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

For the transition period from                      to                     

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		76-0321760 (I.R.S. Employer 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 21, 2011 Common stock, $0.01 par value per share 139,027,039 shares

 

 

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2011

		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 Unaudited 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			43
ITEM 6. Exhibits			43
SIGNATURES			44
EXHIBIT INDEX			45
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.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

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

		June 30,				December 31,
		2011				2010
ASSETS
Current assets:
Cash and cash equivalents		$	279,876			$	464,393
Marketable securities			700,486				612,346
Accounts receivable, net of allowance for bad debts			592,157				609,606
Prepaid expenses and other current assets			196,689				177,153
Total current assets			1,769,208				1,863,498
Drilling and other property and equipment, net of accumulated depreciation			4,159,542				4,283,792
Long-term receivable			—				35,361
Construction deposits			478,320				154,427
Other assets			323,553				389,906
Total assets		$	6,730,623			$	6,726,984
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	60,535			$	99,236
Accrued liabilities			278,897				469,190
Taxes payable			30,627				57,862
Total current liabilities			370,059				626,288
Long-term debt			1,495,707				1,495,593
Deferred tax liability			527,903				542,258
Other liabilities			197,357				201,133
Total liabilities			2,591,026				2,865,272
Commitments and contingencies (Note 9)			—				—
Stockholders’ equity:
Common stock (par value $0.01, 500,000,000 shares authorized; 143,943,839 shares issued and 139,027,039 shares outstanding at June 30, 2011; 143,943,624 shares issued and 139,026,824 shares outstanding at December 31, 2010)			1,439				1,439
Additional paid-in capital			1,975,465				1,972,550
Retained earnings			2,271,609				1,998,995
Accumulated other comprehensive gain			5,497				3,141
Treasury stock, at cost (4,916,800 shares at June 30, 2011 and December 31, 2010)			(114,413	)			(114,413	)
Total stockholders’ equity			4,139,597				3,861,712
Total liabilities and stockholders’ equity		$	6,730,623			$	6,726,984

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								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
Revenues:
Contract drilling		$	869,646			$	811,739			$	1,658,519			$	1,656,177
Revenues related to reimbursable expenses			19,850				10,864				37,366				26,107
Total revenues			889,496				822,603				1,695,885				1,682,284
Operating expenses:
Contract drilling, excluding depreciation			388,006				351,769				750,370				657,996
Reimbursable expenses			19,287				10,379				36,237				25,084
Depreciation			101,175				100,746				202,348				198,148
General and administrative			16,372				16,849				34,097				33,503
Bad debt recovery			(1,700	)			(2,798	)			(10,147	)			(3,898	)
Gain on disposition of assets			(1,240	)			(149	)			(3,881	)			(1,033	)
Total operating expenses			521,900				476,796				1,009,024				909,800
Operating income			367,596				345,807				686,861				772,484
Other income (expense):
Interest income			1,091				477				1,541				1,759
Interest expense			(22,226	)			(21,333	)			(44,270	)			(43,654	)
Foreign currency transaction gain (loss)			(1,555	)			(3,991	)			(3,161	)			(3,530	)
Other, net			(880	)			(34	)			(96	)			(121	)
Income before income tax expense			344,026				320,926				640,875				726,938
Income tax expense			(77,440	)			(96,533	)			(123,677	)			(211,692	)
Net income		$	266,586			$	224,393			$	517,198			$	515,246
Income per share:
Basic		$	1.92			$	1.61			$	3.72			$	3.71
Diluted		$	1.92			$	1.61			$	3.72			$	3.70
Weighted-average shares outstanding:
Shares of common stock			139,027				139,026				139,027				139,026
Dilutive potential shares of common stock			25				53				25				78
Total weighted-average shares outstanding			139,052				139,079				139,052				139,104
Cash dividends declared per share of common stock		$	.875			$	1.50			$	1.75			$	3.50

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)

		Six Months Ended
		June 30,
		2011				2010
Operating activities:
Net income		$	517,198			$	515,246
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			202,348				198,148
Gain on disposition of assets			(3,881	)			(1,033	)
Loss (gain) on sale of marketable securities, net			(782	)			2
Gain on foreign currency forward exchange contracts			(7,231	)			(457	)
Deferred tax provision			(15,623	)			11,921
Accretion of discounts on marketable securities			(231	)			(200	)
Amortization of debt issuance costs			439				449
Amortization of debt discounts			114				167
Stock-based compensation expense			2,920				3,719
Deferred income, net			(32,490	)			56,593
Deferred expenses, net			54,789				(52,311	)
Other assets, noncurrent			(217	)			5,788
Other liabilities, noncurrent			424				7,712
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges			7,231				457
Changes in operating assets and liabilities:
Accounts receivable			51,147				109,118
Prepaid expenses and other current assets			(24,137	)			(20,045	)
Accounts payable and accrued liabilities			(33,070	)			8,666
Taxes payable			4,691				(149,635	)
Net cash provided by operating activities			723,639				694,305
Investing activities:
Capital expenditures			(100,521	)			(221,890	)
Deposits for construction of new rigs			(478,320	)			—
Deposits received on sale of rig			—				18,600
Proceeds from disposition of assets, net of disposal costs			4,205				1,258
Proceeds from sale and maturities of marketable securities			3,312,089				2,550,088
Purchases of marketable securities			(3,399,797	)			(2,399,760	)
Net cash used in investing activities			(662,344	)			(51,704	)
Financing activities:
Redemption of zero coupon debentures			—				(4,238	)
Debt issuance costs and arrangement fees			—				(98	)
Payment of dividends			(245,812	)			(489,670	)
Proceeds from stock plan exercises			—				107
Net cash used in financing activities			(245,812	)			(493,899	)
Net change in cash and cash equivalents			(184,517	)			148,702
Cash and cash equivalents, beginning of period			464,393				376,417
Cash and cash equivalents, end of period		$	279,876			$	525,119

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, 2010 (File No. 1-13926).

     As of July 21, 2011, 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. 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.

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.

     We have presented $154.4 million in “Construction deposits” in our Consolidated Balance Sheets at December 31, 2010, which was previously presented in “Other assets.”

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 6.

     We classify our investments in marketable securities as available for sale and 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 gain” 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) — Other, net.”

     The effect of exchange rate changes on cash balances held in foreign currencies was not material for the six months ended June 30, 2011 and 2010.

Provision for Bad Debts

     We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. In establishing these reserves, we consider historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. Such provision is reported as a component of “Operating expense” in our Consolidated Statements of Operations. See Note 2.

Derivative Financial Instruments

     Our derivative financial instruments consist of foreign currency forward exchange, or FOREX, contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative contract is 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 and is designated as an accounting hedge, the gains and losses are reflected in income in the same period as offsetting gains and losses on the qualifying hedged positions. We report such realized gains and losses as a component of “Contract drilling, excluding depreciation” 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.

     Realized gains or losses upon settlement of derivative contracts not designated as cash flow hedges are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. For the three-month and six-month periods ended June 30, 2011 and 2010, we recognized no foreign currency transaction gain (loss) attributable to FOREX contracts not designated as cash flow hedges. See Notes 5 and 6.

Impairment of Long-Lived Assets

     We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as cold stacking a rig or excess spending over budget on a new-build or major rig upgrade). 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;
	•		the estimated annual cost for rig replacements and/or enhancement programs;
	•		the estimated maintenance, inspection or other costs associated with a rig returning to work;
	•		salvage value for each rig; and
	•		estimated proceeds that may be received on disposition of the rig.

Based on these assumptions and estimates, we develop a matrix using several different utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. The sum of our utilization scenarios (which include active, ready stacked and cold stacked) and probability of occurrence scenarios both equal 100% in the aggregate. We evaluate our cold stacked rigs annually, and we update the matrices for each of our cold stacked rigs at each year end and modify our assumptions giving consideration to the length of time the rig has been cold stacked, the current and expected market for the type of rig and expectations of future oil and gas prices. Further, to test sensitivity, we consider the impact of a 5% reduction in assumed dayrates for the cold stacked rigs (holding all other assumptions and estimates in the model constant). We would not necessarily record an impairment if the sensitivity analysis indicated potential cash flows would be insufficient to recover our carrying value. We would assess other qualitative factors including industry, regulatory and other relevant conditions to determine whether an impairment or further disclosure is warranted.

     As of June 30, 2011, we had eight cold stacked rigs with an aggregate net book value of approximately $91.0 million. Of our cold stacked rigs, four were jack-up rigs, consisting of three mat-supported rigs and one independent-leg, cantilevered rig (all in the U.S. Gulf of Mexico, or GOM), and four were intermediate semisubmersible rigs (two in the GOM and two in Malaysia), including the Ocean Epoch, which was cold stacked in the first quarter of 2011. As of December 31, 2010, we had seven cold stacked rigs with an aggregate net book value of approximately $78.0 million. We performed an impairment review for each of these rigs using the methodology described above. Based on our analyses, we have concluded that these rigs were not subject to impairment at June 30, 2011 and December 31, 2010, respectively.

     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,
		2011				2010				2011				2010
						(In thousands)
Net income		$	266,586			$	224,393			$	517,198			$	515,246
Other comprehensive gains (losses), net of tax:
FOREX contracts:
Unrealized holding (loss) gain			4,643				(3,397	)			7,683				(3,260	)
Reclassification adjustment for loss (gain) included in net income			(3,541	)			356				(4,949	)			(729	)
Investments in marketable securities:
Unrealized holding (loss) gain			(5	)			(18	)			1				(22	)
Reclassification adjustment for loss (gain) included in net income			(5	)			1				(379	)			1
Comprehensive income		$	267,678			$	221,335			$	519,554			$	511,236

Foreign Currency

     Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses, including gains and losses from the settlement of FOREX contracts not designated as accounting hedges, are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. For the three-month and six-month periods ended June 30, 2011, we recognized net foreign currency transaction (losses) of $(1.6) million and $(3.2) million, respectively. For the three-month and six-month periods ended June 30, 2010, we recognized net foreign currency transaction (losses) of $(4.0) million and $(3.5) million, respectively. See Note 5.

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 we estimate 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 2 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 (either lump-sum or dayrate). 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.

Income Taxes

     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. Since forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of the subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes have been provided on these earnings 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, or DEAL, a wholly-owned subsidiary of DOIL. It had been our intention to repatriate the earnings of DEAL to the U.S. and, accordingly, we provided U.S. income taxes on its earnings. However, a tax law provision

that expired at the end of 2009, but was subsequently signed back into law by the President of the United States on December 17, 2010, in conjunction with our decisions in late 2010 and the first half of 2011 to build three new drillships overseas, caused us to reassess our intent to repatriate the earnings of DEAL to the U.S. We now plan to reinvest the earnings of DEAL internationally through another of our foreign companies, and consequently, we are no longer providing U.S. income taxes on its earnings. During the six months ended June 30, 2011, we reversed approximately $15.0 million of U.S. income taxes that had been provided in prior periods for the earnings of DEAL.

Recently Issued Accounting Pronouncements

     In June 2011, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” or ASU 2011-05, which eliminates the option to present components of other comprehensive income, or OCI, as part of the statement of changes in stockholders’ equity, requires the presentation of each component of net income and each component of OCI either in a single continuous statement or in two separate but consecutive statements and also requires presentation of reclassification adjustments on the face of the financial statement. ASU 2011-05 is effective for interim and annual periods beginning after December 15, 2011; however, early adoption is permitted. The adoption of ASU 2011-05 will not have an effect on our financial position, results of operations or cash flows.

     In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs,” or ASU 2011-04. ASU 2011-04 clarifies existing fair value measurement and disclosure requirements, amends certain fair value measurement principles and requires additional disclosures about fair value measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We are in the process of reviewing the impact of this ASU on our financial statements and will incorporate any additional disclosures in our annual financial statements for the year ending December 31, 2012.

2. Supplemental Financial Information

Consolidated Balance Sheet Information

     Accounts receivable, net of allowance for bad debts, consists of the following:

		June 30,				December 31,
		2011				2010
		(In thousands)
Trade receivables		$	583,595			$	633,224
Value added tax receivables			7,442				5,003
Unbilled third party claims			106				45
Related party receivables			3,320				538
Other			1,123				2,704
			595,586				641,514
Allowance for bad debts			(3,429	)			(31,908	)
Total		$	592,157			$	609,606

     During the three-month and six-month periods ended June 30, 2011, we recovered $1.7 million and $10.1 million, respectively, associated with reserves for bad debts recorded in previous years. During the three-month and six-month periods ended June 30, 2010, we recovered $2.8 million and $3.9 million, respectively, associated with the reserves for bad debts recorded in previous years. No additional allowances were deemed necessary for each of the three-month and six-month periods ended June 30, 2011 and 2010.

     In addition, during the six months ended June 30, 2011, we offset $18.4 million in previously reserved trade receivables against the allowance for bad debts as we had exhausted all methods of recovery against this customer.

     Prepaid expenses and other current assets consist of the following:

		June 30,				December 31,
		2011				2010
		(In thousands)
Rig spare parts and supplies		$	51,175			$	50,288
Deferred mobilization costs			60,396				76,868
Prepaid insurance			27,743				9,587
Deferred tax assets			9,557				9,557
Deposits			724				827
Prepaid taxes			32,865				20,347
FOREX contracts			8,410				4,326
Other			5,819				5,353
Total		$	196,689			$	177,153

     Accrued liabilities consist of the following:

		June 30,				December 31,
		2011				2010
		(In thousands)
Accrued capital project/upgrade costs		$	6,848			$	28,947
Payroll and benefits			87,522				76,041
Deferred revenue			55,933				69,825
Rig operating expenses			71,901				81,820
Interest payable			21,219				21,219
Personal injury and other claims			8,563				11,758
Accrued drillship construction installment			—				154,427
Other			26,911				25,153
Total		$	278,897			$	469,190

     At December 31, 2010, we had accrued the first installment payable under a turnkey construction agreement with Hyundai Heavy Industries Co., Ltd., or Hyundai, of $154.4 million and recorded the related noncurrent asset in an equal amount in “Construction deposits” in our Consolidated Balance Sheets. See Note 9.

Consolidated Statement of Cash Flows Information

     We paid interest on long-term debt totaling $41.5 million and $42.0 million for the six-month periods ended June 30, 2011 and 2010, respectively. During the six months ended June 30, 2010, we paid $0.9 million in interest on assessments from the Internal Revenue Service.

     We made estimated U.S. federal income tax payments of $49.0 million and $254.5 million during the six-month periods ended June 30, 2011 and 2010, respectively. We paid $96.5 million and $76.2 million in foreign income taxes, net of foreign tax refunds, during the six months ended June 30, 2011 and 2010, respectively. We paid state income taxes, net of refunds, of $0.2 million and $0.1 million during the six months ended June 30, 2011 and 2010, respectively.

     Capital expenditures for the six months ended June 30, 2011 included $28.9 million that was accrued but unpaid at December 31, 2010. Capital expenditures for the six months ended June 30, 2010 included $64.9 million that was accrued but unpaid at December 31, 2009. Capital expenditures that were accrued but not paid as of June 30, 2011 totaled $6.8 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at June 30, 2011.

3. 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,
		2011				2010				2011				2010
		(In thousands, except per share data)
Net income — basic (numerator):		$	266,586			$	224,393			$	517,198			$	515,246
Effect of dilutive potential shares
Convertible debentures			—				32				—				56
Net income including conversions — diluted (numerator)		$	266,586			$	224,425			$	517,198			$	515,302
Weighted average shares — basic (denominator):			139,027				139,026				139,027				139,026
Effect of dilutive potential shares
Convertible debentures			—				32				—				42
Stock options and stock appreciation rights			25				21				25				36
Weighted average shares including conversions — diluted (denominator)			139,052				139,079				139,052				139,104
Earnings per share:
Basic		$	1.92			$	1.61			$	3.72			$	3.71
Diluted		$	1.92			$	1.61			$	3.72			$	3.70

     The following table sets forth the share effects of stock options and the number of stock appreciation rights excluded from our computations of diluted earnings per share, or EPS, as the inclusion of such potentially dilutive shares would have been antidilutive for the periods presented:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
						(In thousands)
Employee and director:
Stock options			8				8				8				4
Stock appreciation rights			693				672				669				557

4. 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 6.

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

		June 30, 2011
		Amortized				Unrealized				Market
		Cost				Gain (Loss)				Value
		(In thousands)
U.S. Treasury Bills (due within one year)		$	699,994			$	(2	)		$	699,992
Mortgage-backed securities			446				48				494
Total		$	700,440			$	46			$	700,486

		December 31, 2010
		Amortized				Unrealized				Market
		Cost				Gain				Value
		(In thousands)
U.S. Treasury Bills (due within one year)		$	599,965			$	15			$	599,980
Corporate bonds			11,200				560				11,760
Mortgage-backed securities			553				53				606
Total		$	611,718			$	628			$	612,346

     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,
		2011				2010				2011				2010
						(In thousands)
Proceeds from sales		$	73			$	35			$	12,089			$	88
Proceeds from maturities			1,950,000				1,350,000				3,300,000				2,550,000
Gross realized gains			—				—				784				—
Gross realized losses			(1	)			(1	)			(2	)			(2	)

5. 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 FOREX contracts to manage our foreign exchange risk. Our FOREX 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 most of our contracts, is the average spot rate for the contract period.

     We enter into FOREX 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 GAAP.

     We have adopted a hedging strategy whereby certain of our qualifying FOREX contracts are designated as cash flow hedges based on our expected future foreign currency requirements. 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 are recorded as a component of “Accumulated other comprehensive gain,” or AOCG, in our Consolidated Financial Statements. The effective portion of the cash flow hedge will remain in AOCG 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.

     During the six months ended June 30, 2011 and 2010, we settled FOREX contracts with an aggregate notional value of approximately $145.5 million and $147.2 million, respectively, all of which were designated as accounting hedges. During the six-month periods ended June 30, 2011 and 2010, we did not enter into or settle any FOREX contracts that were not designated as accounting hedges.

     The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as accounting hedges for the three-month and six-month periods ended June 30, 2011 and 2010.

		Amount of (Loss) Gain Recognized in Income
		Three Months Ended								Six Months Ended
		June 30,								June 30,
Location of Gain (Loss) Recognized in Income		2011				2010				2011				2010
		(In thousands)
Contract drilling expense		$	5,405			$	(1,643	)		$	7,231			$	457

     As of June 30, 2011, we had FOREX contracts outstanding in the aggregate notional amount of $122.4 million, consisting of $36.9 million in Australian dollars, $66.4 million in Brazilian reais, $17.4 million in British pounds sterling and $1.7 million in Norwegian kroner. These contracts generally settle monthly through December 2011. As of June 30, 2011, all outstanding derivative contracts had been designated as cash flow hedges. See Note 6.

     The following table presents the fair values of our derivative FOREX contracts designated as hedging instruments at June 30, 2011 and December 31, 2010.

Balance Sheet

Fair Value

Balance Sheet

Fair Value

Location

June 30, 2011

December 31, 2010

Location

June 30, 2011

December 31, 2010

(In thousands)

(In thousands)

Prepaid expenses and other current assets

$

8,410

$

4,326

Accrued liabilities

$

—

$

(121

)

     The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated Statements of Operations related to our FOREX contracts designated as cash flow hedges for the three-month and six-month periods ended June 30, 2011 and 2010.

		For The Three Months Ended								For The Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(In thousands)
Amount of gain (loss) recognized in AOCG on derivative (effective portion)		$	7,143			$	(5,226	)		$	11,820			$	(5,015	)
Location of gain (loss) reclassified from AOCG into income (effective portion)		Contract drilling expense				Contract drilling expense				Contract drilling expense				Contract drilling expense
Amount of gain (loss) reclassified from AOCG into income (effective portion)		$	5,448			$	(548	)		$	7,615			$	1,122
Location of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Foreign currency transaction gain (loss)				Foreign currency transaction gain (loss)				Foreign currency transaction gain (loss)				Foreign currency transaction gain (loss)
Amount of Gain Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)		$	—			$	—			$	—			$	—

     As of June 30, 2011, the estimated amount of net unrealized gains associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $8.4 million. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense.

6. 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 residential 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.

     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.

     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. Our two customers in Brazil, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government) and OGX Petróleo e Gás Ltda. (a privately owned Brazilian oil and natural gas company), accounted for $132.5 million and $68.3 million, or 23% and 12%, respectively, of our total consolidated gross trade accounts receivable balances as of June 30, 2011, and $180.8 million and $52.4 million, or 29% and 8%, respectively, as of December 31, 2010.

     In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be 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. Historically, we have not experienced significant losses on our trade receivables. We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. Our allowance for bad debts was $3.4 million and $31.9 million at June 30, 2011 and December 31, 2010, respectively. See Note 2.

     One of our drilling contracts obligates our customer to pay us, over the term of the drilling program, an aggregate drilling rate of $560,000 per day, consisting of $75,000 per day payable in accordance with our normal credit terms (due 30 days after receipt of invoice) and the remainder of the contractual dayrate, $485,000 per day, payable through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties.

     At June 30, 2011, $80.7 million was payable to us from the NPI. Based on current production payout estimates, we expect to collect the entire $80.7 million receivable within the next twelve months and have presented this amount in “Accounts receivable” in our Consolidated Balance Sheets. At June 30, 2011, we believe that collectability of the amount owed pursuant to the NPI arrangement was reasonably assured.

     At December 31, 2010, $85.0 million was payable to us from the NPI, of which $49.6 million and $35.4 million are presented as “Accounts receivable” and “Long-term receivable,” respectively, in our Consolidated Balance Sheets.

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, 2011								December 31, 2010
		Fair Value				Carrying Value				Fair Value				Carrying Value
						(In millions)
4.875% Senior Notes		$	271.1			$	249.7			$	270.0			$	249.7
5.15% Senior Notes			274.0				249.8				271.1				249.7
5.70% Senior Notes			492.6				496.8				493.1				496.8
5.875% Senior Notes			558.2				499.4				550.9				499.4

     We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of June 30, 2011 and December 31, 2010, 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 residential mortgage-backed securities, available for sale were based on the quoted closing market prices on June 30, 2011 and December 31, 2010, 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 FOREX contracts is based on both quoted market prices and valuations derived from pricing models on June 30, 2011 and December 31, 2010, respectively.
	•		Long-term receivable — The carrying amount approximates fair value based on the nature of the instrument.
	•		Long-term debt — The fair value of our 5.70% Senior Notes due 2039, 5.875% Senior Notes due 2019, 4.875% Senior Notes due July 1, 2015, and 5.15% Senior Notes due September 1, 2014 is based on the quoted market prices from brokers of these instruments.

     Certain of our assets and liabilities are required to be measured at fair value in accordance with GAAP. Fair value is defined 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. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are 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, 2011 consisted of cash held in money market funds of $244.3 million and investments in U.S. Treasury Bills of $700.0 million. Our Level 1 assets at December 31, 2010 consisted of cash held in money market funds of $442.2 million and investments in U.S. Treasury Bills of $600.0 million.

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 residential mortgage-backed securities and over-the-counter FOREX contracts. Our residential mortgage-backed securities were valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. Our FOREX contracts are valued based on quoted market prices, which are derived from observable inputs including current spot and forward rates, less the contract rate multiplied by the notional amount. The inputs used in our valuation are obtained from a Bloomberg curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected floating rate cash flows can be calculated. The valuation techniques underlying the models are widely accepted in the financial services industry and do not involve significant judgment.
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.

Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or from Level 2 to Level 3. Our policy regarding fair value measurements of financial instruments transferred into and out of levels is to reflect the transfers as having occurred at the beginning of the reporting period.

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

		June 30, 2011
		Fair Value Measurements Using												Assets at Fair
		Level 1				Level 2				Level 3				Value
		(In thousands)
Assets:
Short-term investments		$	944,290			$	—			$	—			$	944,290
FOREX contracts			—				8,410				—				8,410
Mortgage-backed securities			—				494				—				494
Total assets		$	944,290			$	8,904			$	—			$	953,194

		December 31, 2010
		Fair Value Measurements Using												Assets at Fair
		Level 1				Level 2				Level 3				Value
		(In thousands)
Assets:
Short-term investments		$	1,042,224			$	—			$	—			$	1,042,224
FOREX contracts			—				4,327				—				4,327
Corporate bonds			—				11,760				—				11,760
Mortgage-backed securities			—				606				—				606
Total assets		$	1,042,224			$	16,693			$	—			$	1,058,917
Liabilities:
FOREX contracts		$	—			$	(121	)		$	—			$	(121	)

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,
		2011				2010
		(In thousands)
Drilling rigs and equipment		$	7,235,894			$	7,163,196
Land and buildings			60,027				56,536
Office equipment and other			46,509				44,689
Cost			7,342,430				7,264,421
Less: accumulated depreciation			(3,182,888	)			(2,980,629	)
Drilling and other property and equipment, net		$	4,159,542			$	4,283,792

8. Long-Term Debt

     Long-term debt consists of the following:

		June 30,				December 31,
		2011				2010
		(In thousands)
5.15% Senior Notes (due 2014)		$	249,778			$	249,745
4.875% Senior Notes (due 2015)			249,751				249,724
5.875% Senior Notes (due 2019)			499,382				499,351
5.70% Senior Notes (due 2039)			496,796				496,773
Total		$	1,495,707			$	1,495,593

     The aggregate maturities of long-term debt for each of the five years subsequent to June 30, 2011, are as follows:

(Dollars in thousands)
2012		$	—
2013			—
2014			249,778
2015			249,751
2016			—
Thereafter			996,178
Total		$	1,495,707

9. Commitments and Contingencies

     Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. 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. 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.

     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 deductibles for marine liability coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently $10.0 million per the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year. 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 outside consultants to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate reserve to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At June 30, 2011, our estimated liability for personal injury claims was $35.4 million, of which $8.2 million and $27.2 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2010, our estimated liability for personal injury claims was $35.0 million, of which $11.1 million and $23.9 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. Since December 2010, we have entered into three separate turnkey contracts with Hyundai for the construction of three dynamically positioned, ultra-deepwater drillships, with deliveries scheduled for late in the second and fourth quarters of 2013 and in the second quarter of 2014. The aggregate cost of the three drillships, including commissioning, spares and project management, is expected to be approximately $1.8 billion.

     The contracted price of each drillship is payable in two installments. The first installments, aggregating $478.3 million, were paid in the first and second quarters of 2011 and are reported in “Construction deposits” in our Consolidated Balance Sheets. At June 30, 2011 and December 31, 2010, we had no other purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.

     Letters of Credit and Other. We were contingently liable as of June 30, 2011 in the amount of $72.1 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $4.3 million in letters of credit issued under our $285 million, syndicated, senior unsecured revolving credit facility. At June 30, 2011, two of our outstanding bonds, totaling $19.6 million, had been purchased from a related party after obtaining competitive quotes. Agreements relating to approximately $56.8 million of performance bonds can require collateral at any time. As of June 30, 2011, 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.

10. 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 FASB Accounting Standards Codification Topic 280, Segment Reporting.

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(In thousands)
High-Specification Floaters		$	452,289			$	340,387			$	813,355			$	724,175
Intermediate Semisubmersibles			356,840				389,094				736,339				769,795
Jack-ups			60,512				82,223				108,730				162,172
Other			5				35				95				35
Total contract drilling revenues			869,646				811,739				1,658,519				1,656,177
Revenues related to reimbursable expenses			19,850				10,864				37,366				26,107
Total revenues		$	889,496			$	822,603			$	1,695,885			$	1,682,284

Geographic Areas

     Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At June 30, 2011, our drilling rigs were located offshore twelve countries in addition to the United States. 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,
		2011				2010				2011				2010
		(In thousands)
United States		$	101,221			$	189,019			$	151,495			$	427,566
International:
South America			441,221				312,207				885,324				595,323
Australia/Asia/Middle East			118,454				142,463				223,122				301,392
Europe/Africa/Mediterranean			209,102				140,078				399,150				276,683
Mexico			19,498				38,836				36,794				81,320
Total revenues		$	889,496			$	822,603			$	1,695,885			$	1,682,284

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, 2010. 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. Our current fleet of 46 offshore drilling rigs consists of 32 semisubmersibles, 13 jack-ups and one drillship. We currently have three drillships on order, two of which are expected to be delivered late in the second and fourth quarters of 2013. Our third drillship is expected to be delivered at the end of the second quarter of 2014.

Overview

Industry Conditions

     U.S. Gulf of Mexico — The U.S. government lifted the ban on certain drilling activities in the U.S. Gulf of Mexico, or GOM, on October 12, 2010. Currently, all drilling in the GOM is subject to compliance with the final Drilling Safety Rule (codification of Notice to Lessees, or NTL, 2010-N05), the Workplace Safety Rule on Safety and Environmental Management Systems and other requirements set forth in NTL 2010-N06 and NTL 2010-N10 (known as the Compliance and Review NTL). The Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, recently announced that additional regulations are forthcoming and that multi-person inspection teams will now be utilized for offshore oil and gas inspections. In addition, the BOEMRE is in the process of a comprehensive review of its application of the National Environmental Policy Act of 1969, or NEPA, in reviewing drilling plans, lease sales and other drilling activities in the GOM, particularly the use of categorical exclusions under NEPA to preclude the requirement for or limit the scope of environmental assessments. We are not able to predict the likelihood, nature or extent of any additional rulemaking or the results of reviews by the BOEMRE.

     In addition, in the aftermath of the April 20, 2010 Macondo incident, the number of new drilling permits issued by BOEMRE has been limited. Although the BOEMRE has announced that it is putting in place significant improvements in the oil and gas permit application process, we are unable to predict when or if the pace of permitting in the GOM will return to pre-Macondo levels. It has been reported that the industry currently has approximately 33 floating rigs in the GOM that have been impacted by the regulatory uncertainty that has followed the Macondo incident and that five floating rigs have left the GOM since the imposition of the moratorium in 2010, two of which rigs were ours. Absent an increase in permitting activity, weakness in the GOM market is likely to continue throughout 2011, with the possibility of additional rigs being cold stacked by us and others in the industry.

     International Markets and Mexico — Improving oil prices, which have climbed as high as $114 per barrel since 2011 began, appear to be supporting demand for our equipment in international markets. As a result, dayrates for our international floater units appear to have stabilized, and we are encouraged by the increase in tender activity by our customers across all classes of floater units outside the GOM, although demand for our services has not yet risen sufficiently to provide pricing power on new contracts.

     During the second quarter of 2011, international demand for standard jack-ups remained stable with narrow profit margins, though there was a significant increase in tender activity for standard jack-up units in Mexico late in the period. However, high-specification new-build jack-up rigs coming to market are enjoying significantly higher utilization rates and better pricing than older existing equipment. This new-build activity could result in an oversupply of jack-up rigs and negatively impact the market for standard jack-ups, which comprise most of our jack-up fleet, during the remainder of 2011 and beyond.

Our Fleet

     As of the date of this report, we actively market five rigs in the GOM market, consisting of three semisubmersible rigs and one jack-up rig, all of which are currently contracted in the GOM, as well as an additional jack-up rig that is ready stacked. We also have two intermediate floaters and four jack-up rigs cold stacked in the GOM. One of the three contracted semisubmersible units, the Ocean Monarch, is scheduled to leave the GOM in mid-August for work in Southeast Asia, and one of the jack-up rigs, the Ocean Titan, is expected to commence work in Mexico in mid-November of this year. Given the continuing uncertainty with respect to drilling activity in the GOM, we are continuing to actively seek international opportunities to employ our rigs outside the GOM. However, we can provide no assurance that we will be successful in our efforts to

employ our remaining impacted rigs in the GOM or elsewhere in the near term.

     Since December 31, 2010 through the date of this report, we have entered into 33 new drilling contracts totaling approximately $3.5 billion in backlog and ranging in duration from one well to five years. As of July 21, 2011, our contract backlog was approximately $8.6 billion, of which our contracts in the GOM and Brazil represented approximately $2.1 billion, or 24%, and $5.0 billion, or 58%, respectively.

     Floaters

     Our intermediate and high-specification floater rigs, both domestic and international, accounted for approximately 93% of our revenue during the second quarter of 2011. This market remains stable with marketed industry floater utilization reportedly nearing 90%. Approximately 82% of the time for our intermediate and high-specification floater rigs is committed for the remainder of 2011. Additionally, 55% of the time on our floating rigs is committed in 2012.

     During the second quarter of 2011, among other new drilling contracts, we announced two five-year agreements which will utilize two of our new-build drillships under construction, the Ocean BlackHawk and the Ocean BlackHornet. The two contracts, which are expected to commence in late 2013 and early 2014, respectively, are expected to generate combined maximum total revenue of approximately $1.8 billion. In May, we executed a contract for the construction of a third new-build drillship, for delivery in the second quarter of 2014.

     Ten other agreements were announced in mid-July 2011 following the close of the quarter which are expected to generate combined maximum total revenue of approximately $1.1 billion and represent approximately 14.4 years of contract drilling backlog.

     Jack-ups

     As a result of a recent increase in tender activity in the Mexican Gulf of Mexico, we received new term contracts on two jack-up units currently working offshore Mexico, the Ocean Nugget and the Ocean Summit, and additional tendering activity is ongoing.

Contract Drilling Backlog

     The following table reflects our contract drilling backlog as of July 21, 2011, February 1, 2011 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2010) and July 22, 2010 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2010). 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.

		July 21,				February 1,				July 22,
		2011				2011				2010(4)
						(In thousands)
Contract Drilling Backlog
High-Specification Floaters (1)			$6,022,000				$3,838,000				$4,705,000
Intermediate Semisubmersibles (2)			2,369,000				2,700,000				3,322,000
Jack-ups (3)			259,000				107,000				139,000
Total			$8,650,000				$6,645,000				$8,166,000

     The following table reflects the amount of our contract drilling backlog by year as of July 21, 2011.

		For the Years Ending December 31,
		Total				2011(1)				2012				2013				2014 - 2019
									(In thousands)
Contract Drilling Backlog
High-Specification Floaters (2)			$6,022,000				$   827,000				$1,132,000				$1,087,000				$2,976,000
Intermediate Semisubmersibles (3)			2,369,000				587,000				769,000				526,000				487,000
Jack-ups (4)			259,000				76,000				92,000				69,000				22,000
Total			$8,650,000				$1,490,000				$1,993,000				$1,682,000				$3,485,000

     The following table reflects the percentage of rig days committed by year as of July 21, 2011. 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 final commissioning dates for the Ocean BlackHawk and Ocean BlackHornet and does not include available days for our third drillship on order with Hyundai.

		For the Years Ending December 31,
		2011(1)				2012				2013				2014 - 2019
Rig Days Committed (2)
High-Specification Floaters			97%				71%				62%				20%
Intermediate Semisubmersibles			70%				43%				29%				4%
Jack-ups			48%				21%				15%				1%

General

     The two most significant variables affecting our 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, regulatory 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.

     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 special surveys are performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance activities may result from the special 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 United Kingdom, or U.K., and Norwegian sectors of the North Sea.

     During the remainder of 2011, seven of our rigs will require 5-year surveys, and we expect that they will be out of service for approximately 425 days in the aggregate. We also expect to spend an additional approximately 390

days during 2011 for intermediate surveys, the mobilization of rigs, contract preparation activities and extended maintenance projects. 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 “ — Overview — Contract Drilling Backlog.”

     We renewed our principal insurance policies effective May 1, 2011. Our coverage and policy limits for both physical damage and marine liability insurance are substantially similar to those of our previous policies. We believe that our current policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and at levels appropriate for our business.

     Under our protection and indemnity policy, which expires on May 1, 2012, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. Our deductibles for marine liability coverage, including for personal injury claims, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year, which under our current policy commenced on May 1, 2011.

     We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, 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, 2012, we 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. We do not typically retain loss- of-hire insurance policies to cover our rigs.

Critical Accounting Estimates

     Our significant accounting policies are discussed in Note 1 of our notes to unaudited 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, 2010. There were no material changes to these policies during the six months ended June 30, 2011 except that we no longer expect to repatriate the earnings of Diamond East Asia Limited, or DEAL, to the U.S. Accordingly, we are no longer providing U.S. income taxes on its earnings and have reversed U. S. income taxes on its earnings provided in previous years. For further discussion, see Note 1 “General Information” to our Consolidated Financial Statements in Item 1 of Part I of this report.

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 applicable accounting standards on segment reporting. 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 and Six Months Ended June 30, 2011 and 2010

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

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
						(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	452,289			$	340,387			$	813,355			$	724,175
Intermediate Semisubmersibles			356,840				389,094				736,339				769,795
Jack-ups			60,512				82,223				108,730				162,172
Other			5				35				95				35
Total Contract Drilling Revenue		$	869,646			$	811,739			$	1,658,519			$	1,656,177
Revenues Related to Reimbursable Expenses		$	19,850			$	10,864			$	37,366			$	26,107
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	203,459			$	134,500			$	384,496			$	243,655
Intermediate Semisubmersibles			138,879				157,446				276,616				296,045
Jack-ups			38,552				51,717				80,652				105,345
Other			7,116				8,106				8,606				12,951
Total Contract Drilling Expense		$	388,006			$	351,769			$	750,370			$	657,996
Reimbursable Expenses		$	19,287			$	10,379			$	36,237			$	25,084
OPERATING INCOME
High-Specification Floaters		$	248,830			$	205,887			$	428,859			$	480,520
Intermediate Semisubmersibles			217,961				231,648				459,723				473,750
Jack-ups			21,960				30,506				28,078				56,827
Other			(7,111	)			(8,071	)			(8,511	)			(12,916	)
Reimbursable expenses, net			563				485				1,129				1,023
Depreciation			(101,175	)			(100,746	)			(202,348	)			(198,148	)
General and administrative expense			(16,372	)			(16,849	)			(34,097	)			(33,503	)
Bad debt recovery			1,700				2,798				10,147				3,898
Gain on disposition of assets			1,240				149				3,881				1,033
Total Operating Income		$	367,596			$	345,807			$	686,861			$	772,484
Other income (expense):
Interest income			1,091				477				1,541				1,759
Interest expense			(22,226	)			(21,333	)			(44,270	)			(43,654	)
Foreign currency transaction loss			(1,555	)			(3,991	)			(3,161	)			(3,530	)
Other, net			(880	)			(34	)			(96	)			(121	)
Income before income tax expense			344,026				320,926				640,875				726,938
Income tax expense			(77,440	)			(96,533	)			(123,677	)			(211,692	)
NET INCOME		$	266,586			$	224,393			$	517,198			$	515,246

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

     Operating Income. Operating income during the second quarter of 2011 increased $21.8 million, or 6%, compared to the same period of 2010. Contract drilling revenue during the second quarter of 2011 increased $57.9 million, or 7%, compared to the second quarter of 2010, primarily as a result of an increase in average utilization of our high-specification floaters from 69% during the second quarter of 2010 to 94% during the second quarter of 2011, partially offset by a decline in contract drilling revenues earned by the remainder of our fleet. Revenue generated by our domestic and international high-specification floater rigs increased an aggregate $111.9 million, or 33%, while revenue for our combined semisubmersible and jack-up fleets decreased $32.3 million and $21.7 million, or 8% and 26%, respectively, during the second quarter of 2011 compared to the same quarter in 2010. Results for the second quarter of 2011 reflected the return to work of three of our high specification floaters (two in international markets and one in the GOM) after being idled during the second quarter of 2010 following the Macondo incident in the GOM, as well as revenue generated by the newest addition to our floater fleet, the Ocean Valor, which began operating under contract offshore Brazil in the fourth quarter of 2010. In contrast, subsequent to the second quarter of 2010, we cold stacked two additional intermediate semisubmersible rigs and one jack-up rig, which negatively impacted revenue during the second quarter of 2011. Total contract drilling expense increased $36.2 million, or 10%, during the second quarter of 2011, compared to the second quarter of 2010, and included normal operating costs for the Ocean Valor, as well as increased amortized mobilization costs and higher other operating costs associated with rigs operating internationally rather than domestically.

     Income Tax Expense. Our estimated annual effective tax rate for the three months ended June 30, 2011 was 21.6%, compared to the 29.2% estimated annual effective tax rate for the same period in 2010. The lower effective tax rate in the current quarter is partially the result of differences in the mix of our domestic and international pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operate. Also contributing to our lower effective tax rate in the 2011 quarter, compared to the prior year quarter, was the impact of a tax law provision that expired at the end of 2009 but was subsequently signed back into law by the President of the United States on December 17, 2010. This provision allows us to defer recognition of certain foreign earnings for U.S. income tax purposes. As a consequence of the extension of the tax law provision in December 2010, we were able to defer the recognition of certain of our foreign earnings for U.S. income taxes purposes in the second quarter of 2011 that we were unable to defer during the second quarter of 2010.

Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

     Operating Income. Operating income during the first six months of 2011 decreased $85.6 million, or 11%, compared to the same period of 2010. Revenue generated by our domestic and international high-specification floater rigs increased an aggregate $89.2 million, or 12%, while revenue for our semisubmersible and jackup fleets decreased $33.5 million and $53.4 million, or 4% and 33%, respectively, during the first half of 2011 compared to the first half of 2010. The two newest additions to our floater fleet, the Ocean Courage and Ocean Valor, which began operating under contract late in the first quarter and in the fourth quarter of 2010, respectively, contributed incremental revenue of $88.0 million during the first six months of 2011. However, as of the end of the first half of 2011, we had cold stacked eight rigs, consisting of four intermediate semisubmersible units and four jack-up rigs, including the semisubmersible Ocean Epoch, which was cold stacked in the first quarter of 2011. Total contract drilling expense increased $92.4 million, or 14%, during the first six months of 2011, compared to the same period of 2010, and included a full six months of contract drilling expense for the Ocean Courage and Ocean Valor, as well as increased amortized mobilization costs and higher other operating costs associated with rigs operating internationally rather than domestically.

     In addition, during the first half of 2011, we recovered $8.4 million related to a previously established reserve for bad debt recorded in 2008 related to our operations in the U.K. We also recovered $1.7 million and $3.9 million during the first six months of 2011 and 2010, respectively, related to a reserve established in 2009 related to our operations in Egypt.

     Income Tax Expense. Our estimated annual effective tax rate for the six months ended June 30, 2011 was 21.6%, compared to the 29.2% estimated annual effective tax rate for the same period in 2010. The lower effective tax rate in the current quarter is partially the result of differences in the mix of our domestic and international pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operate. Also contributing to our lower effective tax rate in the 2011 period, compared to the prior year period, was the impact of a tax law provision that expired at the end of 2009 but was subsequently signed back into law by the President of the United States on December 17, 2010. This provision allows us to defer recognition of certain foreign earnings for U.S. income tax purposes. As a consequence of the extension of the tax law provision in December 2010, we were able to defer the

recognition of certain of our foreign earnings for U.S. income taxes purposes in the first half of 2011 that we were unable to defer during the first half of 2010.

     As a result of the tax law provision enacted in December 2010, during early 2011, we reassessed our intent to repatriate the earnings of DEAL to the U.S. We no longer intend to repatriate the earnings of DEAL to a U.S. parent but instead we plan to reinvest its earnings internationally through another of our foreign companies. Consequently, we are no longer providing U.S. income taxes on the earnings of DEAL and, during the six months ended June 30, 2011, we reversed approximately $15.0 million of U.S. income taxes provided in prior periods for the earnings of DEAL.

High-Specification Floaters.

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2011				2010				2011				2010
		(In thousands, except days, percentages and average daily
						revenue amounts)
HIGH-SPECIFICATION FLOATERS:
REVENUE EARNING DAYS (1)
GOM			152				341				242				780
Australia/Asia/Middle East			179				103				286				192
Europe/Africa/Mediterranean			273				90				494				180
South America			597				351				1,197				672
UTILIZATION (2)
GOM			84	%			87	%			67	%			80	%
Australia/Asia/Middle East			98	%			56	%			79	%			68	%
Europe/Africa/Mediterranean			100	%			99	%			91	%			99	%
South America			94	%			58	%			94	%			66	%
AVERAGE DAILY REVENUE (3)
GOM		$	346,300			$	364,600			$	249,200			$	402,900
Australia/Asia/Middle East			388,600				447,500				384,900				449,100
Europe/Africa/Mediterranean			412,200				585,000				409,100				583,100
South America			339,200				306,100				342,800				298,400
CONTRACT DRILLING REVENUE
GOM		$	52,641			$	124,677			$	60,318			$	314,797
Australia/Asia/Middle East			71,850				46,179				114,096				86,259
Europe/Africa/Mediterranean			121,427				56,386				220,099				112,707
South America			206,371				113,145				418,842				210,412
Total Contract Drilling Revenue		$	452,289			$	340,387			$	813,355			$	724,175
CONTRACT DRILLING EXPENSE
GOM		$	21,506			$	39,203			$	31,875			$	81,144
Australia/Asia/Middle East			27,390				12,372				51,946				21,610
Europe/Africa/Mediterranean			40,973				11,232				79,140				22,233
South America			113,590				71,693				221,535				118,668
Total Contract Drilling Expense		$	203,459			$	134,500			$	384,496			$	243,655
OPERATING INCOME		$	248,830			$	205,887			$	428,859			$	480,520