UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2007

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

For the transition period from _________ to ________

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

Delaware		76-0321760
(State or other jurisdiction of incorporation		(I.R.S. Employer
or organization)		Identification No.)

15415 Katy Freeway
Houston, Texas
77094
(Address of principal executive offices)
(Zip Code)
(281) 492-5300
(Registrant’s telephone number, including area code)

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

     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 þ       Accelerated Filer o       Non-Accelerated Filer o

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

     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

As of April 25, 2007 Common stock, $0.01 par value per share 138,353,618 shares

 

 

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED MARCH 31, 2007

		PAGE NO.
COVER PAGE			1
TABLE OF CONTENTS			2
PART I. FINANCIAL INFORMATION			3
ITEM 1. Financial Statements (Unaudited)
Consolidated Balance Sheets			3
Consolidated Statements of Operations			4
Consolidated Statement of Stockholders’ Equity			5
Consolidated Statements of Cash Flows			6
Notes to Consolidated Financial Statements			7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			19
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			38
ITEM 4. Controls and Procedures			39
PART II. OTHER INFORMATION			40
ITEM 1A. Risk Factors			40
ITEM 5. Other Information			40
ITEM 6. Exhibits			40
SIGNATURES			41
EXHIBIT INDEX			42
Form of Award Certificate
Rule 13a-14(a) Certification of the CEO
Rule 13a-14(a) Certification of the CFO
Section 1350 Certification of the CEO and CFO

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)
(In thousands, except per share data)

		March 31,				December 31,
		2007				2006
ASSETS
Current assets:
Cash and cash equivalents		$	302,663			$	524,698
Marketable securities			251,120				301,159
Accounts receivable			464,778				567,474
Rig spare parts and supplies			48,980				48,801
Prepaid expenses and other			28,453				39,415
Total current assets			1,095,994				1,481,547
Drilling and other property and equipment, net of accumulated depreciation			2,652,130				2,628,453
Other assets			16,827				22,839
Total assets		$	3,764,951			$	4,132,839
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	74,535			$	122,000
Accrued liabilities			131,348				184,978
Taxes payable			93,878				26,531
Total current liabilities			299,761				333,509
Long-term debt			524,405				964,310
Deferred tax liability			400,428				448,227
Other liabilities			96,011				67,285
Total liabilities			1,320,605				1,813,331
Commitments and contingencies (Note 8)			—				—
Stockholders’ equity:
Common stock (par value $0.01, 500,000,000 shares authorized, 143,264,136 shares issued and 138,347,336 shares outstanding at March 31, 2007; 134,133,776 shares issued and 129,216,976 shares outstanding at December 31, 2006)			1,433				1,341
Additional paid-in capital			1,799,570				1,299,846
Retained earnings			762,197				1,137,151
Accumulated other comprehensive losses			(4,441	)			(4,417	)
Treasury stock, at cost (4,916,800 shares at March 31, 2007 and December 31, 2006)			(114,413	)			(114,413	)
Total stockholders’ equity			2,444,346				2,319,508
Total liabilities and stockholders’ equity		$	3,764,951			$	4,132,839

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)
(In thousands, except per share data)

		Three Months Ended
		March 31,
		2007				2006
Revenues:
Contract drilling		$	589,912			$	434,653
Revenues related to reimbursable expenses			18,272				13,077
Total revenues			608,184				447,730
Operating expenses:
Contract drilling			214,002				174,206
Reimbursable expenses			16,071				11,291
Depreciation and amortization			55,705				49,582
General and administrative			11,966				9,941
Gain on disposition of assets			(1,502	)			(233	)
Total operating expenses			296,242				244,787
Operating income			311,942				202,943
Other income (expense):
Interest income			9,793				8,375
Interest expense			(10,855	)			(6,806	)
Loss on sale of marketable securities			(3	)			(194	)
Other, net			(607	)			2,373
Income before income tax expense			310,270				206,691
Income tax expense			(86,120	)			(61,370	)
Net income		$	224,150			$	145,321
Earnings per share:
Basic		$	1.66			$	1.13
Diluted		$	1.64			$	1.06
Weighted-average shares outstanding:
Shares of common stock			135,286				129,026
Dilutive potential shares of common stock			3,542				9,725
Total weighted-average shares outstanding			138,828				138,751

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

																		Accumulated
										Additional								Other												Total
		Common Stock								Paid-in				Retained				Comprehensive				Treasury Stock								Stockholders’
		Shares				Amount				Capital				Earnings				Losses				Shares				Amount				Equity
January 1, 2007, before adoption of FIN 48			134,133,776			$	1,341			$	1,299,846			$	1,137,151			$	(4,417	)			4,916,800			$	(114,413	)		$	2,319,508
Cumulative effect of adopting FIN 48			—				—				—				(28,422	)			—				—				—				(28,422	)
January 1, 2007			134,133,776				1,341				1,299,846				1,108,729				(4,417	)			4,916,800				(114,413	)			2,291,086
Net income			—				—				—				224,150				—				—				—				224,150
Dividends to stockholders ($4.125 per share)			—				—				—				(570,682	)			—				—				—				(570,682	)
Conversion of long-term debt			8,964,206				91				439,876				—				—				—				—				439,967
Reversal of deferred tax liability related to imputed interest on converted debentures			—				—				50,743				—				—				—				—				50,743
Stock options exercised			166,154				1				5,003				—				—				—				—				5,004
Stock-based compensation, net			—				—				4,102				—				—				—				—				4,102
Gain on investments, net			—				—				—				—				(24	)			—				—				(24	)
March 31, 2007			143,264,136			$	1,433			$	1,799,570			$	762,197			$	(4,441	)			4,916,800			$	(114,413	)		$	2,444,346

The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)
(In thousands)

		Three Months Ended
		March 31,
		2007				2006
Operating activities:
Net income		$	224,150			$	145,321
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			55,705				49,582
Gain on disposition of assets			(1,502	)			(233	)
Loss on sale of marketable securities, net			3				194
Deferred tax provision			2,956				4,947
Accretion of discounts on marketable securities			(3,990	)			(3,602	)
Amortization/write-off of debt issuance costs			8,979				282
Amortization of debt discounts			62				134
Stock-based compensation expense			961				632
Excess tax benefits from stock-based payment arrangements			(2,410	)			(173	)
Deferred income, net			(5,030	)			5,030
Deferred expenses, net			(3,626	)			83
Other items, net			(249	)			1,380
Changes in operating assets and liabilities:
Accounts receivable			102,109				(80,293	)
Rig spare parts and supplies and other current assets			10,766				(1,917	)
Accounts payable and accrued liabilities			(79,733	)			10,203
Taxes payable			70,488				1,640
Net cash provided by operating activities			379,639				133,210
Investing activities:
Capital expenditures			(98,814	)			(165,332	)
Proceeds from sale/involuntary conversion of assets			3,867				474
Proceeds from sale and maturities of marketable securities			896,587				443,519
Purchases of marketable securities			(842,597	)			(789,185	)
Proceeds from settlement of forward contracts			2,423				438
Net cash used by investing activities			(38,534	)			(510,086	)
Financing activities:
Payment of quarterly and special dividends			(570,682	)			(209,723	)
Proceeds from stock options exercised			5,130				786
Excess tax benefits from stock-based payment arrangements			2,410				173
Other			2				—
Net cash used by financing activities			(563,140	)			(208,764	)
Net change in cash and cash equivalents			(222,035	)			(585,640	)
Cash and cash equivalents, beginning of period			524,698				842,590
Cash and cash equivalents, end of period		$	302,663			$	256,950

     The accompanying notes are an integral part of the consolidated financial statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. General Information

     The unaudited consolidated financial statements of Diamond Offshore Drilling, Inc. and subsidiaries, which we refer to as “Diamond Offshore,” “we,” “us” or “our,” should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2006 (File No. 1-13926).

     As of April 25, 2007, Loews Corporation, or Loews, owned 50.7% of the outstanding shares of our common stock.

Interim Financial Information

     The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the U.S., or GAAP, for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission, or SEC. Accordingly, pursuant to such rules and regulations, they do not include all disclosures required by GAAP for complete financial statements. The consolidated financial information has not been audited but, in the opinion of management, includes all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation of the consolidated balance sheets, statements of operations and statements of cash flows at the dates and for the periods indicated. Results of operations for interim periods are not necessarily indicative of results of operations for the respective full years.

Cash and Cash Equivalents, Marketable Securities

     We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.

     We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in “Accumulated other comprehensive gains (losses)” until realized. The cost of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments are included in our Consolidated Statements of Operations in “Interest income.” The sale and purchase of securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific identification method. Realized gains or losses, as well as any declines in value that are judged to be other than temporary, are reported in our Consolidated Statements of Operations in “Other income (expense).”

Derivative Financial Instruments

     Our derivative financial instruments include foreign currency forward exchange contracts and a contingent interest provision that is embedded in our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, issued on April 11, 2001. See Note 4.

Supplementary Cash Flow Information

     We paid interest on long-term debt totaling $12.5 million and $13.1 million for the three months ended March 31, 2007 and 2006, respectively.

     We paid $5.7 million and $53.0 million in U.S. income taxes during the three months ended March 31, 2007 and 2006, respectively. We paid $5.0 million and $0.8 million in foreign income taxes, net of foreign tax refunds, during the three months ended March 31, 2007 and 2006, respectively.

     We recorded income tax benefits of $3.1 million and $0.3 million related to the exercise of employee stock options during the first three months of 2007 and 2006, respectively.

     During the three months ended March 31, 2007, the holders of $438.5 million in aggregate principal amount of our 1.5% Debentures and the holders of $1.5 million accreted value through the date of conversion, or $2.4 million in aggregate principal amount at maturity, of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, elected to convert their outstanding debentures into shares of our common stock. During the three months ended March 31, 2006, the holders of $8.5 million accreted value through the date of conversion, or $13.9 million in aggregate principal amount at maturity, of our Zero Coupon Debentures, and $10,000 in aggregate principal amount of our 1.5% Debentures elected to convert their outstanding debentures into shares of our common stock. See Note 7.

Capitalized Interest

     We capitalize interest cost for the construction and upgrade of qualifying assets. In April 2005 and July 2006, we began capitalizing interest on expenditures related to the upgrades of the Ocean Endeavor and the Ocean Monarch, respectively, for ultra-deepwater service. In December 2005 and January 2006 we began capitalizing interest on expenditures related to the construction of our two jack-up rigs, the Ocean Scepter and Ocean Shield, respectively.

     A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:

		Three Months Ended
		March 31,
		2007				2006
		(In thousands)
Total interest cost including amortization and write-off of debt issuance costs		$	16,284			$	8,388
Capitalized interest			(5,429	)			(1,582	)
Total interest expense as reported		$	10,855			$	6,806

Debt Issuance Costs

     Debt issuance costs are included in our Consolidated Balance Sheets in “Other assets” and are amortized over the respective terms of the related debt. Interest expense for the three months ended March 31, 2007 includes $8.9 million in debt issuance costs that we wrote-off in connection with the conversions of our 1.5% Debentures and Zero Coupon Debentures into shares of our common stock during the three months ended March 31, 2007. See “ – Supplementary Cash Flow Information” and Note 7.

Treasury Stock

     Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We account for the purchase of treasury stock using the cost method, which reports the cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated Balance Sheets. We did not repurchase any shares of our outstanding common stock during the quarters ended March 31, 2007 or 2006.

Comprehensive Income

     A reconciliation of net income to comprehensive income is as follows:

		Three Months Ended
		March 31,
		2007				2006
		(In thousands)
Net income		$	224,150			$	145,321
Other comprehensive gains (losses), net of tax:
Unrealized holding gain on investments			87				43
Reclassification adjustment for gain included in net income			(111	)			—
Comprehensive income		$	224,126			$	145,364

     The tax related to the change in unrealized holding gain on investments was $47,000 and $23,000 for the quarters ended March 31, 2007 and 2006, respectively. The tax effect on the reclassification adjustment for net gains included in net income was $60,000 for the quarter ended March 31, 2007.

Currency Translation

     Our functional currency is the U.S. dollar. Currency translation adjustments and transaction gains and losses, including gains and losses from the settlement of foreign currency forward exchange contracts, are reported as “Other income (expense)” in our Consolidated Statements of Operations. For the three months ended March 31, 2007 and 2006, we recognized net foreign currency exchange losses of $0.6 million and net foreign currency exchange gains of $2.4 million, respectively. See Note 4.

Revenue Recognition

     Revenue from our dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, we may receive lump-sum fees for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the initial term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.

     From time to time, we may receive fees from our customers for capital improvements to our rigs. We defer such fees received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the asset.

     We record reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement, for the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.

Stock-Based Compensation

     Our Second Amended and Restated 2000 Stock Option Plan, or Stock Plan, provides for the issuance of either incentive stock options or non-qualified stock options to our employees, consultants and non-employee directors. Our Stock Plan also authorizes the award of stock appreciation rights, or SARs, in tandem with stock options or separately. Effective January 1, 2006, we adopted the Financial Accounting Standards Board, or FASB, revised Statement of Financial Accounting Standards, or SFAS, No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123 (R), which requires that compensation cost related to share-based payment transactions be recognized in our financial statements. As a result of adopting SFAS 123 (R), “Operating income” and “Income before income

tax expense” for the three months ended March 31, 2007 and 2006 were reduced by $0.9 million and $0.6 million, respectively.

Use of Estimates in the Preparation of Financial Statements

     The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.

Reclassifications

     Certain amounts applicable to the prior periods have been reclassified to conform to the classifications currently followed. Such reclassifications do not affect earnings.

Recent Accounting Pronouncements

     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” or SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. GAAP has required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We are in the process of evaluating the impact, if any, of applying SFAS 159 on our financial statements; however, we do not expect the adoption of SFAS 159 to have a material impact on our consolidated results of operations, financial position or cash flows.

     In September 2006, the FASB issued SFAS No. 158, “Accounting for Defined Benefit Pension or Other Postretirement Plans,” or SFAS 158. SFAS 158 amends existing guidance to require (1) balance sheet recognition of the funded status of defined benefit plans, (2) recognition in other comprehensive income of various items before they are recognized in periodic benefit cost, (3) the measurement date for plan assets and the benefit obligation to be the balance sheet date, and (4) additional disclosures regarding the effects on periodic benefit cost for the following fiscal year arising from delayed recognition in the current period. SFAS 158 also includes guidance regarding selection of assumed discount rates for use in measuring the benefit obligation. SFAS 158 provides different effective dates for various aspects of the new rules. For public companies, requirements to recognize the funded status of the plan and to comply with the disclosure provisions of SFAS 158 are effective as of the end of the fiscal year ending after December 15, 2006, and the requirement to measure plan assets and benefit obligations as of the balance sheet date is effective for fiscal years ending after December 15, 2008. Early adoption of SFAS 158 is encouraged and must be applied to all of an entity’s benefit plans. During the fourth quarter of 2006, we adopted the requirement to recognize the funded status of our defined benefit pension plan, as well as the disclosure provisions. We have not adopted the requirement to measure plan assets and benefit obligations as of the balance sheet date. See Note 11.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” or SFAS 157, which establishes a separate framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 was issued to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS 157 does not require any new fair value measurements; however, its adoption may result in changes to current practice. Changes resulting from the application of SFAS 157 relate to the definition of fair value, the methods used to measure fair value and the expanded disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, rather than an entity-specific measurement. It also establishes a fair value hierarchy that distinguishes between (i) market participant assumptions developed based on market data obtained from independent sources and (ii) the reporting entity’s own assumptions about market participant assumptions developed based on the best information available under the circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, including interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including interim periods. We are in the process of evaluating the impact, if any, of applying SFAS 157 on our financial statements; however, we do not expect the

adoption of SFAS 157 to have a material impact on our consolidated results of operations, financial position or cash flows.

2. Earnings Per Share

     A reconciliation of the numerators and the denominators of our basic and diluted per-share computations follows:

		Three Months Ended
		March 31,
		2007				2006
		(In thousands, except per share data)
Net income – basic (numerator):		$	224,150			$	145,321
Effect of dilutive potential shares
1.5% Debentures			4,021				940
Zero Coupon Debentures			25				128
Net income including conversions – diluted (numerator)		$	228,196			$	146,389
Weighted average shares – basic (denominator):			135,286				129,026
Effect of dilutive potential shares
1.5% Debentures			3,422				9,383
Zero Coupon Debentures			59				180
Stock options			61				162
Weighted average shares including conversions – diluted (denominator)			138,828				138,751
Earnings per share:
Basic		$	1.66			$	1.13
Diluted		$	1.64			$	1.06

     Our computation of diluted earnings per share, or EPS, for the three months ended March 31, 2007 excludes stock options representing 67,464 shares of common stock and 154,600 SARs. Our computation of diluted EPS for the three months ended March 31, 2006 excludes stock options representing 82,350 shares of common stock. The inclusion of such potentially dilutive shares in the computations of diluted EPS would have been antidilutive for the periods presented.

3. Marketable Securities

     We report our investments as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations.

     Our investments in marketable securities are classified as available for sale and are summarized as follows:

		March 31, 2007
		Amortized				Unrealized				Market
		Cost				Gain (Loss)				Value
		(In thousands)
Debt securities issued by the U.S. Treasury and other U.S. government agencies:
Due within one year		$	249,287			$	123			$	249,410
Mortgage-backed securities			1,702				8				1,710
Total		$	250,989			$	131			$	251,120

		December 31, 2006
		Amortized				Unrealized				Market
		Cost				Gain (Loss)				Value
		(In thousands)
Debt securities issued by the U.S. Treasury and other U.S. government agencies:
Due within one year		$	299,252			$	170			$	299,422
Mortgage-backed securities			1,740				(3	)			1,737
Total		$	300,992			$	167			$	301,159

     Proceeds from sales and maturities of marketable securities and gross realized gains and losses are summarized as follows:

		Three Months Ended
		March 31,
		2007				2006
		(In thousands)
Proceeds from sales		$	696,587			$	443,519
Proceeds from maturities			200,000				—
Gross realized gains			42				—
Gross realized losses			(45	)			(194	)

4. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

     Our international operations expose us to foreign exchange risk, primarily associated with our costs payable in foreign currencies, primarily for employee compensation and purchases from foreign suppliers. We utilize foreign exchange forward contracts to reduce our forward exchange risk. A foreign currency forward exchange contract obligates a contract holder to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specified dates.

     During the three months ended March 31, 2007 and 2006, we settled several of our obligations under various foreign currency forward exchange contracts, which resulted in net realized gains totaling $2.4 million and $0.4 million, respectively. As of March 31, 2007, we had foreign currency forward exchange contracts outstanding, which aggregated $8.6 million, that required us to purchase the equivalent of $5.2 million in British pounds sterling and $3.4 million in Mexican pesos at various times through July 2007.

     These forward contracts are derivatives as defined by SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” or SFAS 133. SFAS 133 requires that each derivative be stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for hedge

accounting, the gains and losses are reflected in income in the same period as offsetting losses and gains on the qualifying hedged positions. The forward contracts that we entered into in 2005 through 2007 did not qualify for hedge accounting. In accordance with SFAS 133, we recorded net pre-tax unrealized gains of $0.6 million and $2.1 million in our Consolidated Statements of Operations for the three months ended March 31, 2007 and 2006, respectively, as “Other income (expense)” to adjust the carrying value of these derivative financial instruments to their fair value. We have presented the $0.6 million and $2.6 million fair value of these foreign currency forward exchange contracts at March 31, 2007 and December 31, 2006, respectively, as “Prepaid expenses and other” in our Consolidated Balance Sheets.

Contingent Interest

     Our 1.5% Debentures, of which $21.5 million aggregate principal amount were outstanding as of March 31, 2007, contain a contingent interest provision. The contingent interest component is an embedded derivative as defined by SFAS 133 and accordingly must be split from the host instrument and recorded at fair value on the balance sheet. The contingent interest component had no value at issuance, at December 31, 2006 or at March 31, 2007.

5. Drilling and Other Property and Equipment

     Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:

		March 31,				December 31,
		2007				2006
		(In thousands)
Drilling rigs and equipment		$	3,958,751			$	3,896,585
Construction work-in-progress			475,148				459,824
Land and buildings			18,392				17,353
Office equipment and other			27,985				27,132
Cost			4,480,276				4,400,894
Less: accumulated depreciation			(1,828,146	)			(1,772,441	)
Drilling and other property and equipment, net		$	2,652,130			$	2,628,453

     Construction work-in-progress at March 31, 2007 consisted of $296.7 million, including accrued capital expenditures of $15.3 million, related to the major upgrades of the Ocean Endeavor and Ocean Monarch to ultra-deepwater service and $178.4 million related to the construction of two new jack-up drilling units, the Ocean Scepter and the Ocean Shield. The Ocean Endeavor is currently in transit to the U.S. Gulf of Mexico, or GOM, on board a heavy-lift vessel. We expect the Ocean Endeavor to arrive in the GOM in late May 2007 and commence drilling operations late in the second quarter of 2007. We anticipate that both the Ocean Scepter and Ocean Shield will be delivered late in the first quarter of 2008, and that the upgrade of the Ocean Monarch will be completed in late 2008.

6. Accrued Liabilities

     Accrued liabilities consist of the following:

		March 31,				December 31,
		2007				2006
		(In thousands)
Accrued project/upgrade costs		$	48,351			$	67,308
Payroll and benefits			34,011				42,496
Deferred revenue			10,280				13,794
Personal injury and other claims			7,934				9,934
Interest payable			6,102				11,823
Hurricane related expenses and deferred gains			3,427				8,328
Other			21,243				31,295
Total		$	131,348			$	184,978

7. Long-Term Debt

     Long-term debt consists of the following:

		March 31,				December 31,
		2007				2006
		(In thousands)
Zero Coupon Debentures (due 2020)		$	3,830			$	5,302
1.5% Debentures (due 2031)			21,510				459,967
5.15% Senior Notes (due 2014)			249,526				249,513
4.875% Senior Notes (due 2015)			249,539				249,528
Total		$	524,405			$	964,310

     Certain of our long-term debt payments may be accelerated due to certain rights that the holders of our debt securities have to put the securities to us. The holders of our outstanding 1.5% Debentures and our Zero Coupon Debentures have the right to require us to purchase all or a portion of their outstanding debentures on April 15, 2008 and June 6, 2010, respectively, at a price equal to 100% of the principal amount of the 1.5% Debentures to be purchased plus accrued and unpaid interest to such date and $706.82 per $1,000 principal amount at maturity of our Zero Coupon Debentures, respectively.

     The aggregate maturities of long-term debt for each of the five years subsequent to March 31, 2007 are as follows:

(In thousands)
2007		$	—
2008			21,510
2009			—
2010			3,830
2011			—
Thereafter			499,065
			524,405
Less: Current maturities			—
Total		$	524,405

     Debt Conversions. During the first three months of 2007, the holders of $438.5 million in aggregate principal amount of our 1.5% Debentures and the holders of $1.5 million accreted value through the date of conversion, or $2.4 million in aggregate principal amount at maturity, of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 8,964,206 shares of our common stock pursuant to these conversions in 2007. At March 31, 2007, there was $6.0 million aggregate principal amount at maturity of our Zero Coupon Debentures outstanding.

     As a result of the conversions of our 1.5% Debentures, we reversed a $50.7 million non-current deferred tax liability during the first quarter of 2007 related to interest expense imputed on these debentures for U.S. federal income tax return purposes. See Note 10.

8. Commitments and Contingencies

     Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. In accordance with SFAS No. 5, “Accounting for Contingencies,” we have assessed each claim or exposure to determine the likelihood that the resolution of the matter might ultimately result in an adverse effect on our financial condition, results of operations or cash flows. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a reserve for the estimated loss at the time that both of these criteria are met. Our management believes that we have established adequate reserves for any liabilities that may reasonably be expected to result from these claims.

     Litigation. We are a defendant in a lawsuit filed in January 2005 in the U.S. District Court for the Eastern District of Louisiana on behalf of Total E&P USA, Inc. and several oil companies alleging that our semisubmersible rig, the Ocean America, damaged a natural gas pipeline in the Gulf of Mexico during Hurricane Ivan. The plaintiffs seek damages from us including, but not limited to, loss of revenue, that are currently estimated to be in excess of $100 million, together with interest, attorneys’ fees and costs. We deny any liability for plaintiffs’ alleged loss and do not believe that ultimate liability, if any, resulting from this litigation will have a material adverse effect on our financial condition, results of operations or cash flows. In addition, we have given notice of the claim to our insurance underwriters. Our deductible for this type of claim is $2.0 million.

     We are one of several unrelated defendants in a lawsuit filed in the Circuit Courts of the State of Mississippi alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our offshore drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. We expect to receive complete defense and indemnity from Murphy Exploration & Production Company pursuant to the terms of our 1992 asset purchase agreement with them. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that ultimate liability, if any, resulting from this litigation will have a material adverse effect on our financial condition, results of operations or cash flows.

     Various other claims have been filed against us in the ordinary course of business. In the opinion of our management, no pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

     Other. Our operations in Brazil have exposed us to various claims and assessments related to our personnel, customs duties and municipal taxes, among other things, that have arisen in the ordinary course of business. At March 31, 2007, our reserves related to our Brazilian operations aggregated $14.4 million, of which $0.5 million and $13.9 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. Reserves related to our Brazilian operations totaled $14.2 million at December 31, 2006, of which $0.5 million was recorded in “Accrued liabilities” and $13.7 million was recorded in “Other liabilities” in our Consolidated Balance Sheets.

     We intend to defend these matters vigorously; however, we cannot predict with certainty the outcome or effect of any litigation matters specifically described above or any other pending litigation or claims. There can be no assurance as to the ultimate outcome of these lawsuits.

     Personal Injury Claims. Our deductible for liability coverage for personal injury claims, which primarily results from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence, with no aggregate deductible.

We engage experts to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models. At March 31, 2007, our estimated liability for personal injury claims was $35.5 million, of which $7.9 million and $27.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2006, we had recorded loss reserves for personal injury claims aggregating $35.0 million, of which $9.9 million and $25.1 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

	•		the severity of personal injuries claimed;
	•		significant changes in the volume of personal injury claims;
	•		the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
	•		inconsistent court decisions; and
	•		the risks and lack of predictability inherent in personal injury litigation.

     Purchase Obligations. As of March 31, 2007, we had purchase obligations aggregating approximately $422 million related to the major upgrades of the Ocean Monarch and the Ocean Endeavor and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We anticipate that expenditures related to these shipyard projects will be approximately $245 million and $177 million for the remainder of 2007 and in 2008, respectively. However, the actual timing of these expenditures will vary based on the completion of various construction milestones and the timing of the delivery of equipment, which are beyond our control.

     We had no other purchase obligations for major rig upgrades or any other significant purchase obligations at March 31, 2007, except for those related to our direct rig operations, which arise during the normal course of business.

9. Segments and Geographic Area Analysis

     We manage our business on the basis of one reportable segment, contract drilling of offshore oil and gas wells. Although we provide contract drilling services from different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics among all divisions and locations, including the nature of services provided and the type of customers for such services.

     Revenues from contract drilling services by equipment-type are listed below:

		Three Months Ended
		March 31,
		2007				2006
		(In thousands)
High Specification Floaters		$	246,381			$	164,913
Intermediate Semisubmersibles			223,726				174,065
Jack-ups			119,805				95,675
Total contract drilling revenues			589,912				434,653
Revenues related to reimbursable expenses			18,272				13,077
Total revenues		$	608,184			$	447,730

Geographic Areas

     At March 31, 2007, our drilling rigs were located offshore twelve countries in addition to the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in foreign operations and our results of operations and the value of our foreign assets are affected by fluctuations in foreign currency exchange rates. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.

		Three Months Ended
		March 31,
		2007				2006
		(In thousands)
United States		$	332,244			$	265,955
Foreign:
Europe/Africa			98,461				47,693
Australia/Asia/Middle East			94,310				63,742
South America			51,413				48,859
Mexico			31,756				21,481
Total revenues		$	608,184			$	447,730

10. Income Taxes

     Our net income tax expense or benefit is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned or operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands company which is one of our wholly owned subsidiaries. Earnings from this subsidiary are reinvested internationally and remittance to the U.S. is indefinitely postponed. Consequently, no U.S. tax expense or benefits were recognized on these earnings or losses in 2007 or 2006.

     We recognized income tax expense of $86.1 million on pre-tax income of $310.3 million during the three months ended March 31, 2007 compared to income tax expense of $61.4 million on pre-tax income of $206.7 million for the three months ended March 31, 2006. Our estimated annual effective tax rate was 27.8% as of March 31, 2007 and 29.7% as of March 31, 2006.

     We adopted the provisions of FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes”, or FIN 48, on January 1, 2007. As a result of the implementation of FIN 48, we recognized a long-term tax receivable of $2.6 million and a long-term tax liability of $31.1 million for uncertain tax positions, the net of which was accounted for as a reduction to the January 1, 2007 balance of retained earnings. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

		Long term				Long term				Net Liability
		Tax				Tax				for Uncertain Tax
		Receivable				Payable				Positions
		(In thousands)
Balance at January 1, 2007		$	2,642			$	(31,064	)		$	(28,422	)
Additions based on tax positions related to the current year			155				(838	)			(683	)
Balance at March 31, 2007		$	2,797			$	(31,902	)		$	(29,105	)

     At March 31, 2007, all $29.1 million of the net unrecognized tax benefits would affect the effective tax rate if recognized.

     We record interest related to accrued unrecognized tax benefits in interest expense and recognize penalties associated with uncertain tax positions in our tax expense. During the three months ended March 31, 2007, we recognized $0.4 million of interest expense and $0.2 million of penalty-related tax expense for uncertain tax positions. At March 31, 2007, we had $12.3 million accrued for the payment of interest and penalties in our Consolidated Balance Sheets.

     In several of the international locations in which we operate certain of our wholly owned subsidiaries enter into agreements with other of our wholly owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be charged for providing the services and equipment. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts. Taxing authorities in the various foreign locations in which we operate could apply one of the alternative transfer pricing methodologies that could result in an increase to our income tax liabilities with respect to tax returns that remain subject to examination. During the next 12 months certain income tax returns will no longer be subject to examination. As a result, we anticipate there is a reasonable possibility that the amount of unrecognized tax benefits attributable to transfer pricing methodology differences will decrease by approximately $8 million to $10 million.

     We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions include years 2000 to 2006.

     The Brazilian tax authorities are auditing our income tax returns for the periods 2000 to 2005. We have received an initial audit report for tax year 2000 disallowing various deductions claimed in the tax return. The tax auditors have issued an assessment for tax year 2000 of approximately $1.5 million, including interest and penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal. We do not anticipate that any adjustments resulting from the tax audit will have a material impact on our consolidated results of operations, financial position or cash flows.

     During the three months ended March 31, 2007, the holders of certain of our debentures elected to convert them into shares of our common stock. (See Note 7.) As a result of the conversions of our 1.5% Debentures, we reversed a non-current deferred tax liability of $50.7 million which was accounted for as an increase to “Additional paid-in capital.” The reversal related to interest expense imputed on these debentures for U.S. federal income tax return purposes.

11. Pension Plan

     The defined benefit pension plan established by Arethusa (Off-Shore) Limited, or Arethusa, effective October 1, 1992 was frozen on April 30, 1996. At that date all participants were deemed fully vested in the plan, which covered substantially all U.S. citizens and U.S. permanent residents who were employed by Arethusa.

     As a result of freezing the plan, no service cost has been accrued for the years presented.

     Components of net periodic benefit costs were as follows:

		March 31,
		2007				2006
		(In thousands)
Interest cost		$	284			$	263
Expected return on plan assets			(256	)			(340	)
Amortization of unrecognized loss			70				76
Net periodic pension expense		$	98			$	(1	)

     During the fourth quarter of 2006 we began the process of terminating the plan and have entered into a letter agreement with an insurance company to transfer the responsibility for making payments of plan benefits to the insurance company. Under the terms of the agreement, all of the assets of the plan were transferred in 2006 to the insurance company along with our additional payment of approximately $0.3 million. We are seeking Pension Benefit Guarantee Corporation, or PBGC, approval to terminate the plan which we expect to obtain in the second quarter of 2007. Once termination has been approved by the PBGC, we will enter into an irrevocable contract with the insurance company. The insurance company will issue their annuity certificates to the plan participants, and we will no longer have any benefit liability under the plan.

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

     The following discussion should be read in conjunction with our unaudited consolidated financial statements (including the notes thereto) included elsewhere in this report and our audited consolidated financial statements and the notes thereto, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 1A, “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2006. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

     We are a leader in deep water drilling with a fleet of 44 offshore drilling rigs. Our fleet currently consists of 30 semisubmersibles, 13 jack-ups and one drillship. In addition, we have two jack-up drilling units on order at shipyards in Brownsville, Texas and Singapore. We expect both of these units to be delivered during the first quarter of 2008.

Overview

Industry Conditions

     Worldwide demand for our mid-water (intermediate) and deepwater (high-specification) semisubmersible rigs remained strong during the first quarter of 2007. However, the jack-up market in the U.S. Gulf of Mexico, or GOM, continues to experience reduced demand, resulting in downward pricing pressure and some rigs being ready-stacked for a period of time between wells. As of April 24, 2007, all of our jack-ups in the GOM were on contract, although two of our rigs were ready stacked for a period of time during the first quarter of 2007. Exclusive of the GOM jack-up market, which accounted for 12 percent of our total revenue for the quarter ended March 31, 2007, solid fundamental market conditions remain in place for all classes of offshore drilling rigs worldwide.

     Gulf of Mexico. In the GOM, the market for our semisubmersible equipment remains firm. The dayrate on one of our seven high-specification floaters for which we have received a Letter of Intent, or LOI, is as high as $500,000 for future work in the GOM. However, the pace of contracting for our high-specification rigs has slowed due to the length of our existing agreements, which extend into 2008 or 2009.

     The dayrates for our five intermediate semisubmersibles currently located in the GOM have reached as high as $300,000 for a future three-well contract, and we have also received a six-month contract extension for another of our intermediate semisubmersible rigs at $300,000 per day beginning in the fourth quarter of 2007. We continue to view the deepwater and intermediate markets in the GOM as under-supplied and believe that the GOM semisubmersible market will remain strong in 2007.

     We expect two of our intermediate semisubmersibles, the Ocean New Era and Ocean Voyager, to mobilize from the GOM to the Mexican sector of the Gulf or Mexico, or Mexican GOM, in the third quarter of 2007. The rigs have commitments at dayrates of $265,000 and $335,000, respectively, on approximately 2¹/2-year contracts ending in early 2010. The terms of these drilling contracts with PEMEX Exploración Y Producción, or PEMEX, expose us to greater risks than we normally assume, such as exposure to increased environmental liability and potential early termination. Under the contracts, the dayrate is fixed for the first two years of the term. Thereafter, the dayrate may be adjusted, either up or down, if average dayrates for comparable GOM rigs at the end of the two-year period are at least 30 percent higher or lower than the PEMEX contract terms. We expect the market for the Mexican GOM to remain strong in 2007.

     Our jack-up fleet in the GOM continued to experience lower utilization during the first quarter of 2007, coupled with increasing downward pressure on dayrates, compared to the fourth quarter of 2006. Our jack-up rigs operating in the GOM during the fourth quarter of 2006 earned an average dayrate in the low $100,000 range as compared to an average dayrate in the mid-$90,000 range during the first quarter of 2007. We believe that the current pricing pressure on jack-up rigs in the GOM, which began in the second quarter of 2006, will extend at least through the second quarter of 2007.

     Brazil. Two of our rigs operating in Brazil are currently working under term contracts that expire in 2009, and two additional rigs are operating under contracts expiring in 2010. Petróleo Brasileiro S.A., or Petrobras, is continuing to seek additional intermediate semisubmersible rigs. Late in the first quarter of 2007, we received notification of the award of five-year term contracts for both the Ocean Whittington and the Ocean Yorktown. Under the agreements, the Ocean Whittington is expected to begin work in Brazil during the third quarter of 2007 and the Ocean Yorktown is expected to begin work in the first quarter of 2008. The Ocean Whittington can earn a variable performance bonus in addition to the day rate for a maximum compensation of $258,000 per day,

excluding a lump-sum mobilization fee. The Ocean Yorktown can earn a variable performance bonus in addition to the day rate for a maximum compensation of $269,000 per day, excluding a lump-sum mobilization fee. We expect the Brazilian semisubmersible market to remain strong in 2007.

     North Sea. Effective industry utilization remains at 100 percent in the North Sea where we have three semisubmersible rigs in the United Kingdom, or U.K., and one unit in Norway. Indicating the strength of this market, one of our four rigs in the North Sea received a one-year extension to the unit’s existing term contract late in the first quarter of 2007, which will now employ the rig until the second quarter of 2009. The other three rigs have term contracts that extend into 2010.

     Australia/Asia/Middle East/Mediterranean. We currently have five semisubmersible rigs and one jack-up unit operating in the Australia/Asia market, and two jack-up rigs and one intermediate floater operating in the Middle East/Mediterranean sector. All nine of these rigs are operating under term contracts for work extending into late 2007, 2008 or 2009. We believe that the Australia/Asia and Middle East/Mediterranean markets will remain strong in 2007.

Contract Drilling Backlog

     The following table reflects our contract drilling backlog as of April 24, 2007 and February 19, 2007 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2006) and reflects both firm commitments (typically represented by signed contracts) as well as LOIs. An LOI is subject to customary conditions, including the execution of a definitive agreement. Contract drilling backlog is based on the full contractual dayrate for our drilling rigs and is calculated assuming full utilization of our drilling equipment for the contract period and that one-half of any potential rig performance bonus will be earned. The amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 95-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, unscheduled repairs, maintenance and weather. Our contract backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and assumes that one-half of any potential rig performance bonus will be earned. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. Changes in our contract drilling backlog between periods is a function of both the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.

						February 19,
		April 24, 2007				2007
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters		$	4,058,000			$	4,115,000
Intermediate Semisubmersibles			3,877,000				2,895,000
Jack-ups			454,000				432,000
Total		$	8,389,000			$	7,442,000

     The following table reflects the amount of our contract drilling backlog by year based on our firm commitments and LOIs as of April 24, 2007.

		For the Years Ending December 31,
		Total				2007 (1)				2008				2009				2010 - 2013
		(In thousands)
Contract Drilling Backlog (2)
High-Specification Floaters		$	4,058,000			$	798,000			$	1,194,000			$	882,000			$	1,184,000
Intermediate Semisubmersibles			3,877,000				894,000				1,332,000				968,000				683,000
Jack-ups			454,000				254,000				171,000				29,000				—
Total		$	8,389,000			$	1,946,000			$	2,697,000			$	1,879,000			$	1,867,000

     The following table reflects the percentage of rig days committed by year as of April 24, 2007. The percentage of rig days committed is calculated as the ratio of total days committed under contracts and LOIs and scheduled shipyard and survey days for all rigs in our fleet to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected delivery dates for the Ocean Endeavor, Ocean Monarch, and our two newbuild jack-up rigs, the Ocean Scepter and Ocean Shield.

		For the Years Ending December 31,
		2007 (1)				2008				2009				2010 - 2013
Contract Drilling Backlog
High-Specification Floaters			100	%			91	%			58	%			17	%
Intermediate Semisubmersibles			97	%			70	%			52	%			9	%
Jack-ups			62	%			17	%			3	%			—

General

     Our revenues vary based upon demand, which affects the number of days our fleet is utilized and the dayrates earned. When a rig is idle, no dayrate is earned and revenues will decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher dayrates, we may mobilize our rigs from one market to another. However, during periods of mobilization, revenues may be adversely affected. As a response to changes in demand, we may withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may decrease or increase revenues, respectively.

     The two most significant variables affecting revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs, and vice versa. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political and economic factors. The availability of rigs in a particular geographical region also affects both dayrates and utilization rates. These factors are not within our control and are difficult to predict.

     We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive lump-sum fees for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contracts (which is the period estimated to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.

     From time to time, we may receive fees from our customers for capital improvements to our rigs. We defer such fees and recognize them into income on a straight-line basis over the period of the related drilling contract as a component of contract drilling revenue. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.

     We receive reimbursements for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement. We record these reimbursements at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations included in Item 1 of Part I of this report.

     Operating Income. Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements, inflation and costs associated with labor regulations in the geographic regions in which our rigs operate. We have experienced and continue to experience upward pressure on salaries and wages as a result of the strengthening offshore drilling market and increased competition for skilled workers. In response to these market conditions we have implemented retention programs, including increases in compensation.

     Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and condition of the equipment.

     Operating expenses generally are not affected by changes in dayrates and may not be significantly affected by short-term fluctuations in utilization. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “ready-stacked” state with a full crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operator when a rig is under contract. However, if the rig is to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. We recognize, as incurred, operating expenses related to activities such as inspections, painting projects and routine overhauls that meet certain criteria and which maintain rather than upgrade our rigs. These expenses vary from period to period. Costs of rig enhancements are capitalized and depreciated over the expected useful lives of the enhancements. Higher depreciation expense decreases operating income in periods subsequent to capital upgrades.

     Periods of high, sustained utilization may result in cost increases for maintenance and repairs in order to maintain our equipment in proper, working order. In addition, during periods of high activity and dayrates, higher prices generally pervade the entire offshore drilling industry and its support businesses, which cause our costs for goods and services to increase.

     Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. Operating revenue decreases because these surveys are performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance costs may be required resulting from the survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year.

     In addition, operating income may be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require dry-docking or shipyard time.

     During 2007, we expect to spend an aggregate of approximately $46 million for 5-year surveys and intermediate surveys, including estimated mobilization costs, but excluding any resulting repair and maintenance costs, which could be significant. Costs of mobilizing our rigs to shipyards for scheduled surveys, which were a major component of our survey-related costs during 2006, are indicative of higher prices commanded by support businesses to the offshore drilling industry. We expect mobilization costs to be a significant component of our survey-related costs in 2007. Survey and maintenance costs incurred during the first quarter of 2007 should not be taken as indicative of future quarterly costs for such activities due to schedule changes which postponed some planned surveys.

     We have made arrangements to renew our principal insurance policies effective May 1, 2007. For physical damage coverage, our deductible is $75.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss). For physical damage due to named windstorms in the U.S. Gulf of Mexico, there is an annual aggregate limit of $125.0 million. If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations or cash flows.

     Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with Statement of Financial Accounting Standards, or SFAS, No. 34, “Capitalization of Interest Cost,” or SFAS 34. During 2006 and 2005, we began capitalizing interest on our two capital upgrade

projects and the construction of our two new jack-up rigs. Pursuant to SFAS 34, the period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. In 2006 we began capitalizing interest on expenditures related to the capital upgrade of the Ocean Monarch and the construction of our two jack-up rigs, and in 2005, we began capitalizing interest on expenditures related to the upgrade of the Ocean Endeavor. See Note 1 “General Information – Capitalized Interest” to our consolidated financial statements included in Item 1 of Part I of this report.

     The upgrade of the Ocean Endeavor has been completed and the rig is currently being transported to the GOM from Singapore by a heavy-lift vessel. We have capitalized interest costs related to this upgrade through the end of March 2007. We will begin depreciating the newly upgraded rig effective April 1, 2007. As a result of the scheduled delivery of the Ocean Endeavor, we anticipate that depreciation and interest expense in 2007 will increase by approximately $6 million (representing nine months of expense) and $2.5 million, respectively.

Critical Accounting Estimates

     Our significant accounting policies are discussed in Note 1 of our notes to consolidated financial statements included in Item 1 of Part I of this report and in Note 1 of our notes to audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2006. There were no material changes to these policies during the three months ended March 31, 2007.

Results of Operations

Three Months Ended March 31, 2007 and 2006

     Comparative data relating to our revenues and operating expenses by equipment type are listed below.

		Three Months Ended
		March 31,								Favorable/
		2007				2006				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
High Specification Floaters		$	246,381			$	164,913			$	81,468
Intermediate Semisubmersibles			223,726				174,065				49,661
Jack-ups			119,805				95,675				24,130
Other			—				—				—
Total Contract Drilling Revenue		$	589,912			$	434,653			$	155,259
Revenues Related to Reimbursable Expenses		$	18,272			$	13,077			$	5,195
CONTRACT DRILLING EXPENSE
High Specification Floaters		$	62,234			$	54,093			$	(8,141	)
Intermediate Semisubmersibles			102,751				86,606				(16,145	)
Jack-ups			40,926				32,208				(8,718	)
Other			8,091				1,299				(6,792	)
Total Contract Drilling Expense		$	214,002			$	174,206			$	(39,796	)
Reimbursable Expenses		$	16,071			$	11,291			$	(4,780	)
OPERATING INCOME
High Specification Floaters		$	184,147			$	110,820			$	73,327
Intermediate Semisubmersibles			120,975				87,459				33,516
Jack-ups			78,879				63,467				15,412
Other			(8,091	)			(1,299	)			(6,792	)
Reimbursable expenses, net			2,201				1,786				415
Depreciation			(55,705	)			(49,582	)			(6,123	)
General and administrative expense			(11,966	)			(9,941	)			(2,025	)
Gain on disposition of assets			1,502				233				1,269
Total Operating Income		$	311,942			$	202,943			$	108,999

     Demand remained strong for our rigs in all markets and geographic regions during the first quarter of 2007, except for the jack-up market in the GOM. Continued high overall utilization and historically high dayrates resulted in an increase in our operating income of $109.0 million, or 54%, to $311.9 million, compared to $202.9 million in the first quarter of 2006. Dayrates have generally increased since the first quarter of 2006, resulting in the generation of additional contract drilling revenues by our fleet. However, overall revenue increases were negatively impacted by the effect of downtime associated with scheduled shipyard projects. Total contract drilling revenues during the first quarter of 2007 increased $155.3 million, or 36%, to $589.9 million compared to the same period in 2006.

     Our results in 2006 were also impacted by higher expenses related to our mooring enhancement and other hurricane preparedness activities, wage increases in late 2005 and the first quarter of 2006 and surveys performed during 2006. In addition, overall cost increases for maintenance and repairs between 2007 and 2006 reflect the impact of high, sustained utilization of our drilling units across our fleet and in all geographic locations in which we operate. The increase in overall operating and overhead costs also reflects the impact of higher prices throughout the offshore drilling industry and its support businesses. Total contract drilling expenses in the first quarter of 2007 increased $39.8 million, or 23%, to $214.0 million, compared to the same period in 2006.

High Specification Floaters.

		Three Months Ended
		March 31,								Favorable/
		2007				2006				(Unfavorable)
		(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM		$	194,370			$	119,126			$	75,244
Australia/Asia/Middle East			19,765				14,833				4,932
South America			32,246				30,954				1,292
Total Contract Drilling Revenue		$	246,381			$	164,913			$	81,468
CONTRACT DRILLING EXPENSE
GOM		$	36,637			$	32,509			$	(4,128	)
Australia/Asia/Middle East			5,935				5,202				(733	)
South America			19,662				16,382				(3,280	)
Total Contract Drilling Expense		$	62,234			$	54,093			$	(8,141	)
OPERATING INCOME		$	184,147			$	110,820			$	73,327

     GOM. Revenues generated by our high-specification floaters operating in the GOM increased $75.2 million during the first quarter of 2007 compared to the same period in 2006, primarily due to higher average dayrates earned during the period ($75.1 million). Average operating revenue per day for our rigs in this market increased to $316,100 during the first quarter of 2007 compared to $193,700 for the same period of 2006, reflecting the continued high demand for this class of rig in the GOM, as several of our rigs began operating under new contracts at increased dayrates subsequent to the first quarter of 2006.

     Average utilization for our high-specification rigs operating in the GOM increased slightly from 97% during the first quarter of 2006 to 98% in the first quarter of 2007, and resulted in $1.4 million in additional revenues.

     Operating costs during the first quarter of 2007 for our high-specification floaters in the GOM increased $4.1 million over the same period in 2006. The increase in operating costs during the current year period is primarily from higher labor and benefits costs as a result of wage increases and other compensation enhancement programs implemented late in the first quarter of 2006. Other operating cost increases during the current year period included higher maintenance and project costs for most of our drilling rigs in this market. These operating cost increases were partially offset by the absence of amortized mobilization costs related to the relocation of the Ocean Baroness to the GOM in the latter half of 2005, which were fully recognized in 2006.

     Australia/Asia/Middle East. Revenues generated by the Ocean Rover, the only high specification floater working in the Australia/Asia/Middle East region, increased $4.9 million to $19.8 million in the first quarter of 2007 compared to revenues of $14.8 million for the comparable period in 2006. The increase in revenues generated by this rig is primarily related to an increase in average operating revenue per day from $165,700 in the first quarter of 2006 to $221,000 in the first quarter of 2007, as a result of a new contract that began in the second quarter of 2006.

     Contract drilling expenses for the Ocean Rover increased by $0.7 million for the first three months of 2007 compared to the first three months of 2006, primarily due to higher salary and other personnel-related costs, as well as higher maintenance and project costs.

     South America. Revenues for our high-specification floaters operating offshore Brazil increased $1.3 million to $32.2 million for the first quarter of 2007 compared to $31.0 million for the same period in 2006, primarily due to an improvement in utilization from 94% during the first quarter of 2006 to 98% during the first quarter of 2007. Average operating revenue per day for our rigs in this market was relatively unchanged as these rigs continued to operate under contracts that were renewed in the latter part of 2005.

     Contract drilling expense for our operations in Brazil increased $3.3 million during the first quarter of 2007 compared to the same period in 2006. The increase in costs is primarily due to higher labor and benefits costs as a result of pay increases and other compensation enhancement programs implemented late in the first quarter of 2006 and higher maintenance and project costs.

Intermediate Semisubmersibles.

		Three Months Ended
		March 31,								Favorable/
		2007				2006				(Unfavorable)
		(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM		$	47,755			$	54,003			$	(6,248	)
Mexican GOM			16,120				21,480				(5,360	)
Australia/Asia/Middle East			55,021				35,629				19,392
Europe/Africa			85,663				45,047				40,616
South America			19,167				17,906				1,261
Total Contract Drilling Revenue		$	223,726			$	174,065			$	49,661
CONTRACT DRILLING EXPENSE
GOM		$	18,834			$	15,412			$	(3,422	)
Mexican GOM			13,373				14,805				1,432
Australia/Asia/Middle East			23,503				19,334				(4,169	)
Europe/Africa			32,928				25,390				(7,538	)
South America			14,113				11,665				(2,448	)
Total Contract Drilling Expense		$	102,751			$	86,606			$	(16,145	)
OPERATING INCOME		$	120,975			$	87,459			$	33,516

     GOM. Revenues generated during the first quarter of 2007 by our intermediate semisubmersible fleet decreased $6.2 million compared to the same quarter of 2006 primarily due to a decrease in utilization. Average utilization for our rigs in this market decreased to 60% during the first quarter of 2007 from 99% during the comparable period of 2006, resulting in a $21.3 million reduction in revenues. The decline in utilization during the first three months of 2007 is primarily the result of our relocation of the Ocean Lexington to Egypt from the GOM in the fourth quarter of 2006 and planned downtime for life extension projects during the entire first quarter of 2007 for the Ocean Saratoga and Ocean Whittington (which relocated to the GOM in the third quarter of 2006). Both the Ocean Lexington and Ocean Saratoga realized nearly 100% utilization in the GOM during the first quarter of 2006.

     Higher average dayrates by our rigs in this market during the first quarter of 2007 compared to the same period in 2006 contributed $15.1 million in additional revenues during the first quarter of 2007. Average operating revenue per day for our intermediate semisubmersibles in the GOM increased to $177,100 in the first quarter of 2007, as compared to $121,300 in the first quarter of 2006.

     Contract drilling expense for our operations in the GOM increased $3.4 million during the first quarter of 2007 compared to the same period in 2006, primarily due to costs associated with life extension projects that began during the third quarter of 2006 for the Ocean Whittington and Ocean Saratoga. The increase in operating expenses during the first three months of 2007 was partially offset by the absence of operating costs for the Ocean Lexington as a result of its late 2006 relocation to Egypt.

     Mexican GOM. Revenues generated by our intermediate semisubmersible rigs operating in the Mexican GOM decreased $5.4 million in the first quarter of 2007 compared to the same period of 2006 primarily due to the relocation of the Ocean Whittington to the GOM in July 2006 due to the early cancellation of its contract by PEMEX. Operating costs in the Mexican GOM decreased by $1.4 million in the first quarter of 2007 compared to the first quarter of 2006, primarily due to the absence of operating costs for the Ocean Whittington, partially offset by higher labor, maintenance and other miscellaneous operating costs.

     Australia/Asia/Middle East. Our intermediate semisubmersibles working in the Australia/Asia/Middle East region generated revenues of $55.0 million during the first three months of 2007 compared to revenues of $35.6 million in the comparable period of 2006. The $19.4 million increase in operating revenues was primarily due to an increase in average operating revenue per day from $97,800 in the first quarter of 2006 to $152,400 during the first quarter of 2007 as all but one of our intermediate semisubmersibles in this region were contracted at higher dayrates

during 2007. The increase in average operating revenue per day resulted in the generation of $19.0 million in additional revenues during the first quarter of 2007.

     Contract drilling expense for the Australia/Asia/Middle East region increased $4.2 million for the first quarter of 2007 compared to the first quarter of 2006. The increase in costs is primarily due to higher local labor costs for the Ocean Epoch, which worked offshore Australia during the first quarter of 2007 compared to the same period in 2006 when the rig worked offshore Malaysia. Other cost increases for our rigs operating in this region during the first quarter of 2007, as compared to the same period in 2006, include higher repair and maintenance costs, higher expatriate labor and other personnel-related costs and increased shorebase support costs, partially offset by lower survey and other inspection costs. In addition, during the first three months of 2007, we recognized $0.2 million in deferred mobilization expenses for the Ocean Epoch in connection with its move from Malaysia to Australia in the fourth quarter of 2006. We did not recognize any deferred mobilization expenses during the first three months of 2006.

     Europe/Africa. Operating revenues for our intermediate semisubmersibles working in the Europe/Africa regions increased $40.6 million in the first quarter of 2007 compared to the first quarter of 2006. Overall utilization during the first quarter of 2007 increased primarily due to the relocation of the Ocean Lexington from the GOM to offshore Egypt in the fourth quarter of 2006, which generated $23.8 million in additional revenues in this region.

     An increase in average dayrates for our rigs in these markets contributed $19.1 million in additional revenues during the first quarter of 2007, as compared to the same quarter in 2006. Average operating revenue per day, excluding the Ocean Lexington, increased from $123,000 during the first quarter of 2006 to $178,000 in the first quarter of 2007 primarily due to higher dayrates earned by the Ocean Nomad and Ocean Guardian during the first quarter of 2007 compared to the same period in 2006.

     We also recognized revenues of $1.4 million during the first quarter of 2007 related to the amortization of mobilization and rig modification fees associated with the Ocean Lexington’s contract offshore Egypt. During the first quarter of 2006 we recognized $3.8 million in revenues related to the amortization of lump sum fees received from customers for rig modifications to the Ocean Guardian and Ocean Vanguard.

     Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa markets increased $7.5 million during the first three months of 2007 compared to the first three months of 2006, primarily due to the inclusion of normal operating costs for the Ocean Lexington ($7.1 million). Higher labor and benefits costs during the first three months of 2007 for our rigs operating in the North Sea and higher shorebase support costs are primarily the result of wage increases late in the first quarter of 2006. These cost increases in the first quarter of 2007 were partially offset by lower survey and repair costs in the region.

     South America. Our intermediate semisubmersibles working offshore Brazil generated revenues of $19.2 million in the first quarter of 2007 compared to revenues of $17.9 million in the comparable period of 2006. The increase in operating revenues was primarily the result of an increase in the average operating revenue per day earned by the Ocean Winner as a result of a contract extension in mid-March 2006. Average operating revenue per day for the Ocean Winner increased from $63,900 during the first quarter of 2006 to $114,000 during the first quarter of 2007 and generated $4.0 million in additional revenue. Revenues for the Ocean Yatzy during the first quarter of 2007 were $1.0 million lower than revenues earned during the comparable period of 2006 due to the rig earning less than the contracted drilling rate for a greater number of operating days in 2007.

     Utilization for our rigs offshore Brazil declined from 99% during the first quarter of 2006 to 90% during the first quarter of 2007 due to downtime for repairs to both of our rigs in this region. This downtime reduced revenue by $1.7 million during the first quarter of 2007.

     Operating expenses for the Ocean Yatzy and Ocean Winner increased $2.4 million in the first quarter of 2007, as compared to the same period in 2006, primarily due to increased labor costs for our rig-based personnel as a result of wage increases and other compensation enhancement programs implemented late in the first quarter of 2006, higher shore-based support costs, and higher repair and maintenance costs associated with downtime for repairs to both of rigs in the first quarter of 2007.

Jack-Ups.

		Three Months Ended
		March 31,								Favorable/
		2007				2006				(Unfavorable)
						(In thousands)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM		$	71,847			$	79,748			$	(7,901	)
Mexican GOM			15,636				—				15,636
Australia/Asia/Middle East			19,524				13,281				6,243
Europe/Africa			12,798				2,646				10,152
Total Contract Drilling Revenue		$	119,805			$	95,675			$	24,130
CONTRACT DRILLING EXPENSE
GOM		$	25,338			$	25,124			$	(214	)
Mexican GOM			3,799				—				(3,799	)
Australia/Asia/Middle East			7,561				5,681				(1,880	)
Europe/Africa			4,228				1,403				(2,825	)
Total Contract Drilling Expense		$	40,926			$	32,208			$	(8,718	)
OPERATING INCOME		$	78,879			$	63,467			$	15,412

     GOM. Revenues generated by our jack-up rigs operating in the GOM decreased $7.9 million during the first quarter of 2007 compared to the first quarter of 2006 primarily due to a decline in utilization. Average utilization for our jack-up fleet in the GOM decreased from 97% in the first quarter of 2006 to 88% in the first quarter of 2007, primarily due to the relocation of two of our jack-up rigs to other regions, and the ready-stacking of two other jack-up rigs for a total of 89 days during the first quarter of 2007. We relocated the Ocean Spur to Tunisia (Europe/Africa region) in February 2006 and the Ocean Nugget to the Mexican GOM during the fourth quarter of 2006. The decline in utilization resulted in an $18.3 million reduction in revenues in the first three months of 2007 compared to the same period of 2006. The overall decline in revenues during the first quarter of 2007 was partially offset by the effect of higher average dayrates earned by our jack-ups in the GOM during the first quarter of 2007 compared to the first quarter of 2006. During the first three months of 2007, our average operating revenue per day increased to $101,100 from $86,500 compared to the same period in 2006, generating $10.4 million in additional revenues.

     Contract drilling expense in the GOM during the first quarter of 2007 remained relatively unchanged. Higher labor and support costs, coupled with higher maintenance and repair costs for our rigs in this market were partially offset by reduced costs for the Ocean Spur and the absence of costs for the Ocean Nugget due to their relocation out of the GOM.

     Mexican GOM. The Ocean Nugget, which began operating in the Mexican GOM in the fourth quarter of 2006, generated $15.6 million in revenues during the first quarter of 2007 and incurred contract drilling expenses of $3.8 million. We had no jack-up rigs operating in this market during the first quarter of 2006.

     Australia/Asia/Middle East. Revenues generated by our two jack-up rigs operating in the Australia/Asia/Middle East regions were $19.5 million in the first quarter of 2007 compared to $13.3 million for the same period in 2006. The $6.2 million increase was primarily due to an increase in average operating dayrates. Our average operating revenue per day increased to $117,100 during the first quarter of 2007 from $72,300 in the first quarter of 2006, primarily due to a new contract at a higher dayrate for the Ocean Heritage that began in the second quarter of 2006. The increase in average operating revenue per day in the first three months of 2007 generated $7.5 million in additional revenues and was partially offset by the effect of slightly lower utilization compared to the same period in the prior year ($1.0 million).

     Operating expenses for our two rigs in this market increased $1.9 million during the first quarter of 2007 compared to the first quarter of 2006. The increase in contract drilling expenses is primarily the result of higher repair costs and higher labor and other personnel-related costs incurred during the first three months of 2007.

     Europe/Africa. Our jack-up rig, the Ocean Spur, began operating in this region during March 2006. The increase in revenues generated and contract drilling expenses incurred during the first quarter of 2007 compared to the same period in 2006 is the result of a full quarter of operations for the Ocean Spur in 2007, as compared to only a partial quarter of operations offshore Tunisia in 2006.

Reimbursable expenses, net.

     Revenues related to reimbursable items, offset by the related expenditures for these items, were $2.2 million and $1.8 million for the quarters ended March 31, 2007 and 2006, respectively. Reimbursable expenses include items that we purchase, and/or services we perform, at the request of our customers. We charge our customers for purchases and/or services performed on their behalf at cost, plus a mark-up where applicable. Therefore, net reimbursables fluctuate based on customer requirements, which vary.

General and Administrative Expense.

     We incurred general and administrative expense of $12.0 million in the first quarter of 2007 compared to $9.9 million for the same period in 2006. The $2.1 million increase in overhead costs between the periods was primarily due to an increase in payroll costs resulting from higher salaries and staffing increases.

Interest Income.

     We earned interest income of $9.8 million in the first quarter of 2007 compared to $8.4 million in the same period in 2006. The $1.4 million increase in interest income is primarily the result of the combined effect of slightly higher interest rates earned on higher average cash balances in the 2007 period, as compared to the 2006 period. See “– Liquidity and Capital Requirements” and “– Historical Cash Flows.”

Interest Expense.

     We recorded interest expense for the first quarter of 2007 of $10.5 million, representing a $3.7 million increase in interest cost compared to the same period in 2006. This increase was primarily attributable to $8.9 million in debt issuance costs that we wrote off in the first quarter of 2007 in connection with conversions of our 1.5 % Convertible Senior Debentures Due 2031, or 1.5% Debentures, and Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, into shares of our common stock, partially offset by lower interest cost associated with our 1.5% Debentures and a greater amount of interest capitalized in the first quarter of 2007 related to our major upgrades of the Ocean Endeavor and Ocean Monarch and construction of our two new jack-up drilling rigs. The increase in capitalized interest costs for the first three months of 2007 compared to the same period in 2006 is attributable to an increase in capitalized project costs subsequent to March 31, 2006. See “– Liquidity and Capital Requirements – Debt Conversions.”

Other Income and Expense (Other, net).

     Included in “Other, net” are foreign currency translation adjustments and transaction gains and losses and other income and expense items, among other things, which are not attributable to our drilling operations. The components of “Other, net” fluctuate based on the level of activity, as well as fluctuations in foreign currencies. We recorded other expense, net, of $0.6 million in the first quarter of 2007 and other income, net, of $2.4 million in the first quarter of 2006.

     During the three months ended March 31, 2007 and 2006, we recognized net foreign currency exchange losses of $0.6 million and net foreign currency exchange gains of $2.4 million, respectively.

Income Tax Expense.

     Our net income tax expense or benefit is a function of the mix between our domestic and international pre-tax earnings or losses, respectively, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned or operated, directly or indirectly, by Diamond Offshore International Limited, a Cayman Islands company which is one of our wholly owned subsidiaries. Earnings from this subsidiary are reinvested internationally and remittance to the U.S. is indefinitely postponed. Consequently, no U.S. tax expense or benefits were recognized on these earnings or losses in 2007 or 2006.

     We recognized income tax expense of $86.1 million on pre-tax income of $310.3 million during the three months ended March 31, 2007 compared to income tax expense of $61.4 million on pre-tax income of $206.7 million for the three months ended March 31, 2006. Our estimated annual effective tax rate was 27.8% as of March 31, 2007 and 29.7% as of March 31, 2006.

     We adopted the provisions of Financial Accounting Standards Board, or FASB, Interpretation No. 48, “Accounting for Uncertainty in Income Taxes,” or FIN 48, on January 1, 2007. As a result of the implementation of FIN 48, we recognized a long-term tax receivable of $2.6 million and a long-term tax liability of $31.1 million for uncertain tax positions, the net of which was accounted for as a reduction to the January 1, 2007 balance of retained earnings.

     The Brazilian tax authorities are auditing our income tax returns for the periods 2000 to 2005. We have received an initial audit report for tax year 2000 disallowing various deductions claimed in the tax return. The tax auditors have issued an assessment for tax year 2000 of approximately $1.5 million, including interest and penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal. We do not anticipate that any adjustments resulting from the tax audit will have a material impact on our consolidated results of operations, financial position or cash flows.

     During the three months ended March 31, 2007, the holders of certain of our debentures elected to convert them into shares of our common stock. See “– Liquidity and Capital Requirements – Debt Conversions” and Note 7 “Long-Term Debt” to our consolidated financial statements included in Item 1 of Part I of this report. As a result of the conversions of our 1.5% Debentures, we reversed a non-current deferred tax liability of $50.7 million which was accounted for as an increase to “Additional paid-in capital.” The reversal related to interest expense imputed on these debentures for U.S. federal income tax return purposes.

Sources of Liquidity and Capital Resources

     Our principal sources of liquidity and capital resources are cash flows from our operations and our cash reserves. We also may make use of our $285 million credit facility for cash liquidity. See “ – $285 Million Revolving Credit Facility.” At March 31, 2007, we had $302.7 million in “Cash and cash equivalents” and $251.1 million in “Marketable securities,” representing our investment of cash available for current operations.

     Cash Flows from Operations. We operate in an industry that has been, and we expect to continue to be, extremely competitive and highly cyclical. The dayrates we receive for our drilling rigs and rig utilization rates are a function of rig supply and demand in the marketplace, which is generally correlated with the price of oil and natural gas. Demand for drilling services is dependent upon the level of expenditures by oil and gas companies for offshore exploration and development, a variety of political and economic factors and availability of rigs in a particular geographic region. As utilization rates increase, dayrates tend to increase as well reflecting the lower supply of available rigs, and vice versa. These factors are not within our control and are difficult to predict. For a description of other factors that could affect our cash flows from operations, see “– Overview – Industry Conditions” and “ – Forward-Looking Statements.”

     $285 Million Revolving Credit Facility. In November 2006, we entered into a $285 million syndicated, 5-year senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit.

     Loans under the Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Based on our current credit ratings at March 31, 2007, the applicable margin on LIBOR loans would have been 0.27%.

     The Credit Facility contains customary covenants, including, but not limited to, the maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens, mergers, consolidations, liquidation and dissolution, changes in lines of business, swap agreements, transactions with affiliates and subsidiary indebtedness.

     As of March 31, 2007 and December 31, 2006, there were no amounts outstanding under the Credit Facility.

     Shelf Registration. We have the ability to issue an aggregate of approximately $117.5 million in debt, equity and other securities under a shelf registration statement. In addition, from time to time we may issue up to eight

million shares of common stock which are registered under an acquisition shelf registration statement, after giving effect to the two-for-one stock split we declared in July 1997, in connection with one or more acquisitions by us of securities or assets of other businesses.

Liquidity and Capital Requirements

     Our liquidity and capital requirements are primarily a function of our working capital needs, capital expenditures and debt service requirements. We determine the amount of cash required to meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements and by evaluating our ongoing rig equipment replacement and enhancement programs, including water depth and drilling capability upgrades. We believe that our operating cash flows and cash reserves will be sufficient to meet these capital commitments; however, we will continue to make periodic assessments based on industry conditions. In addition, we may, from time to time, issue debt or equity securities, or a combination thereof, or utilize borrowings under our Credit Facility to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to effect any such issuance of debt and/or equity securities will be dependent on our results of operations, our current financial condition, current market conditions and other factors beyond our control.

     We believe that we have the financial resources needed to meet our business requirements in the foreseeable future, including capital expenditures for rig upgrades and enhancements, as well as our working capital requirements. We anticipate that we will rely primarily on internally generated cash flows to maintain liquidity. From time to time, we may also make use of our Credit Facility for cash liquidity.

Debt Conversions.

     Our 1.5% Debentures and our Zero Coupon Debentures are convertible into shares of our common stock. The 1.5% Debentures are convertible into shares of our common stock at a rate of 20.3978 shares per $1,000 principal amount of the 1.5% Debentures, or $49.02 per share, subject to adjustment in certain circumstances. The Zero Coupon Debentures are convertible into shares of our common stock at a fixed conversion rate of 8.6075 shares of common stock per $1,000 principal amount at maturity of Zero Coupon Debentures, subject to adjustments in certain events. Upon conversion of the 1.5% Debentures we have the right to deliver cash in lieu of shares of our common stock.

     During the first quarter of 2007, the holders of $438.5 million in aggregate principal amount of our 1.5% Debentures and the holders of $1.5 million accreted value through the date of conversion, or $2.4 million in aggregate principal amount at maturity, of our Zero Coupon Debentures elected to convert their outstanding debentures into shares of our common stock. We issued 8,964,206 shares of our common stock pursuant to these conversions during the first three months of 2007. As of March 31, 2007, approximately $21.5 million principal amount of our 1.5% Debentures and $3.8 million aggregate accreted value, or $6.0 million in aggregate principal amount at maturity, of our Zero Coupon Debentures remained outstanding. The cash requirements for the interest payable to holders of our 1.5% Debentures will decrease due to the reduction in the outstanding principal amount.

Purchase Obligations Related to Rig Construction/Modifications.

     Purchase Obligations. As of March 31, 2007, we had purchase obligations aggregating approximately $422 million related to the major upgrades of the Ocean Monarch and the Ocean Endeavor and construction of two new jack-up rigs, the Ocean Scepter and Ocean Shield. We anticipate that expenditures related to these shipyard projects will be approximately $245 million and $177 million for the remainder of 2007 and in 2008, respectively. However, the actual timing of these expenditures will vary based on the completion of various construction milestones and the timing of the delivery of equipment, which are beyond our control.

     We had no other purchase obligations for major rig upgrades or any other significant purchase obligations at March 31, 2007, except for those related to our direct rig operations, which arise during the normal course of business.

Letters of Credit.

     We are contingently liable as of March 31, 2007 in the amount of $126.6 million under certain performance, bid, supersedeas and custom bonds and letters of credit. In 2006, we purchased three of these performance bonds totaling $73.2 million from a related party after obtaining competitive quotes. Agreements relating to approximately $107.3 million of performance bonds can require collateral at any time. As of March 31, 2007, we had not been

required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.

Credit Ratings.

     Our current credit rating is Baa2 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings would result in higher interest rates for borrowings under our Credit Facility and could also result in higher interest rates on future debt issuances.

Capital Expenditures.

     Through March 31, 2007, we have spent an aggregate of $272.8 million in connection with the major upgrades of the Ocean Endeavor and Ocean Monarch. We estimate that we will spend approximately an additional $176 million on these two projects during the remainder of 2007. Modifications to the Ocean Monarch commenced during the summer of 2006, and we expect completion of the project in late 2008. We have completed sea trials for the Ocean Endeavor and the drilling rig is currently in transit to the GOM on board a heavy-lift vessel. We expect the Ocean Endeavor to arrive in the GOM in late May 2007 and commence drilling operations late in the second quarter of 2007 under a four-year contract.

     Our two high-performance, premium jack-up rigs, the Ocean Scepter and the Ocean Shield, are currently under construction in Brownsville, Texas and in Singapore, respectively. We expect the aggregate capitalized cost for the construction of these new units, including drill pipe and capitalized interest, to be approximately $320 million, of which we had spent $178.4 million through March 31, 2007. We expect to spend an additional approximately $69 million during the remainder of 2007 on these two construction projects. We expect delivery of both units late in the first quarter of 2008.

     During the first three months of 2007, we spent approximately $66 million on our continuing rig capital maintenance program (other than rig upgrades and new construction) and to meet other corporate capital expenditure requirements. We expect to spend approximately an additional $240 million during the remainder of 2007 associated with our ongoing rig equipment replacement and enhancement programs. We expect to finance our 2007 capital expenditures through the use of our existing cash balances or internally generated funds. However, from time to time, we may also make use of our Credit Facility for cash liquidity.

Contract Modifications

     In addition to anticipated capital spending for rig upgrades, new construction and in connection with our rig capital maintenance program, we have committed to spend approximately $65 million towards the modification of two of our intermediate semisubmersible rigs, the Ocean Whittington and Ocean Yorktown, in connection with their upcoming contracts in Brazil for Petrobras. These modifications are required to meet contract specifications for each of the drilling rigs.

Off-Balance Sheet Arrangements.

     At March 31, 2007 and December 31, 2006, we had no off-balance sheet debt or other arrangements.

Historical Cash Flows

     The following is a discussion of our historical cash flows from operating, investing and financing activities for the quarters ended March 31, 2007 and 2006.

Net Cash Provided by Operating Activities.

		Three Months Ended March 31,
		2007				2006				Change
		(In thousands)
Net income		$	224,150			$	145,321			$	78,829
Net changes in operating assets and liabilities			103,630				(70,367	)			173,997
Loss on sale of marketable securities			3				194				(191	)
Depreciation and other non-cash items, net			51,856				58,062				(6,206	)
		$	379,639			$	133,210			$	246,429

     Our cash flows from operations in the first three months of 2007 increased $246.4 million or 185% over cash generated by our operating activities in the first three months of 2006. The increase in cash flow from operations in the first three months of 2007 is primarily the result of higher average dayrates earned by our offshore drilling units as a result of an increase in worldwide demand for offshore contract drilling services. This favorable trend on cash flows was augmented by a decrease in cash required to satisfy our working capital requirements, primarily due to a decrease in our trade accounts receivable, as a result of payments received from our customers. We also received $20.0 million in insurance proceeds during the first quarter of 2007 related to the settlement of certain claims arising from the 2005 hurricanes (total insurance proceeds of $21.4 million were received of which $1.4 million is included in net cash used in investing activities). Trade and other receivables generated cash of $102.1 million during the first three months of 2007 as the billing cycle was completed, as compared to an $80.3 million usage of cash during the comparable period of 2006.

Net Cash Used in Investing Activities.

		Three Months Ended March 31,
		2007				2006				Change
		(In thousands)
Purchase of marketable securities		$	(842,597	)		$	(789,185	)		$	(53,412	)
Proceeds from sale of marketable securities			896,587				443,519				453,068
Capital expenditures			(98,814	)			(165,332	)			66,518
Proceeds from sale/involuntary conversion of assets			3,867				474				3,393
Proceeds from settlement of forward contracts			2,423				438				1,985
		$	(38,534	)		$	(510,086	)		$	471,552

     Our investing activities used $38.5 million during the first three months of 2007 compared to $510.1 million during the comparable period of 2006. During the first three months of 2007, we sold marketable securities, net of sales, of $54.0 million compared to net purchases of $345.7 million during the three months ended March 31, 2006. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets.

     During the first three months of 2007, we spent approximately $32.8 million related to the major upgrades of the Ocean Endeavor and Ocean Monarch and construction of our two new jack-up drilling rigs in addition to $66.0 million related to our ongoing capital maintenance program. During the first three months of 2006, we spent $128.4 million in connection with long-term construction projects (primarily towards the upgrade of the Ocean Endeavor) and an additional $36.9 million on projects associated with our ongoing capital maintenance program. See “– Liquidity and Capital Requirements – Capital Expenditures.”

     As of March 31, 2007, we had foreign currency forward exchange contracts outstanding, which aggregated $8.6 million, that require us to purchase the equivalent of $5.2 million in British pounds sterling and $3.4 million in Mexican pesos at various times through July 2007.

Net Cash Used in Financing Activities.

		Three Months Ended March 31,
		2007				2006				Change
		(In thousands)
Payment of quarterly and special dividends		$	(570,682	)		$	(209,723	)		$	(360,959	)
Proceeds from stock options exercised			5,130				786				4,344
Other			2,412				173				2,239
		$	(563,140	)		$	(208,764	)		$	(354,376	)

     During the first three months of 2007, we paid cash dividends totaling $570.7 million (consisting of an aggregate quarterly cash dividend of $17.3 million, or $0.125 per share of our common stock, and a special cash dividend of $4.00 per share of our common stock, totaling $553.4 million). Our Board of Directors may, in subsequent years, consider paying additional annual special dividends, in amounts to be determined, if it believes that our financial position, earnings outlook, capital spending plans and other relevant factors warrant such action at that time. During the first three months of 2006, we paid cash dividends totaling $209.7 million (consisting of an aggregate quarterly cash dividend of $16.1 million, or $0.125 per share of our common stock, and a special cash dividend of $1.50 per share of our common stock, totaling $193.6 million).

     On April 23, 2007, we declared a quarterly cash dividend of $0.125 per share of our common stock, payable on June 1, 2007 to stockholders of record on May 4, 2007. Any future determination as to payment of quarterly dividends will be made at the discretion of our Board of Directors.

     Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. During the three months ended March 31, 2007 and 2006, we did not repurchase any shares of our outstanding common stock.

Other

     Currency Risk. Some of our subsidiaries conduct a portion of their operations in the local currency of the country where they conduct operations. Foreign countries in which we have significant business operations include Mexico, Brazil, the U.K., Australia and Malaysia. When possible, we attempt to minimize our currency exchange risk by seeking international contracts payable in local currency in amounts equal to our estimated operating costs payable in local currency with the balance of the contract payable in U.S. dollars. At present, however, only a limited number of our contracts are payable both in U.S. dollars and the local currency.

     We also utilize foreign exchange forward contracts to reduce our forward exchange risk. A forward currency exchange contract obligates a contract holder to exchange predetermined amounts of specified foreign currencies at specified foreign exchange rates on specific dates.

     We record currency translation adjustments and transaction gains and losses as “Other income (expense)” in our Consolidated Statements of Operations. The effect on our results of operations from these translation adjustments and transaction gains and losses has not been material and we do not expect them to have a significant effect in the future.

Recent Accounting Pronouncements

     In February 2007, the FASB issued Statement of Financial Accounting Standards, or SFAS, No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” or SFAS 159, which provides companies with an option to report selected financial assets and liabilities at fair value and establishes presentation and disclosure requirements to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. Generally accepted accounting principles, or GAAP, have required different measurement attributes for different assets and liabilities that can create artificial volatility in earnings. The objective of SFAS 159 is to help mitigate this type of volatility in the earnings by enabling companies to report related assets and liabilities at fair value, which would likely reduce the need for companies to comply with complex hedge accounting provisions. SFAS 159 is effective for fiscal years beginning after November 15, 2007. We are in the process of evaluating the impact, if any, of applying SFAS 159 on our financial statements; however, we do not expect the adoption of SFAS 159 to have a material impact on our consolidated results of operations, financial position or cash flows.

     In September 2006, the FASB issued SFAS No. 158, “Accounting for Defined Benefit Pension or Other Postretirement Plans,” or SFAS 158. SFAS 158 amends existing guidance to require (1) balance sheet recognition of the funded status of defined benefit plans, (2) recognition in other comprehensive income of various items before they are recognized in periodic benefit cost, (3) the measurement date for plan assets and the benefit obligation to be the balance sheet date, and (4) additional disclosures regarding the effects on periodic benefit cost for the following fiscal year arising from delayed recognition in the current period. SFAS 158 also includes guidance regarding selection of assumed discount rates for use in measuring the benefit obligation. SFAS 158 provides different effective dates for various aspects of the new rules. For public companies, requirements to recognize the funded status of the plan and to comply with the disclosure provisions of SFAS 158 are effective as of the end of the fiscal year ending after December 15, 2006, and the requirement to measure plan assets and benefit obligations as of the balance sheet date is effective for fiscal years ending after December 15, 2008. Early adoption of SFAS 158 is encouraged and must be applied to all of an entity’s benefit plans. During the fourth quarter of 2006, we adopted the requirement to recognize the funded status of our defined benefit pension plan, as well as the disclosure provisions. We have not adopted the requirement to measure plan assets and benefit obligations as of the balance sheet date. See Note 11 “Pension Plan” to our consolidated financial statements included in Item 1 of Part I of this report.

     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” or SFAS 157, which establishes a separate framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS 157 was issued to eliminate the diversity in practice that exists due to the different definitions of fair value and the limited guidance for applying those definitions in GAAP that are dispersed among the many accounting pronouncements that require fair value measurements. SFAS 157 does not require any new fair value measurements; however, its adoption may result in changes to current practice. Changes resulting from the application of SFAS 157 relate to the definition of fair value, the methods used to measure fair value and the expanded disclosures about fair value measurements. SFAS 157 emphasizes that fair value is a market-based measurement, rather than an entity-specific measurement. It also establishes a fair value hierarchy that distinguishes between (i) market participant assumptions developed based on market data obtained from independent sources and (ii) the reporting entity’s own assumptions about market participant assumptions developed based on the best information available under the circumstances. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, including interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including interim periods. We are in the process of evaluating the impact, if any, of applying SFAS 157 on our financial statements; however, we do not expect the adoption of SFAS 157 to have a material impact on our consolidated results of operations, financial position or cash flows.

Forward-Looking Statements

     We or our representatives may, from time to time, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. Statements made by us in this report that contain forward-looking statements include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

	•		future market conditions and the effect of such conditions on our future results of operations (see “– Overview — Industry Conditions”);
	•		future uses of and requirements for financial resources (see “– Sources of Liquidity and Capital Resources” and “– Liquidity and Capital Requirements”);
	•		interest rate and foreign exchange risk (see “– Liquidity and Capital Requirements– Credit Ratings,” “ – Other” and “Quantitative and Qualitative Disclosures About Market Risk”);
	•		future contractual obligations (see “—Overview—Industry Conditions” and “– Liquidity and Capital Requirements”);
	•		future operations outside the United States including, without limitation, our operations in Mexico (see “—Overview— Industry Conditions”);
	•		business strategy;
	•		growth opportunities;

	•		competitive position;
	•		expected financial position;
	•		future cash flows;
	•		future quarterly or special dividends (see “ – Historical Cash Flows”);
	•		financing plans;
	•		tax planning;
	•		budgets for capital and other expenditures (see “– Liquidity and Capital Requirements”);
	•		timing and cost of completion of rig upgrades and other capital projects (see “– Liquidity and Capital Requirements”);
	•		delivery dates and drilling contracts related to rig construction and upgrade projects (see “—Liquidity and Capital Requirements”);
	•		plans and objectives of management;
	•		performance of contracts (see “— Overview— Industry Conditions”);
	•		outcomes of legal proceedings;
	•		compliance with applicable laws; and
	•		adequacy of insurance or indemnification (see “— Overview—General”) .

     These types of statements inherently are subject to a variety of assumptions, risks and uncertainties that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following:

	•		general economic and business conditions;
	•		worldwide demand for oil and natural gas;
	•		changes in foreign and domestic oil and gas exploration, development and production activity;
	•		oil and natural gas price fluctuations and related market expectations;
	•		the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing, and the level of production in non-OPEC countries;
	•		policies of the various governments regarding exploration and development of oil and gas reserves;
	•		advances in exploration and development technology;
	•		the political environment of oil-producing regions;
	•		casualty losses;
	•		operating hazards inherent in drilling for oil and gas offshore;
	•		industry fleet capacity;
	•		market conditions in the offshore contract drilling industry, including dayrates and utilization levels;
	•		competition;
	•		changes in foreign, political, social and economic conditions;
	•		risks of international operations, compliance with foreign laws and taxation policies and expropriation or nationalization of equipment and assets;
	•		risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;
	•		the risk that an LOI may not result in a definitive agreement;
	•		foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;
	•		risks of war, military operations, other armed hostilities, terrorist acts and embargoes;
	•		changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness;
	•		regulatory initiatives and compliance with governmental regulations;
	•		compliance with environmental laws and regulations;
	•		customer preferences;
	•		effects of litigation;
	•		cost, availability and adequacy of insurance;
	•		adequacy of our sources of liquidity;
	•		the availability of qualified personnel to operate and service our drilling rigs; and
	•		various other matters, many of which are beyond our control.

     The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the Securities and Exchange Commission include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place

undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

     The information included in this Item 3 is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Forward-Looking Statements” in Item 2 of Part I of this report.

     Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at March 31, 2007 and December 31, 2006 assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results which may occur.

     Exposure to market risk is managed and monitored by senior management. Senior management approves the overall investment strategy that we employ and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling instruments or entering into offsetting positions.

Interest Rate Risk

     We have exposure to interest rate risks arising from changes in the level or volatility of interest rates. Our investments in marketable securities are primarily in fixed maturity securities. We monitor our sensitivity to interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on stockholders’ equity. The analysis presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over a one-year period.

     The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on March 31, 2007 and December 31, 2006, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.

     The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes of market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.

     Loans under our $285 million syndicated, 5-year senior unsecured revolving Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. As of March 31, 2007 and December 31, 2006, there were no amounts outstanding under the Credit Facility.

     Our long-term debt, as of March 31, 2007 and December 31, 2006, is denominated in U.S. dollars. Our debt has been primarily issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $41.6 million and $270.8 million as of March 31, 2007 and December 31, 2006, respectively. A 100 basis point decrease would result in an increase in market value of $32.1 million and $33.0 million as of March 31, 2007 and December 31, 2006, respectively.

Foreign Exchange Risk

     Foreign exchange risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. We entered into various forward exchange contracts during 2006 and in the first

three months of 2007 requiring us to purchase predetermined amounts of foreign currencies at predetermined rates. As of March 31, 2007, we had foreign currency forward exchange contracts outstanding, which aggregated $8.6 million, that required us to purchase the equivalent of $5.2 million in British pounds sterling and $3.4 million in Mexican pesos at various times through July 2007.

     These forward exchange contracts were included in “Prepaid expenses and other” in our Consolidated Balance Sheets at March 31, 2007 at fair value in accordance with SFAS No. 133, “Accounting for Derivatives and Hedging Activities.”

     The sensitivity analysis below assumes an instantaneous 20% change in foreign currency exchange rates versus the U.S. dollar from their levels at March 31, 2007 and December 31, 2006.

     The following table presents our market risk by category (interest rates and foreign currency exchange rates):

		Fair Value Asset (Liability)								Market Risk
		March 31,				December 31,				March 31,				December 31,
Category of risk exposure:		2007				2006				2007				2006
						(In thousands)
Interest rate:
Marketable securities		$	251,120	(a)		$	301,159	(a)		$	300	(c)		$	400	(c)
Long-term debt			(517,479	)(b)			(1,231,689	)(b)			—				—
Foreign Exchange:
Forward exchange contracts			600	(d)			2,600	(d)			4,200	(d)			7,400	(d)

ITEM 4. Controls and Procedures.

     Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of our last fiscal quarter that ended on March 31, 2007. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2007 to ensure that required information is disclosed on a timely basis in our reports filed or furnished under the Exchange Act.

     There was no change in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that occurred during the first fiscal quarter of 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1A. Risk Factors.

     Our Annual Report on Form 10-K for the year ended December 31, 2006 includes a detailed discussion of certain material risk factors facing our company. The information presented below describes updates and additions to such risk factors and should be read in conjunction with the risk factors and information disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006.

     The risk factor in our Annual Report on Form 10-K for the year ended December 31, 2006 captioned “We have significantly increased our insurance deductibles and have elected to self-insure for a portion of our liability exposure and for physical damage to rigs and equipment caused by named windstorms in the GOM.” is amended and restated in its entirety as follows:

     We are self-insured for a portion of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico.

     We have made arrangements to renew our principal insurance policies effective May 1, 2007. For physical damage due to named windstorms in the U.S. Gulf of Mexico, our deductible is $75.0 million per occurrence (or lower for some rigs if they are declared a constructive total loss) with an annual aggregate limit of $125.0 million. Accordingly, our insurance coverage for all physical damage to our rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico for the policy period ending April 30, 2008 is limited to $125.0 million. If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations or cash flows.

ITEM 5. Other Information.

     Under the Diamond Offshore Management Bonus Program, our Board’s Executive Committee is authorized to establish an annual bonus pool based on the committee’s evaluation of our company during the year relative to peer companies, the performance of our share price and extraordinary events during the year. As discussed in our definitive proxy statement for our 2007 annual meeting of stockholders, the Executive Committee did establish such a bonus pool for 2006 and paid bonuses under our Management Bonus Program to some of our executive officers. Certain of our executive officers also received bonuses for 2006 under our Incentive Compensation Plan for Executive Officers, in addition to amounts paid under our Management Bonus Program. In February 2007, we paid the executive officers named below the following bonuses for 2006 under our Management Bonus Program:

Name and Title		Bonus Amount
Lawrence R. Dickerson		$	92,800
President and Chief Operating Officer
Gary T. Krenek			200,000
Chief Financial Officer and Senior Vice President
John L. Gabriel, Jr.			76,029
Senior Vice President – Contracts & Marketing
John M. Vecchio			86,534
Senior Vice President – Technical Services

ITEM 6. Exhibits.

     See the Exhibit Index for a list of those exhibits filed or furnished herewith.

SIGNATURES