UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

2006 FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2006

Commission file number 1-14634

GlobalSantaFe Corporation

(Exact name of registrant as specified in its charter)

Cayman Islands	98-0108989
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
15375 Memorial Drive, Houston, Texas	77079-4101
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (281) 925-6000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Ordinary Shares $.01 par value	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No    x

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  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one):    Large accelerated filer  x    Accelerated filer  ¨    Non-Accelerated Filer  ¨

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the Registrant’s most recently completed second fiscal quarter (June 30, 2006) was approximately $13.9 billion (the executive officers and directors of the registrant are considered affiliates for purposes of this calculation).

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Ordinary Shares, $.01 par value, 230,296,242 shares outstanding as of January 31, 2007.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement in connection with the 2007 Annual General Meeting of Shareholders are incorporated into Part III of this Report.

TABLE OF CONTENTS

		Page
Part I
Items 1. and 2.	Business and Properties	8
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	27
Item 3.	Legal Proceedings	27
Item 4.	Submission of Matters to a Vote of Security Holders	31
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	117
Item 9A.	Controls and Procedures	117
Item 9B.	Other Information	118
Part III
Item 10.	Directors and Executive Officers of the Registrant	119
Item 11.	Executive Compensation	119
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	119
Item 13.	Certain Relationships and Related Transactions	119
Item 14.	Principal Accountant Fees and Services	119
Part IV
Item 15.	Exhibits and Financial Statement Schedules	120

We make available on our website, free of charge, at www.globalsantafe.com our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to these reports as soon as reasonably practicable after they are filed with or furnished to the Securities and Exchange Commission. The information contained in our website does not constitute a part of this Annual Report.

EARNINGS CONFERENCE CALL

On Wednesday, May 2, 2007, we are scheduled to release our first quarter 2007 financial results after trading closes on the New York Stock Exchange. On May 3, 2007, at 10:00 a.m. Central Time (11:00 a.m. Eastern Time), we are scheduled to hold an earnings conference call to discuss the results.

Interested parties may participate in the conference by calling (617) 597-5308, confirmation code 28140998. The call is also available through our website at www.globalsantafe.com. We recommend that listeners connect to the website prior to the conference call to ensure adequate time for any software download that may be needed to hear the webcast. Replays will be available starting at 1:00 p.m. Central Time (2:00 p.m. Eastern Time) on the day of the conference call by webcast on our website or by telephoning (617) 801-6888, confirmation code 32289214. Both services will discontinue replays at 12:00 a.m. Central Time on May 17, 2007.

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FORWARD-LOOKING STATEMENTS

Under the Private Securities Litigation Reform Act of 1995, companies are provided a “safe harbor” for discussing their expectations regarding future performance. We believe it is in the best interests of our shareholders and the investment community to use these provisions and provide such forward-looking information. We do so in this report and other communications. Forward-looking statements are often but not always identifiable by use of words such as “anticipate,” “believe,” “budget,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “might,” “plan,” “predict,” “project,” “should,” and “will.”

Our forward-looking statements include statements about the following subjects:

• our possible or assumed results of operations;

• our funding and financing plans;

• the dates drilling rigs will become available following completion of current contracts, the dates rigs will commence contracts and the dollar amount of such contracts, and the dates rigs will be mobilized to other locations;

• with respect to our new ultra-deepwater semisubmersible, the GSF Development Driller III, the estimate of the construction costs for the rig and its projected delivery date;

• our estimation of the costs to remediate thruster defects on the GSF Development Driller I and the GSF Development Driller II and our expectation regarding who will bear those costs;

• our expectation that we will likely replace the jackup GSF Adriatic IV, which was lost in a fire, and the GSF High Island III and GSF Adriatic VII, which were damaged in Hurricane Rita, through the acquisition or construction of replacement assets;

• our expectation that the 60-day waiting period under our loss of hire insurance will serve as the only deductible for the Hurricane Katrina event;

• our expected insurance recoveries for certain of our rigs damaged by Hurricanes Katrina and Rita;

• our estimates of loss of hire recoveries from our insurers;

• our expectation that we will fund any costs incurred associated with remediating rigs, to the extent they are not covered from insurance underwriters, from our existing cash, cash equivalents, and marketable securities balances and future cash flows from operations;

• our expectation that we will fund the costs we incur for the construction of the GSF Development Driller III, from our existing cash, cash equivalents and marketable securities balances and future cash flow from operations;

• our expectation that we will complete the sale of the GSF High Island III in the first quarter of 2007 and that we do not expect the loss of the GSF High Island III or the GSF Adriatic VII to have a material affect in our results of operations in future periods;

• our contract drilling and drilling management services revenue backlogs and the amounts expected to be realized in 2007;

• our estimate of undiscounted future cash flows relating to the determination of impairment of rigs and drilling equipment;

• our belief that we should prevail in the appeal of a proposed adjustment by the Internal Revenue Service and that the Internal Revenue Service could propose similar adjustments with respect to other periods;

• the expected outcomes of legal and administrative proceedings, their materiality, potential insurance coverage and their expected effects on our financial position and results of operations;

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• the assumptions as to risk-free interest rates, stock price volatility, dividend yield and expected lives of awards used to estimate the fair value of stock-based compensation awards and the estimated unrecognized compensation cost and the weighted average period over which such cost is expected to be realized;

• the return assumptions developed by our consultants in determining expected long-term rate of return on pension plan assets assumption;

• our expectations regarding future conditions in various geographic markets in which we operate and the prospects for future work, contract terms and dayrates in those markets;

• our expectations regarding supply and demand for equipment, ancillary services, and drilling rigs in various geographic markets;

• our expectations regarding the time and impact of the entry into service of new rigs under construction, and rigs being upgraded or reactivated;

• our expectation that further new rig construction announcements are likely;

• estimated costs in 2006 for drilling management services;

• our estimated loss on a turnkey drilling project in the first quarter of 2007;

• our use of critical accounting estimates and the assumptions and estimates made by management during the preparation of our financial statements;

• our estimated capital expenditures in 2007;

• our future contractual obligations;

• our expectation that we will fund various commitments, primarily related to our debt and capital lease obligations, leases for office space and other property and equipment, as well as the construction of our new ultra-deepwater semisubmersible drilling rig, with existing cash, cash equivalents, marketable securities and future cash flows from operations;

• our expectation that our effective tax rate will continue to fluctuate from quarter to quarter and year to year as our operations are conducted in different taxing jurisdictions and our expected effective tax rate for 2007;

• our expectation that a subsidiary restructuring completed in fourth quarter of 2006 should facilitate the movement of cash through our subsidiaries at a low tax cost;

• our ability to meet all of our current obligations, including working capital requirements, capital expenditures, total lease obligations, construction and development expenses, and debt service, from our existing cash, cash equivalents and marketable securities balances and future cash flow from operations;

• our expectation that, if required, any additional payments made under certain fully defeased financing leases would not be material to our financial position, results of operations or cash flows in any given year;

• our belief that our exposure to interest rate fluctuations as a result of fixed-for-floating interest rate swaps is not material to our financial position, results of operations or cash flows;

• our belief that credit risk in our investments in commercial paper, money market funds, asset-backed securities, government issues and corporate obligations is minimal;

• our expectation regarding increases in contract drilling expenses in 2007;

• our estimation that the Minerals Management Service of the U.S. Department of Interior or Insurance Underwriters, or both, may impose operating criteria in the Gulf of Mexico that could increase the capital cost or cost of operations or reduce the area of operations for rigs operating there, which could materially and adversely affect our operations and financial condition;

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• our ability to maintain adequate insurance at rates we consider reasonable and our ability to obtain insurance against certain risks;

• our expectations regarding changes in insurance affecting our customers in the Gulf of Mexico and the impact on those customers;

• our expectation regarding the effect of adoption of certain accounting standards; and

• any other statements that are not historical facts.

Our forward-looking statements speak only as of the date of this report and are based on currently available industry, financial, and economic data and our operating plans. They are also inherently uncertain, and investors must recognize that events could turn out to be materially different from our expectations.

Factors that could cause or contribute to such differences include, but are not limited to:

• higher than anticipated accruals for performance-based compensation due to better than anticipated performance, higher than anticipated severance expenses due to unanticipated employee terminations, higher than anticipated legal and accounting fees due to unanticipated financing or other corporate transactions, and other factors that could increase G&A expenses;

• a material or extended decline in expenditures by the oil and gas industry, which is significantly affected by indications and expectations regarding the level and volatility of oil and natural gas prices, which in turn are affected by such things as political, economic and weather conditions affecting or potentially affecting regional or worldwide demand for oil and natural gas, actions or anticipated actions by OPEC, inventory level, deliverability constraints, and futures market activity;

• the extent to which customers and potential customers continue to pursue ultra-deepwater drilling;

• the extent to which we are required to idle rigs or to enter into lower dayrate contracts in response to future market conditions;

• exploration success or lack of exploration success by our customers and potential customers;

• our ability to enter into and the terms of future drilling contracts;

• the entry into service of newly constructed, upgraded or reactivated rigs;

• our ability to win bids for turnkey drilling operations;

• rig availability and our ability to hire suitable rigs at acceptable rates;

• our ability to retain and attract qualified personnel;

• the availability of adequate insurance at a reasonable cost;

• the occurrence of an uninsured or unidentified event;

• the implementation of additional operational requirements in the Gulf of Mexico by governmental agencies or insurers;

• the risks of failing to complete a well or wells under turnkey contracts;

• other risks inherent in turnkey contracts;

• our failure to retain the business of one or more significant customers;

• the termination or renegotiation of contracts by customers;

• the operating hazards inherent in drilling for oil and natural gas;

• the risks of international operations and compliance with foreign laws;

• political and other uncertainties inherent in non-U.S. operations, including exchange and currency fluctuations and the limitations on the ability to repatriate income or capital to the U.S.;

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• compliance with or breach of environmental laws;

• proposed United States tax law changes or other changes in the tax laws or regulations of the U.S. or another country or changes in tax treaties;

• limitations on our ability to use our U.S. tax net operating loss carryforwards;

• changes in employee demographics that impact the estimated remaining service lives of the active participants in our pension plans;

• the impact of governmental laws and regulations and the uncertainties involved in their administration, particularly in some foreign jurisdictions;

• the highly competitive and cyclical nature of our business, with periods of low demand and excess rig availability;

• the level of construction of new rigs, upgrade of existing rigs and reactivation of cold-stacked rigs;

• the continuation or escalation of existing armed hostilities, outbreak of war or other armed conflicts or terrorist attacks;

• the effect of SARS or other public health threats on our international operations;

• political or social disruptions that limit oil and/or gas production;

• the actions of our competitors in the oil and gas drilling industry, which could significantly influence rig dayrates and utilization;

• delays or cost overruns in our rig upgrade, refurbishment and construction projects and rig maintenance and repairs, caused by such things as shortages of materials or skilled labor, unforeseen engineering problems, unanticipated actual or purported change orders, work stoppages, shipyard financial or operating difficulties, adverse weather conditions or natural disasters, unanticipated cost increases, and the inability to obtain requisite permits or approvals;

• the ultimate insurance recoveries for damages caused by Hurricanes Katrina and Rita;

• the unforeseen startup problems inherent in commencing operations with any new rig, including such things as engineering, permitting, crewing and equipment problems;

• the occurrence or nonoccurrence of anticipated changes in our revenue mix between domestic and international drilling markets due to changes in our customers’ oil and gas drilling plans, which can be the result of such things as changes in regional or worldwide economic conditions and fluctuations in the prices of oil and natural gas, which in turn could change or stabilize effective tax rates;

• the vagaries of the legislative process due to the unpredictable nature of politics and national and world events, among other things;

• currently unknown rig repair needs and/or additional opportunities to accelerate planned maintenance expenditures due to presently unanticipated rig downtime;

• changes in oil and natural gas drilling technology or in our competitors’ drilling rig fleets that could make our drilling rigs less competitive or require major capital investments to keep them competitive;

• the adequacy of sources of liquidity;

• the incurrence of secured debt or additional unsecured indebtedness or other obligations by us or our subsidiaries;

• the uncertainties inherent in dealing with financial and other third-party institutions that could have internal weaknesses unknown to us;

• changes in accepted interpretations of accounting guidelines and other accounting pronouncements;

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• the number and severity of future litigation claims, including asbestos-related claims, and the sufficiency of insurance;

• the effects and uncertainties of legal and administrative proceedings and other contingencies; and

• such other factors as may be discussed in this report in “Item 1A. Risk Factors” section and elsewhere, and in our other reports filed with the U.S. Securities and Exchange Commission.

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 disclaim any obligation or undertaking to disseminate any updates or revisions to our statements, forward-looking or otherwise, to reflect changes in our expectations or any change in events, conditions or circumstances on which any such statements are based.

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GlobalSantaFe Corporation is an offshore oil and gas drilling contractor, owning or operating a fleet of 59 marine drilling rigs. As of December 31, 2006, our fleet included 43 cantilevered jackup rigs, 11 semisubmersible rigs, three drillships, and two additional semisubmersible rigs we operate for third parties under a joint venture agreement (see “Joint Venture, Agency and Sponsorship Relationships and Other Investments”). During the first quarter of 2006, we commenced construction of an additional semisubmersible, to be named the GSF Development Driller III. We also have a jackup rig, the GSF High Island III, that is currently not capable of performing drilling operations due to damage arising in 2005 as a result of Hurricane Rita. Subsequent to December 31, 2006, we entered into a contract to sell the rig to a third party and expect to complete the sale during the first quarter of 2007. (See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Involuntary Conversions of Long-Lived Assets and Related Recoveries.”).

We provide offshore oil and gas contract drilling services to the oil and gas industry worldwide on a daily rate (“dayrate”) basis. We also provide oil and gas drilling management services on either a dayrate or completed-project, fixed-price (“turnkey”) basis, as well as drilling engineering and drilling project management services, and we participate in oil and gas exploration and production activities. Business segment and geographic information is set forth in Note 14 of Notes to Consolidated Financial Statements in Item 8 of this Annual Report on Form 10-K. We are a Cayman Islands company, with our principal executive offices in Houston, Texas.

Unless the context otherwise requires, the terms “we,” “us” and “our” refer to GlobalSantaFe Corporation and its consolidated subsidiaries. Substantially all of our businesses are conducted by subsidiaries of GlobalSantaFe Corporation.

CONTRACT DRILLING

Substantially all of our domestic offshore contract drilling operations are conducted by GlobalSantaFe Drilling Company, a wholly owned subsidiary headquartered in Houston, Texas. International offshore contract drilling operations are conducted by a number of our subsidiaries and joint venture companies with operations in 21 countries throughout the world.

Rig Fleet. We have a modern, diversified fleet of 59 mobile offshore drilling rigs as of December 31, 2006, including six cantilevered heavy-duty harsh environment (“HDHE”) jackups, 37 cantilevered jackups, 11 semisubmersibles, including two ultra-deepwater semisubmersibles, three ultra-deepwater, dynamically positioned drillships, and two additional semisubmersible rigs we operate for third parties. All of our rigs, with the exception of the GSF Britannia jackup, were placed into service in 1974 or later, and, as of December 31, 2006, the average age of the rigs in our fleet was approximately 21 years.

Our fleet is deployed in major offshore oil and gas operating areas worldwide. The principal areas in which the fleet is currently deployed are the U.S. Gulf of Mexico, the North Sea, West Africa, the Mediterranean Sea, Southeast Asia, South America, the Middle East and eastern Canada.

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The following table lists the rigs in our drilling fleet as of January 31, 2007, indicating the year each rig was placed in service, each rig’s maximum water and drilling depth capabilities, as currently equipped, current location, customer, and the date each rig is estimated to become available.

Rig Fleet

Status as of January 31, 2007

	YEAR PLACED IN SERVICE	MAXIMUM WATER DEPTH CAPABILITY	DRILLING DEPTH CAPABILITY	LOCATION	CURRENT CUSTOMER	ESTIMATED AVAILABILITY(1)
Heavy-Duty Harsh-Environment Jackups
GSF Galaxy I	1991	400 ft.	30,000 ft.	North Sea	BP	11/08
GSF Galaxy II	1998	400 ft.	30,000 ft.	North Sea	ADTI	03/08
GSF Galaxy III	1999	400 ft.	30,000 ft.	North Sea	Nexen	07/08
GSF Magellan	1992	350 ft.	30,000 ft.	North Sea	Shell	06/08
GSF Monitor	1989	350 ft.	30,000 ft.	Trinidad & Tobago	BP	04/09
GSF Monarch	1988	350 ft.	30,000 ft.	North Sea	Shell	04/09
Cantilevered Jackups
GSF Constellation I	2003	400 ft.	30,000 ft.	Trinidad & Tobago	BP	08/07
GSF Constellation II	2004	400 ft.	30,000 ft.	Mediterranean Sea	Petrobel	04/10
GSF Baltic	1983	375 ft.	25,000 ft.	West Africa	Premier	06/09
GSF Adriatic II	1981	350 ft.	25,000 ft.	West Africa	ChevronTexaco	07/09
GSF Adriatic III	1982	350 ft.	25,000 ft.	U.S. Gulf of Mexico	Nexen	04/07
GSF Adriatic IX	1981	350 ft.	20,000 ft.	West Africa	Total	07/08
GSF Adriatic X	1982	350 ft.	25,000 ft.	Mediterranean Sea	Petrobel	11/08
GSF Key Manhattan	1980	350 ft.	25,000 ft.	Mediterranean Sea	Petrobel	07/08
GSF Key Singapore	1982	350 ft.	25,000 ft.	Mediterranean Sea	Petrobel	06/08
GSF Adriatic VI	1981	328 ft.	20,000 ft.	West Africa	Euroil	06/08
GSF Adriatic VIII	1983	328 ft.	25,000 ft.	West Africa	ExxonMobil	04/09
GSF Adriatic I	1981	300 ft.	25,000 ft.	West Africa	Chevron Texaco	04/09
GSF Adriatic V	1979	300 ft.	20,000 ft.	West Africa	Chevron Texaco	05/09
GSF Adriatic XI	1983	300 ft.	25,000 ft.	Southeast Asia	Petronas Cargali	07/08
GSF Compact Driller	1993	300 ft.	25,000 ft.	Southeast Asia	ChevronTexaco	05/09
GSF Galveston Key	1978	300 ft.	25,000 ft.	Southeast Asia	Cuulong JOC	04/08
GSF Key Gibraltar	1976	300 ft.	25,000 ft.	Southeast Asia	CPOC	11/08
GSF Key Hawaii	1983	300 ft.	25,000 ft.	Middle East	Dolphin Energy	07/07
GSF Labrador	1983	300 ft.	25,000 ft.	North Sea	PetroCanada	07/08
GSF Main Pass I	1982	300 ft.	25,000 ft.	Middle East	Saudi Aramco	05/11
GSF Main Pass IV	1982	300 ft.	25,000 ft.	Middle East	Saudi Aramco	05/11
GSF Parameswara	1993	300 ft.	25,000 ft.	Southeast Asia	Total	07/08
GSF Rig 134	1982	300 ft.	20,000 ft.	Southeast Asia	Petronas Cargali	04/10
GSF Rig 136	1982	300 ft.	25,000 ft.	Southeast Asia	Total	05/08
GSF High Island II	1979	270 ft.	20,000 ft.	Middle East	Saudi Aramco	05/11
GSF High Island IV	1980	270 ft.	20,000 ft.	Middle East	Saudi Aramco	04/11
GSF High Island V	1981	270 ft.	20,000 ft.	West Africa	Perenco	05/07
GSF High Island I	1979	250 ft.	20,000 ft.	U.S. Gulf of Mexico	Linder	03/07
GSF High Island VII	1982	250 ft.	20,000 ft.	West Africa	Total Cameroon	09/08
GSF High Island VIII	1982	250 ft.	20,000 ft.	U.S. Gulf of Mexico	Energy Partners Ltd.	02/07
GSF High Island IX	1983	250 ft.	20,000 ft.	West Africa	Addax Nigeria	07/09
GSF Rig 103	1974	250 ft.	20,000 ft.	Middle East	Occidental	01/08
GSF Rig 105	1975	250 ft.	20,000 ft.	Middle East	Petrobel	08/07
GSF Rig 124	1980	250 ft.	20,000 ft.	Middle East	IPR	09/08
GSF Rig 127	1981	250 ft.	20,000 ft.	Middle East	Maersk	06/07
GSF Rig 141	1982	250 ft.	20,000 ft.	Middle East	Gempetco	05/07
GSF Britannia	1968	230 ft.	20,000 ft.	North Sea	Shell	02/09

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	YEAR PLACED IN SERVICE	MAXIMUM WATER DEPTH CAPABILITY	DRILLING DEPTH CAPABILITY	LOCATION	CURRENT CUSTOMER	ESTIMATED AVAILABILITY (1)
Semisubmersibles
GSF Development Driller I	2005	7,500 ft.	37,500 ft.	U.S. Gulf of Mexico	BHP	07/12
GSF Development Driller II	2005	7,500 ft.	37,500 ft.	U.S. Gulf of Mexico	BP	12/08
GSF Celtic Sea	1998	5,750 ft.	25,000 ft.	U.S. Gulf of Mexico	ExxonMobil	05/08
GSF Arctic I	1983	3,400 ft.	25,000 ft.	U.S. Gulf of Mexico	Nexen	07/10
GSF Rig 135	1983	2,800 ft.	25,000 ft.	West Africa	ExxonMobil	07/10
GSF Rig 140	1983	2,400 ft.	25,000 ft.	North Sea	ADTI	07/09
GSF Aleutian Key	1976	2,300 ft.	25,000 ft.	West Africa	CABGOC	07/08
GSF Arctic III	1984	1,800 ft.	25,000 ft.	North Sea	PetroCanada	01/08
GSF Arctic IV	1983	1,500 ft.	25,000 ft.	North Sea	BP	06/10
GSF Grand Banks	1984	1,500 ft.	25,000 ft.	Eastern Canada	Husky	01/08
GSF Arctic II	1982	1,200 ft.	25,000 ft.	North Sea	Talisman	07/08
Drillships
GSF C.R. Luigs	2000	10,000 ft.	35,000 ft.	U.S. Gulf of Mexico	BHP	09/13
GSF Jack Ryan	2000	10,000 ft.	35,000 ft.	West Africa	BP Angola	07/13
GSF Explorer	1998	7,800 ft.	30,000 ft.	U.S. Gulf of Mexico	BP	08/09
Third-Party Owned Semisubmersibles
Dada Gorgud	1980	1,558 ft.	25,000 ft.	Azerbaijan	BP	(2)
Istiglal	1991	1,558 ft.	25,000 ft.	Azerbaijan	BP	(2)

(1) Estimated based on the anticipated completion date of current commitments, including executed contracts, letters of intent, and other customer commitments for which contracts have not yet been executed.

(2) These contracts are evergreen contracts.

During the third quarter of 2005, a number of our rigs were damaged as a result of hurricanes Katrina and Rita. All these rigs returned to work with the exception of the GSF High Island III and the GSF Adriatic VII. During the second quarter of 2006, we recorded gains of $32.8 million on the GSF High Island III and $30.9 million on the GSF Adriatic VII, which represent recoveries of partial losses under our insurance policy, less amounts previously recognized when the rigs were written down to salvage value. In December 2006, we sold the GSF Adriatic VII to a third party for approximately $29.4 million, net of selling costs, and recorded a gain of $28 million, which represents the selling price less the $1.4 million salvage value. In addition, we increased the gain recognized in the second quarter of 2006 related to the GSF Adriatic VII by $3.2 million to include additional costs reimbursable under the insurance policy. There was no tax impact related to these transactions. Subsequent to December 31, 2006, we entered into an agreement to sell the GSF High Island III to a third party for approximately $26.3 million and expect to complete the sale during the first quarter of 2007. We will record a gain equal to the selling price, net of expenses, less the salvage value of $1.2 million.

During the first quarter of 2004, we retired the drillship Glomar Robert F. Bauer from active service. As a result, we accelerated the remaining depreciation on this rig, which resulted in a $1.5 million charge to depreciation expense in the first quarter of 2004. As a result of continued improvements in the offshore drilling markets, we sold this rig in the fourth quarter of 2005 for $25 million and recorded a net gain of $23.5 million. There was no tax impact related to this transaction.

On May 21, 2004, we completed the sale of our land drilling business to Precision Drilling Corporation for a total sales price of $316.5 million in an all-cash transaction. Our land drilling business consisted of a fleet of 31 rigs, 12 of which were located in Kuwait, eight in Venezuela, four in Saudi Arabia, four in Egypt and three in Oman. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operating Results—Sale of Land Drilling Fleet (Discontinued Operations).”

Rig Types. Jackup rigs have elevating legs which extend to the sea bottom, providing a stable platform for drilling, and are generally preferred in water depths of 400 feet or less. We consider jackup rigs with independent

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cantilevers and a water depth capability of over 300 feet to be “premium” jackup units. All of our jackup rigs have drilling equipment mounted on cantilevers, which allow the equipment to extend outward from the rigs’ hulls over fixed drilling platforms and enable operators to drill both exploratory and development wells. In addition, seven of our jackups are equipped with skid-off packages, which allow the drilling equipment to be transferred to fixed production platforms.

We own one of the world’s largest fleets of HDHE jackup rigs. Three of our HDHE rigs, the GSF Galaxy I, GSF Galaxy II and GSF Galaxy III, are Universe class rig designs capable of operating in water depths up to 400 feet and are currently qualified to operate year-round in the harsh environment of the central North Sea in water depths of up to 360 feet. Our three other HDHE jackup rigs, the GSF Monarch, GSF Monitor and GSF Magellan, are Monarch class rig designs capable of operating in water depths of up to 350 feet. These rigs are capable of operating year-round in the central North Sea in water depths of up to 300 feet.

Semisubmersible rigs are floating offshore drilling units with pontoons and columns that, when flooded with water, cause the unit to partially submerge to a predetermined depth. Most semisubmersibles are anchored to the sea bottom, but some use dynamic positioning (“DP”), which allows the vessels to be held in position by computer-controlled propellers, known as thrusters. Semisubmersibles are classified into five generations, distinguished mainly by their age, environmental rating, variable deck load and water-depth capability. The GSF Aleutian Key is an upgraded second-generation conventionally moored semisubmersible capable of drilling in water depths up to 2,300 feet. The GSF Arctic I, GSF Arctic II, GSF Arctic III, GSF Arctic IV, GSF Grand Banks, GSF Rig 135 and GSF Rig 140 semisubmersibles are third-generation, conventionally moored rigs suitable for drilling in water depths ranging from 1,200 to 3,400 feet. The GSF Celtic Sea, which utilizes a mooring system that is DP-assisted, is a fourth-generation semisubmersible capable of drilling in water depths of up to 5,750 feet. The fifth-generation ultra-deepwater semisubmersibles GSF Development Driller I and GSF Development Driller II utilize a system that offers either conventional mooring or DP and are capable of drilling in water depths of up to 7,500 feet.

Our “deepwater” rigs consist of our semisubmersibles and drillships. We consider rigs with a maximum water-depth capability of 7,500 feet or more, such as the semisubmersibles GSF Development Driller I and GSF Development Driller II and the drillships GSF C.R. Luigs, GSF Jack Ryan and GSF Explorer, to be “ultra-deepwater” rigs.

The GSF C.R. Luigs, GSF Jack Ryan and GSF Explorer are dynamically positioned, ultra-deepwater drillships capable of drilling in water depths up to 10,000 feet, 10,000 feet and 7,800 feet, respectively, as currently equipped. With modifications, maximum water depth capabilities would be 12,000 feet for the GSF C.R. Luigs and GSF Jack Ryan, and 10,000 feet for the GSF Explorer. Drillships are generally preferred for deepwater drilling in remote locations with moderate weather environments because of their mobility and large load carrying capability.

We own all of the drilling rigs in our fleet in the table above excluding those specifically described as being owned by third parties, the GSF Explorer, which is subject to a capital lease with a remaining term of 20 years, and the GSF Jack Ryan, which is subject to a fully defeased capital lease with a remaining term of 14 years. None of our offshore drilling rigs are currently subject to any outstanding liens or mortgages.

In January 2003, in order to take advantage of an attractive financing structure, we entered into a lease-leaseback arrangement with a European bank related to the GSF Britannia cantilevered jackup. Pursuant to this arrangement, we leased the GSF Britannia to the bank, which then leased the rig back to us, each lease being for a five-year term. We have classified this arrangement as a capital lease.

In the first quarter of 2006 we entered into a contract with Keppel FELS, a shipyard located in Singapore, for construction of a new ultra-deepwater semisubmersible, to be named the GSF Development Driller III. Construction costs, excluding capital spares, startup costs, capitalized interest, customer-required modifications and mobilization costs, are estimated to total approximately $590 million. Construction commenced in the first

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quarter of 2006 and delivery is currently expected during the first quarter of 2009. As of December 31, 2006, we have incurred approximately $220 million of capitalized costs related to the GSF Development Driller III, excluding capitalized interest. We anticipate funding construction through our existing cash, cash equivalents and marketable securities balances and future cash flow from operations. In the second quarter of 2006 we executed a seven-year drilling contract with a major oil and gas company for the GSF Development Driller III, providing for expected revenues of approximately $1 billion.

Backlog. Our contract drilling backlog at December 31, 2006, was $10.6 billion, consisting of $9.5 billion related to executed contracts and $1.1 billion related to customer commitments for which contracts had not yet been executed as of January 31, 2007. Approximately $3.2 billion of the backlog is expected to be realized in 2007. Our contract drilling backlog at December 31, 2005 was $4.8 billion.

Drilling Contracts and Major Customers. Contracts to employ our crewed drilling rigs extend over a specified period of time or the time required to drill a specified well or number of wells. While the final contract for employment of a rig is the result of negotiations between us and the customer, most contracts are awarded based upon competitive bidding. For a discussion of competitive conditions, see “Item 1A. Risk Factors—The Intense Price Competition and Cyclicality of the Drilling Industry, Which is Currently Marked by High Demand, Limited Rig Availability, High Dayrates, and a Substantial Increase in the Supply of Drilling Units, Could Have a Material Adverse Effect on Our Revenues and Profitability.” The rates specified in drilling contracts are generally on a dayrate basis and vary depending upon the type of rig employed, equipment and services supplied, geographic location, term of the contract, competitive conditions at the time of negotiations and other variables. Each contract provides for a basic dayrate during drilling operations, and may include performance premiums or lower rates or no payment for periods of equipment breakdown, adverse weather or other conditions which may be beyond our control. When a rig mobilizes to or demobilizes from an operating area, a contract may provide for different dayrates, specified fixed amounts or no payment during the mobilization or demobilization. Our ability to obtain favorable contract terms and conditions is dependent on market conditions. We are generally able to avoid contract language allowing termination at the convenience of our customers in longer term contracts. Of the $9.5 billion of executed contract backlog at January 31, 2007, approximately 1.7% can be terminated without the imposition of significant early termination payments, which are generally equal to the full dayrate for all of the remaining term or substantial percentage of it. All of this 1.7% is at dayrates that are considerably below current market. Contracts may also terminate for other reasons. See “Item 1A. Risk Factors – We May Suffer Losses if our Customers Terminate or Seek to Renegotiate their Contracts.”

Our business is subject to the usual risks associated with having a limited number of customers for our services. One customer accounted for more than 10% of consolidated revenues in 2006: BP provided $494.1 million of contract drilling revenues, $0.7 million of oil and gas revenues, and $0.4 million of drilling management services revenues. One customer accounted for more than 10% of consolidated revenues in 2005: BP provided $261.0 million of contract drilling revenues and $1.2 million of oil and gas revenues. One customer accounted for more than 10% of consolidated revenues in 2004: Total S.A. (“Total”) provided $186.0 million of contract drilling revenues. Our results of operations could suffer a material adverse effect if any of our major customers terminates its contracts with us, fails to renew our existing contracts or refuses to award new contracts to us. See “Item 1A. Risk Factors—We Rely Heavily on a Small Number of Customers and the Loss of a Significant Customer Could Have a Material Adverse Impact on Our Financial Results.”

DRILLING MANAGEMENT SERVICES

We provide drilling management services primarily on a turnkey basis through a wholly owned subsidiary, Applied Drilling Technology Inc. (“ADTI”), and through ADT International, a division of one of our U.K. subsidiaries. ADTI operates primarily in the U.S. Gulf of Mexico, and ADT International operates primarily in the North Sea. Under a typical turnkey arrangement, we will assume responsibility for the design and execution of a well and deliver a logged or cased hole to an agreed depth for a guaranteed price, with payment contingent upon successful completion of the well program. As part of our turnkey drilling services, we provide planning,

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engineering and management services beyond the scope of our traditional contract drilling business and thereby assume greater risk. In addition to turnkey arrangements, drilling management services also participates in project management operations. In our project management operations we provide certain planning, management and engineering services, purchase equipment and provide personnel and other logistical services to customers. Our project management services differ from turnkey drilling services in that the customer retains control of the drilling operations and thus retains the risk associated with the project.

Our drilling management services business is also subject to the usual risks associated with having a limited number of customers for its services. In 2006, one customer, Helis Oil and Gas Company, LLC (“Helis”), accounted for $95.8 million, or 12.7%, of drilling management services revenues. In 2005, one customer, Lundin Petroleum (“Lundin”), accounted for $97.5 million, or 16.5%, of drilling management services revenues. Two customers each accounted for more than 10% of drilling management services revenues in 2004: Helis provided $60.6 million, or 11.4%, of drilling management services revenues, and Lundin provided $56.6 million, or 10.7%, of drilling management services revenues. See “Item 1A. Risk Factors—We Rely Heavily on a Small Number of Customers and the Loss of a Significant Customer Could Have a Material Adverse Impact on Our Financial Results.”

As of December 31, 2006, our drilling management services revenue backlog was an estimated $114.1 million, all of which is expected to be realized in 2007. Our drilling management services backlog was an estimated $23.5 million at December 31, 2005.

OIL AND GAS OPERATIONS

We conduct oil and gas exploration, development and production activities through our oil and gas division. We acquire interests in oil and gas properties principally in order to facilitate the awarding of turnkey contracts for our drilling management services operations. In this capacity, we facilitated the award of 37 projects (27 turnkey wells and 10 well completions) in 2006. We participated in 25 of the 27 turnkey wells, of which 22 were successful. Our oil and gas activities are conducted primarily in the United States offshore Louisiana and Texas and in the U.K. sector of the North Sea.

In the first quarter of 2004 we sold our interest in a drilling project in West Africa for approximately $6.1 million and recorded a gain of $2.7 million ($2.0 million net of taxes). In September 2004, we completed the sale of 50% of our interest in the Broom Field, a development project in the North Sea. We received net proceeds of $35.9 million and recorded a gain of $25.1 million ($13.3 million net of taxes) in connection with this sale. We retained an eight percent working interest in this project. Pursuant to the terms of the sale, if commodity prices exceeded a specified amount, we were also entitled to additional post-closing consideration equal to a portion of the proceeds from the production attributable to this interest sold through September 2005. In 2005, we recorded an additional gain associated with this deferred consideration arrangement of $4.5 million ($2.7 million net of taxes).

JOINT VENTURE, AGENCY AND SPONSORSHIP RELATIONSHIPS AND OTHER INVESTMENTS

In some areas of the world, local customs and practice or governmental requirements necessitate the formation of joint ventures with local participation, which we may or may not control. We are an active participant in several joint venture drilling companies, principally in Azerbaijan, Indonesia, Malaysia, Angola and Nigeria.

In Azerbaijan, the semisubmersibles Istiglal and Dada Gorgud operate under long-term bareboat charters between Caspian Drilling Company Limited (“CDC”), a joint venture in which we hold a 45% ownership interest, and the owner of both rigs, the State Oil Company of the Azerbaijan Republic (“SOCAR”), our sole equity partner in CDC. SOCAR has granted exclusive bareboat charter rights to CDC for the life of the joint venture. During 2005, these bareboat charter rights were extended through October 2011, pursuant to an amendment to the agreement establishing CDC.

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We also participated in a joint venture that operated a petroleum supply base in Indonesia. The Indonesian supply base, in which we held a 42% ownership interest, is located at Merak Point on the western portion of the island of Java. In October 2005, the joint venture entered into an agreement with a third party to sell the entity holding the lease for the supply base. Completion of this sale occurred during the third quarter of 2006. The sale did not have a material impact on our financial statements.

A joint venture in which we hold a passive minority interest operates primarily in Libya, and to a limited extent in Syria. Syria is identified by the U.S. State Department as a state sponsor of terrorism, In addition, Syria is subject to a number of economic regulations, including sanctions administered by the U.S. Treasury Department’s Office of Foreign Assets Control, and comprehensive restrictions on the export and re-export of U.S.-origin items to Syria. On June 30, 2006, Libya was removed from the U.S. government’s list of state sponsors of terrorism and is no longer subject to sanctions or embargoes. We believe our passive minority investment has been maintained in accordance with all applicable laws and regulations. Potential investors could view such passive minority interest negatively, which could adversely affect our reputation and the market for our ordinary shares. In addition, certain U.S. states have recently enacted legislation regarding investments by their retirement systems in companies that have business activities or contacts with countries that have been identified as terrorist-sponsoring states, and similar legislation may be pending or introduced in other states. As a result, certain investors may be subject to reporting requirements with respect to investments in companies such as ours or may be subject to limits or prohibitions with respect to those investments.

Local laws or customs in some areas of the world also effectively mandate establishment of a relationship with a local agent or sponsor. When appropriate in these areas, we enter into agency or sponsorship agreements.

EMPLOYEES

We had approximately 5,962 employees worldwide at December 31, 2006, excluding approximately 1,681 employees provided through contract labor providers. We require highly skilled personnel to operate our drilling rigs and, accordingly, conduct extensive personnel training and safety programs. Approximately 126 of our local employees in Nigeria and 195 of our local employees in Trinidad are represented by labor unions. Through our membership in the U.K. Drilling Contractors Association, we have also entered into a recognition agreement with a union that covers approximately 820 of our 994 employees in the North Sea.

EXECUTIVE OFFICERS OF THE REGISTRANT

The name, age as of December 31, 2006, and office or offices currently held by each of our executive officers are as follows:

Name	Age	Office or Offices
Jon A. Marshall	55	President and Chief Executive Officer
W. Matt Ralls	57	Executive Vice President and Chief Operating Officer
Michael R. Dawson	53	Senior Vice President and Chief Financial Officer
Roger B. Hunt	57	Senior Vice President, Marketing
James L. McCulloch	54	Senior Vice President and General Counsel
Cheryl D. Richard	50	Senior Vice President, Human Resources
R. Blake Simmons*	48	President of Applied Drilling Technology Inc.
Robert L. Herrin, Jr.	48	Vice President and Controller

* Effective March 1, 2007, Mr. Simmons will be named Senior Vice President, Operations. Stephen E. Morrison will succeed Mr. Simmons in his role as President of Applied Drilling Technology Inc. Mr. Morrison currently serves as ADTI’s Vice President of Planning and Analysis, a position he has held since 1998.

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Officers serve for a one-year term or until their successors are elected and qualified to serve. Each executive officer’s principal occupation has been as one of our executive officers or as an executive officer of one of our predecessors, Santa Fe International or Global Marine, for more than the past five years, with the exception of Ms. Richard, Mr. Simmons, and Mr. Herrin. Ms. Richard has been our Senior Vice President, Human Resources since 2003. Prior to joining our organization, Ms. Richard was Vice President, Human Resources, with Chevron Phillips Chemical Company from 2000 to 2003, prior to which she served in a variety of positions with Phillips Petroleum Company (now ConocoPhillips), including operational, commercial and international positions. Mr. Simmons has been President of Applied Drilling Technology Inc. since 2003. Previously he served as Regional Vice President of GlobalSantaFe Drilling U.K. Limited from 2001 to 2003. Mr. Herrin has been Vice President and Controller since 2005. He previously served as Vice President of Internal Audit from 2002 to 2005, prior to which he served as Director of Audit from 1997 to 2002. Mr. Ralls was promoted to Executive Vice President and Chief Operating Officer in 2005. Mr. Ralls previously served as Senior Vice President and Chief Financial Officer from 1999 to 2005. Mr. Dawson was promoted to Senior Vice President and Chief Financial Officer in 2005. He previously served as Vice President and Controller from 2003 to 2005 and Vice President and Treasurer from 2001 to 2003, prior to which he was Vice President, Investor Relations and Corporate Communications.

OTHER

For a discussion of the effects of environmental regulation, see “Item 1A. Risk Factors—Laws and Governmental Regulations May Add to Costs or Limit Drilling Activity.” and “—Governmental Regulations and Environmental Matters Could Significantly Affect Our Operations and Environmental Liabilities Could Have an Adverse Effect on Us.” We have made and will continue to make expenditures to comply with environmental requirements. To date we have not expended material amounts in order to comply and we do not believe that our compliance with such requirements will have a material adverse effect upon our results of operations or competitive position or materially increase our capital expenditures.

For a discussion of the risks associated with our foreign operations, see “Item 1A. Risk Factors—Our International Operations Involve Additional Risks Not Generally Associated With Our Domestic Operations, Which Could Have a Material Adverse Effect on Our Operations or Financial Results.” and “—We May Suffer Losses as a Result of Foreign Exchange Restrictions, Foreign Currency Fluctuations, and Limitations on the Ability to Repatriate Income or Capital to the U.S.”

LICENSES AND PATENTS

We entered into a settlement with Transocean, effective February 14, 2006, that allowed us to obtain a license in order to use their patented dual drilling structure and method on the GSF Development Driller I, GSF Development Driller II, and GSF Development Driller III. See “Item 3. Legal Proceedings” for a further description of the license.

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ITEM 1A. RISK FACTORS

Risk Factors

A MATERIAL OR EXTENDED DECLINE IN EXPENDITURES BY THE OIL AND GAS INDUSTRY, DUE TO A DECLINE OR VOLATILITY IN OIL AND GAS PRICES, A DECREASE IN DEMAND FOR OIL AND GAS OR OTHER FACTORS, COULD SIGNIFICANTLY REDUCE OUR REVENUE AND INCOME.

Our business depends on the level of offshore oil and natural gas exploration, development and production activity in markets worldwide. Prices and demand for oil and natural gas, and market expectations of potential changes in demand and prices, significantly affect this level of activity. Worldwide military, political and economic events have contributed to oil and natural gas price volatility and are likely to continue to do so in the future. Numerous factors may affect oil and natural gas prices and, accordingly, the level of demand for our services, including:

• worldwide demand for oil and natural gas;

• the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain production levels and pricing;

• the level of production by non-OPEC countries;

• changes in supply and demand resulting from the development of liquefied natural gas markets;

• the worldwide military or political environment, including uncertainty or instability resulting from the situation in Iraq or other armed hostilities in the Middle East or other geographic areas in which we operate, or further acts of terrorism in the United States or elsewhere;

• labor, political or other disruptions that limit exploration, development and production in oil-producing countries;

• domestic and foreign tax policy;

• laws and governmental regulations that restrict exploration and development of oil and natural gas in various jurisdictions;

• advances in exploration and development technology that may affect the marketability of our rigs; and

• further consolidation of our customer base.

Depending on the market prices of oil and natural gas, companies exploring for oil and gas may cancel or curtail their drilling programs, thereby reducing demand for drilling services. Even during periods of high prices for oil and natural gas, companies exploring for oil and gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons. Any reduction in the demand for drilling services may materially erode dayrates and utilization rates for our rigs and adversely affect our financial results.

THE INTENSE PRICE COMPETITION AND CYCLICALITY OF THE DRILLING INDUSTRY, WHICH IS CURRENTLY MARKED BY HIGH DEMAND, LIMITED RIG AVAILABILITY, HIGH DAYRATES, AND A SUBSTANTIAL INCREASE IN THE SUPPLY OF DRILLING UNITS, COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR REVENUES AND PROFITABILITY.

The contract drilling business is highly competitive, and we compete with numerous offshore drilling contractors, one of which is larger and has greater resources than us. The drilling industry has experienced consolidation in recent years and may experience additional consolidation, which could create additional large competitors.

Drilling contracts are, for the most part, awarded on a competitive bid basis. Price competition is often the primary factor in determining which qualified contractor is awarded a job, although rig availability and the quality and technical capability of service and equipment are also factors.

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Mergers among oil and natural gas exploration and production companies have reduced the number of available customers, and our business is subject to the risks associated with having a limited number of customers for our services.

We may be required to idle rigs or to enter into lower dayrate contracts in response to market conditions in the future. The industry in which we operate historically has been cyclical, with periods of high demand, inadequate rig supply and increasing dayrates, which have characterized the condition of the market for the last few years, being followed by periods of low demand or excess rig supply, resulting in lower utilization and decreasing dayrates. 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 often created an oversupply of drilling units and has caused a decline in utilization and dayrates when the rigs enter the market, sometimes for extended periods of time as rigs were absorbed into the active fleet.

Eleven premium jackup newbuild rigs have entered into the market since January 1, 2006, and construction is in progress or contracts have been announced for the construction of at least 65 additional premium jackup rigs, an increase in the worldwide premium jackup fleet of approximately 40%. In the deepwater and ultra-deepwater rig class, there have been announcements of the upgrade of five semisubmersibles to deepwater or ultra-deepwater capability and the construction of over 50 new high-specification rigs, an increase in the units in the deepwater fleet of approximately 50%. Most of these rigs, including our GSF Development Driller III, are ultra-deepwater units and represent an increase in the number of ultra-deepwater units worldwide of approximately 160%. Delivery dates for newbuild units range from the first quarter of 2007 through 2010, with a majority of the newbuild jackups scheduled for delivery in 2007 and 2008. However, we expect that the delivery of a number of the units, primarily the deepwater and ultra-deepwater rigs, will be delayed. A number of the shipyard contracts for units currently under construction provide for options for the construction of additional units and we believe further new construction announcements are likely for all classes of rigs. The entry into service of newly constructed, upgraded or reactivated units will increase supply and could curtail a further strengthening of dayrates, or reduce them, in the affected markets or result in a softening of the affected markets as rigs are absorbed into the active fleet, particularly in periods subsequent to 2007. In addition, the marketing of the newbuild jackup and deepwater and ultra-deepwater rigs scheduled for delivery in future periods could have an adverse effect, even in advance of the rigs’ delivery dates. Further increases in construction of new drilling units could exacerbate any such negative impacts on utilization and dayrates. Lower utilization and dayrates in one or more of the regions in which we operate 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 of our drilling rigs if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these assets may not be recoverable.

CONTINUING WORLD TENSIONS, INCLUDING AS THE RESULT OF WARS, OTHER ARMED CONFLICTS AND TERRORIST ATTACKS, COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS.

Continuing world tensions, including those relating to the Middle East and North Korea, as well as terrorist attacks in various locations and related unrest, have significantly increased worldwide political and economic instability, including as it relates to the exploration for and production of oil and gas. The continuation or escalation of existing armed hostilities or the outbreak of additional hostilities as a consequence of further acts of terrorism or otherwise, could cause a downturn in the economies of the United States and other countries. A lower level of economic activity could result in a decline in energy consumption or an increase in the volatility of energy prices, either of which could adversely affect dayrates or utilization, and accordingly our results of operations and future prospects. In addition, our operations in the Middle East could be directly adversely affected by post-war conditions in Iraq to the extent armed hostilities, acts of terrorism or other unrest persist. Acts of terrorism and threats of armed conflicts elsewhere in the Middle East and in or around various other areas in which we operate, such as Southeast Asia and West Africa, could also directly limit or disrupt our markets and operations through the evacuation of personnel, cancellation of drilling contracts, or loss of personnel or assets. Accordingly, our business could be materially adversely affected by the continuation of existing armed conflicts

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or future armed conflicts or acts of terrorism and any resulting instability, either as a result of the adverse effect of these events on the oil and gas industry or the direct impact on our operations and assets.

Terrorism and world tensions have also caused instability in some of the world’s insurance and financial markets. Immediately following the events of September 11, 2001, our war risk and terrorist insurance underwriters canceled those coverages in accordance with the terms of the policies and would only reinstate them for significantly higher premiums. We have reinstated and currently maintain war and terrorism coverage for physical damage to our entire fleet. Such war and terrorism coverage is generally cancelable by underwriters on forty-eight hours’ notice, and, accordingly, following any future acts of terrorism or armed conflicts in and around the various areas in which we operate, underwriters could cancel this coverage completely or cancel and then offer to reinstate on terms that may not be acceptable to us. We may not have insurance to cover any or all of our liabilities to our personnel for death or injury caused by terrorist acts. These developments could subject our worldwide operations to increased risks and, depending on their magnitude, could have a material adverse effect on our business.

United States Government regulations effectively preclude us from actively engaging in business activities in certain countries, including oil-producing countries such as Iran. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.

WE AND CERTAIN OF OUR SUBSIDIARIES ARE SUBJECT TO LITIGATION THAT, IF NOT RESOLVED IN OUR FAVOR AND NOT SUFFICIENTLY INSURED AGAINST, COULD HAVE A MATERIAL ADVERSE EFFECT ON US.

We and our subsidiaries are subject to a variety of litigation and may be sued in additional cases. Certain of our subsidiaries are named as defendants in numerous lawsuits alleging personal injury as a result of exposure to asbestos, silicosis, exposure to toxic fumes or other occupational diseases and medical issues that can remain undiscovered for a considerable amount of time. Some subsidiaries that have been put on notice of potential liabilities have no assets. Other subsidiaries are subject to litigation relating to environmental damage. We cannot predict the outcome of these cases involving our subsidiaries or the potential costs to resolve them. We cannot assure you that insurance will be applicable and sufficient in all cases, that insurers will remain solvent, or that policies will be located. Suits against non-asset owning subsidiaries have and may in the future give rise to alter ego or successor in interest claims against GlobalSantaFe Corporation and its asset-owning subsidiaries to the extent a subsidiary is unable to pay a claim or insurance is not available or sufficient to cover the claims. To the extent that one or more pending or future litigation matters are not resolved in our favor and are not covered by insurance, that could have a material adverse effect on our financial results and condition. For additional information regarding these legal proceedings, see “Item 3. Legal Proceedings.”

TURNKEY DRILLING OPERATIONS ARE CONTINGENT ON OUR ABILITY TO WIN BIDS AND ON RIG AVAILABILITY, AND THE FAILURE TO WIN BIDS OR OBTAIN RIGS FOR ANY REASON MAY HAVE A MATERIAL ADVERSE EFFECT ON OUR FINANCIAL RESULTS.

Our results of operations from our drilling management services segment may be limited by certain factors, including our ability to find and retain qualified personnel, to hire suitable rigs at acceptable rates, and to obtain and successfully perform turnkey drilling contracts based on competitive bids. Our ability to obtain turnkey drilling contracts is largely dependent on the number of these contracts available for bid, which in turn is influenced by market prices for oil and natural gas, among other factors. Furthermore, our ability to enter into turnkey drilling contracts may be constrained from time to time by the availability of GlobalSantaFe or third- party drilling rigs. Constraints on the availability of rigs may cause delays in our drilling management projects and a reduction in the number of projects that we can complete overall, which could have an adverse effect on our results of operations.

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TURNKEY DRILLING OPERATIONS EXPOSE US TO ADDITIONAL RISKS, WHICH CAN ADVERSELY AFFECT OUR PROFITABILITY, BECAUSE WE ASSUME THE RISK FOR OPERATIONAL PROBLEMS AND THE CONTRACTS ARE ON A FIXED-PRICE BASIS.

We enter into a significant number of turnkey contracts each year. Our compensation under turnkey contracts depends on whether we successfully drill to a specified depth or, under some of our contracts, complete the well. Unlike dayrate contracts, where ultimate control is exercised by the customer, we are exposed to additional risks when serving as a turnkey drilling contractor because we make all critical decisions. Under a turnkey contract, the amount of our compensation is fixed at the amount we bid to drill the well. Thus, we are not paid if operational problems prevent performance unless we choose to drill a new well at our own expense. Further, we must absorb the loss if problems arise that cause the cost of performance to exceed the turnkey price. Given the complexities of drilling a well, it is not unusual for unforeseen problems to arise. We are not generally insured against risks of unbudgeted costs associated with turnkey drilling operations. By contrast, in a dayrate contract, the customer retains most of these risks. As a result of the additional risks we assume in performing turnkey contracts, costs incurred from time to time exceed revenues earned. Accordingly, in prior quarters we have incurred significant losses on certain of our turnkey contracts, and we expect that will continue to be the case in the future. Depending on the size of these losses, they may have a material adverse affect on the profitability of our turnkey drilling segment in a given period.

FAILURE TO OBTAIN AND RETAIN KEY PERSONNEL COULD IMPEDE OPERATIONS.

We require highly skilled personnel to operate our rigs and provide technical services and support for our contract drilling and drilling management services business. Competition for the labor required for deepwater and other drilling operations, including for our turnkey drilling and drilling management services businesses and our construction projects, intensifies as the number of rigs activated, added to worldwide fleets or under construction increases. Historically, in periods of high utilization, such as the current period, we have found it more difficult to find and retain qualified individuals. We have experienced significant tightening in the relevant labor markets over the last two years and have lost some experienced personnel to our customers and competitors. In response to these market conditions, we have instituted retention programs, including increases in compensation, and have incurred other costs to assist in our retention of our work force. If these labor trends continue, they could increase our costs further or limit our operations.

WE RELY HEAVILY ON A SMALL NUMBER OF CUSTOMERS AND THE LOSS OF A SIGNIFICANT CUSTOMER COULD HAVE A MATERIAL ADVERSE IMPACT ON OUR FINANCIAL RESULTS.

Our contract drilling business is subject to the usual risks associated with having a limited number of customers for our services. BP provided approximately $495.2 million, or 15%, of our consolidated revenues in 2006. Our five next largest customers for 2006, Total, ENI, Shell, ExxonMobil, and Chevron, none of which individually represented more than 10% of revenues, accounted in the aggregate for approximately 31% of our 2006 consolidated revenues. BP provided approximately $262.2 million, or 11.6%, of our consolidated revenues in 2005. Our five next largest customers for 2005 (Chevron, Total, ExxonMobil, ENI, and Lundin Petroleum), none of which individually represented more than 10% of revenues, accounted in the aggregate for approximately 36.5% of our 2005 consolidated revenues. Our results of operations could be materially adversely affected if any of our major customers were to terminate its contracts with us, fails to renew its existing contracts or refuses to award new contracts to us.

Our drilling management services business is also subject to the usual risks associated with having a limited number of customers for its services. In 2006, one customer, Helis, accounted for $95.8 million, or 12.7%, of drilling management services revenues. Our five next largest drilling management services customers, none of which individually represented more than 10% of drilling management services revenues, accounted in the aggregate for approximately 31.5% of drilling management services revenues for 2006. In 2005, one customer, Lundin Petroleum, accounted for $97.5 million, or 16.5%, of drilling management services revenues. Our five

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next largest drilling management services customers, none of which individually represented more than 10% of drilling management services revenues, accounted in the aggregate for approximately 35% of drilling management services revenues for 2005.

WE MAY SUFFER LOSSES IF OUR CUSTOMERS TERMINATE OR SEEK TO RENEGOTIATE THEIR CONTRACTS.

Certain of our contracts with customers may be cancelable at the option of the customer upon payment of an early termination payment. Such payments may not, however, fully compensate us for the loss of the contract. Contracts also customarily provide for either automatic termination or termination at the option of the customer for poor performance, in the event of total loss of the drilling rig, if drilling operations are suspended for extended periods of time by reason of acts of God or excessive rig downtime for repairs, or in the event of other specified conditions. Early termination of a contract may result in a rig being idle for an extended period of time. Our revenues, results of operations and cash flow may be adversely affected by customers’ early termination of contracts, especially if we are unable to recontract the affected rig within a short period of time. During depressed market conditions, a customer may no longer need a rig that is currently under contract or may be able to obtain a comparable rig at a lower daily rate. As a result, customers may seek to renegotiate the terms of their existing drilling contracts or avoid their obligations under those contracts. The renegotiation of a number of our drilling contracts could adversely affect our financial position, results of operations and cash flows.

RIG UPGRADE, REFURBISHMENT AND CONSTRUCTION PROJECTS, INCLUDING OUR CURRENT SEMISUBMERSIBLE CONSTRUCTION PROJECT, AND RIG MAINTENANCE AND REPAIRS ARE SUBJECT TO RISKS INCLUDING DELAYS AND COST OVERRUNS, WHICH COULD HAVE A MATERIAL ADVERSE IMPACT ON OUR RESULTS OF OPERATIONS.

We currently have an ultra-deepwater semisubmersible rig under construction to be named the GSF Development Driller III. We may also enter into contracts for the construction of additional rigs and may make major upgrade and refurbishment expenditures for our fleet in the future. Rig upgrade, refurbishment and construction projects and rig repairs are subject to the risks of delay or cost overruns inherent in any large construction project, some of which currently may be exacerbated by increased drilling activity worldwide and the increase in construction and upgrade projects. Such risks include the following:

• shortages of materials or skilled labor;

• unforeseen engineering problems;

• unanticipated actual or purported change orders;

• work stoppages;

• financial or operating difficulties of the shipyard upgrading, refurbishing or constructing the rig;

• adverse weather conditions;

• unanticipated cost increases; and

• inability to obtain any of the requisite permits or approvals.

These and other factors could cause delays in the delivery schedule and increases in the costs of upgrade or newbuild projects, including the GSF Development Driller III, and materially and adversely affect our financial condition and results of operations.

Our ongoing operations also rely on a significant supply of capital and consumable spare parts and equipment to maintain and repair our fleet. We also rely on the supply of ancillary services, including supply boats and helicopters. Recently, we have experienced increased delivery times from vendors due to increased drilling activity worldwide and the increase in construction and upgrade projects. We have also experienced a tightening in the availability of ancillary services. Unanticipated shortages in materials, delays in the delivery of necessary spare parts, equipment or other materials, or the unavailability of ancillary services could negatively impact our future operations and result in increases in rig downtime, and delays in the repair and maintenance of our fleet.

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Additionally, new, refurbished or upgraded rigs may face complications following completion of construction work. For example, the commencement of initial drilling contracts for the GSF Development Driller I and GSF Development Driller II were delayed due to a thruster defect and resulting damage in the thruster nozzles. We could also encounter further unexpected difficulties or complications in the use of these rigs or of other rigs in the future that could result in additional downtime or the cancellation of drilling contracts. In addition, our two newly completed semisubmersibles, as well as the one under construction, employ advancements in technology that may lead to certain difficulties, both operational and legal, as to our use of this technology. Our inability to use this technology, or to use it efficiently, could render these rigs less competitive in the marketplace.

OUR BUSINESS INVOLVES NUMEROUS OPERATING HAZARDS AND WE ARE NOT FULLY INSURED AGAINST ALL OF THEM AND THE AMOUNT OF RISK AGAINST WHICH WE ARE NOT INSURED MAY INCREASE; THE OCCURRENCE OF AN UNINSURED OR UNIDENTIFIED EVENT COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR RESULTS OF OPERATIONS AND FINANCIAL CONDITION.

Our operations are subject to the usual hazards incident to the drilling of oil and natural gas wells, including blowouts, explosions, oil spills and fires. Our activities are also subject to hazards peculiar to marine operations, such as collision, grounding, and damage or loss from severe weather. All of these hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We insure against, or have indemnification from customers for some, but not all, of these risks. We insure only a small percentage of our fleet against loss of revenue for rigs that are damaged. Our insurance contains various deductibles and limitations on coverage. The occurrence of a significant event, including terrorist acts, war, civil disturbances, pollution, environmental damage or hurricanes, not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations, could materially and adversely affect our operations and financial condition.

During the third quarter of 2005, a number of our rigs were damaged as a result of Hurricanes Katrina and Rita. All of these rigs have now returned to work with the exception of the GSF Adriatic VII, which we sold in December 2006, and the GSF High Island III, which is contracted for sale.

All of the rigs that were damaged in the hurricanes were covered for physical damage under the hull and machinery provision of our insurance policy, which carries a deductible of $10 million per occurrence. In addition, three rigs damaged in Hurricane Katrina, the GSF Arctic I, the GSF Development Driller I and the GSF Development Driller II, were covered by loss of hire insurance under which we are reimbursed for 100 percent of each rig’s contracted dayrate for up to a maximum of 270 days per rig following 60 days (the “waiting period”) of lost revenue. Our insurance policy provided that if claims for a single event are filed under both the hull and machinery and loss of hire sections of the policy, we would bear only a single deductible from that occurrence of no more than the highest deductible from any individual section. Hurricanes Katrina and Rita are each considered to be a separate occurrence. Based on remediations completed for the three rigs covered under the loss of hire insurance, the amount of revenue we lost during the waiting period will be higher than the $10 million hull and machinery deductible. Therefore, the 60-day waiting period under our loss of hire insurance will serve as the only deductible for the Hurricane Katrina event. None of the jackup rigs damaged during Hurricane Rita were insured for loss of hire and, therefore, a single $10 million hull and machinery deductible applied for damage to the rigs caused by Hurricane Rita and was recognized as a loss in the third quarter of 2005. We have made substantial insurance claims as a result of the damage sustained by these rigs. As required by the financial accounting rules requiring us to record amounts we consider to be collectible, we have recorded both an estimate of the loss for the damage to our rigs in the hurricanes and an estimate of our expected insurance recovery for that loss. Although we have filed claims for those losses, we have thus far recovered only a portion of the amounts from our insurers, and we have not received any assurances from them as to what our ultimate recovery will be. In addition, we could receive less than the anticipated amounts from our insurers for physical damage to our rigs, and we could therefore suffer losses in excess of the $10 million deductible for hull and machinery damage for various reasons, including disagreements with our insurers as to recoverable costs or financial difficulties of our insurers.

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Moreover, there may be disputes with our insurers as to what amounts we may ultimately recover under our hull and machinery and loss of hire insurance due to the thruster damage sustained by the GSF Development Driller I and the GSF Development Driller II prior to the hurricanes. The underwriters have formally reserved their rights to decline coverage for the thruster damage claims on the rigs in respect of both the hull and machinery and loss of hire coverage. Both rigs were being remediated for a thruster defect and resulting damage when they sustained additional damage as a result of Hurricane Katrina, which further delayed the start of the initial drilling contracts for both rigs. We have made claims under our hull and machinery and loss of hire insurance for the GSF Development Driller I and GSF Development Driller II for the periods required to remediate the damage arising from both the thruster defect and Hurricane Katrina. If our insurers agree to pay the hull and machinery claims, significant unresolved issues remain as to the proper application of the loss of hire waiting period, which could lead to substantial differences in the amount of the loss of hire recovery. As of December 31, 2006, we have recorded estimated loss of hire insurance recoveries with respect to the GSF Development Driller I, in the amount we deem to be probable under the assumption that the rig will bear two consecutive 60-day waiting periods, one for the thruster damage claim and one for the hurricane damage claim. The GSF Development Driller II was not out of service longer than the combined 120-day waiting period and therefore no loss of hire recoveries have been recorded for this rig. When the loss of hire claims are resolved with the underwriters, the amount of loss of hire recoveries could be different than the amount currently recorded. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Investing and Financing Activities” for more information regarding these matters.

The catastrophic damage to the oil and gas industry infrastructure in the U.S. Gulf of Mexico brought about by Hurricanes Katrina and Rita and resulting insurance claims produced extremely large losses in the energy insurance market and has led to substantial increases in reinsurance premiums and significant restrictions in coverage for our insurance underwriters. As a result, when we completed our annual renewal in 2006, our insurance premiums increased from an estimated $32 million to approximately $68 million, in part due to an approximate 57% increase in insured hull values and a 161% increase in insured dayrates. We also experienced changes in our insurance coverage when we completed our annual renewal. Our deductible for insurance for rig physical damage remains at $10 million per occurrence, but an additional $20 million annual aggregate has now been imposed on us, which requires us to absorb the first $20 million of losses above the per occurrence deductible. We also have an $11 million per occurrence retention for liability claims. Our windstorm coverage for Gulf of Mexico claims is now subject to a $200 million annual aggregate limit, of which we self-insure 21.5%, resulting in a maximum potential recovery of $157 million under this coverage. The increases in premiums and deductibles would have substantially reduced our insurance recoveries from the 2005 hurricanes if these changes were in effect at the time and they may subject us to increased risks and could materially and adversely affect our operations and financial condition in the future.

Moreover, in the future we may experience instability in the world’s insurance markets, including capital shortfalls and liquidity concerns for insurers of our assets. As a result of insurance market conditions and developments, we may be required to pay higher premiums or may further increase our deductibles or limits in order to offset or mitigate premium increases. We may also experience further reductions and exclusions from coverage, such as elimination of coverage, or significant restrictions on the amount of money recoverable for Gulf of Mexico windstorm or other claims, or we may elect to change our insurance coverage, by increasing deductibles, retentions and other limitations on coverage, which could effectively further increase the amount of risk against which we are not insured. We may not be able to maintain adequate insurance at rates we consider reasonable or be able to obtain insurance against certain risks in the future.

Additionally, insurance market conditions could adversely impact certain of our customers and their demand for our services. In the Gulf of Mexico, our drilling management and oil and gas segments rely in large part on independent oil and gas operators. As a result of the catastrophic impact of Hurricanes Katrina and Rita and the resulting insurance claims, insurance underwriters have substantially increased premiums and significantly restricted coverages for operators in the Gulf of Mexico. As a result, our drilling management clients and partners in our oil and gas operations may not be able to maintain adequate insurance coverage or be able to

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insure against certain risks. This could reduce the ability of these companies to borrow funds, and may result in significant uninsured losses for physical damage or lost income as a result of hurricanes, and could reduce the number of such operators or reduce the volume of wells drilled in this region. These developments could materially and adversely affect the operations of these lines of business in the Gulf of Mexico.

OUR ABILITY TO OPERATE OUR RIGS IN THE U.S. GULF OF MEXICO COULD BE RESTRICTED BY GOVERNMENT REGULATION OR REQUIREMENTS OF OUR INSURANCE UNDERWRITERS.

Hurricanes Ivan, Katrina and Rita caused damage to a number of rigs in the Gulf of Mexico fleet and rigs that were moved off location by the storms may have damaged platforms, pipelines, wellheads and other drilling rigs during their movements. The Minerals Management Service of the U.S. Department of the Interior (“MMS”) has conducted hearings and is undertaking studies to determine methods to prevent or reduce the number of such incidents in the future. The MMS issued interim guidelines for the 2006 hurricane season requiring jackup drilling rigs operating in the Gulf of Mexico to operate during hurricane season with a greater air gap between the hull of the rig and the water, effectively reducing the water depth in which the rigs can operate. The interim regulations also require operators to conduct more stringent assessments of the soil conditions in which the rigs operate in order to increase the survivability of rigs in hurricane conditions. These interim regulations limit the areas in which particular jackup rigs can operate and expose operators to greater risk of a contracted rig not being able to operate at a specified location, and may reduce the marketability of certain rigs or generally decrease the demand for jackup rigs during hurricane season. The MMS has proposed 2007 guidelines for jackups, which could add other requirements and may further reduce the capability of our Gulf of Mexico jackup fleet. In 2006, the MMS issued interim guidelines requiring that semisubmersibles operating in the Gulf of Mexico assess their mooring systems against stricter criteria. Although our rigs operate in compliance with the MMS 2006 interim guidelines, the proposed MMS 2007 guidelines for semisubmersibles, which impose even stricter mooring system criteria, could negatively impact the operations of one of our semisubmersibles if it were to continue operating in the Gulf of Mexico during hurricane season. Moreover, the MMS may issue additional regulations or underwriters may take steps that could increase the cost of operations or reduce the area of operations for our rigs in the future, thus reducing their marketability. Implementation of MMS regulations or requirements of our insurance underwriters may subject us to increased costs or limit the operational capabilities of our rigs and could materially and adversely affect our operations in the Gulf of Mexico.

OUR INTERNATIONAL OPERATIONS INVOLVE ADDITIONAL RISKS NOT GENERALLY ASSOCIATED WITH DOMESTIC OPERATIONS, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR OPERATIONS OR FINANCIAL RESULTS.

Risks associated with our international operations, including drilling management services, any of which could limit or disrupt our markets or operations, include heightened risks of:

• terrorist acts, war and civil disturbances;

• expropriation or nationalization of assets;

• renegotiation or nullification of existing contracts;

• foreign taxation, including changes in law or interpretation of existing law;

• assaults on property or personnel;

• changing political conditions;

• foreign and domestic monetary policies; and

• travel limitations or operational problems caused by public health threats.

Additionally, our ability to compete in the international market may be adversely affected by non-U.S. governmental regulations favoring or requiring the awarding of drilling contracts to local contractors or requiring

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foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, foreign governmental regulations, which may in the future become applicable to the oil and natural gas industry, could reduce demand for our services, or such regulations could directly affect our ability to compete for customers or significantly increase our costs.

Due to our structure and extensive foreign operations, our effective tax rate is based on the provisions of numerous tax treaties, conventions and agreements between various countries and taxing jurisdictions, as well as the tax laws of many jurisdictions. Changes in one or more of these tax regimes, changes in tax laws or changes in the interpretation of existing laws in these regimes could also have a material adverse effect on us.

PUBLIC HEALTH THREATS COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR INTERNATIONAL OPERATIONS AND OUR FINANCIAL RESULTS.

Public health threats, such as Severe Acute Respiratory Syndrome (SARS), a highly communicable disease, outbreaks of which occurred early in 2003 in Southeast Asia and other parts of the world in which we operate, or the widespread transmission of avian influenza (bird flu) in humans, could adversely impact the global economy, the worldwide demand for oil and natural gas, and the level of demand for our services. Any quarantine of personnel or inability to access our offices or rigs could adversely affect our operations. Travel restrictions or operational problems in any part of the world in which we operate, or any reduction in the demand for drilling services caused by public health threats in the future, may materially impact operations and adversely affect our financial results.

WE MAY SUFFER LOSSES AS A RESULT OF FOREIGN EXCHANGE RESTRICTIONS, FOREIGN CURRENCY FLUCTUATIONS, AND LIMITATIONS ON THE ABILITY TO REPATRIATE INCOME OR CAPITAL TO THE U.S.

A substantial portion of our international drilling and services contracts are partially payable in local currency in amounts that are generally intended to approximate our estimated local operating costs, with the balance of the payments under the contract payable in U.S. dollars (except in Malaysia, where we are paid entirely in local currency). In certain jurisdictions, including Egypt and Nigeria, regulations exist which determine the amounts payable in local currency. Those amounts can exceed the local currency costs being incurred, leading to accumulations of excess local currency, which in certain instances can be subject to either temporary blocking or difficulties in converting to U.S. dollars. To the extent our revenues and assets denominated in local currency do not equal our local operating expenses and liabilities, or during periods of idle time when no revenue is earned, we are exposed to currency exchange transaction losses, which could materially and adversely affect our results of operations and financial condition. We incurred foreign currency exchange losses totaling approximately $0.9 million, $2.3 million, and $6.1 million in 2006, 2005, and 2004, respectively. Although we have not historically entered into financial hedging arrangements to manage risks relating to fluctuations in currency exchange rates, we may enter into such arrangements in the future and such arrangements, themselves, could produce losses.

LAWS AND GOVERNMENTAL REGULATIONS MAY ADD TO COSTS OR LIMIT DRILLING ACTIVITY.

Our business is affected by changes in public policy and by federal, state, foreign and local laws and regulations relating to the energy industry. The drilling industry is dependent on demand for services from the oil and natural gas exploration and production industry and, accordingly, we are directly affected by the adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental and other policy reasons. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.

Governments in some non-U.S. countries have become increasingly active in regulating and controlling the ownership of concessions, companies holding concessions, the exploration for oil and natural gas, and other

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aspects of the oil and natural gas industries in these countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil companies and may continue to do so.

GOVERNMENTAL REGULATIONS AND ENVIRONMENTAL MATTERS COULD SIGNIFICANTLY AFFECT OUR OPERATIONS AND ENVIRONMENTAL LIABILITIES COULD HAVE A MATERIAL ADVERSE EFFECT ON US.

Our operations are subject to numerous federal, state, and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment. As a result, the application of these laws could have a material adverse effect on our results of operations by increasing our cost of doing business, discouraging our customers from drilling for hydrocarbons, or subjecting us to liability. For example, we, as an operator of mobile offshore drilling units in navigable U.S. waters and certain offshore areas, including the Outer Continental Shelf, are liable for damages and for the cost of removing oil spills for which we may be held responsible, subject to certain limitations. Our historical and current operations may involve the use or handling of materials that may be classified as environmentally hazardous substances. Laws and regulations protecting the environment have generally become more stringent and may in certain circumstances impose “strict liability,” rendering a person liable for environmental damage without regard to negligence or fault. Environmental laws and regulations may expose us to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. We have potential liabilities under various statutes regulating the cleanup of a number of hazardous waste disposal sites and cannot assure you that we will not be named in similar matters in the future. In addition, one of our subsidiaries was named as a defendant, along with nineteen other companies, in a lawsuit filed on behalf of three landowners in Louisiana. That lawsuit alleges that the defendants 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. The Louisiana Department of Environmental Quality is in the process of conducting its own investigation. The subsidiary, which no longer conducts operations or holds assets, has filed for bankruptcy in Delaware and has been dismissed as a defendant. The co-defendant of our subsidiary filed various motions in the Louisiana proceeding and in the Delaware bankruptcy proceeding attempting to assert alter ego and a similar doctrine of Louisiana law against GlobalSantaFe Corporation and also seeking the dismissal of the bankruptcy. To the extent that one or more pending or future environmental matters or lawsuits are not resolved in our favor and are not covered by insurance or indemnity agreements with subsequent operators in the field, that could have a material adverse effect on our financial results and condition. For further discussion of potential environmental liabilities affecting us, see “Item 3. Legal Proceedings—Environmental Matters.”

WE ARE SUBJECT TO CHANGES IN TAX LAWS AND OUR TAX RETURNS ARE SUBJECT TO REVIEW AND POSSIBLE ADJUSTMENTS.

We are a Cayman Islands company and we operate through our various subsidiaries in numerous countries throughout the world including the United States. Consequently, we are subject to changes in tax laws, treaties, and regulations in and between countries in which we operate, including treaties between the U.S. and other nations. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. A material change in these tax laws, treaties or regulations, including those in and involving the U.S., could result in a higher effective tax rate on our worldwide earnings.

Proposed legislation has been introduced in the U.S. Congress over the past several years that would limit the deductibility of certain interest expense on related-party indebtedness. A similar proposal has also been included in the President’s fiscal year 2008 budget proposals. Such legislation, if enacted, could cause a significant increase in our U.S. tax liability. The American Jobs Creation Act of 2004 mandated the U.S. Treasury to complete a study on the effect of certain deductions such as related-party interest. It is possible that the U.S. Congress will propose further legislation in this regard after the study has been completed.

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Our income tax returns are subject to review and examination in various countries. We are currently under review in various countries, and some of those countries have issued proposed adjustments to our tax returns. While we have agreed to certain adjustments in some of the countries, we believe that our tax returns are materially correct as filed, and we will defend ourselves against any adjustments that we determine to be unwarranted. For more information regarding these matters see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operating Results—Income Taxes.” We cannot rule out the possibility that we may not prevail in all cases or that the final outcome of any future assessment may be adverse to us. However, we do not believe that the ultimate resolution of these outstanding or future assessments will have a material adverse affect on our financial position, results of operations and cash flows.

WE MAY BE LIMITED IN OUR USE OF NET OPERATING LOSSES.

Our ability to benefit from our deferred tax assets depends on us having sufficient future earnings to utilize our net operating loss (“NOL”) carryforwards before they expire. We have established a valuation allowance against the future tax benefit for a number of our foreign NOL carryforwards, and we could be required to record an additional valuation allowance against our foreign or U.S. deferred tax assets if market conditions change materially and, as a result, our future earnings are, or are projected to be, significantly less than we currently estimate. Our NOL carryforwards are subject to review and potential disallowance upon audit by the tax authorities of the jurisdictions where the NOLs were incurred.

As of December 31, 2006, we had approximately $344.1 million of NOL carryforwards for U.S. federal income tax purposes. These NOL carryforwards include NOL carryforwards of Global Marine from periods prior to the 2001 merger of Global Marine with one of our subsidiaries. Section 382 of the U.S. Internal Revenue Code could limit the use of some of these Global Marine NOL carryforwards if the direct and indirect ownership of the stock of Global Marine changed by more than 50% in certain circumstances over a prescribed testing period. The Internal Revenue Service may take the position that the merger caused a greater-than-50-percent ownership change with respect to Global Marine. If the merger did not result in such an ownership change, changes in the ownership of our ordinary shares following the merger may have resulted in such an ownership change. In the event of such an ownership change, the Section 382 rules would limit the utilization of Global Marine’s NOL carryforwards in each taxable year ending after the ownership change to an amount equal to a federal long-term tax-exempt rate published monthly by the Internal Revenue Service, multiplied by the fair market value of all of Global Marine’s stock, each determined at the time of the ownership change. For purposes of this calculation, the value of Global Marine’s stock at such time may be subject to adjustments that would further limit our ability to utilize Global Marine’s NOL carryforwards. If a limitation were imposed under Section 382, it could result in Global Marine’s NOL carryforwards expiring unused or in our inability to fully offset taxable income with NOLs in a particular year, even though our NOL carryforwards exceeded our taxable income for that year.

WE MAY BE REQUIRED TO ACCRUE ADDITIONAL TAX LIABILITY ON CERTAIN EARNINGS.

We have not provided for U.S. deferred taxes on the unremitted earnings of our U.S. subsidiaries that are permanently reinvested. Should a distribution be made from the unremitted earnings of these U.S. subsidiaries, we could be required to record additional U.S. current and deferred taxes that, if material, could have an adverse effect on our financial position, results of operations and cash flows.

OUR SHAREHOLDERS HAVE LIMITED RIGHTS UNDER CAYMAN ISLANDS LAW.

We are incorporated under the laws of the Cayman Islands, and our corporate affairs are governed by our memorandum of association and our articles of association and by the Companies Law (2004 Revision) of the Cayman Islands. Principles of law relating to matters such as the validity of corporate procedures, the fiduciary duties of management, directors and controlling shareholders, and the rights of shareholders differ from those that would apply if we were incorporated in a jurisdiction within the United States. Further, the rights of shareholders under Cayman Islands law are not as clearly established as the rights of shareholders under

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legislation or judicial precedent applicable in some U.S. jurisdictions. As a result, our shareholders may face more uncertainty in protecting their interests in the face of actions by the management or directors than they might have as shareholders of a corporation incorporated in a U.S. jurisdiction.

ITEM 1B. UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 3. LEGAL PROCEEDINGS

In August 2004, certain of our subsidiaries were named as defendants in six lawsuits filed in Mississippi, five of which are pending in the Circuit Court of Jones County and one of which is pending in the Circuit Court of Jasper County, Mississippi, alleging that certain individuals aboard our offshore drilling rigs had been exposed to asbestos. These six lawsuits are part of a group of twenty-three lawsuits filed on behalf of approximately 800 plaintiffs against a large number of defendants, most of which are not affiliated with us. Our subsidiaries have not been named as defendants in any of the other seventeen lawsuits. The lawsuits assert claims based on theories of unseaworthiness, negligence, strict liability and our subsidiaries’ status as Jones Act employers; and seek unspecified compensatory and punitive damages. In general, the defendants are alleged to have manufactured, distributed or utilized products containing asbestos. In the case of our named subsidiaries and that of several other offshore drilling companies named as defendants, the lawsuits allege those defendants allowed such products to be utilized aboard offshore drilling rigs. We have not been provided with sufficient information to determine the number of plaintiffs who claim to have been exposed to asbestos aboard our rigs, whether they were employees nor their period of employment, the period of their alleged exposure to asbestos, nor their medical condition. Accordingly, we are unable to estimate our potential exposure to these lawsuits. We historically have maintained insurance which we believe will be available to address any liability arising from these claims. We intend to defend these lawsuits vigorously, but there can be no assurance as to their ultimate outcome.

We and two of our subsidiaries were defendants in a lawsuit filed on July 28, 2003, by Transocean Inc. (“Transocean”) in the United States District Court for the Southern District of Texas, Houston Division. The lawsuit alleged that the dual drilling structure and method utilized by the GSF Development Driller I and the GSF Development Driller II semisubmersibles infringe on United States patents granted to Transocean. On August 31, 2006, the jury returned a verdict upholding the validity of certain of the Transocean apparatus claims, awarding past damages of approximately $3.6 million, and finding that we had willfully infringed the patents. The judge subsequently entered a ruling overturning the jury’s finding of willful infringement. Transocean has similar patents in most other jurisdictions in which ultra-deepwater semisubmersibles are likely to operate, excluding certain parts of West Africa. It also has patents in Singapore, where the GSF Development Driller I and GSF Development Driller II were constructed and where the similarly designed GSF Development Driller III is being constructed, and in most other jurisdictions in which dual activity rigs are likely to be constructed. We had joined with other parties in proceedings in Europe and Brazil contesting the issuance of patents to Transocean for dual activity methods and structures. The patents that Transocean obtained in those jurisdictions were substantially the same as those granted in the U.S. and Singapore. In June 2006, the European Patent Office invalidated the patent claims that were the subject of the proceedings, and the Brazilian Patent Office has recently entered a preliminary ruling invalidating the patents in that jurisdiction.

We entered into a settlement agreement with Transocean, effective February 14, 2007, in which we were granted a personal, worldwide, royalty bearing and non-exclusive license to operate dual activity rigs under the Transocean patents. The primary terms of the settlement are as follows:

• we will pay approximately $3,000,000 to Transocean for the past use of dual activity by the GSF Development Driller I and GSF Development Driller II;

• at any time we operate in a jurisdiction in which Transocean has a valid, non-expired patent for dual activity, we will pay a royalty of 3% of the basic dayrate of the GSF Development Driller I, GSF

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Development Driller II and GSF Development Driller III, or 5% of the basic dayrate of any dual activity rigs that we hereafter acquire or construct. The Transocean patents are set to expire in 2016;

• we will pay $12,000,000 to Transocean on behalf of ourselves and the shipyards that constructed the GSF Development Driller I and GSF Development Driller II, and the shipyard that is currently constructing the GSF Development Driller III, and we and the shipyards will be relieved of any liability for the alleged infringement arising from the construction of those rigs; and

• we will withdraw from the proceedings opposing the issuance of patents in Europe and Brazil, and we have agreed not to challenge the validity of the Transocean patents in any jurisdiction.

One of our subsidiaries filed suit in February 2004 against its insurance underwriters in the Superior Court of San Francisco County, California, seeking a declaration as to its rights to insurance coverage and the proper allocation among its insurers of liability for claims payments in order to assist in the future management and disposition of certain claims described below. The subsidiary’s three primary insurers have historically been paying settlement and defense costs for the subsidiary. One of these insurers was nearing insolvency and claimed exhaustion of its coverage limits, but following negotiations has agreed to make a cash payment in exchange for a release of all further liability for the subsidiary’s asbestos liabilities. Both of the subsidiary’s other primary insurers have entered into settlement agreements with the subsidiary that will provide for limited additional funding of asbestos liabilities and attorneys’ fees and costs associated therewith. The subsidiary also intends to enter into discussions with its excess insurers. We believe that the subsidiary will continue to have funds from its insurers sufficient to meet its settlement and defense obligations for the foreseeable future.

The insurance coverage in question relates to lawsuits filed against the subsidiary arising out of its 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 the litigation 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 January 1, 2007, the subsidiary had been named as a defendant in approximately 4,200 lawsuits, the first of which was filed in 1990, and a substantial number of which are currently pending. We believe that as of January 1, 2007, from $35 million to $40 million had been expended to resolve claims (including both attorney fees and expenses, and settlement costs), with the subsidiary having expended $4 million of that amount due to insurance deductible obligations, all of which have now been satisfied. Because we rely on information from the insurers of our subsidiary for information regarding the amounts expended in settlement and defense of these lawsuits and are not able to verify or confirm the information, the amount expended by the insurers is not known with precision. 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. Although not all of that will be available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient insurance available to respond to these claims. We do not believe that these claims will have a material impact on our consolidated financial position, results of operations or cash flows.

The same subsidiary is a defendant in a lawsuit filed against it by Union Oil Company of California (“Union”) in the Circuit Court of Cook County, Illinois. That lawsuit arises out of claims alleging personal injury caused by exposure to asbestos at a refinery owned by Union and constructed by our subsidiary. Union has alleged that the subsidiary is required to defend and indemnify it pursuant to the terms of contracts entered into for the construction of the refinery. GlobalSantaFe Corporation has also been named as a defendant in the pending litigation. Union intends to attempt to establish liability against GlobalSantaFe Corporation as the alter ego of, and successor in interest to, its subsidiary and on the basis of a fraudulent conveyance of the subsidiary’s assets, and seeks to pierce the corporate veil between the subsidiary and GlobalSantaFe Corporation. We believe that the allegations of the lawsuit are without merit and intend to vigorously defend against the lawsuit, but cannot provide any assurance as to its ultimate outcome.

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We and a number of our subsidiaries were named as defendants in two lawsuits claiming that the GSF Adriatic VII caused damage to a platform in the South Marsh Island area of the Gulf of Mexico when the rig broke free from its location during Hurricane Rita. On September 20, 2006, Devon Energy Corporation and Pogo Producing Company filed suit in the United States District Court for the Southern District of Texas, Houston Division, claiming that the defendants caused damage in an amount exceeding $75 million. On the same day Apache Corporation, as successor in interest to BP p.l.c., filed suit against the defendants in the United States District Court for the Western District of Louisiana, Lafayette Division, claiming damage in an unspecified amount. We have not been presented with evidence indicating that the GSF Adriatic VII caused the damage, if any, claimed by plaintiffs. In any event, we believe that we will be entitled to the benefits of the Act of God defense. Any liability arising therefrom, including legal fees and expenses, will be paid by our insurance underwriters.

We and our subsidiaries are defendants or otherwise involved in a number of lawsuits in the ordinary course of business. In the opinion of management, our ultimate liability with respect to these pending lawsuits is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

ENVIRONMENTAL MATTERS

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 now been entered by the court. The parties to the settlement have entered into a participation agreement, which makes us liable for approximately 8% of the remediation and related costs. The remediation is complete, but our share of the future operation and maintenance costs of the site is estimated to have a present value of approximately $900,000. 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.

We have also been named as a PRP in connection with a site in California known as the Casmalia Resources Site. We and other PRPs have entered into an agreement with the EPA and the DOJ to resolve potential liabilities. Under the settlement, we are not likely to owe any substantial additional amounts for this site beyond what we have already paid. There are additional potential liabilities related to this site, but these cannot be quantified at this time, and we have no reason at this time to believe that they will be material.

We have been named as one of many PRPs in connection with a site located in Carson, California, formerly maintained by Cal Compact Landfill. On February 15, 2002, we were served with a required 90-day notification that eight California cities, on behalf of themselves and other PRPs, intend to commence an action against us under the Resource Conservation and Recovery Act (“RCRA”). On April 1, 2002, a complaint was filed by the cities against us and others alleging that we have liabilities in connection with the site. However, the complaint has not been served. The site was closed in or around 1965, and we do not have sufficient information to enable us to assess our potential liability, if any, for this site.

One of our subsidiaries has recently been ordered by the California Regional Water Quality Control Board to develop a testing plan for a site known as Campus 1000 Fremont in Alhambra, California. This site was

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formerly owned and operated by certain of our subsidiaries. It is presently owned by an unrelated party, which has also received an order to develop a testing plan for the property. Although the testing plan has not yet been developed and approved, testing costs are expected to be in the range of $200,000. We have also been advised that another subsidiary is likely to be named by the EPA as a PRP for the San Gabriel Valley, Area 3, Superfund site, which includes this property. 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 liable 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 and/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 and/or remedial actions; and

• allocation of the costs of such activities among the PRPs and other site users.

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

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

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

• the remediation methods and technology to be used.

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

On July 11, 2005, one of our subsidiaries, Santa Fe Minerals, Inc., was served with a lawsuit filed on behalf of three landowners in Louisiana in the 12^th Judicial District Court for the Parish of Avoyelles, State of Louisiana. The lawsuit names nineteen other defendants, all of which are 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. The lawsuit specifies 95 wells drilled on the property in question beginning in 1939, and alleges that our subsidiary, which is a dissolved corporation and no longer conducts operations or holds assets, was the operator or non-operating partner in 13 of the wells during certain periods of time. The plaintiffs allege that the defendants are liable on the basis of strict liability, breach of contract, breach of the mineral leases, negligence, nuisance, trespass, and improper handling of toxic or hazardous substances, that their storage and disposal of toxic and hazardous substances constituted an ultra-hazardous activity, and that they violated various state statutes. The lawsuit seeks unspecified amounts of compensatory and punitive damages, payment of funds sufficient to conduct an environmental assessment of the property in question, damages for diminution of property value and injunctive relief requiring that defendants restore the property to its prior condition and prevent the migration of toxic and hazardous substances. Experts retained by the plaintiffs have issued a report suggesting significant contamination in the area operated by the subsidiary and another codefendant, and claiming that over $300 million will be required to properly remediate the contamination. The experts retained by the defendants conducted their own investigation and concluded that the remediation costs will amount to no more than a few million dollars. The Louisiana Department of Environmental Quality is in the process of conducting its own investigation in that regard. We believe that our subsidiary has meritorious defenses to the allegations contained in the lawsuit, and that if liability is established against it that the judgment will be far lower than that being demanded by the plaintiffs. The plaintiffs and the codefendant threatened to add GlobalSantaFe Corporation as a defendant in the

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lawsuit under the “single business enterprise” doctrine contained in Louisiana law. The single business enterprise doctrine is an equitable construct created and applied by the judiciary to impose liability against the parent company or a different subsidiary or affiliated companies where more than one company represents precisely the same single interests. The single business enterprise doctrine is similar to corporate veil piercing doctrines. On August 16, 2006, Santa Fe Minerals, Inc. and its immediate parent company, 15375 Memorial Corporation, which is also 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 United States Bankruptcy Court for the District of Delaware. Later that day, the plaintiffs dismissed Santa Fe Minerals, Inc. 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 Corporation and two other subsidiaries in the lawsuit. We believe that these legal theories should not be applied against GlobalSantaFe Corporation or these other two subsidiaries, and that in any event the manner in which the parent and its subsidiaries conducted their businesses does not meet the requirements of these theories for imposition of liability. The codefendant also seeks to dismiss the bankruptcies. To date, the efforts to assert alter ego and single business enterprise theory claims against GlobalSantaFe Corporation have been rejected by the Court in Avoyelles Parish and we have filed an action with the Delaware Court asking that any such claims be heard there. We intend to continue to vigorously defend against any action taken in an attempt to impose liability against us under these theories or otherwise.

OTHER LEGAL MATTERS

We and our subsidiaries are defendants or otherwise involved in a number of lawsuits in the ordinary course of business. In the opinion of management, our ultimate liability with respect to these pending lawsuits is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of our security holders during the fourth quarter of 2006.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our Ordinary Shares, $.01 par value per share, are listed on the New York Stock Exchange under the symbol “GSF.” The following table sets forth the high and low sales prices of our Ordinary Shares as reported on the New York Stock Exchange Composite Transactions Tape for the calendar periods indicated.

	Price per Share
	High		Low
2006
First Quarter	$	62.41	$	48.40
Second Quarter		65.21		49.73
Third Quarter		58.86		45.75
Fourth Quarter		64.50		44.26
2005
First Quarter	$	39.05	$	31.95
Second Quarter		44.00		32.27
Third Quarter		48.00		40.30
Fourth Quarter		50.22		39.15

On January 31, 2007, the closing price of the Ordinary Shares, as reported by the NYSE, was $58.01 per share. As of January 31, 2007, there were approximately 2,566 shareholders of record of Ordinary Shares. This number does not include shareholders for whom shares are held in a nominee or street name.

DIVIDEND POLICY

We paid dividends of $0.075 in the first two quarters of 2005, $0.15 in the last two quarters of 2005, and $0.225 for all four quarters of 2006. On December 19, 2006, our Board of Directors declared a dividend of $0.225 payable to shareholders of record as of December 29, 2006. This dividend was paid on January 12, 2007. The dividends paid in a given quarter relate to the immediately preceding quarter. Our payment of dividends in the future, if any, will be at the discretion of our Board of Directors and will depend on our results of operations, financial condition, cash requirements, future business prospects, and other factors.

ISSUER REPURCHASES OF ORDINARY SHARES

The following table details our repurchases of ordinary shares for the three months ended December 31, 2006:

Period	Total Number of Shares Purchased		Average Price Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs
October 1 - 31, 2006	2,081,000		$	48.80	2,081,000	$	1.1 billion	(2)
November 1 - 30, 2006	1,768,750		$	55.16	1,768,750	$	1.0 billion	(2)
December 1 - 31, 2006	1,653,931	(1)	$	60.99	1,653,931	$	0.9 billion	(2)
Total	5,503,681		$	54.51	5,503,681

(1) During December 2006, we repurchased a total 1,653,931 shares at an average price of $60.99 per share. As of December 31, 2006, transactions to purchase 278,500 of these shares were not yet settled and these shares are still included in our share base as of December 31, 2006. We purchased these shares with our cash from operations.

(2) On March 3, 2006, our Board of Directors authorized us to repurchase up to $2 billion of our ordinary shares from time to time. All of the shares repurchased during the fourth quarter of 2006 were repurchased pursuant to this plan.

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ITEM 6. SELECTED FINANCIAL DATA

The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data.”

GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

FIVE-YEAR REVIEW

(In millions, except per share and operational data)

	2006			2005			2004			2003			2002
Financial Performance
Revenues:
Contract drilling	$	2,540.2		$	1,640.2		$	1,176.9		$	1,263.9		$	1,458.8
Drilling management services		718.8			566.6			515.2			523.4			400.6
Oil and gas		53.6			56.7			31.6			20.9			10.6
Total revenues	$	3,312.6		$	2,263.5		$	1,723.7		$	1,808.2		$	1,870.0
Operating income:
Contract drilling	$	1,046.4		$	445.3		$	119.1		$	138.0		$	334.7
Drilling management services		11.6			31.3			6.7			31.7			28.6
Oil and gas		27.2			33.9			19.4			12.0			4.8
Gain (loss) on involuntary conversion of long-lived assets, net of related insurance recoveries and loss of hire recoveries (1)		116.5			(6.2	)		24.0			—			—
Gain on sale of assets (2)		—			28.0			27.8			—			—
Impairment loss on long-lived asset (3)		—			—			(1.2	)		—			—
Restructuring costs (4)		—			—			—			(3.4	)		—
Corporate expenses		(91.9	)		(67.9	)		(62.0	)		(52.7	)		(61.8	)
Total operating income		1,109.8			464.4			133.8			125.6			306.3
Other income (expense):
Interest expense		(37.0	)		(41.3	)		(55.5	)		(67.5	)		(57.1	)
Interest capitalized		20.5			38.1			41.0			34.9			20.5
Interest income		23.5			22.7			12.3			11.2			15.1
Loss on retirement of long-term debt (5)		—			—			(32.4	)		—			—
Other (6)		1.1			2.1			(1.2	)		25.0			2.3
Total other income (expense)		8.1			21.6			(35.8	)		3.6			(19.2	)
Income before income taxes		1,117.9			486.0			98.0			129.2			287.1
Provision for income taxes:
Current income tax provision		88.1			57.1			52.6			26.7			45.9
Deferred income tax provision (benefit)		23.4			5.8			14.0			(11.7	)		(20.3	)
Total provision for income taxes (7)		111.5			62.9			66.6			15.0			25.6
Income from continuing operations		1,006.4			423.1			31.4			114.2			261.5
Income from discontinued operations, net of tax effect (8)		—			—			112.3			15.2			16.4
Net income	$	1,006.4		$	423.1		$	143.7		$	129.4		$	277.9

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	2006			2005			2004			2003			2002
Earnings per ordinary share (Basic):
Income from continuing operations	$	4.19		$	1.76		$	0.13		$	0.49		$	1.12
Income from discontinued operations		—			—			0.48			0.06			0.07
Net income	$	4.19		$	1.76		$	0.61		$	0.55		$	1.19
Earnings per ordinary share (Diluted):
Income from continuing operations	$	4.13		$	1.73		$	0.13		$	0.49		$	1.11
Income from discontinued operations		—			—			0.48			0.06			0.07
Net income	$	4.13		$	1.73		$	0.61		$	0.55		$	1.18
Average ordinary shares—Basic		240.1			240.9			234.8			233.2			233.7
Average ordinary shares—Diluted		243.6			245.1			237.2			234.9			236.5
Cash dividends declared per ordinary share	$	0.900		$	0.600		$	0.225		$	0.175		$	0.13
Capital expenditures (9)	$	510.4		$	396.9		$	452.9		$	466.0		$	574.1
Depreciation, depletion and amortization	$	304.7		$	275.3		$	256.8		$	257.5		$	239.1
Ratio of Earnings to Fixed Charges
Ratio of Earnings to Fixed Charges		9.93			5.40			1.66			2.04			4.31
Financial Position (end of year)
Working capital	$	670.6		$	993.8		$	451.6		$	1,020.7		$	712.0
Properties and equipment, net	$	4,514.6		$	4,317.8		$	4,329.9		$	4,180.2		$	4,194.0
Total assets	$	6,220.2		$	6,222.1		$	5,998.2		$	6,149.7		$	5,828.7
Long-term debt, including capital lease obligations	$	639.3		$	574.2		$	586.0		$	1,230.9		$	941.9
Shareholders’ equity	$	4,847.1		$	4,957.5		$	4,466.4		$	4,327.6		$	4,234.2
Operational Data
Average rig utilization (10)		95	%		96	%		86	%		85	%		89	%
Average revenues per day (11)	$	122,600		$	78,900		$	63,500		$	65,900		$	72,400
Number of active rigs—(end of year)		59			61			59			59			58
Turnkey wells drilled		70			80			89			85			78
Turnkey completions		27			19			30			31			20
Number of employees (end of year)		5,962			5,700			5,300			7,100			7,200

(1) In the third quarter of 2005, our fleet in the U.S. Gulf of Mexico was impacted by both Hurricane Katrina and Hurricane Rita. In that quarter we recorded an involuntary loss totaling $127 million against the carrying value of rigs damaged in the storms, offset by $117 million in anticipated insurance recoveries. The net loss of $10 million for that quarter represents our insurance deductible for Hurricane Rita, while the 60-day waiting period under our loss of hire insurance policy will serve as the only insurance deducible for Hurricane Katrina. In the fourth quarter of 2005 we recorded $3.8 million for estimated recoveries from insurers under this loss of hire insurance policy related to Hurricane Katrina, resulting in a net loss for 2005 of $6.2 million. During the first half of 2006, we recorded an additional $21.6 million for estimated recoveries from insurers under the loss of hire insurance policy related to Hurricane Katrina. During the second quarter of 2006, we also recorded gains of $32.8 million on the GSF High Island III and $30.9 million on the GSF Adriatic VII , which represent recoveries of partial losses under our insurance policy, less amounts previously recognized when the rigs were written down to salvage value. In December 2006, we sold the GSF Adriatic VII to a third party for a net purchase price of approximately $29.4 million and recorded a gain of $28 million, which represents the net purchase price net of the $1.4 million salvage value. In addition, we increased the gain recognized in the second quarter of 2006 related to the GSF Adriatic VII by $3.2 million to include additional costs reimbursable under the insurance policy. Subsequent to December 31, 2006, we entered into a contract to sell the GSF High Island III to a third party for approximately $26.3 million and expect to complete the sale during the first quarter of 2007. We will record

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a gain equal to the selling price, net of expenses, less the salvage value of $1.2 million. In 2004, the jackup GSF Adriatic IV encountered well control problems, caught fire and sank while drilling in the Mediterranean Sea off the coast of Egypt. We received insurance proceeds totaling $40.0 million, net of our deductible, and recorded a gain of $24.0 million, net of taxes.

(2) The 2004 amount includes the sale of our oil and gas division’s interests in two oil and gas projects. In the first quarter of 2004, our oil and gas division sold its interest in a drilling project in West Africa for approximately $6.1 million, recording a gain of $2.7 million. In the third quarter of 2004, our oil and gas division sold a portion of its interest in the Broom Field development project in the North Sea for approximately $35.9 million, recording a gain of $25.1 million. Pursuant to the terms of the Broom Field sale, if commodity prices exceeded a specified amount, we were also entitled to additional post-closing consideration equal to a portion of the proceeds from the production attributable to this interest sold through September 2005. In 2005, we recorded an additional gain associated with this deferred consideration arrangement of $4.5 million, which represents the entire deferred consideration earned under the sales agreement. In 2005, we also sold the Glomar Robert F. Bauer drillship for $25 million and recorded a net pre-tax gain of $23.5 million.

(3) In 2004, we sold the platform rig Rig 82 for a nominal sum in connection with our exit from the platform rig business and recognized an impairment loss of approximately $1.2 million.

(4) Restructuring costs for 2003 represent changes in estimated restructuring costs associated with Global Marine recorded in 2001 in connection with the merger of Global Marine and Santa Fe International.

(5) In 2004 we completed the redemption of the entire outstanding $300 million principal amount of Global Marine Inc.’s 7 ¹/8% Notes due 2007, recognizing a loss on the early retirement of debt of approximately $32.4 million.

(6) The 2003 amount includes $22.3 million awarded to us as a result of the settlement of claims filed in 1993 with the United Nations Compensation Commission for losses suffered as a result of the Iraqi invasion of Kuwait in 1990. The claims were for the loss of four rigs and associated equipment, lost revenue and miscellaneous expenditures.

(7) In 2004, we completed a subsidiary realignment to separate our international and domestic holding companies, which included transferring ownership of certain rigs between our domestic and international subsidiaries. The transaction resulted in a charge of $42.5 million, $5.1 million of which is included in current tax expense and $37.4 million of which is included in deferred tax expense.

(8) In 2004, we sold our land drilling business for a total sales price of $316.5 million, recognizing a gain of $113.1 million, net of taxes. Operating results for our land drilling operations have historically been included in contract drilling results. As a result of this sale, however, results of land drilling operations have been excluded from contract drilling results and are reflected in “Income from discontinued operations, net of tax effect” for all periods presented.

(9) Capital expenditures include $13.7 million, $49.8 million, $63.9 million, $16.6 million and $19.2 million of capital expenditures related primarily to our rig building program that had been accrued but not paid as of December 31, 2006, 2005, 2004, 2003 and 2002, respectively.

(10) The average rig utilization rate for a period represents the ratio of days in the period during which the rigs were under contract to the total days in the period during which the rigs were available to work.

(11) Average revenues per day is the ratio of rig-related contract drilling revenues divided by the aggregate contract days, adjusted to exclude days under contract at zero dayrate. The calculation of average revenues per day excludes non-rig related revenues, consisting mainly of reimbursed expenses, totaling $82.0 million, $67.4 million, $32.5 million, $46.9 million, and $64.4 million for the years ended December 31, 2006, 2005, 2004, 2003, and 2002, respectively. Average revenues per day including these reimbursed expenses would have been $126,700, $82,300, $65,100, $67,700, and $74,500, for the years ended December 31, 2006, 2005, 2004, 2003, and 2002, respectively. The calculation of average revenues per day excludes all contract drilling revenues related to our platform rig operations.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

We are an offshore oil and gas drilling contractor, owning or operating a fleet of 59 marine drilling rigs. As of December 31, 2006, our fleet included 43 cantilevered jackup rigs, 11 semisubmersible rigs, three drillships and two additional semisubmersible rigs we operate for third parties under a joint venture agreement (see “Item 1 and 2. Business and Properties—Joint Venture, Agency and Sponsorship Relationships and Other Investments”). During the first quarter of 2006, we commenced construction of an additional semisubmersible, to be named the GSF Development Driller III. We also have a jackup rig, the GSF High Island III, that is currently not capable of performing drilling operations due to damage arising as a result of Hurricane Rita. Subsequent to December 31, 2006, we entered into a contract to sell the rig to a third party and expect to complete the sale during the first quarter of 2007. (See “—Involuntary Conversion of Long-Lived Assets and Related Recoveries.”).

We provide offshore oil and gas contract drilling services to the oil and gas industry worldwide on a daily rate (“dayrate”) basis. We also provide oil and gas drilling management services on either a dayrate or completed-project, fixed-price (“turnkey”) basis, as well as drilling engineering and drilling project management services, and we participate in oil and gas exploration and production activities, principally in order to facilitate the acquisition of turnkey contracts for our drilling management services operations.

We derive substantially all of our revenues from our contract drilling and drilling management services operations, which depend on the level of drilling activity in offshore oil and natural gas exploration and development markets worldwide. These operations are subject to a number of risks, many of which are outside our control. For a discussion of these risks, see “Item 1A. Risk Factors.”

On May 21, 2004, we completed the sale of our land drilling business to Precision Drilling Corporation for a total sales price of $316.5 million in an all-cash transaction. Our land drilling fleet consisted of 31 rigs, 12 of which were located in Kuwait, eight in Venezuela, four in Saudi Arabia, four in Egypt and three in Oman. Operating results for our land drilling operations had historically been included in contract drilling results. As a result of this sale, however, results of land drilling operations have been excluded from contract drilling results and are reflected in “Income from discontinued operations, net of tax effect” in the consolidated statement of income for the year ended December 31, 2004. For further information regarding our land drilling operations, see “Operating Results—Sale of Land Drilling Fleet (Discontinued Operations).”

Critical Accounting Estimates

Our consolidated financial statements are impacted by the accounting policies used and the estimates and assumptions made by management during their preparation. These estimates and assumptions used in connection with some of these policies affect the carrying values of assets and liabilities and disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the period. Actual results could differ from such estimates and assumptions. We consider our accounting estimates to be critical in areas where both: (1) the nature of the estimates and assumptions used are material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change, and (2) the impact of the estimates and assumptions is material to our operating results or financial condition. Following is a discussion of our critical accounting estimates in the areas of pension costs, properties and depreciation, impairment, income taxes and turnkey drilling costs.

PENSION AND POSTRETIREMENT BENEFIT COSTS

Our pension and postretirement benefit costs and liabilities are actuarially determined based on certain assumptions including expected long-term rates of return on plan assets, rate of increase in future compensation levels and the discount rate used to compute future benefit obligations. Actual results could differ materially from these actuarially determined amounts.

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We use a December 31 measurement date for our pension and postretirement benefit plans. The following assumptions were used to determine our pension and postretirement benefit obligations:

	December 31, 2006				December 31, 2005
	U.S. Plans		U.K. Plans		U.S. Plans		U.K. Plans
Discount rate	5.91	%	5.25	%	5.50	%	5.00	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%

The following weighted average assumptions were used to determine our net periodic pension cost:

	Year Ended December 31,
	2006				2005				2004
	U.S. Plans		U.K. Plans		U.S. Plans		U.K. Plans		U.S. Plans		U.K. Plans
Discount rate	5.50	%	5.00	%	5.75	%	5.25	%	6.25	%	5.50	%
Expected long-term rate of return	8.00	%	8.50	%	8.75	%	8.50	%	9.00	%	9.00	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.50	%	4.25	%

The discount rates used to calculate the net present value of future benefit obligations at December 31, 2006 and 2005, and pension costs for the years ended December 31, 2006, 2005 and 2004, for both our U.S. and U.K. plans are based on the average of current rates earned on long-term bonds that receive a Moody’s rating of Aa or better.

We employ third-party consultants for our U.S. and U.K. plans that use portfolio return models to assess the reasonableness of the assumption for expected long-term rate of return on plan assets. Using asset class return, variance, and correlation assumptions, the models produce distributions of possible returns so that we can review the expected return and each fifth percentile return for the portfolio. The assumptions developed by the consultants are forward-looking and are not developed solely by an examination of historical returns. They take into account historical relationships, but are adjusted by our consultants to reflect expected capital market trends. A building block approach is applied to create a coherent framework between the main economic drivers for the portfolio (namely inflation, yields, bond and equity prices). The model is then used to carry out a projection of possible returns for each asset class, and these are combined based on the investment mix for our pension plans.

Following is a summary of how changes in the assumed discount rate and expected return on assets, assuming all other factors remain unchanged, would affect the net periodic pension and postretirement benefit expense for 2006 and related pension and postretirement benefit obligations as of December 31, 2006:

			Discount Rate				Return on Plan Assets
	2006		+0.25%		-0.25%		+0.25%		-0.25%
	(In millions)
Pension Plans
Net Periodic Pension Cost:
U.S. plans	$	25.4	$	23.2	$	27.6	$	24.6	$	26.2
U.K. plans	$	7.3	$	5.3	$	10.2	$	7.1	$	8.3
Projected Benefit Obligation:
U.S. plans	$	411.8	$	397.4	$	426.7		N/A		N/A
U.K. plans	$	231.8	$	217.1	$	248.0		N/A		N/A
Postretirement Benefit Plan
Postretirement Benefit Expense	$	1.8	$	1.8	$	1.8		N/A		N/A
Accumulated Postretirement Benefit Obligation	$	20.2	$	19.8	$	20.6		N/A		N/A

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As of December 31, 2006, we had an unrecognized actuarial loss totaling $129.3 million and prior service cost totaling $7.0 million for our U.S. and U.K. pension plans. These amounts will be recognized in net periodic pension cost over the estimated remaining service lives of the active participants in the plans. Approximately $8.4 million of the actuarial loss and $2.8 million of the prior service costs are expected to be recognized in 2007.

As of December 31, 2006, we had an unrecognized actuarial loss totaling $4.7 million and a prior service credit totaling $0.7 million for our other postretirement benefit plan. These amounts will be recognized in net periodic pension cost over the estimated remaining service lives of the active participants in the plan. Approximately $0.2 million of the actuarial loss and $0.1 million of the prior service credit are expected to be recognized in 2007. The calculation of our other postretirement benefits costs and liabilities includes the weighted-average annual assumed rate of increase in the per capita cost of covered medical benefits. This assumption is based on data available to management at the time the assumption is made. Actual results could differ materially from estimated amounts.

For further discussion of the components of our net periodic pension cost and postretirement benefit expense and funded status of our pension plans and postretirement benefit plan, see Note 10 of Notes to Consolidated Financial Statements.

PROPERTIES AND DEPRECIATION

Rigs and Drilling Equipment. Capitalized costs of rigs and drilling equipment include all costs incurred in the acquisition of capital assets including allocations of interest costs incurred during periods that assets are under construction and while they are being readied for their initial contract. Expenditures that improve or extend the lives of rigs and drilling equipment are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred. Costs of property sold or retired and the related accumulated depreciation are removed from the accounts; resulting gains or losses are included in income.

Depreciation and amortization. We depreciate our rigs and equipment over their remaining estimated useful lives. Our estimates of these remaining useful lives may be affected by such factors as changing market conditions, technological advances in the industry or changes in regulations governing the industry, among other things. We rely primarily on external sources of information as well as our own internal market data in assessing the impact of these factors on estimates of remaining useful lives. Estimates of remaining useful lives are also impacted by mechanical and structural factors. We review engineering data, operating history, maintenance history and third party inspections to assess useful lives from a structural and mechanical perspective. In determining estimated salvage values, we look primarily to external sources of information as well as our own internal data regarding the values of scrap metal and salvaged equipment. Changes in any of the assumptions made in estimating remaining useful lives and salvage values of our properties and equipment could result not only in increases or decreases in annual depreciation expense, but also could impact our criteria for analyzing properties and equipment for impairment.

We periodically evaluate the remaining useful lives and salvage values of our rigs, giving effect to operating and market conditions and upgrades performed on these rigs. As a result of analyses performed on our drilling fleet, effective January 1, 2004, we increased the remaining lives on certain rigs in our jackup fleet to 13 years from a range of 5.6 to 10.1 years, increased salvage values of these and other rigs in our jackup fleet from $0.5 million per rig to amounts ranging from $1.2 to $3.0 million per rig, and increased the salvage values of our semisubmersibles and certain of our drillships from $1.0 million per rig to amounts ranging from $2.5 to $4.0 million per rig. The effect of these changes in estimates was a reduction to depreciation expense for the year ended December 31, 2004, of approximately $18.3 million.

Impairment of Rigs and Drilling Equipment. We review our long-term assets for impairment when changes in circumstances indicate that the carrying amount of the asset may not be recoverable, in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of

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Long-lived Assets.” SFAS No. 144, among other things, requires that long-lived assets and certain intangibles to be held and used be reported at the lower of carrying amount or fair value and establishes criteria to determine when a long-lived asset is classified as available for sale. Assets to be disposed of and assets not expected to provide any future service potential are recorded at the lower of carrying amount or fair value less cost to sell. We did not incur any impairment charges in 2006 and 2005. We recorded an impairment charge of approximately $1.2 million in the first quarter of 2004 related to the sale of the platform rig Rig 82 for a nominal sum in connection with our exit from the platform rig business.

Our determination of impairment of rigs and drilling equipment, if any, requires estimates of undiscounted future cash flows. Actual impairment charges, if any, are recorded using an estimate of discounted future cash flows. The determination of future cash flows related to our rigs and drilling equipment requires us to estimate dayrates and utilization in future periods, and such estimates can change based on market conditions, technological advances in the industry or changes in regulations governing the industry. Significant changes to the assumptions underlying our current estimates of cash flows could require a provision for impairment in a future period.

INCOME TAXES

We are a Cayman Islands company and we operate through our various subsidiaries in numerous countries throughout the world including the United States. Consequently, our tax provision is based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary substantially. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in different taxing jurisdictions. Current income tax expense represents either liabilities expected to be reflected on our income tax returns for the current year, nonresident withholding taxes, or changes in prior year tax estimates which may result from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reported on the balance sheet. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets and liabilities, as well as of valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, as well as changes in tax laws, could require us to adjust the deferred tax assets and liabilities or valuation allowances, including as discussed below.

Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to the expiration of our NOL carryforwards. We have established a valuation allowance against the future tax benefit of a portion of our NOL carryforwards and could be required to record an additional valuation allowance if market conditions deteriorate and future earnings are below, or are projected to be below, our current estimates.

As of December 31, 2004, $71.6 million of a $76.1 million U.S. NOL was expected to expire unutilized at the end of 2005. As a result, we carried a $71.6 million valuation allowance against the 2005 expiring NOL. Over the course of 2005, U.S. taxable income increased significantly as compared to the 2004 estimate to the extent that only $6.3 million of the 2005 expiring NOL was estimated to expire unutilized at the end of the year. As a consequence, $69.8 million of the U.S. valuation allowance was released which resulted in a $24.9 million U.S. tax benefit in 2005. As of December 31, 2006, all of the remaining valuation allowance related to foreign NOL carryforwards.

We have not provided for U.S. deferred taxes on the unremitted earnings of our U.S. subsidiaries that are permanently reinvested. Should a distribution be made to us from the unremitted earnings of these U.S. subsidiaries, we could be required to record additional U.S. current and deferred taxes.

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For a discussion of the impact of changes in estimates and assumptions affecting our deferred tax assets and liabilities, along with the components of our current and deferred income tax provisions, assets and liabilities, see “Operating Results—Income Taxes” following in this section and Note 11 of Notes To Consolidated Financial Statements.

TURNKEY DRILLING ESTIMATES

Turnkey drilling projects often involve numerous subcontractors and third party vendors, and, as a result, the actual final project cost is typically not known at the time a project is completed. We therefore rely on detailed cost estimates created by our project engineering staff to compute and record profits upon completion of turnkey drilling projects based on known revenues. These cost estimates are adjusted as final actual project costs are determined, which may result in adjustments to previously recorded amounts. Further, we recognize estimated losses on turnkey drilling projects immediately upon occurrence of events which indicate that it is probable that a loss will be incurred and, depending on the timing of the events leading to loss recognition in relation to completion of the project, these cost estimates could be significant relative to the total project costs. For a discussion of the estimated costs recognized as part of our turnkey drilling operations at December 31, 2006, and the impact of revisions to estimated prior period costs on our drilling management services operations, see “Operating Results—Drilling Management Services.”

Current Market Conditions and Trends

Although conditions continue to be strong in all of our markets other than the U.S. Gulf of Mexico jackup market, historically the offshore drilling business has been cyclical, with periods of high demand, inadequate rig supply and increasing dayrates, which have characterized the condition of the market for the last few years, being followed by periods of low demand or excess rig supply, resulting in lower utilization and decreasing dayrates. These cycles have been volatile and have traditionally been influenced by a number of factors, including oil and gas prices, the spending plans of our customers, the highly competitive nature of the offshore drilling industry and the construction of new rigs. Even when rig markets appear to have stabilized at a certain level of utilization and dayrates appear to be improving, these markets can change swiftly, making it difficult to predict trends or conditions in the market. The relocation of rigs from weak markets to stable or strong markets may also have a significant impact on utilization and dayrates in the affected markets. The impact of these cycles and market forces on our results of operations is mitigated in part by our contract drilling backlog which was $10.6 billion at December 31, 2006.

A summary of current industry market conditions and trends in our areas of operations follows:

International

Our current international market outlook for 2007 is that demand for drilling rigs will exceed the available supply, due in part to the high percentage of the industry’s rigs that will remain on long term contracts through the period. This supply-demand imbalance is expected to result in continuing high levels of utilization and strong dayrates for rigs with available rig time. These strong market conditions, which have existed for the past few years, have led to a substantial number of orders being placed with shipyards for the construction of additional rigs by both existing and recently formed drilling contractors.

Newbuilds

Eleven premium jackup newbuild rigs have entered the market since January 1, 2006, and construction is in progress or contracts have been announced for the construction of at least 65 additional premium jackup rigs, an increase in the worldwide premium jackup fleet of approximately 40%. Delivery dates for these newbuild units range from the current year through 2010. In the deepwater and ultra-deepwater rig class, there have been announcements of the upgrade of five semisubmersibles to deepwater or ultra-deepwater capability and the construction of over 50 new high-specification rigs, an increase in the units in this deepwater fleet of

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approximately 50%. Most of these rigs, including our GSF Development Driller III, are ultra-deepwater units and represent an increase in the worldwide ultra-deepwater fleet of approximately 160%. Deliveries for these units are forecast to occur from the first quarter of 2007 through 2010. A number of the shipyard contracts for units currently under construction provide for options for the construction of additional units, and we believe further new construction announcements are likely for all classes of rigs. During prior periods of high utilization and dayrates, the entry into service of newly constructed, upgraded and reactivated rigs created an oversupply of drilling units and a decline in utilization and dayrates, sometimes for extended periods of time as rigs were absorbed into the active fleet. Delivery dates for newbuild units range from the first quarter of 2007 through 2010, when the majority of the newbuild jackups are scheduled for delivery in 2007 and 2008. We expect that the delivery of a number of the newbuild units, primarily the deepwater and ultra-deepwater rigs, will be delayed. Delays will be attributable to numerous factors including: the use of new, untested rig designs; the use of shipyards with little or no experience in building offshore drilling units; delays in the deliveries of equipment; and a shortage of experienced, qualified commissioning personnel. At the present time, we believe that through 2007 demand for rigs is adequate to absorb the new rigs expected to be delivered into the active market without a major impact on industry utilization rates and dayrates. The marketing of the newbuild jackups scheduled for delivery after 2007 could have a negative effect on jackup dayrates, however, even in advance of the rigs’ delivery dates. Further increases in the number of new drilling units under construction could exacerbate any such future negative effect. We expect the market for deepwater and ultra-deepwater rigs is expected to remain in balance through 2010 due to the later delivery dates for this class of rigs, the contracted status of existing rigs and apparent strong demand from customers.

Deepwater and Ultra-Deepwater Market

Virtually all deepwater and ultra-deepwater class units in the industry are contracted through 2008 and customers continue to bring additional deepwater and ultra-deepwater requirements to the market. In some cases, however, customers with rigs under long-term contracts have offered to sublease time to other customers. To the extent excess rig demand cannot be satisfied through rig subleases, projects will have to be deferred until 2009 or later, when a number of ultra-deepwater newbuild units without contracts are scheduled to be delivered. In the fourth quarter of 2006, deepwater and ultra-deepwater rigs were being contracted at dayrates in the $475,000 to $530,000 per day range for work commencing in 2008 and 2009. This market is expected to remain in balance through 2010.

U.S. Gulf of Mexico

Both utilization and dayrates for jackups were soft during the fourth quarter of 2006 and these market conditions have continued into the first quarter of 2007. Although dayrates remain high by historical standards, in early 2007 some jackup rigs in the Gulf of Mexico market were contracted at dayrates substantially lower than those which prevailed in 2006. A number of rigs departed the U.S. Gulf of Mexico during 2006 and early 2007, however, including four of our rigs scheduled to commence long-term contracts offshore Saudi Arabia, reducing the marketed supply of jackup units to 81 by the end of January 2007. There have been announcements of the intended departure of an additional nine rigs during the first half of 2007, which will further reduce the marketed supply of jackups in the U.S. Gulf of Mexico to the low 70’s. Despite this decline in marketed supply, utilization has remained relatively weak since the start of the year as customers have been relatively slow to execute drilling plans. Whether dayrates will increase in the future, signifying an improved balance between supply and demand, will depend in part on customers’ willingness to contract jackups during the hurricane season, which will begin in June.

The U.S. Gulf of Mexico market for semisubmersibles and drillships of all water depth capabilities continues to be strong.

North Sea

We believe that the North Sea market for mid-water depth semisubmersibles, heavy-duty harsh environment (“HDHE”) jackups and standard jackups remains strong, although over the last quarter of 2006 there were

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relatively few new contracts awarded due to the lack of available rigs. Some customers have offered to sublease rig time to other customers during 2007, particularly semisubmersibles, which may indicate that these customers do not have sufficient work to utilize all of their contracted rig days. Some subleases have already been entered into and there appears to be sufficient near term demand from customers to fill these gaps in other customers’ contracts. We have not observed any negative impact on market rates as a result of this subleasing activity. We expect that customers will begin to source rigs for 2008 and beyond during the second and third quarters of 2007 and we believe markets for all classes of rigs will remain strong through 2007.

West Africa

The market for all types of drilling units in West Africa remains tight, with customers continuing to delay some of their programs due to the lack of available drilling units. We expect the West Africa jackup fleet to remain at or above 95% utilization throughout 2007 with dayrates anticipated to remain near or above recent rates.

Deepwater and ultra-deepwater rigs in this market are all fully contracted through 2008, with several projects slated for 2008 and beyond still in need of drilling units. This inadequate supply is expected to lead to mobilization of several of the newbuild ultra-deepwater units to West Africa over the next two to four years. Mid-water depth semisubmersible demand remains strong in the region with all units under contract except for one or two units with available rig time at the end of 2007.

Southeast Asia

The market for jackups in Southeast Asia remains strong. We are forecasting demand to exceed supply for the majority of 2007, supporting current high dayrates. Although there are a large number of jackups under construction in the region, the newbuild units have yet to have a significant impact on the supply – demand imbalance. Recently, however, we have observed an increase in the number of rigs responding to requests for bids from customers which could be an indicator of an imbalance in the future. In view of the relatively low number of heavy-lift vessels available to transport jackups from the shipyards to other areas, we expect that this region will be forced to absorb a high number of the newbuild jackups due to be delivered in 2007 and 2008. This increase in the available units in the region could have a negative effect on dayrates. The deepwater market in the Southeast Asia region, although relatively minor compared to the major deepwater markets in the Gulf of Mexico, West Africa and Brazil, is expected to continue to be strong as customers have announced multiple projects for deepwater units in 2008 and beyond.

Middle East and Mediterranean

Recent contract extensions for jackups in the Mediterranean have created a shortage of rigs in 2007 resulting in a movement of rigs into the area. The deepwater market is also expected to be undersupplied in 2007, due in part to announced development projects in Libya. The Gulf of Suez jackup market continues to be stable. In the Arabian Gulf, we continue to observe strong demand for jackups and stable dayrates.

Canada and South America

Drilling activity in Northeastern Canada will remain constrained by rig supply in 2007, especially in view of the strength of markets elsewhere. In early 2007, we moved our HDHE jackup in the region to the North Sea to fulfill commitments in that market. Our deepwater unit in the region remains under contract into 2008.

We currently have two jackups in the South America market and we will be mobilizing two of our semisubmersible units into the area in 2007 to fulfill contracts in the market. We expect the South America jackup market to remain tight throughout 2007 and the market for deepwater and ultra-deepwater units is expected to continue to strengthen due to the Brazilian national oil company’s aggressive five-year drilling campaign.

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Operating Results

OVERVIEW

Data relating to our operations by business segment follows:

	2006			Increase (Decrease)		2005			Increase (Decrease)		2004
	($ in millions)
Revenues: (1)
Contract drilling	$	2,568.4		54	%	$	1,664.5		40	%	$	1,191.8
Drilling management		752.3		27	%		590.3		11	%		531.5
Oil and gas		53.6		(5	)%		56.7		79	%		31.6
Less: intersegment revenues		(61.7	)	29	%		(48.0	)	54	%		(31.2	)
	$	3,312.6		46	%	$	2,263.5		31	%	$	1,723.7
Operating income: (2)
Contract drilling	$	1,046.4		135	%	$	445.3		274	%	$	119.1
Drilling management		11.6		(63	)%		31.3		367	%		6.7
Oil and gas		27.2		(20	)%		33.9		75	%		19.4
Gain (Loss) on involuntary conversion of long-lived assets, net of related recoveries and loss of hire recoveries		116.5					(6.2	)				24.0
Gain on sale of assets		—					28.0					27.8
Impairment loss on long-lived asset		—					—					(1.2	)
Corporate expenses		(91.9	)	35	%		(67.9	)	10	%		(62.0	)
	$	1,109.8		139	%	$	464.4		247	%	$	133.8

(1) Revenues for each segment, excluding intersegment revenues, is set forth in Note 14 in the notes to our consolidated financial statements.

(2) Excludes intersegment revenues and expenses.

Operating income increased by $645.4 million to $1,109.8 million for the year ended December 31, 2006, from $464.4 million in 2005, due primarily to higher dayrates and utilization, offset in part by lower utilization of the U.S. Gulf of Mexico jackup fleet. In addition, included in “Gain (Loss) on Involuntary conversion of long-lived assets, net of recoveries and loss of hire recoveries” for the year ended December 31, 2006, are gains of $66.9 million as a result of recovery from insurers related to the loss of the cantilevered jackups GSF High Island III and GSF Adriatic VII during Hurricane Rita in September 2005, $28.0 million related to the sale of the GSF Adriatic VII, and $21.6 million in expected recoveries under our loss of hire insurance policy related to the GSF Development Driller I. For further details, see “—Involuntary Conversion of Long-Lived Assets and Related Recoveries.” These increases were offset in part by lower turnkey drilling performance, higher depreciation expense, and an increase in corporate expenses.

Operating income increased by $330.6 million to $464.4 million for the year ended December 31, 2005, from $133.8 million in 2004, due primarily to higher dayrates and utilization for the drilling fleet, better turnkey operating performance, increases in oil production, and a $23.5 million gain related to the sale of the drillship Glomar Robert F. Bauer. These factors were offset in part by higher depreciation and depletion expense, a $10 million loss resulting from the rigs damaged in Hurricane Rita in September 2005 (offset in part by $3.8 million for estimated recoveries from insurers under our loss of hire insurance policy relating to Hurricane Katrina), and the impact of a number of rigs being unable to perform drilling operations as a result of damage sustained during the hurricanes. (See “Involuntary Conversion of Long-Lived Assets and Related Recoveries” for further discussion of the impact of the hurricanes.) Operating income for 2004 includes a $24 million gain recorded from an insurance settlement related to the loss of the GSF Adriatic IV, along with a $25.1 million gain related to the

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sale of a portion of a working interest in the Broom Field development project in the North Sea by our oil and gas division. Operating income for 2005 includes a $4.5 million gain related to deferred consideration earned under that sales agreement.

Sale of Land Drilling Business (Discontinued Operations)

On May 21, 2004, we completed the sale of our land drilling business to Precision Drilling Corporation for a total sales price of $316.5 million in an all-cash transaction. Our land drilling business consisted of a fleet of 31 rigs, 12 of which were located in Kuwait, eight in Venezuela, four in Saudi Arabia, four in Egypt, and three in Oman. As a result of this sale, we recognized a gain of $113.1 million, including a net tax benefit of $1.1 million, in the second quarter of 2004.

The following table lists the contribution of our land rig fleet to our consolidated operating results for the year ended December 31, 2004:

	Year Ended December 31,
	2004
	(In millions)
Revenues	$	43.9
Expenses (income):
Direct operating expenses		27.9
Depreciation		4.0
Exit costs		6.8
Gain on sale of assets		(112.0	)
		117.2
Provision for income taxes, including a net tax benefit of $1.1 in 2004 related to the gain on sale of assets		4.9
Income from discontinued operations, net of tax effect	$	112.3

Gains on Sales of Assets

During the first quarter of 2004, we retired the drillship Glomar Robert F. Bauer from active service. As a result, we accelerated the remaining depreciation on the rig, which resulted in a $1.5 million charge to depreciation expense in the first quarter of 2004. As a result of continued improvements in the offshore drilling markets, we sold this rig in the fourth quarter of 2005 for $25 million and recorded a net gain of $23.5 million. There was no tax impact related to this transaction.

In the first quarter of 2004 we sold our interest in a drilling project in West Africa for approximately $6.1 million and recorded a gain of $2.7 million ($2.0 million net of taxes) in connection with this sale in the first quarter of 2004.

In September 2004, our oil and gas division completed the sale of 50% of its interest in the Broom Field, a development project in the North Sea. We received net proceeds of $35.9 million in connection with the sale and recorded a gain of $25.1 million ($13.3 million net of taxes) in 2004. We retained an eight percent working interest in this project. Pursuant to the terms of the sale, if commodity prices exceeded a specified amount, we were also entitled to additional post-closing consideration equal to a portion of the proceeds from the production attributable to this interest sold through September 2005. In 2005 we recorded an additional gain associated with this deferred consideration arrangement of $4.5 million ($2.7 million net of taxes), which represents the entire deferred consideration earned under the sales agreement.

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Asset Impairments

In April 2004, we sold the platform rig Rig 82 for a nominal sum in connection with our exit from the platform rig business and recognized an impairment loss of approximately $1.2 million in the first quarter of 2004.

CONTRACT DRILLING OPERATIONS

Data with respect to our contract drilling operations follows:

	2006			Increase/ (Decrease)		2005			Increase/ (Decrease)		2004
	($ in millions, except average revenues per day)
Contract drilling revenues by area: (1)
U.S. Gulf of Mexico	$	597.5		83	%	$	325.7		24	%	$	263.7
West Africa		575.7		61	%		356.5		77	%		201.9
North Sea		431.5		50	%		288.0		40	%		205.3
Southeast Asia		316.3		61	%		196.9		25	%		157.6
South America		160.8		22	%		131.5		21	%		109.1
Middle East		159.3		34	%		118.5		35	%		87.8
Mediterranean Sea		145.7		101	%		72.6		19	%		61.2
Other		181.6		4	%		174.8		66	%		105.2
	$	2,568.4		54	%	$	1,664.5		40	%	$	1,191.8
Average marine rig utilization by area:
U.S. Gulf of Mexico		82	%	(15	)%		96	%	1	%		95	%
West Africa		98	%	1	%		97	%	20	%		81	%
North Sea		97	%	9	%		89	%	20	%		74	%
Southeast Asia		100	%	3	%		97	%	11	%		87	%
South America		100	%	—	%		100	%	22	%		82	%
Middle East		99	%	2	%		97	%	8	%		90	%
Mediterranean Sea		99	%	(1	)%		100	%	6	%		94	%
Other		100	%	8	%		93	%	7	%		87	%
Total average rig utilization:		95	%	(1	)%		96	%	12	%		86	%
Average revenues per day: (2)	$	122,600		55	%	$	78,900		24	%	$	63,500

(1) Includes revenue earned from affiliates.

(2) Average revenues per day is the ratio of rig-related contract drilling revenues divided by the aggregate contract days. The calculation of average revenues per day excludes non-rig related revenues, consisting mainly of reimbursed expenses, totaling $82.0 million, $67.4 million, and $32.5 million, respectively, for the years ended 2006, 2005, and 2004. Average revenues per day including these reimbursed expenses would have been $126,700, $82,300 and $65,100 for 2006, 2005 and 2004, respectively. The calculation of average revenues per day excludes all contract drilling revenues related to our platform rig operations, which have historically not been material to our contract drilling operations. We completed our planned exit from our platform rig operations in the first quarter of 2004.

Year Ended December 31, 2006, Compared to Year Ended December 31, 2005

Contract drilling revenues before intersegment eliminations increased by $903.9 million to $2,568.4 million for the year ended December 31, 2006, compared to $1,664.5 million for the year ended December 31, 2005. Higher dayrates and utilization, offset in part by lower utilization of the U.S. Gulf of Mexico jackup fleet, accounted for $776.2 million and $83.4 million, respectively, of this increase and higher other revenues and reimbursable revenues accounted for $29.8 million and $14.5 million, respectively, of the remainder.

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Reimbursable revenues represent reimbursements from customers for certain out-of-pocket expenses incurred and have little or no effect on operating income.

All of our areas of operation saw an increase in dayrates during 2006, with West Africa, the ultra-deepwater and deepwater fleets, North Sea, U.S. Gulf of Mexico, Southeast Asia, and Middle East fleets contributing $192.1 million, $112.0 million, $110.1 million, $103.8 million, $103.6 million, and $58.1 million, respectively, of the increase. The increase in utilization was due primarily to our ultra-deepwater and deepwater drilling fleets, which accounted for $112.4 million of the increase, as a result of the addition of the GSF Development Driller I and GSF Development Driller II to our fleet during the second quarter of 2006 and the fourth quarter of 2005, respectively. These increases were offset in part by a decrease in utilization for the U.S. Gulf of Mexico jackup fleet, a $91.4 million impact, attributable in part to the loss of the GSF Adriatic VII and GSF High Island III cantilevered jackups during Hurricane Rita in September 2005, along with lower utilization of the GSF High Island II, GSF High Island IV, GSF Main Pass I, and GSF Main Pass IV, all of which were idle during the fourth quarter of 2006 as they waited to be transferred to Arabian Gulf for a new contract.

The mobilization of marine rigs between the geographic areas shown below also affected each area’s revenues and utilization noted in the table above. These mobilizations were as follows:

Rig	Rig Type	From	To	Completion Date
GSF Jack Ryan	Drillship	South America	West Africa	Mar-05
GSF Adriatic VII	Cantilevered Jackup	South America	U.S. Gulf of Mexico	Apr-05
GSF Explorer	Drillship	U.S. Gulf of Mexico	Other (Black Sea)	May-05
GSF Arctic I	Semisubmersible	South America	U.S. Gulf of Mexico	Jul-05
GSF Development Driller II	Semisubmersible	Shipyard	U.S. Gulf of Mexico	Nov-05
GSF Aleutian Key	Semisubmersible	West Africa	South America	Dec-05
GSF Explorer	Drillship	Other (Black Sea)	U.S. Gulf of Mexico	Mar-06
GSF High Island IX	Cantilevered Jackup	Middle East	West Africa	Apr-06
GSF Constellation II	Cantilevered Jackup	South America	Mediterranean	May-06
GSF Development Driller I	Semisubmersible	Shipyard	U.S. Gulf of Mexico	Jun-06
GSF Aleutian Key	Semisubmersible	South America	West Africa	Dec-06

Contract drilling operating income and margin excluding intersegment revenues and expenses increased to $1,046.4 million and 41%, respectively, for the year ended December 31, 2006 from $445.3 million and 27%, respectively, for 2005, due primarily to higher rig utilization and dayrates as discussed above, offset in part by higher labor expense, repairs and maintenance expenses, insurance costs, and other operating costs associated with higher utilization throughout our worldwide fleet. Contract drilling depreciation expense also increased for the year ended December 31, 2006 compared to 2005 due primarily to the addition of the GSF Development Driller II and GSF Development Driller I semisubmersibles, which were placed in service during the fourth quarter of 2005 and second quarter of 2006, respectively, and to upgrades on several other rigs in our fleet during 2005.

We expect 2007 contract drilling costs, excluding reimbursable expenses, intersegment expenses and depreciation, to be approximately $1.3 billion. The projected increase over 2006 is due to several of our rigs moving to locations with higher operating costs, labor cost increases, higher insurance costs, and a full year of operations for the GSF Development Driller I, which began operating during June 2006.

Our contract drilling backlog at December 31, 2006, was $10.6 billion, consisting of $9.5 billion related to executed contracts and $1.1 billion related to customer commitments for which contracts had not yet been executed as of January 31, 2007. Approximately $3.2 billion of the backlog is expected to be realized in 2007. Our contract drilling backlog at December 31, 2005, was $4.8 billion.

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Year Ended December 31, 2005, Compared to Year Ended December 31, 2004

Contract drilling revenues before intersegment eliminations increased by $472.7 million to $1,664.5 million for the year ended December 31, 2005, compared to $1,191.8 million for the year ended December 31, 2004. Higher dayrates and utilization for our drilling fleet accounted for $250.5 million and $170.5 million, respectively, of this increase and higher reimbursable and other revenues accounted for $35.0 million and $16.7 million, respectively, of the remainder.

We experienced increases in both dayrates and utilization for most of our fleet with the exception of the GSF Adriatic IV cantilevered jackup which sank offshore Egypt in the third quarter of 2004, the cantilevered jackups GSF High Island II, GSF High Island III and GSF Adriatic VII, all U.S. Gulf of Mexico, which were idle in the fourth quarter of 2005 due to damage sustained from Hurricane Rita, lower utilization for the GSF Explorer drillship, which was in a shipyard during the second quarter of 2005, and the mobilization of the GSF Adriatic VII cantilevered jackup from Trinidad to the U.S. Gulf of Mexico during the second quarter of 2005.

Contract drilling operating income and margin excluding intersegment revenues and expenses increased to $445.3 million and 27%, respectively, for the year ended December 31, 2005 from $119.1 million and 10%, respectively, for 2004, due primarily to higher rig utilization and dayrates as discussed above, offset by higher reimbursable expenses, repairs and maintenance expenses, labor expenses and other operating costs associated with higher utilization throughout our worldwide fleet. Repairs and maintenance expense for 2005 includes approximately $18.7 million related to the reactivation of the GSF Arctic II semisubmersible which had been cold-stacked in the North Sea prior to resumption of operations in September 2005. Contract drilling depreciation expense also increased for the year ended December 31, 2005 compared to 2004 due primarily to the addition of the GSF Constellation II cantilevered jackup, which was placed in service during the third quarter of 2004, and to upgrades on several other rigs in our fleet during 2004.

DRILLING MANAGEMENT SERVICES

Results of operations from our drilling management services segment may be limited by certain factors, including our ability to find and retain qualified personnel, to hire suitable rigs at acceptable rates, and to obtain and successfully perform turnkey drilling contracts based on competitive bids. Our ability to obtain turnkey drilling contracts is largely dependent on the number of such contracts available for bid, which in turn is influenced by market prices for oil and gas, among other factors. Furthermore, our ability to enter into turnkey drilling contracts may be constrained from time to time by the availability of GlobalSantaFe or third-party drilling rigs. The market for drilling rigs was constrained during 2006 due to increased drilling activity worldwide and the number of rigs which have been mobilized to other markets. Drilling management services results are also affected by the required deferral of turnkey drilling profit related to wells in which our oil and gas division is either the operator or holds a working interest. This turnkey profit is credited to our full-cost pool of oil and gas properties and is recognized over future periods through a lower depletion rate as reserves are produced. Accordingly, results of our drilling management service operations may vary widely from quarter to quarter and from year to year.

Year Ended December 31, 2006, Compared to Year Ended December 31, 2005

Drilling management services revenues before intersegment eliminations increased by $162.0 million to $752.3 million for the year ended December 31, 2006, from $590.3 million for 2005. Approximately $117.9 million of this increase was attributable to higher average revenues per turnkey project, $40.2 million was attributable to an increase in daywork and other revenues and $16.3 million was attributed to an increase in reimbursable revenues, offset in part by a $12.4 million decrease due to a decrease in the number of turnkey projects completed. Reimbursable revenues represent reimbursements received from the client for certain out-of-pocket expenses and have little or no effect on operating income. The increase in average revenues per turnkey project is primarily a result of higher contract prices due to increases in dayrates and other drilling costs,

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which have increased due to higher demand for rigs and services in the offshore drilling rig market. We completed 97 turnkey projects in 2006 (70 wells drilled and 27 well completions), compared to 99 turnkey projects in 2005 (80 wells drilled and 19 well completions).

Drilling management services operating income and margin, excluding intersegment revenues and expenses, decreased to $11.6 million and 1.6%, respectively, for the year ended December 31, 2006, from $31.3 million and 5.5%, respectively, in 2005. The decrease in operating results was due primarily to the deferral of $30.4 million of turnkey profit on wells in which our oil and gas division was the operator or had a working interest compared to the deferral of $17.1 million in 2005, along with a decrease in the number of turnkey projects performed in the North Sea during 2006 as a result of less rig availability. Also contributing to the reduction in operation margin were losses totaling approximately $19.7 million on 6 turnkey wells during 2006, including a $14.4 million loss related to one well drilled in 2006. In 2005 we incurred losses totaling approximately $4.3 million on 3 of the 99 turnkey projects completed during 2005.

Subsequent to December 31, 2006, we encountered unforeseen difficulties on one additional turnkey project underway at December 31, 2006. We estimate that we will incur a loss of approximately $2.9 million on this project in the first quarter of 2007.

Turnkey drilling projects often involve numerous subcontractors and third party vendors and, as a result, the actual final project cost is typically not known at the time a project is completed (see “Critical Accounting Policies and Estimates—Turnkey Drilling Estimates”). Results for the years ended December 31, 2006 and 2005, were favorably affected by downward revisions to cost estimates of wells completed in prior years totaling $1.5 million and $2.7 million, respectively, which represented less than 1.0% of drilling management services expenses for each of 2005 and 2004. The effect of these revisions was more than offset, however, by the deferral of turnkey profit totaling $30.4 million in 2006 and $17.1 million in 2005, as noted above, related to wells in which our oil and gas division was either the operator or held a working interest. This turnkey profit has been credited to our full cost pool of oil and gas properties and will be recognized through a lower depletion rate as reserves are produced. Estimated costs included in 2006 drilling management services operating results totaled approximately $68.4 million at December 31, 2006. To the extent that actual costs differ from estimated costs, results in future periods will be affected by revisions to this amount.

As of December 31, 2006, our drilling management services backlog was approximately $114.1 million, all of which is expected to be realized in 2007. Our drilling management services backlog was approximately $23.5 million at December 31, 2005.

Year Ended December 31, 2005, Compared to Year Ended December 31, 2004

Drilling management services revenues before intersegment eliminations increased by $58.8 million to $590.3 million for the year ended December 31, 2005, from $531.5 million for 2004. Approximately $157.5 million of this increase was attributable to higher average revenues per turnkey project and $4.8 million was attributable to an increase in daywork and other revenues, offset in part by an $86.1 million decrease due to a decrease in the number of turnkey projects completed and a $17.4 million decrease in reimbursable revenues. The increase in average revenues per turnkey project is a result of obtaining higher contract prices due to increases in drilling costs, primarily dayrates, which increased due to higher demand in the offshore drilling rig market. This higher demand also limited the availability of drilling rigs, contributing to a decrease in the number of turnkey projects completed compared to prior year. The offshore drilling rig market was further constrained by the number of rigs damaged and destroyed during Hurricane Katrina and Hurricane Rita. The decrease in reimbursable revenues is due primarily to a decrease in project management operations in 2005. As noted above, however, reimbursable revenues represent reimbursements received from the client for certain out-of-pocket expenses and have little or no effect on operating income. We completed 99 turnkey projects in 2005 (80 wells drilled and 19 well completions), compared to 119 turnkey projects in 2004 (89 wells drilled and 30 well completions).

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Drilling management services operating income and margin, excluding intersegment revenues and expenses, increased to $31.3 million and 5.5%, respectively, for the year ended December 31, 2005, from $6.7 million and 1.3%, respectively, in 2004, due primarily to better turnkey performance in 2005. Our turnkey operating results for 2005 included losses totaling $4.3 million on 3 of the 99 turnkey projects completed compared to losses totaling approximately $21.1 million on 14 of our 119 projects completed during the year ended December 31, 2004. We also incurred a loss of $0.9 million in connection with our project management operations during the first quarter of 2004.

Results for the years ended December 31, 2005 and 2004, were favorably affected by downward revisions to cost estimates of wells completed in prior years totaling $2.7 million and $3.3 million, respectively, which represented less than 1.0% of drilling management services expenses for each of 2004 and 2003. The effect of these revisions was more than offset, however, by the deferral of turnkey profit totaling $17.1 million in 2005 and $17.6 million in 2004 related to wells in which our oil and gas division was either the operator or held a working interest. Estimated costs included in 2005 drilling management services operating results totaled approximately $33.7 million at December 31, 2005.

OIL AND GAS OPERATIONS

We acquire interests in oil and gas properties principally in order to facilitate the acquisition of turnkey contracts for our drilling management services operations.

Year Ended December 31, 2006, Compared to Year Ended December 31, 2005

Oil and gas revenues decreased by $3.1 million to $53.6 million for the year ended December 31, 2006 from $56.7 million for 2005. Decreases in oil production, along with a decrease in gas prices accounted for $11.4 million and $0.9 million, respectively, of this decrease, offset in part by an increase of $7.8 million due to higher oil prices and $1.4 million due to higher gas production.

Operating income from our oil and gas operations decreased by $6.7 million to $27.2 million in 2006 from $33.9 million in 2005, due primarily to the decreased revenues discussed above, along with an increase in recognition of stock-based compensation expense as required by SFAS 123(R).

Year Ended December 31, 2005, Compared to Year Ended December 31, 2004

Oil and gas revenues increased by $25.1 million to $56.7 million for the year ended December 31, 2005 from $31.6 million for 2004. Increases in oil production and prices, along with an increase in gas prices accounted for $23.2 million, $3.4 million, and $4.6 million, respectively, of this increase, offset in part by a decrease of $6.1 million due to lower gas volumes produced.

Operating income from our oil and gas operations increased by $14.5 million to $33.9 million in 2005 from $19.4 million in 2004, due primarily to the increased revenues discussed above, offset in part by an increase in depletion and lease operating expenses resulting from increases in oil production.

INVOLUNTARY CONVERSION OF LONG-LIVED ASSETS AND RELATED RECOVERIES

During the third quarter of 2005, a number of our rigs were damaged as a result of hurricanes Katrina and Rita. All these rigs returned to work with the exception of the GSF High Island III and the GSF Adriatic VII. During the second quarter of 2006, we recorded gains of $32.8 million on the GSF High Island III and $30.9 million on the GSF Adriatic VII, which represent expected recoveries of partial losses under our insurance policy, less amounts previously recognized when the rigs were written down to salvage value. These amounts were collected in the third quarter of 2006. In December 2006, we sold the GSF Adriatic VII to a third party for a net purchase price of approximately $29.4 million, net of selling costs, and recorded a gain of $28 million, which

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represents the selling price less the $1.4 million salvage value. In addition, we increased the gain recognized in the second quarter of 2006 related to the GSF Adriatic VII by $3.2 million to include additional costs reimbursable under the insurance policy. Subsequent to December 31, 2006, we entered into a contract to sell the GSF High Island III to a third party for approximately $26.3 million and expect to complete the sale during the first quarter of 2007. We will record a gain equal to the proceeds from the sale, net of expenses, less the rig salvage value of $1.2 million. As of December 31, 2006, we have collected a total of $138.7 million in insurance recoveries and proceeds from the rig sale related to hurricanes Katrina and Rita, including the amounts collected on the GSF High Island III and the GSF Adriatic VII discussed above.

All of the rigs that were damaged in the hurricanes were covered for physical damage under the hull and machinery provision of our insurance policy, which carried a deductible of $10 million per occurrence. In addition, three rigs damaged in Hurricane Katrina, the GSF Arctic I, the GSF Development Driller I, and GSF Development Driller II, were covered by loss of hire insurance under which we are reimbursed for 100 percent of their contracted dayrate for up to a maximum of 270 days following 60 days (the “waiting period”) of lost revenue.

Our insurance policy provided that if claims for a single event are filed under both the hull and machinery and loss of hire sections of the policy, we would bear only a single deductible from that occurrence of no more than the highest deductible from any individual section. Hurricanes Katrina and Rita are each considered to be a separate occurrence. Based on remediations completed for the three rigs covered under the loss of hire insurance, the amount of revenue we lost during the waiting period was higher than the $10 million hull and machinery deductible. Therefore, the 60-day waiting period under our loss of hire insurance will serve as the only deductible for the Hurricane Katrina event. The application of the 60-day waiting period provision with regard to the GSF Development Driller I, the only rig that was still out of service after the 60-day waiting period, is complicated by the fact that at the time of the hurricane, the rig was undergoing thruster remediations and, accordingly, we had already put our underwriters on notice as to a claim under the loss of hire section of the policy. As discussed in Note 6 of Notes to Consolidated Financial Statements—“Commitments and Contingencies,” we recorded $21.6 million for loss of hire recoveries in the first half of 2006 with respect to the GSF Development Driller I. None of the jackup rigs damaged during Hurricane Rita was insured for loss of hire and, therefore, a single $10 million hull and machinery deductible applied for damage to the rigs caused by Hurricane Rita and was recognized as a loss in the third quarter of 2005.

A summary of the effects that the estimates of rig damages and estimated insurance recoveries had on our financial statements for the periods indicated are as follows:

	2005			2006			Cumulative to date
	(In millions)
Amounts affecting income statement:
Effects of estimated rig damage:
Estimated recoveries	$	117.0		$	94.9		$	211.9
Losses recognized		(127.0	)		—			(127.0	)
Net effect of rig damage—gain (loss)		(10.0	)		94.9			84.9
Estimated insurance recoveries—loss of hire		3.8			21.6			25.4
Net pretax gain (loss)	$	(6.2	)	$	116.5		$	110.3
Amounts affecting balance sheet:
Accounts receivable from insurers, balance at beginning of period	$	—		$	120.8		$	—
Additions		120.8			123.6			244.4
Collections		—			(109.3	)		(109.3	)
Accounts receivable from insurers attributable to hurricanes, balance at end of period		120.8			135.1			135.1
Add: Other receivables from insurers, at end of period		2.8			3.8			3.8
Total accounts receivable from insurers, as reported, at end of period	$	123.6		$	138.9		$	138.9

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Additions to accounts receivable from insurers in the table above include additions due to revised estimates of rig damages and anticipated loss of hire recoveries, both of which affected pretax income as shown in the table. Capital costs incurred to remediate damage to the rigs were added to the capitalized value of the rigs. Also included in additions to accounts receivable from insurers for 2006 in the table above are anticipated reimbursements for cash outlays to salvage the GSF High Island III and the GSF Adriatic VII, necessitated by the significant damage suffered by those rigs during Hurricane Rita, which did not affect pretax income, totaling $35.2 million for 2006.

In August 2004, the jackup GSF Adriatic IV encountered well control problems, caught fire and sank while drilling in the Mediterranean Sea off the coast of Egypt. All of our personnel on board the rig were evacuated safely, although the rig was a total loss. We received insurance proceeds totaling $40.0 million, net of our deductible, and recorded a gain of $24.0 million, net of taxes, in the third quarter of 2004.

GENERAL AND ADMINISTRATIVE EXPENSES

General and administrative expenses for the year ended December 31, 2006, increased by $23.8 million to $84.0 million, or 2.5% of revenues, from $60.2 million, or 2.7% of revenues, for 2005. The increase in general and administrative expenses was due primarily due to an increase of $20.0 million in stock-based compensation expense, including the recognition of $15.4 million of stock-based compensation expense as required by the adoption of SFAS 123(R).

General and administrative expenses for the year ended December 31, 2005, increased by $3.7 million to $60.2 million, or 2.7% of revenues, from $56.5 million, or 3.3% of revenues, for 2004. The increase in general and administrative expenses was due primarily to pension expense for two retiring executives, amortization of restricted stock, which was granted to employees in February 2005 and is expensed over a three-year period, and costs associated with training and support for our new enterprise resource management software system, which was placed into service on January 1, 2005, along with costs incurred in connection with the implementation of this system in our foreign offices.

OTHER INCOME AND EXPENSE

Interest expense was $37.0 million for 2006, $41.3 million for 2005 and $55.5 million for 2004. The decrease in interest expense for 2006 was due primarily to the repurchase of the Zero Coupon Convertible Debentures during the second and third quarters of 2005, as discussed below in “Liquidity and Capital Resources—Investing and Financing Activities.” The decrease in interest expense for 2005 was due primarily to the retirement of Global Marine’s 7 ¹/8% Notes due 2007 in the second quarter of 2004 and the repurchase of the Zero Coupon Convertible Debentures during the second and third quarters of 2005.

We capitalized $20.5 million, $38.1 million and $41.0 million of interest costs in 2006, 2005 and 2004, respectively, primarily in connection with our rig expansion program discussed in “Liquidity and Capital Resources—Investing and Financing Activities.”

Interest income increased to $23.5 million for the year ended December 31, 2006, from $22.7 million in 2005, due primarily to an increase in our average rate of return on our investments. Interest income increased to $22.7 million for the year ended December 31, 2005, from $12.3 million in 2004, due primarily to an increase in our average rate of return on our investments.

On June 30, 2004, we completed the redemption of the entire outstanding $300 million principal amount of Global Marine Inc.’s 7 ¹/8% Notes due 2007, for a total redemption price of $331.7 million, plus accrued and unpaid interest of $7.1 million. We recognized a loss on the early retirement of debt of approximately $21.0 million, net of a tax benefit of $11.4 million, in the second quarter of 2004. We funded the redemption price from our existing cash, cash equivalents and marketable securities balances.

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Other income of $1.1 million for the year ended December 31, 2006, consists primarily of earnings in our equity investment in Caspian Drilling Company (see “Items 1. and 2. Joint Venture, Agency and Sponsorship Relationships and Other Investments”). Other income of $2.1 million for the year ended December 31, 2005, consists of realized gains on marketable securities related to our nonqualified pension plans, offset by costs incurred to settle a Canadian tax audit for the years 1998-2001 and expenses incurred to support our employees after hurricanes Katrina and Rita. Other expense of $1.2 million for the year ended December 31, 2004, includes a loss of $3.8 million on a commodity derivative entered into in the first quarter of 2004, offset in part by realized gains of $1.6 million on the sale of marketable securities related to one of our nonqualified pension plans.

INCOME TAXES

Our effective income tax rates for financial reporting purposes were approximately 10%, 13% and 68% for the years ended December 31, 2006, 2005 and 2004, respectively. The effective tax rate for 2006 compared to 2005 decreased due in part to the recognition of a net gain of $94.9 million on the recovery of partial losses under our insurance policy attributable to the GSF Adriatic VII and GSF High Island III and the sale of the GSF Adriatic VII to a third party with no corresponding tax expense for financial reporting purposes. The 2006 effective tax rate also benefited from certain changes in our legal structure. Our drilling rigs operating in Egypt are now owned and operated by a subsidiary licensed by the Egyptian Free-Zone authority that is subject to a zero percent corporate income tax rate. Additionally, a subsidiary restructuring completed in the fourth quarter of 2006 resulted in additional tax benefits related to interest expense deductions on intercompany debt. The new corporate structure eventually should facilitate the movement of cash out of some of our significant operating subsidiaries at a lower tax cost.

The 2005 effective tax of 13% is lower than 2004 due primarily to a change in our mix of earnings between domestic earnings and foreign earnings with foreign earnings in low tax jurisdictions increasing disproportionably higher than the increase in domestic earnings. Foreign earnings included a $23.5 million book gain in the sale of the drilling rig Glomar Robert F. Bauer that was subject to a zero percent tax rate. The increase in U.S. taxable income in 2005 resulted in the utilization of $71.6 million of an expiring U.S. NOL. The utilization of this portion of the NOL triggered the release of a previously recorded valuation allowance and the recognition of a $24.9 million tax benefit. The 2005 effective tax rate was further reduced due to lower statutory tax rates in various foreign jurisdictions and a net tax benefit from the resolution of tax audits and tax return filings at amounts lower than had been previously estimated. The effective rate for 2004 includes the effect of a $42.5 million charge related to the subsidiary realignment discussed below. Excluding the $42.5 million charge, our income tax expense would have been $24.1 million, which when compared to our pretax income from continuing operations of $98.0 million, yields an effective tax rate of 25% for 2004.

In December 2004, we completed a realignment of our subsidiaries to separate our international and domestic holding companies to improve operational and financial efficiencies within our organization. This realignment included the redemption of a minority interest in a foreign subsidiary held by one of our U.S. subsidiaries, along with the intercompany sale of certain rigs between U.S. and foreign subsidiaries based upon current projections of the long-term geographic areas of operations of these rigs. These transactions generated a U.S. taxable gain which resulted in a total tax expense of approximately $135.0 million. This expense was reduced in part by the recognition of $77.4 million of tax benefits resulting from the release of valuation allowances previously recorded against a portion of our U.S. NOL carryforwards, the recognition of a $6.8 million tax benefit from the release of deferred tax liabilities and the deferral of $8.3 million of tax expense related to the gain on the intercompany rig sales. This net deferred tax benefit will be recognized for financial reporting purposes over the remaining useful lives of the rigs. The total tax expense recognized for financial reporting purposes was $42.5 million, comprised of $37.4 million of deferred tax expense and $5.1 million of current tax expense.

In connection with an audit of the 2002 and 2003 United States federal income tax returns of our United States subsidiaries, the Internal Revenue Service (“IRS”) has proposed that interest payments made from one of

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our domestic subsidiaries to one of our foreign subsidiaries with respect to certain notes issued in connection with the business combination of Global Marine Inc. and Santa Fe International Corporation were subject to withholding of United States federal income tax at a 30% rate and that, as a result, the domestic subsidiary owes additional tax of approximately $50.6 million plus interest. The IRS may also raise the same issue for interest payments made pursuant to such notes in 2004 through 2006, which would result in proposed adjustments of additional tax of approximately $25.3 million, plus interest, per year. We believe that a 0% withholding tax rate applies to such interest payments. We have protested the adjustment proposed in the revenue agent’s report and are awaiting an appeal conference. We intend to vigorously defend our position. We believe that we should prevail on this issue; consequently, we have made no accrual for this proposed adjustment.

We intend to permanently reinvest all of the unremitted earnings of our U.S. subsidiaries in their businesses. As a result, we have not provided for U.S. deferred taxes on $722.3 million of cumulative unremitted earnings at December 31, 2006. Should a distribution be made to us from the unremitted earnings of our U.S. subsidiaries, we could be required to record additional U.S. current and deferred taxes. It is not practicable to estimate the amount of deferred tax liability associated with these unremitted earnings.

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a comprehensive model for how companies should recognize, measure, present, and disclose in their financial statements uncertain tax positions taken or expected to be taken on a tax return. Tax law is subject to varied interpretation, and whether a tax position will ultimately be sustained may be uncertain. Under FIN 48, tax positions shall initially be recognized in the financial statements when it is more likely than not the position will be sustained upon examination by the tax authorities. Such tax positions shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority assuming full knowledge of the position and all relevant facts. FIN 48 also requires additional disclosures about unrecognized tax benefits associated with uncertain income tax positions and a reconciliation of the change in the unrecognized benefit. In addition, FIN 48 requires interest to be recognized on the full amount of deferred benefits for uncertain tax positions. An income tax penalty is recognized as expense when the tax position does not meet the minimum statutory threshold to avoid the imposition of a penalty. The provisions of this interpretation are required to be adopted for fiscal periods beginning after December 15, 2006. We will be required to apply the provisions of FIN 48 to all tax positions upon initial adoption with any cumulative effect adjustment to be recognized as an adjustment to retained earnings. Upon adoption, management estimates that a cumulative effect adjustment of approximately $8 million to $17 million will be charged to retained earnings to increase reserves for uncertain tax positions. This range is subject to revision as management completes its analysis.

TRANSACTIONS WITH AFFILIATES

Until December 2005, Kuwait Petroleum Corporation, through its wholly owned subsidiary, SFIC Holdings (Cayman), Inc., owned a portion of our outstanding shares. At December 31, 2004, Kuwait Petroleum Corporation held 43,500,000 ordinary shares, approximately 18.4% of our ordinary shares. During 2005, we repurchased all 43,500,000 ordinary shares from Kuwait Petroleum Corporation with the net proceeds of public offerings of an equal number of ordinary shares, as described under “Liquidity and Capital Resources—Investing and Financing Activities.” Kuwait Petroleum Corporation’s ownership interest had entitled it to certain rights pursuant to an intercompany agreement entered into with Santa Fe International in connection with the initial public offering of Santa Fe International and amended in connection with the merger of Global Marine with a wholly-owned subsidiary of Santa Fe International.

During 2006 we terminated our agency agreement with a subsidiary of Kuwait Petroleum Corporation that obligated us to pay certain agency fees in return for their sponsorship that allowed us to operate in Kuwait. During the years ended December 31, 2006 and 2005, we paid $17,000 and $34,000, respectively, in fees pursuant to the agency agreement. We did not earn any revenues from Kuwait Oil Company, K.S.C. (“KOC”), an affiliate of Kuwait Petroleum Corporation, or its affiliate during 2006 and 2005. During the year ended

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December 31, 2004, we earned revenues from KOC and its affiliate for performing land contract drilling services in the ordinary course of business totaling $20.5 million and paid $211,000 of agency fees pursuant to the agency agreement. At December 31, 2005, we had accounts receivable from affiliates of Kuwait Petroleum Corporation of $0.1 million. There were no outstanding receivables as of December 31, 2006.

Liquidity and Capital Resources

SOURCES OF LIQUIDITY

Our primary sources of liquidity are our cash and cash equivalents, marketable securities and cash generated from operations. As of December 31, 2006, we had $348.9 million of cash, cash equivalents and marketable securities, all of which were unrestricted. We had $837.3 million in cash, cash equivalents and marketable securities at December 31, 2005, all of which were unrestricted. Cash generated from operating activities totaled $985.4 million, $591.2 million and $224.8 million for the years ended December 31, 2006, 2005 and 2004, respectively.

During the third quarter of 2005, the GSF High Island III and the GSF Adriatic VII were damaged as a result of Hurricane Rita. During the second quarter of 2006, we declared both rigs as partial losses under our insurance policy and collected $86.5 million from out underwriters during the third quarter of 2006. In December 2006, we sold the GSF Adriatic VII to a third party for a net selling price of approximately $29.4 million. The net proceeds from this sale were collected in December 2006.

Subsequent to December 31, 2006, we entered into a contract to sell the GSF High Island III for approximately $26.3 million. The sale is expected to be completed during the first quarter of 2007.

We do not expect the loss of these rigs to have a material adverse effect on our results of operations in future periods (see—“Involuntary Conversion of Long-lived Assets and Related Recoveries”).

During the second quarter of 2006, we executed a contract with a major oil and gas company for a seven-year contract for the GSF Development Driller III, providing for expected revenues of approximately $1 billion.

We also entered into a contract with Saudi Aramco to provide four cantilevered jackup rigs for four-year terms commencing in the first half of 2007. The four rigs, the GSF Main Pass I, GSF Main Pass IV, GSF High Island II and GSF High Island IV, began mobilizing in the fourth quarter of 2006 from the U.S. Gulf of Mexico to a Middle East shipyard for approximately 60 days of upgrades. The rigs will then move to their drilling locations offshore Saudi Arabia, with contract commencement expected in March and April 2007. This contract provides for expected revenues of approximately $1 billion.

INVESTING AND FINANCING ACTIVITIES

In the first quarter of 2006, we entered into a contract with Keppel FELS, a shipyard located in Singapore, for construction of a new ultra-deepwater semisubmersible, to be named the GSF Development Driller III. Construction costs for the GSF Development Driller III are expected to total approximately $590 million, excluding capital spares, startup costs, capitalized interest, customer-required modifications and mobilization costs. We have incurred a total of approximately $220 million of capitalized costs related to the GSF Development Driller III, excluding capitalized interest, as of December 31, 2006. We expect to fund all construction and startup costs of the GSF Development Driller III from our existing cash and cash equivalents balances and future cash flow from operations.

During the second quarter of 2005, we discovered a defect and resulting damage in the thruster nozzles on our two new ultra-deepwater semisubmersibles, the GSF Development Driller I and GSF Development Driller II. We currently expect that the cost to remediate the thruster equipment for both rigs will be approximately $54 million. Both rigs were being remediated for the thruster defect and resulting damage when they sustained additional damage as a result of Hurricane Katrina. This additional damage further delayed the start of the initial drilling contracts for the GSF Development Driller I and the GSF Development Driller II. Remediations of the

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GSF Development Driller II were completed and the rig went on contract in November 2005. The thruster defect and damage from Hurricane Katrina further delayed the start of the initial drilling contract for the GSF Development Driller I until June 2006.

We have made claims under our hull and machinery and loss of hire insurance for the GSF Development Driller I and GSF Development Driller II for the periods required to remediate the damage arising from both the thruster defect and Hurricane Katrina. Under our loss of hire insurance, we are entitled to reimbursement for our full dayrate for up to 270 days after a 60-day waiting period. Significant unresolved issues remain as to the proper application of the loss of hire waiting period, which could lead to substantial differences in the amount of the loss of hire recovery. The underwriters have formally reserved their rights to decline coverage for the thruster damage claims on the rigs in respect of both the hull and machinery and loss of hire coverage. As of December 31, 2006, we have recorded estimated loss of hire insurance recoveries equal to $25.4 million ($3.8 million in 2005 and $21.6 million in 2006) with respect to the GSF Development Driller I, which is the amount we deem to be probable under the assumption that the rig will bear two consecutive 60-day waiting periods, one for the thruster damage claim and one for the hurricane damage claim. The GSF Development Driller II was not out of service longer than the combined 120-day waiting period and therefore no loss of hire recoveries have been recorded for this rig. When the loss of hire claims are resolved with the underwriters, the amount of loss of hire recoveries could be different than the amount currently recorded.

We expect to fund any costs incurred associated with remediating the rigs, to the extent they are not recovered from the insurance underwriters, from our existing cash, cash equivalents and marketable securities balances and future cash flow from operations.

During 2005, we issued a total of 43,500,000 ordinary shares in two public offerings and in each case immediately used the net proceeds to repurchase an equal number of our ordinary shares from a subsidiary of Kuwait Petroleum Corporation at a price per share equal to the net proceeds per share we received in the offering. The first offering was in April 2005, in which we issued 23,500,000 ordinary shares at an aggregate price, net of underwriting discount, of approximately $799.5 million ($34.02 per share). The second offering was in December 2005, in which we issued 20,000,000 ordinary shares at an aggregate price, net of underwriting discount, of approximately $977.1 million ($48.86 per share). In connection with these transactions, we incurred a total of $0.9 million of expenses, which were recorded as a reduction of additional paid in capital. There was no change in the number of outstanding shares as a result of the two transactions as the shares repurchased were immediately cancelled.

During the second quarter of 2005, we repurchased $599.2 million principal amount at maturity of the then outstanding $600 million principal amount of Global Marine Inc.’s Zero Coupon Convertible Debentures due September 23, 2020 for a total purchase price of $356.1 million, representing $299.8 million in principal payment and $56.3 million in imputed interest. On August 18, 2005, we redeemed the remaining $800,000 principal amount at maturity, bringing the total repurchase price of $356.6 million, representing $300.3 million in principal payment and $56.3 million in imputed interest. We purchased all of the debentures for repurchase at a purchase price of $594.25 per $1,000 of principal amount, plus additional imputed interest for all securities purchased after June 23, 2005, calculated from June 23, 2005 to the date of purchase. We funded the repurchase price from our existing cash, cash equivalents and marketable securities balances.

Our debt to capitalization ratio, calculated as the ratio of total debt, including undefeased capitalized lease obligations, to the sum of total shareholders’ equity and total debt, was 11.8% at December 31, 2006, compared to 10.5% at December 31, 2005. Our total debt includes the current portion of our capitalized lease obligations, which totaled $9.3 million at December 31, 2006 and $9.8 million at December 31, 2005.

FUTURE CASH REQUIREMENTS

At December 31, 2006, we had total long-term debt and capital lease obligations, including the current portion of our capital lease obligations, of $648.6 million and shareholders’ equity of 4,847.1 million. Long-term

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debt, including current maturities, consisted of $297.3 million (net of discount) 7% Notes due 2028; $251.6 million (net of discount) 5% Notes due 2013; $75.0 million outstanding under our revolving credit facility discussed below; and capitalized lease obligations, including the current portion, totaling $24.7 million. We were in compliance with our debt covenants at December 31, 2006.

In August 2006, we entered into a commitment for a five-year $500 million unsecured revolving credit facility with a syndicate of banks. The facility contains customary covenants, including a debt to total tangible capitalization covenant. Our borrowings under the facility will be guaranteed by one of our wholly owned subsidiaries after the time, if any, that the aggregate principal amount of outstanding indebtedness of our subsidiaries, subject to certain exceptions, exceeds ten percent of our consolidated net assets. Borrowings under the facility will be used for general corporate purposes. As of December 31, 2006, there was $75 million outstanding under the facility.

Annual interest on the 7% Notes is $21.0 million, payable semiannually each June and December. Annual interest on the 5% Notes is $12.5 million, payable semiannually each February and August. No principal payments are due under the 7% Notes or the 5% Notes until the maturity date. Interest on the revolving credit facility is based on the applicable LIBOR rate, plus an applicable margin, for the period of each borrowing.

We may redeem the 7% Notes and the 5% Notes in whole at any time, or in part from time to time, at a price equal to 100% of the principal amount thereof plus accrued interest, if any, to the date of redemption, plus a premium, if any, relating to the then-prevailing Treasury Yield and the remaining life of the notes. The indentures relating to the 5% Notes and the 7% Notes contain limitations on our ability to incur indebtedness for borrowed money secured by certain liens and on our ability to engage in certain sale/leaseback transactions. The 7% Notes continue to be an obligation of Global Marine Inc., and GlobalSantaFe Corporation has not guaranteed this obligation. GlobalSantaFe Corporation is the sole obligor under the 5% Notes.

Total capital expenditures for 2007 are currently estimated to be approximately $708 million, including $163 million in construction costs for the GSF Development Driller III, $198 million for major upgrades to the fleet, including $88 million relating to the four rigs we are moving to Saudi Arabia, $242 million for other purchases and replacements of capital equipment, $19 million for capitalized interest, and $86 million (net of intersegment eliminations) for oil and gas operations.

We expect capital costs for our oil and gas segment to increase from 2006 due primarily to an increase in development costs for existing properties, along with an increase in the number of projects, including a number of foreign projects.

On March 3, 2006, our Board of Directors authorized us to repurchase up to $2 billion of our ordinary shares from time to time. Through February 28, 2007, we had repurchased $1,085.1 million of our ordinary shares under this plan, $1,068.6 million of which were repurchased during 2006.

Our funding objective with regard to our defined benefit pension plans is to fund participants’ benefits under the plans as they accrue. We contributed $57.6 million and $6.4 million to our U.S. defined benefit plans in January 2006 and September 2006, respectively. We also made a discretionary contribution of $51.5 million to our U.K. plan in December 2006. Subsequent to December 31, 2006, we contributed $8.0 million to our U.S. defined benefit plans. Any additional funding to our plans will be evaluated based on our 2007 actuarial analysis.

We have various commitments primarily related to our debt and capital lease obligations, leases for office space and other property and equipment as well as a commitment for construction of the GSF Development Driller III. We expect to fund these commitments from our existing cash and cash equivalents and future cash flow from operations.

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The following table summarizes our contractual obligations at December 31, 2006:

	Payments Due by Period
Contractual Obligation	Total		Less than 1 Year		1-3 Years		4-5 Years		After 5 Years
	(In millions)
Principal payments on long-term debt (1)	$	625.0	$	75.0	$	—	$	—	$	550.0
Interest payments		532.8		33.5		67.0		67.0		365.3
Capital lease obligations (2)		42.8		9.3		3.6		3.6		26.3
Non-cancelable operating leases		29.5		10.8		12.7		3.2		2.8
Construction and development commitments (3)		371.2		190.0		181.2		—		—
Total contractual obligations	$	1,601.3	$	318.6	$	264.5	$	73.8	$	944.4

(1) Represents cash payments required. Long-term debt, including current maturities, totaled $623.9 million, net of unamortized discount, at December 31, 2006.

(2) Represents cash payments required. A portion of these obligations is recorded on our balance sheet at net present value at December 31, 2006.

(3) Consists of construction cost commitments related to the remaining newbuild construction, exclusive of any capital spares, startup costs, capitalized interest, customer-required modifications and mobilization costs.

As part of our goal of enhancing long-term shareholder value, we continually consider and from time to time actively pursue business combinations, the acquisition or construction of suitable additional drilling rigs and other assets or the possible sale of existing assets. If we decide to undertake a business combination or an acquisition or additional construction projects, the issuance of additional debt or additional shares could be required. We expect that sometime in the future we will likely replace the jackups GSF Adriatic IV, which was lost in a fire, and the GSF High Island III and GSF Adriatic VII, which were damaged by Hurricane Rita, through the acquisition or construction of replacement assets. We frequently bid for or negotiate with customers regarding multi-year drilling contracts, including, from time to time, contracts that would necessitate the construction of a new drilling rig to fulfill the contract. Our current strategy is to consider construction of a new floating rig only when expected cash flows from the anticipated contract would cover a substantial portion of the capital cost of the rig.

We believe that we will be able to meet all of our current obligations, including working capital requirements, capital expenditures, lease obligations, construction and development commitments and debt service, from our existing cash, cash equivalents and total marketable securities balances, along with future cash flow from operations.

RECENT ACCOUNTING PRONOUNCEMENTS

In June 2006, the Financial Accounting Standards Boards (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 will be effective for fiscal years beginning after December 15, 2006. Please see Note 11 of Notes to the Consolidated Financial Statements for a description of the pronouncement and the effects on our results of operations and financial position.

ADOPTION OF NEW ACCOUNTING PRONOUNCEMENTS

Effective January 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), Share-Based Payment. Please see Note 9 of Notes to the Consolidated Financial Statements for a description of the pronouncement and the effects on our results of operations and financial position.

In September 2006 the FASB issued SFAS No. 157, Fair Value Measurements. This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and

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expands disclosures about fair value measurements. This statement applies under other accounting pronouncements that require or permit fair value measurements and, accordingly, this statement does not require any new fair value measurements. We do not expect the adoption of this statement to have a material impact on our results of operations, financial position or cash flows.

In September 2006, the FASB also issued Statement SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This statement amends SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and For Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and other related accounting literature. We adopted SFAS No. 158 effective December 31, 2006. Please see Note 10 of Notes to the Consolidated Financial Statements for a description of the pronouncement and the effects on our results of operations and financial position.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

In 1998, we entered into fixed-price contracts for the construction of two dynamically positioned, ultra-deepwater drillships, the GSF C.R. Luigs and the GSF Jack Ryan, which began operating in April and December 2000, respectively. Pursuant to two 20-year capital lease agreements, we subsequently novated the construction contracts for the drillships to two financial institutions (the “Lessors”), which owned the drillships and leased them to us. We deposited with three large foreign banks (the “Payment Banks”) amounts equal to the progress payments that the Lessors were required to make under the construction contracts, less a lease benefit of approximately $62 million (the “Defeasance Payment”). In exchange for the deposits, the Payment Banks assumed liability for making rental payments required under the leases and the Lessors legally released us as the primary obligor of such rental payments. Accordingly, we recorded no capital lease obligations on our balance sheet with respect to the two drillships.

In October 2005, we provided consent to the sale of the Lessor of the GSF C.R. Luigs from one large foreign bank to another. In exchange for our consent, we became entitled to receive consideration, which would equal any sum we were obligated to pay on our termination of the lease, if we exercised our right to terminate the lease between March 1, 2006 and December 31, 2006. In June 2006, we terminated the lease on the GSF C.R. Luigs and purchased the vessel. In addition to receiving the consideration equal to the sum we were obligated to pay on termination of the lease, we received, as a rebate of rentals, an amount equal to the sales price paid by us and a refund of a $0.8 million interest payment we were required to make in March 2006 related to interest rate risk in connection with this lease. Accordingly, we decreased the carrying value of the rig by the $0.8 million. Other than the $0.8 million decrease, there was no other impact to the carrying value of the rig. We now have title to the rig and no longer bear any interest rate risk associated with this lease.

We continue to have interest rate risk in connection with the fully defeased financing lease for the GSF Jack Ryan. The Defeasance Payment earns interest based on the British Pound Sterling three-month LIBOR, which approximated 8.00% at the time of the agreement. Should the Defeasance Payment earn less than the assumed 8.00% rate of interest, we will be required to make additional payments as necessary to augment the annual payments made by the Payment Banks pursuant to the agreements. If the December 31, 2006, LIBOR rate of 5.3% were to continue over the next seven years, we would be required to fund an additional estimated $17.3 million for the GSF Jack Ryan during that period. Any additional payments made by us pursuant to the financing lease would increase the carrying value of our leasehold interest in the GSF Jack Ryan and therefore be reflected in higher depreciation expense over its then-remaining useful life. We do not expect that, if required, any additional payments made under this lease would be material to our financial position, results of operations or cash flows in any given year.

In addition to these defeased financing leases, we also have entered into fixed-for-floating interest rate swaps with a total notional amount of $175 million as of both December 31, 2006 and 2005, effectively converting a portion of our 5% Notes into variable-rate debt (see “Fair Value Risk” below). We do not consider our exposure to interest rate fluctuations as a result of these swaps to be material to our financial position, results of operations or cash flows.

FAIR VALUE RISK

Investments. The objectives of our investment strategy are safety of principal, liquidity maintenance, yield maximization and full investment of all available funds. As a result, the portion of our short-term investments portfolio classified as cash and cash equivalents at December 31, 2006, consisted primarily of high credit quality commercial paper, U.S. Government Agency securities and money market funds, all with original maturities of less than three months. We believe that the carrying value of these investments approximated market value at December 31, 2006, due to the short-term nature of these instruments.

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We have outsourced the management of portions of our marketable securities portfolio to third party investment firms. These firms manage the investment of these securities with the goal of optimizing returns on these investments while investing within guidelines set forth by our management. Pursuant to the requirements of Statement of Financial Accounting Standards No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” we have classified our marketable securities portfolio as available-for-sale, and have recorded these marketable securities at fair value on our Consolidated Balance Sheet at December 31, 2006 and 2005. In addition, in connection with certain nonqualified pension plans, we held other investments in debt and equity securities also classified as available-for-sale, which were included in “Other assets” at December 31, 2006 and 2005. Unrealized gains included in Accumulated Other Comprehensive Income on the Consolidated Balance Sheet at December 31, 2006 and 2005, related to our total marketable securities portfolio totaled approximately $1.5 million and $0.5 million, respectively. Due to the short-term maturities of our investments in our marketable securities portfolio, we do not believe that we have a material fair value risk associated with changes in interest rates.

Long-term debt. Our long-term debt is subject to fair value risk due to changes in market interest rates.

The estimated fair value of our $300 million principal amount 7% Notes due 2028, based on quoted market prices, was $327.4 million at December 31, 2006, compared to the carrying amount of $297.3 million (net of discount). The estimated fair value of our $250 million principal amount 5% Notes due 2013, based on quoted market prices, was $238.0 million at December 31, 2006, compared to the carrying amount of $251.6 million (net of discount). The carrying value of our 5% Notes due 2013 includes a mark-to-market adjustment of $2.1 million at December 31, 2006, related to fixed-for-floating interest rate swaps discussed below. Due to the short-term nature of our borrowings under our $500 million unsecured revolving credit facility, the estimated fair value of our outstanding borrowings at December 31, 2006 equaled the carrying amount of $75 million.

The estimated fair value of our 7% Notes due 2028, based on quoted market prices, was $351.1 million at December 31, 2005, compared to the carrying amount of $297.1 million (net of discount). The estimated fair market value of our 5% Notes due 2013, based on quoted market prices, was $248.3 million at December 31, 2005, compared to the carrying amount of $253.5 million (net of discount). The carrying value of our 5% Notes due 2013 included a mark-to-market adjustment of $4.0 million at December 31, 2005, related to fixed-for-floating interest rate swaps discussed below.

We have engaged third-party consultants to assess the impact of changes in interest rates on the fair values of our long-term debt based on a hypothetical ten-percent increase in market interest rates. Market interest rate volatility is dependent on many factors that are impossible to forecast, and actual interest rate increases could be more severe than the hypothetical ten-percent change.

Based upon these sensitivity analyses, if prevailing market interest rates had been ten percent higher at December 31, 2006, and all other factors affecting our debt remained the same, the fair value of our 7% Notes due 2028, as determined on a present-value basis using prevailing market interest rates, would have decreased by $17.3 million or 5.3% and the fair value of the 5% Notes due 2013 would have decreased by $7.2 million or 3.0%. Under comparable sensitivity analysis as of December 31, 2005, the fair value of the 7% Notes due 2028 would have decreased by $22.6 million or 6.4% and the fair value of the 5% Notes due 2013 would have decreased by $7.3 million or 2.9%.

We manage our fair value risk related to our long-term debt by using interest rate swaps to convert a portion of our fixed-rate debt into variable-rate debt. Under these interest rate swaps, we agree with other parties to exchange, at specified intervals, the difference between the fixed-rate and floating-rate amounts, calculated by reference to an agreed-upon notional amount.

As of December 31, 2006 and 2005, we had outstanding fixed-for-floating interest rate swaps with an aggregate notional amount of $175 million, through February 2013. These interest rate swaps are intended to

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manage a portion of the fair value risk related to our 5% Notes due 2013 (the “5% Notes”). Under the terms of these swaps, we have agreed to pay the counterparties an interest rate equal to the six-month LIBOR rate less 0.247% to 0.5175% on the notional amounts and we will receive the fixed 5.00% rate. The total estimated aggregate fair value of these swaps at December 31, 2006 and 2005 was an asset of $2.1 million and $4.0 million, respectively.

The change in the estimated fair values of our long-term debt from 2005 to 2006 is a result of changes in the market interest rate for new bonds with similar risk ratings. The change in the corresponding interest rate swaps from 2005 to 2006 is a result of changes in the 6 month LIBOR and 10-year Treasury bond rates.

In connection with the sensitivity analyses performed relative to the fair values of our long-term debt discussed above, similar analyses were performed to assess the impact of market interest rate movements on the fair values of the fixed-for-floating swaps related to the 5% Notes. Based upon these analyses, if prevailing market interest rates had been ten percent higher at December 31, 2006, and all other factors affecting these swaps had remained the same, the aggregate fair value of the fixed-for-floating interest rate swaps, as determined on a present-value basis using prevailing market interest rates, would have decreased by $4.6 million or 225%. Under comparable sensitivity analysis as of December 31, 2005, the fair value would have decreased by $5.5 million or 120%.

FOREIGN CURRENCY RISK

We are subject to foreign currency risk throughout our international operations (see “Item 1A. Risk Factors—We May Suffer Losses as a Result of Foreign Exchange Restrictions, Foreign Currency Fluctuations and Limitations on Our Ability to Repatriate Income or Capital to the U.S.”). In certain cases we attempt to minimize this currency risk by seeking international drilling contracts payable in local currency in amounts that approximate our estimated local currency-based operating costs and in U.S. dollars for the balance of the contract. We incurred foreign currency exchange losses totaling approximately $0.9 million in 2006, $2.3 million in 2005 and $6.1 million in 2004. Due to the multiple foreign currencies impacting our various areas of operations, we cannot accurately quantify through a sensitivity analysis the impact of changes in these currencies. We have not historically entered into financial hedging transactions to manage risks relating to fluctuations in currency exchange rates. We may, however, enter into such transactions in the future.

CREDIT RISK

The market for our services and products is the offshore oil and gas industry, and our customers consist primarily of major integrated international oil companies and independent oil and gas producers. We perform ongoing credit evaluations of our customers and have not historically required material collateral. We maintain reserves for potential credit losses, and such losses have been within management’s expectations.

Our cash deposits were distributed among various banks in our areas of operations throughout the world as of December 31, 2006 and 2005. In addition, we utilize external money managers to invest excess cash in accordance with our investment guidelines. These managers have invested our funds in commercial paper, money market funds, asset-backed securities, government issues and corporate obligations. Each of these investments complies with our investment guidelines in terms of security type, credit rating, duration, portfolio and issuer exposure limits. As a result, we believe that credit risk in such instruments is minimal.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of GlobalSantaFe Corporation

We have completed integrated audits of GlobalSantaFe Corporation’s 2006, 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2006 in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income and other comprehensive income, shareholders’ equity and cash flows present fairly, in all material respects, the financial position of GlobalSantaFe Corporation and its subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 9 to the consolidated financial statements, the Company changed the method in which it accounts for share-based compensation effective January 1, 2006. As discussed in Note 10 to the consolidated financial statements, the Company changed the method in which it accounts for defined benefit pension and other postretirement plans effective December 31, 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in “Management’s Report on Internal Control Over Financial Reporting” appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in

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accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2007

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

($ in millions, except per share amounts)

	Year Ended December 31,
	2006			2005			2004
Revenues:
Contract drilling	$	2,540.2		$	1,640.2		$	1,176.9
Drilling management services		718.8			566.6			515.2
Oil and gas		53.6			56.7			31.6
Total revenues		3,312.6			2,263.5			1,723.7
Expenses and other operating items:
Contract drilling		1,206.3			935.3			811.5
Drilling management services		707.2			535.3			508.5
Oil and gas		17.1			14.8			7.2
Depreciation, depletion and amortization		304.7			275.3			256.8
Involuntary conversion of long-lived assets, net of related recoveries and loss of hire recoveries		(116.5	)		6.2			(24.0	)
Gain on sale of assets		—			(28.0	)		(27.8	)
Impairment loss on long-lived assets		—			—			1.2
General and administrative		84.0			60.2			56.5
Total expenses and other operating items		2,202.8			1,799.1			1,589.9
Operating income		1,109.8			464.4			133.8
Other income (expense):
Interest expense		(37.0	)		(41.3	)		(55.5	)
Interest capitalized		20.5			38.1			41.0
Interest income		23.5			22.7			12.3
Loss on early retirement of long-term debt		—			—			(32.4	)
Other		1.1			2.1			(1.2	)
Total other income (expense)		8.1			21.6			(35.8	)
Income before income taxes		1,117.9			486.0			98.0
Income tax provision:
Current tax provision		88.1			57.1			52.6
Deferred tax provision		23.4			5.8			14.0
Total income tax provision		111.5			62.9			66.6
Income from continuing operations		1,006.4			423.1			31.4
Income from discontinued operations, net of tax effect		—			—			112.3
Net income		1,006.4			423.1			143.7
Other comprehensive income (loss)		(24.6	)		(29.1	)		2.7
Total comprehensive income	$	981.8		$	394.0		$	146.4
Earnings per ordinary share (Basic):
Income from continuing operations	$	4.19		$	1.76		$	0.13
Income from discontinued operations		—			—			0.48
Net income	$	4.19		$	1.76		$	0.61
Earnings per ordinary share (Diluted):
Income from continuing operations	$	4.13		$	1.73		$	0.13
Income from discontinued operations		—			—			0.48
Net income	$	4.13		$	1.73		$	0.61

See notes to consolidated financial statements.

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

($ in millions)

ASSETS

	December 31,
	2006		2005
Current assets:
Cash and cash equivalents	$	336.4	$	562.6
Marketable securities		12.5		274.7
Accounts receivable, less allowance for doubtful accounts of $6.3 in 2006 and $4.8 in 2005		653.4		431.5
Accounts receivable from insurers		138.9		123.6
Costs incurred on turnkey drilling projects in progress		11.0		24.2
Prepaid expenses		68.8		39.6
Other current assets		12.7		13.3
Total current assets		1,233.7		1,469.5
Properties and equipment:
Rigs and drilling equipment, less accumulated depreciation of $1,886.4 in 2006 and $1,615.1 in 2005		4,250.3		3,836.5
Construction in progress		229.0		453.7
Oil and gas properties, full-cost method, less accumulated depreciation, depletion and amortization of $35.0 in 2006 and $25.8 in 2005		35.3		27.6
Net properties and equipment		4,514.6		4,317.8
Goodwill		339.2		339.0
Deferred income taxes		34.3		28.2
Other assets		98.4		67.6
Total assets	$	6,220.2	$	6,222.1

See notes to consolidated financial statements.

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

($ in millions)

LIABILITIES AND SHAREHOLDERS’ EQUITY

	December 31,
	2006			2005
Current liabilities:
Accounts payable	$	284.5		$	236.3
Accrued compensation and related employee costs		111.5			84.1
Accrued income taxes		17.8			7.8
Accrued interest		6.6			6.4
Deferred revenue		13.1			19.6
Dividends payable		51.9			55.0
Capital lease obligations		9.3			9.8
Other accrued liabilities		68.4			56.7
Total current liabilities		563.1			475.7
Long-term debt		623.9			550.6
Capital lease obligations		15.4			23.6
Deferred income taxes		27.7			15.4
Pension and other post retirement benefits		64.5			132.1
Other long-term liabilities		78.5			67.2
Commitments and contingencies (Note 6)		—			—
Shareholders’ equity:
Ordinary shares, $0.01 par value, 600 million shares authorized, 230,470,382 shares and 244,741,077 shares issued and outstanding at December 31, 2006 and 2005, respectively		2.3			2.4
Additional paid-in capital		3,176.3			3,246.9
Retained earnings		1,764.1			1,779.2
Accumulated other comprehensive loss		(95.6	)		(71.0	)
Total shareholders’ equity		4,847.1			4,957.5
Total liabilities and shareholders’ equity	$	6,220.2		$	6,222.1

See notes to consolidated financial statements.

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2006			2005			2004
	(In millions)
Cash flows from operating activities:
Net income	$	1,006.4		$	423.1		$	143.7
Adjustments to reconcile net income to cash flows from operating activities:
Depreciation, depletion and amortization		304.7			275.3			260.8
Deferred income taxes		23.4			5.8			9.5
Stock-based compensation expense		38.0			4.3			1.2
Involuntary conversion of long-lived assets, net of related recoveries and loss of hire recoveries		(116.5	)		6.2			(24.0	)
Gain on sale of assets		—			(28.0	)		(139.8	)
Impairment loss on long-lived asset		—			—			1.2
Loss on early retirement of long-term debt		—			—			32.4
Changes in working capital:
Increase in accounts receivable		(271.0	)		(73.6	)		(27.1	)
Increase in prepaid expenses and other current assets		(15.4	)		(22.8	)		(5.7	)
Increase (decrease) in accounts payable		84.2			39.6			(16.9	)
Increase (decrease) increase in accrued liabilities		47.6			(5.0	)		(3.4	)
Increase (decrease) in deferred revenues		(7.1	)		(7.5	)		0.4
Increase in other long-term liabilities		37.4			20.3			43.6
Payment of imputed interest on the Zero Coupon Bond Debentures		—			(56.3	)		—
Contribution to defined benefit plans		(115.5	)		—			(59.6	)
Other, net		(30.8	)		9.8			8.5
Net cash flows from operating activities		985.4			591.2			224.8
Cash flows from investing activities:
Capital expenditures		(546.5	)		(411.0	)		(405.6	)
Proceeds from sale of land drilling fleet assets		—			—			316.5
Cash received from insurance for involuntary conversion of long-lived assets		109.3			—			40.0
Proceeds from disposals of property and equipment		33.7			29.6			58.7
Purchases of held-to-maturity marketable securities		—			—			(169.2	)
Proceeds from maturities of held-to-maturity marketable securities		—			—			254.0
Purchases of available-for-sale marketable securities		(1,214.0	)		(882.0	)		(195.9	)
Proceeds from sales of available-for-sale marketable securities		1,474.4			815.6			115.9
Other		2.7			—			—
Net cash flow provided by (used in) investing activities		(140.4	)		(447.8	)		14.4
Cash flows from financing activities:
Dividend payments		(217.6	)		(108.2	)		(46.9	)
Payments on long-term debt		—			(300.3	)		(331.7	)
Borrowings under credit facility		150.0			—			—
Payment on credit facility		(75.0	)		—			—
Excess tax deduction resulting from option exercises		7.4			—			—
Payments on capitalized lease obligations		(10.1	)		(9.9	)		(9.7	)
Payments for ordinary shares repurchased and retired		(1,068.6	)		(1,776.6	)		—
Proceeds from issuance of ordinary shares		143.5			2,007.5			43.5
Other		(0.8	)		—			0.5
Net cash flow used in financing activities		(1,071.2	)		(187.5	)		(344.3	)
Decrease in cash and cash equivalents		(226.2	)		(44.1	)		(105.1	)
Cash and cash equivalents at beginning of period		562.6			606.7			711.8
Cash and cash equivalents at end of period	$	336.4		$	562.6		$	606.7

See notes to consolidated financial statements.

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

	Ordinary Shares					Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	Shares		Par Value
	($ in millions)
Balance at December 31, 2003	233,516,104		$	2.3		$	2,959.1		$	1,410.8		$	(44.6	)	$	4,327.6
Net income	—			—			—			143.7			—			143.7
Minimum pension liability adjustment	—			—			—			—			1.7			1.7
Unrealized gain on securities	—			—			—			—			1.0			1.0
Comprehensive income																146.4
Exercise of employee stock options	2,234,423			0.1			38.0			—			—			38.1
Shares issued under other benefit plans	250,928			—			6.7			—			—			6.7
Dividends declared	—			—			—			(52.9	)		—			(52.9	)
Shares canceled	(43,974	)		—			(1.2	)		—			—			(1.2	)
Income tax benefit from stock option exercises	—			—			1.7			—			—			1.7
Balance at December 31, 2004	235,957,481			2.4			3,004.3			1,501.6			(41.9	)		4,466.4
Net income	—			—			—			423.1			—			423.1
Minimum pension liability adjustment	—			—			—			—			(25.2	)		(25.2	)
Unrealized gain on securities	—			—			—			—			(3.9	)		(3.9	)
Comprehensive income																394.0
Exercise of employee stock options	8,577,761			—			227.4			—			—			227.4
Shares issued under other benefit plans	205,525			—			4.4			—			—			4.4
Shares issued	43,500,000			0.4			1,775.3			—			—			1,775.7
Shares canceled	(43,500,000	)		(0.4	)		(1,776.2	)		—			—			(1,776.6	)
Restricted stock:
Shares issued	310			—			—			—			—			—
Expense accrual	—			—			4.3			—			—			4.3
Dividends declared	—			—			—			(145.5	)		—			(145.5	)
Income tax benefit from stock option exercises	—			—			7.2			—			—			7.2
Other	—			—			0.2			—			—			0.2
Balance at December 31, 2005	244,741,077			2.4			3,246.9			1,779.2			(71.0	)		4,957.5
Net income	—			—			—			1,006.4			—			1,006.4
Adjustments to initially apply FASB No. 158, net of tax	—			—			—			—			(97.0	)		(97.0	)
Minimum pension liability adjustment	—			—			—			—			71.4			71.4
Unrealized loss on securities	—			—			—			—			(0.3	)		(0.3	)
Realized loss on securities	—			—			—			—			1.3			1.3
Comprehensive income																981.8
Stock-based compensation:
Exercise of employee stock options	4,664,748			0.1			139.2			—			—			139.3
Issuance of stock-based awards	99,324			—			1.4			—			—			1.4
Stock-based compensation expense	—			—			38.0			—			—			38.0
Income tax benefit	—			—			7.4			—			—			7.4
Shares issued under other benefit plans	148,721			—			4.2			—			—			4.2
Shares repurchased and retired (1)	(19,183,488	)		(0.2	)		(261.4	)		(807.0	)					(1,068.6	)
Dividends declared	—			—			—			(214.5	)		—			(214.5	)
Other	—			—			0.6			—			—			0.6
Balance at December 31, 2006	230,470,382		$	2.3		$	3,176.3		$	1,764.1		$	(95.6	)	$	4,847.1

(1) As of December 31, 2006, the trade date for the repurchase of 278,500 shares for a total purchase price of $16.5 million had occurred, but the repurchase had not yet settled and accordingly such shares were still outstanding as of that date.

See notes to consolidated financial statements

68

GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Basis of Presentation and Description of Business

GlobalSantaFe Corporation is an offshore oil and gas drilling contractor, owning or operating a fleet of 59 marine drilling rigs. As of December 31, 2006, our fleet included 43 cantilevered jackup rigs, 11 semisubmersible rigs, three drillships, and two additional semisubmersible rigs we operate for third parties under a joint venture agreement. During the first quarter of 2006, we commenced construction of an additional semisubmersible, to be named the GSF Development Driller III. We also have a jackup rig, the GSF High Island III, that is currently not capable of performing drilling operations due to damage arising in 2005 as a result of Hurricane Rita. Subsequent to December 31, 2006, we entered into a contract to sell the rig to a third party and expect to complete the sale during the first quarter of 2007 We provide offshore oil and gas contract drilling services to the oil and gas industry worldwide on a daily rate (“dayrate”) basis. We also provide oil and gas drilling management services on either a dayrate or completed-project, fixed-price (“turnkey”) basis, as well as drilling engineering and drilling project management services, and we participate in oil and gas exploration and production activities.

BASIS OF PRESENTATION

The accompanying consolidated financial statements include the accounts of GlobalSantaFe Corporation and its consolidated subsidiaries. Unless the context otherwise requires, the terms “we,” “us” and “our” refer to GlobalSantaFe Corporation and its consolidated subsidiaries. The consolidated financial statements and related footnotes are presented in U.S. dollars and in accordance with accounting principles generally accepted in the United States of America. Certain prior period amounts have been reclassified to conform to the current presentation.

DIVIDENDS

Holders of GlobalSantaFe Ordinary Shares are entitled to participate in the payment of dividends in proportion to their holdings. Under Cayman Islands law, we may pay dividends or make other distributions to our shareholders, in such amounts as the Board of Directors deems appropriate from our profits or out of our share premium account (equivalent to additional paid-in capital) provided we thereafter have the ability to pay our debts as they come due. Cash dividends, if any, will be declared and paid in U.S. dollars. We declared cash dividends of $51.9 million that were unpaid as of December 31, 2006.

SALE OF LAND DRILLING BUSINESS (DISCONTINUED OPERATIONS)

On May 21, 2004, we completed the sale of our land drilling business to Precision Drilling Corporation for a total sales price of $316.5 million in an all-cash transaction. As a result of this sale, we recognized a gain of $113.1 million, including a net tax benefit of $1.1 million.

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table lists the contribution of our land rig fleet to our consolidated operating results for the year ended December 31, 2004.

	Year Ended December 31,
	2004
	(In millions)
Revenues	$	43.9
Expenses (income):
Direct operating expenses		27.9
Depreciation		4.0
Exit costs		6.8
Gain on sale of assets		(112.0	)
		117.2
Provision for income taxes, including a net tax benefit of $1.1 in 2004 related to the gain on sale of assets		4.9
Income from discontinued operations, net of tax effect	$	112.3

Note 2—Summary of Significant Accounting Policies

PRINCIPLES OF CONSOLIDATION

We consolidate all of our majority-owned subsidiaries and joint ventures over which we exercise control through either the joint venture agreement or related operating and financing agreements. We account for our interest in other joint ventures using the equity method. All material intercompany accounts and transactions are eliminated in consolidation.

CASH EQUIVALENTS AND MARKETABLE SECURITIES

Cash equivalents include highly liquid debt instruments with remaining maturities of three months or less at the time of purchase. Our marketable securities portfolio is classified as available-for-sale and, as such, these marketable securities are recorded at fair value in our Consolidated Balance Sheet at December 31, 2006 and 2005. Realized and unrealized gains and losses related to these marketable securities are calculated using the specific identification method. Unrealized gains and losses are included in Accumulated Other Comprehensive Loss in the Consolidated Balance Sheet at December 31, 2006 and 2005. In addition, we hold securities in connection with certain nonqualified pension plans, which are also classified as available-for-sale (see Note 3). We recorded $0.4 million of realized gains and $2.6 million of realized losses related to our marketable securities portfolio in 2006 and we recorded $0.6 million of realized gains and $0.2 million of realized losses related to our marketable securities portfolio in 2005. With respect to available-for-sale securities held in connection with certain nonqualified pension plans, we recorded realized gains of $2.4 million in 2006, $3.1 million in 2005 and $1.6 million in 2004.

PROPERTIES AND DEPRECIATION

Rigs and Drilling Equipment. Capitalized costs of rigs and drilling equipment include all costs incurred in the acquisition of capital assets including allocations of interest costs incurred during periods that assets are under construction or while the they are being readied for their initial contract. Expenditures that improve or extend the lives of rigs and drilling equipment are capitalized. Expenditures for maintenance and repairs are

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

charged to expense as incurred. Costs of property sold or retired and the related accumulated depreciation are removed from the accounts; resulting gains or losses are included in income.

We periodically evaluate the remaining useful lives and salvage values of our rigs, giving effect to operating and market conditions and upgrades performed on these rigs. As a result of analyses performed on our drilling fleet, effective January 1, 2004, we increased the remaining lives on certain rigs in our jackup fleet to 13 years from a range of 5.6 to 10.1 years, increased salvage values of these and other rigs in our jackup fleet from $0.5 million per rig to amounts ranging from $1.2 to $3.0 million per rig, and increased the salvage values of our semisubmersibles and certain of our drillships from $1.0 million per rig to amounts ranging from $2.5 to $4.0 million per rig. The effect of these changes in useful lives was a reduction to depreciation expense for the year ended December 31, 2004, of approximately $18.3 million.

During the third quarter of 2005, the GSF High Island III and the GSF Adriatic VII were damaged as a result of Hurricane Rita. During the second quarter of 2006, we recorded gains of $32.8 million on the GSF High Island III and $30.9 million on the GSF Adriatic VII, which represent recoveries of partial losses under our insurance policy, less amounts previously recognized when the rigs were written down to salvage value. In December 2006, we sold the GSF Adriatic VII to a third party for approximately $29.4 million, net of selling costs, and recorded a gain of $28 million, which represents the selling price less the $1.4 million salvage value. In addition, we increased the gain recognized in the second quarter of 2006 related to the GSF Adriatic VII by $3.2 million to include additional costs reimbursable under the insurance policy. There was no tax impact related to these transactions. Subsequent to December 31, 2006, we entered into an agreement to sell the GSF High Island III to a third party for approximately $26.3 million and expect to complete the sale during the first quarter of 2007. We will record a gain equal to the selling price, net of expenses, less the salvage value of $1.2 million.

During the first quarter of 2004, we retired the drillship Glomar Robert F. Bauer from active service. As a result, we accelerated the remaining depreciation on the rig, which resulted in a $1.5 million charge to depreciation expense in the first quarter of 2004. As a result of continued improvements in the offshore drilling markets, we sold this rig in the fourth quarter of 2005 for $25 million and recorded a net gain of $23.5 million. There was no tax impact related to this transaction.

Rigs and drilling equipment included $689.8 million and $1.1 billion of assets recorded under capital leases at December 31, 2006 and 2005, respectively. Accumulated amortization of assets under capital leases totaled $204.0 million and $288.2 million at December 31, 2006 and 2005, respectively.

We review our long-term assets for impairment when changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Long-lived assets and certain intangibles to be held and used are reported at the lower of carrying amount or fair value. Assets to be disposed of and assets not expected to provide any future service potential are recorded at the lower of carrying amount or fair value less cost to sell. We did not record any impairment charges during the years ended December 31, 2006 and 2005. In April 2004, we sold the platform rig Rig 82 for a nominal sum in connection with our exit from the platform rig business and recognized an impairment loss of approximately $1.2 million in the first quarter of 2004.

Oil and Gas Properties. We use the full-cost method of accounting for oil and gas exploration and development costs. Under this method of accounting, we capitalize all costs incurred in the acquisition, exploration and development of oil and gas properties and amortize such costs, together with estimated future development and dismantlement costs, using the units-of-production method.

Costs of offshore unproved properties and development projects are not amortized until they are fully evaluated. Unproved oil and gas properties totaled approximately $1.2 million and $1.4 million at December 31,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2006 and 2005, respectively. All unproved properties are reviewed periodically to ascertain if impairment has occurred. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Costs of proved oil and gas properties that exceed the present value of estimated future net revenues are charged to expense.

Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center, in which case the gain or loss is recognized in income. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss recognized.

In December 2003, our oil and gas division participated in a drilling project in West Africa off the coast of Mauritania. Our share of the costs incurred in connection with this project totaled approximately $3.4 million, $2.9 million of which was classified as unproved oil and gas properties at December 31, 2003. In March 2004, we sold our interest in this project for approximately $6.1 million and as a result of this being the only project in our African cost center we recorded a gain of $2.7 million ($2.0 million net of taxes) in the first quarter of 2004.

In September 2004, our oil and gas division completed the sale of 50% of its interest in the Broom Field, a development project in the North Sea. We received net proceeds of $35.9 million and, because we sold 50% of our reserve base, causing a significant alteration in the relationship between our capitalized cost and proved reserves in our North Sea cost center, we recorded a gain of $25.1 million ($13.3 million net of taxes) in connection with this sale. We retained an eight percent working interest in this project. Pursuant to the terms of the sale, if commodity prices exceeded a specified amount, we were also entitled to additional post-closing consideration equal to a portion of the proceeds from the production attributable to this interest sold through September 2005. In 2005 we recorded an additional gain associated with this deferred consideration arrangement of $4.5 million ($2.7 million net of taxes), which represents the entire deferred consideration earned under the sales agreement.

INTERSEGMENT TURNKEY DRILLING PROFITS

We defer all turnkey drilling profit related to wells in which one of our oil and gas subsidiaries was the operator and defer turnkey profit up to the share of our oil and gas subsidiaries’ costs in properties in which our oil and gas division holds a non-operating working interest. This turnkey profit is credited to our full cost pool of oil and gas properties and is generally recognized through a lower depletion rate as reserves are produced.

GOODWILL

We test goodwill annually for impairment (and in interim periods if certain events occur indicating that the carrying value of goodwill and/or indefinite-lived intangible assets may be impaired).

We have defined reporting units within our contract drilling segment based upon economic and market characteristics of these units. All of the goodwill recorded in connection with the merger of Santa Fe International Corporation and Global Marine Inc. has been allocated to the jackup drilling fleet reporting unit. The estimated fair value of this reporting unit for purposes of our annual goodwill impairment testing is based upon the present value of its estimated future net cash flows, utilizing a discount rate based upon our cost of capital. We have completed our goodwill impairment testing for 2006 and were not required to record a goodwill impairment loss.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

REVENUE RECOGNITION

Our contract drilling business provides crewed rigs to customers on a dayrate basis. Dayrate contracts can be for a specified period of time or the time required to drill a specified well or number of wells. Revenues and expenses from dayrate drilling operations, which are classified under contract drilling services, are recognized on a per-day basis as the work progresses. Lump-sum fees received as compensation for the cost of relocating drilling rigs from one major operating area to another, whether received up-front or upon termination of the drilling contract, are recognized as earned, which is generally over the primary term of the related drilling contract.

We also design and execute specific offshore drilling or well-completion programs for customers at fixed prices under short-term “turnkey” contracts. Revenues and expenses from turnkey contracts, which are classified under drilling management services, are earned and recognized upon completion of each contract.

We recognize revenue from oil and gas production at the time title transfers.

We recognize reimbursements received from customers for out-of-pocket expenses incurred as revenues.

DERIVATIVE FINANCIAL INSTRUMENTS

From time to time, we may make use of derivative financial instruments to manage our exposure to fluctuations in cash flows, interest rates or foreign currency exchange rates. We account for our derivative financial instruments pursuant to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” Derivative instruments held by us at December 31, 2006, consisted of certain fixed-for-floating interest rate swaps related to a portion of our long-term debt (see Note 8).

FOREIGN CURRENCY TRANSACTIONS

The United States dollar is the functional currency for all of our operations. Realized and unrealized foreign currency transaction gains and losses are recorded in income.

We may be exposed to the risk of foreign currency exchange losses in connection with our foreign operations. Such losses are the result of holding net monetary assets (cash and receivables in excess of payables) or liabilities (payables in excess of cash and receivables) denominated in foreign currencies during periods of a strengthening (or, in the case of net monetary liabilities, weakening) U.S. dollar. We incurred foreign currency exchange losses totaling approximately $0.9 million, $2.3 million and $6.1 million in 2006, 2005 and 2004, respectively. We attempt to lessen the impact of exchange rate changes by requiring customer payments to be primarily in U.S. dollars, by keeping foreign cash balances at minimal levels and by not speculating in foreign currencies.

INCOME TAXES

We are a Cayman Islands company and we operate through our various subsidiaries in numerous countries throughout the world including the United States. Consequently, our tax provision is based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. The income tax rates imposed and methods of computing taxable income in these jurisdictions vary substantially. Our effective tax rate for financial statement purposes will continue to fluctuate from year to year as our operations are conducted in different taxing jurisdictions. Current income tax expense represents either liabilities expected to be reflected

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on our income tax returns for the current year, nonresident withholding taxes, or changes in prior year tax estimates which may result from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferred tax assets or liabilities as reported on the balance sheet. Valuation allowances are established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferred tax assets and liabilities, as well as of valuation allowances, we must make estimates and assumptions regarding future taxable income, where rigs will be deployed and other matters. Changes in these estimates and assumptions, as well as changes in tax laws, could require us to adjust the deferred tax assets and liabilities or valuation allowances, including as discussed below.

Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to the expiration of our net operating loss (“NOL”) carryforwards. We have established a valuation allowance against the future tax benefit of a portion of our NOL carryforwards and could be required to record an additional valuation allowance if market conditions deteriorate and future earnings are below, or are projected to be below, our current estimates.

We have not provided for U.S. deferred taxes on the unremitted earnings of our U.S. subsidiaries that are permanently reinvested. Should a distribution be made from the unremitted earnings of these U.S. subsidiaries, we could be required to record additional U.S. current and deferred taxes.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make certain estimates and assumptions. These estimates and assumptions affect the carrying values of assets and liabilities and disclosures of contingent assets and liabilities at the balance sheet date and the amounts of revenues and expenses recognized during the period. Actual results could differ from such estimates.

Note 3—Investments

Our marketable securities portfolio is classified as available-for-sale, and, accordingly, we have recorded these marketable securities at fair value in our Consolidated Balance Sheet at December 31, 2006 and 2005. In addition, we held other investments in debt and equity securities also classified as available-for-sale held in connection with certain nonqualified pension plans, which were included in “Other assets” at December 31, 2006 and 2005. Cost, net unrealized gains and losses and fair values of our investments in debt and equity securities are disclosed in the table that follows:

	2006
	Cost		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(in millions)
Fixed Income Mutual Funds	$	9.7	$	—	$	—	$	9.7
Equity Mutual Funds		11.0		1.5		—		12.5
Auction Rate Securities		12.5		—		—		12.5
	$	33.2	$	1.5	$	—	$	34.7

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	2005
	Cost		Gross Unrealized Gains		Gross Unrealized Losses			Fair Value
	(in millions)
Fixed Income Mutual Funds	$	8.1	$	—	$	(0.1	)	$	8.0
Equity Mutual Funds		7.9		2.4		—			10.3
Treasury Notes		120.5		0.1		(1.2	)		119.4
Corporate Securities		64.3		—		(0.7	)		63.6
Fixed Income Asset Backed Securities		43.4		—		—			43.4
Government Agency Securities		38.9		—		—			38.9
Other		9.5		—		—			9.5
	$	292.6	$	2.5	$	(2.0	)	$	293.1

Note 4—Long-term Debt

Long-term debt as of December 31 consisted of the following:

	December 31,
	2006		2005
5% Notes due 2013, net of unamortized discount of $0.4 million and $0.5 million at December 31, 2006 and 2005, respectively (1)	$	251.6	$	253.5
7% Notes due 2028, net of unamortized discount of $2.7 million and $2.9 million at December 31, 2006 and 2005, respectively		297.3		297.1
Borrowings under $500 million revolving credit facility		75.0		—
Total long-term debt	$	623.9	$	550.6

(1) Balances at December 31, 2006 and 2005 include mark-to-market adjustments totaling $2.1 million and $4.0 million, respectively, as part of fair-value hedge accounting related to fixed-for-floating interest rate swaps (see Note 8).

In August 2006, we entered into a commitment for a five-year $500 million unsecured revolving credit facility with a syndicate of banks. The facility contains customary covenants, including a debt to total tangible capitalization covenant. Our borrowings under the facility will be guaranteed by one of our wholly owned subsidiaries after the time, if any, that the aggregate principal amount of outstanding indebtedness of our subsidiaries, subject to certain exceptions, exceeds ten percent of our consolidated net assets. Interest on the revolving credit facility is based on the applicable LIBOR rate, plus an applicable margin, for the period of borrowing.

During the second quarter of 2005, we repurchased $599.2 million principal amount at maturity of the then outstanding $600 million principal amount of Global Marine Inc.’s Zero Coupon Convertible Debentures due September 23, 2020 for a total purchase price of $356.1 million, representing $299.8 million in principal payment and $56.3 million in imputed interest. On August 18, 2005, we redeemed the remaining $800,000 principal amount at maturity, bringing the total repurchase price of $356.6 million, representing $300.3 million in principal payment and $56.3 million in imputed interest. We purchased all of the debentures for repurchase at a purchase price of $594.25 per $1,000 of principal amount, plus additional imputed interest for all securities purchased after June 23, 2005, calculated from June 23, 2005 to the date of purchase. We funded the repurchase price from our existing cash, cash equivalents and marketable securities balances.

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No principal payments are required with respect to either the 5% Notes or the 7% Notes prior to their final maturity date. We may redeem the 5% Notes and the 7% Notes in whole at any time, or in part from time to time, at a price equal to 100% of the principal amount thereof plus accrued interest, if any, to the date of redemption, plus a premium, if any, relating to the then-prevailing Treasury Yield and the remaining life of the notes.

The indenture relating to the 5% Notes contains limitations on our ability to incur indebtedness for borrowed money secured by certain liens and on our ability to engage in certain sale/leaseback transactions. The indenture, however, does not restrict our ability to incur additional senior indebtedness. The indenture relating to the 7% Notes contain limitations on Global Marine’s ability to incur indebtedness for borrowed money secured by certain liens and to engage in certain sale/leaseback transactions.

Note 5—Involuntary Conversion of Long-Lived Assets and Related Recoveries

During the third quarter of 2005, a number of our rigs were damaged as a result of hurricanes Katrina and Rita. All these rigs returned to work with the exception of the GSF High Island III and the GSF Adriatic VII. During the second quarter of 2006, we recorded gains of $32.8 million on the GSF High Island III and $30.9 million on the GSF Adriatic VII, which represent expected recoveries of partial losses under our insurance policy, less amounts previously recognized when the rigs were written down to salvage value. These amounts were collected in the third quarter of 2006. In December 2006, we sold the GSF Adriatic VII to a third party for a net purchase price of approximately $29.4 million, net of selling costs, and recorded a gain of $28 million, which represents the selling price less the $1.4 million salvage value. In addition, we increased the gain recognized in the second quarter of 2006 related to the GSF Adriatic VII by $3.2 million to include additional costs reimbursable under the insurance policy. We collected the $29.4 million during the fourth quarter of 2006. Subsequent to December 31, 2006 we entered into a contract to sell the GSF High Island III to a third party for approximately $26.3 million and expect to complete the sale during the first quarter of 2007. Any gain recorded on the sale will be equal to the proceeds from the sale, net of expenses, less the rig salvage value of $1.2 million. As of December 31, 2006, we have collected a total of $138.7 million in insurance recoveries and proceeds from the rig sale related to hurricanes Katrina and Rita, including the amounts collected on the GSF High Island III and the GSF Adriatic VII discussed above.

All of the rigs that were damaged in the hurricanes were covered for physical damage under the hull and machinery provision of our insurance policy, which carried a deductible of $10 million per occurrence. In addition, three rigs damaged in Hurricane Katrina, the GSF Arctic I, the GSF Development Driller I, and GSF Development Driller II, were covered by loss of hire insurance under which we are reimbursed for 100 percent of their contracted dayrate for up to a maximum of 270 days following 60 days (the “waiting period”) of lost revenue.

Our insurance policy provided that if claims for a single event are filed under both the hull and machinery and loss of hire sections of the policy, we would bear only a single deductible from that occurrence of no more than the highest deductible from any individual section. Hurricanes Katrina and Rita are each considered to be a separate occurrence. Based on remediations completed for the three rigs covered under the loss of hire insurance, the amount of revenue we lost during the waiting period was higher than the $10 million hull and machinery deductible. Therefore, the 60-day waiting period under our loss of hire insurance will serve as the only deductible for the Hurricane Katrina event. The application of the 60-day waiting period provision with regard to the GSF Development Driller I, the only rig that was still out of service after the 60-day waiting period, is complicated by the fact that at the time of the hurricane, the rig was undergoing thruster remediations and, accordingly, we had already put our underwriters on notice as to a claim under the loss of hire section of the policy. As discussed in Note 6 of Notes to Consolidated Financial Statements—“Commitments and Contingencies,” we recorded $21.6

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million for loss of hire recoveries in the first half of 2006 with respect to the GSF Development Driller I. None of the jackup rigs damaged during Hurricane Rita was insured for loss of hire and, therefore, a single $10 million hull and machinery deductible applied for damage to the rigs caused by Hurricane Rita and was recognized as a loss in the third quarter of 2005.

A summary of the effects that the estimates of rig damages and estimated insurance recoveries had on our financial statements for the periods indicated are as follows:

	2005			2006			Cumulative to date
	(In millions)
Amounts affecting income statement:
Effects of estimated rig damage:
Estimated recoveries	$	117.0		$	94.9		$	211.9
Losses recognized		(127.0	)		—			(127.0	)
Net effect of rig damage—gain (loss)		(10.0	)		94.9			84.9
Estimated insurance recoveries—loss of hire		3.8			21.6			25.4
Net pretax gain (loss)	$	(6.2	)	$	116.5		$	110.3
Amounts affecting balance sheet:
Accounts receivable from insurers, balance at beginning of period	$	—		$	120.8		$	—
Additions		120.8			123.6			244.4
Collections		—			(109.3	)		(109.3	)
Accounts receivable from insurers attributable to hurricanes, balance at end of period		120.8			135.1			135.1
Add: Other receivables from insurers, at end of period		2.8			3.8			3.8
Total accounts receivable from insurers, as reported, at end of period	$	123.6		$	138.9		$	138.9

Additions to accounts receivable from insurers in the table above includes additions due to revised estimates of rig damages and anticipated loss of hire recoveries, both of which affected pretax income as shown in the table. Capital costs incurred to remediate damage to the rigs were added to the capitalized value of the rigs. Also included in additions to accounts receivable from insurers for 2006 in the table above are anticipated reimbursements for cash outlays to salvage the GSF High Island III and the GSF Adriatic VII, necessitated by the significant damage suffered by those rigs during Hurricane Rita, which did not affect pretax income, totaling $35.2 million for 2006.

In August 2004, the jackup GSF Adriatic IV encountered well control problems, caught fire and sank while drilling in the Mediterranean Sea off the coast of Egypt. All of our personnel on board the rig were evacuated safely, although the rig was a total loss. We received insurance proceeds totaling $40.0 million, net of our deductible, and recorded a gain of $24.0 million, net of taxes, in the third quarter of 2004.

Note 6—Commitments and Contingencies

At December 31, 2006, we had office space and equipment under operating leases with remaining terms ranging from approximately one to seven years. Certain of the leases may be renewed at our option, and some are subject to rent revisions based on the Consumer Price Index or increases in building operating costs. In addition, at December 31, 2006, the GSF Britannia cantilevered jackup and the GSF Explorer drillship were held under capital leases through 2007 and 2026, respectively. Total rent expense was $275.1 million for 2006, $203.8

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million for 2005, and $106.7 million for 2004. Included in rent expense was the rental of offshore drilling rigs used in our turnkey operations totaling $246.8 million for 2006, $163.2 million for 2005, and $90.8 million for 2004.

Future minimum rental payments with respect to our lease obligations with lease terms in excess of one year, as of December 31, 2006, were as follows:

	Capital Leases			Operating Leases
	(In millions)
Year ended December 31:
2007	$	9.3		$	10.6
2008		1.8			8.5
2009		1.8			4.1
2010		1.8			1.7
2011		1.8			1.5
Later years		26.4			2.8
Total future minimum rental payments		42.9		$	29.2
Less amount representing imputed interest		(18.2	)
Present value of future minimum rental payments under capital leases		24.7
Less current portion included in accrued liabilities		(9.3	)
Long-term capital lease obligations	$	15.4

As of December 31, 2006, we had an operating lease in place for Santa Fe International’s offices in Dallas, Texas which was closed as part of a restructuring program implemented in connection with the merger of Global Marine and Santa Fe International (“the Merger”). These costs are included in the table above. Costs associated with the closure of Santa Fe International’s office in Dallas were recognized as a liability assumed in the Merger and included in the cost of acquisition.

In January 2003, we entered into a lease-leaseback arrangement with a European bank related to the GSF Britannia cantilevered jackup. Pursuant to this arrangement, we leased the GSF Britannia to the bank for a five-year term for a lump-sum payment of approximately $37 million, net of origination fees of approximately $1.5 million. The bank then leased the rig back to us for a five-year term with an effective annual interest rate based on the 3-month British Pound Sterling LIBOR plus a margin of 0.625%, under which we make annual lease payments of approximately $8.0 million, payable in advance. We have classified this arrangement as a capital lease.

In March 2002, we entered into a sublease agreement with BP America Inc. for our current executive offices located at 15375 Memorial Drive, Houston, Texas. This sublease expires in September 2009. Lease payments pursuant to this sublease total $2.3 million per year. In July 2002, we also entered into an 11-year 8 month lease for our Aberdeen, Scotland, office. Payments pursuant to this lease are £612,250 (approximately $1.2 million) per year. Payments under this lease may be adjusted in 2009 based on prevailing market rates.

CAPITAL COMMITMENTS

In the first quarter of 2006, we entered into a contract with Keppel FELS, a shipyard located in Singapore, for construction of a new ultra-deepwater semisubmersible, to be named the GSF Development Driller III.

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Construction costs for the GSF Development Driller III are expected to total approximately $590 million, excluding capital spares, startup costs, capitalized interest, customer-required modifications and mobilization costs. We have incurred a total of approximately $220 million of capitalized costs related to the GSF Development Driller III, excluding capitalized interest, as of December 31, 2006.

During the second quarter of 2005, we discovered a defect and resulting damage in the thruster nozzles on our two new ultra-deepwater semisubmersibles, the GSF Development Driller I and GSF Development Driller II. Both rigs were being remediated for the thruster defect and resulting damage when they sustained additional damage as a result of Hurricane Katrina. This additional damage further delayed the start of the initial drilling contracts for the GSF Development Driller I and the GSF Development Driller II. Remediations of the GSF Development Driller II were completed and the rig went on contract in November 2005. The thruster defect and damage from Hurricane Katrina further delayed the start of the initial drilling contract for the GSF Development Driller I until June 2006.

We have made claims under our hull and machinery and loss of hire insurance for the GSF Development Driller I and GSF Development Driller II for the periods required to remediate the damage arising from both the thruster defect and Hurricane Katrina. Under our loss of hire insurance, we are entitled to reimbursement for our full dayrate for up to 270 days after a 60-day waiting period. Significant unresolved issues remain as to the proper application of the loss of hire waiting period, which could lead to substantial differences in the amount of the loss of hire recovery. The underwriters have formally reserved their rights to decline coverage for the thruster damage claims on the rigs in respect of both the hull and machinery and loss of hire coverage. As of December 31, 2006, we have recorded estimated loss of hire insurance recoveries equal to $25.4 million ($3.8 million in 2005 and $21.6 million in 2006) with respect to the GSF Development Driller I, which is the amount we deem to be probable under the assumption that the rig will bear two consecutive 60-day waiting periods, one for the thruster damage claim and one for the hurricane damage claim. The GSF Development Driller II was not out of service longer than the combined 120-day waiting period and therefore no loss of hire recoveries have been recorded for this rig. When the loss of hire claims are resolved with the underwriters, the amount of loss of hire recoveries could be different than the amount currently recorded.

LEGAL PROCEEDINGS

In August 2004, certain of our subsidiaries were named as defendants in six lawsuits filed in Mississippi, five of which are pending in the Circuit Court of Jones County and one of which is pending in the Circuit Court of Jasper County, Mississippi, alleging that certain individuals aboard our offshore drilling rigs had been exposed to asbestos. These six lawsuits are part of a group of twenty-three lawsuits filed on behalf of approximately 800 plaintiffs against a large number of defendants, most of which are not affiliated with us. Our subsidiaries have not been named as defendants in any of the other seventeen lawsuits. The lawsuits assert claims based on theories of unseaworthiness, negligence, strict liability and our subsidiaries’ status as Jones Act employers; and seek unspecified compensatory and punitive damages. In general, the defendants are alleged to have manufactured, distributed or utilized products containing asbestos. In the case of our named subsidiaries and that of several other offshore drilling companies named as defendants, the lawsuits allege those defendants allowed such products to be utilized aboard offshore drilling rigs. We have not been provided with sufficient information to determine the number of plaintiffs who claim to have been exposed to asbestos aboard our rigs, whether they were employees nor their period of employment, the period of their alleged exposure to asbestos, nor their medical condition. Accordingly, we are unable to estimate our potential exposure to these lawsuits. We historically have maintained insurance which we believe will be available to address any liability arising from these claims. We intend to defend these lawsuits vigorously, but there can be no assurance as to their ultimate outcome.

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We and two of our subsidiaries were defendants in a lawsuit filed on July 28, 2003, by Transocean Inc. (“Transocean”) in the United States District Court for the Southern District of Texas, Houston Division. The lawsuit alleged that the dual drilling structure and method utilized by the GSF Development Driller I and the GSF Development Driller II semisubmersibles infringe on United States patents granted to Transocean. On August 31, 2006, the jury returned a verdict upholding the validity of certain of the Transocean apparatus claims, awarding past damages of approximately $3.6 million, and finding that we had willfully infringed the patents. The judge subsequently entered a ruling overturning the jury’s finding of willful infringement. Transocean has similar patents in most other jurisdictions in which ultra-deepwater semisubmersibles are likely to operate, excluding certain parts of West Africa. It also has patents in Singapore, where the GSF Development Driller I and GSF Development Driller II were constructed and where the similarly designed GSF Development Driller III is being constructed, and in most other jurisdictions in which dual activity rigs are likely to be constructed. We had joined with other parties in proceedings in Europe and Brazil contesting the issuance of patents to Transocean for dual activity methods and structures. The patents that Transocean obtained in those jurisdictions were substantially the same as those granted in the U.S. and Singapore. In June 2006, the European Patent Office invalidated the patent claims that were the subject of the proceedings, and the Brazilian Patent Office has recently entered a preliminary ruling invalidating the patents in that jurisdiction.

We entered into a settlement agreement with Transocean, effective February 14, 2007, in which we were granted a personal, worldwide, royalty bearing and non-exclusive license to operate dual activity rigs under the Transocean patents. The primary terms of the settlement are as follows:

• We will pay approximately $3,000,000 to Transocean for the past use of dual activity by the GSF Development Driller I and GSF Development Driller II;

• At any time we operate in a jurisdiction in which Transocean has a valid, non-expired patent for dual activity, we will pay a royalty of 3% of the basic dayrate of the GSF Development Driller I, GSF Development Driller II and GSF Development Driller III, or 5% of the basic dayrate of any dual activity rigs that we hereafter acquire or construct. The Transocean patents are set to expire in 2016;

• We will pay $12,000,000 to Transocean on behalf of ourselves and the shipyards that constructed the GSF Development Driller I and GSF Development Driller II, and the shipyard that is currently constructing the GSF Development Driller III and we and the shipyards will be relieved of any liability for the alleged infringement arising from the construction of those rigs; and

• We will withdraw from the proceedings opposing the issuance of patents in Europe and Brazil, and we have agreed not to challenge the validity of the Transocean patents in any jurisdiction.

One of our subsidiaries filed suit in February 2004 against its insurance underwriters in the Superior Court of San Francisco County, California, seeking a declaration as to its rights to insurance coverage and the proper allocation among its insurers of liability for claims payments in order to assist in the future management and disposition of certain claims described below. The subsidiary’s three primary insurers have historically been paying settlement and defense costs for the subsidiary. One of these insurers was nearing insolvency and claimed exhaustion of its coverage limits, but following negotiations has agreed to make a cash payment in exchange for a release of all further liability for the subsidiary’s asbestos liabilities. Both of the subsidiary’s other primary insurers have entered into settlement agreements with the subsidiary that will provide for limited additional funding of asbestos liabilities and attorneys’ fees and costs associated therewith. The subsidiary also intends to enter into discussions with its excess insurers. We believe that the subsidiary will continue to have funds from its insurers sufficient to meet its settlement and defense obligations for the foreseeable future.

The insurance coverage in question relates to lawsuits filed against the subsidiary arising out of its involvement in the design, construction and refurbishment of major industrial complexes. The operating assets of

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the subsidiary were sold and its operations discontinued in 1989, and the subsidiary has no remaining assets other than the insurance policies involved in the litigation 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 January 1, 2007, the subsidiary had been named as a defendant in approximately 4,200 lawsuits, the first of which was filed in 1990, and a substantial number of which are currently pending. We believe that as of January 1, 2007, from $35 million to $40 million had been expended to resolve claims (including both attorney fees and expenses, and settlement costs), with the subsidiary having expended $4 million of that amount due to insurance deductible obligations, all of which have now been satisfied. Because we rely on information from the insurers of our subsidiary for information regarding the amounts expended in settlement and defense of these lawsuits and are not able to verify or confirm the information, the amount expended by the insurers is not known with precision. 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. Although not all of that will be available due to the insolvency of certain insurers, we believe that the subsidiary will have sufficient insurance available to respond to these claims. We do not believe that these claims will have a material impact on our consolidated financial position, results of operations or cash flows.

The same subsidiary is a defendant in a lawsuit filed against it by Union Oil Company of California (“Union”) in the Circuit Court of Cook County, Illinois. That lawsuit arises out of claims alleging personal injury caused by exposure to asbestos at a refinery owned by Union and constructed by our subsidiary. Union has alleged that the subsidiary is required to defend and indemnify it pursuant to the terms of contracts entered into for the construction of the refinery. GlobalSantaFe Corporation has also been named as a defendant in the pending litigation. Union intends to attempt to establish liability against GlobalSantaFe Corporation as the alter ego of, and successor in interest to, its subsidiary and on the basis of a fraudulent conveyance of the subsidiary’s assets, and seeks to pierce the corporate veil between the subsidiary and GlobalSantaFe Corporation. We believe that the allegations of the lawsuit are without merit and intend to vigorously defend against the lawsuit, but cannot provide any assurance as to its ultimate outcome.

We and a number of our subsidiaries were named as defendants in two lawsuits claiming that the GSF Adriatic VII caused damage to a platform in the South Marsh Island area of the Gulf of Mexico when the rig broke free from its location during Hurricane Rita. On September 20, 2006, Devon Energy Corporation and Pogo Producing Company filed suit in the United States District Court for the Southern District of Texas, Houston Division, claiming that the defendants caused damage in an amount exceeding $75 million. On the same day Apache Corporation, as successor in interest to BP p.l.c., filed suit against the defendants in the United States District Court for the Western District of Louisiana, Lafayette Division, claiming damage in an unspecified amount. We have not been presented with evidence indicating that the GSF Adriatic VII caused the damage, if any, claimed by plaintiffs. In any event, we believe that we will be entitled to the benefits of the Act of God defense. Any liability arising therefrom, including legal fees and expenses, will be paid by our insurance underwriters.

We and our subsidiaries are defendants or otherwise involved in a number of lawsuits in the ordinary course of business. In the opinion of management, our ultimate liability with respect to these pending lawsuits is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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ENVIRONMENTAL MATTERS

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 now been entered by the court. The parties to the settlement have entered into a participation agreement, which makes us liable for approximately 8% of the remediation and related costs. The remediation is complete, but our share of the future operation and maintenance costs of the site is estimated to have a present value of approximately $900,000. 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.

We have also been named as a PRP in connection with a site in California known as the Casmalia Resources Site. We and other PRPs have entered into an agreement with the EPA and the DOJ to resolve potential liabilities. Under the settlement, we are not likely to owe any substantial additional amounts for this site beyond what we have already paid. There are additional potential liabilities related to this site, but these cannot be quantified at this time, and we have no reason at this time to believe that they will be material.

We have been named as one of many PRPs in connection with a site located in Carson, California, formerly maintained by Cal Compact Landfill. On February 15, 2002, we were served with a required 90-day notification that eight California cities, on behalf of themselves and other PRPs, intend to commence an action against us under the Resource Conservation and Recovery Act (“RCRA”). On April 1, 2002, a complaint was filed by the cities against us and others alleging that we have liabilities in connection with the site. However, the complaint has not been served. The site was closed in or around 1965, and we do not have sufficient information to enable us to assess our potential liability, if any, for this site.

One of our subsidiaries has recently been ordered by the California Regional Water Quality Control Board 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 also received an order to develop a testing plan for the property. Although the testing plan has not yet been developed and approved, testing costs are expected to be in the range of $200,000. We have also been advised that another subsidiary is likely to be named by the EPA as a PRP for the San Gabriel Valley, Area 3, Superfund site, which includes this property. 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 liable 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 and/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 and/or remedial actions; and

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• allocation of the costs of such activities among the PRPs and other site users.

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

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

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

• the remediation methods and technology to be used.

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

On July 11, 2005, one of our subsidiaries, Santa Fe Minerals, Inc., was served with a lawsuit filed on behalf of three landowners in Louisiana in the 12^th Judicial District Court for the Parish of Avoyelles, State of Louisiana. The lawsuit names nineteen other defendants, all of which are 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. The lawsuit specifies 95 wells drilled on the property in question beginning in 1939, and alleges that our subsidiary, which is a dissolved corporation and no longer conducts operations or holds assets, was the operator or non-operating partner in 13 of the wells during certain periods of time. The plaintiffs allege that the defendants are liable on the basis of strict liability, breach of contract, breach of the mineral leases, negligence, nuisance, trespass, and improper handling of toxic or hazardous substances, that their storage and disposal of toxic and hazardous substances constituted an ultra-hazardous activity, and that they violated various state statutes. The lawsuit seeks unspecified amounts of compensatory and punitive damages, payment of funds sufficient to conduct an environmental assessment of the property in question, damages for diminution of property value and injunctive relief requiring that defendants restore the property to its prior condition and prevent the migration of toxic and hazardous substances. Experts retained by the plaintiffs have issued a report suggesting significant contamination in the area operated by the subsidiary and another codefendant, and claiming that over $300 million will be required to properly remediate the contamination. The experts retained by the defendants conducted their own investigation and concluded that the remediation costs will amount to no more than a few million dollars. The Louisiana Department of Environmental Quality is in the process of conducting its own investigation in that regard. We believe that our subsidiary has meritorious defenses to the allegations contained in the lawsuit, and that if liability is established against it that the judgment will be far lower than that being demanded by the plaintiffs. The plaintiffs and the codefendant threatened to add GlobalSantaFe Corporation as a defendant in the lawsuit under the “single business enterprise” doctrine contained in Louisiana law. The single business enterprise doctrine is an equitable construct created and applied by the judiciary to impose liability against the parent company or a different subsidiary or affiliated companies where more than one company represents precisely the same single interests. The single business enterprise doctrine is similar to corporate veil piercing doctrines. On August 16, 2006, Santa Fe Minerals, Inc. and its immediate parent company, 15375 Memorial Corporation, which is also 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 United States Bankruptcy Court for the District of Delaware. Later that day, the plaintiffs dismissed Santa Fe Minerals, Inc. 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 Corporation and two other subsidiaries in the lawsuit. We

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believe that these legal theories should not be applied against GlobalSantaFe Corporation or these other two subsidiaries, and that in any event the manner in which the parent and its subsidiaries conducted their businesses does not meet the requirements of these theories for imposition of liability. The codefendant also seeks to dismiss the bankruptcies. To date, the efforts to assert alter ego and single business enterprise theory claims against GlobalSantaFe Corporation have been rejected by the Court in Avoyelles Parish and we have filed an action with the Delaware Court asking that any such claims be heard there. We intend to continue to vigorously defend against any action taken in an attempt to impose liability against us under these theories or otherwise.

CONTINGENCIES AND OTHER LEGAL MATTERS

In 1998, we entered into fixed-price contracts for the construction of two dynamically positioned, ultra-deepwater drillships, the GSF C.R. Luigs and the GSF Jack Ryan, which began operating in April and December 2000, respectively. Pursuant to two 20-year capital lease agreements, we subsequently novated the construction contracts for the drillships to two financial institutions (the “Lessors”), which owned the drillships and leased them to us. We deposited with three large foreign banks (the “Payment Banks”) amounts equal to the progress payments that the Lessors were required to make under the construction contracts, less a lease benefit of approximately $62 million (the “Defeasance Payment”). In exchange for the deposits, the Payment Banks assumed liability for making rental payments required under the leases and the Lessors legally released us as the primary obligor of such rental payments. Accordingly, we recorded no capital lease obligations on our balance sheet with respect to the two drillships.

In October 2005, we provided consent to the sale of the Lessor of the GSF C.R. Luigs from one large foreign bank to another. In exchange for our consent, we became entitled to receive consideration, which would equal any sum we were obligated to pay on our termination of the lease, if we exercised our right to terminate the lease between March 1, 2006 and December 31, 2006. In June 2006, we terminated the lease on the GSF C.R. Luigs and purchased the vessel. In addition to receiving the consideration equal to the sum we were obligated to pay on termination of the lease, we received, as a rebate of rentals, an amount equal to the sales price paid by us and a refund of a $0.8 million interest payment we were required to make in March 2006 related to interest rate risk in connection with this lease. Accordingly, we decreased the carrying value of the rig by the $0.8 million. Other than the $0.8 million decrease, there was no other impact to the carrying value of the rig. We now have title to the rig and no longer bear any interest rate risk associated with this lease.

We continue to have interest rate risk in connection with the fully defeased financing lease for the GSF Jack Ryan. The Defeasance Payment earns interest based on the British Pound Sterling three-month LIBOR, which approximated 8.00% at the time of the agreement. Should the Defeasance Payment earn less than the assumed 8.00% rate of interest, we will be required to make additional payments as necessary to augment the annual payments made by the Payment Banks pursuant to the agreements. If the December 31, 2006, LIBOR rate of 5.3% were to continue over the next six years, we would be required to fund an additional estimated $17.3 million for the GSF Jack Ryan during that period. Any additional payments made by us pursuant to the financing lease would increase the carrying value of our leasehold interest in the GSF Jack Ryan and therefore be reflected in higher depreciation expense over its then-remaining useful life. We do not expect that, if required, any additional payments made under this lease would be material to our financial position, results of operations or cash flows in any given year.

We and our subsidiaries are defendants or otherwise involved in a number of lawsuits in the ordinary course of business. In the opinion of management, our ultimate liability with respect to these pending lawsuits is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

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Note 7—Accumulated Other Comprehensive Loss

The components of our accumulated other comprehensive loss were as follows:

	Unrealized Gain (Loss) on Securities			Pension Liability Adjustment, Net of Tax			Accumulated Other Comprehensive Loss
	(In millions)
Balance at December 31, 2004	$	4.4		$	(46.3	)	$	(41.9	)
Net change for the year		(3.9	)		(25.2	)		(29.1	)
Balance at December 31, 2005		0.5			(71.5	)		(71.0	)
Net change for the year		1.0			(25.6	)		(24.6	)
Balance at December 31, 2006	$	1.5		$	(97.1	)	$	(95.6	)

The pension liability adjustments in the table above are shown net of deferred tax benefit of $9.2 million and $17.3 million in 2006 and 2005, respectively. The tax effect of the unrealized holding gains and losses was immaterial for all periods presented.

Note 8—Derivative Financial Instruments, Fair Values of Financial Instruments, and Concentrations of Credit Risk

DERIVATIVE INSTRUMENTS

As part of our overall risk management strategy, we entered into an oil futures commodity swap in July 2005 to manage our exposure to oil commodity price risk related to the forecasted sale of oil production from the Broom field. This swap effectively locked in predetermined prices for the first 600 barrels of our oil production per day from July 1, 2005 to July 31, 2005 and then the first 900 barrels of our forecasted oil production per day over the term of the remaining hedging period, which ranged from August 1, 2005 through December 31, 2005. At final settlement we had no resulting gain or loss. We had designated this instrument as a cash flow hedge.

We manage our fair value risk related to our long-term debt by using interest rate swaps to convert a portion of our fixed-rate debt into variable-rate debt. Under these interest rate swaps, we agree with other parties to exchange, at specified intervals, the difference between the fixed-rate and floating-rate amounts, calculated by reference to an agreed upon notional amount.

As of December 31, 2006, we had fixed-for-floating interest rate swaps with a total notional amount of $175 million related to our 5% Notes. These fixed-for-floating interest rate swaps are designed to be perfectly effective hedges against changes in fair value of our 5% Notes resulting from changes in market interest rates. The total estimated aggregate fair value of these swaps was an asset of $2.1 million at December 31, 2006 and an asset of $4.0 million at December 31, 2005.

FAIR VALUES OF FINANCIAL INSTRUMENTS

The estimated fair value of our $300 million principal amount 7% Notes due 2028, based on quoted market prices, was $327.4 million at December 31, 2006, compared to the carrying amount of $297.3 million (net of discount). The estimated fair value of our $250 million principal amount 5% Notes due 2013, based on quoted market prices, was $238.0 million at December 31, 2006, compared to the carrying amount of $251.6 million (net of discount). The carrying value of our 5% Notes due 2013 includes a mark-to-market adjustment of $2.1 million

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at December 31, 2006, related to the fixed-for-floating interest rate swaps discussed above. Due to the short term nature of our borrowings under our $500 million unsecured revolving credit facility, the estimated fair value of our outstanding borrowing at December 31, 2006 equaled the carrying amount of $75 million.

The fair values of our cash equivalents, trade receivables, and trade payables approximated their carrying values due to the short-term nature of these instruments.

CONCENTRATIONS OF CREDIT RISK

The market for our services and products is the offshore oil and gas industry, and our customers consist primarily of major integrated international oil companies and independent oil and gas producers. We perform ongoing credit evaluations of our customers and have not historically required material collateral. We maintain reserves for potential credit losses, and such losses have been within management’s expectations.

Our cash deposits were distributed among various banks in our areas of operations throughout the world as of December 31, 2006. In addition, we utilize external money mangers to invest excess cash in accordance with our Investment Guidelines. These managers have invested our funds in commercial paper, money market funds, asset backed securities, government issues and corporate obligations. Each of these investments complies with our investment guidelines in terms of security type, credit rating, duration, portfolio and issuer exposure limits. As a result, we believe that credit risk in such instruments is minimal.

Note 9—Stock-Based Compensation Plans

We have various stock-based compensation plans under which we may grant our ordinary shares or options to purchase a fixed number of shares. Stock options, stock appreciation rights (“SARs”), and performance-awarded restricted stock units (“PARSUs”) granted under our various stock-based compensation plans vest over two to four years. Stock options and SARs expire ten years after the grant date. We issue new ordinary shares when stock options and SARs are exercised and when PARSUs vest.

Prior to January 1, 2006, we accounted for our stock-based compensation plans using the intrinsic-value method prescribed by Accounting Principles Board (“APB”) Opinion No. 25. Accordingly, we computed compensation cost for each employee stock option granted as the amount by which the quoted market price of our ordinary shares on the date of grant exceeded the amount the employee must pay to acquire the ordinary shares. The amount of compensation cost, if any, was charged to income over the vesting period. No compensation cost was recognized for any of our outstanding stock options, because all of them had exercise prices equal to the market price of the ordinary shares on the date of grant. No compensation cost was required to be recognized for options granted under our Employee Share Purchase Plan. We did, however, recognize compensation cost over the vesting period for all grants of PARSUs based on the market price of the ordinary shares at the date of grant. SARs were not granted prior to January 1, 2006.

Effective January 1, 2006, we adopted the fair value recognition provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No. 123(R), “Share-Based Payments,” using the modified prospective application transition method. Under this method, compensation cost recognized for the year ended December 31, 2006, includes the applicable amounts of: (a) compensation cost of all stock-based awards granted prior to, but not yet vested as of, January 1, 2006 (based on the grant-date fair value recorded in accordance with the original provisions of SFAS No. 123 and previously presented in pro forma footnote disclosures), and (b) compensation cost for all stock-based awards granted subsequent to January 1, 2006 (based on the grant-date fair value recorded in accordance with the new provisions of SFAS No. 123(R)). Results for prior periods have not been restated.

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Effect of Adopting SFAS No. 123(R)

The following is the effect of adopting SFAS No. 123(R) as of January 1, 2006 (in millions, except per share amounts):

	Year Ended December 31, 2006
Stock based compensation expense—stock options	$	6.7
Stock based compensation expense—stock appreciation rights		13.7
Related deferred income tax benefit		(2.0	)
Decrease in net income	$	18.4
Decrease in basic earnings per share	$	(0.08	)
Decrease in diluted earnings per share	$	(0.08	)

The amounts above relate to the impact of recognizing compensation expense related to stock options and SARs only. Compensation expense related to PARSUs was recognized before implementation of SFAS No. 123(R). Stock-based compensation expense recognized for PARSUs, not included in the table above, totaled $17.6 million, on a pretax basis, for the year ended December 31, 2006. Stock-based compensation expense is allocated to our various operating segments, including corporate general and administrative expenses, based on participant awards and reported as a component of their operating expense. The total amount of compensation cost included in net income for our stock-based compensation was $34.2 million for the twelve months ended December 31, 2006, net of a $3.8 million related tax benefit.

We recognize expense for our stock-based compensation over the vesting period, which represents the period in which an employee is required to provide service in exchange for the award, or through the date an employee is eligible for retirement, whichever period is shorter. We recognize compensation expense for stock-based awards immediately for employees who are eligible to retire at the grant date. We recognized compensation expense totaling $6.9 million and $8.1 million for the year ended December 31, 2006, related to PARSUs and SARs, respectively, granted during that period to employees who were eligible to retire at the grant date.

Prior to adopting SFAS No. 123(R), we presented all tax benefits of deductions resulting from the exercise and vesting of stock-based awards as operating cash flows. SFAS No. 123(R) requires the cash flows resulting from excess tax benefits (tax deductions realized in excess of the compensation costs recognized) from the date of adoption of SFAS No. 123(R) to be classified as a part of cash flows from financing activities. Approximately $7.4 million of excess tax benefits has been classified as financing cash flows for the year ended December 31, 2006.

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Prior Period Pro Forma Presentation

Under the modified prospective application transition method, results for prior periods have not been restated to reflect the effects of implementing SFAS No. 123(R). The following pro forma information, as required by SFAS No. 148, “Accounting for Stock-Based Compensation Transition and Disclosure, an Amendment of FASB Statement No. 123,” is presented for comparative purposes and illustrates the pro forma effect on net income and earnings per ordinary share for the periods presented as if we had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation prior to January 1, 2004 (in millions, except per-share amounts):

	Pro forma Twelve Months Ended December 31, 2005			Pro forma Twelve Months Ended December 31, 2004
Income from continuing operations, as reported	$	423.1		$	31.4
Add stock-based employee compensation expense included in net income, net of related tax effects		4.5			0.7
Deduct: Total stock-based employee compensation expense determined under fair-value based method for all awards, net of related tax effects		(25.9	)		(31.3	)
Pro forma net income	$	401.7		$	0.8
Basic earnings per ordinary share:
As reported	$	1.76		$	0.13
Pro forma	$	1.67		$	—
Diluted earnings per ordinary share:
As reported	$	1.73		$	0.13
Pro forma	$	1.64		$	—

Assumptions

Estimates of fair values of stock options, options granted under the Employee Share Purchase Plan, which was terminated effective January 1, 2006, and SARs, on the grant dates for purposes of calculating the data in the tables above were computed using the Black-Scholes option-pricing model based on the following assumptions:

	Twelve Months Ended December 31,
	2006	2005	2004
Expected price volatility range	35%—38%	42%—48%	42%—50%
Risk-free interest rate range	4.3%—5.1%	3.3%—4.1%	2.4%—4.0%
Expected annual dividend yield	1.9%	1.2%	0.9%
Expected life of SARs / stock options	7 years	4-6 years	4-6 years
Expected life of PARSUs	3 years	3 years	3 years
Expected life of Employee Share Purchase Plan options	N/A	1 year	1 year

Effective January 1, 2006, we modified our assumption for determining expected volatility to reflect the available implied volatility rates and then gradually increase to the long-term historical average over the contractual term of the awards. We had previously relied on historical volatility rates in determining the grant-date fair values of our stock options. We believe that this combined measure of implied and historical volatility is the best available indicator of our expected volatility. The effect of this change on income before taxes, net income and basic and diluted earnings per share for the year ended December 31, 2006 was not material.

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Expected lives of SARs granted during 2006 are determined based on the accounting guidance under Staff Accounting Bulletin No. 107 (“SAB 107”) and our plan provisions. The increase in expected life from previous stock option grants is due primarily to a change in the population of employees who receive SARs. We believe this method is the best estimate of future exercise patterns currently available.

Risk-free interest rates are determined using the implied yield currently available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the options and stock appreciation rights.

Expected dividend yields are based on the approved annual dividend rate in effect and the current market price of our ordinary shares at the time of grant. No assumption for a future dividend rate change has been included unless there is an approved plan to change the dividend in the near term.

Estimated forfeiture rates are derived from historical forfeiture patterns. We believe the historical experience method is the best estimate of forfeitures currently available.

At December 31, 2006, there were a total of 3,016,825 shares available for future grants under our stock-based compensation plans.

Stock Options

A summary of the status of stock options granted is presented below:

	Number of Shares Under Option		Weighted Average Exercise Price
Shares under option at December 31, 2003	19,144,874		$	27.76
Granted	3,306,000		$	25.49
Exercised	(2,234,423	)	$	17.05
Canceled	(1,122,390	)	$	31.04
Shares under option at December 31, 2004	19,094,061		$	28.38
Granted	348,031		$	37.53
Exercised	(8,577,761	)	$	26.50
Canceled	(389,134	)	$	31.26
Shares under option at December 31, 2005	10,475,197		$	30.12
Granted	—			—
Exercised	(4,664,748	)	$	29.85
Canceled	(131,944	)	$	31.45
Shares under option at December 31, 2006	5,678,505		$	30.32
Options exercisable at December 31,
2004	12,534,408		$	29.74
2005	7,217,838		$	31.76
2006	4,556,244		$	30.93

All stock options granted during 2005 and 2004 had exercise prices equal to the market price of our ordinary shares on the date of grant. We did not grant any stock options during 2006. The weighted average per share fair value of options as of the grant date was $16.29 in 2005 and $11.19 in 2004. As of December 31, 2006, there was approximately $1.0 million of total unrecognized compensation cost related to the nonvested portion of the 2005 and 2004 stock option grants. This cost is expected to be recognized over a weighted-average period of 0.8 years. We issue new shares when stock options are exercised.

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The total intrinsic value of options exercised (i.e., the difference in the market price at exercise and the price paid by the employee to exercise the option) was $131.3 million and $127.2 million during the years ended December 31, 2006 and 2005, respectively. The total amount of cash received from exercise of options was $139.2 million and $227.3 million for the years ended December 31, 2006 and 2005, respectively. The actual tax benefit realized for the tax deductions from option exercises totaled $7.4 million and $7.2 million for the years ended December 31, 2006 and 2005, respectively.

The following table summarizes information with respect to stock options outstanding at December 31, 2006:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding at December 31, 2006	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable at December 31, 2006	Weighted Average Exercise Price
$11.56 to $24.32	453,476	4.81	$	19.91	453,476	$	19.91
$24.73 to $25.00	1,425,454	6.77	$	24.74	649,192	$	24.74
$25.02 to $29.50	1,108,399	5.04	$	26.28	1,060,550	$	26.25
$29.85 to $37.48	1,558,645	5.40	$	31.82	1,295,613	$	31.01
$37.50 to $51.41	1,132,531	3.22	$	43.39	1,097,413	$	43.57
	5,678,505	5.19	$	30.32	4,556,244	$	30.93

Performance-Awarded Restricted Stock Units

From time to time, the Compensation Committee of our Board of Directors grants awards of ordinary shares to key employees and directors at no cost to the employee or director. To date, all such awards have been restricted for three years after grant in that the shares are subject to forfeiture if the employee or director terminates his or her employment under certain conditions during a three-year vesting period, subject to acceleration upon the occurrence of certain events. In addition, the opportunity to receive such an award and the size of the award in a given year are usually performance-based in that they are usually dependent upon our performance in the prior year.

In 2005 and 2006, the Compensation Committee granted PARSUs as part of the annual long-term incentive grants. Each PARSU represents one of our ordinary shares and cliff vests after three years of continued service. Upon vesting, each PARSU, together with dividend equivalent payments accrued throughout the three-year vesting period, is paid out in the form of ordinary shares.

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A summary of the status of our PARSUs is presented in the table that follows:

	Number of Shares		Weighted Average Market Price
Number of contingent shares as of December 31, 2003	139,852		$	24.32
Granted	—		$	—
Issued	—		$	—
Canceled	—		$	—
Number of contingent shares as of December 31, 2004	139,852		$	24.32
Granted	370,064		$	37.59
Issued	(310	)	$	37.48
Canceled	(13,963	)	$	37.48
Number of contingent shares as of December 31, 2005	495,643		$	34.04
Granted	459,035		$	57.22
Issued	(99,341	)	$	24.31
Canceled	(55,880	)	$	28.87
Number of contingent shares as of December 31, 2006	799,457		$	46.12
Shares vested at December 31, 2004	—			—
Shares vested at December 31, 2005	139,852		$	24.32
Shares vested at December 31, 2006	—			—

The amount of compensation cost included in income for our PARSUs was $17.6 million for 2006 and $4.3 million for 2005. As of December 31, 2006, there was approximately $14.9 million of total unrecognized compensation cost related to the nonvested portion of the outstanding PARSUs grants. This cost is expected to be recognized over a weighted-average period of 2.46 years.

Stock Appreciation Rights

Beginning January 2006, we also grant SARs to key employees and to non-employee directors at no cost to the grantee. Under the SARs the grantee receives ordinary shares at exercise equal in value to the difference between the market value of our ordinary shares at the exercise date and the market value of our ordinary shares at the date of grant.

	Number of Awards	Weighted Average Grant Date Fair Value
Number outstanding as of December 31, 2005	—		—
Granted	979,300	$	20.67
Issued	—		—
Canceled	—		—
Number outstanding as of December 31, 2006	979,300	$	20.67
Awards vested at December 31, 2006	—		—

The amount of compensation cost included in income for our SARs, on a pretax basis, was $13.7 million for the year ended December 31, 2006. As of December 31, 2006, there was approximately $6.1 million of total unrecognized compensation cost related to the nonvested portion of the outstanding SARs. This cost is expected to be recognized over a weighted average period of 2.68 years.

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Note 10—Retirement Plans

PENSIONS

We have defined benefit pension plans in the United States and the United Kingdom covering all of our U.S. employees and a portion of our non-U.S. employees. These plans are designed and operated to be in compliance with applicable U.S. tax-qualified requirements and U.K. tax requirements for funded plans and, as such, the trust earnings are not subject to income taxes. For the most part, benefits are based on the employee’s length of service and eligible earnings. Substantially all benefits are paid from established trust funds. We are the sole contributor to the plans, with the exception of our plans in the U.K., to which employees also contribute.

Effective December 31, 2006 we adopted the Financial Accounting Standards Board’s (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” This statement amends SFAS No. 87, “Employers’ Accounting for Pensions,” SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and For Termination Benefits,” SFAS No. 186, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” and other related accounting literature. Under SFAS No. 158 we are required to recognize the overfunded or underfunded status of a defined benefit postretirement plan as an asset or liability in our statement of financial position and to recognize the changes in that funded status in the year in which the changes occur through comprehensive income.

Prior to SFAS No. 158 we recognized our pension liability based on the excess of the accumulated benefit obligation (“ABO”) over our plan assets. Under SFAS No. 158 we are required to recognize our pension liability based on the projected benefit obligation (“PBO”) that exceeds plan assets. While the ABO and PBO are both actuarially computed present values of earned benefits based on service to date, the PBO takes into consideration future salary levels. Prior to SFAS No. 158 we also recognized an intangible asset when the ABO exceeded the plan assets, up to the amount of existing prior service cost. Under SFAS No. 158 these amounts must now be reported in Accumulated Other Comprehensive Income (“AOCI”). Below is a chart outlining the incremental effect of adopting SFAS 158 as of December 31, 2006.

	Before Adopting FAS 158			Adjustments to Adopt FAS 158			After Adopting FAS 158
	(In millions)
US Plans
Assets:
Noncurrent benefit asset	$	81.6		$	(81.6	)	$	—
Intangible asset		2.3			(2.3	)		—
Liabilities:
Current benefit liability		1.5			—			1.5
Noncurrent benefit liability		19.3			17.7			37.0
Shareholders’ Equity:
AOCI		(0.1	)		(101.6	)		(101.7	)
UK Plans
Assets:
Noncurrent benefit asset	$	25.8		$	(25.8	)		—
Liabilities:
Noncurrent benefit liability		—			8.8		$	8.8
Shareholders’ Equity:
AOCI		—			(34.6	)		(34.6	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We use a December 31 measurement date for our pension plans. The following table shows the changes in the projected benefit obligation and assets for all pension plans for the years ended December 31, 2006 and 2005 and a reconciliation of the plans’ funded status as of December 31, 2005. Under SFAS No. 158, this reconciliation is no longer necessary as of December 31, 2006.

	December 31, 2006						December 31, 2005
	U.S. Plans			U.K. Plan			U.S. Plans			U.K. Plan
	(In millions)
Change in projected benefit obligation:
Projected benefit obligation at beginning of year	$	397.4		$	179.3		$	346.9		$	192.0
Service cost		13.2			8.6			11.2			10.6
Interest cost		22.5			9.6			19.7			9.6
Employee contributions		—			2.6			—			2.6
Plan amendments		—			—			0.5			—
Actuarial loss (gain)		(8.3	)		10.2			45.1			(11.8	)
Exchange rate fluctuations		—			24.3			—			(21.1	)
Benefits paid		(13.0	)		(2.8	)		(26.0	)		(2.6	)
Projected benefit obligation at end of year	$	411.8		$	231.8		$	397.4		$	179.3
Change in plan assets:
Fair value of plan assets at beginning of year	$	274.7		$	127.7		$	265.5		$	110.5
Actual return on plan assets		44.7			18.3			19.3			23.1
Employer contributions		66.9			56.1			15.9			7.2
Employee contributions		—			2.6			—			2.6
Exchange rate fluctuations		—			21.1			—			(13.1	)
Benefits paid		(13.0	)		(2.8	)		(26.0	)		(2.6	)
Fair value of plan assets at end of year	$	373.3		$	223.0		$	274.7		$	127.7
Reconciliation of funded status:
Funded status at end of year	$	(38.5	)	$	(8.8	)	$	(122.7	)	$	(51.6	)
Unrecognized net loss		N/A			N/A			134.9			28.6
Unrecognized prior service cost		N/A			N/A			9.8			—
Net amount recognized	$	(38.5	)	$	(8.8	)	$	22.0		$	(23.0	)
Amounts recognized in the Consolidated Balance Sheets consist of:
Current liability	$	(1.5	)	$	—			N/A			N/A
Noncurrent liability		(37.0	)		(8.8	)		N/A			N/A
Prepaid pension cost (accrued benefit liability)		N/A			N/A		$	(78.8	)	$	(37.5	)
Intangible asset		N/A			N/A			9.8			—
Accumulated other comprehensive loss		N/A			N/A			91.0			14.5
Net amount recognized	$	(38.5	)	$	(8.8	)	$	22.0		$	(23.0	)
Amounts recognized in Accumulated Other Comprehensive Loss consist of:
Net actuarial loss	$	94.7		$	34.6			N/A			N/A
Prior service cost		7.0			—			N/A			N/A
Net amount recognized	$	101.7		$	34.6		$	—		$	—

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The following table provides information related to those plans in which the PBO exceeded the fair value of plan assets as of December 31, 2005. Due to SFAS No. 158 requiring the pension obligation to be calculated using the PBO, this chart is not necessary as of December 31, 2006.

	December 31, 2005
	U.S. Plans		U.K. Plan
	(In millions)
Projected benefit obligation	$	397.4	$	179.3
Fair value of plan assets	$	274.7	$	127.7

The following table provides information related to those plans in which the ABO exceeded the fair value of plan assets as of December 31, 2005. Due to SFAS No. 158 requiring the pension obligation to be calculated using the PBO, this chart is not necessary as of December 31, 2006.

	December 31, 2005
	U.S. Plans		U.K. Plan
	(In millions)
Accumulated benefit obligation	$	353.5	$	161.8
Fair value of plan assets	$	274.7	$	127.7

The components of net periodic pension benefit cost for our pension plans were as follows:

	Year ended December 31,
	2006						2005						2004
	U.S. Plans			U.K. Plan			U.S. Plans			U.K. Plan			U.S. Plans			U.K. Plan
	(In millions)
Service cost—benefits earned during the period	$	13.2		$	8.6		$	11.2		$	10.6		$	10.9		$	12.9
Interest cost on projected benefit obligation		22.5			9.6			19.7			9.6			19.7			8.2
Expected return on plan assets		(26.2	)		(12.0	)		(22.8	)		(9.2	)		(18.3	)		(8.3	)
Recognized actuarial loss		13.0			1.1			8.6			4.1			8.6			3.2
Settlement loss		0.1			—			3.2			—			—			—
Amortization of prior service cost		2.8			—			4.0			—			4.6			—
Net periodic pension cost	$	25.4		$	7.3		$	23.9		$	15.1		$	25.5		$	16.0

PLAN ASSETS

Our weighted-average asset allocations for our various pension plans at December 31, 2006 and 2005, by asset category are as follows:

	December 31, 2006				December 31, 2005
	U.S. Plans		U.K. Plans		U.S. Plans		U.K. Plans
Equity securities	71	%	63	%	70	%	85	%
Fixed-income securities	29	%	10	%	30	%	12	%
Real estate	—		2	%	—		3	%
Cash	—		25	%	—		—
Total	100	%	100	%	100	%	100	%

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Our objective with regard to our allocation of pension assets is to limit the variability of our pension funding requirements, while maintaining funding at levels that will ensure the payment of obligations as they come due. Our strategy in achieving this objective is to allocate our pension assets in a mix that will achieve an optimal rate of return based on the anticipated timing of our pension benefit obligations, while minimizing the effects of short-term volatility in plan asset market values on our funding requirements.

We employ third-party consultants who determine our asset allocations by performing an asset/liability analysis for our various pension plans based on the demographics of plan participants, including compensation levels and estimated remaining service lives, to determine the timing and amounts of our benefit obligations under the various plans. These consultants then, based on the results of the asset/liability analysis, determine the optimal asset allocations for the pension trust assets within the guidelines set by us. Target asset allocations for pension plan assets for 2006 were 70% equity securities and 30% fixed-income securities for our U.S. plans and 90% equity securities and 10% fixed-income securities for our U.K. plans. The U.K. plan has a large balance in cash for year end 2006 due to the funding of the U.K. pension plan in December 2006. Our target allocations for pension plan assets for 2007 are 70% equity securities and 30% fixed-income securities for our U.S. plans and 70% equity securities, 20% fixed-income securities, and 10% real estate investments for our U.K. plans.

FUNDING

Our funding objective is to fund participants’ benefits under the plans as they accrue. During 2006 we contributed $64.0 million to our U.S. plans and $51.5 million to our U.K. plans. The 2005 actuarial valuation determined that there were no minimum 2005 pension contribution requirements and we therefore decided to defer any contributions until 2006.

BENEFIT PAYMENTS

Expected benefit payments under our pension plans for the next five years are summarized in the following table:

	Years Ended December 31,
	2007		2008		2009		2010		2011		2012-2016
	(In millions)
U.S. Plans	$	13.7	$	14.7	$	16.0	$	17.6	$	18.5	$	126.9
U.K. Plans	$	1.2	$	1.2	$	1.3	$	1.4	$	1.5	$	12.0

These expected benefit payments are estimated based on the assumptions used to calculate our projected benefit obligation as of December 31, 2006, and include benefits attributable to estimated future service.

NONQUALIFIED PLANS

We have established grantor trusts to provide funding for benefits payable under certain of our nonqualified plans, which are included in the preceding tables. Assets in these trusts, which are irrevocable and can only be used to pay such benefits, with certain exceptions, are excluded from plan assets in the preceding tables in accordance with Statement of Financial Accounting Standards No. 87, “Employers’ Accounting for Pensions.” The fair market value of such assets was $22.2 million at December 31, 2006, and $18.4 million at December 31, 2005 (see Note 3).

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OTHER POSTRETIREMENT BENEFITS

During 2005 we discontinued offering retiree healthcare coverage for current employees who had not met certain eligibility requirements. For eligible participants we provide retiree health care benefits to those who are enrolled in our U.S. Health Care Plan at the time of their retirement and who elect to enroll for such coverage. For the most part, health care benefits require a contribution from the retiree. We also provided term life insurance to certain retirees, both U.S. citizens and non-U.S. citizens who retired prior to July 1, 2002.

Similar to the pension plans reported above, under SFAS No. 158 we are required to recognize the overfunded or underfunded status of the plan as an asset or liability in our statement of financial position and to recognize the changes in that funded status in the year in which the changes occur through comprehensive income. Below is a chart outlining the incremental effect of adopting SFAS No. 158 as of December 31, 2006.

	Before Adopting FAS 158		Adjustments to Adopt FAS 158			After Adopting FAS 158
	(In millions)
Liabilities:
Current benefit liability	$	1.5		—		$	1.5
Noncurrent benefit liability		14.7	$	4.0			18.7
Shareholders’ Equity:
AOCI		—		(4.0	)		(4.0	)

We use a December 31 measurement date for our postretirement benefit plans. The following table shows the changes in the projected benefit obligation and assets for our postretirement benefit plans for the years ended December 31, 2006 and 2005 and a reconciliation of the plans’ funded status as of December 31, 2005. Under SFAS No. 158 this reconciliation is no longer necessary as of December 31, 2006.

	December 31, 2006			December 31, 2005
	(In millions)
Change in projected benefit obligation:
Projected benefit obligation at beginning of year	$	20.1		$	22.7
Service cost		0.4			0.4
Interest cost		1.1			1.1
Employee contributions		1.0			0.8
Plan amendments		—			(4.5	)
Actuarial loss (gain)		(0.1	)		2.2
Benefits paid		(2.3	)		(2.6	)
Projected benefit obligation at end of year	$	20.2		$	20.1
Change in plan assets:
Fair value of plan assets at beginning of year	$	—		$	—
Employer contributions		1.3			1.8
Employee contributions		1.0			0.8
Benefits paid		(2.3	)		(2.6	)
Fair value of plan assets at end of year	$	—		$	—

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

	December 31, 2006			December 31, 2005
	(In millions)
Reconciliation of funded status:
Funded status at end of year	$	(20.2	)	$	(20.1	)
Unrecognized net loss		N/A			5.1
Unrecognized prior service cost		N/A			(0.8	)
Net amount recognized	$	(20.2	)	$	(15.8	)
Amounts recognized in the Consolidated Balance Sheets consist of:
Current liability	$	(1.5	)		N/A
Noncurrent liability		(18.7	)		N/A
Prepaid pension cost (accrued benefit liability)		N/A		$	(15.8	)
Intangible asset		N/A			N/A
Accumulated other comprehensive loss		N/A			N/A
Net amount recognized	$	(20.2	)	$	(15.8	)
Amounts recognized in Accumulated Other Comprehensive Loss consist of:
Net actuarial loss	$	4.7			N/A
Prior service credit		(0.7	)		N/A
Net amount recognized	$	4.0		$	—

The components of net periodic benefit cost for our postretirement plan were as follows:

	Year ended December 31,
	2006			2005			2004
	(In millions)
Service cost—benefits earned during the period	$	0.4		$	0.4		$	0.5
Interest cost on projected benefit obligation		1.1			1.1			1.3
Recognized actuarial loss		0.4			0.2			—
Amortization of prior service cost		(0.1	)		(0.1	)		0.5
Net periodic pension cost	$	1.8		$	1.6		$	2.3

The expected benefit payments under our postretirement plans for the next five years are summarized in the following table:

Years Ended December 31,
2007	2008	2009	2010	2011	2012-2016
(In millions)
$1.6	$1.6	$1.7	$1.7	$1.7	$9.7

These expected benefit payments are estimated based on the assumptions used to calculate our projected benefit obligation as of December 31, 2006, and include benefits attributable to estimated future service.

The weighted-average annual assumed rate of increase in the per capita cost of covered postretirement medical benefits was 10%, 9% and 9% for 2006, 2005 and 2004, respectively. The 10% rate for 2006 is expected to decrease ratably to 5% in 2011 and remain at that level thereafter. The health care cost trend rate assumption can have an effect on the amounts reported. For example, as of and for the year ended December 31, 2006, increasing or decreasing the assumed health care cost trend rates by one percentage point each year would change

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the accumulated postretirement benefit obligation by approximately $0.3 million and $(0.3) million, respectively, and the aggregate of the service and interest cost components of net periodic postretirement benefit by approximately $16,600 and $(15,500), respectively.

We do not consider our postretirement benefits costs and liabilities to be material to our results of operations or financial position.

PLAN ASSUMPTIONS

The following assumptions were used to determine our pension and postretirement benefit obligations:

	December 31, 2006				December 31, 2005
	U.S. Plans		U.K. Plans		U.S. Plans		U.K. Plans
Discount rate	5.91	%	5.25	%	5.50	%	5.00	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%

The following weighted average assumptions were used to determine our net periodic pension and benefit costs:

	Year Ended December 31,
	2006				2005				2004
	U.S. Plans		U.K. Plans		U.S. Plans		U.K. Plans		U.S. Plans		U.K. Plans
Discount rate	5.50	%	5.00	%	5.75	%	5.25	%	6.25	%	5.50	%
Expected long-term rate of return	8.00	%	8.50	%	8.75	%	8.50	%	9.00	%	9.00	%
Rate of compensation increase	4.00	%	4.00	%	4.00	%	4.00	%	4.50	%	4.25	%

The discount rates used to calculate the net present value of future benefit obligations at December 31, 2006 and 2005, and pension costs for the years ended December 31, 2006, 2005 and 2004, for both our U.S. and U.K. plans are based on the average of current rates earned on long-term bonds that receive a Moody’s rating of Aa or better.

We employ third-party consultants for our U.S. and U.K. plans that use portfolio return models to assess the reasonableness of the assumption for expected long-term rate of return on plan assets. Using asset class return, variance, and correlation assumptions, the models produce distributions of possible returns so that we can review the expected return and each fifth percentile return for the portfolio. The assumptions developed by the consultants are forward-looking and are not developed solely by an examination of historical returns. They take into account historical relationships, but are adjusted by our consultants to reflect expected capital market trends. A building block approach is applied to create a coherent framework between the main economic drivers for the portfolio (namely inflation, yields, bond and equity prices). The model is then used to carry out a projection of possible returns for each asset class, and these are combined based on the investment mix for our pension plans. The volatility and correlation assumptions are also forward-looking. They take into account historical relationships, but are adjusted by our consultants to reflect expected capital market trends.

DEFINED CONTRIBUTION PLAN

We have a defined contribution (“401(k)”) savings plan in which substantially all of our U.S. employees are eligible to participate. Company contributions to the 401(k) savings plan are based on the amount of employee contributions. We match 100% of each participant’s first six percent of compensation contributed to the plan. Charges to expense with respect to this plan totaled $9.0 million for 2006, $7.8 million for 2005, $6.6 million for 2004.

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We also sponsor various defined contribution plans for certain of our U. K. employees. Charges to expense for these plans totaled $1.5 million for 2006, $1.1 million for 2005, and $0.9 million for 2004.

Note 11—Income Taxes

Income from continuing operations before income taxes was comprised of the following:

	2006		2005		2004
	(In millions)
United States	$	124.5	$	91.5	$	(50.9	)
Foreign		993.4		394.5		148.9
Income from continuing operations before income taxes	$	1,117.9	$	486.0	$	98.0

Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. We are a Cayman Islands company and the Cayman Islands does not impose corporate income taxes. Our U.S. subsidiaries are subject to a U.S. tax rate of 35%.

At December 31, the provision for income taxes consisted of the following:

	2006			2005		2004
	(In millions)
Current    —Foreign	$	87.5		$	54.8	$	46.1
—U.S. federal		(0.2	)		1.5		6.5
—State		0.8			0.8		—
		88.1			57.1		52.6
Deferred  —Foreign		(4.0	)		3.0		(0.4	)
—U.S. federal		27.4			2.8		14.4
		23.4			5.8		14.0
Provision for income taxes	$	111.5		$	62.9	$	66.6

A reconciliation of the differences between our income tax provision computed at the appropriate statutory rate and our reported provision for income taxes follows:

	2006			2005			2004
	($ in millions)
Income tax provision at statutory rate (Cayman Islands)	$	—		$	—		$	—
Taxes on U.S. and foreign earnings at greater than the Cayman Islands rate		124.5			99.0			115.9
Permanent differences		(7.3	)		(7.6	)		(7.0	)
Subsidiary realignment		—			—			42.5
Change in valuation allowance		(10.5	)		(29.2	)		(84.8	)
Other, net		4.8			0.7			—
Provision for income taxes	$	111.5		$	62.9		$	66.6
Effective tax rate		10	%		13	%		68	%

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We intend to permanently reinvest all of the unremitted earnings of our U.S. subsidiaries in their businesses. As a result, we have not provided for U.S. deferred taxes on $722.3 million of cumulative unremitted earnings at December 31, 2006. Should a distribution be made to us from the unremitted earnings of our U.S. subsidiaries, we could be required to record additional U.S. current and deferred taxes. It is not practicable to estimate the amount of deferred tax liability associated with these unremitted earnings.

Deferred tax assets and liabilities are recorded in recognition of the expected future tax consequences of events that have been recognized in our financial statements or tax returns. The significant components of our deferred tax assets and liabilities as of December 31 were as follows:

	2006			2005
	(In millions)
Deferred tax assets:
Net operating loss carryforwards—U.S.	$	120.5		$	131.6
Net operating loss carryforwards—various foreign		58.9			63.4
Tax credit carryforwards		24.3			23.4
Accrued expenses not currently deductible		66.7			68.1
Other		40.3			19.5
		310.7			306.0
Less: Valuation allowance		(22.4	)		(32.9	)
Deferred tax assets, net of valuation allowance		288.3			273.1
Deferred tax liabilities:
Depreciation and depletion for tax in excess of book expense		281.5			260.3
Other		0.2			—
Total deferred tax liabilities		281.7			260.3
Net future income tax asset (1)	$	6.6		$	12.8

(1) The difference between the change in the net deferred tax asset of $6.2 million between December 31, 2006 and 2005, differs from the deferred tax expense of $ 23.4 million reported for 2006 due primarily to net tax benefits charged to equity accounts as a result of the tax effects of minimum pension liability adjustments and deductions taken for employee option exercises.

We have historically established valuation allowances against our NOL carryforwards when, based on earnings projections, we determine that it is more likely than not that the NOL in a particular jurisdiction will not be fully utilized.

In 2006, we decreased the valuation allowance related to our deferred tax assets by a net $10.5 million in various foreign jurisdictions. In 2005, we decreased the valuation allowance related to our deferred tax assets by $29.2 million, $24.9 million of which relates to the utilization of Global Marine’s U.S. net operating loss (“NOL”) carryforwards. Over the course of 2005, U.S. taxable income increased significantly as compared to the 2004 estimate to the extent that only $6.3 million of the 2005 expiring NOL was not utilized at the end of the year. As a consequence, $69.8 million of the U.S. valuation allowance was released which resulted in a $24.9 million U.S. tax benefit in 2005. The total valuation allowance was further reduced by $4.3 million as the associated NOLs expired. As of December 31, 2006 all of the remaining valuation allowance relates to foreign NOL carryforwards. The valuation allowance against U.S. and foreign NOLs was reduced by $77.4 million and $7.4 million respectively in 2004 due to utilization of U.S. NOL’s and the expiration of foreign NOLs.

In December 2004, we completed a subsidiary realignment to separate our international and domestic holding companies. This realignment included the redemption of a minority interest in a foreign subsidiary held by one of our U.S. subsidiaries, along with the intercompany sale of certain rigs between U.S. and foreign

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subsidiaries. These transactions generated a U.S. taxable gain which resulted in a total tax expense of approximately $135.0 million. This expense was reduced in part by the recognition of $77.4 million of tax benefits resulting from the release of valuation allowances previously recorded against a portion of our U.S. NOL carryforwards, the recognition of a $6.8 million tax benefit from the release of deferred tax liabilities and the deferral of $8.3 million of tax expense related to the gain on the intercompany rig sales. This net deferred tax benefit will be recognized for financial reporting purposes over the remaining useful lives of the rigs. The total tax expense recognized for financial reporting purposes was $42.5 million, comprised of $37.4 million of deferred tax expense and $5.1 million of current tax expense.

At December 31, 2006, we had $344.1 million of U.S. NOL carryforwards. In addition, we have $20.5 million of non-expiring U.S. alternative minimum tax credit carryforwards. The NOL carryforwards and the U.S. alternative minimum tax credit carryforwards can be used to reduce our U.S. federal income taxes payable in future years. The NOL carryforwards subject to expiration expire as follows (in millions):

Year ended December 31:	Total		United States		Foreign
2006	$	6.1		—	$	6.1
2007		22.0	$	22.0		—
2008		18.8		18.8		—
2009		1.9		—		1.9
2010		2.3		—		2.3
2011		1.3		—		1.3
2013		22.5		—		22.5
2014		2.0		—		2.0
2016		10.3		—		10.3
2018		22.9		22.9		—
2020		53.4		53.4		—
2021		43.3		43.3		—
2022		113.0		113.0		—
2023		70.7		70.7		—
2024		—		—		—
Total	$	390.5	$	344.1	$	46.4

In addition, we also had $20.3 million, $109.4 million, $13.4 million, $20.6 million, $4.2 million, $3.9 million, $1 million and $1.5 million of non-expiring NOL carryforwards in the United Kingdom, Trinidad and Tobago, Luxemburg, Netherlands, Saudi Arabia, Hungary, Ireland and Brazil respectively.

Our ability to realize the benefit of our deferred tax asset requires that we achieve certain future earnings levels prior to the expiration of our NOL carryforwards. We have established a valuation allowance against the future tax benefit of a portion of our NOL carryforwards and could be required to further adjust that valuation allowance if market conditions change materially and future earnings are, or are projected to be, significantly different from our current estimates. Our NOL carryforwards are subject to review and potential disallowance upon audit by the tax authorities in the jurisdictions where the loss was incurred.

In July 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”), an interpretation of SFAS 109, “Accounting for Income Taxes.” FIN 48 prescribes a comprehensive model for how companies should recognize, measure, present, and disclose in their financial statements uncertain tax positions taken or expected to be taken on a tax return. Tax law is subject to varied interpretation, and whether a tax position will ultimately be sustained may be uncertain. Under FIN 48, tax positions shall initially be recognized in the financial statements when it is more likely than not the position will be sustained upon

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examination by the tax authorities. Such tax positions shall initially and subsequently be measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with the tax authority assuming full knowledge of the position and all relevant facts. FIN 48 also requires additional disclosures about unrecognized tax benefits associated with uncertain income tax positions and a reconciliation of the change in the unrecognized benefit. In addition, FIN 48 requires interest to be recognized on the full amount of deferred benefits for uncertain tax positions. An income tax penalty is recognized as expense when the tax position does not meet the minimum statutory threshold to avoid the imposition of a penalty. The provisions of this interpretation are required to be adopted for fiscal periods beginning after December 15, 2006. We will be required to apply the provisions of FIN 48 to all tax positions upon initial adoption with any cumulative effect adjustment to be recognized as an adjustment to retained earnings. Upon adoption, management estimates that a cumulative effect adjustment of approximately $8 million to $17 million will be charged to retained earnings to increase reserves for uncertain tax positions. This range is subject to revision as management completes its analysis.

Note 12—Earnings Per Ordinary Share

A reconciliation of the numerators and denominators of the basic and diluted per share computations for net income follows:

	Year Ended December 31,
	2006		2005		2004
	(In millions, except share and per share amounts)
Numerator:
Income from continuing operations	$	1,006.4	$	423.1	$	31.4
Income from discontinued operations		—		—		112.3
Net income	$	1,006.4	$	423.1	$	143.7
Denominator:
Ordinary shares—Basic		240,122,709		240,888,294		234,754,492
Add effect of employee stock options		3,456,298		4,238,312		2,416,794
Ordinary shares—Diluted		243,579,007		245,126,606		237,171,286
Earnings per ordinary share:
Basic:
Income from continuing operations	$	4.19	$	1.76	$	0.13
Income from discontinued operations		—		—		0.48
Net income	$	4.19	$	1.76	$	0.61
Diluted:
Income from continuing operations	$	4.13	$	1.73	$	0.13
Income from discontinued operations		—		—		0.48
Net income	$	4.13	$	1.73	$	0.61

The computation of diluted earnings per ordinary share excludes outstanding stock options and SARs with exercise prices greater than the average market price of GlobalSantaFe ordinary shares for the period, because the inclusion of these options and SARs would have the effect of increasing diluted earnings per ordinary share (i.e. their effect would be “antidilutive”). Antidilutive options that were excluded from diluted earnings per ordinary share and could potentially dilute basic earnings per ordinary share in the future represented 5,985 shares in 2006, 1,897,236 shares in 2005, and 9,090,138 shares in 2004. A total of 247,200 SARs were also excluded from the computation of diluted earnings per ordinary share for 2006. There were no SARs outstanding during the 2005 and 2004 periods.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Diluted earnings per ordinary share for 2004 excludes 4,875,062 potentially dilutive shares that would have become issuable upon conversion of the Zero Coupon Convertible Debentures because the inclusion of such shares would have been antidilutive. We redeemed all of the Zero Coupon Convertible Debentures in 2005 (see Note 4).

Note 13—Supplemental Cash Flow Information

In December 2006, our Board of Directors declared a regular quarterly cash dividend in the amount of $0.225 per ordinary share. The dividend in the amount of $51.9 million was paid on January 12, 2007, to shareholders of record as of the close of business on December 29, 2006.

Cash payments for capital expenditures for the year ended December 31, 2006, include $49.8 million of capital expenditures that were accrued but unpaid at December 31, 2005. Cash payments for capital expenditures for the year ended December 31, 2005, include $63.9 million of capital expenditures that were accrued but unpaid at December 31, 2004. Cash payments for capital expenditures for the year ended December 31, 2004, include $16.6 million of capital expenditures that were accrued but unpaid at December 31, 2003. Capital expenditures that were accrued but not paid as of December 31, 2006, totaled $13.7 million. This amount is included in “Accounts payable” in the Consolidated Balance Sheet at December 31, 2006.

In connection with damage sustained by our rigs from Hurricane Katrina and Hurricane Rita (see Note 5), we have accrued a receivable of approximately $135.1 million, which represents amounts expected to be recovered from our insurance underwriters, including loss of hire recoveries. This amount is included in “Accounts receivable from insurers”, along with various other insurance claims receivable, on the Consolidated Balance Sheet as of December 31, 2006.

Cash payments for interest, net of amounts capitalized, totaled $13.2 million for the year ended December 31, 2006. Cash payments made for interest in 2005 were exceeded by amounts capitalized, resulting in the gross interest payments of $33.5 million being capitalized. Cash payments for interest, net of amounts capitalized, totaled $10.2 million for the year ended December 31, 2004. Cash payments for income taxes, net of refunds, totaled $33.8 million, $66.7 million, and $37.6 million for the years ended December 31, 2006, 2005 and 2004, respectively.

Note 14—Segment and Geographic Information

We have three lines of business, each organized along the basis of services and products and each with a separate management team. Our three lines of business are reported as separate operating segments and consist of contract drilling, drilling management services and oil and gas. Our contract drilling business provides fully crewed, mobile offshore drilling rigs to oil and gas operators on a daily rate basis and is also referred to as dayrate drilling. Our drilling management services business provides offshore oil and gas drilling management services on either a dayrate or completed-project, fixed-price (“turnkey”) basis, as well as drilling engineering and drilling project management services. Our oil and gas business participates in exploration and production activities, principally in order to facilitate the acquisition of turnkey contracts for our drilling management services operations.

We evaluate and measure segment performance on the basis of operating income. Intersegment revenues, which have been eliminated from the consolidated totals, are recorded at transfer prices which are intended to approximate the prices charged to external customers. Segment operating income consists of revenues from external customers less the related operating costs and expenses and excludes interest expense, interest income, restructuring costs and corporate expenses. Segment assets consist of all current and long-lived assets, exclusive of affiliate receivables and investments.

103

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Information by operating segment, together with reconciliations to the consolidated totals, is presented in the following table:

	Contract Drilling		Drilling Management Services		Oil and Gas		Corporate			Eliminations and Other			Consolidated
	(In millions)
REVENUES FROM EXTERNAL CUSTOMERS
2006	$	2,540.2	$	718.8	$	53.6		—			—		$	3,312.6
2005		1,640.2		566.6		56.7		—			—			2,263.5
2004		1,176.9		515.2		31.6		—			—			1,723.7
INTERSEGMENT REVENUES
2006		28.2		33.5		—		—		$	(61.7	)		—
2005		24.3		23.7		—		—			(48.0	)		—
2004		14.9		16.3		—		—			(31.2	)		—
TOTAL REVENUES
2006		2,568.4		752.3		53.6		—			(61.7	)		3,312.6
2005		1,664.5		590.3		56.7		—			(48.0	)		2,263.5
2004		1,191.8		531.5		31.6		—			(31.2	)		1,723.7
OPERATING INCOME
2006		1,046.4		11.6		27.2	$	(91.9	)		116.5	(1)		1,109.8
2005		445.3		31.3		33.9		(67.9	)		21.8	(2)		464.4
2004		119.1		6.7		19.4		(62.0	)		50.6	(3)		133.8
DEPRECIATION, DEPLETION AND AMORTIZATION
2006		287.5		—		9.3		7.9			—			304.7
2005		259.6		—		8.0		7.7			—			275.3
2004		246.3		—		5.0		5.5			—			256.8
CAPITAL EXPENDITURES
2006 (4)		485.9		—		16.2		8.3			—			510.4
2005		371.2		—		14.1		11.6			—			396.9
2004		416.2		—		20.4		16.3			—			452.9
SEGMENT ASSETS
2006		5,741.5		125.0		199.1		284.5			(129.9	)(5)		6,220.2
2005		5,888.6		114.1		145.0		173.3			(98.9	)		6,222.1
2004		5,554.4		82.4		119.5		320.2			(78.3	)		5,998.2
GOODWILL
2006		339.2		—		—		—			—			339.2
2005		339.0		—		—		—			—			339.0
2004		338.1		—		—		—			—			338.1

(1) During the third quarter of 2005, a number of our rigs were damaged as a result of hurricanes Katrina and Rita. All of these rigs returned to work with the exception of the GSF High Island III and the GSF Adriatic VII. During the first half of 2006 we recorded $21.6 million for estimated recoveries from insurers under the loss of hire insurance policy related to Hurricane Katrina. During the second quarter of 2006, we also recorded gains of $32.8 million on the GSF High Island III and $30.9 million on the GSF Adriatic VII, which represent recoveries of partial losses under our insurance policy, less amounts previously recognized

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

when the rigs were written down to salvage value. These amounts were collected in the third quarter of 2006. In December 2006, we sold the GSF Adriatic VII to a third party for a net purchase price of approximately $29.4 million and recorded a gain of $28 million, which represents the net purchase price net of the $1.4 million salvage value. In addition, we increased the gain recognized in the second quarter of 2006 related to the GSF Adriatic VII by $3.2 million to include additional costs reimbursable under the insurance policy.

(2) The 2005 amount includes a gain of $23.5 million relating of the sale of the Glomar Robert F. Bauer and gains totaling $4.5 million relating to deferred consideration on the sale of a portion of our oil and gas division’s interest in certain oil and gas properties (Note 2). These amounts were offset by amounts recorded as a result of damage sustained by our rigs from Hurricanes Rita and Katrina during third quarter of 2005. We recorded an involuntary loss totaling $127 million against the carrying value of rigs damaged in the storms, offset by $117 million in anticipated insurance recoveries. The net loss of $10 million represents our insurance deductible for Hurricane Rita, while the 60-day waiting period under our loss of hire insurance policy will serve as the only insurance deducible for Hurricane Katrina. In the fourth quarter of 2005 we recorded $3.8 million for estimated recoveries from insurers under this loss of hire insurance policy related to Hurricane Katrina.

(3) The 2004 amount includes a gain of $24.0 million as a result of the loss of the GSF Adriatic IV and gains totaling $27.8 million related to the sales of our oil and gas division’s interests in certain oil and gas properties, offset in part by an impairment loss of $1.2 million in connection with the sale of a platform rig (Note 2).

(4) Capital expenditures include approximately $13.7 million, $49.8 million and $63.9 million of capital expenditures related primarily to our rig building program that had been accrued but not paid as of December 31, 2006, 2005 and 2004, respectively (Note 13).

(5) Amounts for 2006, 2005, and 2004 reflect the deferral of intersegment turnkey drilling profit credited to our full cost pool of oil and gas properties (see Note 2).

Turnkey drilling projects often involve numerous subcontractors and third party vendors and, as a result, the actual final project cost is typically not known at the time a project is completed. Results for the years ended December 31, 2006 and 2005, were favorably affected by downward revisions to cost estimates of wells completed in prior years totaling $1.5 million and $2.7 million, respectively, which represented approximately less than 1.0% of drilling management services expenses for both 2005 and 2004. The effect of these revisions was more than offset, however, by the deferral of turnkey profit totaling $30.4 million in 2006 and $17.1 million in 2005 related to wells in which a subsidiary of our oil and gas division was either the operator or held a working interest. This turnkey profit has been credited to our full cost pool of oil and gas properties and will be recognized through a lower depletion rate as reserves are produced.

One customer accounted for more than 10% of consolidated revenues in 2006: BP provided $494.1 million of contract drilling revenues, $0.7 million of oil and gas revenues, and $0.4 million of drilling management services revenues. One customer accounted for more than 10% of consolidated revenues for 2005: BP provided $261.0 million of contract drilling revenues and $1.2 million of oil and gas revenues. One customer accounted for more than 10% of consolidated revenues in 2004: Total and its affiliated companies provided $186.0 million of contract drilling revenues.

105

GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We are incorporated in the Cayman Islands; however, all of our operations are located in countries other than the Cayman Islands. Revenues and assets by geographic area in the tables that follow were attributed to countries based on the physical location of the assets. The mobilization of rigs among geographic areas has affected area revenues and long-lived assets over the periods presented. Revenues from external customers by geographic areas were as follows:

	2006		2005		2004
	(In millions)
United Kingdom	$	493.7	$	439.6	$	330.5
Egypt		219.9		112.8		97.8
Angola		196.8		148.1		7.9
Other foreign countries (1)		1,198.9		883.2		675.8
Total foreign revenues		2,109.3		1,583.7		1,112.0
United States		1,203.3		679.8		611.7
Total revenues	$	3,312.6	$	2,263.5	$	1,723.7

(1) Individually less than 5% of consolidated revenues for 2006, 2005, and 2004.

Long-lived assets by geographic areas, based on their physical location at December 31, were as follows:

	2006		2005
	(In millions)
Properties and equipment:
United Kingdom	$	512.6	$	588.3
Angola		399.6		460.3
Other foreign countries (1)		1,508.7		1,706.0
Total foreign long-lived assets		2,420.9		2,754.6
United States		1,864.7		1,109.5
Total productive assets		4,285.6		3,864.1
Construction in progress—United States		—		453.7
Construction in progress—Singapore		229.0		—
Total properties and equipment		4,514.6		4,317.8
Goodwill		339.2		339.0
Total long-lived assets	$	4,853.8	$	4,656.8

(1) Individually less than 10% of consolidated long-lived assets at December 31.

Note 15—Transactions with Affiliates

Until December 2005, Kuwait Petroleum Corporation, through its wholly owned subsidiary, SFIC Holdings (Cayman), Inc., owned a portion of our outstanding shares. At December 31, 2004, Kuwait Petroleum Corporation held 43,500,000 ordinary shares, approximately 18.4% of our ordinary shares. During 2005, we repurchased all 43,500,000 ordinary shares from Kuwait Petroleum Corporation with the net proceeds of public offerings of an equal number of ordinary shares, as described in Note 16—Share Repurchase. Kuwait Petroleum Corporation’s ownership interest had entitled it to certain rights pursuant to an intercompany agreement entered into with Santa Fe International in connection with the initial public offering of Santa Fe International and amended in connection with the Merger.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The intercompany agreement, as amended, provided that, as long as Kuwait Petroleum Corporation and its affiliates, in the aggregate, owned at least 10% of our outstanding ordinary shares, the consent of SFIC Holdings was required to change the jurisdiction of any of our existing subsidiaries or incorporate a new subsidiary in any jurisdiction in a manner materially adversely affecting the rights or interests of Kuwait Petroleum Corporation and its affiliates or to reincorporate us in another jurisdiction and provide SFIC Holdings rights to access information concerning us. The intercompany agreement, as amended, also provided that SFIC Holdings had the right to designate up to three representatives to our Board of Directors based on SFIC Holdings’ ownership percentage. As of December 31, 2005, all of SFIC Holdings’ representatives on our Board of Directors had resigned.

As part of our land drilling operations, we provided contract drilling services in Kuwait to the Kuwait Oil Company, K.S.C. (“KOC”), a subsidiary of Kuwait Petroleum Corporation, and also provided contract drilling services to a partially owned affiliate of KOC in the Kuwait-Saudi Arabian Partitioned Neutral Zone. Such services were performed pursuant to drilling contracts containing terms and conditions and rates of compensation which materially approximated those that were customarily included in arm’s-length contracts of a similar nature. In connection therewith, KOC provided us rent-free use of certain land and maintenance facilities. On May 21, 2004, we completed the sale of our land drilling fleet and related support equipment and we no longer provide contract drilling services to KOC. We still, however, maintained an agency agreement with a subsidiary of Kuwait Petroleum Corporation that obligated us to pay certain agency fees.

During 2006 we terminated our agency agreement with a subsidiary of Kuwait Petroleum Corporation that obligated us to pay certain agency fees in return for their sponsorship that allows us to operate in Kuwait. During the years ended December 31, 2006 and 2005 we paid $17,000 and $34,000, respectively, of agency fees pursuant to the agency agreement. We did not earn any revenues from KOC or its affiliate during 2006 and 2005. During the year ended December 31, 2004, we earned revenues from KOC and its affiliate for performing land contract drilling services in the ordinary course of business totaling $20.5 million and paid $211,000 of agency fees pursuant to the agency agreement. At December 31, 2005 we had accounts receivable from affiliates of Kuwait Petroleum Corporation of $0.1 million. There were no outstanding receivables as of December 31, 2006.

Note 16—Share Repurchase

On March 3, 2006, our Board of Directors authorized us to repurchase up to $2 billion of our ordinary shares from time to time. As of December 31, 2006, we had repurchased a total of 19,461,988 shares for $1,085.1 million at an average price of $55.75 per share. At December 31, 2006, transactions to purchase 278,500 of these shares for a total purchase price of $16.5 million were not yet settled and these shares were included as shares outstanding as of December 31, 2006.

During 2005, we issued a total of 43,500,000 ordinary shares in two public offerings and, in each case, immediately used the net proceeds to repurchase an equal number of our ordinary shares from a subsidiary of Kuwait Petroleum Corporation at a price per share equal to the net proceeds per share we received in the offering. The first offering was in April 2005, in which we issued 23,500,000 ordinary shares at an aggregate price, net of underwriting discount, of approximately $799.5 million ($34.02 per share). The second offering was in December 2005, in which we issued 20,000,000 ordinary shares at an aggregate price, net of underwriting discount, of approximately $977.1 million ($48.86 per share). In connection with these transactions, we incurred a total of $0.9 million of expenses, which were recorded as a reduction of additional paid in capital. There was no change in the number of outstanding shares as the result of the two transactions as the shares repurchased were immediately cancelled.

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Note 17—Summarized Financial Data—Global Marine Inc. and Subsidiaries

Global Marine Inc. (“Global Marine”), one of our wholly owned subsidiaries, is a domestic and international offshore drilling contractor, with a fleet of 12 mobile offshore drilling rigs worldwide as of December 31, 2006. Global Marine, through its subsidiaries, provides offshore drilling services on a dayrate basis in the U.S. Gulf of Mexico and internationally, provides drilling management services on a turnkey basis, and also engages in oil and gas exploration, development and production activities, principally in order to facilitate the acquisition of turnkey contracts for its drilling management services operations.

Summarized financial information for Global Marine and its consolidated subsidiaries follows:

	Year Ended December 31,
	2006		2005		2004
	(In millions)
Sales and other operating revenues	$	1,214.4	$	720.6	$	705.9
Operating Income		151.0		109.1		133.0
Net income		152.7		116.9		9.7
			December 31,
			2006		2005
			(In millions)
Current Assets			$	540.8	$	254.3
Net properties and equipment				883.5		946.2
Other assets				1,216.3		1,524.7
Current liabilities				245.9		412.9
Total long-term debt (1)				312.7		312.9
Other long-term liabilities				93.4		102.8
Net equity				1,988.5		1,896.6

(1) Includes capitalized lease obligation.

108

SUPPLEMENTAL OIL AND GAS DISCLOSURE (Unaudited)

Pursuant to Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”), we are required to provide supplemental oil and gas disclosures if our oil and gas subsidiaries are considered significant. In 2006 and 2005, our oil and gas operations were not considered significant under the provisions in SFAS 69. Our estimated 2004 net proved reserves and proved developed reserves of crude oil, natural gas and natural gas liquids are shown in the table below.

	2004
	Gas		Oil
	Millions of Cubic feet		Thousands of Barrels
United States:
Proved Reserves:
Balance, January 1	5,906		287
Increase (decrease) during the year attributable to:
Revisions of previous estimates	181		56
Extensions, discoveries and other additions	1,377		18
Production	(2,752	)	(85	)
Sales of minerals in place	402		1
Balance, December 31	5,114		277
Proved Developed Reserves:
January 1	5,906		287
December 31	5,081		277
United Kingdom:
Proved Reserves:
Balance, January 1	—		4,188
Increase (decrease) during the year attributable to:
Revisions of previous estimates	—		146
Extensions, discoveries and other additions	—		586
Production	—		(263	)
Sales of minerals in place	—		(2,094	)
Balance, December 31	—		2,563
Proved Developed Reserves:
January 1	—		—
December 31	—		2,563
Total:
Proved Reserves:
Balance, January 1	5,906		4,475
Increase (decrease) during the year attributable to:
Revisions of previous estimates	181		202
Extensions, discoveries and other additions	1,377		604
Production	(2,752	)	(348	)
Sales of minerals in place	402		(2,093	)
Balance, December 31	5,114		2,840
Proved Developed Reserves:
January 1	5,906		287
December 31	5,081		2,840

109

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.

Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves are located in the United States and in the United Kingdom (North Sea). Proved developed reserves are those proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

The estimates of our proved oil and gas reserves in the United States were prepared by Netherland, Sewell and Associates, Inc. (“Netherland & Sewell”) and estimates of our proved oil and gas reserves in the United Kingdom were prepared by the firm of DeGolyer and MacNaughton, based on data supplied by us. The reports issued by these firms, including descriptions of the bases used in preparing the reserve estimates, are filed as exhibits to this Annual Report on Form 10-K.

There were no capitalized costs of unproved oil and gas properties excluded from the full cost amortization pool as of December 31, 2004. Costs incurred related to oil and gas activities consisted of the following:

	2004
	(in millions)
United States:
Exploration costs	$	1.3
Development costs		2.5
Acquisition of properties		0.7
Total United States	$	4.5
United Kingdom:
Exploration costs	$	0.2
Development costs		15.7
Acquisition of properties		—
Total United Kingdom	$	15.9
Total:
Exploration costs	$	1.5
Development costs		18.2
Acquisition of properties		0.7
Total	$	20.4

The calculation of estimated future net cash flows in the following table assumed the continuation of existing economic conditions. Future net cash inflows were computed by applying year-end prices (except for future price changes as allowed by contract) of oil and gas to the expected future production of proved reserves, less future expenditures (based on year-end costs) expected to be incurred in developing and producing such reserves.

110

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves as of December 31 follows:

	2004
	(In millions)
United States:
Future cash inflows	$	43.5
Future production and development costs		17.2
Future net cash flows		26.3
Ten percent annual discount for estimated timing of cash flows		3.8
Standardized measure of discounted future net cash relating to proved oil and gas reserves	$	22.5
United Kingdom:
Future cash inflows	$	102.7
Future production and development costs		48.6
Future net cash flows		54.1
Ten percent annual discount for estimated timing of cash flows		14.7
Standardized measure of discounted future net cash relating to proved oil and gas reserves	$	39.4
Total:
Future cash inflows	$	146.2
Future production and development costs		65.8
Future net cash flows		80.4
Ten percent annual discount for estimated timing of cash flows		18.5
Standardized measure of discounted future net cash relating to proved oil and gas reserves	$	61.9

111

Principal sources of changes in the standardized measure of discounted future net cash flows follow:

	2004
	(in millions)
United States:
Balance, January 1	$	24.4
Revisions to quantity estimates and production rates		2.0
Prices, net of lifting costs		2.0
Estimated future development costs		(1.2	)
Accretion of ten percent discount		2.4
Additions, extensions and discoveries plus improved recovery		4.4
Net sales of production		(16.3	)
Sales and purchases of reserves in place		2.7
Development costs incurred		0.2
Other		1.9
Balance, December 31	$	22.5
United Kingdom:
Balance, January 1	$	33.3
Revisions to quantity estimates and production rates		3.1
Prices, net of lifting costs		1.3
Estimated future development costs		(0.1	)
Accretion of ten percent discount		3.3
Additions, extensions and discoveries plus improved recovery		12.4
Net sales of production		(11.3	)
Sales and purchases of reserves in place		(16.7	)
Development costs incurred		15.5
Other		(1.4	)
Balance, December 31	$	39.4
Total:
Balance, January 1	$	57.7
Revisions to quantity estimates and production rates		5.1
Prices, net of lifting costs		3.3
Estimated future development costs		(1.3	)
Accretion of ten percent discount		5.7
Additions, extensions and discoveries plus improved recovery		16.8
Net sales of production		(27.6	)
Sales and purchases of reserves in place		(14.0	)
Development costs incurred		15.7
Other		0.5
Balance, December 31	$	61.9

112

Results of operations from producing activities follow:

	2004
	(in millions)
United States:
Revenues	$	19.4
Expenses:
Production costs		3.1
Depreciation, depletion and amortization		3.8
Technical support and other		1.6
		8.5
Gains on sales of properties		—
Income before income taxes		10.9
Income tax expense		3.8
Results of operations from producing activities	$	7.1
United Kingdom:
Revenues	$	12.2
Expenses:
Production costs		0.9
Depreciation, depletion and amortization		1.2
Technical support and other		1.6
		3.7
Gains on sales of properties		25.1
Income before income taxes		33.6
Income tax expense		16.5
Results of operations from producing activities	$	17.1
Total:
Revenues	$	31.6
Expenses:
Production costs		4.0
Depreciation, depletion and amortization		5.0
Technical support and other		3.2
		12.2
Gains on sales of properties		25.1
Income before income taxes		44.5
Income tax expense		20.3
Results of operations from producing activities	$	24.2

Results of operations from producing activities in the table above exclude a gain of $2.7 million ($2.0 million net of taxes) related to the sale of our oil and gas division’s interest in a drilling project in West Africa off the coast of Mauritania. This interest was classified as unproved oil and gas properties on our Consolidated Balance Sheet at December 31, 2003.

113

CONSOLIDATED SELECTED QUARTERLY FINANCIAL DATA (Unaudited)

The consolidated selected quarterly financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data.”

	2006								2005
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter			Second Quarter		First Quarter
	(In millions, except per share data)
Revenues	$	950.6	$	909.2	$	773.4	$	679.4	$	603.5	$	596.6		$	574.8	$	488.6
Operating income		370.6		281.8		276.6		180.8		198.2		118.1			94.5		53.6
Net income		349.4		245.6		248.5		162.9		180.2		107.6			85.1		50.2
Net income includes the following special items:
Gain (loss) on involuntary conversion of long-lived asset, net of related recoveries and loss of hire (1)		31.2		—		66.4		18.5		3.8		(6.5	)		—		—
Gain on sale of assets (2)		—		—		—		—		23.5		2.0			0.7		—
Earnings per ordinary share (Basic)		1.50		1.03		1.02		0.66		0.74		0.44			0.36		0.21
Earnings per ordinary share (Diluted)		1.48		1.02		1.01		0.65		0.73		0.44			0.35		0.21
Cash dividend declared per ordinary share		0.225		0.225		0.225		0.225		0.225		0.15			0.15		0.075
Price ranges of ordinary shares:
High		64.50		58.86		65.21		62.41		50.22		48.00			44.00		39.05
Low		44.26		45.75		49.73		48.40		39.15		40.30			32.27		31.95

(1) During the third quarter of 2005, a number of our rigs were damaged as a result of hurricanes Katrina and Rita. All of these rigs returned to work with the exception of the GSF High Island III and the GSF Adriatic VII. During the first quarter we recorded $18.9 million ($18.5 million, net of tax) for estimated recoveries from insurers under the loss of hire insurance policy related to Hurricane Katrina. During the second quarter of 2006, we recorded $2.7 million for estimated recoveries from insurers under the loss of hire insurance policy related to Hurricane Katrina, and also recorded gains of $32.8 million on the GSF High Island III and $30.9 million on the GSF Adriatic VII, which represent recoveries of partial losses under our insurance policy, less amounts previously recognized when the rigs were written down to salvage value. These amounts were collected in the third quarter of 2006. In December 2006, we sold the GSF Adriatic VII to a third party for a net purchase price of approximately $29.4 million, net of selling costs, and recorded a gain of $28 million, which represents the selling price less the $1.4 million salvage value. In addition, we increased the gain recognized in the second quarter of 2006 related to the GSF Adriatic VII by $3.2 million to include additional costs reimbursable under the insurance policy. In the third quarter of 2005, we recorded an involuntary loss totaling $127 million against the carrying value of rigs in the U.S. Gulf of Mexico damaged in hurricanes Katrina and Rita, offset by $117 million in anticipated insurance recoveries. The net loss of $10 million for that quarter ($6.5 million, net of tax) represents our insurance deductible for Hurricane Rita, while the 60-day waiting period under our loss of hire insurance policy will serve as the only insurance deducible for Hurricane Katrina. In the fourth quarter of 2005, we recorded $3.8 million for estimated recoveries from insurers under this loss of hire insurance policy related to Hurricane Katrina, resulting in a net loss for 2005 of $6.2 million.

(2) In the third quarter 2004, our oil and gas division sold a portion of its interest in the Broom Field development project in the North Sea. Pursuant to the terms of the sale, if commodity prices exceeded a specified amount, we were entitled to additional post-closing consideration equal to a portion of the proceeds from the production attributable to this interest sold through September 2005. In 2005 we recorded an additional gain associated with this deferred consideration arrangement of $4.5 million ($2.7 million, net of taxes), which represents the entire deferred consideration earned under the sales agreement. In 2005 we also sold the Glomar Robert F. Bauer drillship for $25 million and recorded a gain of $23.5 million. There was no tax impact related to this transaction.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ON FINANCIAL STATEMENT SCHEDULE

To the Board of Directors and Shareholders of GlobalSantaFe Corporation:

Our audits of the consolidated financial statements, of management’s assessment of the effectiveness of internal control over financial reporting and of the effectiveness of internal control over financial reporting referred to in our report dated February 28, 2007 appearing in the 2006 Annual Report to Shareholders of GlobalSantaFe Corporation (which report, consolidated financial statements and assessment are included in this Annual Report on Form 10-K) also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2007

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GLOBALSANTAFE CORPORATION AND SUBSIDIARIES

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

(In millions)

	Balance at Beginning of Year		Additions				Deductions			Balance at End of Year
			Charged to Costs and Expenses		Charged to Other Accounts
Year ended December 31, 2006:
Allowance for doubtful accounts receivable	$	4.8	$	2.0	$	—	$	(0.5	)	$	6.3
Deferred tax asset valuation allowance		32.9		3.7		—		(14.2	)	$	22.4
Year ended December 31, 2005:
Allowance for doubtful accounts receivable	$	3.5	$	2.3	$	—	$	(1.0	)	$	4.8
Deferred tax asset valuation allowance		62.1		24.2		—		(53.4	)	$	32.9
Year ended December 31, 2004:
Allowance for doubtful accounts receivable	$	7.9	$	—	$	—	$	(4.4	)	$	3.5
Deferred tax asset valuation allowance		149.6		9.1		2.1		(98.7	)	$	62.1

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

ITEM 9A. CONTROLS AND PROCEDURES

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of December 31, 2006, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934 (the “Act”. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2006, in ensuring that information required to be disclosed by us in the reports that we file or submit under the Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, including ensuring that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There were no changes in our internal control over financial reporting for the fourth quarter of 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of GlobalSantaFe Corporation is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. GlobalSantaFe Corporation’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Internal control over financial reporting includes those written policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of GlobalSantaFe Corporation;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of GlobalSantaFe Corporation are being made only in accordance with authorization of management and directors of GlobalSantaFe Corporation; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the consolidated financial statements.

Internal control over financial reporting includes the controls themselves, monitoring (including internal auditing practices) and actions taken to correct deficiencies as identified.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of GlobalSantaFe Corporation’s internal control over financial reporting as of December 31, 2006. Management based this assessment on criteria for effective internal control over financial reporting described in “Internal Control—Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessment included an evaluation of the design of GlobalSantaFe Corporation’s internal control over financial reporting and testing of the operating

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effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of our Board of Directors.

Based on this assessment, management determined that, as of December 31, 2006, GlobalSantaFe Corporation maintained effective internal control over financial reporting.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report appearing elsewhere in this report, which expresses unqualified opinions on our management’s assessment and on the effectiveness of our internal control over financial reporting as of December 31, 2006.

ITEM 9B. OTHER INFORMATION

During the fourth quarter of 2006, various individuals adopted written plans pursuant to Rule 10b5-1 under the U.S. Securities Exchange Act of 1934. Each plan provides for the exercise of specified stock options and/or stock-settled stock appreciation rights (“SARs”) granted by us and the sale of the underlying GlobalSantaFe ordinary shares at specified per share market price targets, and/or provides for the sale of GlobalSantaFe ordinary shares already owned by the individual at specified per share market price targets. In addition, the 10b5-1 plans generally provide for the exercise of any in-the-money stock options and/or SARs granted by us, to the extent not previously exercised, and the sale of the underlying ordinary shares two business days before the options or SARs are due to terminate or expire. Among the individuals who adopted 10b5-1 plans during the fourth quarter are:

Thomas W. Cason	Director
Michael R. Dawson	Senior Vice President and Chief Financial Officer
Roger B. Hunt	Senior Vice President, Marketing
James L. McCulloch	Senior Vice President and General Counsel
Myrtle L. Penelton	Vice President, Tax
W. Matt Ralls	Executive Vice President, Operations
Cheryl D. Richard	Senior Vice President, Human Resources
Anil B. Shah	Vice President and Treasurer
R. Blake Simmons	President, Applied Drilling Technology Inc

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information relating to our directors and Section16(a) beneficial ownership reporting compliance is incorporated herein by reference to the Sections entitled “Election of Directors,” “Board Committees” and “Other Matters—Section16(a) Beneficial Ownership Reporting Compliance” of our definitive proxy statement which will be filed no later than 120 days after December 31, 2006.

Information related to our audit committee and the designation of our audit committee financial expert is incorporated herein by reference to the section entitled “Board Committees and Other Board Matters” of our definitive proxy statement which will be filed no later than 120 days after December 31, 2006.

Information with respect to our executive officers required by Item 401 of Regulation S-K is set forth in Part I of this Annual Report on Form 10-K under the caption “Executive Officers of the Registrant.”

We have adopted a code of ethics that applies to the Chief Executive Officer, the Chief Financial Officer, the Treasurer, and the Controller. We have posted a copy of the code on our Internet website at: http://www.globalsantafe.com under the caption “Corporate Governance.” Copies of the code may be obtained free of charge from our website or by requesting a copy in writing from our Secretary at 15375 Memorial Drive, Houston, Texas 77079. We intend to disclose any amendments to, or waivers from, a provision of the code of ethics that applies to the Chief Executive Officer, the Chief Financial Officer or the Controller by posting such information on our website.

ITEM 11. EXECUTIVE COMPENSATION

Information required by Item 11 is incorporated herein by reference to the Sections entitled “Director Compensation” and “Executive Compensation” of our definitive proxy statement which will be filed no later than 120 days after December 31, 2006.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information related to security ownership required by Item 12 is incorporated herein by reference to the Section entitled “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Directors and Executive Officers,” and “Equity Compensation Plan Information” of our definitive proxy statement which will be filed no later than 120 days after December 31, 2006.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information required by Item 13 is incorporated herein by reference to the Sections entitled “Board Independence,” “Board Committees and Other Board Matters” and, if applicable, “Certain Relationships and Related Transactions” of our definitive proxy statement which will be filed no later than 120 days after December 31, 2006.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information required by Item 14 is incorporated herein by reference to the Section entitled “Audit Committee Report” of our definitive proxy statement which will be filed no later than 120 days after December 31, 2006.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following are included as exhibits to this Annual Report on Form 10-K (Commission File No. 1-14634). Exhibits filed herewith are so indicated “+”. Exhibit incorporated by reference are so indicated by parenthetical information.

2.1	Agreement and Plan of Merger, dated as of August 31, 2001, among the Company, Silver Sub, Inc., Gold Merger Sub, Inc. and Global Marine Inc. (incorporated herein by this reference to the Company’s Current Report on Form 8-K filed September 4, 2001).
2.2	Purchase Agreement between GlobalSantaFe Corporation, GlobalSantaFe Drilling Venezuela, C.A., GlobalSantaFe Drilling Operations Inc., and Saudi Drilling Company Limited as Seller Parties and Precision Drilling Corporation, P. D. Technical Services Inc., Precision Drilling De Venezuela C.A., Precision Drilling Services Saudi Arabia Ltd., Muscat Overseas Oil & Gas Drilling Co. LLC, and Precision Drilling (Cyprus) Limited as Buyer Parties dated as of April 1, 2004 (incorporated herein by this reference to Exhibit 99.1 to the Company’s Current Report on 8-K filed April 2, 2004).
3.1	Amended and Restated Memorandum of Association of the Company, adopted by Special Resolution of the members effective May 23, 2006 (incorporated herein by this reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 25, 2006).
3.2	Amended and Restated Articles of Association of the Company, adopted by Special Resolution of the members effective May 23, 2006 (incorporated herein by this reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the Commission on May 25, 2006).
4.1	Indenture dated as of September 1, 1997, between Global Marine Inc. and Wilmington Trust Company, as Trustee, relating to Debt Securities of Global Marine Inc. (incorporated herein by this reference to Exhibit 4.1 of Global Marine Inc.’s Registration Statement on Form S-4 (No. 333-39033) filed with the Commission on October 30, 1997); First Supplemental Indenture dated as of June 23, 2000 (incorporated herein by this reference to Exhibit 4.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 2000); Second Supplemental Indenture dated as of November 20, 2001 (incorporated herein by this reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
4.2a	Form of 7% Note Due 2028 (incorporated herein by this reference to Exhibit 4.2 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated May 20, 1998).
4.2b	Terms of 7% Note Due 2028 (incorporated herein by this reference to Exhibit 4.1 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated May 20, 1998).
4.3	Indenture dated as of February 1, 2003, between GlobalSantaFe Corporation and Wilmington Trust Company, as Trustee, relating to Debt Securities of GlobalSantaFe Corporation (incorporated herein by this reference to Exhibit 4.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
4.4a	Form of 5% Note due 2013 (incorporated herein by this reference to Exhibit 4.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
4.4b	Terms of 5% Note due 2013 (incorporated herein by this reference to Exhibit 4.11 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.1	Bareboat Charter Agreement, dated July 2, 1996, between the United States of America and Global Marine Capital Investments Inc. (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated August 1, 1996).

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10.2a	Head Lease Agreement dated 8th December 1998 by and between BMBF (No. 12) Limited, as lessor, and Global Marine International Drilling Corporation, as lessee, relating to one double hulled, dynamically positioned ultra-deepwater Glomar class 456 drillship to be constructed by Harland and Wolff Shipbuilding and Heavy Industries Ltd. with hull number 1740 (incorporated herein by this reference to Exhibit 10.14 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1998).
10.2b	Deed of Guarantee and Indemnity dated 8th December 1998 by and between Global Marine Inc., as Guarantor, and BMBF (No. 12) Limited, as Lessor (incorporated herein by this reference to Exhibit 10.15 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1998).
10.3a	Head-lease Agreement dated January 30, 2003 between GlobalSantaFe Drilling Company (North Sea) Limited, as lessor, and Sogelease B.V., as lessee, in respect of the jack-up drilling unit known as “Britannia” (incorporated herein by this reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.3b	Sub-lease Agreement dated January 30, 2003 between Sogelease B.V., as sub-lessor, and GlobalSantaFe Drilling Company (North Sea) Limited, as sub-lessee, in respect of the jack-up drilling unit known as “Britannia” (incorporated herein by this reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.3c	Guarantee and Indemnity dated January 30, 2003 between GlobalSantaFe Corporation, as guarantor, and Sogelease B.V. relating to the jack-up drilling unit known as “Britannia” (incorporated herein by this reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.4	Revolving Credit Agreement dated as of August 15, 2006, among GlobalSantaFe Corporation, the lenders from time to time parties thereto, Citibank, N.A., Wells Fargo Bank, N.A., HSBC Bank USA, National Association and the Royal Bank of Scotland PLC (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on August 18, 2006).
*10.5	Schedule of Compensation for Non-Employee Directors (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on September 21, 2006).
*10.6	Base Salaries and Annual Incentive Targets for Certain Executive Officers (incorporated herein by this reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on December 13, 2006).
*10.7a	2006 Annual Incentive Plan (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed December 20, 2005).
*10.7b	2007 Annual Incentive Plan (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 1, 2007).
*10.8a	Global Marine Inc. 1989 Stock Option and Incentive Plan (incorporated herein by this reference to Exhibit 10.6 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1988); First Amendment (incorporated herein by this reference to Exhibit 10.6 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1990); Second Amendment (incorporated herein by this reference to Exhibit 10.7 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1991); Third Amendment (incorporated herein by this reference to Exhibit 10.19 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1993.); Fourth Amendment (incorporated herein by this reference to Exhibit 10.16 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1994.); Fifth Amendment (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 1996.); Sixth Amendment (incorporated herein by this reference to Exhibit 10.18 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1996).

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*10.8b		Global Marine Inc. 1990 Non-Employee Director Stock Option Plan (incorporated herein by this reference to Exhibit 10.18 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1991); First Amendment (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 1995); Second Amendment (incorporated herein by this reference to Exhibit 10.37 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1996).
*10.8c		1997 Non-Employee Director Stock Option Plan (incorporated herein by this reference to the Company’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997); Amendment to 1997 Non-Employee Director Stock Option Plan (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1998); Amendment to 1997 Non-Employee Director Stock Option Plan (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1998); Amendment to 1997 Non-Employee Director Stock Option Plan dated March 23, 1999 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999); Amendment to Non-Employee Director Stock Option Plan dated December 1, 1999 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999).
*10.8d		1997 Long-Term Incentive Plan (incorporated herein by this reference to the Company’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997); Amendment to 1997 Long Term Incentive Plan (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1998); Amendment to 1997 Long Term Incentive Plan dated December 1, 1999 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999).
*10.8e		GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended March 31, 1998); First Amendment (incorporated herein by this reference to Exhibit 10.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 2000).
*10.8e	(1)	Memorandum dated November 20, 2001, Regarding Grant of Restricted Stock under the GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan, including Terms and Conditions of Restricted Stock (incorporated herein by this reference to Exhibit 10.39 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8e	(2)	Form of Notice of Grant of Stock Options used for stock option grants under the GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan (incorporated herein by this reference to Exhibit 10.41 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8e	(3)	Form of Memorandum dated March 4, 2002, Regarding Grant of Performance-Based Restricted Units under the GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan to certain executive officers of the Company, respectively, including Terms and Conditions of Performance-Based Restricted Units (incorporated herein by this reference to Exhibit 10.40 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8f		GlobalSantaFe Corporation 2001 Non-Employee Director Stock Option and Incentive Plan (incorporated herein by this reference to the Company’s Registration Statement on Form S-8 (No. 333-73878) filed November 21, 2001).
*10.8g		GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
*10.8g	(1)	Form of Notice of Grant of Stock Options used for stock option grants under the GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.41 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

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*10.8g(2)	Form of Memorandum dated March 4, 2002, Regarding Grant of Performance-Based Restricted Units under the GlobalSantaFe Corporation 2001 Long-Term Incentive Plan to certain executive officers of the Company, respectively, including Terms and Conditions of Performance-Based Restricted Units (incorporated herein by this reference to Exhibit 10.40 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8g(3)	Form of Notice of Stock Option Grant to Non-Employee Directors under the GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.10g(3) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
*10.8h	GlobalSantaFe 2003 Long-Term Incentive Plan (as Amended and Restated Effective June 7, 2005) (incorporated herein by this reference to Exhibit 10.4 to the Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
*10.8h(1)	Forms of Memoranda Regarding Grant of Performance Units under the GlobalSantaFe 2003 Long-Term Incentive Plan to certain executive officers of the Company, including terms and conditions for 2003-2005 and 2004-2006 performance cycles (incorporated herein by this reference to Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003).
*10.8h(2)	Form of Notice of Grant of Stock Options for stock option grants under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.37 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003).
*10.8h(3)	Form of Notice of Stock Option Grant used for new stock option grants to non-employee directors under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.38 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003).
*10.8h(4)	Form of Notice of Grant for Non-Employee Director Restricted Stock Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
*10.8h(5)	Form of the Notice of Grant of Stock Options under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on March 2, 2005).
*10.8h(6)	Form of the Notice of Grant of Performance Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on March 2, 2005).
*10.8h(7)	Form of the Notice of Grant of Performance-Awarded Restricted Stock Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 2, 2005).
*10.8h(8)	Form of Notice of Grant of Non-Employee Director Restricted Stock Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.10h(8) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
*10.8h(9)	Form of Notice of Grant of Stock-Settled Stock Appreciation Rights under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2005).
*10.8h(10)	Form of the Notice of Grant and Specification of the Terms and Conditions of Non-Employee Director Stock-Settled Stock Appreciation Rights under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).

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+*10.8h(11)	Form of Notice of Grant of Stock-Settled Stock Appreciation Rights under the GlobalSantaFe 2003 Long-Term Incentive Plan.
*10.9a	GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective January 1, 2001; and Amendment to GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective November 20, 2001 (incorporated herein by this reference Exhibit 10.33 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.9b	Trust Agreement between GlobalSantaFe Corporate Services Inc. and Fidelity Management Trust Company for the GlobalSantaFe Key Employee Deferred Compensation Trust dated as of July 12, 2002 (incorporated herein by this reference Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.10a	GlobalSantaFe Retention Program (As Amended and Restated Effective December 20, 2005) (incorporated herein by this reference Exhibit 10.12a to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
*10.10b	Retention Notice Under GlobalSantaFe Retention Program (incorporated herein by this reference Exhibit 10.12b to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
*10.11a	Employee Severance Protection Plan adopted May 2, 1997 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the fiscal year ended June 30, 1997); Form of Executive Severance Protection Agreement thereunder, effective October 18, 1999, between the Company and fourteen officers, respectively (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999); Amendments to Executive Severance Protection Agreements, dated October 25, 2001, between the Company and three executive officers, respectively (incorporated herein by this reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002).
*10.11b	Form of Severance Agreement dated August 16, 2001, between Global Marine Inc. and six executive officers, respectively (subsequently assumed by the Company) (incorporated herein by this reference to Exhibit 10.4 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended September 30, 2001); Supplemental Agreement to Severance Agreement dated January 20, 2003 by and between Global Marine Inc., GlobalSantaFe Corporation and W. Matt Ralls (incorporated herein by this reference to Exhibit 10.25 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
*10.11c	Form of Severance Agreement dated July 29, 2003, between the Company and three executive officers, respectively (incorporated herein by this reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003).
*10.11d	Form Severance Agreement with Executive Officers (incorporated herein by this reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed with the Commission on July 26, 2005).
*10.11e	GlobalSantaFe Severance Program for Shorebased Staff Personnel effective January 1, 2006, through December 31, 2006 (incorporated herein by this reference to Exhibit 10.13e to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
+*10.11f	GlobalSantaFe Severance Program for Shorebased Staff Personnel effective January 1, 2007, through December 31, 2007.
*10.12	Group Life and Accident and Health Insurance Policy between Aetna Life Insurance Company and GlobalSantaFe effective January 1, 2004 (incorporated herein by this reference to Exhibit 10.42 of GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004).

124

*10.13	Form of GlobalSantaFe Indemnity Agreement (incorporated herein by this reference to Exhibit 10.51 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
*10.14a	GlobalSantaFe Personal Financial Planning Assistance Program for Senior Executive Officers (incorporated herein by this reference to Exhibit 10.44 of GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.14b	GlobalSantaFe Personal Financial Planning Assistance Program for Key Employees (incorporated herein by this reference to Exhibit 10.45 of GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.15a	GlobalSantaFe Supplemental Executive Retirement Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).
+*10.15b	Grantor Trust Agreement under the GlobalSantaFe Supplemental Executive Retirement Plan, effective December 30, 2005.
*10.15c	GlobalSantaFe Pension Equalization Plan effective as of July 1, 2002 (incorporated herein by this reference Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
+*10.15d	Grantor Trust Agreement under the GlobalSantaFe Pension Equalization Plan, effective December 30, 2005.
+12.1	Statement setting forth detail of Computation of Ratios of Earnings to Fixed Charges.
+21.1	List of Subsidiaries.
+23.1	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
+23.2	Consent of Netherland, Sewell & Associates, Inc.
+23.3	Consent of DeGolyer and MacNaughton.
+31.1	Chief Executive Officer’s Certification pursuant to Rule 13a—14(a) of the Securities Exchange Act of 1934.
+31.2	Chief Financial Officer’s Certification pursuant to Rule 13a—14(a) of the Securities Exchange Act of 1934.
+32.1	Chief Executive Officer’s Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
+32.2	Chief Financial Officer’s Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Report regarding estimates of the Company’s proved oil and gas reserves in the United States prepared by Netherland, Sewell & Associates, Inc. (incorporated herein by this reference to Exhibit 99.2 to the Company’s Form 10-K/A amendment to Annual Report on Form 10-K for the year ended December 31, 2004).
99.2	Report regarding estimates of the Company’s proved oil and gas reserves in the United Kingdom prepared by DeGolyer and MacNaughton (incorporated herein by this reference to Exhibit 99.3 to the Company’s Form 10-K/A amendment to Annual Report on Form 10-K for the year ended December 31, 2004).

+ Filed herewith.

* Indicates management contract or compensatory plan or arrangement.

125

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.

	GLOBALSANTAFE CORPORATION (REGISTRANT)
Date: February 28, 2007	By:	/S/    MICHAEL R. DAWSON
		(Michael R. Dawson) Senior Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/S/    JON A. MARSHALL         (Jon A. Marshall)	President, Chief Executive Officer and Director (Principal Executive Officer)	February 28, 2007
/S/    MICHAEL R. DAWSON         (Michael R. Dawson)	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 28, 2007
/S/    ROBERT L. HERRIN, JR.         (Robert L. Herrin, Jr.)	Vice President and Controller (Principal Accounting Officer)	February 28, 2007
/S/    W. RICHARD ANDERSON         (W. Richard Anderson)	Director	February 28, 2007
/S/    FERDINAND A. BERGER         (Ferdinand A. Berger)	Director	February 28, 2007
/S/    THOMAS W. CASON         (Thomas W. Cason)	Director	February 28, 2007
/S/    RICHARD L. GEORGE         (Richard L. George)	Director	February 28, 2007
/S/    EDWARD R. MULLER         (Edward R. Muller)	Director	February 28, 2007
/S/    PAUL J. POWERS         (Paul J. Powers)	Director	February 28, 2007
/S/    ROBERT E. ROSE       (Robert E. Rose)	Director	February 28, 2007
/S/    STEPHEN J. SOLARZ         (Stephen J. Solarz)	Director	February 28, 2007
/S/    CARROLL W. SUGGS         (Carroll W. Suggs)	Director	February 28, 2007
/S/    JOHN L. WHITMIRE         (John L. Whitmire)	Director	February 28, 2007

126

EXHIBIT INDEX

The following are included as exhibits to this Annual Report on Form 10-K (Commission File No. 1-14634). Exhibits filed herewith are so indicated “+”. Exhibit incorporated by reference are so indicated by parenthetical information.

2.1	Agreement and Plan of Merger, dated as of August 31, 2001, among the Company, Silver Sub, Inc., Gold Merger Sub, Inc. and Global Marine Inc. (incorporated herein by this reference to the Company’s Current Report on Form 8-K filed September 4, 2001).
2.2	Purchase Agreement between GlobalSantaFe Corporation, GlobalSantaFe Drilling Venezuela, C.A., GlobalSantaFe Drilling Operations Inc., and Saudi Drilling Company Limited as Seller Parties and Precision Drilling Corporation, P. D. Technical Services Inc., Precision Drilling De Venezuela C.A., Precision Drilling Services Saudi Arabia Ltd., Muscat Overseas Oil & Gas Drilling Co. LLC, and Precision Drilling (Cyprus) Limited as Buyer Parties dated as of April 1, 2004 (incorporated herein by this reference to Exhibit 99.1 to the Company’s Current Report on 8-K filed April 2, 2004).
3.1	Amended and Restated Memorandum of Association of the Company, adopted by Special Resolution of the members effective May 23, 2006 (incorporated herein by this reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Commission on May 25, 2006).
3.2	Amended and Restated Articles of Association of the Company, adopted by Special Resolution of the members effective May 23, 2006 (incorporated herein by this reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the Commission on May 25, 2006).
4.1	Indenture dated as of September 1, 1997, between Global Marine Inc. and Wilmington Trust Company, as Trustee, relating to Debt Securities of Global Marine Inc. (incorporated herein by this reference to Exhibit 4.1 of Global Marine Inc.’s Registration Statement on Form S-4 (No. 333-39033) filed with the Commission on October 30, 1997); First Supplemental Indenture dated as of June 23, 2000 (incorporated herein by this reference to Exhibit 4.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 2000); Second Supplemental Indenture dated as of November 20, 2001 (incorporated herein by this reference to Exhibit 4.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
4.2a	Form of 7% Note Due 2028 (incorporated herein by this reference to Exhibit 4.2 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated May 20, 1998).
4.2b	Terms of 7% Note Due 2028 (incorporated herein by this reference to Exhibit 4.1 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated May 20, 1998).
4.3	Indenture dated as of February 1, 2003, between GlobalSantaFe Corporation and Wilmington Trust Company, as Trustee, relating to Debt Securities of GlobalSantaFe Corporation (incorporated herein by this reference to Exhibit 4.9 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
4.4a	Form of 5% Note due 2013 (incorporated herein by this reference to Exhibit 4.10 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
4.4b	Terms of 5% Note due 2013 (incorporated herein by this reference to Exhibit 4.11 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.1	Bareboat Charter Agreement, dated July 2, 1996, between the United States of America and Global Marine Capital Investments Inc. (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Current Report on Form 8-K (Commission File No. 1-5471) dated August 1, 1996).

10.2a	Head Lease Agreement dated 8th December 1998 by and between BMBF (No. 12) Limited, as lessor, and Global Marine International Drilling Corporation, as lessee, relating to one double hulled, dynamically positioned ultra-deepwater Glomar class 456 drillship to be constructed by Harland and Wolff Shipbuilding and Heavy Industries Ltd. with hull number 1740 (incorporated herein by this reference to Exhibit 10.14 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1998).
10.2b	Deed of Guarantee and Indemnity dated 8th December 1998 by and between Global Marine Inc., as Guarantor, and BMBF (No. 12) Limited, as Lessor (incorporated herein by this reference to Exhibit 10.15 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1998).
10.3a	Head-lease Agreement dated January 30, 2003 between GlobalSantaFe Drilling Company (North Sea) Limited, as lessor, and Sogelease B.V., as lessee, in respect of the jack-up drilling unit known as “Britannia” (incorporated herein by this reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.3b	Sub-lease Agreement dated January 30, 2003 between Sogelease B.V., as sub-lessor, and GlobalSantaFe Drilling Company (North Sea) Limited, as sub-lessee, in respect of the jack-up drilling unit known as “Britannia” (incorporated herein by this reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.3c	Guarantee and Indemnity dated January 30, 2003 between GlobalSantaFe Corporation, as guarantor, and Sogelease B.V. relating to the jack-up drilling unit known as “Britannia” (incorporated herein by this reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
10.4	Revolving Credit Agreement dated as of August 15, 2006, among GlobalSantaFe Corporation, the lenders from time to time parties thereto, Citibank, N.A., Wells Fargo Bank, N.A., HSBC Bank USA, National Association and the Royal Bank of Scotland PLC (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on August 18, 2006).
*10.5	Schedule of Compensation for Non-Employee Directors (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on September 21, 2006).
*10.6	Base Salaries and Annual Incentive Targets for Certain Executive Officers (incorporated herein by this reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on December 13, 2006).
*10.7a	2006 Annual Incentive Plan (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed December 20, 2005).
*10.7b	2007 Annual Incentive Plan (incorporated herein by this reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed with the Commission on February 1, 2007).
*10.8a	Global Marine Inc. 1989 Stock Option and Incentive Plan (incorporated herein by this reference to Exhibit 10.6 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1988); First Amendment (incorporated herein by this reference to Exhibit 10.6 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1990); Second Amendment (incorporated herein by this reference to Exhibit 10.7 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1991); Third Amendment (incorporated herein by this reference to Exhibit 10.19 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1993.); Fourth Amendment (incorporated herein by this reference to

		Exhibit 10.16 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1994.); Fifth Amendment (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 1996.); Sixth Amendment (incorporated herein by this reference to Exhibit 10.18 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1996).
*10.8b		Global Marine Inc. 1990 Non-Employee Director Stock Option Plan (incorporated herein by this reference to Exhibit 10.18 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1991); First Amendment (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 1995); Second Amendment (incorporated herein by this reference to Exhibit 10.37 of Global Marine Inc.’s Annual Report on Form 10-K (Commission File No. 1-5471) for the year ended December 31, 1996).
*10.8c		1997 Non-Employee Director Stock Option Plan (incorporated herein by this reference to the Company’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997); Amendment to 1997 Non-Employee Director Stock Option Plan (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1998); Amendment to 1997 Non-Employee Director Stock Option Plan (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1998); Amendment to 1997 Non-Employee Director Stock Option Plan dated March 23, 1999 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999); Amendment to Non-Employee Director Stock Option Plan dated December 1, 1999 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999).
*10.8d		1997 Long-Term Incentive Plan (incorporated herein by this reference to the Company’s Registration Statement on Form S-8 (No. 333-7070) filed June 13, 1997); Amendment to 1997 Long Term Incentive Plan (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1998); Amendment to 1997 Long Term Incentive Plan dated December 1, 1999 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999).
*10.8e		GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan (incorporated herein by this reference to Exhibit 10.1 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended March 31, 1998); First Amendment (incorporated herein by this reference to Exhibit 10.2 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended June 30, 2000).
*10.8e	(1)	Memorandum dated November 20, 2001, Regarding Grant of Restricted Stock under the GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan, including Terms and Conditions of Restricted Stock (incorporated herein by this reference to Exhibit 10.39 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8e	(2)	Form of Notice of Grant of Stock Options used for stock option grants under the GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan (incorporated herein by this reference to Exhibit 10.41 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8e	(3)	Form of Memorandum dated March 4, 2002, Regarding Grant of Performance-Based Restricted Units under the GlobalSantaFe Corporation 1998 Stock Option and Incentive Plan to certain executive officers of the Company, respectively, including Terms and Conditions of Performance-Based Restricted Units (incorporated herein by this reference to Exhibit 10.40 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

*10.8f		GlobalSantaFe Corporation 2001 Non-Employee Director Stock Option and Incentive Plan (incorporated herein by this reference to the Company’s Registration Statement on Form S-8 (No. 333-73878) filed November 21, 2001).
*10.8g		GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001).
*10.8g	(1)	Form of Notice of Grant of Stock Options used for stock option grants under the GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.41 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8g	(2)	Form of Memorandum dated March 4, 2002, Regarding Grant of Performance-Based Restricted Units under the GlobalSantaFe Corporation 2001 Long-Term Incentive Plan to certain executive officers of the Company, respectively, including Terms and Conditions of Performance-Based Restricted Units (incorporated herein by this reference to Exhibit 10.40 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
*10.8g	(3)	Form of Notice of Stock Option Grant to Non-Employee Directors under the GlobalSantaFe Corporation 2001 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.10g(3) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
*10.8h		GlobalSantaFe 2003 Long-Term Incentive Plan (as Amended and Restated Effective June 7, 2005) (incorporated herein by this reference to Exhibit 10.4 to the Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2005).
*10.8h	(1)	Forms of Memoranda Regarding Grant of Performance Units under the GlobalSantaFe 2003 Long-Term Incentive Plan to certain executive officers of the Company, including terms and conditions for 2003-2005 and 2004-2006 performance cycles (incorporated herein by this reference to Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003).
*10.8h	(2)	Form of Notice of Grant of Stock Options for stock option grants under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.37 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003).
*10.8h	(3)	Form of Notice of Stock Option Grant used for new stock option grants to non-employee directors under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.38 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003).
*10.8h	(4)	Form of Notice of Grant for Non-Employee Director Restricted Stock Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004).
*10.8h	(5)	Form of the Notice of Grant of Stock Options under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the Commission on March 2, 2005).
*10.8h	(6)	Form of the Notice of Grant of Performance Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Commission on March 2, 2005).
*10.8h	(7)	Form of the Notice of Grant of Performance-Awarded Restricted Stock Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Commission on March 2, 2005).
*10.8h	(8)	Form of Notice of Grant of Non-Employee Director Restricted Stock Units under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.10h(8) to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).

*10.8h(9)	Form of Notice of Grant of Stock-Settled Stock Appreciation Rights under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed with the Commission on December 20, 2005).
*10.8h(10)	Form of the Notice of Grant and Specification of the Terms and Conditions of Non-Employee Director Stock-Settled Stock Appreciation Rights under the GlobalSantaFe 2003 Long-Term Incentive Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2006).
+*10.8h(11)	Form of Notice of Grant of Stock-Settled Stock Appreciation Rights under the GlobalSantaFe 2003 Long-Term Incentive Plan.
*10.9a	GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective January 1, 2001; and Amendment to GlobalSantaFe Corporation Key Employee Deferred Compensation Plan effective November 20, 2001 (incorporated herein by this reference Exhibit 10.33 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.9b	Trust Agreement between GlobalSantaFe Corporate Services Inc. and Fidelity Management Trust Company for the GlobalSantaFe Key Employee Deferred Compensation Trust dated as of July 12, 2002 (incorporated herein by this reference Exhibit 10.34 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.10a	GlobalSantaFe Retention Program (As Amended and Restated Effective December 20, 2005) (incorporated herein by this reference Exhibit 10.12a to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
*10.10b	Retention Notice Under GlobalSantaFe Retention Program (incorporated herein by this reference Exhibit 10.12b to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
*10.11a	Employee Severance Protection Plan adopted May 2, 1997 (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the fiscal year ended June 30, 1997); Form of Executive Severance Protection Agreement thereunder, effective October 18, 1999, between the Company and fourteen officers, respectively (incorporated herein by this reference to the Company’s Annual Report on Form 20-F for the calendar year ended December 31, 1999); Amendments to Executive Severance Protection Agreements, dated October 25, 2001, between the Company and three executive officers, respectively (incorporated herein by this reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002).
*10.11b	Form of Severance Agreement dated August 16, 2001, between Global Marine Inc. and six executive officers, respectively (subsequently assumed by the Company) (incorporated herein by this reference to Exhibit 10.4 of Global Marine Inc.’s Quarterly Report on Form 10-Q (Commission File No. 1-5471) for the quarter ended September 30, 2001); Supplemental Agreement to Severance Agreement dated January 20, 2003 by and between Global Marine Inc., GlobalSantaFe Corporation and W. Matt Ralls (incorporated herein by this reference to Exhibit 10.25 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
*10.11c	Form of Severance Agreement dated July 29, 2003, between the Company and three executive officers, respectively (incorporated herein by this reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003).
*10.11d	Form Severance Agreement with Executive Officers (incorporated herein by this reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed with the Commission on July 26, 2005).

*10.11e	GlobalSantaFe Severance Program for Shorebased Staff Personnel effective January 1, 2006, through December 31, 2006 (incorporated herein by this reference to Exhibit 10.13e to the Company’s Annual Report on Form 10-K for the year ended December 31, 2005).
+*10.11f	GlobalSantaFe Severance Program for Shorebased Staff Personnel effective January 1, 2007, through December 31, 2007.
*10.12	Group Life and Accident and Health Insurance Policy between Aetna Life Insurance Company and GlobalSantaFe effective January 1, 2004 (incorporated herein by this reference to Exhibit 10.42 of GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.13	Form of GlobalSantaFe Indemnity Agreement (incorporated herein by this reference to Exhibit 10.51 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).
*10.14a	GlobalSantaFe Personal Financial Planning Assistance Program for Senior Executive Officers (incorporated herein by this reference to Exhibit 10.44 of GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.14b	GlobalSantaFe Personal Financial Planning Assistance Program for Key Employees (incorporated herein by this reference to Exhibit 10.45 of GlobalSantaFe Corporation’s Annual Report on Form 10-K for the year ended December 31, 2004).
*10.15a	GlobalSantaFe Supplemental Executive Retirement Plan (incorporated herein by this reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002).
+*10.15b	Grantor Trust Agreement under the GlobalSantaFe Supplemental Executive Retirement Plan, effective December 30, 2005.
*10.15c	GlobalSantaFe Pension Equalization Plan effective as of July 1, 2002 (incorporated herein by this reference Exhibit 10.35 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).
+*10.15d	Grantor Trust Agreement under the GlobalSantaFe Pension Equalization Plan, effective December 30, 2005.
+12.1	Statement setting forth detail of Computation of Ratios of Earnings to Fixed Charges.
+21.1	List of Subsidiaries.
+23.1	Consent of PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.
+23.2	Consent of Netherland, Sewell & Associates, Inc.
+23.3	Consent of DeGolyer and MacNaughton.
+31.1	Chief Executive Officer’s Certification pursuant to Rule 13a—14(a) of the Securities Exchange Act of 1934.
+31.2	Chief Financial Officer’s Certification pursuant to Rule 13a—14(a) of the Securities Exchange Act of 1934.
+32.1	Chief Executive Officer’s Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
+32.2	Chief Financial Officer’s Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1	Report regarding estimates of the Company’s proved oil and gas reserves in the United States prepared by Netherland, Sewell & Associates, Inc. (incorporated herein by this reference to Exhibit 99.2 to the Company’s Form 10-K/A amendment to Annual Report on Form 10-K for the year ended December 31, 2004).

99.2 Report regarding estimates of the Company’s proved oil and gas reserves in the United Kingdom prepared by DeGolyer and MacNaughton (incorporated herein by this reference to Exhibit 99.3 to the Company’s Form 10-K/A amendment to Annual Report on Form 10-K for the year ended December 31, 2004).

+ Filed herewith.

* Indicates management contract or compensatory plan or arrangement.