPR-05-01560.

3. COMPLETION DATE:

Expected Completion Date for the Work will now be November 30, 2005.

CHANGE ORDER Number:

1WORK ORDER Number:

BPR-05-01560

CONTRACT Number:

980249Project Code/Identification (if applicable):

Bonsai Well

Additional Drill Pipe

Date:

October 10, 2005WORK ORDER requested by:

George Coltrin

(Name)

4. ORIGINAL WORK RELEASE VALUE

$ 60,000

VALUE OF APPROVED CHANGE ORDERS TO DATE

0

THIS CHANGE ORDER VALUE

$ 22,500

TOTAL CURRENT WORK RELEASE VALUE $ 82,500



/s/ Belinda Erdelt

13-OCT-05

/s/ W. Brad James

10/18/05COMPANY APPROVAL

DATE

CONTRACTOR ACCEPTANCE

DATE Belinda Erdelt

W. Brad James

Printed Name

Printed Name

PSCM Manager - GoM Drilling & Wells

Marketing Manager - North America District

Title

Title

WORK ORDER


Description/Scope of Work/Additional Terms and Conditions:

Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of this, the separate written agreement will be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT.

Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain additional equipment and materials described herein below as required for supporting COMPANY’s drilling operations on the Kaskida Well located in the Gulf of Mexico.

The Work Order includes the provision of Additional Drill Pipe for the Drilling Unit “Deepwater Horizon”. An additional 3,000’ (69 joints) of 6-5/8” premium grade drill pipe will be furnished by CONTRACTOR in accordance with the following technical specifications:

6 5/8” X 40.5# .625 WALL, 5.375”ID., 95% WALL, RIII S-135 (44.5 +/- 6”) W/6 5/8”FH API + 4” LTS (12 PIN X 14” BOX) (8 1/2” OD X 4 1/4” ID) TOOL JOINT TK34 INTERNAL PLASTIC COATING, ARMACOR M HARDBANDING APPLIED 3/32” PROUD ON 3” OF BOX OD BEGINING 1/4” TO 3/8” ABOVE ELEVATOR SHOULDER

COMPANY shall pay CONTRACTOR a “Fee” which shall hereinafter be defined as $1,500/day for the drill pipe. The drill pipe will be required for the duration of the Kaskida Well which is expected to last for a two hundred (200) day time period. Thus, the Estimated Value of Work Order is calculated as follows:

($1,500/day) (200 days) = $300,000 1

Date: December 13, 2005 Work Order requested by: George Coltrin



Houston, Texas 77084 Work Order No.: BPR-05-02811 Paykey No.: ZNAX04KIDA Project Identification: Kaskida Well

Additional Drill Pipe Estimated Value of Work Order: $300,000 Expected Start Date: January 1, 2006 Expected Completion Date: July 15, 2006

th

The Estimated Value of this Work Order as set forth in the heading of this document is based only on the Work as presently defined. If the duration of the Kaskida Well should exceed the estimated two hundred (200) day time period, then COMPANY will provide an extension to this Work Order in the form of a “Change Order.” Regardless of the duration of the Kaskida Well the agreed Fee will be paid until the drill pipe is returned and offloaded at COMPANY’s shore base facility.

The Fee shall commence at 00:00 on January 1, 2006, and shall end after the drill pipe has been returned and offloaded at COMPANY’s shore base facility at Fourchon, Louisiana.

COMPANY shall also reimburse CONTRACTOR for all costs associated to re-inspect the drill pipe to DS1 Level 5 standards and return to CONTRACTOR’s yard in Amelia, Louisiana, after the Kaskida Well is completed. All inspection, repair and transportation costs, including freight and handling charges associated with movement of the drill pipe, will be for COMPANY’s account regardless of the Estimated Value of Work Order noted hereinabove.

The pricing information presented herein shall be firm and fixed for the duration of this Work Order and will serve as the basis of any subsequent price adjustments, if deemed necessary.


2



P.O. Box 22024

Tulsa, OK 74121-2024


Paykey No.: ZNAX04KIDA

ACCEPTED BY: /s/ Anton Dibowitz


CONTRACTOR

COMPANY

Anton Dibowitz

Belinda Erdelt

Printed Name

Printed Name

Title: Sr. Marketing Representative

Title: PSCM Mgr – GoM Drilling & Wells

Date: 12/21/05

Date: 15-Dec-05 Notices:







Attention: Anton Dibowitz


Phone: 832-587-8500

Mail Code: 624A, WL4

Fax: 832-587-8754

Phone: 281-366-7334

Fax: 281-366-4697


WORK ORDER


Description/Scope of Work/Additional Terms and Conditions:

Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of this, the separate written agreement will be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT.

Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain additional equipment and materials described herein below as required for supporting COMPANY’s drilling operations on the Tamara Well located in the Gulf of Mexico.

The Work Order includes the provision of Additional Drill Pipe for the Drilling Unit “Deepwater Horizon”. An additional 3,000’ (69 joints) of 6-5/8” premium grade drill pipe will be furnished by CONTRACTOR in accordance with the following technical specifications:

6 5/8” X 40.5# .625 WALL, 5.375”ID., 95% WALL, RIII S-135 (44.5 +/- 6”) W/6 5/8”FH API + 4” LTS (12 PIN X 14” BOX) (8 1/2” OD X 4 1/4” ID) TOOL JOINT TK34 INTERNAL PLASTIC COATING, ARMACOR M HARDBANDING APPLIED 3/32” PROUD ON 3” OF BOX OD BEGINING 1/4” TO 3/8” ABOVE ELEVATOR SHOULDER

COMPANY shall pay CONTRACTOR a “Fee” which shall hereinafter be defined as $1,500/day for the drill pipe. The drill pipe will be required for the duration of the Tamara Well which is expected to last for a one hundred and fifty six (156) day time period. Thus, the Estimated Value of Work Order is calculated as follows:

($1,500/day) (156 days) = $234,000 1

Date: August 12, 2006 Work Order requested by: George Coltrin

CONTRACTOR: Transocean Holdings, Inc.1311 Broadfield, Suite 400


Work Order No.: BPR-06-02376 Paykey No.: ZNAXTAMARA Project Identification: Tamara Well

Additional Drill Pipe Estimated Value of Work Order: $234,000 Expected Start Date: August 12, 2006 Expected Completion Date: January 15, 2007

th

The Estimated Value of this Work Order as set forth in the heading of this document is based only on the Work as presently defined. If the duration of the Tamara Well should exceed the estimated one hundred and fifty six (156) day time period, then COMPANY will provide an extension to this Work Order in the form of a “Change Order.” Regardless of the duration of the Tamara Well the agreed Fee will be paid until the drill pipe is returned and offloaded at COMPANY’s shore base facility.

The Fee shall commence at 00:00 on August 12, 2006, and shall end after the drill pipe has been returned and offloaded at COMPANY’s shore base facility at Fourchon, Louisiana.

COMPANY shall also reimburse CONTRACTOR for all costs associated to re-inspect the drill pipe to DS1 Level 5 standards and return to CONTRACTOR’s yard in Amelia, Louisiana, after the Tamara Well is completed. All inspection, repair and transportation costs, including freight and handling charges associated with movement of the drill pipe, will be for COMPANY’s account regardless of the Estimated Value of Work Order noted hereinabove.

The pricing information presented herein shall be firm and fixed for the duration of this Work Order and will serve as the basis of any subsequent price adjustments, if deemed necessary.


2

Forward invoices/statements to: BP America Production CompanyAttention: Scanning Dept. S646

P.O. Box 22024

Tulsa, OK 74121-2024


Paykey No.: ZNAXTAMARA


APPROVED BY: /s/ Ben Steven Smith

CONTRACTOR

COMPANY

Anton Dibowitz

Ben Steven Smith

Printed Name

Printed Name

Title: Marketing Manager, North America

Title: Sr. PSCM Specialist, Drilling Rigs

Date: Date: 10/4/06

Notices: Transocean Holdings, Inc.

BP America Production Company 1311 Broadfield, Suite 400

200 Westlake Park Boulevard Houston, Texas 77084

Houston, Texas 77079 Attention: Anton Dibowitz

Attention: Steve Smith Phone: 832-587-8500

Mail Code: 646C, WL4 Fax: 832-587-8754

Phone: 281-366-2041

Fax: 281-366-7130


Amendment No. 27


This Amendment No. 27 is entered into effective as of the 18 day of September, 2006, by BP America Production Company (hereinafter referred to as “COMPANY”) with a place of business at 501 WestLake Park Boulevard, Houston, Texas 77079, and Transocean Holdings Inc. (hereinafter referred to as “CONTRACTOR”) with a place of business at 1311 Broadfield, Suite 400, Houston, Texas 77084.


WHEREAS, by Drilling Contract No. 980249 made and effective the 9 day of December, 1998, COMPANY and CONTRACTOR entered into that certain Contract for the “Deepwater Horizon” (hereinafter referred to as “CONTRACT”), as previously amended; and WHEREAS, COMPANY and CONTRACTOR desire to amend the CONTRACT as more particularly set forth herein; NOW THEREFORE, for and in consideration of the mutual covenants and agreements hereinafter provided, COMPANY and CONTRACTOR agree to amend the CONTRACT as follows: 1. EXHIBIT A, DAYRATES, shall be revised as follows to indicate a $14,175/day increase in the dayrates in accordance with

Article 2.3.2 of said CONTRACT, which Article has been amended per Contract Extension Agreement letter dated April 19, 2004, and subsequently amended per Amendment No. 24 to adjust the dayrates to reflect the change in costs for labor, catering, insurance, spare parts and supplies if the costs of any of the aforesaid items vary by three percent (3%) from the costs thereof.

EXHIBIT A DAYRATES


E-39

1

Operating Rate

$291,701.00 per day Moving Rate

$291,701.00 per day Standby Rate With Crews

$291,701.00 per day Standby Rate Without Crews

$291,701.00 per day less documented cost savings Stack Rate With Crews

$291,701.00 per day less documented cost savings Stack Rate Without Crews $291,701.00 per day less documented cost savings Equipment Repair Rate

$ -0- per day Hurricane Evacuation Rate

Standby Rates Without Crews plus documented expenses of evacuated crew

Additional Personnel (as described in Exhibit F-2, attached)

$650.00 per day

th

th

Note The following documentation which supports all of the increases reflected above is attached hereto and made a part of this Amendment No. 27: • BASIS FOR COST ESCALATIONS, DEEPWATER HORIZON, September 18, 2006 • DEEPWATER HORIZON, Exhibit F-l: Personnel to be Provided, Adjusted Labor as of September 18, 2006 • DEEPWATER HORIZON, Exhibit F-2: Additional Personnel to be Provided, Adjusted Labor as of September 18, 2006 • U.S. Department of Labor, Bureau of Labor Statistics, Data extracted on: October 24, 2006, Producer Price Index – Commodities,

Series Id: WPU119102, Group: Machinery and equipment, Item: Oil field and gas field drilling machinery • Transocean letter from Betsy Kelly, CPCU, ARe, Manager-Insurance, to Kim Schutts, Re: Annual Premiums, Deepwater Horizon• Memorandum dated April 11, 2006 regarding April 2006 Base Pay Compensation Adjustment • Letter between Transocean Holdings Inc. and Delta Catering Management LLC regarding catering adjustment. Except as changed by this Amendment No. 27 the CONTRACT as previously amended shall remain in full force and effect. IN WITNESS WHEREOF, the authorized representatives of the parties hereto have executed this Amendment No. 27 in duplicate originals as of the day and year first above written. BP AMERICA PRODUCTION COMPANY COMPANY

TRANSOCEAN HOLDINGS INC. CONTRACTOR

E-40

2

By:

/s/ Wilbert Long Jr. 1/16/08

Wilbert Long Jr.

Printed Name

Title:

Head of PSCM (GOM)

By: /s/ Terry Bonno

Terry Bonno

Printed Name

Title: Marketing Director, Americas Business Unit


DEEPWATER HORIZON September 18, 2006

$ Per Day

E-41

3

Sept. 18, 2005Baseline Costs

Sept. 18, 2006Baseline Costs

Variance

AdjustedSept. 2006

Baseline Costs

Clause No.:


$ 33,168

$ 35,110 $ 1,942

$ 35,110

Labor & Burden (per schedule) $ 828 $ 1,715 $ 887

$ 1,715 Training Costs

$ 1,499

$ 2,125 $ 626

$ 2,125

Transportation Costs

$ 35,495

$ 38,950 $ 3,455

$ 38,950

Total Base Labor Cost 10%

Percentage Increase



$ 2,101

$ 2,464 $ 363

$ 2,464


$ 305

$ 357 $ 52

$ 357


$ 2,406

$ 2,821 $ 415

$ 2,821


2.3.2c) Base Maintenance Element: $ 16,030 $ 18,241

$ 2,211 $ 18,241

Total Base Matinenance Costs $ 2,211

Percentage Increase

14%


Hull & Machinery

$ 2,555

$ 10,305 $ 7,750

$ 10,305

Marine P&I

$ 2,257

$ 1,916 $ -341

$ 1,916

Excess Liability

$ 483

$ 1,032 $ 549

$ 1,032

Brokers Fee $ 110 $ 244 $ 134

$ 244 Oil Pollution

$ 26

$ 29 $ 3

$ 29

Total Base Insurance Cost:

$ 5,431

$ 13,525 $ 8,094

$ 13,525


Total Baseline Operating Costs $ 59,362 $ 73,537

$ 14,175 $ 73,537

Total Dayrate Increase = $ 14,175/day

ADDITIONAL PERSONNEL

Labor & Burden (addtl personnel)

$ 432

$ 519 $ 87

$ 519

Training & Transportation Costs (addtl

personnel)

$ 29

$ 67

$ 38

$ 67

Catering (Additional Personnel)

$ 30

$ 36 $ 6

$ 36

Insurance: Marine P&I

$ 0

$ 28 $ 28

$ 28

Total Additional Personnel Cost:

$ 491

$ 650 $ 159

$ 650

Percentage Increase 32.4%

Total Additional Personnel Increase =

$ 159/day

Exhibit F-1: Personnel to be Provided

DEEPWATER HORIZON Adjusted Labor as of September 18, 2006

The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short. This includes all Training, Transportation, Catering and Marine P&I costs. The figures in column “B” are the daily cost of all crew members excluding Training, Transportation, Catering and Marine P&I costs. The figures in column “C” are the daily cost of overtime excluding Training, Transportation, Catering and Marine P&I costs (assuming a daily schedule of 12 hours) The figures in column “D” are the hourly cost of overtime excluding Training, Transportation, Catering and Marine P&I costs.

E-42

4

A

B C

D


No. of Personnel

Daily Rate per Daily

Hourly

On Assigned

person (inc.

Total Daily on

Overtime

Overtime

Board To Rig

JOB CLASSIFICATION

TT&C & P&I)

Board Cost Rates

Rates

1 2

OIM 1,107.22 976.51 926.20 77.18

3 6

Toolpusher

951.44

2,462.20 770.42

64.20

2 4

Driller

794.54

1,327.66 731.28

60.94

4 8

Assistant Driller

664.34

2,134.52 576.09

48.01

2 4

Derrickhand

586.61

911.81 483.45

40.29

2 4

Pumphand 510.98 827.18 443.81 36.98

8 16

Floorhand

481.79

3,075.16 409.01

34.08

1 2

Maintenance Supervisor 931.47 800.76 750.45 62.54

1 2


808.69

677.98 627.67

52.31

2 4

Chief Mechanic

736.54

1,211.66 662.15

55.18

2 4

Mechanic

664.34

1,067.26 576.09

48.01

1 2


543.61

412.90 432.19

36.02

2 4

Motor Operator 543.61 825.80 432.19 36.02

1 2


808.69

677.98 627.67

52.31

1 2


1 2

Electrician

664.34

533.63 576.09

48.01

1 2


736.54

605.83 662.15

55.18

1 2


664.34

533.63 576.09

48.01

1 2


909.34

778.63 868.12

72.34

1 2

Subsea Supervisor 808.69 677.98 748.15 62.35

1 2

Master

1,021.54

890.82 840.52

70.04

1 2

Chief Mate 827.02 696.31 770.00 64.17

1 2

Bosun

606.34

475.63 506.96

42.25

3 6

AB Seaman

520.45

1,269.18 455.10

37.92

2 4

DP Operator

693.14

1,124.86 610.42

50.87

2 4


609.10

956.79 510.25

42.52

3 6

Crane Operator

606.34

1,426.89 506.96

42.25

1 2

Deck Pusher

649.74

519.03 558.69

46.56

2 4

Lead Roustabouts 448.25 701.72 369.04 30.75

9 18

Roustabouts

448.25

3,157.72 369.04

30.75

1 2

Welder

586.61

455.90 483.45

40.29

1 2


664.34

533.63 483.32

40.28

1 2

Material Coordinator

577.15

446.43 472.16

39.35

1 2

Medic (RSTT)

577.15

446.43 472.16

39.35

1 2

Radio Operator

519.15

388.44 403.03

33.59

1 2

RSTC 625.67 494.96 444.65 37.05

0 0

—

—

— —

—

0 0

—

—

— —

—

0 0

— — — —

—

0 0

—

—

— —

—

69 138

Total Labor Costs =

$ 35,109.66

Exhibit F-2: Additional Personnel to be Provided

DEEPWATER HORIZON Adjusted Labor as of September 18, 2006

The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short. This includes all Training, Transportation, Catering and Marine P&I costs. The figures in column “B” are the daily cost of all crew members excluding Training, Transportation, Catering and Marine P&I costs. The figures in column “C” are the daily cost of overtime excluding Training, Transportation, Catering and Marine P&I costs (assuming a daily schedule of 12 hours)

The figures in column “D” are the hourly cost of overtime excluding Training, Transportation, Catering and Marine P&I costs.

E-43

5

A B C D GOM Base Labor GOM Overtime Rates

No. of Personnel Daily Rate per Daily Hourly

On Board

Assigned To Rig

JOB CLASSIFICATION

person (inc.TT&C & P&I)

Total Daily onBoard Cost

Overtime Rates

OvertimeRates

1 2

Deck Pusher

649.74

519.03

558.69

46.56

0 0

— — — — —0

0 —

—

—

—

—

0 0

—

—

—

—

—

0 0

— — — — —1

2 Total Labor Costs = $ 519.03

Total Addtl Labor Costs including TTC & P&l =

649.74

BLS Home | Programs & Surveys | Get Detailed Statistics | Glossary | What’s New | Find It’ In DOL

Data extracted on: October 24, 2006 (11:24:35 AM)

Producer Price Index-Commodities



E-44

6


U.S. Department of Labor

Bureau of Labor Statistics Bureau of Labor Statistics Data

www.bls.gov Advanced Search | A-Z Index

Change Output From: 1996 To: 2006 GOOptions:

Include graphs NEW!

More Formatting Options

Series Id: WPU119102 Not Seasonally Adjusted Group: Machinery and equipment Item: Oil field and gas field drilling machineryBase Date: 8200

Year Jan

Feb Mar

Apr May

Jun

Jul

Aug

Sep

Oct Nov

Dec

Annual

1996 124.0

124.0 124.0

124.3 124.2 124.8 125.3 125.3 125.3 126.2

126.6 127.1 125.11997

127.7 127.9

128.6 129.1

129.2

129.3

129.3

129.5

129.7

130.3 131.4

132.0

129.5

1998 133.1

132.9 133.1

133.0 133.0

133.0

132.9

132.9

132.9

133.6 133.6

133.6

133.1

1999 133.8

133.7 133.7

133.9 133.9

134.0

134.0

133.7

133.7

133.7 134.4

134.6

133.9

2000 134.9

136.3 136.3

136.3 136.5

136.5

136.5

136.6

136.7

138.7 138.7

138.7

136.9

2001 143.5

143.9 144.0

144.0 144.0

145.5

145.6

145.8

145.7

146.1 146.1

146.1

145.0

2002 146.2

146.2 146.6

146.6 146.4

146.4

146.4

146.4

146.7

146.7 146.7

146.7

146.5

2003 149.8

149.8 149.8

151.7 152.3 152.5 152.5 152.5 153.1 153.1

153.1 153.5 152.02004

153.8 153.9

154.8 156.4

157.1

157.1

156.6

156.7

156.8

157.0 157.9

160.1

156.5

2005 162.0

163.7 169.0

169.8 171.3

172.0

172.5

172.5

172.7

173.9 178.7

180.0

171.5

2006 179.7

182.9 183.6

184.1 188.2

190.5 (P) 190.6 (P) 192.6(P) 192.3 (P)

U.S. Bureau of Labor Statistics Phone: (202) 691-5200Postal Square Building Fax-on-demand: (202) 691-63252 Massachusetts Ave., NE Data questions: blsdata [email protected], DC 20212-0001 Technical (web) questions: [email protected]


http://data.bls.gov/PDQ/servlet/SurveyOutputServlet:jsessionid=f03080c7caaf$3F$3F$3 10/24/2006

These costs and limits reflect the coverage provided at this time and are subject to change upon renewal.

** Based on SIR accrual of $ 13.88 per person per day assigned to the rig. Best Regards, Signed electronically Betsy Kelly, CPCU, ARe Manager- Insurance

E-45

7

BETSY KELLY MANAGER-INSURANCE

TRANSOCEAN OFFSHORE DEEPWATER DRILLING INC. 4 GREENWAY PLAZA HOUSTON, TX77046


Deepwater Horizon

Effective May 1,2006 Coverage: All Risk Hull & MachineryCarrier: various Underwriters @ Lloyds, led by Limit and Wellington SyndicatesInsured Value: $ 370,000,000Deductible: $ 10,000,000NET ANNUAL PREMIUM: $ 3,761,055 Effective December 31, 2006 Coverage: Primary Marine Protection & IndemnityCarrier various Underwriters @ Lloyds, led by Limit and XL SyndicatesSelf Insured Retention: $10,000,000 per occurrenceDEDUCTIBLE ACCRUAL: $ 709,380** Effective May 1, 2006 Excess LiabilityCoverage: various Underwriters @ Lloyds, led by Limit and Wellington SyndicatesCarriers: $930,000,000Limits: $ 376,623NET ANNUAL PREMIUM:

Effective October 1, 2005

Coverage: Oil PollutionCarrier: Surety coverage – backed by Underwriters @Lloyds NET ANNUAL PREMIUM: $ 10,558 Effective December 31, 2005

U.S. Broker: McGriff, Seibels & Williams, IncAnnual Fee: $ 40,841 Effective July 1, 2006

London Broker: Lloyd & Partners Ltd.Annual Fee: $ 48,313


INTEROFFICE MEMORANDUM

North America Region April 11, 2006

Transocean is committed to providing a competitive salary, as well as a comprehensive benefit package, training, and long term career development opportunities for all employees. Therefore, effective 1 April 2006, a 5% Across-the-Board increase in base pay has been approved for all US Gulf Coast full time regular rig-based positions. This increase will be retroactive for all work performed on or after 1 April 2006, and will be reflected on your regular scheduled pay check beginning 14 April 2006. If you have any questions or comments, please feel free to contact myself at 832-587-8551, or Donna Schaaf at 832-587-8699.

E-46 8

TO: All GOM Rig Based Employees SUBJECT: BASE PAY COMPENSATION ADJUSTMENT FROM: Amy Smith

Delta Catering Management, LLC 5749 Sustina Drive, #300 Harahan, LA 70123

Dear Mrs. Marney, Reference is made for all purposes to the certain Catering Agreement dated June 24, 2005 by and between Transocean Holdings Inc. (“Company”) and Delta Catering Management, LLC (“Caterer”) for the Drilling Unit, the “Deepwater Horizon” (“Agreement”) Company requested an adjustment to rates for the “Deepwater Horizon” which would allow for the annual increase and a change to Schedule C. We have received and reviewed the new rates as requested and return the attached revised Schedule C as an attachment to this letter. Schedule C will now include the new catering crew Labor Rate Schedule which was formerly provided in Schedule A-l Item 2.0 - Manning. And, the references will be deemed changed accordingly. This revised Schedule C will qualify as the annual escalation as provided in Schedule A-l Item 6.0 and will be effective March 1, 2006. These rates will remain valid and will not be adjusted for one year. At that time the rates can be adjusted again at a mutually agreed rate. If you are in agreement with this adjustment, please indicate your acceptance in the space provided below and return one original copy of this letter to us for our files. Regards,

Tim Juran Division Manager, North America /ks

E-47

9

TRANSOCEAN HOLDINGS INC 1311 BROADFIELD BLVD SUITE 400 HOUSTON, TEXAS 77084

TIM JURAN

DIVISION MANAGER NORTH AMERICA

April 20, 2006

Attn: Mrs. Marcia Marney Ref: Cost Increases Catering Agreement – “Deepwater Horizon”

/s/ Tim Juran_

AGREED AND ACCEPTED THIS 26 DAY OF April, 2006CATERING MANAGEMENT, LLC SIGNED Marcia Marney

TITLE President + General Manager

DATED April 26, 2006

PHONE: (832) 587-8596 FAX: (832) 587-8754 E-MAIL: [email protected]

Rate Adjustment – Delta Catering Deepwater Horizon

REVISED SCHEDULE C - MARCH 1, 2006 CATERING SERVICE RATES

FOR THE DEEPWATER HORIZON

The Caterer’s catering service manday rates for this Drilling Unit shall be based on the following information:

LABOR RATE SCHEDULE

Delta Rate Adjustment - Horizon

E-48

10

Average Total POB 150

Average Daily Casual Meals 2

Catering Crew Complement 18

Fixed Daily Rate

$ 3,031

Cost per Man Per day - Groceries & Supplies $ 15.50

Costs for Incremental Personnel

Catering Position

On Board

Range Max. EmployeeHourly Wage

Daily Cost(Incl.

burden)

Total Daily On Board

Costs

HourlyOvertime Rate

Cost/HourStandby Rate

Executive Steward 1

$13.00 -$15.00 $ 15.00 $ 375.10 $ 375.10 $ 37.50 $ 31.25

Day Cook 1

$9.50 -$11.00 $ 11.00

$ 271.85

$ 271.85

$ 27.20

$ 22.65

Night Cook 1

$8.25 -$9.00 $ 9.00

$ 225.35

$ 225.35

$ 22.55

$ 18.80

Baker 1

$8.50 -$9.25 $ 9.25 $ 231.30 $ 231.30 $ 23.15 $ 19.30

Prep. Cook 2

$7.45 -$8.45 $ 8.45

$ 211.50

$ 423.00

$ 21.15

$ 17.65

Senior Orderly 4

$7.50 -$8.25 $ 8.25

$ 206.30

$ 825.20

$ 20.65

$ 17.20

Utility / Galleyhand 8

$6.25 -$7.45 $ 7.45 $ 186.25 $ 1,490.00 $ 18.60 $ 15.50

Total On Board 18

$ 3,841.80

WORK ORDER


Description/Scope of Work/Additional Terms and Conditions: Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of this, the separate written agreement will be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT. Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain additional equipment and materials described herein below as required for supporting COMPANY’s drilling operations on the Big Kahuna Well located in the Gulf of Mexico. For the avoidance of doubt, all such items shall be considered as CONTRACTOR’s equipment. The Work Order includes the provision of Additional 6-5/8” Drill Pipe for the Drilling Unit “Deepwater Horizon”. An additional 3,000’ (69 joints) of 6-5/8” premium grade drill pipe will be furnished by CONTRACTOR in accordance with the following technical specifications:


COMPANY shall pay CONTRACTOR a “Fee” which shall hereinafter be defined as $1,500/day for the drill pipe. The drill pipe will be required for the duration of the Big Kahuna Well which is expected to last for a one hundred and twenty-five (125) day time period. Thus, the Estimated Value of Work Order is calculated as follows:

($1,500/day) (125 days) = $187,500 or, rounded off is $200,000

1

Date: January 24, 2007


George Coltrin




Work Order No.:

BPR-07-00223 Paykey No.:

ZGMXKAHUNA Project Identification:

Big Kahuna Well

Additional 6-5/8” Drill Pipe Estimated Value of Work Order:

$200,000 Expected Start Date:

January 10, 2007 Expected Completion Date:

May 15, 2007

th

The Estimated Value of this Work Order as set forth in the heading of this document is based only on the Work as presently defined. If the duration of the Big Kahuna Well should exceed the estimated one hundred and twenty-five (125) day time period, then COMPANY will provide an extension to this Work Order in the form of a “Change Order.” Regardless of the duration of the Big Kahuna Well the agreed Fee will be paid until the drill pipe is returned and offloaded at COMPANY’s shore base facility. The Fee shall commence at 00:00 on January 10, 2007, and shall end after the drill pipe has been returned and offloaded at COMPANY’s shore base facility at Fourchon, Louisiana. COMPANY shall also reimburse CONTRACTOR for all costs associated to re-inspect the drill pipe to DS1 Level 5 standards and return to CONTRACTOR’s yard in Amelia, Louisiana, after the Big Kahuna Well is completed. All inspection, repair and transportation costs, including freight and handling charges associated with movement of the drill pipe, will be for COMPANY’s account regardless of the Estimated Value of Work Order noted hereinabove. The pricing information presented herein shall be firm and fixed for the duration of this Work Order and will serve as the basis of any subsequent price adjustments, if deemed necessary.


2



P.O. Box 22024

Tulsa, OK 74121-2024


Paykey No.: ZGMXKAHUNA



CONTRACTOR

COMPANY

Anton Dibowitz

Ben Steven Smith

Printed Name

Printed Name

Title:

Marketing Manager

Title:

Sr. PSCM Sourcing Specialist

Date:

2/22/07 Date: Feb. 14, 2007 Notices: Transocean Holdings, Inc.







Attention: Steve Smith

Phone: 832-587-8500

Mail Code: 646C, WL4

Fax: 832-587-8754

Phone: 281-366-2041

E-Mail: [email protected] Fax: 281-366-7130


WORK ORDER


Description/Scope of Work/Additional Terms and Conditions: Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of this, the separate written agreement will be referred to as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT. Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to furnish certain additional equipment and materials described herein below as required for supporting COMPANY’s drilling operations on various deep water projects located in the Gulf of Mexico. For the avoidance of doubt, all such items shall be considered as CONTRACTOR’s equipment. The Work Order includes the provision of Additional 6-5/8” Drill Pipe for the Drilling Unit “Deepwater Horizon”. An additional 3,000’ (69 joints) of 6-5/8” premium grade drill pipe will be furnished by CONTRACTOR in accordance with the following technical specifications:


COMPANY shall pay CONTRACTOR a “Fee” which shall hereinafter be defined as $1,500/day for the drill pipe. The drill pipe will be required for the remaining term of the CONTRACT. The Estimated Value of Work Order is calculated as follows:

($1,500/day) (1,300 days) = $1,950,000 1

Date: March 1, 2007


George Coltrin

CONTRACTOR:


Work Order No.:


(To be advised on a per well basis) Project Identification:

Transocean “Deepwater Horizon”


$1,950,000 Expected Start Date:

February 25, 2007 Expected Completion Date:

September 17, 2010

th

The Estimated Value of this Work Order as set forth in the heading of this document is based only on the Work as presently defined. If the duration of the last deep water project should exceed the estimated one thousand, three hundred (1,300) day time period, then COMPANY will provide an extension to this Work Order in the form of a “Change Order.” Regardless of the duration of the deep water projects, the agreed Fee will be paid until the drill pipe is returned and offloaded at COMPANY’s shore base facility. The Fee shall commence whenever the drill pipe has been delivered to the Drilling Unit, and shall end after the drill pipe has been returned and offloaded at COMPANY’s shore base facility at Fourchon, Louisiana. COMPANY shall also reimburse CONTRACTOR for all costs associated to re-inspect the drill pipe to DS1 Level 5 standards and return to CONTRACTOR’s yard in Amelia, Louisiana, after the last deep water project is completed. All inspection, repair and transportation costs, including freight and handling charges associated with movement of the drill pipe, will be for COMPANY’s account regardless of the Estimated Value of Work Order noted hereinabove. COMPANY, at its sole option, may terminate this Work Order at any time short of its one thousand, three hundred (1,300) day time period by providing notice in writing thirty (30) days in advance to CONTRACTOR along with inspection and redelivery as above. The pricing information presented herein shall be firm and fixed for the duration of this Work Order and will serve as the basis of any subsequent price adjustments, if deemed necessary.

2



P.O. Box 22024

Tulsa, OK 74121-2024


Paykey No.: To be advised on a per well basis

ACCEPTED BY: /s/ Terry Poonno


CONTRACTOR

COMPANY

Terry Poonno

Ben Steven Smith

Printed Name

Printed Name

Title:

Marketing Mgr, North America Div.

Title:

Sr. PSCM Specialist

Date:

April 20, 2007 Date: April 10, 2007 Notices: Transocean Holdings, Inc.








Phone: 832-587-8500

Mail Code: WL4-1995C

Fax: 832-587-8754

Phone: 281-366-2041

E-Mail: [email protected] Fax: 281-366-4697


Amendment No. 28


This Amendment No. 28 is made and entered into as of the 18 day of May, 2007, by and between BP America Production Company (hereinafter referred to as “COMPANY”) and Transocean Holdings, Inc. (hereinafter referred to as “CONTRACTOR’) with a place of business at 1311 Broadfield, Suite 400, Houston, Texas 77084.


WHEREAS, by Drilling Contract No. 980249 made and effective the 9 day of December, 1998, COMPANY and CONTRACTOR entered into that certain Contract for the “Deepwater Horizon”, (hereinafter referred to as “CONTRACT”) as previously amended ; and WHEREAS, COMPANY and CONTRACTOR desire to amend the CONTRACT to provide for the procurement, transportation, and maintenance of six (6) pup joints for use on the “Deepwater Horizon” (hereinafter referred to as “Drilling Unit”). WHEREAS, CONTRACTOR agrees to purchase, transport to the Drilling Unit, and own six (6) pup joints and; WHEREAS, the delivery of such equipment is estimated circa June 15, 2007; CONTRACTOR will make all reasonable effort to have such equipment delivered to the Drilling Unit in a timely manner; however, CONTRACTOR shall not be responsible for any late delivery and/or associated downtime and; NOW THEREFORE for and in consideration of the foregoing agreed provisions as well as the mutual covenants and agreements hereinafter provided. COMPANY and CONTRACTOR agree to amend the CONTRACT as follows: A new line item shall be added to EXHIBIT A, DAYRATES, to indicate that effective June 15, 2007, COMPANY will pay CONTRACTOR an additional day rate in the amount of $73.00 per day for the purchase and use of the six (6) pup joints until the end of the day September 18, 2010. This additional day rate shall be payable regardless of any other day rate in effect at any time. In the event the CONTRACT is terminated for any reason before the end of the CONTRACT term as now known, COMPANY shall pay CONTRACTOR a lump sum determined by the product of the additional day rate multiplied by the number of days remaining up to and including the end of the day September 18, 2010. If the current term of the CONTRACT goes beyond September 18, 2010, under Article I, paragraph 1.1.5, the parties agree that COMPANY’s and CONTRACTOR’s obligations arising under this Amendment will expire at the end of the day September 18, 2010. Except as changed by this Amendment No. 28, the CONTRACT as amended shall remain in full force and effect between the parties. IN WITNESS WHEREOF, the authorized representatives of the parties hereto have executed this Amendment No. 28 in duplicate originals as of the day and year first above written.


Transocean Holdings, Inc.COMPANY

CONTRACTOR By: /s/ Ben Steven Smith

By: /s/ Andrew Tietz

Ben Steven Smith

Andrew Tietz

Printed Name

Printed Name Title: Sr. PSCM Specialist

Title: Marketing Manager

th

th

Notice No. 29


This notice is effective as of the 18 day of September 2007, and is issued to BP America Production Company (hereinafter referred to as “COMPANY”) with a place of business at 200 Westlake Park Blvd, Houston, Texas 77079.


WHEREAS, COMPANY and Transocean Holdings Inc. (hereinafter referred to as “CONTRACTOR”) entered into Drilling Contract No. 980249 made and effective the 9 day of December, 1998, for the “Deepwater Horizon” (hereinafter referred to as “CONTRACT”), which has been previously amended; and WHEREAS, COMPANY and CONTRACTOR desire to set forth a notice as to the current application to dayrates of Amendment 24 of the CONTRACT as more particularly set forth therein; NOW THEREFORE, CONTRACTOR advises as follows: CONTRACTOR’S name change: CONTRACTOR’S name is hereby changed from Transocean Holdings Inc. to Transocean Holdings LLC. The Operating Rate (and, consequently, all other dayrates except the Equipment Repair Rate) specified in EXHIBIT A, DAYRATES shall be adjusted as per Item 3 of Amendment No. 24 to the CONTRACT. Accordingly, CONTRACTOR hereby advises COMPANY that the Operating Rate on the Deepwater Horizon shall be $377,594.00 beginning September 18, 2007 and ending December 17, 2007. Additional rates are set forth in the attached Exhibit A along with support information for the average dayrate calculation. These rates are auditable as per Amendment 24 of the CONTRACT. Except as changed by this notice, No. 29, the CONTRACT as amended shall remain in full force and effect between the Parties. IN WITNESS WHEREOF, the authorized representatives of the Parties have executed this Amendment No. 29 in duplicate originals as of the day and year first above written.

E-49

1


Transocean Holdings LLC (formerly known asCOMPANY

Transocean Holdings Inc.)

CONTRACTOR By: /s/ Ben Steven Smith 06/07/08

By: /s/ Michael D. Acuff

Ben Steven Smith

Michael D. Acuff

Printed Name

Printed Name

th

th

EXHIBIT A

DAYRATES

E-50

2


Operating Rate

$377,594 per day Moving Rate

$377,594 per day Standby Rate With Crews

$377,594 per day Standby Rate Without Crews

$377,594 per day less documented cost savings Stack Rate With Crews

$377,594 per day less documented cost savings Stack Rate Without Crews $377,594 per day less documented cost savings Equipment Repair Rate $ -0- Per Day subject to Article 2.2.5(a) Hurricane Evacuation Rate


Average Dayrates Calculation

The rigs used for the calculation of the average dayrates are

Discoverer Spirit Discoverer Deep Seas Discoverer Millennium Cajun Express

The table below identifies the dayrates used in the calculation average for the Deepwater Horizon’s Operating Rate for the period detailed herein:

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Rig

Actual contracted day ratesas calculated on Sept. 14,

2007

$ 475,739

$ 444,688

$ 296,204

$ 293,746 Average Actual Daily Rate $ 377,594

WORK ORDER


Description/Scope of Work/Additional Terms and Conditions: Article 5.1.1 of Drilling Contract No. 980249 (“CONTRACT”) stipulates that any modifications to the Drilling Unit after the Commencement Date shall be as agreed in a separate written agreement. In respects of this, the separate written agreement will be referred to herein as a “Work Order” and implementation of the requirements delineated in the Work Order shall be in accordance with the terms and conditions of the CONTRACT. Under this Work Order COMPANY is requesting and CONTRACTOR has agreed to acquire and rent to COMPANY certain additional equipment and materials described herein below (“Equipment”) as required for supporting COMPANY’s drilling operations from the Deepwater Horizon (“Drilling Unit”). The term of the rental shall be from the time of the delivery of such Equipment, throughout the remaining term of the CONTRACT, until the scheduled ending on September 18, 2010. For the avoidance of doubt, throughout and upon the completion of the CONTRACT, such items shall be considered as CONTRACTOR’s equipment. The Work Order is for the rental of the Equipment, hereinafter more specifically described as Additional 6-5/8” Drill Pipe for the Drilling Unit “Deepwater Horizon”. An additional string of 6-5/8” premium grade drill pipe consisting of approximately 15,000’ with .522” wall and approximately 10,300’ with .640” wall will be acquired by CONTRACTOR and rented to COMPANY in accordance with the following technical specifications:

• 15,450ft (+0%,-3%) Pipe, Drill 6-5/8”, Grade V150 (.522” wall) 95% minimum body wall, 6-5/8” FH connection - Range 3, lengths (44.5ft, +/-6”) 8-1/2” OD x 4-1/4” ID tool joints, 12” pin tong space, 15” box tong space, with SmoothEdge feature on pins and boxes (i.e. both ends), pin end tool joint marking as per modified ISO 10407, 1993 tool joint identification specification detailed in Figure 3 & 4 of Transocean’s Technical Information Bulletin HQS-OPT-TIB-516-02 (New Drill Pipe Manufacturing Specification) except with an added second ring groove to be centered through the milled flat as per Grant Prideco sketch 1H051 Rev 2, pre-torqued connections, 3” band of TCSTi high performance casing friendly hardbanding applied 3/32” proud (+1/32”, -0”) to pins and boxes (i.e. both

1

Date: November 29, 2007


David Sims




Work Order No.:


COMPANY will advise for each well Project Identification:


$4,500,000.00 Expected Start Date:

October 01, 2008 Expected Completion Date:

September 18, 2010

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ends) beginning 1/4” to 3/8” from elevator shoulder, TK34XT internal plastic coating, additional specifications as per Transocean Technical Information Bulletin HQS-OPS-TIB-516-02 (New Drill Pipe Manufacturing Specification) and NS1. Rust-Veto AS or equivalent long term storage compound on threads with high density polyethylene non-metallic composite reinforced thread protectors applied wrench tight. Either Plusco 372 or Oil Center Research 1122 NFP Protekto-Coat black water based varnish on pipe OD. • 10,300ft (+0%,-3%) Pipe, Drill 6-5/8”, Grade V150 (.640” wall) 95% minimum body wall, 6-5/8” FH connection - Range 3, lengths (44.5ft, +/-6”) 8-1/2” OD x 4-1/4” ID tool joints, 12” pin tong space, 15” box tong space, with SmoothEdge feature on pins and boxes (i.e. both ends), pin end tool joint marking as per modified ISO 10407, 1993 tool joint identification specification detailed in Figure 3 & 4 of Transocean’s Technical Information Bulletin HQS-OPT-TIB-516-02 (New Drill Pipe Manufacturing Specification) except with an added second ring groove to be centered through the milled flat as per Grant Prideco sketch 1H051 Rev 2, pre-torqued connections, 3” band of TCSTi high performance casing friendly hardbanding applied 3/32” proud (+1/32”, -0”) to pins and boxes (i.e. both ends) beginning 1/4” to 3/8” from elevator shoulder, TK34XT internal plastic coating, additional specifications as per Transocean Technical Information Bulletin HQS-OPS-TIB-516-02 (New Drill Pipe Manufacturing Specification) and NS1. Rust-Veto AS or equivalent long term storage compound on threads with high density polyethylene non-metallic composite reinforced thread protectors applied wrench tight. Either Plusco 372 or Oil Center Research 1122 NFP Protekto-Coat black water based varnish on pipe OD.

For the provision of the Equipment, the total cost of this pipe ($3,621,173) multiplied by 1.1, to account for 10% capital asset tax, shall be amortized at 12% interest for the term starting at the delivery of the Equipment and ending on September 18, 2010 (“Rental Period”). COMPANY shall pay this calculated daily rental payment (“Daily Payment”) to CONTRACTOR within thirty (30) days after receipt of monthly invoice and shall be payable regardless of whether there is any other day rate in effect at any time. The Daily Payment shall be calculated by the Excel payment function shown below, where RP symbolizes the Rental Period in days.

For example, if CONTRACTOR delivers the Equipment on October 1, 2008, the Rental Period would be 717 days through September 18, 2010. Using the Excel payment function above, the Daily Payment would be calculated as follows:

If the current term of the CONTRACT goes beyond September 18, 2010, under Article I, paragraph 1.1.5, the parties agree that COMPANY’s payment obligations arising under this Work Order will expire at the end of the day September 18, 2010. For clarification, the Equipment will continue to be provided by CONTRACTOR and COMPANY’s liability and obligations as described in this Work Order (with exception of the payment of the Daily Payment) will continue through the completion of the well in progress on September 18, 2010. If COMPANY elects to extend the CONTRACT, other than to complete the well in progress, CONTRACTOR’s provision of the Equipment will be discussed during the negotiation of the extension. If the CONTRACT is terminated prior to September 18, 2010, for any reason, COMPANY shall pay CONTRACTOR, within thirty (30) working days after receipt of invoice, a lump sum determined by the difference between (i) the product of the Daily Payment as calculated in (A) above multiplied by the number of days from the delivery of the Equipment until the termination date (“Termination Period”) and (ii) the revised value of the daily amount as calculated by the Excel function in (B) below (“Revised Daily Payment”) multiplied by the Termination Period, shown as TP below.

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(A) = - PMT ((1+12%)^(1/365)-1,[RP],3621173*1.1) Daily Payment .

(Example) = - PMT ((1+12%)^(1/365)-1,717,3621173*1.1)= $6,198

(B) = - PMT ((1+12%)^(1/365)-1,[TP],3621173*1.1) Revised Daily Payment .

For clarity, the lump sum payment is calculated as follows: ((B) x TP) - ((A) x TP) All inspection, repair, replacement and transportation costs, including freight and handling charges associated with movement of the Equipment, will be for COMPANY’s account regardless of the Estimated Value of Work Order noted hereinabove, however when the Equipment is no longer required for COMPANY’s requirements, COMPANY will have no obligation to inspect repair or replace, the Equipment and CONTRACTOR will have no obligation to provide the Equipment. The pricing information presented herein shall be firm and fixed for the duration of this Work Order and will serve as the basis of any subsequent price adjustments, if deemed necessary. COMPANY as lessee accept full responsibility for the Equipment during the rental period and agrees to return the Equipment to CONTRACTOR as lessor at or before the end of the rental period in as good condition as when received, ordinary wear and tear excepted, which condition shall be determined by a third party inspection at COMPANY’s cost. CONTRACTOR makes no warranty of quality, merchantability or fitness for any purpose or any other warranty of any kind, express or implied, with respect to the equipment.

This Work Order shall be otherwise performed in accordance with the terms and conditions of this CONTRACT as amended.

3



P.O. Box 22024

Tulsa, OK 74121-2024


Paykey No.: COMPANY will advise for each well


ACCEPTED BY: /s/ A. M. Polhamus

COMPANY

CONTRACTOR

Ben Steven Smith

A. M. Polhamus

Printed Name

Printed Name

Title:

Sr. PSCM Specialist

Title:

North America Division Manager

Date:

12/03/07

Date:

November 29, 2007 Notices: BP America Production Company

Notices: Transocean Holdings, Inc.






Attention: Mac Polhamus

Mail Code: 646C, WL4-1995C

Phone: 832-587-8597

Phone: 281-366-2041

Fax: 832-587-8754

Fax: 281-366-7130 E-Mail:

E-Mail: [email protected] [email protected]

Amendment No. 30


This Amendment is effective as of the 18 day of December 2007, and is issued to BP America Production Company (hereinafter referred to as “COMPANY”) with a place of business at 200 Westlake Park Blvd, Houston, Texas 77079.


WHEREAS, COMPANY and Transocean Holdings Inc. (hereinafter referred to as “CONTRACTOR”) entered into Drilling Contract No. 980249 made and effective the 9 day of December, 1998, for the “Deepwater Horizon” (hereinafter referred to as “CONTRACT”), which has been previously amended; and WHEREAS, COMPANY and CONTRACTOR desire to set forth a notice as to the current application to dayrates of Amendment 24 of the CONTRACT as more particularly set forth therein; NOW THEREFORE, CONTRACTOR advises as follows: The Operating Rate (and, consequently, all other dayrates except the Equipment Repair Rate) specified in EXHIBIT A, DAYRATESshall be adjusted as per Article 3 of Amendment No. 24 to the CONTRACT. Accordingly, CONTRACTOR hereby advises COMPANY that the Operating Rate on the Deepwater Horizon shall be $444,165.00 beginning December 18, 2007 and ending March 17, 2008. Additional rates are set forth in the attached EXHIBIT A along with support information for the average dayrate calculation. These rates are auditable as per Amendment 24 of the CONTRACT. CONTRACTOR’S personnel labor rates set forth in the attached EXHIBIT F-l supersedes Exhibit F-l in Amendment 27. Article 3 of Amendment 24 to Drilling Contract No. 980249 is replaced in its entirety with the following Article 3: 3. The Operating Rate (and, consequently, all other dayrates except the Equipment Repair Rate) specified in EXHIBIT A, DAYRATES shall be revised to the amount, and periodically adjusted in accordance with terms, set forth below. An Operating Rate of $275,000 per day shall be payable to CONTRACTOR commending September 18, 2005, through the end of the initial 2 year term of the CONTRACT extension. The rate specified is based on wage scales and current operating expenses as of March 1, 2005. CONTRACTOR shall have the right to adjust the rate for documented changes, if any, in the base operating costs no sooner than the commencement of the first year and then no more often than annually thereafter during the initial 2 year term of the CONTRACT extension. The Operating Rate shall be adjusted to a “Market Rate” at the commencement of year three (3) of the CONTRACT extension (i.e., on September 18, 2007) and then at the beginning of every three (3) months thereafter, until the end of the term of the CONTRACT. The Market Rate will be calculated only using Transocean legacy rigs, i.e. rigs that Transocean owned prior to Transocean’s merger with GlobalSantaFe. The Market Rate for the three (3) month period shall be the average of the actual contracted dayrates, excluding incentive components, then being earned by the following Transocean fifth (5 ) generation DP rigs when they are operating in the USGOM: 1. DISCOVERER ENTERPRISE* 2. DISCOVERER SPIRIT 3. DISCOVERER DEEP SEAS 4. DEEPWATER MILLENIUM 5. CAJUN EXPRESS

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6. DEEPWATER PATHFINDER 7. DEEPWATER FRONTIER 8. SEDCO ENERGY 9. SEDCO EXPRESS 10. DEEPWATER EXPEDITION 11. DEEPWATER DISCOVERY For avoidance of doubt, legacy GlobalSantaFe drilling units (i.e. CR Luigs, GSF Explorer, Jack Ryan, GSF Development Driller I, GSF Development Driller II and GSF Development Driller III) and new build Transocean sixth (6 generation rigs (e.g. Discoverer Inspiration, Discoverer Clear Leader and Discoverer Americas) shall not be included in the list of “Transocean DP fifth (5 ) generation rigs” for the purpose of computing the Market Rate for the Deepwater Horizon. • Idle rigs or idle time shall not be counted in the Market Rate calculation unless the idle rig is under contract in the USGOM for a

contract to begin within the three (3) month period covered by the rate calculation. Then the operating Rate of that contract shall be used. A zero rate shall never be used.

• A rig under USGOM contract which is nevertheless idle for the convenience of the Operator or otherwise shall be included in the

rate calculation using the Operating Rate of that contract. • Transocean legacy rigs contracted in the USGOM but which are outside the USGOM for a period of time shall be counted in the

average using their GOM dayrate. • If there are fewer that four (4) rigs in the list above operating in the USGOM, then the following rigs will be added (when

contracted to COMPANY in the USGOM) in the order listed, to bring the total up to four (4) rigs for the calculation***. a. DEVELOPMENT DRILLER II** b. DEVELOPMENT DRILLER I c. GSF JACK RYAN d. GSF C.R. LUGIS e. OCEAN CONFIDENCE (outfitted to 10,000’)***

• If there are fewer than four (4) rigs using the COMPANY contracted rigs on the list above, then the average shall be calculated using three (3) rigs.

• If there are fewer than three (3) rigs in the pool for calculating the average, the dayrate shall stay at the last calculated rate until

the pool increases to at least three (3) rigs. COMPANY shall have the right to terminate the CONTRACT by giving ninety (90) days written notice if there are fewer that three (3) rigs in the pool for one (1) continuous year from the first time there were fewer than three (3) rigs available for the pool used in the Market Rate average calculation.

* The DISCOVERE ENTERPRISE dayrate shall not be included in the average until the commencement of Contract BPM-06-02155, December 11, 2007. **The DEVELOPMENT DRILLER II dayrate shall not be included in the average until it concludes its initial three (3) year term contract with COMPANY. The Development Driller II shall continue to be excluded from the calculations if any exercised option(s) after the initial three (3) year term limits or caps the dayrate paid during the option period. However, any exercised option period(s) after the initial three (3) year term in which the dayrates are obtained by mutual agreement based on current market rates shall be included in the Market Rate calculation. *** If COMPANY reimburses Diamond Offshore Company for the 10,000’ upgrade on a “lump sum” basis, then the lump sum paid for the upgrade will be divided out over the firm term of the contract to arrive at a daily sum to be added to the Operating Rate for purposes of calculating the Market Rate. If the Ocean Confidence’s rate (on any day

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the average calculation is made) is set by a stipulated or limited rate in an option attached to its current contract, then its rate shall not be included in the average calculation. Upon reasonable notification, any given Market Rate calculation shall be subject to audit by third party auditors contracted by COMPANY. Errors in any given Market Rate calculation inconsistent with the above shall be adjusted promptly following the issuance of the relevant audit report. Except as changed by this Amendment, No. 30, the CONTRACT as previously amended shall remain in full force and effect between the Parties. IN WITNESS WHEREOF, the authorized representatives of the Parties have executed this Amendment No. 30 in duplicate originals as of the day and year first above written.

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Transocean Holdings Inc COMPANY CONTRACTOR By: /s/ Wilbert Long, Jr.

By: /s/ Jess M. Richards

Wilbert Long, Jr.

Jess M. Richards

Printed Name

Printed Name Title: Head of GoM PSCM

Title: Marketing Manager – North AmericaDate: 8/10/09

Date: 8/10/09

EXHIBIT A

DAYRATES



Cajun Express Discoverer Millennium Discoverer Spirit Discoverer Deep Seas Discoverer Enterprise


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RATES PER 24 HOUR DAY Operating Rate

$444,165 per day Moving Rate

$444,165 per day Standby Rate With Crews

$444,165 per day Standby Rate Without Crews

$444,165 per day less documented cost savings Stack Rate With Crews $444,165 per day less documented cost savings Stack Rate Without Crews

$444,165 per day less documented cost savings Equipment Repair Rate

$ -0- Per Day subject to Article 2.2.5(a) Hurricane Evacuation Rate


Rig

Actual contracted day rates as calculated onDecember 14, 2007

A

$ 462,501

B

$ 447,379

C

$ 497,198

D

$ 293,746

E

$ 520,000

Average Actual Daily Rate $ 444,165

Exhibit F-l: Personnel to be Provided

Deepwater Horizon Adjusted Labor as of December 18, 2007

The figures in column “A” are to be used as the basis for adding personnel to the permanent crew and for determining the credit for crew members short. This includes all Training, Transportation, Catering and Marine P&I costs. The figures in column “B” are the daily cost of all crew members excluding Training. Transportation, Catering and Marine P&I costs. The figures in column “C” are the daily cost of overtime excluding Training, Transportation, Catering and Marine P&I costs (assuming a daily schedule of 12 hours) The figures in column “D” are the hourly cost of overtime excluding Training. Transportation, Catering and Marine P&I costs.

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A B C D


No. of Personnel Daily Rate per

Daily HourlyOn

Board

Assigned To Rig

JOB CLASSIFICATION

person (inc.TT&C & P&I)

Total Daily on Board Cost

Overtime

Rates

OvertimeRates

1 2

OIM

1,293.28

1,157.04

1,107.77

92.313

6 Toolpusher

1,073.60 2,812.07

888.09 74.012

4 Driller

911.58

1,550.67

865.41

72.124

8 Assistant Driller

761.54

2,501.20

686.61

57.222

4 Derrickhand 655.02

1,037.54

559.63

46.642

4 Pumphand

570.66

932.40

507.77

42.318

16 Floorhand

536.73 3,458.17

467.32 38.941

2 Maintenance Supervisor

1,074.01

937.76

888.50

74.041

2 Mechanical Supervisor

921.31 785.06

735.80 61.322

4 Chief Mechanic

823.09

1,373.70

759.97

63.332

4 Mechanic

739.84

1,207.20

660.74

55.061

2 Senior Motor Operator 589.91

453.67

482.04

40.172

4 Motor Operator

589.91

907.34

482.04

40.171


921.31 785.06

735.80 61.321

2 Chief Electrician

823.09

686.85

759.97

63.331

2 Electrician

739.84 603.60

660.74 55.061

2 Chief Electronic Technician

823.09

686.85

759,97

63.331

2 Electronic Technician

739.84

603.60

660.74

55.061

2 Senior Sub Sea Sup Dp 1,024.95

888.71

1,000.57

83.381

2 Subsea Supervisor

908.58

772.34

861.87

71.821

2 Master

1,128.61 992.37

943.11 78.591

2 Chief Mate

923.18

786.93

879.27

73.271

2 Bosun

659.36 523.11

564.80 47.073

6 AB Seaman

569.48

1,395.05

506.36

42.202

4 DP Operator

756.02

1,239.55

680.02

56.672

4 Assistant Dp Operator 662.91

1,053.33

569.04

47.423

6 Crane Operator

664.09

1,583.54

570.45

47.541

2 Deck Pusher

713.41

577.17

629.23

52.442

4 Lead Roustabouts

488.99

769.06

410.42

34.209

18 Roustabouts

488.99 3,460.77

410.42 34.201

2 Welder

637.66

501.41

538.94

44.911

2 Senior Materials Coordinator

724.06

587.82

538.56

44.881

2 Material Coordinator 627.00

490.76

526.24

43.851

2 Medic (RSTT)

640.02

503.78

541.76

45.151

2 Radio Operator

562.69

426.45

449.59

37.471

2 RSTC

695.65

559.41

510.15

42.510

0 Offshore Safety Advisor

692.97 —

548.31 45.690

0 —

—

—

—

—0

0 —

—

—

—

—0

0 — — —

— —

69 138

Total Labor Costs = $ 39,591.36

Amendment No. 31


This Amendment is effective as of the 18 day of March 2008, and is issued to BP America Production Company (hereinafter referred to as “COMPANY”) with a place of business at 200 Westlake Park Blvd, Houston, Texas 77079.


WHEREAS, COMPANY and Transocean Holdings LLC (hereinafter referred to as “CONTRACTOR”) entered into Drilling Contract No. 980249 made and effective the 9 day of December, 1998, for the “Deepwater Horizon” (hereinafter referred to as “CONTRACT”), which has been previously amended; and WHEREAS, COMPANY and CONTRACTOR desire to set forth a notice as to the current application to dayrates of Amendment 30 of the CONTRACT as more particularly set forth therein; NOW THEREFORE, CONTRACTOR advises as follows: The Operating Rate (and, consequently, all other dayrates except the Equipment Repair Rate) specified in EXHIBIT A, DAYRATES shall be adjusted as per Article 3 of Amendment No. 30 to the CONTRACT. Accordingly, CONTRACTOR hereby advises COMPANY that the Operating Rate on the Deepwater Horizon shall be $455,592.00 beginning March 18, 2008 and ending June 17, 2008. Additional rates are set forth in the attached EXHIBIT A along with support information for the average dayrate calculation. These rates are auditable as per Amendment 30 of the CONTRACT. Except as changed by this Amendment, No. 31, the CONTRACT as amended shall remain in full force and effect between the Parties. IN WITNESS WHEREOF, the authorized representatives of the Parties have executed this Amendment No. 31 in duplicate originals as of the day and year first above written.

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Transocean Holdings LLCCOMPANY

CONTRACTOR By: /s/ Wilbert Long, Jr.

By: /s/ Jess M. Richards

Wilbert Long, Jr.

Jess M. Richards

Printed Name

Printed Name Title: Head of GoM PSCM

Title: Marketing Manager – North America

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EXHIBIT A

DAYRATES



Cajun Express Discoverer Millennium Discoverer Spirit Discoverer Deep Seas Discoverer Enterprise


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2


Operating Rate $455,592 per day Moving Rate $455,592 per day Standby Rate With Crews $455,592 per day Standby Rate Without Crews $455,592 per day less documented cost savings Stack Rate With Crews $455,592 per day less documented cost savings Stack Rate Without Crews $455,592 per day less documented cost savings Equipment Repair Rate $ -0- Per Day subject to Article 2.2.5(a) Hurricane Evacuation Rate Standby Rates Without Crews plus documented expenses of

evacuated crew

Rig

Actual contracted day rates as calculated onMarch 14, 2008

A

$ 478,238

B

$ 447,379

C

$ 497,198

D

$ 335,146

E

$ 520,000

Average Actual Daily Rate $ 455,592

Amendment No. 38


This Amendment is made and effective on this 28th day of September 2009 by and between BP America Production Company (hereinafter referred to as “COMPANY”) with a place of business at 501 Westlake Park Blvd., Houston, Texas 77079, and Transocean Holdings LLC. (hereinafter referred to as “CONTRACTOR”) with a place of business at 1311 Broadfield Blvd., Houston, Texas 77084. COMPANY and CONTRACTOR may sometimes be referred to herein individually as a “Party” and collectively as the “Parties”.


WHEREAS, by Contract No. 980249 made and effective the 9 December 1998, COMPANY and CONTRACTOR entered into that certain contract for the provision of the Drilling Unit “Deepwater Horizon” and related service, as previously amended by Amendments No. 1 through No. 37 (hereinafter referred to as “Contract”); and WHEREAS, COMPANY and CONTRACTOR desire to further amend the Contract as more particularly set forth herein. NOW THEREFORE, for and in consideration of the mutual covenants and agreements hereinafter provided, COMPANY and CONTRACTOR agree to amend the Contract as follows: 1. The Parties agree to extend the term of the Contract for an additional three (3) years commencing from 12:01 a.m. local time

on September 18, 2010, which date may sometimes be referred to herein as the “Renewal Date”. 2. The Parties agree that with effect from the Renewal Date, the dayrates identified in Exhibit “A”, Dayrates, shall be revised as

follows:

3. The Parties agree that the dayrates specified above will be adjusted in accordance with the adjustment provisions of

Article 2.3.2 of the Contract on the first anniversary of the Renewal Date in respect of the second year of the extended term described in Paragraph 1 above and on the second anniversary of the Renewal Date in respect of the third year of the extended term described in Paragraph 1 above. The cost components specified in sub-paragraphs a-d of Article 2.3.2 from which any revisions are to be based shall be base lined to figures supplied by CONTRACTOR to COMPANY and reflect CONTRACTOR’s cost on the Renewal Date and are to be agreed by the PARTIES within ninety (90) days after the Renewal Date.

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Operating Rate US$497,000.00/day

Moving Rate US$497,000.00/day

Standby Rate With Crews US$497,000.00/day

Standby Rate Without Crews US$497,000.00/day less documented cost savings

Stack Rate With Crews US$497,000.00/day less documented cost savings

Stack Rate Without Crews US$497,000.00/day less documented cost savings

Equipment Repair Rate US$497,000.00/day subject to Article 2.2.5(A)

Hurricane Evacuation Rate Standby Rate Without Crews plus documented expenses of evacuation

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4. With effect from the Renewal Date, existing Articles 21, 22, 23, 24, 25 and 34 of the Contract are to be deleted and replaced

with the following: ARTICLE 21 LIABILITIES AND INDEMNITIES 21.0 As used in this Article 21, the following defined terms shall have the meaning ascribed to them below:

“AFFILIATE” of a company shall mean a current or future person or entity directly or indirectly controlling, controlled by, or under common control with such company. “Control” in this context, in the case of a corporation with outstanding voting stock, shall mean the direct or indirect ownership of a power to vote with respect to outstanding shares of a corporation’s capital stock constituting 50% or more of the votes of any class of such corporation’s outstanding voting stock. “CLAIMS” means all claims, liens, liabilities, fines, penalties, judgments, losses, damages, and expenses (including without limitation legal costs and expenses and other costs of defence), and shall, except as otherwise expressly provided, include claims based on contractual indemnity. “COMPANY GROUP” shall mean COMPANY, the CO-VENTURERS, its and their respective AFFILIATES and its and their respective directors, officers, invitees and employees (including agency personnel), but shall not include any member of CONTRACTOR GROUP. “COMPANY’S MATERIALS” shall mean the equipment, materials, services and supplies to be provided directly or indirectly by COMPANY. “CONTRACT AREA” shall mean the area in which the WORK is to be performed as set out in Article 14.7. “CONTRACTOR’S EQUIPMENT” shall mean the DRILLING UNIT together with the DRILLING EQUIPMENT necessary for the performance of the WORK as listed in Exhibit B – CONTRACTOR EQUIPMENT. “CONTRACTOR GROUP” shall mean CONTRACTOR, SUB-CONTRACTORS, its and their AFFILIATES, its and their respective directors, officers, invitees and employees (including agency personnel), but shall not include any member of COMPANY GROUP or SERVICE COMPANY GROUP provided that if any member of SERVICE COMPANY GROUP is also a SUB-CONTRACTOR it shall be considered, with respect to services performed for CONTRACTOR, to fall within the CONTRACTOR GROUP notwithstanding the definition of SERVICE COMPANY GROUP. “CONTRACTOR’S PERSONNEL” or “PERSONNEL” shall mean CONTRACTOR’S labour and supervisory personnel engaged in the performance of the WORK, as listed in Exhibit F-1, whether directly employed or indirectly employed through a SUBCONTRACTOR. “CO-VENTURERS” as applied to COMPANY shall mean any parties to a joint venture agreement whereby COMPANY undertakes to act as operator for such CO-VENTURERS within the CONTRACT AREA in which CONTRACTOR may be required to perform the WORK. “DEMOBILISATION” shall mean those activities associated with closing down CONTRACT activities in the CONTRACT AREA and moving the DRILLING UNIT off the final location to another location, as may be agreed between the PARTIES, which, upon

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completion, shall cause the CONTRACT scope to have been completed. “DRILLING EQUIPMENT” shall mean the drilling and other drilling related equipment supplied with the DRILLING UNIT as listed in Exhibit BI – Drilling Unit Specifications, Exhibit B2 – Material Equipment List, and any material or supplies to be furnished by CONTRACTOR in Exhibit B-3 – Material, Supplies and Services. “DRILLING UNIT” shall mean the named vessel Transocean Deepwater Horizon, formerly known as the RBS8D. “PARTY” shall mean individually COMPANY or CONTRACTOR and collectively referred to as “PARTIES”. “SERVICE COMPANY” or “SERVICE COMPANIES” shall mean those other companies and persons (including their servants and agents) hired by COMPANY and providing miscellaneous services in conjunction with the WORK. “SERVICE COMPANY GROUP” shall mean any SERVICE COMPANY, its sub-contractors of any tier, its and their AFFILIATES, and its and their respective directors, officers, invitees and employees (including agency personnel), but shall not include any member of COMPANY GROUP or CONTRACTOR GROUP. “SUB-CONTRACTOR” shall mean any company contracted or hired by CONTRACTOR of any tier for the provision of any services in conjunction with the WORK. “SUB-SEA EQUIPMENT” shall mean CONTRACTOR GROUP’s sub-sea and mooring equipment including but not limited to riser, slip joints, control hoses, blowout preventers, anchors, anchor winches, anchor wires and chains, tripping lines and buoys, flex joints, control pods, tensioners and attendant components. “THIRD PARTY” shall mean any party, excluding any member of the COMPANY GROUP or any member of the CONTRACTOR GROUP. “WELL” shall mean a single hole drilled or to be drilled to a pre-defined spatial target located within the CONTRACT AREA, and shall include any remedial deviations or sidetracking required to reach the target. Any action taken to achieve a second spatial target, or after reaching the pre-defined spatial target any re-spudding or side tracking shall be considered a new WELL. “WORK” shall mean the provision of equipment, personnel and services by CONTRACTOR as specified in the CONTRACT.

21.1 CONTRACTOR’S EQUIPMENT

(a) CONTRACTOR shall release, defend, indemnify and hold COMPANY GROUP and SERVICE COMPANY GROUP harmless from and against any and all CLAIMS for loss, damage or destruction of CONTRACTOR’S EQUIPMENT, excepting only damage to or loss of:

i) CONTRACTOR’S in-hole DRILLING EQUIPMENT when in the hole as stated in Sub-article 21.1 (b).

ii) The SUB-SEA EQUIPMENT as stated in Sub-article 21.1 (c).

Notwithstanding the foregoing, COMPANY shall not be liable to reimburse CONTRACTOR for the loss of or damage to CONTRACTOR’s in-hole DRILLING EQUIPMENT and SUB-SEA EQUIPMENT if such loss or damage is due to the sole negligence and/or sole default of CONTRACTOR GROUP and/or a defect in CONTRACTORS EQUIPMENT caused by CONTRACTOR GROUP’s negligence.

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(b) In-hole DRILLING EQUIPMENT

(i) COMPANY shall reimburse CONTRACTOR for the cost of repair or replacement for loss of or damage

(including damage as a result of corrosive properties induced by drilling or completion fluids or geological formation fluids) to its in-hole DRILLING EQUIPMENT while in the hole, less an allowance for depreciation (including, but not limited to drill pipe, drill collars, stabilizers, and subs). The discounted replacement cost factor shall be a percentage of the actual replacement costs, as set out below. Notwithstanding the foregoing COMPANY’S liability in respect of such lost in-hole DRILLING EQUIPMENT shall be limited to US$ 2,500,000 per event.

For the purpose of assessing the discounted depreciated cost for the lost in-hole materials, CONTRACTOR shall use the formula and factors as follows: Discounted Replacement Cost is equal to: [(DR% X Replacement Cost) X (100% - Depreciation Allowance)] + shipping & handling Where:

(DR): Discounted replacement cost factor or start factor as set out in the above table. Select the DR from the column to which standard the equipment (Other than Sub-Sea Equipment) has been inspected.

* if the subject equipment was inspected to Cat 5 inspection then 100% applies and 90% applies if inspected to a lesser standard.

(F): Depreciation Factor is the monthly depreciation percentage from the tables above.

Depreciation Allowance shall mean: F x Number of MONTHS from the COMMENCEMENT DATE. The Depreciation Allowance shall not exceed the maximum depreciation set out in the foregoing table. Shipping and handling costs are from CONTRACTOR’S yard or vendor stocking location to the DRILLING UNIT.

(ii) It is further agreed that in the event of any loss covered under this Sub-article 21.1 (b), COMPANY may, at

its option, obtain a cost estimate for replacement

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OTHER IN-HOLE

DRILL PIPE (DP) DS1-Cat5/ SUB-SEA

Other than

Other than DS1-

EQUIPMENT

Inspection Criteria DS1-Cat5 DS1-CAT5 CAT5

N/AStart

COMMENCEMENT DATE

Start Factor (DR)

100%

90%

100% (Cat 5)/ 90% (Other)*

100%

Depreciation Factor (F)

2%

2%

1%

1%

Max. Depreciation

50%

50%Cap

$2.5M

$10M

of the lost item. Prior to replacement of the item, CONTRACTOR shall submit to COMPANY at least two formal cost quotes (reflecting a detailed description of equipment, price, vendors, vendor representative names, date of quotes, delivery timing, etc.) for the replacement of the lost item. Should COMPANY be able to obtain such replacement of equipment of equal quality at a lesser cost than that which would be paid by the CONTRACTOR, then the CONTRACTOR will have the option of replacing the material at the lesser cost or asking COMPANY to purchase it. Regardless of whether COMPANY or CONTRACTOR actually purchases the replacement material, credit for the percentage depreciation stipulated above will be calculated in accordance with this provision of the CONTRACT; however, the basis for depreciation shall be the lower of the actual price paid by COMPANY for said material or the price actually paid by CONTRACTOR for said material, as applicable.

(c) SUB-SEA EQUIPMENT

COMPANY shall release, defend, indemnify and hold harmless CONTRACTOR GROUP from all CLAIMS for damage to or loss of CONTRACTOR’S SUB-SEA EQUIPMENT while deployed in its normal operating position and shall reimburse CONTRACTOR an amount equal to the then current replacement costs delivered to the DRILLING UNIT, or the repair cost, whichever is the lesser amount, subject to the formula set forth in Sub-article 21.1(b)(i). Notwithstanding the foregoing COMPANY’S liability in respect of such replacement SUB-SEA EQUIPMENT shall be limited to US$10,000,000 per event.

21.2 COMPANY’s MATERIALS

(a) CONTRACTOR shall take all reasonable precautions (including but not limited to the making out of loading notes) to protect and save from loss or damage items of COMPANY’S MATERIALS while in the custody and care of CONTRACTOR. Subject to Sub-article 21.2(b) below when no longer required for the WORK CONTRACTOR shall return surplus COMPANY’s MATERIALS to COMPANY, in the same condition as when handed to CONTRACTOR fair wear and tear excepted.

(b) CONTRACTOR shall not be liable to COMPANY for any loss of or damage to items of COMPANY’S MATERIALS

except where caused by the negligence of CONTRACTOR GROUP. However, CONTRACTOR’S liability hereunder shall be limited to US$ 25,000 (twenty-five thousand US dollars) per occurrence.

21.3 Personnel and Property

(a) Except as provided for under the provisions of Sub-article 21.5 (b) (i), COMPANY shall release, defend, indemnify and hold CONTRACTOR GROUP harmless from and against any and all liability for sickness, injury or death of any THIRD PARTY or the loss of or damage to any THIRD PARTY property and against all CLAIMS resulting therefrom to the extent of any negligent act or default on the part of COMPANY GROUP in the performance of any of COMPANY’s obligations hereunder.

(b) Except as provided for under the provisions of Sub-articles 21.5(a), 21.5 (b)(ii), (iii) and (iv) CONTRACTOR shall

release, defend, indemnify and hold COMPANY GROUP and subject to the provisions of Article 21.11, SERVICE COMPANY GROUP, harmless from and against any and all liability for sickness, injury or death of any THIRD PARTY or the loss of or damage to any THIRD PARTY property and against all CLAIMS resulting therefrom, to the extent of any negligent act or default on the part of CONTRACTOR GROUP in the performance of any of CONTRACTOR’s obligations hereunder.

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(c) Except as provided for under the provisions of Sub-article 21.2 (b), COMPANY shall release, defend, indemnify and

hold CONTRACTOR GROUP harmless from and against any and all liability for loss of or damage to COMPANY GROUP property (including COMPANY’s MATERIALS) and/or the property belonging to, or in the possession of COMPANY GROUP personnel and against any and all liability for sickness, injury, or death to any of COMPANY GROUP personnel arising out of the CONTRACT or in tort and against all CLAIMS resulting therefrom.

(d) Except as provided for under the provisions of Sub-articles 21.1 (b) and (c) CONTRACTOR shall release, defend,

indemnify and hold COMPANY GROUP and SERVICE COMPANY GROUP harmless from and against any and all liability for loss of or damage to CONTRACTOR GROUP property and/or the property belonging to, or in the possession of CONTRACTOR GROUP personnel and against any and all liability for sickness, injury or death to any of CONTRACTOR GROUP personnel arising out of the CONTRACT or in tort and against all CLAIMS resulting therefrom.

21.4 Loss of or Damage to the Hole

COMPANY shall release, defend, indemnify, and hold CONTRACTOR GROUP harmless from and against any and all liability for loss of, damage to, or destruction of the hole (including well equipment) and against all CLAIMS arising therefrom, provided that in the event of CONTRACTOR GROUP’S sole negligence, COMPANY may instruct CONTRACTOR, as its sole remedy, either to drill a new hole to the depth at which the said loss or damage occurred or to re-drill such section of the damaged hole in both instances at the RE-DRILLING RATE and in accordance with the terms of the CONTRACT.

21.5 Underground Damage and Control of Blowout and Pollution

(a) Reservoir Damage

COMPANY shall release, defend, indemnify and hold CONTRACTOR GROUP harmless against any damage to or destruction of or loss or impairment of any property right in or to oil, gas or other mineral substance or water if at the time of the act or omission causing such damage, destruction, loss or impairment the said substance had not been reduced to physical possession above the surface of the sea-bed, and for any loss or damage to any formation strata or reservoir beneath the seabed resulting from operations under the CONTRACT.

(b) Pollution

(i) CONTRACTOR property

CONTRACTOR shall assume all responsibility for, including control, clean-up and removal of and shall release, defend, indemnify and hold harmless COMPANY GROUP and, subject to the provisions of Sub-article 21.11, the SERVICE COMPANY GROUP, from all CLAIMS, howsoever caused and arising for pollution or contamination originating from the DRILLING UNIT from, by way of example, spills of fuels, lubricants, motor oils, pipe dope, paints, solvents, ballast, bilge and garbage. For the avoidance of doubt such pollution or contaminants shall exclude any WELL substances, produced fluids, or substances in the riser or drillstring. It shall include any drilling fluids and other such contaminants stored on the DRILLING UNIT prior to use, wholly in CONTRACTOR’S or its SUB-CONTRACTOR’S possession, care or control.

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(ii) Blow-out, cratering, seepage or uncontrolled release of hydrocarbons

Except as provided for under the provisions of Sub-article 21.5 (b) (i) but subject always to Sub-article 21.5 (b) (iv), COMPANY shall assume all responsibility for, including control, clean-up and removal of and shall release, defend, indemnify and hold harmless CONTRACTOR GROUP from all CLAIMS, howsoever caused and arising in relation to pollution or contamination which may result from fire, blow-out, cratering, seepage, or any other uncontrolled flow of oil, gas, wastes or other substance from any WELL arising out of the CONTRACT.

(iii) Drilling fluids and chemicals

Except as provided for under the provisions of Sub-article 21.5 (b) (i) and (iv), COMPANY shall further assume all responsibility for, including clean-up and removal, of any pollution or contamination arising from the use or disposal of oil emulsion, oil based or chemically treated drilling fluids, produced fluids, contaminated cuttings and cavings, lost circulation materials and fluids as well as the furnishing, transportation and disposal or containerisation of any materials and shall release, defend, indemnify and hold CONTRACTOR GROUP harmless from, all CLAIMS, howsoever arising in respect of such pollution or contamination including control, clean-up and removal operations.

(iv) In the event of pollution or contamination as contemplated in Sub-article 21.5 b) ii) and/or Sub-article

21.5 b) iii) whereby COMPANY incurs a liability in respect of the sickness, injury or death of a THIRD PARTY or the loss of, or damage to, any THIRD PARTY property as a result of CONTRACTOR’S negligence, then CONTRACTOR shall reimburse COMPANY to the extent of CONTRACTOR’s negligence in respect of all such losses or damages incurred by COMPANY up to a maximum aggregate limit of liability of US$10,000,000).

(v) CONTRACTOR shall immediately notify COMPANY of all instances of pollution arising out of operations

hereunder and confirm such notification in writing or by telefax or e-mail to COMPANY within 24 hours of the event.

(c) Blowout and cratering

In the event that any WELL shall blowout or crater from any cause, including, but not limited to, the negligence or breach of duty (statutory, contractual or otherwise) of the CONTRACTOR GROUP, COMPANY shall be responsible for and release, indemnify and hold harmless CONTRACTOR GROUP for all CLAIMS resulting therefrom, and shall bear the entire cost and expense of, killing the WELL or otherwise bringing the WELL under control.

This assumption of liability by COMPANY applies only to the cost of bringing the well under control and does not apply to loss or damage to property or injuries to or death of persons caused by such blow-out or crater and shall in no event alter, lessen or affect the liabilities or responsibilities of CONTRACTOR or COMPANY specified elsewhere in the CONTRACT.

21.6 Sunken Property

When required by AUTHORITY or when CONTRACTOR’S sunken property interferes with present or currently planned operations of COMPANY as may be advised by COMPANY in writing, CONTRACTOR shall at its own expense raise and remove the DRILLING UNIT and any property of CONTRACTOR or its SUB- CONTRACTORS which may sink in the course of operations hereunder. In the event that CONTRACTOR does not carry out these obligations, COMPANY may buoy and light the sunken DRILLING UNIT or property

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and may remove it (without prejudice to COMPANY’S rights) and in such event CONTRACTOR shall refund to COMPANY all costs so incurred. The fact that the sunken DRILLING UNIT or property is insured or has been declared a total loss shall not absolve CONTRACTOR from its obligations to raise and/or remove same. This Article shall remain binding on CONTRACTOR notwithstanding the termination of the CONTRACT for any reason.

The obligations of CONTRACTOR as provided for in Sub-article 21.6 shall cease when the DRILLING UNIT comes under tight tow at the final LOCATION prior to DEMOBILISATION except where COMPANY has previously provided written notice to CONTRACTOR that there is sunken property of CONTRACTOR or CONTRACTOR GROUP that must be removed in accordance with the terms of this CONTRACT.

21.7 Consequential Loss

Notwithstanding any provisions to the contrary elsewhere in the CONTRACT (but without prejudice to Articles 21.1 through 21.6), and except to the extent of any agreed liquidated damages or any termination fees provided for in the CONTRACT, COMPANY shall save, indemnify, release, defend and hold harmless CONTRACTOR GROUP from COMPANY GROUP’S own Consequential Loss and CONTRACTOR shall save, indemnify, release, defend and hold harmless COMPANY GROUP, and SERVICE COMPANY GROUP from CONTRACTOR GROUP’s own Consequential Loss, CONTRACTOR’s obligation with respect to SERVICE COMPANY GROUP shall be subject to the provisions of Sub-article 21.10. For the purposes of this Sub-article 21.7 the expression “Consequential Loss” shall mean any indirect or consequential loss howsoever caused or arising whether under contract, by virtue of any fiduciary duty, in tort or delict (including negligence), as a consequence of breach of any duty (statutory or otherwise) or under any other legal doctrine or principle whatsoever whether or not recoverable at common law or in equity. Without prejudice to the foregoing, “Consequential Loss” shall be deemed to include, also, the following losses, whether direct or indirect or consequential:

(a) loss or damage arising out of any delay, postponement, interruption or loss of production, any inability to produce,

deliver or process hydrocarbons; (b) loss or damage incurred or liquidated or pre-estimated damages of any kind whatsoever borne or payable, under any

contract for the sale, exchange, transportation, processing, storage or other disposal of hydrocarbons; (c) losses associated with business interruption including the cost of overheads incurred during business interruption; (d) or any loss of or anticipated loss of use, profit or revenue, or loss of bargain, contract, expectation or opportunity

(which for the avoidance of doubt shall not include payments due to CONTRACTOR by way of remuneration under this CONTRACT or damages of CONTRACTOR for the loss of this CONTRACT or any profit, revenue, expectation or opportunity thereunder); and

(e) COMPANY GROUP’s spread costs, such as hire or other charges payable to owners of vessels or equipment and the

costs of keeping the COMPANY GROUP’s vessels and equipment and SERVICE COMPANY GROUP equipment and personnel on location or other similar costs; and

(f) any other loss or anticipated loss or damage whatsoever in the nature of or consequential upon the foregoing.

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21.8 Indemnities in their Entirety

It is the PARTIES intention that the release, defense, indemnity and hold harmless obligations provided for in this CONTRACT are to apply:

a) without regard to any conflicting rules of liability under any applicable law or regulation,

b) without regard to any successful limitation or exoneration of liability proceeding filed by or on behalf of either

PARTY or any other person or entity pursuant to the laws of any state or country or the provisions of any international convention, and

c) whether or not the CLAIM is: (1) predicated on negligence, breach of duty (statutory or otherwise) or strict liability

(except as expressly set out in Sub-articles 21,1, 21.2 b), 21.3 a), 21.3 b), 21.4 and 21.5 b) iv)), or (ii) sought directly or indirectly by way of recovery, indemnification, or contribution by any person or entity against either PARTY (or any person or entity to whom indemnity is owed).

The release, defense, indemnity and hold harmless obligations as provided in the CONTRACT shall apply whether or not any injury, death, illness, loss or damage is occasioned by or the result in whole or in part of the negligence or fault, whether sole, concurrent, gross, joint, active, or passive, of either PARTY (or any person or entity to whom indemnity is owed), breach of contract, any theory of tort, strict liability, breach of duty (statutory, expressed, implied or otherwise provided in law or equity), breach of warranty (expressed or implied), or WILFUL MISCONDUCT, products liability or any other theory of liability, or the unseaworthiness of any vessel or unairworthiness of any aircraft, or is the result of any pre-existing condition or other premises liability (patent or latent, known or unknown)„ and shall include, without limitation, any injury, death, illness, loss or damage directly or indirectly arising out or related to ingress, egress, loading or unloading or the presence of any covered person at or on or in transit to or from the CONTRACT AREA or any facility, platform, rig, vessel, aircraft or other premises owned, leased, used, or chartered by CONTRACTOR GROUP, SERVICE COMPANY GROUP or COMPANY GROUP directly or indirectly connected with any WORK under this CONTRACT within the CONTRACT AREA.

“WILFUL MISCONDUCT” shall mean an intentional disregard of good and prudent standards of performance.

21.9 Claims

If either PARTY becomes aware of any incident likely to give rise to a CLAIM under the above indemnities, they shall notify the other and both parties shall co-operate fully in investigating the incident.

21.10 The releases of liability, indemnities, defence, save and hold harmless provisions furnished by CONTRACTOR in Article 21,

and the releases of liability, indemnities, defence, save and hold harmless provisions given by SERVICE COMPANY in COMPANY contracts shall apply:

(a) save as provided below for the benefit of the SERVICE COMPANY GROUP in the case of the releases of liability and

indemnities, defence, save and hold harmless provisions furnished by CONTRACTOR; and,

(b) for the benefit of CONTRACTOR GROUP in the case of the releases of liability and indemnities, defence, save and hold harmless provisions given by the SERVICE COMPANY in COMPANY contracts.

The releases of liability, indemnities, defence, save and hold harmless provisions given by CONTRACTOR in this ARTICLE 21 in favour of SERVICE COMPANY GROUP shall be

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provided by CONTRACTOR on the express understanding that they shall only apply in favour of such SERVICE COMPANIES who have provided substantially similar and reciprocal releases of liability, indemnities, defence, save and hold harmless provisions in favour of CONTRACTOR GROUP in their respective contracts with COMPANY. The releases of liability, indemnities, defence, save and hold harmless provisions provided by CONTRACTOR in this Article 21 in favour of SERVICE COMPANY GROUP shall become effective from such time and for such duration as such SERVICE COMPANIES become bound by substantially similar reciprocal releases of liability, indemnities, defence, save and hold harmless provisions in favour of CONTRACTOR GROUP in their respective contracts with COMPANY. In fulfilment of this objective, COMPANY shall use commercially reasonable endeavours to ensure that in its respective contracts with SERVICE COMPANIES, the releases of liability, indemnities, defence, save and hold harmless provisions contained in such contracts in favour of CONTRACTOR GROUP shall be substantially similar and reciprocal to the releases of liability, indemnities, defence, save and hold harmless provisions given by CONTRACTOR in this Article 21 in favour of SERVICE COMPANY GROUP. In the event that COMPANY is unable to fully fulfil the foregoing objective, then without delay, and in any event prior to permitting such SERVICE COMPANY to travel to the DRILLING UNIT, COMPANY shall notify CONTRACTOR in writing with details of the additional risk being assumed by CONTRACTOR, as soon as is reasonably practicable thereafter and the PARTIES further undertake to meet to discuss ways of minimising the impact of such a notification within the overall requirements of the CONTRACT. Failure by COMPANY to issue such written notification as required herein will constitute a material breach of the terms of the CONTRACT. In the event that COMPANY advises CONTRACTOR that one or more SERVICE COMPANIES have declined to provide substantially similar releases of liability, indemnities, defence, save and hold harmless provisions in favour of CONTRACTOR GROUP in their respective contracts with COMPANY, the PARTIES shall meet to discuss and agree ways of minimising the impact of such additional risks as may be identified by either PARTY which may include: alternative working practices or arrangements to minimise the impact of such risks; a separate mutual hold harmless agreement applicable at the LOCATION or additional compensation to enable CONTRACTOR to insure against such additional risks. The failure of any SERVICE COMPANY to provide substantially similar releases of liability, indemnities, defence, save and hold harmless provisions in favour of CONTRACTOR GROUP in their respective contracts with COMPANY or agree a risk mitigation plan to the satisfaction of CONTRACTOR as provided for herein shall entitle CONTRACTOR to refuse access to the DRILLING UNIT for all such SERVICE COMPANIES and CONTRACTOR shall not be penalised in any fashion by COMPANY.

21.11 Notwithstanding Sub-article 21.10, the failure of one or more SERVICE COMPANIES to provide substantially similar releases

of liability, indemnities, defence, save and hold harmless provisions in favour of CONTRACTOR GROUP in its respective contracts with COMPANY as envisaged herein shall cause such SERVICE COMPANIES to be considered a THIRD PARTY for the purposes of this CONTRACT.

ARTICLE 22 NOT USED ARTICLE 23 NOT USED ARTICLE 24 NOT USED

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ARTICLE 25 NOT USED ARTICLE 34 NOT USED

5. With effect from the Renewal Date, the following new Articles 36 and 37 (together with Attachment 1 referenced in Article 36), are to be inserted as follows:

ARTICLE 36 BUSINESS ETHICS

COMPANY wishes to make it clear that it intends its business dealings to be characterised by honesty and freedom from deception and fraud and that it finds unethical behaviour unacceptable. Practices that COMPANY considers dishonest, unethical or unacceptable are listed in Attachment 1 – CODE OF CONDUCT and are set out in further detail in the document entitled “Our commitment to integrity” (hereafter referred to as the “BP Code of Conduct”) a copy of which may be obtained using the web link highlighted in Attachment 1 - CODE OF CONDUCT. CONTRACTOR shall review the BP Code of Conduct. In connection with the performance of this CONTRACT, CONTRACTOR undertakes and agrees to act consistently with the principles of the BP Code of Conduct and refrain from practices that COMPANY considers dishonest, unethical or unacceptable, as set out in Attachment 1- CODE OF CONDUCT.

ARTICLE 37 ANTI-CORRUPTION UNDERTAKINGS 37.0 “COUNTRY OF OPERATIONS” shall mean the country in which the WORK is to be performed as set out in CONTRACT

SCHEDULE. COUNTRY OF OPERATIONS shall encompass the CONTRACT AREA.

37.1 CONTRACTOR and COMPANY each agree and undertake to the other that in connection with this CONTRACT and the transactions contemplated by this CONTRACT, they will each respectively comply with all applicable laws, rules, regulations, decrees and/or official governmental orders of the United Kingdom, the United States of America and the COUNTRY OF OPERATIONS relating to anti-bribery and anti-money laundering.

37.2 CONTRACTOR agrees, undertakes and confirms that, in connection with the transactions contemplated by this CONTRACT, it

and each of its AFFILATES and its and their respective directors, officers, employees and persons acting within their scope of authority on behalf of them, have not, made, offered or promised to make, and will not make, offer, or promise to make, any payment or other transfer of anything of value, including without limitation the provision of any service, gift or entertainment, directly or indirectly

(a) to any government official (including directors, officers and employees of government-owned and government-

controlled companies and public international organizations);

(b) to any director, officer or employee of COMPANY or its CO-VENTURERS or any of its or their AFFILIATES; (c) to any political party, official of a political party, or candidate for public office; (d) to an agent or intermediary for payment to any of the foregoing; or

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(e) to any other person or entity

for the purpose of obtaining or influencing the award of or carrying out this CONTRACT if and to the extent that to do so is or would be either, in violation of or inconsistent, in any material way, with the anti-bribery or anti-money laundering laws of any relevant jurisdiction, including, without limitation, the U.S. Foreign Corrupt Practices Act, the U.K. Anti-Terrorism, Crime and Security Act 2001 and successor legislation, the applicable country legislation implementing the OECD Convention on Combating Bribery of Foreign Public Officials in International Business Transactions and/or the anti-corruption laws of the COUNTRY OF OPERATIONS.

For the purposes of this Article 37, the term “government official” shall mean any director, officer or employee of any government or any department, agency or instrumentality thereof, and/or of any enterprise in which a government owns an interest, and/or of any public international organization. This term also includes any person acting in any official, administrative or judicial capacity for or on behalf of any such government or department, agency, instrumentality, COMPANY, or public international organization.

37.3 CONTRACTOR agrees and undertakes that in connection with this CONTRACT and in connection with any other business

transactions involving COMPANY GROUP and CONTRACTOR in the COUNTRY OF OPERATIONS, CONTRACTOR and each of its Affiliates shall:

a) have and will apply effective disclosure controls and procedures; and

b) have and will maintain books, records, and accounts which, in reasonable detail, accurately and fairly reflect the

transactions undertaken and the disposition of assets; and c) have and will maintain an internal accounting controls system that is sufficient to ensure the proper authorization,

recording and reporting of all transactions and to provide reasonable assurance that violations of the anticorruption laws of the applicable jurisdictions will be prevented, detected and deterred.

37.4 In the event that COMPANY has any reasonable basis for a good faith belief that CONTRACTOR and/or any of its Affiliates

may not be in compliance, in any material way with the undertakings and/or requirements set forth in Sub-articles 37.1, 37.2 and/or 37.3, then COMPANY shall advise CONTRACTOR in writing within fourteen (14) days of it first becoming aware of such a possibility, and CONTRACTOR shall thereafter cooperate fully with any and all enquiries undertaken by or on behalf of COMPANY in connection therewith, including the provision by CONTRACTOR of personnel and supporting documents and affidavits if reasonably deemed necessary by COMPANY.

37.5 COMPANY shall have the right to terminate this CONTRACT with immediate effect:

(a) with respect to breach or non-fulfillment of CONTRACTOR’S agreements, duties and undertakings in Sub-article 37.2; or (b) with respect to a material breach by CONTRACTOR in connection with the CONTRACT in the performance of its

obligations set out in Sub-Articles 37.1 and 37.3 which results in a material adverse effect on COMPANY;

provided however, that COMPANY shall have provided CONTRACTOR with written notice of its intention to terminate the CONTRACT under the provisions of this Article 37 together with the reasons therefore and that CONTRACTOR has been unable within thirty (30) business days of delivery of such notice to provide COMPANY with evidence which reasonably demonstrates that CONTRACTOR has not failed to comply with or

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fulfill any of the foregoing agreements, undertakings or requirements. Termination shall, except as provided in this Sub-article 37.5, represent COMPANY’s sole and exclusive right of recourse against CONTRACTOR, whether under this CONTRACT or otherwise at law Notwithstanding termination of this CONTRACT pursuant to this Sub-article 37.5, CONTRACTOR agrees to indemnify and hold harmless COMPANY and its affiliates and their respective officers, directors and employees, from the cost of any fines assessed by any AUTHORITY on such persons or entities as a result of any breach by CONTRACTOR of the provisions of Sub-articles 37.1 to 37.5 and 37.8.

37.6 In the event of termination in accordance with the provisions of this Article 37, COMPANY shall make payment to

CONTRACTOR for the WORK performed up to the time at which COMPANY terminated the CONTRACT and such other payments as may be due in respect of such termination as described in Exhibit A – DAYRATES.

37.7 Any dispute arising hereunder as the result of COMPANY exercising its rights under Sub-article 37.5 hereof shall be settled in

accordance with the provisions of Article 35.4 – ARBITRATION. 37.8 CONTRACTOR shall endeavour that the foregoing provisions (or substantially equivalent provisions) are included in all its

sub-contracts entered into for the purpose of conducting the WORK hereunder.

6. With effect from the Renewal Date, delete the existing text of Exhibit D and insert new Exhibit D, HSSE Requirements, incorporating the attached terms marked as “Exhibit D”.

7. With effect from the Renewal Date, delete the existing text of Exhibit B-2 and insert new Exhibit B-2, material equipment

list, incorporating the attached terms marked as “Exhibit B-2”. The Parties expressly agree that the following items are owned by CONTRACTOR, are dedicated to the DRILLING UNIT and will be available at COMPANY’s request, and once deployed to the DRILLING UNIT shall form a part of CONTRACTOR’s EQUIPMENT, but any costs associated with maintenance, inspection and replacement of said items, which will be incurred at COMPANY’s sole discretion, shall be borne by COMPANY, notwithstanding any provision of the contract to the contrary:

14,000 feet of 6-5/8” drill pipe 32.6 ppf S-135 FH R3 4,000 feet of 6-5/8” drill pipe 40 ppf S-135 FH R3 8,000 feet of 5” drill pipe 19.5 ppf S-135 4 / ” IF R3

8. With effect from the Effective Date, delete the existing text of Exhibit F-1 and insert new Exhibit F-1, PERSONNEL,

incorporating the attached terms marked as “Exhibit F-1”. The Parties expressly acknowledge that the adoption of the replacement Exhibit F-1 by this Amendment No. 38 is without prejudice to the rights of the Parties under the Contract, including without limitation COMPANY’s rights under Letter of Agreement dated April 19, 2004, Subject: Contract Extension Agreement (“AGREEMENT”) Contractor-5121-2002-011. The Parties further agree that the adoption of the replacement Exhibit F-1 by this Amendment No. 38 shall serve to extinguish the rights and obligations of the Parties pursuant to the Letter of Agreement dated February 20, 2005, Reference No. “CONTRACTOR 5121 — 2002 — 011” in respect of the furnishing of two (2) additional Deck Pushers.

Except as expressly changed by this Amendment No. 38, the Contract shall remain in full force and effect.

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1 2

IN WITNESS WHEREOF, the authorized representatives of the Parties hereto have executed this Amendment No. 38 in duplicate originals as of the date and year first above written. BP AMERICA PRODUCTION COMPANY COMPANY

TRANSOCEAN HOLDINGS LLC CONTRACTOR

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By: /s/ Wilbert Long Jr.

Wilbert Long Jr.

Printed Name

Title: CPO GoM

By: /s/ Keelan Adamson

Keelan Adamson

Printed Name

Title: Managing Director - North America

ATTACHMENT 1 — CODE OF CONDUCT

The BP code of conduct stands for a fundamental BP commitment — to comply with all applicable legal requirements and the high ethical standards set out in this code — wherever we operate. To help us meet this commitment, the code defines what BP expects of its businesses and people regardless of location or background. It provides both guidance in key areas and references to more detailed standards, instructions and processes for further direction. All employees must adhere to the principles and requirements contained in this code and should consult the code for guidance when acting on behalf of BP. Employees must not use a contractor, agent, consultant or other third party to perform any act which conflicts with this Code. Employees who engage third parties such as contractors, agents or consultants to work on behalf of BP are required to gain a commitment from such parties that they will support the principles of this Code, including a contractual requirement to act consistently with the Code when working on our behalf. BP wishes to make it clear that it intends its business dealings to be characterised by honesty and freedom from deception and fraud and that it finds unethical behaviour unacceptable. Practices that BP considers dishonest, unethical or unacceptable include the following: • Fraud, bribery or corruption • Deception; • Clandestine brokering or sharing of tender information; • Collusion for the purpose of corrupting a competitive tender; and • Payments, gifts or entertainment from suppliers to BP staff, agents or representatives to influence decision-making. • Harassment in the Workplace BP is committed to ensuring that its contractors apply the applicable principles contained within the “Code of Conduct” document. BP will endeavour to employ only those contractors that subscribe to these principles, demonstrate their commitment to working towards their fullest application, and agree to the measurement of their performance by BP. The individual rights are intended to lead to greater mutual respect between both individuals and the companies they work for. They seek to encourage safer and more secure employment, increase efficiency, improve job satisfaction and provide a better trained workforce for all those engaged in the provision of Services under the Contract. An electronic copy of BP’s Code of Conduct “Commitment to Integrity” can be downloaded from the following internet web site:

A-128

15

http://www.bp.com/sectiongenericarticle.do?categoryld=9003494&contentld=7006600

Where to go for help If you do have a question or concern about legal or ethical standards, what, as a Contractor, should you do? A good place to start Contacting the BP Representative/Contract Accountable Manager named in Section 1 of the Contract is usually a good place to start with a legal or business conduct issue. You may also get help or advice from your own legal or compliance & ethics advisors within your own company. The BP OpenTalk line If you feel unsure about where to go for help, or are uncomfortable contacting the Contract Accountable Manager, BP has an additional resource that can help — OpenTalk. The purpose of OpenTalk is to answer questions and respond to concerns about compliance, ethics and the requirements described in this code. The OpenTalk telephone line and e-mail facility is operated by an independent company that helps businesses respond to questions and concerns about compliance and ethics. The line operates 24 hours a day/seven days a week and also has translation services available at all times. Call OpenTalk on your local number or on 0800 917 3604 (UK), 1-800 225-6141 (US), or the collect call number 1 704 540 2242. or at the following: A full list of local telephone numbers can be accessed on the OpenTalk website http://opentalk.bpweb.bp.com or you can e-mail the following address [email protected]

A-129

16

EXHIBIT B-2

MATERIAL EQUIPMENT LIST SEPTEMBER 28, 2009

A-130

A. Unit Specifications

General

Unit Name

:

Deepwater Horizon (RBS8D) Rig Type

:

Semi-SubmersibleUnit/Design/Shape

:

IHI-RBF Exploration Unit Flag

:

marshall islandsUnit Classification :

ABSIMO Certification (yes/no)

:

YesWhich code Version :

1989 as Amended 1991 Year of Construction

:

2000Construction Yard

:

HyundaiType of Positioning System (anchor /Dp /combined)

: DPS-3 A.1 Main Dimensions/Technical Description

Weight (lightship) mt:

25,539Overall Width

ft:

255.9Overall Length

ft:

396.0Main Deck Width

ft: 200.1Main Deck Length

ft:

267.4Main Deck Depth ft:

27.9Number of Main Columns / Diameter (L x B)

No x ft:

4 / 49.2 x 49.2 (Top); 45.9 x 57.4 (Bottom) Number of Small Columns / Diameter

No x ft:

0Drilling Draft / Related Displacement

ft x mt:

75.5 x 52,589Transit Draft / Related Displacement

ft x mt: 28.9 x 36,036Survival Draft / Related Displacement

ft x mt:

54.1 x 44,305Moonpool Dimensions ft x ft:

21 x 93Maximum Opening Through Spider Deck

ft:

N/APontoon Length ft:

374.0Pontoon Breadth (ends/middle)

ft:

57.4/50.9Pontoon Height

ft:

29.9Accommodation for Maximum No. of Personnel

Qty: 146 A.2 Storage Capacities

Fuel

bbls:

27,855 (98%)Drill Water bbls:

13,076Potable Water

bbls:

7,456Active Liquid Mud (see F.2)

bbls:

4,141 (90%)Mud Processing Tank (see F.2)

bbls: 464Reserve Liquid Mud (see F.2)

bbls:

10,304 (100%)Bulk Bentonite/Barite (see F.3)

cu ft:

13,625 (100%)Bulk Cement (see F.3)

cu ft:

8,175 (100%)

A-131

Sack Storage

No. or ft2:

10,000 sacksPipe Rack Area

ft2:

9,367Load Bearing Capacity Ib/ft2:

500Riser Sack Area

ft:

10,000Load Bearing Capacity Ib/ft2:

700Miscellaneous Storage Area

ft2:

See DrawingBrine Storage (Column)

bbls:

5,136 (100%)Brine Storage (Pontoon)

bbls:

25,000Base Oil Mud Storage

bbls:

5,033 (98%)Ballast System bbls:

140,550 (incl. Pontoon brine tanks) A.3 Propulsion / Thrusters

Thruster/Type (azimuth/in line)

:

Azimuth - Full 360Quantity

:

8Location (aft, opposite corners, 4 corners)

: 4 CornersDriven by Electric Motor (yes/No)

:

Yes - Variable Speed Drive Make/Type :

KamewaPower Output (HP EA.)

:

7375 hp (5500 kw)Propeller Type(Fixed / Variable Pitch) :

FixedNozzled (yes/no)

:

Yes (w/5o down tilt)Thruster Power (HP Total)

:

59,000 (44 MN) DP System

:

‘Class III Kongsberg-Simrad Dynamic Positioning System in accordance with ABS DPS-3 requirements and recommendations. System consists of a triple redundant dynamic positioning system and shall accept inputs from Hipap Acoustic Positioning System, four (4) different GPS (DGPS) based on correction signal inputs from different sources, (3) three gyrocompass, (3) three vertical reference units, and (3) three wind sensors, as well as operator input. Power Management System is interfaced with the Integrated Alarm & Control System.

Position Reference

:

Kongsberg-Simrad Hipap & DGPS

A-132

:

Kongsberg-Simrad IACS will operate as the System Control & Data acquisition system for the MODU. The IACS will perform several different functions including: Power Management System, Machinery Monitoring & Control, Manual Thruster control and Autopilot, Dynamic Positioning Control, Ballast & Bunker Monitoring & Control, Bulk Storage Sys. Monitoring & Control, Safety Sys. (Fire, Gas, WT Doors, HVAC Control, etc.)

A-4 Operational Capabilities

Maximum Designed Water Depth Capability ft:

10,000 Outfitted Max. Water Depth Capability

ft:

8,000Normal Min. Water Depth Capability

ft: 250Drilling Depth Capability (Rated)

ft:

30,000Transit Speed Towed (Historical Avg.)

Knots:

4.5Transit Speed Self-Propelled (Historical Avg.)

Knots:

7.5 A-5 Variable Loading (VL)

Transit VL

mt:

See Exhibit B-1Drilling VL mt: See Exhibit B-1Survival VL

mt:

See Exhibit B-1 A-6 Environmental Limits

Drilling (including stationkeeping)

:

See Exhibit B-1 Air Gap

ft:

32.8Sign. Wave Height ft: 26Max. Wave Height

ft:

48.2Spec. Peak Period

see:

Pierson-Moskowitz Spectrum Max. Wind Velocity

knots:

60 (1 min.)Max Current Velocity

knots:

See Exhibit B-1Max. Heave (Drill Floor Center)

ft:

6-7 (D.A.)Max. Pitch

degrees:

2-3 (S.A.)Max. Roll degrees: 2-3 (S.A.)Survival (excluding stationkeeping)

Air Gap

ft:

54.2Sig. Wave Height

ft:

41Max. Wave Height

ft:

72.2Spec. Peak Period

sec:

15Max. Wind Velocity

knots:

103 (1 min.)Max. Current Velocity knots: 3.5Max. Heave (Drill Floor Center)

ft:


degrees:

6.5 (S.A.)Max. Roll

degrees:

6.5 (S.A.)

A-133

Transit (field move)

Air Gap

ft:

79.4Sign. Wave Height

ft:

16-21Max. Wave Height

ft:

30 - 40Max. Wave Period

sec:

8-12Max. Wind Velocity

knots:

50Max. Current Velocity

knots:

3.5Max. Heave

ft:


degrees:

9.0 (S.A.)Max. Roll

degrees:

9.0 (S.A.)Derrick Loading

kips:

Empty * See derrick loading capability in Operations Manual.

A.7.1 Anchor Winches

Quantity no.: 0Make

:

Type (electric/hydraulic/diesel)

:

Rated Pull

mt:

Speed Low Gear

ft/m:

Test Load

:

Control Locations (Local/Remote/Both)

:

Emergency Release (Type/Location) : A.7.2 Fairleads

Quantity

no.:

Columns structually enhanced for future fairleads Make

:

Free Rotating Range

degrees:

A.7.3 Anchors : Company Supplied.A.7.3.1 Anchors - Primary

:

Company Supplied.A.7.3.2 Anchors - Spare

:

Company Supplied. A.7.4 Anchor Lines

:

Company Supplied, to be installed at a later date A.7.5 Anchor Line Running/Retrieval System

A.7.5.1 Pennant Lines : N/AA.7.5.2 Anchor Buoys

:

N/AA.7.5.3 Chaser

:

N/A A.7.6 Towing Gear

Towing Bridle Size

inches:

0Hook-Up System : Air Winch, Ingersoll Rand FA5A Rating

mt:

682Power Required for Infield Tow

Bollard Pull:

N/APower Required for Ocean Tow

Bollard Pull:

N/ASpare Bridle

yes/no:

No

A-134

A.7.7 Supply Vessel Mooring Lines

Quantity

no.:

2 eachSystem

mt:

Southwest Ocean Services, 180’x40’Rating

lbs.:

Surge Force, 22,700 lbs. A.8 Marine Loading Hoses

:

BothLocation of Loading Manifolds (port/stbd./both)

A.8.1 Potable Water Hoses

Quantity

no.:

2 x 150’ (50’ lengths) Size

inch:

3Make/Type

:

Goodall SS290Color Coding

yes/no:

YesMake/Type/Connection

:

Weco, 250 psi WP A.8.2 Drilling Water Hose

Quantity

no.:

2 x 150: (50’ lengths) Size

inch:

5Make/Type

:


yes/no:


:

Weco 300 psi WP A.8.3 Gas Oil Hose

Quantity

no.:

2 x 150’Size

inch:

4Make/Type

:


yes/no:


:

TODO, 300 PSI WPPressure Rating psi: 300 A.8.4 Mud Chemical Hose

Quantity

no.:


inch:

6Make/Type

:


yes/no:

YesMake/Type/Connection : TODO 300 PSI WP A.8.5 Cement Hose

Quantity

no.:


inch:

6Make/Type

:


yes/no:

YesMake/Type/Connection : Weco 120 PSI WP A.8.6 Base Oil Hose

Quantity

no.:


inch:

4Make/Type

:

Color Coding

yes/no:

Yes Make/Type/Connection : TODO

A-135

Pressure Rating

:

300 PSI WP A.8.7 Brine Hose

Quantity

no.:


inch:

4Make/Type

:


yes/no:


:

WecoPressure Rating

:

500 PSI WP A.9 Cranes, Hoists, & Material Handling

A.9.1 Cranes, Revolving, Main

Quantity

no.:

2Specification (API, etc.) : ABS/US-DenMake

:

LiebherrType

:

PedestalLocation (stbd, port, aft, fwd)

:

Port & Stbd.Maximum Rated Capacity (main hook)

mt:

100Maximum Rated Capacity (whip hook)

mt:

15Boom Length

ft:

150Line Length (Nominal Boom Length) ft: 1,893• Main Boom

ft:

1,920• Whip Line

ft:

475

Main Hoist, Platform Lift, 4 Lines

Radius Meters

Metric Tons

6.6

92

10 92

11

80

15

75

20

65

25

50

30 40

35

36

40 30

45

26

48

23.7

No Load Main Hoist, Seastate Lift, 4 Lines

Radius Meters

Metric Tons

6.6 51.5

10

46

11

44.8

15

40.7

20

36.8

25 33.5

30

30.6

35 26.4

40

22.4

45

19.4

48

18

No Load

A-136

Main Hoist, Platfrom Lift, 4 Lines Radius Meters Metric Tons

6.6 92

10

92

11 80

15

75

20

65

25

50

30

40

35 36

40

30

45 26

48

23.7

No Load Main Hoist, Seastate Lift, 4 Lines

Radius Meters

Metric Tons

6.6

51.5

10 46

11

44.8

15

40.7

20

36.8

25

33.5

30 30.6

35

26.4

40 22.4

45

19.4

48

18

No Load

Radius Meters

Metric Tons Whip Line

51

15Platform Lift

51

10Seastate Lift

No Load

A-137

yes/no:

YesHook Load Indicator Automatically Corrected for Boom Angle

:

Both

Alarm (audible, visual, both)

yes/no:

YesAutomatic Brake

yes/no:

YesSafety Latch on Hooks

yes/no:

YesCrown Saver (limit switch)

yes/no:

YesBoom Illumination

no.:

2Baskets for Personnel Transfer

A.9.2 Cranes, Revolving, Secondary

Quantity

no.:

1Specification (API, etc.)

:

APIMake : OutreachType

:

Knuckle boomLocation (stbd., port, aft, fwd.)

:

ForwardMaximum Rated Capacity (main hook)

It.:

SWL 4000 KG/ 8800 lbs 14.6 meters / 47.9 ftMaximum Rated Capacity (main hook)

It.:

SWL 3000 KG/ 6600 lbs 21meters / 68 ftBoom Length

ft.:

68Line Length (nominal)

ft.:

N/A A.9.3 Forklifts

Quantity

no.:

1Make/Type

:

Stewart & StevensonRated Capacity

lbs.:

5000Location

:

Sack Room A.9.4 Monorail Overhead Cranes Quantity

no.:

1Make

:

HydraliftType

:

Gantry TypeRated Capacity

mt:

37 (18.5x2)Location

:

Aft Riser Deck A.9.5 BOP Handling System : Hydralift Bridge Crane Make/Type

mt:

310Rated Capacity

BOP Carrier

Make/Type

:

Hydralift “C” Cart complete w/false rotary deckRated Capacity

mt:

310 A.9.6 Air Hoists/Derrick Winches

A.9.6.1 Rig Floor Winches (Non Man-Riding)

Quantity

no.:

4Make

:

Ingersoll Rand

A-138

Type

:

AirRated Capacity

st:

5.5Wire Diameter inch: 0.75Automatic Brakes

yes/no:

YesOverload Protection yes/no: NoAutomatic Spooling

yes/no:

Yes A.9.6.2 Monkey Board Work Winch

Quantity

no.:

1Make : Ingersoll RandType

:

AirRated Capacity st.: 0.25Wire Diameter

inch:

3/8”Automatic Brakes

yes/no:

YesOverload Protection

yes/no:

No A.9.6.3 Rig Floor “Man-Riding” Winch

Quantity no.: 2Make

:

Ingersoll RandType

:

AirRated Capacity

st.:

0.25Wire Diameter/Non-twist Wire

inch:

3/8”Automatic Brakes yes/no: YesOverload Protection

yes/no:

NoAutomatic Spooling yes/no: YesCertified for Man-Riding

yes/no:

Yes A.9.6.4 Utility Winch (i.e. Deck Winch)

A.9.6.5 Cellar Deck Winch

Quantity

no.:

4Make : Ingersoll RandType

:

AirRated Capacity

st.:

5.5Wire Diameter

inch:

0.75Automatic Brakes

yes/no:

NoOverload Protection

yes/no:

NoAutomatic Spooling

yes/no:

YesMan-Riding : 2 A.10 Helicopter Landing Deck

Location

:

Port/Fwd - Main Deck Dimensions

ft.xft.:

72.8 x 72.8Perimeter Safety Net

yes/no:

YesLoad Capacity

It.:

11.9Designed for Helicopter Type : Sikorsky S-92Tie Down Points

yes/no:

YesCovered by Foam Fire System (See L.36)

yes/no:

Yes

A-139

A.10.1 Helicopter Refueling System

Fuel Storage Capacity

US Gal.:

2,250 (750x3)Jettisonable yes/no: NoFuel Transport Containers

Qty.:

3Volume (ea) : 750Covered by Foam Fire System (See L.3.5)

yes/no:

Yes A.11 Auxiliary Equipment

A.11.1 Water Distillation

Quantity

no.:

6Make/Type : Alfa-LavalCapacity (each/total)

cu.ft./day:

20 Metric Tons Ea. (Depending on Engine Utilization) A.11.2 Broilers

:

N/A A.11.3 Air Conditioning

Quantity

no.:

4 Air Handlers, 6 Compressor/CondensersMake/Type : CarrierCapacity (Total System)

tons:

200 A.11.4 Electric Welding Sets

Quantity

no.:

3Current Capacity amp: 400Make / Type

:

Lincoln S-7046 SAE 400 A.11.5 High Pressure Cleaner

Quantity

no.:

2Make/Type

:

UnitorElectric/Pneumatic

:

ElectricMax Delivered Pressure PSI: 1600Ring Main

yes/no:

YesOutlets Number: 6 B. General Rig Description

B.1 Derrick & Substructure

B.1.1 Derrick / Mast

Make/Type : DrecoRated for Wind Speed

•With Full Set Back

Knots:

60/71 (GOMEX/WOS) •With No Set Back Knots: 103/99 (GOMEX/WOS) Height

ft.:

242 (drill floor to top of gin pole) Dimensions of Base ft.xft.: 48x48Dimensions of Crown

ft.xft.:

18x18Gross Nominal Capacity

st.:

1000Maximum Number of Lines

no.:

14,1 Spare Sheave Fitted in cluster Ladders w/Safety Cages & Rests

yes/no:

YesPlatform for Crown Sheave Access yes/no: Yes

A-140

Counter Balance, System for Rig Tongs & Pipe Spinning Tong

yes/no:

Yes

Lighting System Explosion Proof

yes/no:

Yes B.1.2 Racking Platform

Unit is capable of field transiting with 238 stands of drill pipe w/o exceeding rated design loads of the derrick.

Make/Type

:

VarcoRacking Platform Total Capacity w/5-12/” or 6-5/8 D.P.

ft.:

31,000 (nominal) Fixed Fingers (on left side of derrick) - up to 6-5/8 D.P. ft.: 20,000 (nominal) Adjustable Fingers (on right side) - 7” Casing

ft.:

11,000 (nominal) or

Adjustable Fingers (on right side) - 9-5/8” Casing

ft.:

11,000 (nominal) or

Adjustable Fingers (on right side) -13-3/8” or 13

ft.:

9,500 (nominal) Racking Platform Capacity of 8” - 9” DC no.: 8 Auxiliary Derrick (Moonpool)

Make/Type

:

DrecoCapacity

:

300 Tons B.1.3 Automatic Pipe Racker

Make/Type : 2 - Varco RPS-6i Pipe Rackers Pipe racker on fwd. Side to be capable of handling 20”, 16”, 13-5/8”, 11-3/4”, 9-7/8”, 9-5/8” 7-5/8” & 7” casing.

B.1.4 Casing Stabbing Board

Make/Type

:

Dreco/Hyd.Adjustable from/to Height Above R/Table

ft./ft.:

Adjustable Casing Stabbing Basket - 28’ Reach Auxiliary Pipe Handler (Moonpool)

Make/Type : National - Casing/Tubular Horizontal to Vertical Rotator B.1.5 Substructure

Make/Type

:

HHIHeight

ft.:

14.75Width

ft.:

80Length

ft.:

71Setback Capacity st.: 1,000Hookload

st.:

1,000Simultaneous Setback-Hookload Capacity

st.:

2,000

A-141

Tensioner Capacity

st.:

1,750Clear Height Below Rotary Table Beams(from 3rd deck)

ft.:

29.5 B.1.6 Weather Proofing

Rig Floor Windbreaks Height ft.: 11.5Derrickman Windbreaks Height

ft.:

none B.1.7 Derrick TV Camera System

Camera Located at

:

Monkey Board/Crown Make/Type : ColorZoom/Pan/Tilt-Function

yes/no:

YesMonitor Located at : Driller’s House B.2 Drawworks & Associated Equipment

B.2.1 Drawworks

Make/Type : Hitec/AHD 1000Drum Type

:

Lebus Grooving 2” Drill Line Spinning Cathead Type : N/ABreakout Cathead Type

:

N/ACrown Block Safety Device

:

YesMake

:

Hitec/SDIModel

:

Hitec/SDIRated Input Power Continuous hp: 6900Rated Input Power Maximum

hp:

8400Drum Diameter inches: 73.5Maximum Line Pull 14 Lines

st:

1,000 (intermittent)Maximum Line Pull 12 Lines

st:

880Maximum Line Pull 10 Lines

st:

750Maximum Line Pull 8 Lines

st:

600Independent Freshwater Cooling System for Drawworks yes/no: Yes B.2.2 Drawworks Power

Number of Electric Motors

no.:

6Make

:

General ElectricModel

:

GEB22A1Output Power Continuous

hp:

1150Output Power Intermittent (max.)

hp:

1400 B.2.3 Auxiliary Brake

Make

:

HitecModel

:

Regenerative AC braking: A11 6 Motors. Motors are split in to two groups w/redundant master controllers and automatic control transfer in case of failure of primary controller.

Independent Back-up System Type

:

Failsafe Disc Brakes

A-142

B.2.4 Sandline

:

N/A B.2.5 Automatic Driller

Make/Type

:

Hitec Auxiliary Drawworks (Moonpool)

Make/Type

:

HitecLift Capacity

mt:

300Input HP

:

1000 B.3 Derrick Hoisting Equipment

B.3.1 Crown Block

Make/Type

:

DrecoRated Capacity

st:

1000No. of Sheaves : 7 Sheave Cluster, Plus Dual In-Line Sheaves on

Fastline & Deadline. Sheave Diameter

inch:

72Sheave Grooved for Line Size inch: 2 Auxiliary Crown Block (Moonpool)

Make/Type

:

DrecoRated Capacity

mt:

300 B.3.2 Traveling Block

Make/Type : ShafferRated Capacity

st:

1000 on 14 LinesNo. of Sheaves

no.:

8Sheave Diameter

inches:

72Sheave Grooved for Line Size

inch:

2 Auxiliary Traveling Block

Make/Type : DrecoRated Capacity

mt:

300 B.3.3 Hook

Make/Type

:

Varco / Rotating Hook Adapter Rated Capacity

st:

1000Complete w/Spring Assembly / Hook

yes/no:

Yes. Active Counter Balance w/Stand, Jump &Locking Device

Hydraulic Locking Device. B.3.4 Swivel

Make/Type

:

Integrated in TDSRated Capacity

st:

N/ATest/Working Pressure

PSI/PSI:

N/AGooseneck & Washpipe Minimum ID >=76mm

yes/no:

N/A Left-hand Pin Connection Size inches: N/AAccess Fitting for Wireline Entry on Top of Gooseneck

yes/no:

N/A

A-143

B.3.5 Drilling Line

Diameter

inch:

2”Type : 6x26 EIPS, IWRC Powersteel Plus Length (original)

ft.:

12500Support Frame for Drum/Cover yes/no: yesDrilling Line Drum Power Driven

yes/no:

yesSpare Reel Drilling Line

yes/no:

noLocation (rig, shore, etc.)

:

N/A B.3.6 Anchor Dead Line

Make/Type

:

Dreco/FRH-160CRWeight Sensor yes/no: Yes B.3.7 Drill String Motion Compensator

Make/Type

:

Hitec ASA Active Heave Comp. Stroke

ft.:

13.7Capacity - Compensated st: 500Capacity - Locked

st:

1000 B.3.8 Block Guidance System

Make/Type

:

Dreco B.3.9 Retraction System for Traveling Block

Make/Type : Shaffer/Retract Dolly B.4 Rotating System

B.4.1 Rotary Table

Make/Type

:

Varco / RST 60-1/2”Maximum Opening

inches:

60-1/2”Rated Capacity st: 1000Static Load Capacity

st:

1000Rotating Load Capacity st@rpm: 37.5 Ton @ 10 rpmTwo Speed Gearbox

yes/no:

NoMax RPM @ Max Torque

RPM/Ft.Lbs.:

25/48,000Emergency Chain Drive

yes/no:

NoDriven by an Independent Electric Motor

yes/no:

NoElectric Motor Type/Make

:

Hydraulic x 4Maximum Continuous Torque

ft-lbs:

40000Drip Pan/Mud Collection System yes/no: Yes B.4.2 Rotary Table Adapter Bushing

Size

inches:

60-1/2 x 49-1/2Quantity

:

1 each 60-1/2 x 49-1/2 Adapter Bushing; 2 ea 49-1/2 x 37.5 Spot Adapter Bushing

B.4.3 Master Bushing

Make/Type

:

Varco MPCH

A-144

Size

inch:

37-1/2Inset Bushing

No:

3,2,1 B.4.4 Kelly Bushing

B.4.5 Top Drive

Make

:

Varco TDS8S w/Swingout Parking SystemType (electric/hydraulic)

:

ElectricRated Capacity

st:

750Test/Working Pressure psi/psi: 11250/7500Remote Operated Kelly Cock

yes/no:

YesIf Driven by Electric Motor

Make/Type

:

GE GEB-20ACOutput Power

hp:

1150Output Torque

ft-lbs:

94,000 @ 600 VoltsMax. Torque @ Max. RPM ft-lbs - RPM: Per Manufacturer’s rating 1150 HP 270 RPM = 13,000

ft-lbs; 95 RPM = 63,000 ft-lbs Two Speed Gearbox

rpm:

No (Single speed)Maximum Rotary Speed : 270Cooling System Type

:

All B.4.6 Top Drive Makeout/Breakout System

Make

:

VarcoModel : PH100Type

:

HydraulicMax. Breakout Torque That Can be applied by System ft-lbs: 100,000 B.4.7 Raised back-up System

Make

:

VarcoModel

:

RBS4Torque Rating ft-lbs: 100,000Vertical Travel

ft:

10Pipe Range : 4-3/4 In. to 8-1/4 In, C. Power Supply Systems

C.1 Rig Power Plant

C.1.1 Diesel Engines


:

Wartsila / 18V32Maximum Continuous Power

hp:

7290 KW 9775 HPAt Rotation Speed of

rpm:

720Equipped w/Spark Arrestors

yes/no:

YesMufflers Installed

yes/no:

YesTotal Fuel Consumption, Drilling (Average) bbl/day: Av 270. Estimate only, based on GOM weather and will

vary depending on operations

Normal Drilling:

bbl/day:

270 (Est. only, will vary depending on operations

A-145

Tripping:

bbl/day:

270 (Est. only, will vary depending on operationsTop Hole Drilling: bbl/day: 305 (Est. only, will vary depending on operations

Estimated w/2,500 KW hotel load. C.1.2 DC - Generator

Type

:

N/A C.1.3 AC - Generator

Quantity

no.:

6Make/Type : ABB/AMG 0900xU10 Continuous Power

kw:

7,000At Rotation Speed of rpm: 720Output Volts

volts:

11,000 C.1.4 Variable Frequency Drives

Number of Inverters

no.:

8 Thruster DrivesMake/Type : ABB/Sami-MegastarMaximum continuous Power (Total)

kw:

5.5 mwInput Volts volts: Thrusters 1-6: 3.3 / 3.3 KV Input Volts

volts:

Thrusters 7-8: 1.65 / 1.65 KV Output Volts

volts:

0-3,300 variable AC (All 8 thruster drives) Number of Inverters

no.:

6 Drilling Drive Lineups Make/Type : GEMaximum continuous Power (Total)

kw:

12,000Output Volts volts: 600 C.1.5 Transformer System

Quantity

no.:

8 Thruster Transformers Make/Type

:

ABBContinuous Power (ea) KVA: 7,300 KVAInput/Output Volts (dual wound secondaries)

volts: Thrusters 1-6: 11 KV / 3.3 / 3.3 KV

volts:

Thrusters 7-8: 11 KV / 1.65 / 1.65 KVFrequency

Hz:

60Quantity

no.:

6 Drilling Transformers Make/Type

:

OlsunContinuous Power (ea)

KVA:

3000 - 3 ea. Delta-Delta, 3 ea. Delta-WyeOutput Volts

volts:

11KV/600VFrequency Hz: 60Quantity

no.:

4 Quadrant Transformers Make/Type

:

OlsunContinuous Power (ea)

KVA:

2500Output Volts

volts:

11KV/480V, Delta-Wye Frequency

Hz:

60

A-146

C.1.6 Emergency Shutdown

Emergency shutdown switches for complete power system (AC & DC), located at the following points.

: Central Control Room; Rig Floor; Engine Control Room

C.1.7 Auxiliary Power Supply

Power Supply for a Mud Logging Unit

yes/no:

YesPower Supply Available:

Output Volts

volts:

480Frequency

Hz:

60Current amps: 100Phase

single / three:

Three C.1.8 Compressed Air Systems

Air Compressors - High Pressure

Quantity

no.:

2Make

:

HamworthyModel : 4swl234Rated Capacity

scfm:

65 eachWorking Pressure PSI: 5000Prime Mover (electric/diesel)

:

ElectricalContinuous Power

HP:

60 Quantity

no.:

1Make : PriceModel

:

W-3Rated Capacity scfm: 200 eachWorking Pressure

PSI:

5000Prime Mover (electric/diesel)

:

ElectricalContinuous Power

HP:

75 Air Dryers

Quantity

no.:

2Make/Type : Hamworthy Regenerative Tower (Dual)Rated Capacity

scfm:

90 Air Compressors - Medium Pressure (rig air):

Quantity

no.:

4Make

:

Gardner DenverModel

:

EBQ99F Rotary Screw Rated Capacity scfm: 750 eachWorking Pressure

PSI:

125Prime Mover (electric/diesel)

:

ElectricContinuous Power

HP:

200 Air Dryers

Quantity

no.:

4Make/Type : Desiccant Dominick Hunter / DX110 HeatlessRated Capacity

scfm:

1089 ea Air Compressors - Lower Pressure (bulk air):

Quantity

no.:

3

A-147

Make

:

Kimray -4 each reduicing wave/back pressure valveModel

:

Series G Regulator 318 FGT-BP & FGT-PRRated Capacity scfm: 176 each (10,600cf/hr each) Working Pressure

PSI:

60 Air Dryers

Quantity

no.:

NoneMake/Type

:

Rated Capacity

scfm:

C.2 Emergency Generator - Emergency Generator Not Required due to Power System Design C.2.1 Engine (Standby)

Quantity

no.:

1Make/Type

:

Caterpillar 3408 DITA Maximum Output

kw:

400 cont. power output At Rotation Speed rpm: 1200Starting Methods (Automatic, Manual,

:

Automatic Electric / Hydraulic Air/Hydraulic)

Maximum Angle of Operation

degrees:

22.5 Per ABS C.2.2 AC Generator (Standby)

Quantity

no.:

1Make/Type : Caterpillar SR4Maximum Output

kw

370At Rotation Speed rpm: 1200Output Volts

volts:

480Capable of Back-Feeding to Main Bus

yes/no:

Yes - To 480V Motors C.3 Primary Electric Motors

C.3.1 Propulsion Motors

Type:

See Thruster Motors C.3.2 Thruster Motors

Quantity

no.:

8Type (AC/DC)

:

ABB - AC, Squirrel Cage Motors Power of Each

MW

5.5RPM

RPM:

0-780Output

Volts:

2x3300 D. Drillstring Equipment

D.1 Tubulars

D.1.1 Kellies

A-148

D.1.2 Top Drive Saver Subs

Quantity

no.:

2Connection Type

:

HT55API Classification

:

8 CProtector

yes/no:

NoQuantity

no.:

2Connection Type

:

4-1/2 IFAPI Classification

:

8 CProtector

yes/no:

No D.1.3 Drill Pipe

Drill Pipe OD - String #1

inch:

5.5Grade

:

S135Total Length

ft:

16000Range : 3Weight

lbs/ft

21.9 NominalTensile Yield Strength Premium

lbs.:

621000Internally Plastic Coated

yes/no:

Yes, TK-34Tool Joint OD/ID

inch /inch:

7” x 4” provisionalMake Up Torque

ft-lbs:

46300Tool Joint Pin Length

inch:

12Tapered Shoulder Tool Joints degree: 18Connection Type

:

HT 55Type of Hardfacing

:

X-Metal 7,000API Classification

:

PremiumThread Protectors

yes/no:

Yes Drill Pipe OD - String #2

inch:

6.625Grade : V-150Total Length

ft.:

15,450 (+0%, -3%)Range

:

3Weight

lbs/ft:

34.02Tensile Yield Strength Premium

lbs.:

1,420,100Internally Plastic coated

yes/no:

Yes, TK-34Tool Joint OD/ID

inch /inch:

8.5” x 4.25”Make Up Torque ft-lbs: Max 56k, Min 54.5kTool Joint Pin Length

inch:

12Tapered Shoulder Tool Joints

degree:

18Connection Type

:

6-5/8 FHType of Hardfacing

:


:


yes/no:

Yes Drill Pipe OD - String #3

inch:

6.625Grade

:

V-150Total Length

ft.:

10,300 (+0%, -3%)Range

:

3Weight

lbs/ft:

40.9Tensile Yield Strength Premium

lbs.:

1,410,000Internally Plastic coated yes/no: Yes, TK-34Tool Joint OD/ID

inch /inch:

8.5” x 4.25”Make Up Torque

ft-lbs:

Max 67k, Mix 63k

A-149

Tool Joint Pin Length

inch:


degree:

18Connection Type

:

6-5/8 FHType of Hardfacing

:


:


yes/no:

Yes Drill Pipe OD - String #4 Landing String

inch:

5.5 Grade

:

S-135Total Length

ft.:

7000Range

:

3Weight

lbs/ft:

38Tensile Yield Strength Premium

lbs.:

1170600Internally Plastic Coated yes/no: YesTool Joint OD/ID

inch /inch:

7-1/8 x 3-3/4 Provisional Tool Joint Pin Length

inch:


degree:

18Connection Type

:

HT 55Type of Hardfacing

:


:

PremiumThread Protectors yes/no: Yes D.1.4 Drill Pipe Pup Joints (Integral)

OD

:

5.5”Grade/Yield

:

4145 H Equiv. To 120K Tool Joint OD/ID

inch /inch:

7-1/4 x 3-3/4Weight lb/ft: 40Connection Type

:

HT-55Stress Relief Pin Groove

:

NoBoreback on Box

:

NoInternally Plastic Coated

yes/no:

NoThread Protectors

yes/no:

YesLength

ft.:

5Quantity no.: 2Length

ft.:

10Quantity

no.:

1Length

ft.:

15Quantity

no.:

2Length

ft.:

20Quantity

no:

1OD : 6.625Grade/Yield

:

V-105Tool Joint OD/ID

inch /inch:

8.5” x 4.25”Weight

lb/ft:

47.76Connection Type

:

6-5/8 FHStress Relief Pin Groove

:

NoBoreback on Box

:

NoInternally Plastic Coated yes/no: NoThread Protectors

yes/no:

YesLength

ft.:

5

A-150

Quantity no.:

2Length ft.:

10Quantity no.:

1Length ft.:

15Quantity no.:

2Length ft.:

20Quantity no:

1 O.D. :

Grade/Yield inch /inch:

Tool Joint OD/ID :

Grade lb/ft:

Weight :

Connection Type :

Stress Relief Pin Groove :Boreback on Box yes/no:

Internally Plastic Coated yes/no:

Thread Protectors ft.:

Length no.:

Quantity ft.:

Length no.:

Quantity ft.:Length no.:

Quantity ft.:

Length no:

Quantity yes/no:

Thread Protectors :

N/A D.1.5 Drill Pipe Casing Protectors D.1.6 Heavy Weight Drill Pipe

(Integral)

Quantity no.:

30Nominal Size OD inch:

5-1/2”Weight lbs/ft

58” NominalRange : 2Tool Joint OD inch:

7-1/4”Tool Joint ID inch:

3-3/4”Pin Stress Relief Groove yes/no:

NoBox, Bore Back yes/no:

NoType of Hardfacing :

X-Metal 7000Internally Plastic Coated yes/no:

NoConnection Type : HT55Thread Protectors yes/no:

Yes, Bale Type Quantity no.:

36Nominal Size OD inch:

6-5/8” S-135 FH R-3Weight lbs/ft

70.8Range :

3Tool Joint OD inch:Tool Joint ID inch:

A-151

Pin Stress Relief Groove yes/no:

Box, Bore Back yes/no:

Type of Hardfacing :

Internally Plastic Coated yes/no:

Connection Type :

Thread Protectors yes/no:

D.1.7 Drill Collars

Quantity no.:

15OD Body inches:

9.5ID Body inches:

3”Nominal Length of each Joint ft.:

31.5 NominalDrill Collar Body (Slick/Spiral) :

SpiralRecess for “Zip” Elevator yes/no:

YesRecess for Slips yes/no: YesStress Relief Pin Groove yes/no:

YesBoreback on Box yes/no:

YesB.S.R. :

2.72Connection Type :

7-5/8”reg.Thread Protectors yes/no:

Yes, Bale TypeQuantity no.:

15OD Body inches: 8-1/14”ID Body inches:

2-13/16”Nominal Length of each Joint ft:

31.5 ft. NominalDrill Collar Body (Slick/Spiral) :


YesRecess for Slips yes/no:

YesStress Relief Pin Groove yes/no:

YesBoreback on Box yes/no: YesB.S.R. :

2.93Connection Type yes/no:

6-5/8” reg.Thread Protectors yes/no:

yes, Bale TypeQuantity no:

30OD Body inches:

6-1/2”ID Body inches:

2-1/2”Nominal Length of each Joint ft: 31.5 ft. NominalDrill Collar Body (Slick/Spiral) :


YesRecess for Slips yes/no:

YesStress Relief Pin Groove yes/no:

YesBoreback on Box yes/no:

YesB.S.R. :

2.73Connection Type yes/no: 4” IFThread Protectors yes/no:

Yes, Bale Type D.1.8 Shot Drill Collars :

Company Supplied.D.1.9 Non-Magnetic Drill Collars :

Company Supplied.D.1.10 Core Barrels :

Company Supplied.D.1.11 Stabilizers :

Company Supplied.D.1.12 Roller Reamers : Company Supplied.

A-152

D.1.13 Shock Absorbers (Damping Subs) :

Company Supplied. D.1.14 Drilling Jars :

Company Supplied. D.1.15 Inside BOP Valve

Quantity :

2Make :

SMF / BVROD inch:

7-1/4 x 2-1/4Connection Type :

HT 55Working Pressure Rating PSI:

15000 Quantity no.:

2Make :

SMF / BVROD inch:

6-1/2 x 2-13/16Connection Type :

4-1/2 IF (NC-50)Working Pressure Rating PSI: 15000 D.1.16 Full Opening Safety Valve

Quantity no.:

2Make :

SMF/KC2SOD/ID inch x inch:

7-1/4” x 2-1/8”Connection Type : HT55Working Pressure PSI:

15000 Quantity no.:

2Make :

SMF/KC2SOD/ID inch x inch:

6-5/8” / 2-13/16”Connection Type :

4-1/2 IF (NC 50)Working Pressure PSI: 15000 D.1.17 Circulation Head :

N/A D.1.18 Top Drive Valves

Upper:

Quantity no.:

2Make/Type : VarcoWorking Pressure :

15000Max. OD Body inch:

8-5/8”Min. ID Body inch:

3-1/16”Connection Type :

7-5/8 Reg.Lower:

Quantity no.:

2Make/Type : VarcoWorking Pressure PSI:

15000Max. OD Body inch:

8-5/8”Min. ID Body inch:

3-1/16”Connection Type :

7-5/8 Reg. D.1.19 Circulation Subs :

Company Supplied.D.1.20 Cup Type Testers : Company Supplied.D.1.21 Plug Type Testers :

Company Supplied.

A-153

D1.22 Drop-In Valves :

Company Supplied. D.1.23 Near-Bit Subs (Box-Box)

Quantity no.:

2OD Size inch:

9-1/2”ID Size inch:

3”Top Connection inch:

7-5/8 Reg.Boreback yes/no:

YesBSR :

2.25-3Bottom Connection inch:


NoBored for Float Valve yes/no:

YesFloat Size inch:

5F-6R Quantity no.: 2OD Size inch:


2-13/16”Top Connection inch:


YesBSR :


6-5/8 Reg.Boreback yes/no: NoBored for Float Valve yes/no:

YesFloat Size inch:

5F-6R Quantity no.:

2OD Size inch:


2-13/16”Top Connection inch: 6-5/8 Reg.Boreback yes/no:

YesBSR :




YesFloat Size inch:

5F-6R Quantity no.:

2OD Size inch:


2-1/2”Top Connection inch:

4-1/2 XHBoreback yes/no:

YesBSR :

2.25-3Bottom Connection inch: 4-1/2 Reg.Boreback yes/no:


YesFloat Size inch:

4 R D.1.24 Crossover Subs

Quantity no.:

2OD Size inch: 8-1/4” x 9-1/2”Top Connection Size inch:

6-5/8 Reg.Type (pin/box) :

Box

A-154

ID

:

2-13/16”BSR

:

2.25-3Boreback yes/no: YesBottom Connection Size

inch:

7-5/8 Reg.Type (pin/box) : PinID

:

3”BSR

:

2.25-3Relief Groove

yes/no:

Yes Quantity no.: 2OD Size

inch:

7-1/4” x 8-1/4”Top Connection Size inch: HT 55Type (pin/box)

:

BoxID

inch:

3”BSR

:

2.25-3Boreback

yes/no:

NoBottom Connection Size inch: 6-5/8 Reg.Type (pin/box)

:

PinID : 3”BSR

:

2.25-3Relief Groove

yes/no:

Yes Quantity

no.:

2OD Size inch: 7-1/4” x 6-1/2”Top Connection Size

inch:

HT 55Type (pin/box) : BoxID

inch:

2-1/2”BSR

:

2.25-3Boreback

yes/no:

NoBottom Connection Size

inch:

4-1/2 XH (NC 46)Type (pin/box) : PinID

:

2-1/2”BSR : 2.25-3Relief Groove

yes/no:

Yes Quantity

no.:

2OD Size

inch:

6-1/2” x 8-1/2”Top Connection Size

inch:

4 IF (NC 46)Type (pin/box)

:

BoxID inch: 2-1/2”BSR

:

2.25-3Boreback

yes/no:

YesBottom Connection Size

inch:

6-5/8 Reg.Type (pin/box)

:

PinID

inch:

2-1/2”BSR

:

2.25-3Relief Groove yes/no: Yes Quantity

no.:

2OD Size

inch:

7-1/4 x 6-5/8Top Connection Size

inch:

HT 55Type (pin/box)

:

Box

A-155

ID

inch:

2-13/16”BSR

:

2.25-3Boreback yes/no: NoBottom Connection Size

inch:

4-1/2 IF (NC 50)Type (pin/box) : PinID

inch:

2-13/16”BSR

:

2.25-3Relief Groove

yes/no:

Yes Quantity no.: 2OD Size

inch:

6-5/8 x 8-1/4Top Connection Size inch: 4-1/2 IFType (pin/box)

:

BoxID

inch:

2-13/16”BSR

:

2.25-3Boreback

yes/no:

YesBottom Connection Size inch: 6-5/8 Reg.Type (pin/box)

:

PinID inch: 2-13/16”BSR

:

2.25-3Relief Groove

yes/no:

Yes Quantity

no.:

OD Size inch:

Top Connection Size

inch:

Type (pin/box) :

ID

inch:

BSR

:

Boreback

yes/no:

Bottom Connection Size

inch:

Type (pin/box) :

ID

inch:

BSR :

Relief Groove

yes/no:

D.1.25 Stabbing Subs - Approximately 9” Long

Quantity

no.:

1OD

inch:

9.5ID

inch:

3Top Connection Size inch: HT 55Type (pin/box)

:

BoxBottom Connection Size

inch:


:

Pin Quantity

no.:

1OD

inch:

9.5Top Connection Size inch: 4-1/2 IFType (pin/box)

:

BoxID

inch:

3Bottom Connection Size

inch:


:

Pin

A-156

Quantity

no.:

1OD

inch:

8.25ID inch: 2-13/16Top Connection Size

inch:

HT 55Type (pin/box) : BoxBottom Connection Size

inch:

6-5/8” RegType (pin/box)

:

Pin Quantity

no.:

OD inch:

ID

inch:

Top Connection Size inch:

Type (pin/box)

:

Bottom Connection Size

inch:

Type (pin/box)

:

D.1.26 Pump In/Testing Subs

Quantity

no.:

1Connection Pin/Box: HT 55 BoxUnion Type

:

2: 1502 FemaleQuantity

:

1Connection

Pin/Box:

HT 55 PinUnion Type

:

2” 1502 FemaleQuantity : 1Connection

Pin/Box:

4-1/2 IF BoxUnion Type : 2” 1502 FemaleQuantity

:

1Connection

Pin/Box:

4-1/2 IF PinUnion Type

:


:

1Connection Pin/Box: 4 XHUnion Type

:

2” 1502 FemaleQuantity : 1Connection

Pin/Box:

6-5/8 Reg. PinUnion Type

:


:

1Connection

Pin/Box:

7-5/8 Reg. PinUnion Type

:

2” 1502 Female D.1.27 Side Entry Subs

Quantity

:

1Top Connection

Box/Pin:

HT 55 BoxLower Connection

:

HT 55 PinOutlet Size & Type

:


:

1Top Connection

Box/Pin:

4-1/2 IF BoxLower Connection : 4-1/2 IF PinOutlet Size & Type

:

2” 1502 Female D.1.28 Drilling Bumper Subs

:

Company Supplied.D.1.29 Hole Openers

:

Company Supplied.D.1.30 Underreamers

:

Company Supplied.

A-157

D.2 Handling Tools

D.2.1 Drill Pipe Elevators

Quantity

no.:

2Make : VarcoModel

st:

BX Frame 4Drill Collars Inserts

150 Tons:

6-1/2”, 8-1/4”, 9-1/2” Casing Inserts

350 Tons:

Company Supplied.Drill Pipe Inserts

500 Tons:

5, 5-1/2”Elevators 750 Tons: 5, 5-1/2”BOP Handling Elevators

st:

1,000 Refer E6.10 D.2.2 Drill Collar Elevators

Size

inch:

N/AQuantity

no.:

Make

:

Model :

Rated Capacity

st:

Size

inch:

N/AQuantity

no.:

Make

:

Model

:

Rated Capacity st:

Size inch: N/AQuantity

no.:

Make

:

Model

:

Rated Capacity

st:

Size

inch:

N/AQuantity no.:

Make

:

Model

:

Rated Capacity

st:

D.2.3 Tubing Elevators

Type:

Company Supplied. D.2.4 Drill Pipe Hand Slips

Size

inch:

5-1/2”Quantity

no.:

1Make/Type

:

Varco/SDXL Size

inch:

5Quantity

no.:

1Make/Type : Varco/SDXL Size

inch:

3-1/2”Quantity

no.:

N/AMake/Type

:

N/A

A-158

D.2.5 Power Slips

Make/Type

:

Varco PS 30Quantity : 1Slip Assembly: 20” to 18-5/8”

:

1Slip Assembly: 16” to 6-5/8” : 1Slip Assembly: 2-3/8 to 10-3/4”

:

1Insert Carriers for Drillpipe

:

5”, 5-1/2”Insert Carriers for Drill Collars

:

6-1/2, 8-1/4, 9-1/2Insert Carriers for Casing

:

Company Supplied.Die Sets for 13-3/8”, 9-5/8” & 7” Carriers : Company Supplied. Mousehole Slips : Varco Mousehole Spider, Range 3-1/2” to 14” D.2.6 Drill Collar Slips

Size

inch:

8-1/2” to 10”Quantity

no.:

1Make/Type : Varco/DCS-L Size inch: 8” to 9-1/2”Quantity

no.:

1Make/Type

:

Varco/DCS-L Size

inch:

5-1/2” to 7”Quantity no.: 1Make/Type

:

Varco/DCS-R D.2.7 Drill Collar Safety Clamps

Quantity

no.:

1Model

:

MP-LRange

:

19-3/8” to 4-1/2” D.2.8 Tubing Slips

:

Company Supplied.D.2.9 Tubing Spider : Company Supplied.D.2.10 Drill Collar Lift Subs

:

10 ea.: NC 46 Conn. For 6-1/2” D.C.

:

5 ea.: 6-5/8 Reg. Conn. For 8-1/4” D.C.

:

5 ea.: 7-5/8 Reg. Conn. For 9-1/2” D.C. D.2.11 Dc Lifting Plugs

:

N/A D.2.12 Bit Breaker

Quantity

no.:

1For Bit Size

inch:

26 Quantity

no.:

1For Bit Size

inch:

17-1/2Quantity

no.:

1For Bit Size inch: 14-3/4”Quantity

no.:

1For Bit Size

inch:

12-1/4Quantity

no.:

1

A-159

For Bit Size

inch:

8-1/2 D.2.13 Gauge Rings

Sizes

:

26,17-1/2,14-3/4,12-1/4,8-1/2 D.2.14 Elevator Links

Quantity of Sets

no.:

3Make/Type

:

VarcoSize

inch:

3.5Length inch: 120”, 180” & 108”Rated Capacity

st:

500Quantity of Sets no.: 2Make/Type

:

VarcoSize

inch:

4-3/4”Length

inch:

264” & 216”Rated Capacity

st:

750Quantity of Sets no.: 1Make/Type

:

VarcoSize inch: 4-3/4”Length

inch:

200”Rated Capacity

st:

1000 D.2.15 Drill Pipe Spinner

Type:

Grayspin Mark 30 D.2.16 Mud Saver Bucket

Make : DrecoSize

inch:

9-3/4 to 3-1/2”Operation

:

Remote from DWS D.2.17 Ezy Torque

Make/Type : VarcoMaximum Line Pull

lb:

31000Quantity : 2 D.2.18 Rotary Rig Tongs

Quantity

no:

2Make/Type

:

Varco HT 100Size Range (Max. OD/Min. OD)

inch /inch:

17 to 4Torque Rating

ft-lbs:

Max 100,000, reduces depending on sizeQuantity no: 2Make/Type

:

Varco HT 50Size Range (Max. OD/Min. OD)

:

20” / 17-1/4”Torque Rating

ft-lbs:

50000 D.2.19 Tubing Tongs (Manual)

D.2.20 Tubing Tongs (Power)

D.2.21 Iron Roughneck

Make/Type

:

Varco/AR3200Size Range (Max OD/Min OD) Drill Collars

inch /inch:

9-1/2” / 4” Size Range (Max OD/Min OD) Drill Pipe

inch /inch:

6-5/8” / 3-1/2”

A-160

D.3 Fishing Equipment

D.3.1 Overshots

Quantity

no.:

1Make/Type : F.STop Sub Connection Type

:

6-5/8 Reg.Overshot OD

inch:

11-3/4”Max. Catch Size

inch:

9-1/2”To Catch Size: Spiral Grapple inch: 9-1/2, 9-3/8, 8-1/2, 8-3/8, 8-1/4, 8-1/8, 7-1/4, 7-1/8, 7, 6-7/8,

6-5/8, 6-1/2, 6-3/8 To Catch Size: Basket Grapple

inch:

5-1/2, 5Control Rings : For Above GrappleExtension Sub Length

ft.:

2.5Lipped Guide (oversize, regular)

inch:

11-3/4, 15, 21Quantity

no.:

1Make/Type

:

SH Series 150Top Sub Connection Type : 4 1/2 IFOvershot OD

inch:

8-3/8Max Catch Size inch: 7-1/4To Catch Size: Spiral Grapple

inch:

7-1/4, 7-1/8, 7, 6-7/8To Catch Size: Basket Grapple

inch:

6-5/8, 6-1/2, 6-3/8, 5-1/2, 5 Control Rings

:

For Above GrappleExtension Sub Length

ft:

2.5Lipped Guide (oversize, regular) : 8-3/8, 11 D.3.2 Hydraulic Fishing Jar : Company SuppliedD.3.3 Jar Intensifier

:

Company SuppliedD.3.4 Surface Jar

:

Company Supplied D.3.5 Fishing Bumper Subs


:

GotcoOD Body inch: 8Min. ID

inch:

3.5Stroke

inch:

20Connection Type

:

6-5/8 Reg.Quantity

no.:

1Make/Type

:

GotcoOD Body

inch:

6-1/2”Min. ID inch: 2.25Stroke

inch:

20Connection Type

:

4-/12 IF D.3.6 Safety Joints

:

Company SuppliedD.3.7 Junk Baskets (Reverse Circ.)

:

Company Supplied D.3.8 Junk Subs : Company SuppliedQuantity

no.:

1Make/Type

:

GotcoFor Hole Size

inch:

11-1/2 to 13Boot OD

inch:

9-5/8

A-161

Connection Type

:

6-5/8 Reg.Quantity

no.:

1Make/Type : GotcoFor Hole Size

inch:

7-1/2 to 8-1/2Boot OD inch: 6-5/8Connection Type

:

4-1/2 reg.Quantity

no.:

1Make/Type

:

GotcoFor Hole Size

inch:

14-3/4 to 17-1/2Boot OD inch: 12-7/8Connection Type

:

7-5/8 reg. D.3.9 Flat Bottom Junk Mill

:

Company Supplied D.3.10 Magnet Fishing Tool

Quantity

no.:

1Make/Type : Gotco/Flush GuideOD Body

inch:

16Hole Size inch: 17.5Connection Type

:

6-5/8 Reg. Pin D.3.11 Taper Taps

:

Company SuppliedD.3.12 Die Collars

:

Company Supplied D.3.13 Sheared Drill Pipe Recovery System

(In conjunction w/11-3/4” overshot)

Quantity

no.:

1Make/Type

:

Gotco/Special Short Guide w/Soft Metal BottomOD Body

inch:

11-3/4 Quantity no.: 1Make/Type

:

Gotco/Special Short Guide w/Soft Metal BottomOD Body inch: 11-3/4 Quantity

no.:

1Make/Type

:

Gotco/Mill Extension to Dress 5” Drill PipeOD Body

inch:

11-3/4 Quantity

no.:

1Make/Type : Gotco/Mill Extension to Dress 5-1/2” Drill Pipe OD Body

inch:

11-3/4 E. Well Control / Subsea Equipment

E.1 Lower Riser Diverter Assy.

:

N/A E.2 Primary BOP Stack (from Bottom to Top)

Stack Complete with:

• Guide Frame

yes/no:

Yes

A-162

• Pick Up Attachment

yes/no:

Yes• Transport Base

yes/no:

YesSize (bore)

inch:

18.75Working Pressure

PSI:

15000H2S Service

yes/no:

Yes E.2.1 Alternate Hydraulic Connector

N/A E.2.2 Hydraulic Wellhead Connector

Size

inch:

18-3/4Make/Type

:

Vetco SHD H-4Working Pressure

PSI:

15000Hot Tap for Underwater Intervention ROV

yes/no:

YesSpare Connector Same Type yes/no: NoHydrate Seal

yes/no:

Yes (1- O-Ring & 1- Lip Seal Options as STD.) Glycol Injection (ROV)

yes/no:

Yes (4x1” NPT @ 90 Deg. Increments) Pilot Operated Check Valve, Close Function

yes/no:

Yes E.2.2A Hydraulic Wellhead Connector

Size

inch:

18-3/4Make/Type

:

Cameron DWHCWorking Pressure

PSI:

15000Hot Tap for Underwater Intervention ROV

yes/no:

YesSpare Connector Same Type

yes/no:

NoHydrate Seal

yes/no:

Yes (1- O-Ring & 1- Lip Seal Options as STD.) Glycol Injection (ROV)

yes/no:

Yes (4x1” NPT @ 90 Deg. Increments) Pilot Operated Check Valve, Close Function

yes/no:

Yes E.2.3 Ram Type Preventers

Preventers

Quantity

no.:

5Bore Size inch: 18-3/4Working Pressure

PSI:

15000Make

:

CameronModel

:

Type TLType (single/double)

:

Double x 2, Single x 1Stack Configuration

:

A1, A2, CL, BSR, SSCSR, VBR, VBR, LFPR, CH Rams Locks

yes/no:

YesPreventer Connection Type - Top : CX18Preventer Connection Type - Bottom

:

CX18Side Outlets yes/no: YesSize

inch:

3-1/16Connection Type

:

No. 6 Cameron Clamp AX Groove

A-163

Blind/Shear Rams:

Super/Shear Rams - Less Than or Equal to

Qty.:

1 Set13-5/8”

Blind/Shear Rams

Qty.:

1 Set Variable Rams:

Quantity

No.:

2 SetsSize Range (max/min)

inch / inch:

3-1/2 x 6-5/8 DPQuantity

no:

Size Range (max/min) inch / inch:

Quantity

no:

Size Range (max/min) inch / inch:

Pipe Rams:

Quantity

Qty.:

1 SetSize

inch:

5-1/2Quantity Qty.:

Size

inch:

E.2.4 Stack Configuration

(Blind/Shear/Pipe/Variable)

Upper Shear Rams Cavity 5

:

BSRLower Shear Rams Cavity 4

:

SSCSR (Less than or Equal to 13-5/8”) Middle Upper Ram Cavity 3 : VBRMiddle Lower Ram Cavity 2

:

VBRLower Rams - Cavity 1 : LFPRPosition of Side Outlets - Kill

Upper

:

Below BSR (Cavity #5)Lower

:

Below LFRP (Cavity #1) Position of Side Outlets - Choke

• LMRP

:

Below Lower Annular (#2) • Stack

:

Below Top VBR (Cavity #3) • Stack : Below Bottom VBR (Cavity #2) E.2.5 Annular Type Preventer On

Stack

Size

inch:

n/aWorking Pressure

PSI:

n/aMake/Type

:

n/a E.2.6 Mandrel

Make/Type : Cameron 18-3/4 10 HCSize

inch:

18.75 E.2.7 Fail-Safe Hydraulic Valves

(Kill & Choke)

Quantity on Each Side Outlet no.: 2Size (ID)

inch:

3-1/16”Make/Type : Cameron MCSWorking Pressure

PSI:

15000Solid Block

yes/no:

Yes

A-164

E.2.8 Subsea Accumulators

(See also E.7.1 - Surface Accumulator Unit)

LMRP

Quantity no.: 2 ea. 10 gal. (Pods)Useful Capacity per Accumulator (w/o Pre-Charge)

US Gal.:

0 Bottle Working Pressure

PSI:

6000Quantity

no.:

6 ea. 15 gal.Useful Capacity per Accumulator (w/o Pre-Charge)

US Gal.:

0 Bottle Working Pressure PSI: 6000Quantity

no.:

4 ea. 60 gal.Useful Capacity per Accumulator (w/o Pre-Charge) US Gal.: 0 Bottle Working Pressure

PSI:

6000BOP

Quantity

no.:

6 ea. 15 gal.Useful Capacity per Accumulator (w/o Pre-Charge)

US Gal.:

0 Bottle Working Pressure PSI: 6000Quantity

no.:

8 ea. 80 gal.Useful Capacity per Accumulator (w/o Pre-Charge) US Gal.: 0 Bottle Working Pressure

PSI:

6000 E.2.9 Hydraulic Control Pod/Receptacles

Quantity

no.:

2Redundancy %: 100Color Coded

yes/no:

YesRemote Regulation of Operating Pressure for Functions Requiring Lower Operating Pressure

yes/no:

Yes

Spare Control Pod

yes/no:

NoDeadman System

yes/no:

YesPressure & Temperature Sensor’s LMRP

yes/no:

Yes E.3 Primary Lower Marine Riser Package

(From Bottom to Top)

E.3.1 Hydraulic Connector

Make/Type

:

Cameron 18-3/4-10 HC or Equivalent Size

inch:


PSI:

10000Hot Tap for Underwater Intervention

yes/no:

YesSpare Connector Same Type yes/no: No

A-165

E.3.2 Annular Type Preventer (LMRP)

Size inch: 18-3/4Quantity

no.:

2Working Pressure PSI: 10000Make/Type (2*70.5=141” Total Height)

:

Cameron Type DL E3.3 Flex Joint

Make/Type

:

Oil States 18-3/4”Size inch: 21Max Deflection

degrees:

20 (10 from Vertical) E.3.4 Riser Adapter

Make/Type

:

Vetco HMF-Class HSize

inch:

21 (Minimum ID-19.25”) E.3.5 Connection Lines to Riser

Type (Rigid Loops, Coflexip, etc.)

Make:

Coflexip

Size: 3” ID x 200’

WP:

15,000 PSICollapse PSI:

12,710 PSI E.3.6 Riser Centralizer

:

Hydralift E.4 Annular Gas Handler

Make/Type

:

Supplied by Company at Later Date. Hard Piping & Control Functions to be Supplied by Contractor.

Rating

:

N/ANumber Outlets

:

N/ANumber Valves

:

N/A E.5 Secondary Lower Marine Riser Pack.

:

N/A E.6 Primary Marine Riser System

E.6.1 Marine Riser Joints

:

Designed for 10,000 Ft. Water Depth Make/Mode

:

Vetco / HMF-Class HOD

inch:

21.25, 21.5ID

inch:

19.5Wall Thickness inch: .875 & 1.00Average Length of Each Joint

ft.:

90Weight of One Complete Joint (In Air)

39,920

lbs.11 ea. x1” wall Slick

37,340

lbs. (Future for 10,000 foot water depth.)8 ea. x 0.875” wall Slick

62,035

lbs., 8,000’ rated buoyancy, 52” OD 3 ea. x 0.875” wall buoyed

62,287


62,216

lbs., 6,000’ rated buoyancy, 52” OD 11 ea. x 1.000” wall buoyed 60,707 lbs., 5,000’ rated buoyancy, 52” OD 11 ea. x 1.000” wall buoyed

60,069


55,895


54595


47356

lbs., 1,000’ rated buoyancy, 42” OD

A-166

9 ea. x 1.000” wall buoyed

no.:

90 ea. 90’ jts.Quantity grade: API 5L Grade X80 Mod. Pipe Material

PSI:

80 KSIMinimum Yield Strength : HMF-Class HType Riser Connectors

no.:

N/ADogs

Pup Joints

Quantity no.: 1Length

ft.:

45.0Quantity no.: 1Length

ft.:

37.5 X0Quantity

no.:

1Length

ft.:

30.0Quantity

no.:

1Length ft.: 22.5Quantity

no.:

1Length ft.: 15 E.6.2 Telescopic Joint

Make/Type

:

VetcoSize (ID)

inch:

19.75Stroke ft: 65Double Seals

yes/no:

YesWorking Pressure PSI: 500Spare Telescoping Joint

yes/no:

YesLocation

:

Shore or RigRotating Support Ring for Riser Tensioners

type:

Vetco SDC Connection Points no.: 6 E.6.3 Kill/Choke Lines

Quantity

no.:

2Outside Diameter

inch:

6.625Inside Diameter

inch:

4.5Working Pressure

PSI:

15000LMRP Isolation Valves

yes/no:

Yes. Fail Open E.6.4 Booster Lines

Quantity

no.:

1Outside Diameter

inch:

4.5Inside Diameter

inch:


PSI:

6000LMRP Isolation Valve (Mud Boost Valve)

yes/no:

Yes, Failsafe Close E.6.5 Hydraulic Supply Lines

Quantity

no.:

1Outside Diameter

inch:

3.5Inside Diameter

inch:


PSI:

5000

A-167

E.6.6 Upper Ball (Flex) Joint

Make/Type

:

Oilstates Diverter 3Size inch: 21-1/4Maximum Deflection

deg.:

20 (10 from vertical)Spare Upper Ball (Flex) Joint yes/no: No E.6.7 Buoyancy Modules (If Fitted)

Make

:

CummingQuantity of Buoyed Riser Joints no.: 78OD of Buoyed Riser Joints

inch:

42” on 1000’ Buoyancy, 52” all other Buoyancy Joints Length of Each Module ft.: 14Volume of Each Module

ft3:

42”/32.50, 52”/69.30 (12 mod. Per Joint) Module Lift in Seawater

2,287


2,298


2,495 lbs., 6,000’ rated buoyancy, 52” OD

2,620


2,695 lbs., 4,000’ rated buoyancy, 52” OD

2,828


2,938


1,437

lbs., 1,000’ rated buoyancy, 42” OD Rated Capacity

ft:

1,000 to 8,000 E.6.8 Marine Riser Spider

Make/Type : Vetco / Hydraulic E.6.9 Marine Riser Gimbal

Make/Type

:

Vetco E.6.10 Riser Handling Tools

Tool Riser Lifting

no.:

31,000 Ton Solid Body Elevators no.: 1BX Frame 5, 1,000 Ton

no.:

1, Fitted w/8-5/8” Insert Bushing Type

:

HMF - Class hTorque Wrenches

:

2 - Dual Speed E.6.11 Riser Test Tools

Quantity

no.:

2Type : HMF-Class H Hydraulic Test Tool (Pin) E.6.12 Instrumented Riser Jt.

:

N/A E.7 Secondary Marine Riser Sys.

:

N/A E.8 Diverter BOP (For Installation in Fixed Housing)

Make/Type

:

Hydril 60Max Bore Size

inch:

21-1/4

A-168

Working Pressure

PSI:

500Number of Diverter Outlets

no.:

2Outlet OD inch: 14Insert Packer Size ID

inch:

N/A CSOElement Type : Nitrile RubberRunning from Diverter to

:

Overboard, port/stbd. / Poorboy MGS E.8.1 Diverter Flowline

Quantity

no.:

1ID of Flowline inch: 18 NominalValve Types

:

Diverter SleeveSize inch: 18Working Pressure

PSI:

500Control Valve Type (Air / Hydraulic / etc.)

:

HydraulicRemote Controlled from

Location:

Drillers Workstation E.8.2 Diverter Control Panels

Driller’s Panel

Make : CameronModel

:

MultiplexLocation

:

Drillers WorkstationLocking / Unlocking Control

yes/no:

Yes Remote Panel

Make

:

CameronModel : MultiplexLocation

:

Control RoomLocking/Unlocking Control

yes/no:

Yes E.9 Subsea Support System

E.9.1 Riser Tensioners

:

Ability to Skid Tensioners from Well Centerline Quantity

no.:

6Make/Type

:

Hydralift - InlineCapacity Each Tensioner

st.:

800 KipsMaximum Stroke

ft.:

50 - Max. StrokeWireline Size

inch:

N/ALine Travel

ft.:

N/AIndependent Air Compressors yes/no: YesIndependent Air Drying Unit

yes/no:

YesRiser Recoil System

yes/no:

Yes E.9.2 Guideline System

:

N/AE.9.3 Remote Guideline Repl. Tool

:

N/A E.9.4 Remote Guideline Cutting Tool : N/AE.9.5 Pod Line Tensioners

:

No, turn Down Sheaves Complete w/Storm Loop within Moonpool Included within Design Layout.

A-169

E.9.6 Tensioner / Compensator Air Pressure Vessels

Quantity

no.:

30Total Capacity ft3: 2747Read Working Pressure

PSI:

3000Pressure Relief Valve Installed yes/no: Yes Standby APVs

Quantity

no.:

16Total Capacity

ft3:

588Rated Working Pressure PSI: 4000Pressure Relief Valve Installed

yes/no:

Yes E.10 BOP Control System

Cameron Mux system including: 2 ea. remote control panels, one located in Driller’s House & one in the Control Room, both panels incorporate full function & monitoring system for BOP’s & diverter system. In addition, a BOP Workstation located in the Subsea Shop w/keyboard & monitor for functioning of BOP. One each pod test stand & Mux system analyzer consisting of test stand & portable computer test set. Two each Mux cable reels complete w/11,000’ of Multiplex cable, one reel blue & one reel yellow for functioning yellow & blue pods plus one spare. Two each stack mounted pods, complete w/subsea electronics assemblies; one is designated for yellow side and one is designated for the blue side.

E.10.1 Surface Accumulator Unit (See also E.2.8 & E.4.8 - Subsea Accumulators) Make

:

CameronModel/Type

:

MuxLocation : Accumulator RoomSoluble Oil Reservoir Capacity

US Gal.:

500Oil/Water Mix Capacity US Gal / Min. 1200Glycol Reservoir Capacity

US Gal.:

300No. of Bottles Installed

no.:

45 Main, 6 Diverter = 51 Total Useful Cap. Per Accum. (w/o pre-charge)

US Gal.:

40Bottle Working Pressure

PSI:

5000Control Manifold Model

:

MultiplexRegulator Type

:

Pressure Switch / Relief Valves Total Useful Accum. Volume (Surface & Stack) Equals all Preventor Opening & Closing Volumes

yes/no:

Yes

Plus Percent Additional Volume

%:

50 E.10.2 Accumulator Hydraulic Pumps

Electric Driven

Quantity

no.:

2

A-170

Power Source

:

From Bus AMake

:

FMCModel : P509 898Each Driven by Motor of Power

hp:

100Flow Rate of Each Pump US Gal / Min. 32At Minimum Operating Pressure

PSI:

5000Secondary

Quantity

no.:

1Power Source

:

From Bus BMake : FMCModel

:

P509 898Each Driven by Motor of Power hp: 100Flow Rate of Each Pump US Gal / Min.

32At Minimum Operating Pressure

PSI:

5000 E.10.3 Driller’s Control Panel

Graphic control panel at driller’s position showing subsea functions w/controls for the following functions of the BOP Stack

Location

:

Driller Work StationBoost Line Control Valve

yes/no:

YesMarine Riser Connector

yes/no:

YesAll Annular Type BOPs

yes/no:

YesAll Ram Type BOPs yes/no: YesLock for Ram Type BOPs

yes/no:

YesWellhead & LMRP Connector yes/no: YesInner & Outer Kill & Choke Line Valves

yes/no:

YesLow Acc. Pressure Warning

yes/no:

YesLow Reservoir Level Warning

yes/no:

YesLow Rig Air Pressure Warning

yes/no:

YesPressure Regulator for Annular yes/no: YesFlowmeter

yes/no:

YesQuantity of Pressure Gauges no.: 29Emergency Push Button for Automatic Riser Disconnection

:

Yes

Other control Functions

yes/no:

YesControl Panel Make

:

CameronControl Panel Model

:

Multiplex E.10.4 Remote Control Panels

Ability to Operate Main Closing Unit Valves (directly).

yes/no:

NoQuantity

no.:

2Make/Model

:

Cameron / MultiplexLocations

:

Driller’s Workstation & Control Room Operating System Routing (Direct/via Primary Control Panel)

: Direct Dual bus

E.11 Subsea Control System

A-171

E.11.1 Hose Reels

Quantity

no.:

2 BOP Control (MUX)Location : MoonpoolMake/Type

:

CameronMaximum Storage Length Ea. ft.: 11000Drive Motor Type

:

AirQuantity

no.:

1 HotlineLocation

:

MoonpoolMake/Type

:

Synflex (Kevlar)Maximum Storage Length Ea. ft.: 11000Drive Motor Type

:

Air E.11.2 Pod Hose

Type:

N/A (Mux System) E.11.3 Pod Hose Manifold

Make/Model

:

NoneSurface Test Stump yes/no: Yes E.11.4 Surface Test Pod yes/no: Yes E.12 Deadman System

:

Yes - Part of Cameron Controls E.13 Subsea Auxiliary Equipment

E.13.1 Hole Position Indicator

Make/Type : SimardQuantity of Monitors

no.:

2 (Blue Pod / Yellow Pod) Monitor Location

:

Driller’s Work StationMonitor Location

:

Control RoomsRecorder

yes/no:

No E.13.2 Riser Angle Indicator

Make/Type : SimradQuantity of Monitors

no.:

2 (Blue Pod/Yellow Pod) Monitor Location

:

Driller’s Work StationMonitor Location

:

Control RoomRecorder

yes/no:

NoLocation

:

Flex Joint Neck, Lower Stack E.13.3 Slope Indicators

Make

:

ReganQuantity

no.:

2Provision for Installation on BOP

yes/no:

YesPin Connector

yes/no:

NoOther

:

Lower Stack LMRP E.13.5 ROV System : Power & Foundations Supplied

A-172

E.14 Choke Manifold

E.14.1 Choke Manifold (For Instrumentation, See H.3)

Make

:

Stewart & Stevenson Minimum ID inch: 3-1/16Maximum WP

PSI:

15000H2S Service

yes/no:

YesQuantity of Fixed Chokes

no.:

N/AMake

:

N/AModel : N/ASize (ID)

inch:

N/AQuantity of Adjustable chokes no.: 2Make

:

Stewart & Stevenson / Foley Model

:

Model QF2Size (ID)

inch:

3-1/16”Quantity of Power Chokes

no.:

2Make : Stewart / Stevenson / Foley Model

inch:

Model QF2 Hydraulic Size (ID) yes/no: 3-1/16”Power Choke Remote Control panel

YesMake

:

Houston DigitalModel

:

CPU w/ 2 ea. 27” Redundant Monitors & Hyd. Back-up.Location

yes/no:

Driller’s Workstation / Choke ManifoldGlycol Injection

No Inlet Available E.14.2 Flexible Choke & Kill Lines (Connecting Riser to Drilling Unit)Quantity

no.:

2Make/Type

:

CoflexipID

inch:

3”Working Pressure / Test Pressure

PSI/PSI:

15,000/22,500Quantity no.: N/AMake/Type

:

N/AID inch: N/AWorking Pressure / Test Pressure

PSI/PSI:

N/A E.15 BOP Testing Equipment

E.15.1 Hydraulic BOP Test Pump

Make

:

ShafferModel/Type : Electro Hydraulic Variable Speed 5 GPMPressure Rating

PSI:

22500Chart Recorder

yes/no:

Yes E.15.2 BOP Test Stump

Quantity

no.:

1Test Pressure

PSI:

15000Type : Vetco / CameronSize

:

18.75Connected to Deck (Welded/Bolted)

:

Bolted

A-173

E.16 Wellhead Running/Retrieving/Testing Tools (RT/RRT/TT)

E.16.1 RT’s for Casing Installation : Company SuppliedE.16.2 RRT’s for Casing Installation

:

Company SuppliedE.16.3 Miscellaneous Tools : Company SuppliedE.16.4 DP Hang-Off Subs

:

Company SuppliedE.16.5 Mini-Hose Bundle for Hyd. R. Tools

Company Supplied E.16.6 Emergency BOP Recovery System

yes/no:

YesMake/Type : Cameron F.1 High Pressure Mud System

System Working Pressure

PSI:

7500System Test Pressure

PSI:

11250Built to Which Design Standard

:

ANSI, API F.1.1 Mud Pumps

Quantity

no.:

4Make : Continental EmscoModel

:

FC-2200Type (Triplex/Duplex)

:

TriplexLiner Sizes Available

inch:

5” - 9”Mud Pump Drive Motors

no.:

2Motor Type : ACContinuous Power Rating Per Motor

hp:

1150Fluid End Type: Two PieceMaximum Working Pressure

PSI:

7500Test Pressure

PSI:

11250Pump Stroke Counter

Type:

HitecSupercharging Pump

Type:

HalcoDriven by Motor of Power hp: 100Discharge/Suction Line ID

inch / inch:

5”-12”MP Pulsation Dampener Type: White RockSoft Pump

:

1 SystemReset Relief Valve

Type:

RetscoWorking Flowrate Per Pump @ 90% of Max. SPM

SPM:

90 SPM @ 90%Maximum SPM

SPM:

100 SPM @ 100% F.1.2 Tansfer Pumps / Mixing Pumps (Centrifuge) Treatment Pumps (Desilter / Desander) Quantity

no.:

4Make

:

HalcoModel

:

2500Driver Motor Type

:

Electric / BeltPower Output

hp:

100Impeller : 14”Impeller Speed

RPM:

1,200 RPMPacking Type

:

Mechanical Seal

A-174

Mixing Pumps

Quantity

no.:

3Make : HalcoModel

:

2500Driver Motor Type : Electric / BeltPower Output

hp:

125Impeller

:

14”Impeller Speed

RPM:

1200 RPMPacking Type

:

Mechanical Seal Charging Pumps

Quantity no.: 4Make

:

HalcoModel

:

2500Driver Motor Type

:

Electric/BeltPower Output

hp:

100Impeller : 14”Impeller Speed

RPM:

1200Packing Type : Mechanical Seal Column Transfer

Quantity

no.:

6 (4 Reserve Mud & 2 Brine) Make

:

HalcoModel : 2500Driver Motor Type

:

ElectricPower Output hp: 125Impeller

:

11.5Impeller Speed

RPM:

1800Packing Type

:

Mechanical Seal F.1.3 Booster Pump

Quantity

no.:

Rig Mud PumpMake/Type : See Section F.1.1Pumping Capacity (ea)

US Gal / Min.

See Section F.1.1Drive Motor Type

:

See Section F.1.1Power Output

hp:

See Section F.1.1 F.1.4 StandPipe Manifold

Quantity of Standpipes

no.:

2 @ 7500 PSI WPStandpipes ID inch: 5H-Type Standpipe Manifold

yes/no:

YesKill Line Outlet

yes/no:

YesFill-Up/Bleed-Off Line Outlet

yes/no:

YesOutlets (Total)

no.:

4ID

inch:

5 & 3

A-175

Type Connections

:

WecoDimensions OD X ID

inch x inch:

6x5Design Standard : ANSI, API F.1.5 Rotary Hoses

Quantity

no.:

2 @ 7500 PSI WPMake/Type

:

BeattieID x Length

inch x ft.:

5 x 126Snubbing Lines

yes/no:

Yes F.1.6 Cementing Hose

Type (i.e. Coflexip) : BeattieLength

ft.:

85ID

inch:

3Working Pressure

PSI:

15000 F.1.7 Chiksan Steel Hoses

Integral Non-Screwed

yes/no:

YesMake/Type : 1502ID Nominal

inch:

2Section Length

ft.:

12Quantity

no.:

4Section Length

ft.:

10Quantity no.: 4Sweep Swivels, Make/Type

:

LS15/Style 50Nom. Size ID inch: 2Fittings, Non-Screwed Type

yes/no:

YesSuitable for H2S Service

yes/no:

No F.2 Low Pressure Mud System

F2.1 Mud Tanks

Quantity no.: 15Column Tanks

Quantity

:

4Capacity 100%

bbls:

10304Surface Tanks

Quantity

:

10Capacity 90%

bbls:

4141Capacity Tank No.1 bbls: 201Type (Active/Reserve)

:

ChemicalCapacity Tank No. 2

bbls:

201Type (Active/Reserve)

:


bbls:


:


bbls:

183Type (Active/Reserve) : ChemicalCapacity Tank No. 5

bbls:


:

Upper Hull Reserve Capacity Tank No. 6

bbls:


:


bbls:

508

A-176

Type (Active/Reserve)

:


bbls:

575Type (Active/Reserve) : ActiveCapacity Tank No. 9

bbls:

566Type (Active/Reserve) : ActiveCapacity Tank No. 10

bbls:


:

ActiveMixer in each Tank

yes/no:

YesMud Guns in each Tank

yes/no:

Yes F.2.2 Processing Tanks

Quantity no.: 6Total Capacity (@100%)

bbls.:

464Capacity Sand Trap Tank

bbls.:

119Capacity Degasser Tank

bbls.:

69Capacity Desander Tank

bbls.:

69Capacity Desilter Tank bbls.: 69Capacity Desilter Tank

bbls.:

69Capacity Treated Mud Tank bbls.: 69 F.2.3 Pill / Slug Tank

Capacity (@90%)

bbls.:

196Mud Agitator

yes/no:

YesMud Guns yes/no: Yes F.2.4 Trip Tank

Capacity @ 100%

bbls:

100 (2 x 50)Capacity/Foot

bbls/ft:

4.6Level Indicator

yes/no:

YesElectric Pump make

:

Halco x 2Model Type : CentrificalMotor Output

hp:

30Facility for Casing Fill-Up yes/no: NoAlarm & Strip Chart Recorder (See H.1.11)

yes/no:

Yes F.2.5 Stripping Tank

Capacity (@100%)

bbls:

10 Approx.Capacity/Foot

bbls/ft:

0.8Equalizing Facility w/Trip Tank

yes/no:

YesTransfer Pump yes/no: NoAlarm & Strip Chart Recorder (See H.1.11)

yes/no:

Yes F.2.6 Chemical Mixing Tank

:

Separate Mixing Tank Above for Mixing CausticCapacity

Gal.:

100 Model DA-13Chemical Mixer Type

:

Portable Rotor/Stator - Dual Impeller Mixing

Assembly, 1/3 hp air motor

A-177

F.2.7 Shale Shakers Primary:

Quantity no.: 7Make/Model

:

Brandt/LCM-2D CS Type : Linear Motion/Cascading Driven by No. of Electric Motor

no.:

3Design Flowrate

bbl/min:

Depending on Mud Characteristics Cascading:

Quantity

no.:

See Above.Make/Model : See Above.Type

:

See Above.Driven by No. of Electric Motor no.: See Above.Design Flowrate

bbl/min:

See Above. F.2.8 Desander

Quantity

no.

REMOVEDMake/Model :

Type

:

Number of Cones x Sizes no.x inch:

Type/Size Centrifugal Pump

:

Driven by Electric Motor of what power?

hp:

Is pump Dedicated to Desander

yes/no:

Max. Flowrate

gal / min:

F.2.9 Desilter

Quantity no.: REMOVEDMake/Model

:

Type

:

Number of Cones x Sizes

no.xinch:

Type/Size Centrifugal Pump

:

Driven by Electric Motor of hp:

Is Pump Dedicated to Desilter

yes/no:

Max. Flowrate gal/min:

F.2.10 Mud Cleaner

Quantity

no.:

Desilter Cones Over One Linear Motion ShakerMake/Model

:

Brandt, LCM-2D/LMC Type

:

Desilter Cones Over One Linear Motion ShakerNumber of Cones x Sizes

no.xinch:

40 x 4 w/Discharge Over Shaker or Overboard Type/Size Centrifugal Pump

:

2 ea 8 x 6 x 14Driven by Electric Motor of

hp:

100 ea.Is Pump Dedicated to Mud cleaner

yes/no:

NOMax. Flowrate

bbl/min:

2400 Inlet & Outlet for Centrifuge to be Provided

F.2.11 Mud/Gas Separator (Poor Boy)

:

Shall be capable to direct flow from flowline to MGSMake/Type

:

SwacoGas Discharge Line ID

inch:

12” NominalGas Discharge Location, Primary

:

Top

A-178

Can Discharge Be Tied Into Burner System

yes/no:

No Mud Seal Height

feet: 22Calculated Gas Throughput

mmscf:

20Dimensions

: Overall - 48 ft. x 6 ft. F.2.12 Degasser

Quantity

: 2Make/Type

:

Burgess/1500Capacity

: 1000 GPM X 2Type/Size Centrifugal Pump

:

N/ADriven by Electric Motor of Power

hp: N/ADischarge Line Running to

:

6”Vacuum Pump Make

:

InternalType :

N/A F.2.13 Mud Agitators

Quantity

no.:

5Make/Model

: Brandt/MA-20Driven by Motor of Power

hp:

20Located in Tanks (See F.2.1 for Tank Numbers)

:

1,2,3,4 & Slug Tanks Quantity

no.:

12Make/Model

: Brandt / MA-25Driven by Motor of Power

hp:

25Located in Tanks (See F.2.1 for Tank Numbers)

: 5,6,7,8,9, & 10 (2 in ea. tank) F.2.14 Mud Centrifuge

Quantity no.: 1Make/Model

:

MI SWACOFeed Pump Make/Model

:

F.2.15 Mud Hopper

Quantity

no.:

2Make/Model

:

Vortex VenturesFeed Pump Make/Model :

Mixing Pumps F.2.16 Shearing Hoppers

Quantity

no.:

2Make/Model

: Vortex VenturesFeed Pump Make/Model

:

Mixing Pumps

A-179

F.2.17 Deck Hoppers

Quantity

no.:

1Make/Model

:

HalcoFeed Pump Make/Model

:

Mixing Pumps F.3 Bulk System

F.3.1 Barite/Bentonite Silos

Quantity

no.:

5Capacity of Each Silo

C.F.:

2725Locations

:

ColumnsType Weight Loadcell

: HydraulicManufacturer

:

Martin DeckerPressure Rating

:

65Relief Valve(s) Installed yes/no:

Yes F.3.2 Barite Day Tanks

Quantity

:

2Capacity of Each Silo

C.F.: 1030Locations

:

Cmt. RoomType Weight Loadcell

:



PSI:

65Relief Valves (s) Installed

yes/no: Yes F.3.3 Surge Tank For Barite

Quantity

no.:

2Capacity of Each Tank

C.F.:

75Type Weight Loadcell :

Hydraulicmanufacturer

:


PSI: 65Relief Valve (s) Installed

yes/no:

Yes F.3.4 Cement Silos

Quantity

no.:

3Capacity of Each Silo C.F.:

2725Locations

:

ColumnsType Weight Loadcell

:

HydraulicManufacturer

:


PSI: 65Relief Valve (s) Installed

yes/no:

YesSeparate Mud/Cement Loading Facilities

yes/no:

YesDischarge Line for Cement Independent yes/no:

YesFrom Barite/Bentonite Discharge Line

F.3.5 Cement Day Tanks

Quantity

no.: 2Capacity of Each Silo

C.F.:

1030Locations

:

Cement RoomType Weight Loadcell :

HydraulicManufacturer

:


PSI:

65

A-180

Relief Valve (s) Installed

yes/no:

Yes F.3.6 Surge Tank for Cement

: Third Party F.3.7 Bulk Transfer System

(See also C.1.8 - Compressed Air System)

Independent Air System for the Silos & Surge Tanks

yes/no:

Noconsisting of a high -volume low-pressure Compressor &

Air Dryer

Air Reduced from Main Air Supply through Pressure

yes/no: YesRegulators

Separate Volume Tank & Dryer

yes/no:

No G. Casing / Cementing Equipment

:

Company Supplied G.1 Casing Equipment

:

Company SuppliedG.1.1 API Casing Drift

: Company SuppliedG.1.2 Clamp-on CSG Thread Protectors

Company Supplied G.1.3 Casing Elevator

:

Company SuppliedManufacturer

:

Type

:

Capacity

st:

Inserts for

inch:

G.1.3 Side Door Casing Elevator

:

Company SuppliedG.1.4 Single Joint Casing Elevator

:

Company Supplied G.1.5 Slip Type Elevator / Spiders

: Company SuppliedQuantity

no.:

Company Supplied G.1.6 Casing Slips (Hand)

Quantity

no.:

Company SuppliedMake/Type :

Company SuppliedFor OD Casing

inch:

Company Supplied Quantity

no.:

Company SuppliedMake/Type

: Company SuppliedFor OD Casing

inch:

Company Supplied Quantity no.:


:

Company SuppliedFor OD Casing

inch:

Company Supplied G.1.7 Casing Bowls

Quantity

no.:


:

Company SuppliedFor OD Casing (max/min) :

Company Supplied

A-181

Quantity :

Company Supplied Make/Type :

Company Supplied For OD Casing (max/min) : Company Supplied G.1.8 Casing Tongs : Company Supplied G.1.9 Power Casing Tongs :

Company Supplied G.1.10 Power Unit for Casing & Tubing Tongs

Quantity no.:

1 Central Hydraulic Unit Driven by Electric Motor yes/no:

Yes G.1.11 Casing Circulating Head (Swedge)

Company Supplied G.1.12 Casing Spears (Internal) : Company Supplied G.1.13 Casing Cutters (Internal) :

Company Supplied G.1.14 Crossover Casing to Drill Pipe :

Company Supplied G.1.15 Casing Scrappers :

Company Supplied G2 Cementing Equipment

G.2.1 Cement Unit : Company Supplied G.2.2 Cementing Manifold

Discharge Manifold Working Pressure PSI:

15000Cement Pump Discharge Lines Min. ID inch:

3 NominalCement Pump Discharge Lines Working Pressure PSI: 15000 G.2.3 Cement Kelly : N/AG.2.4 Cementing Tubing :

N/A H. Instrumentation/Communication

H.1 Drilling Instrumentation at Driller’s Position

Make/Type :

Hitec Smart Drilling InstrumentationSensor Type : Electronic Deadend Calibrated for Number of Lines Strung (6,8,10,12, etc.) no.:

User Selectable H.1.1 Weight Indicator

Make/Type :

Hitec Smart Drilling InstrumentationSensor Type :

Electronic Deadend Calibrated for Number of Lines Strung (6,8,10,12, etc.) no.:

User Selectable H.1.2 Standpipe Pressure Gauges

Quantity no.:

2 ea. local, 2 ea. DWS, 1 ea. Choke PanelMake/Type :

Hitec Smart Drilling Instrumentation / HDIPressure Range (Maximum) PSI:

10,000 H.1.3 Choke Manifold Pressure Gauge

Quantity no.: 2 Local, 2 Hitec SDI, 2 Choke Panel

A-182

Make/Type :

HDIPressure Range (Maximum) PSI:

0 - 16,000 / Selectable H.1.4 Rotary Speed Tachometer

Make/Type : Hitec Smart Drilling InstrumentationCapacity Range (Maximum) rpm:

0-200 H.1.5 Rotary Torque Indicator :

Hitec Smart Drilling Instrumentation H.1.6 Motion Compensator Instruments

Make/Type :

Hitec Smart Drilling InstrumentationHook Position Indicator yes/no: Yes on SDI Screens Lock/Unlock Indicator yes/no:

Yes H.1.7 Pump Stroke Counters

Make/Type :

Hitec Smart Drilling InstrumentationOne Pump Stroke Indicator & One Cumulative Pump Stroke Counter for each Pump

yes/no:

Yes

H.1.8 Tong Torque Indicator

Make/Type :

HitecCapacity Range (Maximum) ft.lbs.:

Dependent on Tong Length Input H.1.9 Pit Volume Totalizer

Make/Model :

Hitec Smart Drilling InstrumentationFloats in Active Mud Tanks yes/no: YesFloats in Reserve Mud Tanks yes/no:

YesLoss/Gain Indicator yes/no:

YesAlarm (Audio & Visual) yes/no:

Yes H.1.10 Mud Flow Indicator

Make/Model :

Hitec Smart Drilling InstrumentationHigh/Low Alarm (Audio & Visual) yes/no: Yes H.1.11 Trip Tank Indicator

Make/Model :

Hitec Smart Drilling InstrumentationChart Recorder yes/no:

Data Logging Alarm yes/no:

Yes H.1.12 General Alarm Sys. yes/no: Yes H.1.13 Automatic Driller

Make/Type :

Hitec Smart Drilling Instrumentation H.1.14 Remote Choke Control Unit (See E.14.1)

Make/Model :

Houston Digital

A-183

H.2 Drilling Parameter Recorder

Quantity no.:

User Defined Elect. Data AcquisitionLocation - 1 : Driller’s House Location - 2 :

Drilling Ofices Make/Type : Hitec Smart Drilling InstrumentationQuantity of Pens no.:

User Defined Elect Data AcquisitionParameter Recorded :



User Defined Elect Data AcquisitionParameter Recorded : User Defined Elect Data AcquisitionParameter Recorded :

User Defined Elect Data AcquisitionParameter Recorded : User Defined Elect Data AcquisitionParameter Recorded :


User Defined Elect Data Acquisition H.3 Instrumentation at Choke Manifold

H.3.1 Standpipe Pressure Gauge

Make/Type :

Strain Gauge Pressure Range (Maximum) PSI: 0-10,000 H.3.2 Choke Manifold Pressure Gauge

Make/Type :

Strain Gauge Pressure Range PSI: 0-15,000H.3.1 & H.3.2 Combined on One Panel yes/no:

YesVisible from Choke Operating Position yes/no: Yes H.4 Standpipe Pressure Gauge

Strain Gauges Make/Type :

OtecoPressure Range PSI:

0-10,000Visible from Driller’s Position yes/no: No H.5 Deviation Equipment

H.5.1 Measuring Device

Quantity no.:

1Make/Type :

TotcoDeviation Range degree:

0-8 / 0-16 H.5.2 Wireline Winch

Make/Model :

MatheyWire Length (Nominal) ft.:

25000Depth Counter yes/no:

YesWire Size inch:

3/16Pull Indicator Ibs:

Yes H.6 Calibrated Press. Gauges : Strain Gauges

A-184

H.7 Rig Communication System

H.7.1 Telephone System

No. of Stations no.: 120Make/Type :

Mitel Exchange Explosion Proof yes/no: As Required H.7.2 Public Address System

Can be combined with above yes/no.:

YesMake/Type : AkustaExplosion Proof yes/no.:

As Required H.7.3 Drill Floor - Derrickman’s Talkback (For Intercom System)

No. of Stations no.:

21Location :

DWS-DERLocation :

CCR-ECRLocation :

Floor, ROV, CP Area, Monkeyboard, MP Room, Moonpool, Shakers, Crown, Pit Room, Sack Room, Mud Lab, Schlumberger, Knuckleboom Crane

Make/Type :

Federal Signal Explosion Proof :

As Required H.7.4 Hand-Held VHF Radios

Quantity :

24 Min.Make/Type : Motorola Radins HT-750 H.8 Environmental Instrumentation

H.8.1 Temperature Indicators

Air Temperature : YesMake/Model :

Kongsberg (Integral to Metocean System)Seawater Temperature : YesMake/Model :

Kongsberg (Integral to Metocean System)Recorder yes/no:

Yes H.8.2 Barometer Pressure Indicator yes/no:

Yes Make/Model :

Kongsberg (Integral to Metocean System)Recorder : Yes H.8.3 Humidity Sensing Indicator yes/no:

YesMake/Model :

Kongsberg (Integral to Metocean System)Recorder :

No H.8.4 Wind Speed / Direction Monitor :

Yes - Qty. 3 Make/Model :

R.M. Young / DEIF879 Recorder :

Yes

A-185

H.8.5 Wave Profile Recorder :

NoH.9 Additional Module Specific Instrumentation

H.9.1 Roll, Pitch & Heave Indicator

Make/Type : 2 ea. Seatex MRU-5, 1 ea. Watson VRURecorder :

Included in IACS/DP H.9.2 Gyro Compass

Make/Model :

3 ea. Anschutz / Standard 20Located at : ECR H.9.3 Echo Sounder : YesMake/Model :

Furuno / FE880 Located at :

BridgeRecorder :

Yes H.9.4 Current Indicator : Doppler Current Profiler Make/Model :

Fugro Geos - RDI Oceans Surveyor 75 KHz PALocated at : Port/Aft - “Dipping” SystemRecorder :

Fugro Geos Rig ADCP3 Version 3..27 H.9.5 Weather Facsimile Recorder :

YesMake/Model :

Furuno / Fax 270 Located at : Radio Room Recorder yes/no:

Yes H.9.6 Radar yes/no:

YesQuantity no.:

1Make/Model :

FURUNO 28375 Located at :

BridgeBandwidth cm: S-BandQuantity no.:

2Make/Model : FURUNO 2827 Located at :

ECRBandwidth cm:

X-Band H.10 Radio Equipment

H.10.1 SSB Transceiver

Quantity no.: 2Make/Model :

Sailor / RE2100 Power watts:

250Frequency Ranges hz:

100 khz - 30 MHz (Synthesized Crystal) :

Synthesized Facsimile Capable :

NoTelex Capable :

N/A H.10.2 EPIRBs

Quantity no.:

5Make/Model :

ACR/SAT

A-186

H.10.3 VHF Radio Telephone

Quantity no.:

5Make/Model : Sailor / RT 2048 W/ DSC Power watts:

25 WattsChannels :

H.10.4 VHF Radio Transceiver

Quantity no.:

3Make/Model :

FURUNO FM-8800 Power watts: 25 W H.10.5 Radio Beacon Transmitter

Quantity no.:

1Make/Model :

Southern Avionics / SA 100Power watts:

100 W H.10.6 Aeronautical VHF Transceiver

Quantity YES 1Make/Model :

ICOMPower watts:

40 W PEPFrequency Range hz:

118-137(Synthesized/Crystal): :

H.10.7 Watch Receiver


Sailor / R501 Frequency khz:

2182 H.10.8 Scrambler

Quantity no.: NoMake/Model :

H.10.9 Telex

Quantity YES

2Make/Model :

FURUNO H.10.10 Satellite Comm. System

Make/Model :

DMS / Spacetrack 400 Type : Vsat C/Ku Band Facsimile Link yes/no :

YesTelex Link yes/no :

YesTelephone Link :

Full Voice/Fax Other Capabilities :

Wide Area Network V3.5 Make/Model :

Caprock/Seatel Dual Band 9797Type : Single Stabilized Dual Band 2.4m AntennaFacsimile Link yes/no :

Telex Link yes/no :

Telephone Link :

Other Capabilities :

A-187

I. Production Test Equipment

I.1 Burners :

N/AI.2 Burner Booms : Foundations Only I.3 Lines on Burner Booms :

N/A I.3.1 Oil Line

OD inch:

4Working Pressure PSI:

1480 PSIConnection Type at Burner End :

Suitable to Connect to Well Test EquipmentH2S yes/no: YesPressure Gauge connection @ Barge End inch:

Provided by Well Test Company I.3.2 Gas Line

OD inch:

3”Working Pressure PSI:

1480 PSIExtended Beyond Burner By ft.:

Provided by Well Test Company Connection Type at Burner End Type: Suitable to Connect to Well Test EquipmentH2S yes/no:

YesPressure Gauge Connection at Barbe End inch: Provided by Well Test Company I.3.3 Water Line

OD inch:

Seawater - 1-1/2” Working Pressure PSI:

285 PSIConnection Type at Burner End Type: Suitable to Connect to Well Test Equipment Pressure Gauge Connection at Barge End inch:

Provided by Well Test Company I.3.4 Air Line

OD inch:


285 PSIConnection Type at Burner End Type:

Suitable to Connect to Well Test Equipment Pressure Gauge Connection at Barge End inch: Provided by Well Test Company I.3.5 Pilot Gas Line

ID inch:

Provided by Well Test CompanyWorking Pressure PSI:

Connection Type at Burner End Type:

Pressure Gauge Connection at Rig End inch:

I.4 Sprinkler System

Sufficient to give protection to rig & personnel against heat radiation damage from the burners

yes/no:

Provided by Well Test Company

A-188

I.5 Fixed Lines for Well Testing

I.5.1 Drill Floor to Separator Area

Type (Screwed/Welded, Both) :

Tested & Certified Flexible Flowlines Provided by Well Test Company for Connecting from Rig Floor to Well Test Equipment.

I.5.2 Separator Area to Both Burner Booms


WeldedQuantity no. 2 ea. / one oil / one gas Size OD inch:

3” Gas / 4” Oil Working Pressure PSI: 1480 PSIConnection Type at Separator Type:

Suitable for Connecting to Well Test Company Connection Type at Boom Type:

As AboveNumber of Valves/Lines no.:

Provided by Well Test CompanySize of Valves inch: Provided by Well Test CompanyH2S yes/no:

YesValves Installed Near Separator Area for yes/no: YesSwitching Gas to Either Burner

I.5.3 Mud Pumps to 2-Burner Boom : N/A I.5.4 Rig Air System to Both Burner Booms

Type (Screwed/Welded, both) :

WeldedQuantity no.: 1 ea. Port & Starboard Size OD inch:


150Non-Return Valves Fitted yes/no:

Yes I.5.5 Oil Storage Tank to Overboard

Type (Screwed/Welded, both) : Provided by Well Test CompanyQuantity no.:

Size ID inch:

Working Pressure PSI:

Height Above Water Level ft.:

Connection Type at Separator Area Type:

I.5.6 Separator To Vent Stack of Rig


No Vent from Separator. Relief to FlairQuantity no.:

Size ID inch:


Connection Type at Separator Area Type:

A-189

I.6 Auxiliary Power Availability

I.6.1 For Field Laboratory (Well Test Equipment)

Quantity KW:

2 ea. 330 kw Volts V: 480Frequency Hz:

60 I.6.2 For Crude Transfer Pump

Quantity KW:

As above only Volts V:

Freqeuncy Hz:

I.6.3 For Electric Heaters

Quantity KW:

As above only Volts V:

Frequency Hz:

J. Workover Tools :

Company Supplied K. Accommodation :

Company Supplied K.1 Offices :

Company Supplied K.1.1 Company Representatives Office

Quantity : 3Complete w/Desk, Filing Cabinet(s) & Other Necessary Furniture :

YesUnrestricted View to Drill Floor : No (CCTV Monitor) K.1.2 Contractor Representatives Office

Quantity :

4Unrestricted View to Drill Floor : No (CCTV Monitor) K.1.3 Radio Room : Yes - On Bridge Quantity :

1 K.1.4 Hospital Room

Number of Beds/Bunks :

3 Bunks / 6 Beds Wash Basin : YesMedical Cabinet :

YesDangerous Drugs Locker : Yes K.1.5 Mud Laboratory & Facilities

Separate Room yes/no:

YesEquipped With:

• Mud Balance yes/no:

Yes• Marsh Funnel yes/no:

Yes• Filtration Kit yes/no: Yes• Sand Content Kit yes/no: Yes• Stop Watch yes/no:

Yes K.2 Living Quarters

A-190

K.2.1 Total Persons Accommodated

Quantity :

146 K.2.2 Accommodation for Company’s Personnel

Total Quantity : 60Quantity of Single Bed Rooms :

2C/W Attached Toilet :

YesQuantity of Two-Bed Rooms : 19C/W Attached Toilet :

YesQuantity of Four-Bed Rooms : 5C/W Attached Toilet :

N/A K.2.3 Accommodation for Contractor’s Personnel

Total Quantity :

86Quantity of Single Bed Rooms :

4C/W Attached Toilet :

YesQuantity of Two-Bed Rooms : 33C/W Attached Toilet :

YesQuantity of Four-Bed Rooms : 4C/W Attached Toilet :

N/A K.2.4 Galley

Quantity :

1 K.2.5 Mess Seating Capacity

Main Mess : 60Auxiliary Mess :

N/A K.2.6 Meeting Rooms

Quantity :

1 K.2.7 Recreation Rooms

Quantity : 2Recreation Facilities: :

Yes• TV :

Yes• VCR : Yes• Pool Table :

No• Ping Pong Table :

No• Computer :

YES• Other :

Darts/Cards/Reading K.2.8 Other Rooms

Laundry :

1Dry Food Store : 1Refrigerator :

3Change Rooms :

3Prayer Room :

NoCinema :

YESWorkout/Weight Room : Yes L. Safety Equipment

L.1 General Safety Equipment

A-191

L.1.1 General Personnel Protective Gear

Safety Hats (Contractor Only/Everyone Not Supplied) :

Contractor Only Safety Boots (Contractor Only/Everyone Not Supplied) : Contractor Only Safety Clothing (Contractor Only/Everyone Not Supplied) :

Contractor Only Ear Protection (Contractor Only/Everyone Not Supplied) : Contractor Only Rubber Gloves (Contractor Only/Everyone Not Supplied) :

Contractor Only Rubber Aprons (Contractor Only/Everyone Not Supplied) :

Contractor Only Full Face Visors (Contractor Only/Everyone Not Supplied) :

Contractor Only Eye Shields (For Grinding Machines, Etc.) :

Yes •(Contractor Only/Everyone Not Supplied) : Contractor Only Dust Masks (Contractor Only/Everyone Not Supplied) :

Contractor Only Rubber Gloves - Elbow Length for Chemical Handling :

Contractor Only •(Contractor Only/Everyone Not Supplied) :

Contractor Only Explosion Proof Hand Torches c/w Batteries

•(Contractor Only/Everyone Not Supplied) :

Contractor Only Safety Belts c/w Lines (Contractor Only/Everyone Not Supplied) :

Contractor Only L.1.2 Eyewash Stations


Haws #8317 Located at :

Mud Process Room Located at :

Drill FloorLocated at :

Mud Mixing Room L.1.3 Derrick Safety Equipment

Derrick Escape Chute (Rem Chute) no.: N/A - Derrick fall protection it to be provided• Make/Type :

N/ADerrick Safety Belts no.:

N/A• Make/Type : TBA L.1.4 Derrick Climbing Assistant

Make/Type :

N/A L.1.5 Fresh Air Blowers (Bug Blowers)

Quantity : 2Make/Type :

Brandt B-250 & B-400 Located at :

Rig Floor / Portable

A-192

Located at: :

L.2 Gas/Fire/Smoke Detection

1.2.1 H2S Monitoring System

Make/Type :

Kongsburg (Autronica/Crowcon/Detcon)Sampling Points at:

• Bell Nipple yes/no:

Yes• Drill Floor yes/no:

Yes• Shaleshaker yes/no:

Yes• Mud Tanks yes/no: Yes• Ventilation System into Living Quarters yes/no:

Yes• Other :

Yes• General Alarm yes/no:

YesAlarm Types (Audible, Visual, both), at:

• Driller’s Console :

Both• Engineroom :

Both• Mud Room :

Both• Living Quarters each Level : Both• Central Area Each Structural Level :

Both• Other :

Both• Central Alarm Panel yes/no:

Yes• Located at :

Bridge L.2.2 Combustible Gas Monitoring System

Make/Type :

Simrad Integrated Alarm & Control SystemSampling Points at: yes/no:

• Bell Nipple yes/no:

Yes• Drill Floor yes/no:

Yes• Shale Shaker yes/no:

Yes• Mud Tanks yes/no:

Yes• Ventilation System into Living Quarters yes/no: Yes• Other :

Yes• General Alarm yes/no:

N/AAlarm Types (Audible, Visual, Both) at:

• Driller’s Console :

Both• Other :

Both L.2.3 H2S Detectors (Portable)


Industrial Scientific ATX612, Combustable Gas

/ O2 / H2SPhials for H2S: Measuring Range

• From 1 to 20 RPM no.: As required• From 100 to 600 RPM no.:

As required L.2.4 CO2 Gas Detectors (Portable)

Quantity no.: NoneMake/Type :

Phials for CO2: Measuring Range

• From 1 to 20 RPM no.:

A-193

• From 20 to 200 RPM no.:

• From 250-3000 RPM no.:

L.2.5 Explosimeters

Quantity no.:

See H2S Detectors Make/Type :

I.2.6 Fire/Smoke Detectors in Accommodations

Make/Type :

Optical with a few ThermalFire Detection yes/no:

YesSmoke Detection yes/no:

YesCentral Alarm Panel yes/no:

YesLocation :

CCR L.3 Fire Fighting Equipment

L.3.1 Fire Pumps

Quantity no.:

2Make/Model :

PattersonType :

CentrifugalOutput US Gal/Min.:

550All Offtake Points Supplied by Each Pump yes/no: Yes Location of Pumps :

Aux. Machine Room Port Location of Pumps :

Aux. Machine Room STB. Fire Fighting Water Delivery Conforms to yes/no:

YesMODUs

MODU Spec Version :

1998 L.3.2 Hydrants & Hoses

Hydrants Positioned Such That any Point May be Reached by a Single Hose Length from Two Separate Hydrants.

yes/no:

Yes

Quantity of Hydrants no.:

59Hose Connections/Hydrant no.:

59 x 1Hose Max. Diam. inch: 2.5” ODLength ft.:

50 L.3.3 Portable Fire Extinguishers

Quantity (Total) no.:

70Type 1 - CO2 no/lbs:

2 @ 4

no/lbs:

37 @15

no/lbs: 2 @ 150Type 2 - Dry Chemical no/lbs:

17 @ 5

no/lbs: 9 @10

no/lbs:

3 @ 50Type 3 - Foam no/lbs:

10 AFFF

no/lbs:

0

no/lbs:

0Mounted Adjacent to Access Ways & Escape Routes yes/no: Yes

A-194

L.3.4 Fire Blankets

Location :

Rig Floor, Galley, Helicopter BoxQuantity no.: 3 L.3.5 Fixed Foam System

Automatically Injected into Fixed Fire Water System at Central Point w/Remote Manual Control.

yes/no:

Yes

Make/Type :

PattersonQuantity Foam Stored On Site Gal: 200Inductor Tube yes/no:

YesFoam Nozzles no.: 4Located at :

Heliport - 3 Turret MountedLocated at :

Heliport - 1 Hose Reels Located at :

L.3.6 Helideck Foam System

Dedicated System Adequate for at least 10 Minutes fire fighting at the Rate Quoted in the IMO MODU Code

yes/no: Yes

IMO MODU Code Version :

1998Make/Type :

DoolyQuantity of Monitors no.:

3Foam Type :

Ansulite 3x3 Low Viscosity AFFFRate US Gal/Min: 350 gpm ea. L.3.7 Fixed Fire Extinguishing System

Protected Spaces

Engine Room, Type (Halon/CO2) :

CO2Paint Locker, Type (Halon/CO2) :

CO2Emergency Generator, Type (Halon/CO2) : CO2SCR Room, Type (Halon/CO2) :

CO2Other (Specify Location & Type) : CO2 in Mud Pump Room Alarms (Audible, Visual or Both) :

AudibleAutomatic Shutting of Mechanical Ventilation in Protected Spaces

yes/no:

Yes

Remote Manual Release Located at :

Entrance to Space & at BottlesRemote Manual Release Located at :

Remote Manual Release Located at :

L.3.8 Manual Water Deluge System yes/no:

YesProtected Spaces :

Drill Floor, Lifeboats Protected Spaces :

Liferafts, Moonpool Water Supplied from Fire Main Line yes/no:

Yes Main Salt Water Ring L.3.9 Water Sprinkler System in Accommodations

Automatic yes/no: Yes

A-195


130Pressurized Tank Capacity ft3:

53.47 L.4 Breathing Apparatus :

12 L.5 Emergency First Aid Equipment

L.5.1 First Aid Kits

Quantity no.:

3 L.5.2 Burn Kits

Quantity no.: 3 L.5.3 Resuscitators

Quantity no.:

1Charged (spare) Oxygen Cylinders no.:

10 L.5.4 Stretchers / Stokes Litters w/Lift Bridles

Quantity no.: 2Type :

Billy Pugh #S-1 Located at :

In Hosiptal & On Third Deck L.6 Helideck Rescue Equipment

L.6.1 Storage Boxes

Quantity no.: 1Construction Material :

StainlessMax. Height Open inch:

48 L.6.2 Equipment

Aircraft Axe yes/no: YesLarge Fireman’s Rescue Axe. yes/no:

YesCrowbar yes/no: YesHeavy Duty Hacksaw yes/no:

YesSpare Blades yes/no:

YesGrapnel Hook yes/no:

NoLength of Wire Rope Attached ft.:

100Quick Release Knife yes/no:

YesBolt Croppers yes/no:

Yes L.7 Rig Safety Store

Equipment to Repair, Recharge & Restock :

R&BF will carry all spares necessary to ensure an efficient & safe operation.

L.8 Emergency Warning Alarms

Approved System to Give Warning of Different Emergencies yes/no:

Yes

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L.9 Survival Equipment

L.9.1 Lifeboats

Make/Type :

FassmerQuantity no.: 4Capacity person/craft:

73Locations (Fore, Aft, Port, Stbd.) :

2 Forward, 2 AFT Fire Protection yes/no:

YesRadios yes/no:

YesFlares yes/no: YesFood yes/no:

YesFirst Aid Kits yes/no: Yes L.9.2 Liferafts

Make/Type :

VikingQuantity no.:

6Capacity Person/craft: 25Davit Launched yes/no:

Yes & Float Free Locations (Fore, Aft, Port, Stbd.) : 3 Fore, 3 AFT Fire Protection yes/no:

NoRadios yes/no:

NoFlares yes/no:

YesFood yes/no:

YesFirst Aid Kits yes/no: YesMake/Type :

VikingQuantity no.:

Capacity Person/craft:

Davit Launched yes/no:

Locations (Fore, Aft, Port, Stbd.) :

Fire Protection yes/no:

Radios yes/no:

Flares yes/no:

Food yes/no:

First Aid Kits yes/no:

L.9.3 Rescue Boat

Make/Type :

Port Fwd. Lifeboat is Designated as a Rescue

BoatEngine Power hp:

29 L.9.4 Life Jackets

Make/Type :

Safeguard w/Light, #S22SRTQuantity no.:

163

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L.9.5 Life Buoys

Make/Type :

Jim BuoyQuantity no.: 10 L.9.6 Work Vests

Make/Type :

Billy PughQuantity no.:

30 L.9.7 Escape Ladders/Nets

Make/Type : Permanent Ladders Quantity no:

4, 1 per Corner Column L.9.8 Distress Signals

Type :

DatrexQuantity no.:

12 ea. M. Pollution Prevention Equipment

M.1 Sewage Treatment

Make/Model :

Hamworthy (USCG Approved)System Type :

BiologicalConforms to (Marpol Annex IV, Etc.) :

Yes M.2 Garbage Compaction

Make/Model :

Envior-Pak I Model 5000 System Type : AirConforms to (Marpol Annex IV, Etc.) :

Yes M.3 Garbage Disposal/Grinder

Make/Model :

Gulf Gulp I Tuff Gut System Type : ElectricConforms to (Marpol Annex IV, Etc.) :

Yes N. Third Party Equipment

N.1 Space Available

Mud Loggers (Available Sq.Ft.) Sq.Ft.:

555 Sq.Ft.MWD/LWD (Available Sq.Ft.) Sq.Ft.:

555 Sq.Ft.Cement Unit (Available Sq.Ft.) Sq.Ft.:

1,087 Sq.Ft. ROV (Available Sq.Ft.) Sq.Ft.:

1,184 Sq.Ft. Electric Log (Available Sq.Ft.) Sq.Ft.: 895 Sq.Ft.

EXHIBIT “D”

HSSE REQUIREMENTS

[ATTACHED]

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HSE Management

ATTACHMENTS 1. Scope Specific HSSE Requirements

HSSE Standard 01 Vibration HSSE Standard 02 Noise HSSE Standard 03 Automation/Mechanisation HSSE Standard 04 Man Riding HSSE Standard 05 Lifting Operation HSSE Standard 06 Waste Management HSSE Standard 07 Maintenance HSSE Standard 08 Dropped Objects HSSE Standard 09 Risk Management HSSE Standard 10 Ventilation HSSE Standard 11 Lighting HSSE Standard 12 Work Time HSSE Standard 13 Hazardous Materials

2. CONTRACT AREA Specific HSE Requirements • GoM Specific HEALTH, SAFETY, SECURITY, AND ENVIRONMENTAL REQUIREMENTS • Substance Abuse Policy

1.0 “GETTING HSE RIGHT”

COMPANY is committed to conducting its business in a manner which:-

(a) ensures that all COMPANY facilities are designed, constructed, maintained and operated to high and consistent standards;

(b) complies with all relevant laws and regulations; and (c) is compatible with the balanced economic and environmental needs of the community.

2.0 HEALTH, SAFETY AND ENVIRONMENTAL MANAGEMENT SYSTEM

2.1 Prior to commencement of the DRILLING SERVICES and at routine periods thereafter, CONTRACTOR shall provide COMPANY with a written statement on the health, safety and environmental (HSE) policy of CONTRACTOR relevant to the DRILLING SERVICES to be performed by CONTRACTOR and subsequently, any revision or amendment issued during the term of the CONTRACT.

2.2 CONTRACTOR must have in place and be actively using a formal HSE management

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Provision and Operation of an Offshore Mobile Drilling Unit Section 8

HSE Management

INDEX

1.0

GETTING HSE RIGHT 2.0

HEALTH, SAFETY AND ENVIRONMENTAL MANAGEMENT SYSTEM 3.0

COMPATIBILITY OF HSE MANAGEMENT SYSTEMS4.0

COMPLIANCE 5.0

REPORTING 6.0

WORKING CONDITIONS 7.0

WASTE DISPOSAL AND ENVIRONMENTAL SAFEGUARDS8.0

SUBSTANCE ABUSE POLICY9.0

HSE REFERENCE DOCUMENTS

CONTRACTOR’s Initial

COMPANY’S Initial Amendment 1 to CON-ANG-31-5367

system which demonstrates commitment to continuous improvement and excellence in HSE issues.

2.3 CONTRACTOR’s HSE management system shall be adequately documented, shall be shown to be effective in

implementing the aims and objectives of CONTRACTOR’s HSE policy and shall include provisions for auditing the effectiveness of CONTRACTOR’s HSE management system as applied to the DRILLING SERVICES.

2.4 CONTRACTOR shall review its HSE management system at least annually and update it as necessary.

2.5 Without prejudice to the foregoing generalities, CONTRACTOR’s HSE management system shall:-

(a) require an assessment of all identifiable HSE risks associated with the DRILLING SERVICES to be identified and

submitted to COMPANY and shall indicate the proposed method of controlling those risks to an acceptable level;

(b) include measurable and realistic targets for HSE performance, covering, but not necessarily limited to:-

• the frequency of injuries; • the frequency of chemical and oil spills; • the number of statutorily reportable events; and • predetermined targets for environmental emissions and waste production as appropriate to the DRILLING

SERVICES;

(c) include a follow-up system to ensure that all remedial actions identified by reviews and investigations are closed out, including accidents, incidents and HSE audits;

(d) incorporate measures which demonstrate that all PERSONNEL provided by CONTRACTOR are competent and

physically/medically fit at all times to perform their tasks;

(e) incorporate measures which demonstrate that, in the performance of the DRILLING SERVICES, PERSONNEL provided by CONTRACTOR are not under the influence of drugs or alcohol (see section 12.0); and

(f) demonstrate that the system for the pre-qualification and selection of SUBCONTRACTORS ensures the

compatibility and effectiveness of the SUBCONTRACTOR’S own HSE management systems.

2.6 Certain activities pose a higher risk to the safety of personnel, property and the environment. Higher risk activities will accordingly demand a higher level of HSE management from CONTRACTOR. Where the use of a SUBCONTRACTOR involves the importation of higher risk activity, CONTRACTOR shall ensure and demonstrate the appropriate level of HSE management.

2.7 Risk may vary from one LOCATION to another and, where the DRILLING SERVICES is being provided at more than

one LOCATION, CONTRACTOR may be required to provide different levels of HSE management at each LOCATION.

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CONTRACTOR’s Initial COMPANY’S Initial Amendment 1 to CON-ANG-31-5367

3.0 COMPATIBILITY OF HSE MANAGEMENT SYSTEMS

3.1 CONTRACTOR’s HSE management system shall, where relevant interfaces exist, be compatible with COMPANY’S HSE management system. CONTRACTOR shall liaise with COMPANY REPRESENTATIVE to ensure that the roles and responsibilities in the systems of all parties are clearly defined and allocated and are clearly understood by all parties involved in the DRILLING SERVICES and associated operations.

3.2 Within the framework of its HSE management system, CONTRACTOR shall perform the DRILLING SERVICES to

HSE performance standards, which are compatible with those in COMPANY’s HSE Management System.

3.3 Where appropriate, the interfaces between CONTRACTOR and COMPANY shall be documented in the form of an HSE Management System (HSEMS) Interface Document which when agreed between the PARTIES hereto shall be deemed to be incorporated in the CONTRACT. The preparation of these Interface Documents shall be to the account of the CONTRACTOR and shall be prepared before the COMMENCEMENT DATE. The HSEMS Interface Document shall incorporate any specific requirements relevant to the DRILLING SERVICES and take account of current industry standards, appropriate legislation and guidelines applicable to the CONTRACT AREA.

3.4 Where applicable, the CONTRACTOR shall ensure that similar standards apply to the HSE management systems used

by all SUBCONTRACTORS.

3.5 CONTRACTOR’S HSE management system together with the HSE Management System Bridging Document (“HSEMS”) shall collectively define and govern the HSE requirements for the DRILLING SERVICES.

4.0 COMPLIANCE

4.1 CONTRACTOR and its SUB-CONTRACTORS shall observe and comply with all relevant and current statutory requirements, approved codes of practice and industry guidance on HSE matters.

4.2 CONTRACTOR shall ensure that PERSONNEL and personnel provided by the CONTRACTOR comply with all

relevant HSE legislation and guidance and that they are:-

(a) fully conversant with the working conditions at the LOCATION, the hazards and risks associated with the DRILLING SERVICES and the roles and standards relating to the environment including the handling of waste and hazardous materials;

(b) fully aware that they are expected to bring to the immediate notice of their Supervisor all health, safety and

environmental risks which they believe not to be under adequate control, so that action may be taken to prevent potential injuries or other losses and provide a safe and healthy workplace;

(c) familiar with all other safety and working instructions applicable in the CONTRACT AREA; and

(d) available at all times for periodic drills, instructions on survival, life saving and fire fighting as requested and

conducted by COMPANY and shall, prior to or on the day of arrival offshore, attend a safety induction course conducted by the COMPANY.

4.3 If, in the opinion of COMPANY REPRESENTATIVE, CONTRACTOR is working in a manner which contravenes any

requirement of these HSE provisions, COMPANY shall serve notice on CONTRACTOR to this effect and CONTRACTOR shall immediately take action to rectify the situation.

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CONTRACTOR’s Initial COMPANY’S Initial Amendment 1 to CON-ANG-31-5367

5.0 REPORTING

Full details of the HSE reporting responsibilities of the CONTRACTOR are provided in ATTACHMENT 2 to SECTION 4. 6.0 WORKING CONDITION

6.1 CONTRACTOR will immediately notify COMPANY REPRESENTATIVE of all CONTRACTOR incidents resulting in personal injury or damage to property in connection with the DRILLING SERVICES.

6.2 CONTRACTOR shall ensure that it’s PERSONNEL and shall keep all places of work as clean and tidy as is reasonably

practicable under the circumstances, to minimise the risk of causing injury to persons, damage to property or delays in providing the DRILLING SERVICES.

7.0 WASTE DISPOSAL AND ENVIRONMENTAL SAFEGUARDS

In the performance of the DRILLING SERVICES, CONTRACTOR shall at all times:-

(a) observe and comply with all laws and regulations concerning the production, carrying, keeping, treating and/or disposal of waste;

(b) act to minimise the quantity of wastes; and

(c) comply with the worksite environmental management system as it affects their operations.

If required by the applicable law, CONTRACTOR shall register as a Registered Waste Broker or a Licensed Waste Manager.

8.0 SUBSTANCE ABUSE POLICY

8.1 COMPANY is committed to providing a safe and healthy and working environment for all employees, visitors and third parties impacted by our operations. This includes an environment free from the hazards caused by the abuse of substances including drugs and alcohol. The policy equally applies in all aspects to both onshore and offshore staff both of COMPANY and its contractors and at all locations where work is performed on behalf of COMPANY.

8.2 In addition, COMPANY specific requirements related to applicable law and the CONTRACT AREA may require

additional considerations to be appropriately managed by CONTRACTOR. Specific requirements applicable to the CONTRACT AREA are additionally included in SECTION 8 – Attachment 2.

9.0 HSE REFERENCE DOCUMENTS

9.1 In the performance of the DRILLING SERVICES, CONTRACTOR shall, as appropriate, refer the following reference documents attached hereto:

Attachment 1. Scope Specific HSE Requirements Attachment 2. CONTRACT AREA Specific HSE Requirements

• GoM Specific Health, Safety, Security, and Environmental Requirements • Substance Abuse Policy

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9.2 CONTRACTOR shall observe and comply with these HSE provisions and failure to meet their requirements or to satisfy

COMPANY with regard to the control of HSE risks will be regarded as due cause for termination of the CONTRACT without notice and without financial penalty to COMPANY.

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ATTACHMENT 1 Scope Specific HSSE Requirements

The following HSSE Standards for Drilling Equipment shall apply to this CONTRACT. HSSE Standard 01 Vibration HSSE Standard 02 Noise HSSE Standard 03 Automation/Mechanisation HSSE Standard 04 Man Riding HSSE Standard 05 Lifting Operation HSSE Standard 06 Waste Management HSSE Standard 07 Maintenance HSSE Standard 08 Dropped Objects HSSE Standard 09 Risk Management HSSE Standard 10 Ventilation HSSE Standard 11 Lighting HSSE Standard 12 Work Time HSSE Standard 13. Hazardous Material

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HSSE Standard 1

HSSE Standard 01 – Vibration Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. The purpose of this standard is to ensure that personnel are protected against the effects of Hand Arm Vibration Syndrome (HAVS). Without effective controls, people who use high vibration tools on a regular or prolonged basis may suffer various forms of damage to their hands and arms. The widest known form of damage is “Vibration White Finger” (VWF). All personnel who use power tools for any period that could cause HAVS should be monitored for their exposure and necessary controls put in place to prevent such injury occurring. The Drilling Contractor and Well Services Providers shall ensure that all tools and equipment used on the Well-site is designed to minimize vibration levels to as low as reasonably practical. The fabrication/refurbishment methodology should also take account of the tools to be used and wherever possible, those having the potential to cause HAVS should not be employed. A tool register and tracking system should be in place. Regular health screening of employees likely to be at risk shall be conducted. The BP Well-site Representative shall also be responsible for periodically reviewing compliance arrangements for their effectiveness and continuous application. Prior to any work commencing, a Task Risk Assessment (TRA) must be carried out and all personnel likely to be using power tools with the potential to cause HAVS made aware of the associated dangers. This standard covers, but is not exclusive to the following tools:

Air Hammers Air Chisels Needle Guns Angle grinders Bench Grinders Drills or similar hand held tools

Specification: Low vibration equipment should be the preferred option where possible. When purchasing new tools or equipment. Prior to purchase, information should be sought regarding vibration levels and vibration controls which are built into the equipment. When working with powered equipment, it is essential that good working practices are adopted. The hierarchy of control measures along with a number of simple but effective practices can be adopted to reduce the risk of injury to that which is as low as is reasonably practicable. In order to keep vibration levels down to the absolute minimum necessary for efficient operation, equipment should be regularly inspected, serviced and maintained. Manufacturers and Drilling Contractor maintenance schedules should be followed. All defects or damage should be reported immediately. The following measures can also help keep down vibration exposures: Cutting tool should be kept sharp Grinding wheels should be dressed properly

Amendment 1 to CON-ANG-31-5367

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CONTRACTOR’S Initial COMPANY’S Initial

Worn parts should be replaced Vibration dampers, bearings and gears should be checked and replaced when found to be defective Competency: It is important that those persons operating powered tools are competent in their use. Operators need to be made aware of the hazards and what can be done to reduce the risk. Key information should include: Potential sources of hand-arm vibration The health effects of hand-arm vibration The risk factors - high levels of vibration and regularity of exposure Ways to minimise risk including:- Changes to working practices to reduce exposure How to use tools to minimise grip force, strain etc. Maintenance of good blood circulation at work Symptoms: Tingling or pins and needles at the end of the work period (may be accompanied by numbness). With continued exposure, the user may suffer periodic attacks in which the fingers change colour when exposed to cold. In mild cases the whiteness and numbness only affects the tips of the fingers. As the condition becomes more severe the whole finger down to the knuckles becomes white. Maintaining good blood circulation is important in avoiding HAVS and the symptoms associated with it, so in cold weather stay warm, wrap up in warm waterproof clothing, wear lined gloves or use glove liners and avoid standing or kneeling in the same position for prolonged periods.

Amendment 1 to CON-ANG-31-5367

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CONTRACTOR’S Initial

COMPANY’S Initial

HSSE STANDARD 02 NOISE

HSSE Standard 02 – Noise Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. This Standard is intended to outline an approach for the management of noise in order to reduce the risk of noise-induced hearing damage. Hearing damage is cumulative and irreversible and can occur over a long period of time. During facilities design, individual items of equipment, and complete systems should be assessed to ensure that noise levels are kept as low as reasonably practical. Well-site supervisors have a duty to ensure that all people working under their control are made aware of any noise risks associated with their activities or workplace, the effects of exposure to high noise levels and the necessary precautions to be taken. This should be formalised as part of local safe systems of work within e.g. Task Risk Assessment, Job Safe Analyses and Permit to Work processes. Noise exposure shall be reduced to the lowest level reasonably practicable. Factors to consider are; a) noise action levels expressed in decibel units as dB(A) and; b) how long people are exposed to the noise, daily and over longer periods of time. First Action Level - a daily personal noise exposure of 82 dB(A) for 12 hours. Second Action Level - a daily personal noise exposure of 88dB(A) for 12 hours. Peak action level - this is based on the highest pressure reached by an instantaneous sound pressure level for any single event e.g operation of mud pump pop-off valve. Where Well-site personnel are likely to be exposed to noise, then a competent person should complete a noise assessment to: a) Identify which employees are involved b) Determine the action level Areas at first action level and above should be identified as ear protection zones and ear protection provided. Where noise levels are at second action levels and above then steps should be taken to reduce exposure by means other than ear protection e.g.

Noise reduction at source during workplace/equipment design and specification Engineering control ie damping, isolation, silencers, maintenance etc Enclosure, screens, barriers and noise refuges Reduction of time spent in noisy areas

Ear protection zones should all be clearly demarcated and signs fitted at appropriate places to alert people of the hazards. Adequate supplies of technically suitable hearing protection devices should be made available. Where employees are likely to be exposed at or above any action levels they must be provided with information, instruction and training that covers:

Risk of damage to hearing Steps to minimize that risk How to obtain and use ear protection How to report defects

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CONTRACTOR’S Initial COMPANY’S Initial Amendment 1 to CON-ANG-31-5367

All noise measurement equipment should be regularly tested in line with a formal planned maintenance system requirement. Where it is not reasonably practicable to mark ear protection zones then adequate alternative arrangements should be made to ensure employees are aware where or when protection should be worn eg:

Attaching warning signs to tools Written instructions for particular tasks (ie permit to work)

Audit and Review Noise assessment and noise management actions require to be documented and resultant recommendations placed within a suitable action tracking system. Such noise management records require periodic review to track action items eg:

New noise sources addressed Noise assessments up-dated and verified Training schedules met

Targets for continuous improvement should be established and a process should exist for regular self assessment. GLOSSARY AND ABBREVIATIONS dB(A) - Unit of sound level and noise exposure. A-weighting (A) of the audible frequencies is designed to compensate for the sensitivity of the ear. The ear is more sensitive to noise at frequencies in the middle of the audible range than it is to either very high or low frequencies.

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HSSE STANDARD 03 – AUTOMATION/MECHANISATION

HSSE Standard 03 – Automation/Mechanization Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. Within the Drilling industry, the move from manual to mechanization and/or automated systems is growing. This is particularly noticeable on some of the new build offshore MODUS where many of the tasks that previously required some degree of manual handling, are now completed by automated or mechanized processes. Unless correctly managed from conception to completion these processes do not necessarily make drilling operations safer. Mechanization may reduce minor hazards but potentially introduce more serious hazards such as equipment collision and dropped objects onto main working areas. The following must be followed for drilling implemented mechanization or automation projects. During conception, build and commissioning To achieve optimum levels of safe operation, a holistic approach should be applied whereby designers, manufacturers and importantly end users all have input to the risk assessment process at the earliest possible stage. A competent third party should carry out QRA to ensure that there are actual benefits. The engineering complexities introduced by mechanized and automated systems should be fully evaluated on the basis of risk assessment. Subsequent training of personnel must take account of the human factors involved. Computerized control programmes should be devised jointly by the software specialist, equipment manufacturer and subjected to a risk assessment process involving the end user. Software and control systems must be embedded is such a manner that no matter what happens to power supplies onboard the rig including induced surges and loss of UPS battery derived power, no software is corrupted or lost, nor any control system malfunctions. MOC procedures should be used for software changes during commissioning, final back up software should be stored in a fireproof location and be quickly accessible. It is important that upgrading equipment does not become a reason to “dumb-down” the quality of the operators, if anything the project should ensure that proficiency standards rise. A suitable “competency matrix” should be produced and implemented prior to operations. The decision to mechanize/automate increases the requirement for strong, maintenance systems. Maintenance processes must be upgraded before the equipment starts to operate on drilling operations. This includes manuals, drawings, maintenance training and incorporation into the Planned Maintenance System. Before a mechanization and/or automation project starts the various philosophies that introduced equipment will operate around must be understood, agreed on by all vendors and followed during the project e.g. is zone management to be controlled by anti collision or collision awareness processes. Mechanization and automation often needs to be backed up by other critical systems e.g. CCTV. The provision and design of these systems must be part of the overall project and no final commissioning should start until all systems have gone through equipment testing in their final position.

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Unless other critical design characteristics prevent it, new build mechanized rigs should use a minimum 40 by 40 floor area to give adequate space for personnel movement and equipment. The drillers cabin must be located so that there is an uninterrupted view of all mechanized equipment and operational areas including the “V” door. For major upgrades/new build simulators working in a safe environment should be used for initial training, prior to individuals using actual rig equipment. The design team must develop, within the Basis of Design, an outline of how operations will continue / stop in the event of equipment failure. During Drilling and other operations Before any laptop is connected to an operational system – a PTW must be correctly issued with implications of potential failure fully explained to all parties. No software is to be modified without written permission from a competent authority. All modifications must be under a PTW process. In the event of the failure of a critical system or part of such a system e.g. CCTV, unless unsafe to do so for well control reasons, rig floor operations must be halted and only restarted once suitable risk analysis and mitigation is in place. Protection systems such as Zone Management must be fully tested, as a minimum, on a daily basis and the tests recorded in the IADC logbook. In the event of failure within any aspect of the Zone Management unless unsafe to do so for well control reasons, rig floor operations must be halted and only restarted once suitable risk analysis and mitigation is in place. A fully functional register of any “bypasses and defeats” relating to software, sensors etc for mechanized and/or automated equipment, must be in place before any operations commence. The contents of the register must form part of any toolbox talks and any other processes relating to risk awareness.

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HSSE STANDARD 04 – MAN RIDING

HSSE STANDARD 04 - MAN-RIDING Please note – This standard outlines the minimum conditions that shall apply before any man-riding operation can take place on a COMPANY operated drilling rig. Local legislative requirements and industry standards should also be considered. Lifting and lowering personnel by air hoist (man-riding) on drilling rigs is considered a high potential risk activity and must only be considered when no safer alternative method can be found. Man-riding must be kept to an absolute minimum and shall only be performed under the strictest of controls and always with the permission of the on duty OlM/Tool-pusher/Rig Superintendent. Man-riding must only take place under the supervision of the person in charge of the area who shall nominate only trained personnel to perform tasks. The following controls must be adhered to on any COMPANY drilling operation: Man-riding should be considered a “safety critical” routine and must be conducted under a Permit to Work. A pre-job risk assessment/Job Safety Analysis and tool-box talk must be held. Specific working instructions must be available, understood and followed by all those involved in the operation. A min of three people shall be used at all times and clear lines of communication established. Consideration should be given in the use of the hands free radio. Hand signals are to be agreed by all parties prior to commencement of the man-riding operation. Adverse weather conditions and lighting conditions should be assessed prior to the commencement of any man-riding operation. Man-riding air-hoists shall be used solely for hoisting and lowering personnel and must incorporate the following safety features in their design: a) The hoist-operating lever should automatically return to neutral on release from any operating position. b) An automatic brake should be fitted so that it will apply whenever the operating lever is returned to neutral or on loss of

power. c) In the event of failure of the automatic brake a secondary brake should be provided to prevent the load from falling. This may

be manual in operation and simple in design. d) A clutch capable of disengaging should not be fitted. f) A plate fixed to the frame of the man-riding air hoist stating “For Manriding Purposes Only” and the Safe Working Load

should be clearly Identified on the air-hoist. g) The air supply to the hoist will be regulated to the manufacturers recommended air pressure. h) A device should be fitted to prevent the winch from over-riding or under-riding e.g. a ball type, isolation valve on the air

supply line, close to the hoist- operating handle. I) A functional load limiting device should be installed. j) Anti-spin wire should be used or a swivel fitted to prevent the rope turning.

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k) Hydraulically operated man-riding winches should have self-locking and self braking systems fitted. Safety hooks shall not be attached to the air hoist line when used for man-riding. The employee must be shackled directly onto the end of the air hoist line without any intervening chains, slings, swivels or other fittings. (Shackle must be secured) Any tools carried into the derrick must be tied off to either the employee or the air hoist line and no other equipment shall be lifted. (All tools should be logged) The riding belt used shall be of an approved standard and inspected for wear or damage before use. When man-riding operations are taking place, all other operations in the vicinity shall be suspended. At no time shall the traveling blocks be moved or pipe rotated. No other activity shall interfere with man-riding operations. A sign shall be placed in Dog House clearly stating that man-riding operations are on-going. Personnel involved in man-riding operations shall be fully trained and deemed competent to perform the work. When a man-riding lifting basket is used it must be verified that the slings and basket have a current Certificate of Inspection. The total weight of the basket, equipment and personnel must be determined to ensure the safe working load of the air-hoist and the basket slings are not exceeded. Personnel riding in the basket must have a safety line secured to the air-hoist line and when work is carried out above the monkey board level, radio communications shall be used and a banksman shall maintain line of sight at all times. Mechanised man-riding lifting baskets e.g. “cherry-picker” should have a collision/ emergency stop system fitted. When any equipment or tools are hoisted into the derrick, the area below shall be kept clear of personnel and steps taken to ensure no one enters into the area. Consideration shall be given to the weight of air-hoist line versus the weight of the man rider when hoisted above a certain level (e.g. the minimum weight of a man while using 19mm airhoist line above the monkey board level is approximately 200lbs/91kg). Prior to commencing with any man-riding operation a contingency rescue/recovery plan should be established in the event of possible equipment failure or power loss. All of the above safe working practices would apply when man-riding operations are conducted under the drill floor.

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HSSE Standard 05– LIFTING OPERATIONS

HSSE Standard 05 – Lifting Operations Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. (This standard incorporates BP Golden Rules of Safety relating to Lifting Operations) The purpose of this standard is to prevent injuries or incidents during mechanical lifting operations. All lifting equipment shall be certified or successfully load tested and documented prior to use. Lifting equipment comprises: lifting Gear – any device which is used or designed to be used directly or indirectly to connect to a load or appliance (e.g. a crane or chain block) and does not form part of the load, e.g. sling, chain, hook, shackle, eyebolt or lifting beam. Lifting Appliances – any mechanical device capable of raising or lowering a load, e.g. a crane, winch, pipe handler, BOP handler, fork lift truck or chain block. All lifting operations shall be planned and appropriately supervised. The level of supervision will be determined by an assessment, by competent person, of the lift to be completed. The first step in planning shall be to conduct a Risk Assessment/Job safe Analysis. Risks identified can then be eliminated or adequately controlled so that the job can be safely completed. Lifting Gear All lifting gear shall be certified for use, as a minimum, within the previous twelve months. Prior to use, all lifting gear and lifting appliances shall be marked with their safe working load (SWL) and be visually examined by a competent person. A system of color coding shall be used whereby only lifting gear with the current color code can be used. A register of lifting gear shall be maintained at each Well-site which shall include:

• Description of gear, e.g. 4 leg sling with links and lifting ring, socket each end • Certification number (or Identification number if different) • SWL • Date in Service • Location in use at Well-site • Dates inspected

Before the lifting operation commences, the following checks shall be made:

• The SWL is clearly marked • The ID number is visible so that equipment can be checked against certification • The color code is current • The equipment is not damaged in any way

Hand spliced wires and slings are not permitted. When transporting barrels, a net, basket or specialist device is recommended. Slings constructed in synthetic fibres are easily damaged and can be sensitive to chemical attack. Strength is lost if there are any cuts, tears, abrasion, fraying and burst stitching, therefore this sling type requires close examination by a competent person for any signs of damage prior to every lifting operation. Storage of web slings shall be strictly controlled to preserve their condition and prevent contamination. Positive locking pipe hooks, as opposed to open ended pipe hooks, will be used when lifting casing by the box end or pin end with a crane.

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Slings not included in the lifting gear register shall be kept separate from those tracked in the register. This refers to BP/Third Party transit slings that do not belong to the Drling Contractor. Lifting appliances All lifting appliances shall be certified for use. Operators of lifting appliances shall be trained, competent and certified for that equipment. All lifting appliances will be included within the Planned Maintenance system in use at the Well-site. Crane operations Crane operators shall be able to clearly communicate with the handling crew, only one of which should be designated as banksman. Hand signals should be clearly understood by everyone involved in the lifting operation. Check the area around the load to be lifted is clear and the load is not attached to the deck, transportation cradle, or adjacent equipment. The banksman shall not be both banksman and slinger. The banksman is in charge of the lift and is there solely to direct activities and operations. If using hand signals stand in a position where the crane operator can clearly see him and he can maintain visual contact with the load. All hooks used on the traveling blocks, fast line and slings shall have safety latches fitted that are in good working order. Routine maintenance of the crane will be in accordance with the planned maintenance system. A crane log book shall be maintained and should include maintenance records, wire rope installation dates, safety device inspection dates, including calibration, certificate and reel number of the wire currently in use. Fork Lift Fork lifts will be rated and maintained to meet the area classifications of the area in which they are to operate. Fork lifts shall be fitted with: an audible warning for reversing, a visual warning in noisy areas, a reversing mirror and a caged driver enclosure. When parking a forklift the forks should be six inches off the deck and the mast tilted forward until the forks rest on the deck. The engine should then be switched off and the keys removed. In cold climates, fork lift trucks may be left with power on, subject to local controls. Air Winches Operators should have clear visibility of the operation and operating instructions clearly displayed, Air winches shall be operated according to manufacturer’s instructions, fitted with drum guards and control levers marked up and down.

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HSSE STANDARD 06 – WASTE MANAGEMENT

HSSE Standard 06 – Waste management Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. Waste management involves monitoring of emissions, wastes and discharges as well as surveillance of the receiving environment both within and outside the Well-site, against set targets, using proper disposal practices. Developing a waste minimization plan should be a fundamental part of the overall well planning process and should integrate BP and Third Party requirements with those of the Drilling Contractor. At each Well-site, there shall be adequate storage facilities to provide containment of hydrocarbons and chemicals. Transfer of these substances will be subject to control measures that have been developed using risk assessment techniques. A system shall be in place to ensure that relevant personnel have been trained in those control measures. At each Well-site, all discharges arising from drainage shall be monitored to prevent sea or land contamination by substances harmful to the environment. Similarly, prior to their discharge, either to sea or to landfill sites, all substances shall be evaluated for their potential effect on the environment. Emergency response plans shall include contingencies for effectively managing and responding to chemical and hydrocarbon spills, all of which shall be reported through both BP and Contractor reporting systems. Rig equipment, primarily including, but not limited to, engines used for power generation, and refrigeration / fire-fighting systems, shall be maintained to prevent excessive emissions (gases) to the atmosphere. Excessive is defined as any generation of emissions greater than expected within manufacturers operating parameters. Systems shall be in place to ensure that expected performance is being maintained. Leakage of halons and other chlorinated fluorocardons (CFCs), considered to be ozone depleting chemicals shall be minimized through effective air emissions tracking and prevention programmes. Halons and other CFCs may be used to replenish existing systems, but new systems shall not employ the use of ozone depleting chemicals where environmentally friendly alternatives are available. Contractor waste management systems and processes shall be a consideration during the BP rig selection process.

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HSSE STANDARD 07 – MAINTENANCE

HSSE Standard 07 – Maintenance Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. Well-site facilities shall be maintained within their design envelope to ensure safe, healthy, and efficient and environmentally secure performance. The Contractor shall have in place a planned maintenance system (PMS) for the equipment. All safety critical, load bearing, lifting, hoisting and pressure containing equipment shall be included. The system shall be rigorously applied and details of any overdue items shall be reported on a periodic basis to senior Contractor management. The BP Well-site supervisor shall periodically take an overview of the application of the PMS and shall be kept informed of critical maintenance overdue items. Third party equipment on long-term hire and located at the Well-site shall also be subject to a formal system of planned maintenance and inspection. Third Party equipment on short-term hire shall have been subject to formal maintenance and inspection checks prior to transport to the Well-site. All third party equipment should have appropriate certification prior to transportation and during the storage on the offshore installation. Clearly defined and documented maintenance and inspection procedures shall be in place to maintain technical integrity. Personnel shall be trained in the use of these procedures and fully understand their application. Maintenance personnel must be trained and competent in their maintenance discipline. All lifting equipment shall have been certified for use within the previous twelve months and shall be visually examined before each lifting operation by a competent person. The most recent equipment certification should be available at the Well-site for inspection at all times. Registers and systems shall be maintained for safety critical equipment, well control equipment, temporary equipment, lifting equipment, hoses, pressure gauges and pressure relief valves.

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HSSE STANDARD 08 – DROPPED OBJECTS

HSSE Standard 08 – Dropped Objects Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. The potential for dropped objects/falling objects from within drilling derricks and from other areas around the rig is high. The problem is common to fixed installations, mobile drilling units and land rigs. Dropped objects prevention has been the subject of various cross-industry initiatives over the years. Within BP, the DROPS campaign provides an example of dropped objects prevention best practice and covers derricks/masts, lower substructures and BOP areas. The following standard draws from cross industry Drilling Contractor input to the DROPS programme DROPS standards/expectations should be included at the facility design review/assessment stage. Raise awareness by alerting individuals to the potential and consequences of dropped objects. This should be done at an individual level, safety meetings, tool-box talks and other related forums. The second step is to divide the derrick and sub-floor level into different zones and compile an inventory of equipment. Fastening methods should be identified, tag numbers recorded (where applicable). The time and effort spent initially compiling this list will be beneficial as it will indicate every item within the derrick and sub-structure. In addition, it should highlight any item that has the potential to drop. Remove all redundant equipment that which will not impact on essential items. For all remaining essential items, controls and standards should be in place based on associated risk. A periodic inspection process should be put in place to ensure that these controls and standards continue to be adequate and to assess the necessary actions required to prevent items from falling. Third party hoisting and lifting surveys should be checked for their effectiveness. Follow-up of inspection findings should also be checked. Third party equipment handled and used in the derrick should be viewed in the same way once all rig owned equipment has been considered. A primary cause of dropped objects over recent years has been winch operations. The operation of the winch must be such that the people are knowledgeable of the system, are trained banksmen and operate the winch within the design criteria. The principles as described above for preventing dropped objects do not change in the automated environments of remote controlled drilling systems. Stringent inspection routines and familiarity with the proper use of automated systems must be maintained at all times. In order to keep the system live, it needs to be updated whenever changes are made to the inventory or to the structure itself.

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HSSE STANDARD 09 - RISK MANAGEMENT

HSSE Standard 09 – Risk Management Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. Risk Management at the Well-site involves control of risks arising from the complete cycle of activities ranging from the selection of resources, the design and operation of working systems, the delivery of services and the control and disposal of waste. Risks shall be reduced to a level deemed to be “As low as reasonably practical” (ALARP). The principle of ALARP allows effort to be focused to where it will have most impact. At each Well-site, an established risk assessment process shall be in place that is documented, effective, and auditable and is communicated throughout the organization. This process shall be based on:

• Hazard identification – identifying hazards which are the potential causes of harm • Risk assessment – assessing the risk which may arise from the hazards • Risk Control – deciding on suitable measures to eliminate or control risk • Implementing and maintaining control measures - implementing standards and ensuring that they are effective

The following is a summary of the preferred hierarchy of risk management principles:

• Eliminate risks by substituting the hazardous with the less hazardous – e.g. by using a less hazardous substance or by substituting a type of machine that is better guarded to achieve the same end result

• Combating risks at source by engineering controls – e.g. by protecting the dangerous parts of a machine by guarding or by designing machinery that reduces the amount of manual handling (iron roughneck)

• Minimise risks by the design of suitable systems of working • Minimise risks by the use of personal protective equipment

The hierarchy reflects that risk elimination and risk control by the use of physical engineering controls can be more reliably maintained than those, which rely solely on people. There are several risk assessment tools available and the level of the risk assessment will depend on the complexity and nature of the hazards involved in each particular operation. The BP Golden Rules of safety define the minimum Permit to work, Confined Space Entry and Energy Isolation requirements. At each BP Well-site, these formal systems shall be supplemented by risk assessment tools, which shall include:

• Safety Observation Programme - e.g. STOP/START • Task based risk assessment/Job safe Analysis – a simple, systematic assessment undertaken by persons with the knowledge

and experience of both the specific task and the location where the task will be undertaken • Inspection and Audit Programme – Both BP and the Drilling Contractor shall follow a formal system of inspection and

audit covering all aspects the rig and the management systems in place • Toolbox Talks - Pre-Job meetings where all personnel involved (including Third Party) gather to discuss and understand the

nature of the work to be performed and the controls to be exercised to reduce risk to ALARP • HAZID (Hazard Identification) – Structured and systematic assessment of an activity split into a number of steps with each

step being reviewed in sequence asking “what could go wrong?” e.g. drilling a high temperature/high pressure well • HAZOP (Hazard and Operability) - generally used when identifying equipment hazards at the design stage

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• Health and Safety Method Statements - Effective way of providing information to employees about how work is expected to be done and the precautions that should be taken

• PHSER (Project Health Safety Environmental Review) - To assure the client Business Unit that HSE sensitive areas have been identified and that appropriate project engineering and operational systems have or will be developed to control identified HSE risks.

• Major Accident Hazard Identification and Assessment – Structured and systematic assessment of all major accident hazards that may affect the drilling rig e. g. Escape of hydrocarbons leading to possible fire, explosion, or toxic gas release; collisions offshore; structural/mooring foundation failure; Major mechanical/electrical failure; Loss of stability/buoyancy.

All personnel at the worksite should be aware of which level of risk assessment is applicable to given tasks. In particular, personnel must be aware of the day to day risks associated with Routine tasks and must not rely on predetermined or standard assessment sheets. Where the Well-site work may impact other activities e.g. ongoing production operations, a simultaneous operations review shall be held and the risks and control measures documented and communicated to all relevant personnel. Further information and guidance can be found within the key HSE processes that support Getting HSE Right expectations (Key Process Number Three – HSE Risk management)

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HSSE STANDARD 10 – VENTILATION

HSSE Standard 10 – Ventilation Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. Well-site environmental problems may arise due to the presence of airborne pollutants such as dust, gases or vapours, or due to an uncomfortable or stressful thermal environment. Consideration to these potential problems should be given initially at the design stage where, as far as reasonably practical, equipment and facilities shall be designed to minimize the presence of airborne pollutants. Where such pollutants are unavoidable and in addition to other controls that may be required on the basis of risk assessment, Well-site ventilation shall be provided to control emissions, exposures, and chemical hazards. Ventilation may be deficient in:

• confined spaces; e.g. mud storage tanks and enclosed vessels • facilities failing to provide adequate maintenance of ventilation equipment; e.g. around shale shaker areas • windowless areas; and • areas with high occupant densities.

Ventilation systems can be employed in three ways:

• Local Extract Ventilation (LEV) should be used as close to the source of pollutant as possible to minimize the escape of the pollutant into the atmosphere. The extraction devices can be either hoods, enclosures or fume cupboards coupled to a system of ducts, fans and air cleaners.

• Dilution Ventilation should be used to reduce the concentration of the pollutants to a safe level. • Heating, ventilating and air-conditioning systems (HVAC) should be used to convey heat or cooling in order to control

temperature and maintain reasonably comfortable conditions.

As part of the Well-site Safety Management System, there shall be a process for ensuring that a competent person tests airborne concentrations of pollutants, and that suitable and adequate ventilation is provided where necessary. Where ventilation has been fitted, it shall be included within the Well-site planned maintenance system and be tested to ensure that design criteria are being met and that efficiency is being maintained. All Third Party equipment brought onto the Well-site, shall also be subject to these controls. Many working environments are uncomfortable due to excessive heat or cold in one form or another. Expected temperatures, the rate of work and the type of clothing to be worn shall be taken into account when considering thermal environment ventilation controls. Health surveillance programme As part of the ongoing health surveillance programme, all ventilation systems should be tested annually by competent Occupational hygienist.

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HSSE STANDARD 11 – LIGHTING

HSSE Standard 11 – Lighting Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. Well-site lighting systems shall provide a sufficient level of illumination in all areas likely to be manned and where apparatus is installed. Working areas, drilling derricks/masts, corridors, stairways, ladders, walkways and landings shall be especially well lit. Lighting systems shall be provided so that escape routes, embarkation areas (where applicable) and any control panel or operational station which would need to be manned in the event of loss of normal electrical power can be supplied from the emergency power source. The twenty-four hour nature of Well-site activities requires natural lighting to be supplemented by artificial sources. When work is conducted under artificial light, the effects of glare, an excess of natural and artificial lighting and of lighting deficiency shall be considered and assessed. Both extremes shall be avoided. Dust, dirt and use will progressively reduce the light output. Attention to general cleaning and maintenance and a realistic lamp replacement policy will help maintain the required standard of illuminance. Sufficient spare parts for Well-site lighting shall be maintained at the Well-site. During the facilities design stage, adequate and secure means for accessing and maintaining lighting systems should be accommodated. All light fittings to have a secondary means of fixing to minimize dropped objects.

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HSSE STANDARD 12 – WORK TIME

HSSE Standard 12 – Work Time

Please note - This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs. This standard should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. The purpose of this standard is to avoid the need for Well-site personnel to work excessive hours that could lead to fatigue and subsequent impairment of mental alertness. For fulltime Well-site personnel e.g. Rig Crews, BP Drilling Supervisors and Catering crews, work rotas should normally be based on an equal time rotation, (e.g. 2/2 or 4/4 week rotation) the length of time depending on area of operation. The normal maximum work period is twelve hours (Operations may be based on shorter work periods e.g. eight hours, with less time spent away from the work location). Where possible, the shift patterns should avoid “short changes.” Add-hoc Well-site personnel e.g. Service Hands and occasional visitors will normally comply with the normal maximum work period of twelve hours. Where it is identified at the planning stage that the work cannot be completed within the twelve hour period, additional hours may be worked when authorized by the Well-site Supervisor e.g. Senior Toolpusher. Where the operation exceeds twelve hours on an ongoing basis, either additional resource must be made available, or the operation should be suspended and resumed on the next shift period. Working hours shall be monitored and where necessary additional hours shall be authorized on the following basis by the Well-site Supervisor:

• 0 – 12 hours - no additional authorization required • 12–16 hours - only with the agreement of the line Supervisor, who shall advise the Well-site Supervisor. • Over 16 hours – only with the permission of the Well-site Supervisor (hours to be recorded in log)

Personnel shall have a minimum eight hour rest period after each twelve hour shift. Work time may need to be considered as part of the risk assessment process. When this is the case, factors to be considered should include:

• The nature of the demands (both physical and mental) • The working environment • The work activity • Sleep deprivation e.g. off duty call out • Travel aspects e.g. travel time to rig, possible weather delays • Back-up for “no-shows”

The above applies to all Well-site personnel.

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HSSE STANDARD 13 – HAZARDOUS MATERIAL

HSSE Standard 13 – Hazardous materials Please note – This standard outlines the minimum conditions that shall apply on all BP operated drilling rigs and should be considered and applied in conjunction with Contractor management systems, local legislative requirements and industry standards. All materials and substances that may have an adverse effect on health or the environment are considered hazardous. Personnel who are required to work with hazardous materials and substances shall be made aware of the hazards and given adequate training and instruction to include; the nature of the material and the risks created by exposure; the precautions to be taken; how to use relevant personal protective equipment; emergency procedures. At each well-site there shall be: • A system to maintain hazardous chemicals inventory & Material Safety Data Sheets (MSDS). Third Party suppliers e.g. mud

companies will be made aware of and shall follow this system • A person responsible for controlling and co-ordinating hazardous substances • An understanding and application of the hierarchy of risk controls (elimination, substitution, engineering, procedural, PPE as last

resort) • An assessment process which identifies any requirement for exposure monitoring &/or health surveillance • A means of informing the workforce of health risks and precautions for tasks involving hazardous substances e.g. Right to Know

Law in US and duties under Health and Safety at Work Act in UK • Contractor & Third Party alignment on Hazardous Substances management Only approved personnel shall handle explosives, radioactive materials, dangerous liquids and gases. The Permit to Work System shall be used to control the handling of these items. A process summary is outlined on the following page which should be used as a guide to managing hazardous materials at the Well-site.

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Hazardous Material Process Summary

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GoM Specific HEALTH, SAFETY, SECURITY, AND ENVIRONMENTAL

REQUIREMENTS

The following constitute Health, Safety, Security, and Environmental (HSSE) Requirements for Contractor and any subcontractors performing work on Company Sites (real estate owned or leased by Company, where Company is the operator) and on Company Project Sites (where work is performed exclusively for Company). HSSE Requirements encompass compliance with all applicable federal, state/provincial, maritime, and local statutes, regulations, enforceable agreements, agency orders, permits, and contract documents. HSSE Requirements also include specific Company requirements as disclosed below and any site-specific requirements not specified below. Each contractor will ensure that any subcontractor it employs meets these HSSE Requirements. Contractor will take any additional precautions necessary to prevent harm to personnel or damage to the environment or, property. Contractor will strive to deliver an incident and injury-free work place. Contractor will provide, at Company’s request, a monthly breakdown of hours worked by Contractor PERSONNEL on the DRILLING UNIT Company Specific HSSE Requirements for all Contractors In order to meet Company’s specific HSSE Requirements, Contractor will have a HSSE Program with a focus on continual performance improvement (or utilize Company’s program). Company has the right to audit Contractor’s HSSE Program and documents. At a minimum, the following elements will be included in Contractor’s HSSE Program: 1) Leadership

Contractor Leadership will actively communicate HSSE expectations and Company requirements, routinely monitor HSSE performance, develop action plans for continuous improvement, and actively take ownership of HSSE.

CONTRACTOR will ensure that CONTRACTOR’S employees understand COMPANY’S HSSE policy.

2) Behavior Based Safety

CONTRACTOR will have a behavior-based safety program which, at a minimum, will include a safety observation program (or utilize COMPANY’S program) with performance targets. CONTRACTOR will communicate to CONTRACTOR employees the expectation that everyone has an obligation to stop work that is unsafe.

In addition, CONTRACTOR will have a hazard identification and risk assessment process for completing a daily pre-job task hazard analysis and/or work permitting system to identify and control the hazards to an acceptable level. At a minimum, a process for completing daily Job Safety Analysis (JSA), or Job Safety Environmental Analysis (JSEA), is required to facilitate the daily task hazard analysis.

3) HSSE Meetings

CONTRACTOR will conduct or take part in regularly scheduled on-site or off-site HSSE meetings discussing, among other topics, facility and job hazards, incidents, near-misses, site-specific safety and health rules, and site-specific procedures.

4) Incident Reporting and Investigations

CONTRACTOR will immediately notify COMPANY of all CONTRACTOR or SUBCONTRACTOR incidents resulting in personal injury, spills or releases, security issues, loss or damage to property, or near-misses. COMPANY may require CONTRACTOR to conduct an investigation for any HSSE incident. COMPANY retains the right to participate or conduct its own incident investigation. For all incident investigations, CONTRACTOR will provide a written investigation report to the COMPANY. The

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Provision and Operation of an Offshore Mobile Drilling UnitSECTION 8 HSE Management ATTACHMENT 2 CONTRACT AREA SPECIFIC HSE REQUIREMENTS


COMPANY’s Initial Amendment 1 to CON-ANG-31-5367

investigation report shall identify possible root causes associated with the incident as well as proposals for corrective action. When requested, CONTRACTOR will furnish COMPANY with a copy of non-privileged reports made by or on behalf of ONTRACTOR concerning an incident, including any non-privileged statements or other investigative material.

5) Personal Protective Equipment

CONTRACTOR will ensure CONTRACTOR’S employees have proper personal protective equipment (PPE) before work begins, and that PPE is worn as required. CONTRACTOR shall obtain and comply with individual site PPE requirements.

6) CONTRACTOR Employee Conduct

CONTRACTOR shall comply fully with the Substance Abuse Policy (Attachment 2 to this SECTION 8.0 of the CONTRACT).

COMPANY has the right to require CONTRACTOR to remove and bar from the COMPANY Sites or COMPANY Project Sites any personnel whose conduct (condition or action) jeopardizes the safety of any person. In addition, CONTRACTOR will not permit any barred person to work at any other COMPANY Site or COMPANY Project Site without prior COMPANY written approval.

7) Contractor Employee HSSE Competency

Contractor will ensure that regulatory required training for Contractor’s employees has been identified and completed. . Company may require reasonable additional site-specific training and documentation.

8) Short Service Contractor Employee Policy

CONTRACTOR will comply with its own or COMPANY’S site-specific short service employee policy.

9) Preventative Maintenance Program

Contractor will have a preventative maintenance program that includes, at a minimum, the identification and prioritization of maintenance for safety and/or environmental critical items.

10) Chemicals Brought to Company Site

CONTRACTOR will ensure Material Safety Data Sheets (MSDSs) are available at the COMPANY Sites and/or COMPANY Project Sites for all chemicals CONTRACTOR brings to the site, and that the MSDS is reviewed as part of the JSA/JSEA discussion

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Company Specific HSSE Requirements Specifically Selected for Certain Contractors (Company and Contractor will initial all those that apply). See web site for details: http://nasupplierhsse.bpglobal.com.

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Initialled by: (if applicable)

Contractor

Company

⌧

⌧

1. CONTRACTOR’S will have a written Waste Management plan at the COMPANY project site for work performed that, at a minimum, requires identification of waste and disposal methods Waste Management

⌧

⌧

2. COMPANY requires CONTRACTOR to have an acceptable CONTRACTOR’S Environmental

Management System (C-EMS).

3. Contractors will meet or exceed BP’s Driving Standard.

⌧

⌧

4. CONTRACTOR will have and apply a Fitness-for-Duty program which includes assessment of the physical capability of employees to perform certain specific tasks and a physical agility testing component.

5. CONTRACTOR will supply COMPANY with a valid Certificate of Recognition applicable to Province of Operation certified by Petroleum Industry Training Service (PITS) or Contractor’s Service Line certifying body.

⌧

⌧ 6. CONTRACTOR must have a working knowledge of the Drilling and Well Operations Policy.



SUBSTANCE ABUSE POLICY

COMPANY has a strong commitment to provide a safe work place for its employees and other persons working or visiting on its premises or projects. This “Substance Abuse Policy” (hereinafter this Attachment 2 “Substance Abuse Policy” is referred to as “Policy”), is established in order to assist in maintaining a safe working environment and to protect COMPANY property. Contractors, subcontractors, and vendors who perform labor or services on COMPANY premises, on COMPANY Projects, or on whose premises COMPANY’S employees spend substantial time must have and administer a formal substance abuse interdiction policy, which informs employees about the risks of using illegal drugs or misusing prescription and over the counter drugs. CONTRACTOR and SUBCONTRACTORS (hereinafter in this Attachment 2 “Substance Abuse Policy” referred to as “Contractor” or “Contractors”) must also implement a policy that includes substance testing of Contractor’s employees entering COMPANY premises. Contractors working on COMPANY’S premises shall be subject to testing under this Policy by COMPANY. Contractors working on COMPANY Projects must implement a policy that includes substance testing of personnel consistent with the terms of this Policy. For the purpose of this Policy, a “COMPANY Project” refers to any work performed under this CONTRACT. . COMPANY reserves the right to prohibit solicitation of bids from, deny entry to COMPANY premises, or cancel any project, or portion thereof, with any Contractor or vendor that fails to present a written policy that meets the COMPANY’S minimum standards as set forth in Section II herein below, or that fails to administer an acceptable policy. SECTION I – POLICY STATEMENT The use, possession, concealment, transportation, promotion, or sale of the following substances is strictly prohibited on COMPANY premises, including all property owned, operated, leased by, or under the control of COMPANY, as well as on the location of any authorized COMPANY Project, regardless of the physical location where such work is performed.(1)

• Prohibited substances are defined as: (a) any alcoholic beverage, the use of which is not authorized by the Company, (b) any substance that an individual may not sell, possess, use, or distribute under federal or applicable state laws, and (c) any otherwise legal but illicitly-used substances.

• “Otherwise legal but illicitly-used substances” include (a) prescription drugs obtained without proper medical authorization,

and (b) prescribed drugs, over-the-counter drugs, and other substances not being used for their intended purposes or at intended dosage.

• Drug paraphernalia and similar items used for substance abuse are likewise prohibited on COMPANY premises.

Contractors and vendors shall submit a copy of their policy and program to the COMPANY employee designated to administer contracts or to such other individual as may hereafter be designated by

(1) In many contracts, Company reserves the right to remove a contractor’s employees for any reason. In no way does this policy detract from that right.

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Company. Such policy must provide for substance testing of Contractor employees and must meet the minimum standards as set forth in Section II below. Any Contractor or vendor employee found to be in violation of this Policy shall, thereafter, be prohibited from entering COMPANY premises and prohibited from working on any COMPANY Project. Reinstatement of the access privilege may be made after one year upon request of the employing contractor. Such requests should be made to the COMPANY employee designated to administer contracts and will be evaluated on the merits of each case. A request will be granted only upon receipt of evidence that the employee successfully passed a substance test conducted within not more than thirty (30) days prior to the date of the request, and has successfully completed an assessment by a Substance Abuse Professional (SAP), and has complied with all recommended treatment or rehabilitation prescribed by the SAP.

SECTION II – TESTING

A. DEFINITIONS

For the purpose of this policy:

1. “Substance testing” means the analysis of urine, saliva, or breath; however, at times circumstances may warrant

additional testing methods.

2. “Chain of custody” means the combination of procedures and documentation which provides a faithful and accurate written record of the custody of a biological specimen, from the time of initial collection of a specimen to final laboratory analysis.

3. “Negative test result” means a laboratory conclusion that the presence of a substance was not detected in a specimen at

or above the screening and confirmation levels utilized. 4. “Screened non-negative result” or “presumptive positive result” means laboratory conclusion based on immunoassay

that a specimen was found to contain one or more substances present at or above the screening cut-off level. 5. “Confirmed positive result” means laboratory confirmation using gas chromatography/mass spectrometry (GC/MS) of a

positive substance test by a Medical Review Officer (MRO).

B. LABORATORY AND SAMPLING STANDARDS

1. Testing for the following substances, at the indicated screening and confirmation cut-offs, are recommended:

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Drug EMIT Screen

GC/MS Confirmation Levels

Amphetamines 1000 ng

500 ng Marijuana

50 ng

15 ng Cocaine

300 ng

150 ng Opiates

2000 ng

2000 ng PCP

25 ng 25 ng Alcohol

.02 BAC

.02 BAC



Contractors subject to DOT testing or state laws should abide by appropriate levels.

2. The specimens of applicants and current employees will be tested using an immunoassay. (Approved on-site testing is permissible.) In this testing scheme, a non-negative finding is called a screened non-negative. All screened non-negatives will be further tested using GC/MS. In this testing scheme, a positive finding is called a presumptive positive. All presumptive positives will undergo MRO review.

3. Alcohol screening testing may include utilization of either breath or saliva testing. Tests which are screened positive

will undergo confirmation via the use of an evidential-quality breathalyzer for confirmation of positive alcohol test results. MRO review is not required for positive alcohol test results, unless otherwise required by applicable local, state, or federal law.

C. CONFIDENTIALITY

Company will require that contractors and vendors certify that each employee assigned to work on Company premises has passed a substance test that meets the standards of this policy. Contractors and vendors must maintain records related to substance tests conducted under this Policy, which are subject to audit by COMPANY as further set forth in Sections IV and VI of this Policy. CONTRACTOR shall not have the obligation to disclose to COMPANY any individual results of tests conducted by CONTRACTOR. However, CONTRACTOR shall prohibit such individuals in violation of the Policy from entering COMPANY premises and working on any COMPANY Project CONTRACTOR shall certify to BP, upon request, that it has met the drug testing requirements of this Policy, including the removal of any staff who have received a positive drug or alcohol test..

D. TESTING

1. Contractors will conduct substance testing in these situations:

a. before any contractor employee may enter COMPANY premises or perform work on any COMPANY Project for the first time.

b. annual random drug testing of at least 25% of Contractor’s employees engaged in work on COMPANY premises

and on any COMPANY Project; this requirement will be met if Contractor covers the applicable employees under a larger drug testing pool that is subject to annual random testing of at least 25% of the pool population.

c. upon reasonable suspicion by the Contractor or COMPANY that a contractor employee on COMPANY premises

or working on a COMPANY Project is under the influence of or has consumed any substance or item prohibited by this Policy.

d. when required by COMPANY management, immediately following any incident that results in a recordable

bodily injury as defined by OSHA, or damage to COMPANY or Contractor-owned property, and/or when otherwise required by federal, state or local law. Additionally, any substance testing regulated and/or required by DOT (FHA, RSPA, USCG), must be strictly adhered to. (Note: Substance testing may also be required by the Contractor, vendor or COMPANY following a near-miss incident. A near-miss incident is any incident which, if it

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had proceeded to a reasonably possible and more serious level of development, would have had the potential for personnel injuries, property damage, or serious liability claims).

2. Contractors will assume all costs associated with testing they conduct. 3. The refusal of a contractor’s employee to sign a consent form or submit to any testing required by this Policy will

result in revocation of the person’s access privileges. A refusal to test shall include a failure to cooperate with any part of the testing process, including: (1) failing to remain until the process is completed; (2) failing to provide a sufficient or adequate specimen (without medical explanation); (3) failing to appear for testing (including failing to appear within a reasonable time after being notified of testing); (4) failing to submit to a re-collection or retesting when required; or (5) submitting a specimen that the MRO verifies as adulterated or substituted.

E. EXCEPTIONS

The following exceptions may be granted at the discretion of COMPANY management: 1. Contractors and Contractors’ employees who are contracted or hired on short notice may be permitted to begin work

on-site or on a COMPANY Project pending receipt of the results of pre-access substance testing. This permission will not extend beyond seven (7) calendar days from the first date after work starts by Contractor.

Any person working under this provision must be removed from the work site immediately upon receipt of a positive test result, or at the end of seven (7) calendar days if test results have not been reported. This provision covers only employees needed for initial staffing and does not extend to those hired with sufficient time for pre-access testing (2-3 days after job begins).

2. Contractors or vendors who have a need for site access and whose work on COMPANY premises or on a COMPANY Project poses a minimal safety risk may be exempted in whole or in part from compliance with this Policy. Requests for an exemption should be made to the COMPANY employee designated to administer contracts, or to such other individual as may hereafter be designated by the COMPANY.

F. VALIDITY PERIOD

A pre-access substance test must have been administered within ninety (90) days immediately preceding access. This requirement may be waived by local authorized COMPANY management for persons who are regaining access after an absence of not more than ninety (90) days.

COMPANY will recognize a substance test conducted on a Contractor’s employee while that employee worked for a different employer if (1) the test is conducted within the 90-day period required by this policy, and (2) the laboratory and sampling procedures meet the standards set forth in this Policy. COMPANY prefers that the testing requirements be verified by an independent agency such as the Contractor’s Safety Council.

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SECTION III – SEARCHES AND INSPECTIONS

COMPANY reserves the right at all times on its premises to conduct unannounced substance screens, searches, and inspections of contractors, contractors’ employees, vendors, and other persons, including their effects, lockers, baggage, desks, tool boxes, clothing, and vehicles located on COMPANY premises or worksites, as a means of enforcing this Policy.

Any controlled substances or items prohibited by this Policy, or any materials that are illegal to possess, will be retained by COMPANY and may be destroyed or turned over to the appropriate law enforcement agency.

The refusal of any person to submit to a search or inspection will result in the revocation of the person’s access privileges. SECTION IV – COMPLIANCE AUDITS

COMPANY reserves the right to periodically audit a Contractor’s records to verify compliance with this policy. Such verification will include, but not be limited to:

1. examination of the Contractor’s substance abuse policy and its implementing directives and procedures; 2. a determination that substance testing is being conducted in those situations where it is required and that the testing meets

the standards of this policy; 3. examination of chain of custody procedures which ensure integrity of collected specimens; or 4. evaluation of laboratory services.

Audit results will be treated as confidential in order to protect the privacy of tested persons. Notwithstanding any other provision of this Policy, under no circumstance will CONTRACTOR GROUP be obligated to disclose to or discuss with COMPANY GROUP or any member of COMPANY GROUUP the test results or records of any individual or member of CONTRACTOR GROUP. SECTION V – SUBCONTRACTS In all cases where a Contractor is permitted to employ a subcontractor, the Contractor is responsible for ensuring that the subcontractor and subcontractor’s employees are in compliance with this policy. Contracts between contractors and subcontractors must stipulate that COMPANY reserves the right to audit subcontractor’s substance programs. SECTION VI – CONSENT FORMS The Contractor must obtain a signed consent demonstrating each employee’s agreement to release to Contractor the results of any substance testing performed by COMPANY on COMPANY premises, unless prohibited by applicable federal, state, or local law. COMPANY will look at substance test results only during occasional compliance audits as described in Section IV, or when testing is required by COMPANY as described in Section II.

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SECTION VII – NOTICE The Contractor must ensure that each of its employees and employees of its subcontractors is informed of the provisions of this policy and of the Contractor’s substance abuse policy. Notice will include the consequences of failure to comply, and will be made prior to entering COMPANY premises or working on COMPANY Projects. SECTION VIII – CONCLUSION Consideration for work on COMPANY premises or Company Projects will be conditioned upon contractor’s and vendor’s implementation of a policy that, in COMPANY’S sole judgment, conforms to the minimum standards expressed in this policy. Program development and implementation are the responsibility of the contractor. The central goal of this policy is to provide a safe and efficient working environment for all persons on COMPANY premises, and to ensure that COMPANY Projects are performed in a safe and efficient manner. Cooperation is vitally important to the achievement of this important goal.

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Exhibit F-1

Personnel to be Provided Deepwater Horizon

Notes: 1. Rates and Fees to be provided thirty (30) days prior to Commencement Date of Contract Extension. 2. Above manning assumes CONTRACTOR will not put CONTRACTOR Personnel onboard workboats to handle cargo. 3. CONTRACTOR to have a forty-eight (48) hour allowance (for each occurrence prior to the enactment of penalty) to replace

CONTRACTOR Personnel that have to leave the drilling unit for emergency purposes or who fail to show up for crew change. 4. CONTRACTOR shall not be penalized when requested by COMPANY to reduce CONTRACTOR’S Exhibit F-1 Personnel in

order to provide additional bed space to accommodate COMPANY Personnel. Record of such CONTRACTOR Personnel reductions shall be mutually agreed by CONTRACTOR and COMPANY with such agreement recorded in the daily IADC log.

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No. of Personnel Daily

Hourly

On Assigned

Daily Rate

Overtime

OvertimeBoard Rig


per person Rates

Rates1

2 OIM

1 2

Sr. Toolpusher

2 4

Toolpusher

2 4

Driller

4 8

Assistant Driller

2 4

Derrickhand

2 4

Pumphand

12 24

Floorhand

1 2

Maintenance Supervisor

1 2


2 4

Chief Mechanic

2 4

Mechanic

3 6

Motor Operator

1 2

Electrical/Electronic Supervisor

1 2

Chief Electrician

1 2

Electrician

1 2

Chief Electronic Tech

1 2


1 2

Sr. Subsea Supervisor - MUX

1 2

Subsea Supervisor

1 2

Master

1 2

Chief Mate

1 2

Bosun

3 6

AB Seaman

2 4

DP Operator III

2 4

DP Operator II

3 6

Crane Operator

2 4

Deckpusher

13 26

Roustabout

1 2

Welder

1 2

Sr Materials Coordinator

1 2

Materials Coordinator

1 2

Medic

1 2

Radio Operator

1 2

RSTC

76 152

Total

Amendment No. to Contract No. 980249

Exhibit 31.1

CEO CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES−OXLEY ACT OF 2002

I, Steven L. Newman, certify that:

1. I have reviewed this report on Form 10−Q of Transocean Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material factnecessary to make the statements made, in light of the circumstances under which such statements were made, not misleading withrespect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in thisreport;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a−15(e) and 15d−15(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a−15(f) and 15d−15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designedunder our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries,is made known to us by others within those entities, particularly during the period in which this report is being prepared;and

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to bedesigned under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report ourconclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by thisreport based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during theregistrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that hasmaterially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalentfunction):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financialinformation; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in theregistrant’s internal control over financial reporting.

Dated: August 4, 2010 /s/ Steven L. Newman Name: Steven L. NewmanPresident and Chief Executive Officer

Exhibit 31.2

CFO CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES−OXLEY ACT OF 2002

I, Ricardo H. Rosa, certify that:

1. I have reviewed this report on Form 10−Q of Transocean Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material factnecessary to make the statements made, in light of the circumstances under which such statements were made, not misleading withrespect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all materialrespects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in thisreport;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (asdefined in Exchange Act Rules 13a−15(e) and 15d−15(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a−15(f) and 15d−15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designedunder our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries,is made known to us by others within those entities, particularly during the period in which this report is being prepared;and

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to bedesigned under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and thepreparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report ourconclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by thisreport based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during theregistrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that hasmaterially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalentfunction):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reportingwhich are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financialinformation; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in theregistrant’s internal control over financial reporting.

Dated: August 4, 2010 /s/ Ricardo H. Rosa Name: Ricardo H. RosaSenior Vice President and Chief Financial Officer

Exhibit 32.1

CERTIFICATION PURSUANT TO SECTION 906 OFTHE SARBANES−OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b)


Pursuant to Section 906 of the Sarbanes−Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, UnitedStates Code), I, Steven L. Newman, Chief Executive Officer of Transocean Ltd., a Swiss corporation (the “Company”), hereby certify, to myknowledge, that:

(1) the Company’s Quarterly Report on Form 10−Q for the quarter ended June 30, 2010 (the “Report”) fully complies with therequirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operationsof the Company.

Dated: August 4, 2010 /s/ Steven L. Newman Name: Steven L. NewmanPresident and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes−Oxley Act of 2002 (Subsections(a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosuredocument.

A signed original of this written statement required by Section 906 has been provided to Transocean Ltd. and will be retained byTransocean Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

CERTIFICATION PURSUANT TO SECTION 906 OFTHE SARBANES−OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b)


Pursuant to Section 906 of the Sarbanes−Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, UnitedStates Code), I, Ricardo H. Rosa, Senior Vice President and Chief Financial Officer of Transocean Ltd., a Swiss corporation (the “Company”),hereby certify, to my knowledge, that:

(1) the Company’s Quarterly Report on Form 10−Q for the quarter ended June 30, 2010 (the “Report”) fully complies with therequirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operationsof the Company.

Dated: August 4, 2010 /s/ Ricardo H. Rosa Name: Ricardo H. RosaSenior Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes−Oxley Act of 2002 (Subsections(a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosuredocument.

A signed original of this written statement required by Section 906 has been provided to Transocean Ltd. and will be retained byTransocean Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.

second-quarter results

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Transcript of second-quarter results