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

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

Commission file number 1-13926

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
      Yes þ       No o

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

Large accelerated filer þ		Accelerated filer o
Non-accelerated filer o		Smaller reporting company o
(Do not check if a smaller reporting company)

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
      Yes 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 July 24, 2009		Common stock, $0.01 par value per share		139,003,798 shares

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2009

		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 Statements of Cash Flows			5
Notes to Consolidated Financial Statements			6
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			20
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			41
ITEM 4. Controls and Procedures			43
PART II. OTHER INFORMATION			44
ITEM 4. Submission of Matters to a Vote of Security Holders			44
ITEM 6. Exhibits			44
SIGNATURES			45
EXHIBIT INDEX			46
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except per share data)

		June 30,				December 31,
		2009				2008
ASSETS
Current assets:
Cash and cash equivalents		$	470,428			$	336,052
Marketable securities			200,920				400,592
Accounts receivable, net of provision for bad debts			736,518				574,842
Prepaid expenses and other current assets			150,052				123,046
Assets held for sale			32,201				32,201
Total current assets			1,590,119				1,466,733
Drilling and other property and equipment, net of accumulated depreciation			3,918,052				3,414,373
Long-term receivable			17,157				—
Other assets			83,205				73,325
Total assets		$	5,608,533			$	4,954,431
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	66,004			$	93,982
Accrued liabilities			315,932				329,526
Taxes payable			46,627				85,579
Current portion of long-term debt			4,107				—
Total current liabilities			432,670				509,087
Long-term debt			998,562				503,280
Deferred tax liability			501,745				462,026
Other liabilities			129,371				118,553
Total liabilities			2,062,348				1,592,946
Commitments and contingencies (Note 11)			—				—
Stockholders’ equity:
Common stock (par value $0.01, 500,000,000 shares authorized, 143,920,598 shares issued and 139,003,798 shares outstanding at June 30, 2009 and 143,917,850 shares issued and 139,001,050 shares outstanding at December 31, 2008)			1,439				1,439
Additional paid-in capital			1,960,534				1,957,041
Retained earnings			1,694,755				1,516,908
Accumulated other comprehensive income			3,870				510
Treasury stock, at cost (4,916,800 shares at June 30, 2009 and December 31, 2008)			(114,413	)			(114,413	)
Total stockholders’ equity			3,546,185				3,361,485
Total liabilities and stockholders’ equity		$	5,608,533			$	4,954,431

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

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share data)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Revenues:
Contract drilling		$	923,458			$	936,626			$	1,779,166			$	1,706,966
Revenues related to reimbursable expenses			22,949				17,746				52,961				33,508
Total revenues			946,407				954,372				1,832,127				1,740,474
Operating expenses:
Contract drilling			304,853				273,436				602,600				558,443
Reimbursable expenses			22,431				17,346				52,146				32,534
Depreciation			85,431				70,803				170,493				139,995
General and administrative			16,166				15,768				32,481				31,490
Gain on disposition of assets			(93	)			(226	)			(148	)			(277	)
Total operating expenses			428,788				377,127				857,572				762,185
Operating income			517,619				577,245				974,555				978,289
Other income (expense):
Interest income			1,190				2,941				1,766				7,314
Interest expense			(11,288	)			(1,895	)			(12,405	)			(3,237	)
Foreign currency transaction gain			13,733				12,574				9,608				14,441
Other, net			(416	)			(86	)			651				(248	)
Income before income tax expense			520,838				590,779				974,175				996,559
Income tax expense			(133,398	)			(174,615	)			(238,154	)			(289,888	)
Net income		$	387,440			$	416,164			$	736,021			$	706,671
Income per share:
Basic		$	2.79			$	2.99			$	5.30			$	5.09
Diluted		$	2.79			$	2.99			$	5.29			$	5.08
Weighted-average shares outstanding:
Shares of common stock			139,002				138,959				139,001				138,916
Dilutive potential shares of common stock			79				124				72				152
Total weighted-average shares outstanding			139,081				139,083				139,073				139,068

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)

		Six Months Ended
		June 30,
		2009				2008
Operating activities:
Net income		$	736,021			$	706,671
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			170,493				139,995
(Gain) on disposition of assets			(148	)			(277	)
(Gain) loss on sale of marketable securities, net			(599	)			3
(Gain) on foreign currency forward exchange contracts			(8,837	)			(17,150	)
Deferred tax provision			37,910				22,715
Accretion of discounts on marketable securities			(503	)			(838	)
Amortization/write-off of debt issuance costs			274				304
Amortization of debt discounts			134				120
Stock-based compensation expense			3,376				3,209
Excess tax benefits from stock-based payment arrangements			—				(1,081	)
Deferred income, net			66,716				2,113
Deferred expenses, net			(2,257	)			(4,650	)
Long-term receivable			(17,157	)			—
Other items, net			6,619				5,019
Changes in operating assets and liabilities:
Accounts receivable			(166,449	)			(150,283	)
Prepaid expenses and other current assets			(25,108	)			(17,731	)
Accounts payable and accrued liabilities			(49,073	)			(69,834	)
Taxes payable			(46,014	)			(24,219	)
Net cash provided by operating activities			705,398				594,086
Investing activities:
Capital expenditures			(226,284	)			(319,879	)
Rig acquisition			(460,000	)			—
Proceeds from disposition of assets, net of disposal costs			453				1,131
Deposits received on sale of rig			6,000				—
Proceeds from sale and maturities of marketable securities			3,198,829				650,022
Purchases of marketable securities			(2,998,780	)			(649,107	)
(Cost of) proceeds from settlement of foreign currency forward exchange contracts			(28,862	)			7,496
Net cash used in investing activities			(508,644	)			(310,337	)
Financing activities:
Issuance of 5.875% senior unsecured notes			499,255				—
Debt issuance costs and arrangement fees			(3,752	)			—
Payment of dividends			(558,036	)			(382,648	)
Proceeds from stock plan exercises			155				1,510
Excess tax benefits from stock-based payment arrangements			—				1,081
Redemption of 1.5% debentures			—				(73	)
Net cash used in financing activities			(62,378	)			(380,130	)
Net change in cash and cash equivalents			134,376				(96,381	)
Cash and cash equivalents, beginning of period			336,052				637,961
Cash and cash equivalents, end of period		$	470,428			$	541,580

     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, 2008 (File No. 1-13926).

     As of July 24, 2009, Loews Corporation, or Loews, owned 50.4% 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.

     Our management has evaluated subsequent events through July 28, 2009.

Adoption of FSP APB 14-1.

     We adopted Financial Accounting Standards Board, or FASB, Staff Position, or FSP, Accounting Principles Board, or APB, No. 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (including Partial Cash Settlement)”, or FSP APB 14-1, on January 1, 2009. FSP APB 14-1 applies to convertible debt securities that may be settled by the issuer fully or partially in cash and requires that the statement be retrospectively applied to all past periods presented. For convertible debt securities falling within the scope of FSP APB 14-1, issuers must separate the securities into two components: debt and equity. The proceeds of the issuance are first allocated to the debt based on the estimated fair value of a similar debt issue without a conversion option; the remaining proceeds are allocated to equity.

     Both our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, and our 1.5% Convertible Senior Debentures Due 2031, or 1.5% Debentures, are within the scope of FSP APB 14-1. Consequently, we retrospectively applied the requirements of the pronouncement to both of these issuances. The effect of adoption on our Consolidated Balance Sheets is as follows:

		Zero Coupon Debentures								1.5% Debentures								Total
		June 30,				December 31,				June 30,				December 31,				June 30,				December 31,
		2009				2008				2009				2008				2009				2008
		(In thousands)
Increase (Decrease):
Drilling and other property and equipment, net		$	6,256			$	6,429			$	9,046			$	9,240			$	15,302			$	15,669
Deferred tax liability			1,049				1,080				1,709				1,741				2,758				2,821
Additional paid-in capital			48,997				48,997				62,701				62,701				111,698				111,698
Retained earnings			(43,790	)			(43,648	)			(55,364	)			(55,202	)			(99,154	)			(98,850	)

     The effect of the adoption of FSP APB 14-1 on our Consolidated Statements of Operations is as follows:

		Zero Coupon Debentures																1.5% Debentures																Total
		June 30																June 30																June 30
		Three Months								Six Months								Three Months								Six Months								Three Months								Six Months
		2009				2008				2009				2008				2009				2008				2009				2008				2009				2008				2009				2008
		(In thousands)
Increase (Decrease):
Depreciation expense		$	86			$	69			$	173			$	139			$	97			$	73			$	194			$	145			$	183			$	142			$	367			$	284
Tax expense			(15	)			(12	)			(31	)			(24	)			(16	)			(12	)			(32	)			(23	)			(31	)			(24	)			(63	)			(47	)
Income from continuing operations			(71	)			(57	)			(142	)			(115	)			(81	)			(61	)			(162	)			(122	)			(152	)			(118	)			(304	)			(237	)
Net income			(71	)			(57	)			(142	)			(115	)			(81	)			(61	)			(162	)			(122	)			(152	)			(118	)			(304	)			(237	)

     Debt discounts related to our Zero Coupon Debentures and 1.5% Debentures were fully amortized in 2005 and 2007, respectively. Consequently, the adoption of FSP APB 14-1 had no effect on the carrying amount of our Zero Coupon Debentures at June 30, 2009 and December 31, 2008. Our then outstanding 1.5% Debentures were redeemed in full in April 2008.

     The carrying amounts of the liability and equity components of the debentures at June 30, 2009 and December 31, 2008 is as follows:

		Zero Coupon Debentures								1.5% Debentures								Total
		June 30,				December 31,				June 30,				December 31,				June 30,				December 31,
		2009				2008				2009				2008				2009				2008
		(In thousands)
Carrying amount of liability component of debt issue		$	4,107			$	4,036			$	—			$	—			$	4,107			$	4,036
Carrying amount of equity component of debt issue		$	48,997			$	48,997			$	62,701			$	62,701			$	111,698			$	111,698

     Interest expense (net of capitalized interest) for our Zero Coupon Debentures related to the contractual coupon rate was $36,000 and $7,000 for the three months ended June 30, 2009 and 2008, respectively, with an effective interest rate of 3.63% in each period. Interest expense (net of capitalized interest) for our Zero Coupon Debentures related to the contractual coupon rate was $72,000 and $12,000 for the six months ended June 30, 2009 and 2008, respectively, with an effective interest rate of 3.63% in each period. Interest expense (net of capitalized interest) for the 1.5% Debentures related to the contractual coupon interest rate was $16,000 and $17,000 for the three months and six months ended June 30, 2008, respectively. The effective interest rate for the 1.5% Debentures was 1.6% for the three months ended June 30, 2008. See Note 10.

     The adoption of FSP APB 14-1 resulted in a $0.01 per share decline in basic and diluted earning per share for the three months ended June 30, 2008, from $3.00 per share to $2.99 per share. The adoption of FSP APB 14-1 had no effect on previously stated basic and diluted earnings per share for the six months ended June 30, 2008. As required, our consolidated financial statements and notes thereto have been adjusted to reflect the effect of adoption of FSP APB 14-1 on January 1, 2009.

Other Reclassifications

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

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. See Note 5.

     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, net.”

Fair Value of Financial Instruments

     We believe that the carrying amount of our current financial instruments approximates fair value because of the short maturity of these instruments. For non-current financial instruments we use quoted market prices, when available, and discounted cash flows to estimate fair value.

     We have adopted FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments,” which requires disclosures about fair value of financial instruments for interim reporting periods as well as in annual financial statements. See Note 5.

Supplementary Cash Flow Information

     We paid interest on long-term debt totaling $12.5 million and $12.6 million for the six months ended June 30, 2009 and 2008, respectively.

     We made estimated U.S. federal income tax payments of $140.0 million and $235.0 million during the six months ended June 30, 2009 and 2008, respectively. We paid $106.1 million and $62.1 million in foreign income taxes, net of foreign tax refunds, during the six months ended June 30, 2009 and 2008, respectively.

     Capital expenditures for the six months ended June 30, 2009 included $59.4 million that were accrued but unpaid at December 31, 2008. Capital expenditures for the six months ended June 30, 2008 included $43.0 million that were accrued but unpaid at December 31, 2007. Capital expenditures that were accrued but not paid as of June 30, 2009 totaled $47.6 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at June 30, 2009.

     We recorded income tax benefits of $2,000 and $1.3 million related to employee stock plan exercises during the six months ended June 30, 2009 and 2008, respectively.

Capitalized Interest

     We capitalize interest cost for the construction and upgrade of qualifying assets. There were no qualifying expenditures during the six months ended June 30, 2009. During the six months ended June 30, 2008, we capitalized interest on qualifying expenditures related to the upgrade of the Ocean Monarch for ultra-deepwater service (completed December 2008) and the construction of our two jack-up rigs, the Ocean Shield (completed May 2008) and the Ocean Scepter (completed August 2008).

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

		Three Months				Six Months
		Ended				Ended
		June 30, 2008
		(In thousands)
Total interest cost including amortization of debt issuance costs		$	7,186			$	14,052
Capitalized interest			(5,291	)			(10,815	)
Total interest expense as reported		$	1,895			$	3,237

Assets Held For Sale

     At December 31, 2008, we had transferred the $32.2 million net book value of the Ocean Tower to “Assets held for sale” in our Consolidated Balance Sheets. In December 2008, we entered into an agreement to sell the rig, which was damaged during a hurricane in September 2008, at a price in excess of its $32.2 million carrying value. In connection with the execution of the sales agreement, and amendments thereto, we received $9.5 million in aggregate deposits ($3.5 million in 2008 and $6.0 million in 2009) from the purchaser, which we have recorded in

“Accrued liabilities” in our Consolidated Balance Sheets. We expect to complete the sale in the third quarter of 2009.

     We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

	•		dayrate by rig;
	•		utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);
	•		the per day operating cost for each rig if active, ready-stacked or cold-stacked; and
	•		salvage value for each rig.

Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various combinations of assumed utilization rates and dayrates.

     As of June 30, 2009, we evaluated the Ocean Tower and our three mat-supported jack-up rigs (Ocean Champion, Ocean Crusader and Ocean Drake), which had been cold-stacked during the second quarter of 2009, for impairment. The Ocean Tower has a pending sales agreement for a price in excess of its carrying value (see “ — Assets Held For Sale”) and is not considered to be impaired. We evaluated our three cold-stacked rigs for impairment using the probability-weighted cash flow analysis discussed above. Based on these analyses, we determined that the probability-weighted cash flows exceeded the carrying value of each rig.

     Management’s assumptions are an inherent part of our asset impairment evaluation and the use of different assumptions could produce results that differ from those reported.

Comprehensive Income

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands)
Net income		$	387,440			$	416,164			$	736,021			$	706,671
Other comprehensive gains (losses), net of tax:
Unrealized holding gain on forward exchange contracts			3,831				—				3,831				—
Unrealized holding gain on investments			9				9				36				18
Reclassification adjustment for gain included in net income			(14	)			—				(507	)			—
Comprehensive income		$	391,266			$	416,173			$	739,381			$	706,689

     The tax related to the change in unrealized holding gains on investments was approximately $5,000 and $19,000 for the three months and six months ended June 30, 2009. The tax effect on the reclassification adjustment for net gains included in net income was approximately $8,000 and $273,000 for the three and six months ended June 30, 2009, respectively. The tax related to the change in unrealized holding gains on our forward exchange contracts was approximately $2.1 million for the three months and six months ended June 30, 2009.

     The tax related to the change in unrealized holding gains on investments was approximately $5,000 and $10,000 for the three months and six months ended June 30, 2008, respectively.

Foreign Currency

     Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses, including gains and losses on our foreign currency forward exchange contracts not designated as accounting hedges, are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. For the three and six months ended June 30, 2009, we recognized net foreign currency exchange gains of $13.7 million and $9.6 million,

respectively. For the three and six months ended June 30, 2008, we recognized net foreign currency exchange gains of $12.5 million and $14.4 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 fees (either lump-sum or dayrate) 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 as incurred.

     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.

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.

2. Earnings Per Share

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands, except per share data)
Net income — basic (numerator):		$	387,440			$	416,164			$	736,021			$	706,671
Effect of dilutive potential shares
1.5% Debentures			—				10				—				11
Zero Coupon Debentures			24				5				46				8
Net income including conversions — diluted (numerator)		$	387,464			$	416,179			$	736,067			$	706,690
Weighted average shares — basic (denominator):			139,002				138,959				139,001				138,916
Effect of dilutive potential shares
1.5% Debentures			—				5				—				38
Zero Coupon Debentures			52				52				52				52
Stock options and SARs			27				67				20				62
Weighted average shares including conversions — diluted (denominator)			139,081				139,083				139,073				139,068
Earnings per share:
Basic		$	2.79			$	2.99			$	5.30			$	5.09
Diluted		$	2.79			$	2.99			$	5.29			$	5.08

     Our computation of diluted earnings per share, or EPS, for the three months ended June 30, 2009 excludes stock options representing 8,000 shares of common stock and 449,652 stock appreciation rights, or SARs. Our computation of EPS for the six months ended June 30, 2009 excludes stock options representing 15,704 shares of common stock and 466,029 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the periods presented.

     Our computation of diluted EPS for the three and six months ended June 30, 2008 excludes 140,607 and 149,178 SARs, respectively. The inclusion of such potentially dilutive shares in the computation 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. See Note 5.

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

		June 30, 2009
		Amortized				Unrealized				Market
		Cost				Gain				Value
		(In thousands)
Due within one year		$	199,988			$	2			$	199,990
Mortgage-backed securities			872				58				930
Total		$	200,860			$	60				$200,920

		December 31, 2008
		Amortized				Unrealized				Market
		Cost				Gain				Value
		(In thousands)
Due within one year		$	398,791			$	758			$	399,549
Mortgage-backed securities			1,016				27				1,043
Total		$	399,807			$	785				$400,592

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands)
Proceeds from sales		$	999,886			$	99,992			$	2,448,829			$	100,022
Proceeds from maturities			750,000				250,000				750,000				550,000
Gross realized gains			36				—				768				—
Gross realized losses			(34	)			(2	)			(169	)			(3	)

4. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

     Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. We may utilize foreign currency forward exchange contracts to reduce our forward exchange risk. Our foreign currency forward exchange contracts may obligate us to exchange predetermined amounts of foreign currencies on specified dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for certain of our contracts, is the average spot rate for the contract period.

     We enter into foreign currency forward exchange contracts when we believe market conditions are favorable to purchase contracts for future settlement with the expectation that such contracts, when settled, will reduce our exposure to foreign currency gains/losses on foreign currency expenditures in the future. The amount and duration

of such contracts is based on our monthly forecast of expenditures in the significant currencies in which we do business and for which there is a financial market (i.e., Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner). These forward contracts are derivatives as defined by Statement of Financial Accounting Standards, or 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. For derivative contracts entered into prior to May 2009, we did not seek hedge accounting treatment under SFAS 133. Accordingly, prior to May 2009, all adjustments to record the carrying value of our derivative financial instruments at fair value were reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.

     Realized gains or losses upon settlement of the derivative contracts not designated as cash flow hedges are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. During the six months ended June 30, 2009, we settled foreign currency exchange contracts with an aggregate notional value of approximately $214.6 million.

     Beginning in May 2009, we began a hedging strategy and designated certain of our qualifying foreign currency forward exchange contracts as cash flow hedges pursuant to SFAS 133. These hedges are expected to be highly effective, and therefore, , adjustments to record the carrying value of the effective portion of our derivative financial instruments to their fair value is recorded as a component of “Accumulated other comprehensive income,” or AOCI, in our Consolidated Financial Statements. The effective portion of the cash flow hedge will remain in AOCI until it is reclassified into earnings in the period or periods during which the hedged transaction affects earnings or it is determined that the hedged transaction will not occur. Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to fair value are recorded as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.

     Realized gains or losses upon settlement of derivative contracts designated as cash flow hedges will be reported as a component of “Contract drilling expense” in our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our expenditures in local foreign currencies in the countries in which we operate. We did not settle any forward exchange contracts designated as cash flow hedges during the three and six months ended June 30, 2009.

     As of June 30, 2009, we had foreign currency exchange contracts outstanding, in the aggregate notional amount of $125.0 million, consisting of $33.3 million in Australian dollars, $34.4 million in Brazilian reais, $30.4 million in British pounds sterling, $6.9 million in Mexican pesos and $20.0 million in Norwegian kroner. These contracts generally settle monthly through February 2010. As of June 30, 2009, all outstanding derivative contracts had been designated as cash flow hedges, except for derivative contracts with a notional amount aggregating $3,6 million in British pounds sterling and $2.4 million in Norwegian kroner. See Note 5.

     The following table presents the fair values of our derivative financial instruments at June 30, 2009.

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

(In thousands)

(In thousands)

Derivatives designated as hedging instruments under SFAS 133:

Foreign currency forward           exchange contracts

Prepaid expenses and      other current assets

$

6,406

Accrued liabilities

$

(243

)

Derivatives not designated as hedging instruments under SFAS 133:

Foreign currency forward           exchange contracts

Prepaid expenses and      other current assets

$

130

$

—

     The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated Statements of Operations related to our foreign currency forward exchange contracts designated as cash flow hedges under SFAS 133 for each of the three and six month periods ended June 30, 2009.

						Location of Gain
		Location of Gain				Recognized in Income		Amount of Gain
		(Loss)				on Derivative		Recognized in Income on
Amount of Gain		Reclassified from		Amount of Gain (Loss)		(Ineffective Portion		Derivative (Ineffective
Recognized in AOCI		AOCI into Income		Reclassified from		and Amount Excluded		Portion and Amount
on Derivative		(Effective		AOCI into Income		from Effectiveness		Excluded from
(Effective Portion)		Portion)		(Effective Portion)		Testing)		Effectiveness Testing)
(In thousands)								(In thousands)
$     5,894		n/a		$     —		Foreign currency      transaction gain		$	269

     The following table presents the amounts recognized in our Consolidated Statements of Operations related to our foreign currency forward exchange contracts not designated as hedging instruments under SFAS 133 for the three and six month periods ended June 30, 2009 and 2008.

		Amount of Gain Recognized in Income
		Three Months Ended June 30,								Six Months Ended June 30,
Location of Gain (Loss) Recognized in Income		2009				2008				2009				2008
		(In thousands)
Foreign currency transaction gain		$	8,594			$	15,027			$	8,568			$	17,150

     The amounts presented in the table above include unrealized gains of $12.6 million and $37.4 million for the three months and six months ended June 30, 2009, respectively, to record the carrying value of our derivative financial instruments to their fair value. The amounts presented in the table above include unrealized gains of $8.3 million and $9.5 million for the three months and six months ended June 30, 2008, respectively, to record the carrying value of our derivative financial instruments to their fair value.

5. Financial Instruments and Fair Value Disclosures

Concentrations of Credit and Market Risk

     Financial instruments which potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including mortgage-backed securities. We place our excess cash investments in high quality short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.

     Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies and government-owned oil companies. In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may appear uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements.

     In December 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected balance of one of our customers in the United Kingdom, or U.K., that has entered into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy). We also provide allowances for potential credit losses when necessary. In addition, during the first three months of 2009, we recorded a $3.2 million provision for bad debts related to receivables owed by one of our customers in the U.S. Gulf of Mexico that is experiencing credit problems; however, we subsequently collected $0.6 million of these previously reserved amounts and reversed a corresponding portion of the provision for bad debts.

     No additional allowances were deemed necessary for the periods presented. Prior to December 2008, we have not experienced significant losses on our trade receivables.

     A majority of our investments in debt securities are U.S. government securities with minimal credit risk. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.

Fair Values

     The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents, marketable securities, accounts receivable, forward exchange contracts and accounts payable approximate fair value. Fair values and related carrying values of our debt instruments are shown below:

		June 30, 2009								December 31, 2008
		Fair Value				Carrying Value				Fair Value				Carrying Value
		(In millions)
Zero Coupon Debentures		$	4.3			$	4.1			$	3.0			$	4.0
4.875% Senior Notes			254.1				249.6				230.0				249.6
5.15% Senior Notes			246.0				249.7				237.0				249.6
5.875% Senior Notes			491.6				499.3				—				—

     We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of June 30, 2009 and December 31, 2008, respectively. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange. The following methods and assumptions were used to estimate the fair value of each class of financial instrument for which it was practicable to estimate that value:

	•		Cash and cash equivalents — The carrying amounts approximate fair value because of the short maturity of these instruments.
	•		Marketable securities — The fair values of the debt securities, including mortgage-backed securities, available for sale were based on the quoted closing market prices on June 30, 2009 and December 31, 2008, respectively.
	•		Accounts receivable and accounts payable — The carrying amounts approximate fair value based on the nature of the instruments.
	•		Forward exchange contracts — The fair value of our foreign currency forward exchange contracts is based on both quoted market prices and valuations derived from pricing models on June 30, 2009 and December 31, 2008, respectively.
	•		Long-term debt — The fair value of our Zero Coupon Debentures is based on the closing market price of our common stock on June 30, 2009 and December 31, 2008, respectively, and the stated conversion rate for the debentures. The fair values of our 4.875% Senior Notes due 2015 and 5.15% Senior Notes due 2014 are based on the quoted closing market prices on June 30, 2009 and December 31, 2008, respectively, from brokers of these instruments. The fair value of our 5.875% Senior Notes due 2019 is based on the quoted market price on June 30, 2009 from brokers of this instrument.

     Effective January 1, 2008, we adopted SFAS No. 157, “Fair Value Measurements,” or SFAS 157, which requires additional disclosures about our assets and liabilities that are measured at fair value. SFAS 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. SFAS 157 also establishes a fair value hierarchy which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The standard describes three levels of inputs that may be used to measure fair value:

Level 1		Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds and U.S. Treasury Bills. Our Level 1 assets at June 30, 2009 included $443.0 million in cash held in money market funds and $200.0 million of investments in U.S. Treasury Bills.

Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 assets and liabilities include mortgage-backed securities and over-the-counter foreign currency forward exchange contracts that are valued using a model-derived valuation technique.

Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

Assets and liabilities measured at fair value on a recurring basis are summarized below:

		June 30, 2009
		Fair Value Measurements Using
		Level 1				Level 2				Level 3				Fair Value
		(In thousands)
Assets:
Short-term investments		$	642,977			$	—			$	—			$	642,977
Residential mortgage-backed securities			—				930				—				930
Forward exchange contracts			—				6,536				—				6,536
Total assets		$	642,977			$	7,466			$	—			$	650,443
Liabilities:
Forward exchange contracts		$	—			$	(243	)		$	—			$	(243	)

		December 31, 2008
		Fair Value Measurements Using
		Level 1				Level 2				Level 3				Fair Value
		(In thousands)
Assets:
Short-term investments		$	700,038			$	—			$	—			$	700,038
Residential mortgage-backed securities			—				1,043				—				1,043
Total assets		$	700,038			$	1,043			$	—			$	701,081
Liabilities:
Forward exchange contracts		$	—			$	(37,301	)		$	—			$	(37,301	)

6. Prepaid Expenses and Other Current Assets

     Prepaid expenses and other current assets consist of the following:

		June 30,				December 31,
		2009				2008
		(In thousands)
Rig spare parts and supplies		$	52,541			$	52,481
Deferred mobilization costs			24,138				28,924
Prepaid insurance			24,982				11,845
Deferred tax assets			9,350				9,350
Foreign currency forward exchange contracts			6,536				—
Deposits			4,136				3,846
Prepaid taxes			25,437				11,589
Other			2,932				5,011
Total		$	150,052			$	123,046

7. Drilling and Other Property and Equipment

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

		June 30,				December 31,
		2009				2008
		(In thousands)
Drilling rigs and equipment		$	6,275,825			$	5,600,306
Land and buildings			31,806				35,069
Office equipment and other			35,936				34,021
Cost			6,343,567				5,669,396
Less: accumulated depreciation			(2,425,515	)			(2,255,023	)
Drilling and other property and equipment, net		$	3,918,052			$	3,414,373

     In June 2009, we acquired the Ocean Courage, a newbuild, dynamically positioned, semisubmersible drilling rig, for $460.0 million, exclusive of final commissioning and initial mobilization costs, drill string and other necessary capital spares.

8. Long-term Receivable

     During the second quarter of 2009, one of our customers sought short-term financial relief with respect to an existing contractual agreement with us for a six-well, one-year minimum contract term, program that began in May 2009. As a result, we agreed to amend our existing contract with this customer, and in consideration of this amendment, we will receive a $20,000 per day increase in the total contractual operating dayrate, to a total of $560,000 per day, for a minimum of the first 240 days of the initial one-year contract. Under the terms of the amended agreement, the customer is obligated to pay us $75,000 per day in accordance with our normal credit terms (due 30 days after receipt of invoice). The remainder of the dayrate for the six well program (minimum of 240 days) will be paid through the conveyance of a 27% net profit interest, or NPI, in three developmental oil-and-gas producing properties covering six wells owned by the customer. Based on the current production payout estimate, we anticipate that the first payment from the conveyance of the NPI will commence in early 2010. Payment of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices. At June 30, 2009, the $17.2 million portion of this trade receivable, which is expected to be paid from the NPI, is presented as “Long-term Receivable” in our Consolidated Balance Sheets.

9. Accrued Liabilities

     Accrued liabilities consist of the following:

		June 30,				December 31,
		2009				2008
		(In thousands)
Accrued maintenance/capital projects		$	92,172			$	106,135
Deferred revenue			85,063				39,307
Payroll and benefits			59,482				69,326
Rig operating expenses			27,318				30,056
Interest payable			15,036				10,385
Personal injury and other claims			10,146				10,489
Hurricane related expenses			3,219				5,080
Foreign currency forward exchange contracts			243				37,301
Other			23,253				21,447
Total		$	315,932			$	329,526

10. Long-Term Debt

     Long-term debt consists of the following:

		June 30,				December 31,
		2009				2008
		(In thousands)
Zero Coupon Debentures (due 2020)		$	4,107			$	4,036
5.15% Senior Notes (due 2014)			249,652				249,623
4.875% Senior Notes (due 2015)			249,646				249,621
5.875% Senior Notes (due 2019)			499,264				—
			1,002,669				503,280
Less: Current maturities			(4,107	)			—
Total		$	998,562			$	503,280

     At June 30, 2009, there was $6.0 million aggregate principal amount at maturity, or $4.1 million accreted, or carrying, value, of our Zero Coupon Debentures outstanding.

     5.875% Senior Notes

     On May 4, 2009, we issued $500.0 million aggregate principal amount of our 5.875% Senior Notes Due May 1, 2019, or 5.875% Senior Notes, for general corporate purposes. The 5.875% Senior Notes were issued at an offering price of 99.851% of the principal and resulted in net proceeds to us of approximately $495.5 million.

     The notes bear interest at 5.875% per year, payable semiannually in arrears on May 1 and November 1 of each year, beginning November 1, 2009, and mature on May 1, 2019. The 5.875% Senior Notes are unsecured and unsubordinated obligations of Diamond Offshore Drilling, Inc., or DODI, and rank equal in right of payment to existing and future unsecured and unsubordinated indebtedness of DODI. We have the right to redeem all or a portion of these notes for cash at any time or from time to time, on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.

     As reflected in the table below, the holders of our outstanding Zero Coupon Debentures have the right to require us to purchase all or a portion of their outstanding debentures on June 6, 2010. The aggregate maturities of long-term debt for each of the five years subsequent to June 30, 2009 are as follows:

(In thousands)
2009		$	—
2010			4,107
2011			—
2012			—
2013			—
Thereafter			998,562
			1,002,669
Less: Current maturities			(4,107	)
Total		$	998,562

11. 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,” or SFAS 5, 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 and 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. During the second quarter of 2009, the U.S. District Court ruled in our favor and dismissed a lawsuit filed in January 2005 by Total E&P USA, Inc. and several oil companies against us alleging that our semisubmersible rig, the Ocean America, damaged a natural gas pipeline in the Gulf of Mexico during Hurricane Ivan. The plaintiffs have 30 days to appeal the judgment.

     We are one of several unrelated defendants in lawsuits 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 and 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 and cash flows.

     Personal Injury Claims. Our deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, is $5.0 million per occurrence, with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. 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 June 30, 2009, our estimated liability for personal injury claims was $33.0 million, of which $9.5 million and $23.5 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2008, our estimated liability for personal injury claims was $30.1 million, of which $9.5 million and $20.6 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.

12. Segments and Geographic Area Analysis

     Although we provide contract drilling services with 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 of such services, in accordance with SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands)
High Specification Floaters		$	334,527			$	354,218			$	646,661			$	635,289
Intermediate Semisubmersibles			465,762				464,598				882,762				837,820
Jack-ups			123,169				117,810				249,743				233,857
Total contract drilling revenues			923,458				936,626				1,779,166				1,706,966
Revenues related to reimbursable expenses			22,949				17,746				52,961				33,508
Total revenues		$	946,407			$	954,372				1,832,127			$	1,740,474

Geographic Areas

     At June 30, 2009, 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 international operations and our results of operations and the value of our international 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								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
		(In thousands)
United States		$	333,865			$	396,048			$	690,180			$	719,561
International:
Australia/Asia/Middle East.			199,232				147,793				373,457				254,768
South America			172,708				158,067				297,409				285,604
Europe/Africa/Mediterranean			160,970				172,077				310,802				309,608
Mexico			79,632				80,387				160,279				170,933
Total revenues		$	946,407			$	954,372			$	1,832,127			$	1,740,474

13. Income Taxes

     Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. It is our intention to indefinitely reinvest future earnings of DOIL to finance foreign activities except to the extent that such earnings were immediately subject to U.S. federal income taxes and except for the earnings of Diamond East Asia Limited, a wholly-owned subsidiary of DOIL formed in December 2008. Accordingly, U.S. income taxes have been provided on the earnings of Diamond East Asia Limited.

     On March 31, 2009, the statute of limitations relative to a 2003 uncertain tax position in Mexico expired. As a consequence we reversed $5.5 million of previously accrued interest expense and $5.9 million of previously accrued tax expense, $0.8 million of which had been accrued for penalties.

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, 2008 and Item 1A of Part II, “Risk Factors,” included in our Quarterly Report on Form 10Q for the quarter ended March 31, 2009. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

     We provide contract drilling services to the energy industry around the globe and are a leader in offshore drilling. With the addition of the 10,000 foot, dynamically positioned, semisubmersible Ocean Courage in June 2009, we now have a fleet of 46 offshore rigs currently consisting of 31 semisubmersibles, 14 jack-ups and one drillship.

Overview

Industry Conditions

     The global economic recession continued to weigh on energy demand in the second quarter of 2009. Crude oil prices remained volatile, and our customers are continuing to defer new drilling programs until project economics improve. Against this background, demand and pricing for available drilling rigs is continuing to deteriorate, with customers actively seeking to farm-out time on many of the contracted rigs to other operators. In effect, farming out rigs creates additional supply against which we must compete. The decline in drilling activity is expected to be further exacerbated by the influx of new-build rigs over the next several years. We expect our extensive contract backlog to help mitigate the impact of the current market on us at least through the end of 2009 and into 2010; however, we have experienced negative effects of the current market such as customer credit problems, customers seeking bankruptcy protection, customers attempting to renegotiate or terminate contracts, a further slowing in the pace of new contracting activity, declines in dayrates for new contracts, declines in utilization, and the stacking of idle equipment. We would expect a prolonged decline in energy prices and the global economy to have a further negative impact on us.

     Floaters

     Approximately 86% of the time on our intermediate and high-specification floater rigs is committed for the remainder of 2009. Additionally, commitments for 69% of the time on our floating rigs extend at least through 2010, with 8% of our floating units having contracts extending into the 2014-2015 timeframe.

     During the second quarter, we reached an agreement with a customer in Australia to mobilize the Ocean America from the U.S. Gulf of Mexico, or GOM, to Australia to commence a two-year agreement originally scheduled for the Ocean Bounty. A lengthy repair period had been planned for the Ocean Bounty, and the rig swap will allow our customer to begin work at an earlier date.

     In the United Kingdom, or U.K., sector of the North Sea, we agreed to move time from the Ocean Nomad to the Ocean Princess for a customer that was employing both rigs. As a result, the Ocean Nomad will now become available for work during the third quarter of 2009, but the remaining Ocean Nomad work will be transferred to the Ocean Princess at the existing $339,000 dayrate. In addition, the Ocean Princess will receive a 120-day term extension at a dayrate of $275,000 in consideration for moving the Ocean Nomad time to the Ocean Princess.

     The weak market allowed us to complete the opportunistic purchase of a newbuild, semi-submersible offshore drilling rig, formerly known as PetroRig I, from Jurong Shipyard Pte Ltd. in June 2009. The purchase price for the dynamically positioned rig, which has been renamed Ocean Courage, was $460.0 million exclusive of final commissioning and initial mobilization costs, drillstring and other necessary capital spares. We have received several inquires for the 10,000-ft. water depth rated rig from potential customers regarding availability of the unit. We estimate that the earliest the rig could commence work is the fourth quarter of 2009, allowing time to identify and secure a drilling contract and to subsequently mobilize the rig from Singapore to the contract location.

     International Jack-ups

     The industry’s jack-up market is divided between an international sector and a U.S. sector, with the international sector historically characterized by contracts of longer duration and higher prices, compared to the generally shorter term and lower priced domestic sector. However, to date in 2009 demand and dayrates are also

continuing to soften internationally. Based on analyst reports to the effect that less than 20% of the industry’s new-build jack-up order book is under contract, it is expected that an oversupply of jack-up rigs will have an increasingly negative impact on the international sector during 2009 and beyond.

     GOM Jack-ups

     In the domestic jack-up sector, rapidly declining energy prices (particularly natural gas prices) have negatively impacted both demand and dayrates. In response, where possible we are continuing to seek to move units out of the GOM and into markets with generally longer contract duration and higher prices. Two of our five jack-up rigs in the GOM are under contract. To reduce costs, the remaining three mat rigs have been stacked and are not being actively marketed. Absent a sustained improvement in energy prices, weakness in the GOM is likely to continue in 2009, with an increasing number of rigs being cold-stacked by the industry in an effort to help bring equipment supply and demand into equilibrium. The number of working jack-ups in the GOM remains at its lowest level since the early 1970’s.

Contract Drilling Backlog

     The following table reflects our contract drilling backlog as of July 20, 2009, February 5, 2009 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2008), and July 24, 2008 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2008). The 2008 period includes both firm commitments (typically represented by signed contracts), as well as previously-disclosed letters of intent, or LOIs, where indicated. An LOI is subject to customary conditions, including the execution of a definitive agreement, and as such may not result in a binding contract. Contract drilling backlog is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, 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, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are a function of 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 5,
		July 20, 2009				2009				July 24, 2008(1)
						(In thousands)
Contract Drilling Backlog
High-Specification Floaters		$	4,016,000			$	4,346,000			$	4,535,000
Intermediate Semisubmersibles			4,391,000				5,567,000				6,199,000
Jack-ups			311,000				346,000				543,000
Total		$	8,718,000			$	10,259,000			$	11,277,000

     The following table reflects the amount of our contract drilling backlog by year as of July 20, 2009.

		For the Years Ending December 31,
		Total				2009(1)				2010				2011				2012 - 2016
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters		$	4,016,000			$	723,000			$	1,351,000			$	1,031,000			$	911,000
Intermediate Semisubmersibles			4,391,000				795,000				1,269,000				876,000				1,451,000
Jack-ups			311,000				174,000				109,000				28,000				—
Total		$	8,718,000			$	1,692,000			$	2,729,000			$	1,935,000			$	2,362,000

     The following table reflects the percentage of rig days committed by year as of July 20, 2009. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization 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 final commissioning date for the Ocean Courage.

		For the Years Ending December 31,
		2009(1)				2010				2011				2012 - 2016
Rig Days Committed (2)
High-Specification Floaters			83	%			74	%			49	%			10	%
Intermediate Semisubmersibles			88	%			67	%			46	%			15	%
Jack-ups			54	%			17	%			4	%			—

General

     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. 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.

     Demand affects the number of days our fleet is utilized and the dayrates earned. As utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of available rigs. Conversely, as utilization rates decrease, dayrates tend to decrease as well, reflecting the excess supply of rigs. 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.

     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 and costs associated with labor regulations in the geographic regions in which our rigs operate.

     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 and the regions in which our rigs are working.

     Operating expenses generally are not affected by changes in dayrates, and short-term reductions in utilization do not necessarily result in lower operating expenses. 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.

     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, as well as from quarter to quarter.

     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, except for rigs located in the U.K. and Norwegian sectors of the North Sea.

     During the remaining half of 2009, we currently expect to spend approximately 394 rig days to complete a 5-year survey for the Ocean Yatzy, intermediate surveys, the mobilization of rigs, contractually required modifications for international contracts and extended maintenance projects. In addition, we expect the Ocean Bounty to be taken out of service at some time during the third quarter of 2009 for shipyard work yet to be determined; however, we currently expect the drilling rig to be out of service until at least the end of 2009. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ —Contract Drilling Backlog.”

     We have elected to self-insure for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs, it could have a material adverse effect on our financial position, results of operations and cash flows. However, under our insurance policy that expires on May 1, 2010, we continue to carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico, for which our deductible for physical damage is $25.0 million per occurrence.

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, 2008. There were no material changes to these policies during the six months ended June 30, 2009.

Results of Operations

     Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of economic characteristics among all our divisions and locations, including the nature of services provided and the type of customers for our services. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information.” However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in our fleet and the geographic regions in which they operate to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.

Three Months Ended June 30, 2009 and 2008

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

		Three Months Ended
		June 30,								Favorable/
		2009				2008				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	334,527			$	354,218			$	(19,691	)
Intermediate Semisubmersibles			465,762				464,598				1,164
Jack-ups			123,169				117,810				5,359
Total Contract Drilling Revenue		$	923,458			$	936,626			$	(13,168	)
Revenues Related to Reimbursable Expenses		$	22,949			$	17,746			$	5,203
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	98,991			$	89,503			$	(9,488	)
Intermediate Semisubmersibles			132,696				131,539				(1,157	)
Jack-ups			66,233				48,834				(17,399	)
Other			6,933				3,560				(3,373	)
Total Contract Drilling Expense		$	304,853			$	273,436			$	(31,417	)
Reimbursable Expenses		$	22,431			$	17,346			$	(5,085	)
OPERATING INCOME
High-Specification Floaters		$	235,536			$	264,715			$	(29,179	)
Intermediate Semisubmersibles			333,066				333,059				7
Jack-ups			56,936				68,976				(12,040	)
Other			(6,933	)			(3,560	)			(3,373	)
Reimbursable expenses, net			518				400				118
Depreciation			(85,431	)			(70,803	)			(14,628	)
General and administrative expense			(16,166	)			(15,768	)			(398	)
Gain on disposition of assets			93				226				(133	)
Total Operating Income		$	517,619			$	577,245			$	(59,626	)
Other income (expense):
Interest income			1,190				2,941				(1,751	)
Interest expense			(11,288	)			(1,895	)			(9,393	)
Foreign currency transaction gain			13,733				12,574				1,159
Other, net			(416	)			(86	)			(330	)
Income before income tax expense			520,838				590,779				(69,941	)
Income tax expense			(133,398	)			(174,615	)			41,217
NET INCOME		$	387,440			$	416,164			$	(28,724	)