Edgar Filing: DIAMOND OFFSHORE DRILLING INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2011


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

For the transition period from to

Commission file number 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 April 20, 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 MARCH 31, 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		19

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		37

ITEM 4. Controls and Procedures		39

PART II. OTHER INFORMATION		39

ITEM 6. Exhibits		39

SIGNATURES		40

EXHIBIT INDEX		41
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)


	March 31,			December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	493,221		$	464,393
Marketable securities		500,564			612,346
Accounts receivable, net of allowance for bad debts		550,750			609,606
Prepaid expenses and other current assets		159,602			177,153

Total current assets		1,704,137			1,863,498
Drilling and other property and equipment, net of accumulated depreciation		4,225,999			4,283,792
Long-term receivable		15,003			35,361
Other assets		666,764			544,333

Total assets	$	6,611,903		$	6,726,984


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	66,511		$	99,236
Accrued liabilities		288,588			469,190
Taxes payable		37,423			57,862

Total current liabilities		392,522			626,288

Long-term debt		1,495,650			1,495,593
Deferred tax liability		528,164			542,258
Other liabilities		203,022			201,133

Total liabilities		2,619,358			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 March 31, 2011; 143,943,624 shares issued and 139,026,824 shares outstanding at December 31, 2010)		1,439			1,439
Additional paid-in capital		1,973,781			1,972,550
Retained earnings		2,127,333			1,998,995
Accumulated other comprehensive gain		4,405			3,141
Treasury stock, at cost (4,916,800 shares at March 31, 2011 and December 31, 2010)		(114,413	)		(114,413	)

Total stockholders’ equity		3,992,545			3,861,712

Total liabilities and stockholders’ equity	$	6,611,903		$	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
	March 31,
	2011			2010
Revenues:
Contract drilling	$	788,873		$	844,438
Revenues related to reimbursable expenses		17,516			15,243

Total revenues		806,389			859,681


Operating expenses:
Contract drilling, excluding depreciation		362,364			306,227
Reimbursable expenses		16,950			14,705
Depreciation		101,173			97,402
General and administrative		17,725			16,654
Bad debt recovery		(8,447	)		(1,100	)
Gain on disposition of assets		(2,641	)		(884	)

Total operating expenses		487,124			433,004


Operating income		319,265			426,677

Other income (expense):
Interest income		450			1,282
Interest expense		(22,044	)		(22,321	)
Foreign currency transaction gain (loss)		(1,606	)		461
Other, net		784			(87	)


Income before income tax expense		296,849			406,012

Income tax expense		(46,237	)		(115,159	)


Net income	$	250,612		$	290,853


Income per share:
Basic	$	1.80		$	2.09

Diluted	$	1.80		$	2.09


Weighted-average shares outstanding:
Shares of common stock		139,027			139,026
Dilutive potential shares of common stock		26			103

Total weighted-average shares outstanding assuming dilution		139,053			139,129


Cash dividends declared per share of common stock	$	0.875		$	2.00

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)
(In thousands)


	Three Months Ended
	March 31,
	2011			2010
Operating activities:
Net income	$	250,612		$	290,853
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		101,173			97,402
Gain on disposition of assets		(2,641	)		(884	)
Loss (gain) on sale of marketable securities, net		(783	)		1
Gain on foreign currency forward exchange contracts		(1,826	)		(2,099	)
Deferred tax provision		(14,774	)		(4,843	)
Accretion of discounts on marketable securities		(181	)		(73	)
Amortization of debt issuance costs		219			211
Amortization of debt discounts		57			89
Stock-based compensation expense		1,236			1,938
Deferred income, net		(11,021	)		55,063
Deferred expenses, net		22,597			(30,246	)
Other assets, noncurrent		897			(5,024	)
Other liabilities, noncurrent		870			5,419
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges		1,826			2,099
Changes in operating assets and liabilities:
Accounts receivable		79,759			(44,875	)
Prepaid expenses and other current assets		(1,479	)		5,052
Accounts payable and accrued liabilities		(32,753	)		(19,762	)
Taxes payable		12,691			114,560

Net cash provided by operating activities		406,479			464,881


Investing activities:
Capital expenditures		(61,743	)		(107,798	)
Deposits for construction of new rigs		(308,854	)		—
Proceeds from disposition of assets, net of disposal costs		2,786			989
Proceeds from sale and maturities of marketable securities		1,362,016			1,200,053
Purchases of marketable securities		(1,249,835	)		(1,349,900	)

Net cash used in investing activities		(255,630	)		(256,656	)


Financing activities:
Debt issuance costs and arrangement fees		—			(98	)
Payment of dividends		(122,021	)		(278,597	)
Proceeds from stock plan exercises		—			107

Net cash used in financing activities		(122,021	)		(278,588	)


Net change in cash and cash equivalents		28,828			(70,363	)
Cash and cash equivalents, beginning of period		464,393			376,417

Cash and cash equivalents, end of period	$	493,221		$	306,054

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 April 20, 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.

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 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 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).”

The effect of exchange rate changes on cash balances held in foreign currencies was not material for the three months ended March 31, 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. 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. 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 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 by assigning probabilities to various combinations of assumed utilization rates and dayrates.

During the first quarter of 2011, we cold stacked an intermediate semisubmersible rig, the Ocean Epoch, in Malaysia. The cold stacking of the Ocean Epoch, which had previously been operating offshore Australia, increased the number of cold stacked rigs in our fleet to eight. We performed an impairment review of this rig using the methodology described above, and based on our analyses, concluded that this rig was not subject to impairment at March 31, 2011.

In addition to the Ocean Epoch that was cold stacked in the first quarter of 2011, our current cold stacked fleet consists of one independent-leg, cantilevered and three mat-supported jack-up rigs (all in the U.S. Gulf of Mexico, or GOM) and three intermediate semisubmersible rigs (two in the GOM and one in Malaysia). We believe that there have been no changes in circumstances that indicate that the carrying values of these cold stacked rigs may not be recoverable.

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
	March 31,
	2011			2010
	(In thousands)
Net income	$	250,612		$	290,853
Other comprehensive gains (losses), net of tax:
FOREX contracts:
Unrealized holding gain		3,040			137
Reclassification adjustment for gain included in net income		(1,408	)		(1,085	)

Investments in marketable securities:
Unrealized holding gain (loss)		6			(4	)
Reclassification adjustment for (gain) loss included in net income		(374	)		—

Comprehensive income	$	251,876		$	289,901

The tax related to the change in unrealized holding gain on FOREX contracts for the three months ended March 31, 2011 and 2010 was approximately $1.6 million and $74,000, respectively. The tax related to the reclassification adjustment for FOREX contracts included in net income for the three months ended March 31, 2011 and 2010 was approximately $758,000 and $584,000, respectively.

The tax related to the change in unrealized holding gain on investments was approximately $3,000 for the three months ended March 31, 2011 and the tax benefit related to the change in unrealized holding loss on investments was approximately $2,000 for the three months ended March 31, 2010. The tax effect on the reclassification adjustment for net gains included in net income was approximately $201,000 for the three months ended March 31, 2011.

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 periods ended March 31, 2011 and 2010, we recognized net foreign currency transaction gain (loss) of $(1.6) million and $0.5 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 the fourth quarter of 2010 and in the first quarter of 2011 to build two 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 three months ended March 31, 2011, we reversed approximately $15.0 million of U.S. income taxes that had been provided in prior periods for the earnings of DEAL.

2. Supplemental Financial Information

Consolidated Balance Sheet Information

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


	March 31,			December 31,
	2011			2010
	(In thousands)
Trade receivables	$	547,174		$	633,224
Value added tax receivables		7,428			5,003
Unbilled third party claims		51			45
Related party receivables		400			538
Other		826			2,704

		555,879			641,514
Allowance for bad debts		(5,129	)		(31,908	)

Total	$	550,750		$	609,606

During the three months ended March 31, 2011 and 2010, we recovered $8.4 million and $1.1 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 periods ended March 31, 2011 and 2010.

In addition, during the three months ended March 31, 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:


	March 31,		December 31,
	2011		2010
	(In thousands)
Rig spare parts and supplies	$	54,905	$	50,288
Deferred mobilization costs		73,939		76,868
Prepaid insurance		3,957		9,587
Deferred tax assets		9,557		9,557
Deposits		951		827
Prepaid taxes		5,123		20,347
FOREX contracts		6,791		4,326
Other		4,379		5,353

Total	$	159,602	$	177,153

Accrued liabilities consist of the following:


	March 31,		December 31,
	2011		2010
	(In thousands)
Accrued capital project/upgrade costs	$	10,727	$	28,947
Payroll and benefits		73,360		76,041
Deferred revenue		68,130		69,825
Rig operating expenses		72,873		81,820
Interest payable		29,422		21,219
Personal injury and other claims		8,415		11,758
Accrued drillship construction installment		—		154,427
Other		25,661		25,153

Total	$	288,588	$	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 “Other assets” in our Consolidated Balance Sheets. See Note 9.

Consolidated Statement of Cash Flows Information

We paid interest on long-term debt totaling $12.5 million for each of the three-month periods ended March 31, 2011 and 2010. During the three months ended March 31, 2010, we paid $0.9 million in interest on assessments from the Internal Revenue Service.

We did not pay any U.S. federal income taxes during the three-month period ended March 31, 2011 and paid $0.5 million in the three-month period ended March 31, 2010. We paid $48.5 million and $37.3 million in foreign income taxes, net of foreign tax refunds, during the three months ended March 31, 2011 and 2010, respectively. We received a refund for state income taxes of $0.1 million during the three months ended March 31, 2010.

Capital expenditures for the three months ended March 31, 2011 included $28.9 million that was accrued but unpaid at December 31, 2010. Capital expenditures for the three months ended March 31, 2010 included $64.9 million that was accrued but unpaid at December 31, 2009. Capital expenditures that were accrued but not paid as of March 31, 2011 totaled $10.7 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at March 31, 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
	March 31,
	2011		2010
	(In thousands, except per share
	data)
Net income — basic (numerator):	$	250,612	$	290,853
Effect of dilutive potential shares
Convertible debentures		—		24

Net income including conversions — diluted (numerator)	$	250,612	$	290,877


Weighted average shares — basic (denominator):		139,027		139,026
Effect of dilutive potential shares
Convertible debentures		—		52
Stock options and SARs		26		51

Weighted average shares including conversions — diluted (denominator)		139,053		139,129

Earnings per share:
Basic	$	1.80	$	2.09

Diluted	$	1.80	$	2.09

Our computation of diluted earnings per share, or EPS, excludes stock options representing 8,000 shares of common stock and 758,976 stock appreciation rights, or SARs, for the three months ended March 31, 2011. Our computation of diluted EPS for the three months ended March 31, 2010 excludes 441,037 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the periods presented.

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:


	March 31, 2011
	Amortized		Unrealized		Market
	Cost		Gain		Value
	(In thousands)
U.S. Treasury Bills (due within one year)	$	499,982	$	7	$	499,989
Mortgage-backed securities		520		55		575

Total	$	500,502	$	62	$	500,564


	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
	March 31,
	2011			2010
	(In thousands)
Proceeds from sales	$	12,016		$	53
Proceeds from maturities		1,350,000			1,200,000
Gross realized gains		784			—
Gross realized losses		(1	)		(1	)

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.

In May 2009, we 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 three months ended March 31, 2011 and 2010, we settled FOREX contracts with an aggregate notional value of approximately $77.2 million and $52.4 million, respectively, all of which were designated as accounting hedges. During the three-month periods ended March 31, 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 periods ended March 31, 2011 and 2010.


	For the Three Months Ended March 31,
Location of Gain Recognized in Income	2011		2010
	(In thousands)
Contract drilling expense	$	1,826	$	2,099

As of March 31, 2011, we had FOREX contracts outstanding in the aggregate notional amount of $142.3 million, consisting of $7.8 million in Australian dollars, $103.7 million in Brazilian reais, $22.7 million in British pounds sterling, $1.4 million in Mexican pesos and $6.7 million in Norwegian kroner. These contracts generally settle monthly through December 2011. As of March 31, 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 financial instruments at March 31, 2011.

Assets

Liabilities

Balance Sheet

Location

Fair Value

Location

Fair Value

(In

thousands)

Derivatives designated as hedging instruments:

FOREX contracts

Prepaid expenses and
other current assets

6,791

Accrued liabilities

(77

)

The following table presents the fair values of our derivative financial instruments at December 31, 2010.

Assets

Liabilities

Balance Sheet

Location

Fair Value

Location

Fair Value

(In

thousands)

Derivatives designated as hedging instruments:

FOREX contracts

Prepaid expenses and other current assets

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 months ended March 31, 2011 and 2010.

Location of Gain

Amount of

Recognized in Income

Amount of Gain

Gain

Amount of

on Derivative

Recognized in Income on

Recognized in

Location of Gain

Gain

(Ineffective Portion and

Derivative (Ineffective

AOCG on

Reclassified from

Amount Excluded

Portion and Amount

Derivative

AOCG into Income

from Effectiveness

Excluded from

(Effective Portion)

Testing)

Effectiveness Testing)

For The Three

Months Ended

March 31,

2011

2010

2011

2010

2011

2010

(In thousands)

4,677

212

Contract drilling
expense

2,167

1,670

Foreign currency transaction gain

—

As of March 31, 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 $6.7 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 $129.9 million and $68.6 million, or 24% and 13%, respectively, of our total consolidated gross trade accounts receivable balances as of March 31, 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 $5.1 million and $31.9 million at March 31, 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 March 31, 2011, $77.4 million was payable to us from the NPI. Based on current production payout estimates, we expect to collect $62.4 million of the receivable within the next twelve months and have presented this amount in “Accounts receivable” in our Consolidated Balance Sheets. The remaining $15.0 million has been presented as “Long-term receivable” in our Consolidated Balance Sheets. At March 31, 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.



	March 31, 2011				December 31, 2010
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
4.875% Senior Notes	$	267.7	$	249.7	$	270.0	$	249.7
5.15% Senior Notes		270.9		249.7		271.1		249.7
5.70% Senior Notes		491.8		496.8		493.1		496.8
5.875% Senior Notes		547.8		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 March 31, 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 March 31, 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 March 31, 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 was 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 March 31, 2011 consisted of cash held in money market funds of $460.3 million and investments in U.S. Treasury Bills of $500.0 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:


	March 31, 2011
	Fair Value Measurements Using							Assets at Fair
	Level 1		Level 2			Level 3		Value
	(In thousands)
Assets:
Short-term investments	$	960,311	$	—		$	—	$	960,311
FOREX contracts		—		6,791			—		6,791
Mortgage-backed securities		—		575			—		575

Total assets	$	960,311	$	7,366		$	—	$	967,677


Liabilities:

FOREX contracts	$	—	$	(77	)	$	—	$	(77	)


	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:


	March 31,			December 31,
	2011			2010
	(In thousands)
Drilling rigs and equipment	$	7,203,766		$	7,163,196
Land and buildings		58,460			56,536
Office equipment and other		45,560			44,689

Cost		7,307,786			7,264,421
Less: accumulated depreciation		(3,081,787	)		(2,980,629	)

Drilling and other property and equipment, net	$	4,225,999		$	4,283,792

8. Long-Term Debt

Long-term debt consists of the following:


	March 31,		December 31,
	2011		2010
	(In thousands)
5.15% Senior Notes (due 2014)	$	249,762	$	249,745
4.875% Senior Notes (due 2015)		249,738		249,724
5.875% Senior Notes (due 2019)		499,366		499,351
5.70% Senior Notes (due 2039)		496,784		496,773

Total	$	1,495,650	$	1,495,593

The aggregate maturities of long-term debt for each of the five years subsequent to March 31, 2011, are as follows:


(Dollars in thousands)
2012	$	—
2013		—
2014		249,762
2015		249,738
2016		—
Thereafter		996,150

Total	$	1,495,650

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 March 31, 2011, our estimated liability for personal injury claims was $37.3 million, of which $7.6 million and $29.7 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. In December 2010 and January 2011, we entered into separate turnkey contracts with Hyundai for the construction of two dynamically positioned, ultra-deepwater drillships, the Ocean BlackHawk and Ocean BlackHornet, with deliveries scheduled for late in the second and fourth quarters of 2013, respectively. The aggregate cost of both drillships, including commissioning, spares and project management, is expected to be approximately $1.2 billion.

The contracted price of each drillship is payable in two installments. The first installments, aggregating $308.9 million, were paid in the first quarter of 2011 and are reported in “Other assets” in our Consolidated Balance Sheets. At March 31, 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 March 31, 2011 in the amount of $95.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $10.6 million in letters of credit issued under our $285 million, syndicated, senior unsecured revolving credit facility. At March 31, 2011, we had purchased three of our outstanding bonds, totaling $47.7 million, from a related party after obtaining competitive quotes. Agreements relating to approximately $47.7 million of performance bonds can

require collateral at any time. As of March 31, 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 Financial Accounting Standards Board Accounting Standards Codification Topic 280, Segment Reporting.

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


	Three Months Ended
	March 31,
	2011		2010
	(In thousands)
High-Specification Floaters	$	361,066	$	383,788
Intermediate Semisubmersibles		379,499		380,701
Jack-ups		48,218		79,949
Other		90		—

Total contract drilling revenues		788,873		844,438
Revenues related to reimbursable expenses		17,516		15,243

Total revenues	$	806,389	$	859,681

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 March 31, 2011, our drilling rigs were located offshore thirteen 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
	March 31,
	2011		2010
	(In thousands)
United States	$	50,274	$	238,547

International:
South America		444,103		283,115
Australia/Asia/Middle East		104,668		158,929
Europe/Africa/Mediterranean		190,048		136,606
Mexico		17,296		42,484

Total revenues	$	806,389	$	859,681


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 two drillships on order with expected deliveries late in the second and the fourth quarters of 2013.

Overview

Industry Conditions

On October 12, 2010, the U.S. government lifted the ban on certain drilling activities in the U.S. Gulf of Mexico, or GOM. All drilling in the GOM is now subject to compliance with enhanced safety requirements set forth in Notices to Lessees, or NTL, 2010-N05 or 2010-N06, both of which were implemented during the drilling ban. Additionally, all drilling in the GOM is required to comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management Systems, as well as NTL 2010-N10 (known as the Compliance and Review NTL). We continue to evaluate these new measures to ensure that our rigs and equipment are in full compliance, where applicable. Additional requirements could be forthcoming based on further recommendations by regulatory agencies continuing to investigate the Macondo well incident that occurred on April 20, 2010. We are not able to predict the likelihood, nature or extent of any additional rulemaking. During the first quarter of 2011, the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, began issuing a limited number of new drilling permits. However, we are not able 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 35 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. As of the date of this report, we have three semisubmersible units under contract in the GOM, including the Ocean Monarch, whose contract the operator has sought to terminate,, as well as two jack-up units, both of which are under contract. Given the continuing uncertainty with respect to drilling activity in the GOM, our customers may seek to move additional rigs to locations outside of the GOM or to perform activities which are allowed under the enhanced safety requirements.

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 in the near term. In addition, given the ongoing uncertainty in the GOM with respect to drilling activity and other industry factors, we have cold stacked two intermediate floaters and four jack-up rigs in the GOM.

While dayrates we receive for new contracts are no longer at the peak levels achieved at the height of the most recent up-cycle, improving oil prices, which have climbed as high as $112 per barrel since 2011 began, appear to be supporting demand for our equipment. As a result, dayrates for our international floater units appear to have stabilized, although demand for our services has not risen sufficiently to provide significant pricing power on new contracts. Additionally, the continuing regulatory uncertainty in the GOM could cause us or others to move additional rigs out of the GOM to international locations. If we, or others, move a large number of additional rigs out of the GOM to international locations, the increased supply of available rigs entering the international market, coupled with un-contracted new-build rigs scheduled for delivery between now and the end of 2011, could create downward pressure on dayrates unless demand improves sufficiently to absorb the new supply.

Since December 31, 2010 through the date of this report, we have entered into 17 new drilling contracts totaling approximately $254.0 million in backlog and ranging in duration from one well to a 430-day term. As of April 18, 2011, our contract backlog was approximately $6.1 billion, of which our contracts in the GOM represented approximately $133.0 million, or 2%, of our total contract backlog, excluding any contract backlog attributable to the Ocean Monarch pursuant to a contract that the operator has sought to terminate.

Floaters

Our intermediate and high-specification floater rigs, both domestic and international, accounted for approximately 92% of our revenue during the first quarter of 2011. Approximately 73% of the time on our intermediate and high-specification floater rigs is committed for the remainder of 2011. Additionally, 52% of the time on our floating rigs is committed in 2012.

International Jack-ups

During the first quarter of 2011, demand for our international jack-ups remained weak but stable. However, the high-specification new-build equipment coming to market is enjoying a significantly higher utilization rate than older existing equipment, and the oversupply of jack-up rigs could have an increasingly negative impact on the international sector throughout the remainder of 2011 and beyond.

U.S. Gulf of Mexico Jack-ups

The jack-up market in the GOM has been adversely impacted by the slow issuance of jack-up permits subsequent to the lifting of the drilling moratorium, as well as the impact of lower natural gas prices on both demand and dayrates. Our two remaining jack-ups in the GOM are primarily working under short-term contracts and could experience significant downtime unless permitting activity increases or if natural gas prices deteriorate further. Absent an increase in permitting activity and a sustained improvement in natural gas prices, weakness in the GOM jack-up market is likely to continue throughout 2011, with the possibility of additional rigs being cold stacked by us and others in the industry.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of April 18, 2011, February 1, 2011 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2010) and April 19, 2010 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 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.


	April 18,		February 1,		April 19,
	2011		2011		2010⁽⁴⁾
	(In thousands)
Contract Drilling Backlog
High-Specification Floaters ⁽¹⁾	$	3,540,000	$	3,838,000	$	5,175,000
Intermediate Semisubmersibles⁽²⁾		2,452,000		2,700,000		3,767,000
Jack-ups ⁽³⁾		111,000		107,000		185,000

Total	$	6,103,000	$	6,645,000	$	9,127,000


(1)		Contract drilling backlog as of April 18, 2011 for our high-specification floaters includes (i) $2.8 billion attributable to our contracted operations offshore Brazil for the years 2011 to 2016 and (ii) $112.0 million attributable to our contracted operations in the GOM during 2011.

(2)		Contract drilling backlog as of April 18, 2011 for our intermediate semisubmersibles includes (i) $1.9 billion attributable to our contracted operations offshore Brazil for the years 2011 to 2015 and (ii) $18.0 million attributable to our contracted operations in the GOM during 2011.

(3)		Contract drilling backlog as of April 18, 2011 for our jack-ups includes (i) $51.0 million attributable to our contracted operations offshore Brazil for the years 2011 to 2012 and (ii) $3.0 million attributable to our contracted operations in the GOM during 2011.

(4)		Contract drilling backlog as of April 19, 2010 includes $395.8 million attributable to the Ocean Monarch pursuant to a contract that the operator has sought to terminate.

The following table reflects the amount of our contract drilling backlog by year as of April 18, 2011.


	For the Years Ending December 31,
	Total		2011⁽¹⁾		2012		2013		2014 - 2016
	(In thousands)
Contract Drilling Backlog
High-Specification Floaters ⁽²⁾	$	3,540,000	$	1,126,000	$	1,064,000	$	631,000	$	719,000
Intermediate Semisubmersibles ⁽³⁾		2,452,000		882,000		827,000		428,000		315,000
Jack-ups ⁽⁴⁾		111,000		97,000		14,000		—		—

Total	$	6,103,000	$	2,105,000	$	1,905,000	$	1,059,000	$	1,034,000


(1)		Represents a nine-month period beginning April 1, 2011.

(2)		Contract drilling backlog as of April 18, 2011 for our high-specification floaters includes (i) $630.0 million, $799.0 million and $613.0 million for the years 2011 to 2013, respectively, and $720.0 million in the aggregate for the years 2014 to 2016, attributable to our contracted operations offshore Brazil and (ii) $112.0 million for 2011 attributable to our contracted operations in the GOM.

(3)		Contract drilling backlog as of April 18, 2011 for our intermediate semisubmersibles includes (i) $559.0 million, $700.0 million and $371.0 million for the years 2011 to 2013, respectively, and $315.0 million in the aggregate for the years 2014 to 2016, attributable to our contracted operations offshore Brazil and (ii) $18.0 million for 2011 attributable to our contracted operations in the GOM.

(4)		Contract drilling backlog as of April 18, 2011 for our jack-ups includes (i) $37.0 million and $14.0 million for years 2011 and 2012, respectively, attributable to our contracted operations offshore Brazil and (ii) $3.0 million for 2011 attributable to our contracted operations in the GOM.

The following table reflects the percentage of rig days committed by year as of April 18, 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).


	For the Years Ending December 31,
	2011⁽¹⁾			2012			2013			2014 - 2016
Rig Days Committed ⁽²⁾
High-Specification Floaters		81	%		62	%		34	%		13	%
Intermediate Semisubmersibles		67	%		44	%		22	%		5	%
Jack-ups		35	%		2	%		—			—


(1)		Represents a nine-month period beginning April 1, 2011.

(2)		Includes approximately 550 and 403 scheduled shipyard, survey and mobilization days for 2011 and 2012, respectively.

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, six of our rigs will require 5-year surveys, and we expect that they will be out of service for approximately 360 days in the aggregate. We also expect to spend an additional approximately 190 days during 2011 for intermediate surveys, the mobilization of rigs 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 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. Under our insurance policy that expires on May 1, 2011, 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.

In addition, under our insurance policy that expires on May 1, 2011, 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. We believe that the 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 is appropriate for our business. 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 the current policy commences on May 1 of each year.

We are in the process of renewing our principal insurance coverages to be effective May 1, 2011. While we expect our coverage and policy limits for physical damage insurance to be similar to our current policy, the availability of liability coverage in our insurance market has contracted and we expect that our policy limits for marine liability insurance may decrease. We expect, however, that the policy limits for our marine liability insurance will remain within the range that is customary for companies of our size in the offshore drilling industry, and at levels we believe to be appropriate for our business.

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 three months ended March 31, 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 of our notes to consolidated financial statements included 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 Months Ended March 31, 2011 and 2010

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


	Three Months Ended
	March 31,
	2011			2010
	(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters	$	361,066		$	383,788
Intermediate Semisubmersibles		379,499			380,701
Jack-ups		48,218			79,949
Other		90			—

Total Contract Drilling Revenue	$	788,873		$	844,438


Revenues Related to Reimbursable Expenses	$	17,516		$	15,243

CONTRACT DRILLING EXPENSE
High-Specification Floaters	$	181,037		$	109,155
Intermediate Semisubmersibles		137,737			138,599
Jack-ups		42,100			53,628
Other		1,490			4,845

Total Contract Drilling Expense	$	362,364		$	306,227


Reimbursable Expenses	$	16,950		$	14,705

OPERATING INCOME
High-Specification Floaters	$	180,029		$	274,633
Intermediate Semisubmersibles		241,762			242,102
Jack-ups		6,118			26,321
Other		(1,400	)		(4,845	)
Reimbursable expenses, net		566			538
Depreciation		(101,173	)		(97,402	)
General and administrative expense		(17,725	)		(16,654	)
Bad debt recovery		8,447			1,100
Gain on disposition of assets		2,641			884

Total Operating Income	$	319,265		$	426,677


Other income (expense):
Interest income		450			1,282
Interest expense		(22,044	)		(22,321	)
Foreign currency transaction gain (loss)		(1,606	)		461
Other, net		784			(87	)

Income before income tax expense		296,849			406,012
Income tax expense		(46,237	)		(115,159	)

NET INCOME	$	250,612		$	290,853

Operating Income. Operating income during the first quarter of 2011 decreased $107.4 million, or 25%, compared to the same period of 2010. During the first three months of 2011, our operating results were negatively impacted by a decline in revenue earned by our rigs despite an improvement in oil prices from the same time a year ago.

Aggregate revenues during the first quarter of 2011 decreased $55.6 million, or 7%, compared to the first quarter of 2010, as a result of a decline in dayrates earned across our fleet, primarily by our high-specification floaters and our jack-ups, as well as a decrease in average utilization for our overall fleet from 74% during the first quarter of 2010 to 71% during the first quarter of 2011. Revenue generated by our domestic and international floater rigs decreased an aggregate $23.9 million, or 3%, and revenue for our combined jackup fleet decreased $31.7 million, or 40%, during the first quarter of 2011 compared to the first quarter of 2010. In February 2011, we cold stacked an intermediate semisubmersible floater in Malaysia which had previously operated offshore Australia. However, 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 $54.7 million during the first quarter of 2011. Total contract drilling expense increased $56.1 million, or 18%, during the first quarter of 2011, compared to the first quarter of 2010, and included normal operating costs 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 quarter 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. During the first quarter of 2010, we recovered $1.1 million related to a reserve established in 2009 related to our operations in Egypt.

Income Tax Expense. Our estimated annual effective tax rate for the three months ended March 31, 2011 was 20.5%, compared to the 28.6% 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 first quarter of 2011 that we were unable to defer during the first quarter of 2010.

As a result of the tax law provision enacted in December 2010 and our decisions in the fourth quarter of 2010 and during the first quarter of 2011 to build two new drillships overseas, 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 first quarter of 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
	March 31,
	2011			2010
	(In thousands, except days,
	percentages and average daily
	revenue amounts)
HIGH-SPECIFICATION FLOATERS:
REVENUE EARNING DAYS ⁽¹⁾
GOM		90			439
Australia/Asia/Middle East		107			89
Europe/Africa/Mediterranean		221			90
South America		600			321

UTILIZATION ⁽²⁾
GOM		50	%		76	%
Australia/Asia/Middle East		59	%		88	%
Europe/Africa/Mediterranean		82	%		84	%
South America		95	%		77	%

AVERAGE DAILY REVENUE ⁽³⁾
GOM	$	85,300		$	431,900
Australia/Asia/Middle East		378,600			451,000
Europe/Africa/Mediterranean		405,200			584,700
South America		346,400			290,000

CONTRACT DRILLING REVENUE
GOM	$	7,677		$	190,120
Australia/Asia/Middle East		42,246			40,080
Europe/Africa/Mediterranean		98,672			56,321
South America		212,471			97,267

Total Contract Drilling Revenue	$	361,066		$	383,788


CONTRACT DRILLING EXPENSE
GOM	$	10,369		$	41,941
Australia/Asia/Middle East		24,556			9,238
Europe/Africa/Mediterranean		38,167			11,001
South America		107,945			46,975

Total Contract Drilling Expense	$	181,037		$	109,155



OPERATING INCOME	$	180,029		$	274,633


⁽¹⁾		A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

⁽²⁾		Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all of the specified rigs in our fleet (including cold-stacked rigs).

⁽³⁾		Average daily revenue is defined as contract drilling revenue for all of the specified rigs in our fleet (excluding revenues for mobilization, demobilization and contract preparation) per revenue earning day.

Rig Relocations:


Rig	Relocation Details	Date
*2011:*
Ocean Confidence	Europe/Africa/Mediterranean (Republic of Congo to Angola)	January 2011

*2010:*
Ocean Star	GOM to South America (Brazil)	January 2010
Ocean Valor	Completion of construction and relocation from Singapore shipyard to South America (Brazil)	March 2010
Ocean Courage	GOM to South America (Brazil)	March 2010
Ocean Baroness	GOM to South America (Brazil)	March 2010
Ocean America	GOM to Australia/Asia/Middle East (Australia)	March 2010
Ocean Confidence	GOM to Europe/Africa/Mediterranean (Republic of Congo)	August 2010
Ocean Endeavor	GOM to Europe/Africa/Mediterranean (Egypt)	August 2010
Ocean Rover	Australia/Asia/Middle East (Malaysia to Indonesia)	November 2010

GOM. Revenues generated by our high-specification floaters operating in the GOM decreased $182.4 million during the first quarter of 2011, compared to the same period in 2010, as a result of 349 fewer revenue earning days ($150.9 million) and a decrease in average daily revenue earned during the first quarter of 2011 ($31.2 million). The decrease in revenue earning days is primarily due to the relocation out of the GOM of six of our high-specification rigs since the first quarter of 2010 (three to Brazil and one each to Australia, the Republic of Congo and Egypt) and unplanned downtime for the Ocean Monarch due to a force majeure assertion by one of our customers in the GOM following the April 2010 Macondo well incident. Contract drilling expense for high-specification floaters in the GOM for the first quarter of 2011 decreased by $31.6 million, compared to the first quarter of 2010, primarily due to a $30.2 million reduction attributable to the rigs which relocated to other regions as well as a reduction in normal operating costs associated with downtime for the Ocean Monarch.

Australia/Asia/Middle East. Revenue from our high-specification rigs operating in the Australia/Asia/Middle East region increased $2.2 million during the first quarter of 2011, compared to the same period of 2010, primarily due to a $1.8 million increase in amortized mobilization revenue recognized in the first quarter of 2011 compared to the same period in 2010. The favorable effect in the first quarter of 2011 of 18 incremental revenue earning days for the Ocean America operating offshore Australia was partially offset by the impact of a decrease in average dayrate earned by the Ocean Rover operating offshore Indonesia during the 2011 quarter. Contract drilling expense for our operations in this region increased $15.3 million during the first quarter of 2011, compared to the same period of 2010, primarily due to the inclusion of normal operating and amortized mobilization costs for the Ocean America ($14.7 million).

Europe/Africa/Mediterranean. Revenue generated by our high-specification floaters operating in the Europe/Africa/Mediterranean region increased $42.4 million during the first quarter of 2011, compared to the same period of 2010, primarily due to 131 incremental revenue earning days during the first three months of 2011 ($76.4 million), partially offset by a decrease in average daily revenue earned ($39.6 million). These revenue changes reflect 133 incremental revenue earning days and lower dayrates earned by our two additional rigs operating in this region in the first quarter of 2011 compared to the first quarter of 2010 when only the Ocean Valiant was operating offshore Angola. Contract drilling expense for our operations during the first three months of 2011 increased $27.2 million, compared to the same period of 2010, due to the inclusion of normal operating and amortized mobilization costs for the two additional rigs in the region during the 2011 period.

South America. Revenues earned by our high-specification floaters operating offshore Brazil during the first quarter of 2011 increased $115.2 million, compared to the first quarter of 2010, primarily due to 279 incremental revenue earning days during the first three months of 2011 ($80.6 million) compared to the prior year quarter. The increase in revenue earning days during the first quarter of 2011 was the result of relocating four rigs (including the Ocean Valor) to this region during the first quarter of 2010, where they generated additional revenues of $90.9 million during the first quarter of 2011. Contract drilling expense for our operations in Brazil increased $61.0 million during the first quarter of 2011, compared to the same period in 2010, primarily due to the inclusion of normal operating costs for the relocated rigs for the entire first quarter of 2011 and higher repair and maintenance costs for the Ocean Quest.

Intermediate Semisubmersibles.


	Three Months Ended
	March 31,
	2011			2010
	(In thousands, except days,
	percentages and average daily
	revenue amounts)
INTERMEDIATE SEMISUBMERSIBLES:
REVENUE EARNING DAYS ⁽¹⁾
GOM		90			98
Mexico		—			88
Australia/Asia/Middle East		216			260
Europe/Africa/Mediterranean		264			180
South America		798			707

UTILIZATION ⁽²⁾
GOM		33	%		81	%
Mexico		—			59	%
Australia/Asia/Middle East		60	%		72	%
Europe/Africa/Mediterranean		98	%		61	%
South America		98	%		93	%

AVERAGE DAILY REVENUE ⁽³⁾
GOM	$	202,800		$	199,200
Mexico		—			263,400
Australia/Asia/Middle East		266,900			326,800
Europe/Africa/Mediterranean		308,100			369,700
South America		270,300			251,400

CONTRACT DRILLING REVENUE
GOM	$	18,251		$	19,552
Mexico		—			23,752
Australia/Asia/Middle East		57,592			85,028
Europe/Africa/Mediterranean		81,465			66,537
South America		222,191			185,832

Total Contract Drilling Revenue	$	379,499		$	380,701


CONTRACT DRILLING EXPENSE
GOM	$	4,179		$	6,428
Mexico		72			10,852
Australia/Asia/Middle East		23,616			24,824
Europe/Africa/Mediterranean		20,743			22,421
South America		89,127			74,074

Total Contract Drilling Expense	$	137,737		$	138,599



OPERATING INCOME	$	241,762		$	242,102


⁽¹⁾		A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

⁽²⁾		Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all of the specified rigs in our fleet (including cold-stacked rigs).

⁽³⁾		Average daily revenue is defined as contract drilling revenue for all of the specified rigs in our fleet (excluding revenues for mobilization, demobilization and contract preparation) per revenue earning day.

Rig Relocations:


Rig	Relocation Details	Date
*2011*:
Ocean Epoch	Australia/Asia/Middle East (cold stacked February 2011)	February 2011

*2010*:
Ocean Voyager	Mexico to GOM (cold stacked June 2010)	March 2010
Ocean New Era	Mexico to GOM (cold stacked September 2010)	August 2010

GOM. Revenues and contract drilling expense for our rigs working in the GOM decreased $1.3 million and $2.3 million, respectively, during the first quarter of 2011, compared to the same quarter of 2010, primarily due to a decrease in utilization of our GOM semisubmersible fleet from 81% in the first quarter of 2010 to 33% in the first quarter of 2011. We currently have only one semisubmersible unit operating in the GOM; two other semisubmersible floaters were cold stacked during 2010 after their return from offshore Mexico.

Mexico. Our two intermediate semisubmersible rigs operating offshore Mexico during the first quarter of 2010 generated revenues and incurred contract drilling expense of $23.8 million and $10.9 million, respectively, including a $4.0 million lump sum demobilization fee earned by the Ocean Voyager on completion of its contract offshore Mexico. These rigs were relocated to the GOM after completing their contracts offshore Mexico during 2010. We currently have no intermediate semisubmersible rigs operating offshore Mexico.

Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working in the Australia/Asia/Middle East region decreased $27.4 million during the first quarter of 2011, compared to the same period of 2010, as a result of 44 fewer revenue earning days ($14.5 million) combined with a decrease in average daily revenue earned ($12.9 million) during the first quarter of 2011. The decrease in revenue during the first quarter of 2011 was primarily due to cold stacking the Ocean Epoch after completion of its contract in February 2011. Contract drilling expense decreased slightly during the first quarter of 2011, compared to the same quarter of the prior year, as reduced costs for the cold stacked Ocean Bounty and Ocean Epoch were partially offset by increased operating costs for the Ocean Patriot.

Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region increased $14.9 million during the first quarter of 2011, compared to the same period in 2010, primarily due to 84 more revenue earning days ($31.2 million) partially offset by a reduction in average daily revenue earned ($16.3 million) during the first quarter of 2011. The net increase in revenue earned during the first quarter of 2011, compared to the prior year quarter, is primarily attributable to 86 incremental revenue earning days for the Ocean Nomad, which was ready stacked the entire first quarter of 2010, partially offset by a lower dayrate earned by the Ocean Vanguard due to a decrease in contracted dayrate earned subsequent to the first quarter of 2010.

South America. Both revenue earning days and average daily revenue earned by our intermediate semisubmersible fleet working in the South America region increased during the first quarter of 2011, compared to the same quarter of the prior year, and contributed total incremental revenue of $22.8 million and $15.1 million, respectively. The increase in revenue earning days was attributable to the full utilization of the Ocean Guardian (Falkland Islands) and Ocean Lexington (Brazil) during the first quarter of 2011 compared to only partial utilization of these rigs during the same quarter of 2010. In addition, during March 2010, the Ocean Winner began operating under a contract extension at a higher dayrate than its previous contract. Contract drilling expense increased $15.0 million during the first quarter of 2011, compared to the prior year quarter, due to a full quarter of operating costs for the Ocean Guardian and Ocean Lexington during the first three months of 2011, compared to the prior year quarter, as well as higher operating costs in the region, including labor and related costs, repair costs and freight.

Jack-Ups.


	Three Months Ended
	March 31,
	2011			2010
	(In thousands, except days,
	percentages and average daily
	revenue amounts)
JACK-UPS:
REVENUE EARNING DAYS ⁽¹⁾
GOM		105				250
Mexico		159				135
Australia/Asia/Middle East		52				180
Europe/Africa/Mediterranean		180				227
South America		59				—

UTILIZATION ⁽²⁾
GOM		19	%			40	%
Mexico		88	%			75	%
Australia/Asia/Middle East		58	%			100	%
Europe/Africa/Mediterranean		67	%			84	%
South America		66	%			—

AVERAGE DAILY REVENUE ⁽³⁾
GOM	$	64,300			$	54,600
Mexico		108,900				135,200
Australia/Asia/Middle East		63,700				187,900
Europe/Africa/Mediterranean		55,100				60,400
South America		141,200				—

CONTRACT DRILLING REVENUE
GOM	$	6,740			$	13,632
Mexico		17,296				18,732
Australia/Asia/Middle East		4,830				33,821
Europe/Africa/Mediterranean		9,911				13,748
South America		9,441				16

Total Contract Drilling Revenue	$	48,218			$	79,949


CONTRACT DRILLING EXPENSE
GOM	$	6,550			$	20,117
Mexico		9,845				11,043
Australia/Asia/Middle East		5,036				11,762
Europe/Africa/Mediterranean		10,896				9,502
South America		9,773				1,204

Total Contract Drilling Expense	$	42,100			$	53,628



OPERATING INCOME	$	6,118			$	26,321


⁽¹⁾		A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

⁽²⁾		Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all of the specified rigs in our fleet (including cold-stacked rigs).

⁽³⁾		Average daily revenue is defined as contract drilling revenue for all of the specified rigs in our fleet (excluding revenues for mobilization, demobilization and contract preparation) per revenue earning day.

Rig Relocations:


Rig	Relocation Details	Date
*2011:*
None

*2010:*
Ocean Shield	Sold	July 2010
Ocean Scepter	GOM to South America (Brazil)	August 2010
Ocean Spartan	Cold stacked (GOM)	September 2010

GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $6.9 million during the first quarter of 2011, compared to the first quarter of 2010, due to 145 fewer revenue earning days during the first quarter of 2011 ($7.9 million), primarily as a result of the relocation of the Ocean Scepter out of the GOM and the cold stacking of the Ocean Spartan in the third quarter of 2010. The decrease in revenue from fewer revenue earning days during the first quarter of 2011 was partially offset by the effect of higher average daily revenue earned during the first three months of 2011 ($1.0 million). Contract drilling expense for our jack-ups in the GOM decreased $13.6 million during the first quarter of 2011, compared to the same period of 2010, primarily due to cold stacking the Ocean Spartan, relocation of the Ocean Scepter to Brazil, and the absence of inspection and related repair costs for the Ocean Columbia during the first quarter of 2011.

Mexico. Revenue generated by our jack-up fleet operating offshore Mexico during the first quarter of 2011 decreased $1.4 million, compared to same quarter of 2010, primarily due to a decrease in average daily revenue earned ($4.2 million), partially offset by the effect of 24 additional revenue earning days ($3.2 million).

Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the Australia/Asia/Middle East region decreased $29.0 million during the first quarter of 2011, compared to the same period in 2010, primarily due to 128 fewer revenue earning days ($24.0 million) and a reduction of average daily revenue earned ($6.5 million) during the first quarter of 2011. Revenue earning days during the first three months of 2011 decreased primarily due to the sale of the Ocean Shield in 2010. Contract drilling expense decreased $6.7 million during the first quarter of 2011, compared to the same period in 2010, primarily due to a reduction in costs for the Ocean Shield ($7.6 million).

Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region decreased $3.8 million during the first quarter of 2011, compared to the same period in 2010, primarily due to a decrease of 47 revenue earning days ($2.9 million) and a decrease in average daily revenue earned ($0.9 million) during the first quarter of 2011. Contract drilling expense increased $1.4 million during the first quarter of 2011, compared to the same period in 2010, primarily due to higher overhead and repair costs.

South America. Contract drilling revenues and expenses increased $9.4 million and $8.6 million, respectively, during the first quarter of 2011 compared to same period in 2010. Our sole jack-up rig in the region, the Ocean Scepter, was relocated to offshore Brazil in August 2010 and began operating under contract in the first quarter of 2011.

Sources of Liquidity and Capital Resources

Our principal sources of liquidity and capital resources are cash flows from our operations and our cash reserves. We may also make use of our $285 million credit facility for cash liquidity. See “— $285 Million Revolving Credit Facility.”

At March 31, 2011, we had $493.2 million in “Cash and cash equivalents” and $500.6 million in “Investments and marketable securities,” representing our investment of cash available for current operations.

Cash Flows from Operations. Our cash flows from operations are impacted by the ability of our customers to weather instability in the U.S. and global economies, as well as the volatility in energy prices. 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. If a potential customer is unable to obtain an adequate level of credit, it may preclude us from doing business with that potential customer.

These external factors which affect our cash flows from operations are not within our control and are difficult to predict. For a description of other factors that could affect our cash flows from operations, see “— Overview — Industry Conditions,” “ — Forward-Looking Statements” and “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010.

One of our drilling contracts obligates our customer to pay us, over the term of the six-well 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. Two wells remain to be drilled under this contract. We have collected $17.0 million through the NPI since July 2010.

At March 31, 2011, $77.4 million was payable to us from the NPI. Based on current production payout estimates, we expect to collect $62.4 million of the receivable within the following twelve months and have presented this amount in “Accounts receivable” in our Consolidated Balance Sheets included in Item 1 of Part I of this report. The remaining $15.0 million has been presented as “Long-term receivable” in our Consolidated Balance Sheets at March 31, 2011 included in Item 1 of Part I of this report. However, payment of such amounts, and the timing of such payments, is contingent upon such production and upon energy sale prices. At March 31, 2011, we believe that collectability of the amount owed pursuant to the NPI arrangement was reasonably assured.

$285 Million Revolving Credit Facility. We maintain a $285 million syndicated, senior unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including loans and performance or standby letters of credit, that will mature on November 2, 2011.

Loans under the Credit Facility bear interest at a rate per annum equal to, at our election, either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. Under our Credit Facility, we also pay, based on our current credit ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on the total commitment under the Credit Facility regardless of usage and a utilization fee that applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50% of the total commitment under the facility. Changes in our credit ratings could lower or raise the fees that we pay under the Credit Facility.

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

Based on our current credit ratings at March 31, 2011, the applicable margin on LIBOR loans would have been 0.24%. As of March 31, 2011, there were no loans outstanding under the Credit Facility; however $10.6 million in letters of credit were issued and outstanding under the Credit Facility.

Liquidity and Capital Requirements

Our liquidity and capital requirements are primarily a function of our working capital needs, capital expenditures and debt service requirements. We determine the amount of cash required to meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements, our ongoing rig equipment replacement and enhancement programs, and our obligations relating to the construction of our new drillships. We believe that our operating cash flows and cash reserves will be sufficient to meet both our working capital requirements and our capital commitments over the next twelve months; however, we will continue to make periodic assessments based on industry conditions and will adjust capital spending programs if required.

In addition, we may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current market conditions and other factors beyond our control. Additionally, we may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes.

Contractual Cash Obligations. The following table sets forth our contractual cash obligations at March 31, 2011.


	Payments Due By Period
Contractual Obligations			Less than						After 5
	Total		1 year		1 — 3 years		4 — 5 years		years
	(In thousands)
Long-term debt (principal and interest) ⁽¹⁾	$	2,676,026	$	70,407	$	165,876	$	652,931		1,786,813
Construction contracts ⁽²⁾		720,660		—		720,660		—		—
Operating leases		3,300		1,900		1,400		—		—

Total obligations	$	3,399,986	$	72,307	$	887,936	$	652,931	$	1,786,813


⁽¹⁾		See Note 8 “Long-Term Debt” to our Consolidated Financial Statements in Item 1 Part 1 of this report.

⁽²⁾		In December 2010 and January 2011, we entered into separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of two dynamically positioned, ultra-deepwater drillships with deliveries scheduled for late in the second and fourth quarters of 2013. See Note 9 “Commitments and Contingencies — Purchase Obligations” to our Consolidated Financial Statements in Item 1 Part 1 of this report.

The above table excludes foreign currency forward exchange, or FOREX, contracts in the aggregate notional amount of $142.3 million outstanding at March 31, 2011. See further information regarding these contracts in Item 3, “Quantitative and Qualitative Disclosures About Market Risk — Foreign Exchange Risk” and Note 5 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 1 of Part I of this report.

As of March 31, 2011, the total unrecognized tax benefit related to uncertain tax positions was $47.9 million. In addition, we have recorded a liability, as of March 31, 2011, for potential penalties and interest of $26.7 million and $9.6 million, respectively, related to the tax benefit related to uncertain tax positions. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

We had no other purchase obligations for major rig upgrades or any other significant obligations at March 31, 2011, except for those related to our direct rig operations, which arise during the normal course of business.

Other Commercial Commitments — Letters of Credit.

We were contingently liable as of March 31, 2011 in the amount of $95.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $10.6 million in letters of credit issued under our Credit Facility. We purchased three of these bonds totaling $47.7 million from a related party after obtaining competitive quotes. Agreements relating to approximately $47.7 million of performance bonds can require collateral at any time. As of March 31, 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. Banks have issued letters of credit on our behalf securing certain of these bonds. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.


			For the Years Ending December 31,
	Total		2011		2012		Thereafter
	(In thousands)
Other Commercial Commitments
Customs bonds	$	5,559,129	$	5,559,129	$	—	$	—
Performance bonds		59,302,313		39,324,897		19,977,416		—
Other		30,788,510		2,730,000		28,058,510

Total obligations	$	95,649,952	$	47,614,026	$	48,035,926	$	—

Credit Ratings.

Our current credit rating is Baa1 for Moody’s Investors Services and A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings would result in higher rates for borrowings under our Credit Facility and could also result in higher interest rates on future debt issuances.

Capital Expenditures.

We have budgeted approximately $320 million on capital expenditures for 2011 associated with our ongoing rig equipment replacement and enhancement programs and other corporate requirements. During the first three months of 2011, we spent approximately $61.7 million toward these programs. In addition, in the first quarter of 2011, we paid $308.9 million to Hyundai as first installments for the construction of two new, ultra-deepwater drillships, the Ocean BlackHornet and Ocean BlackHawk, with delivery scheduled for late in the second and fourth quarters of 2013, respectively. The total cost, including commissioning, spares and project management, is expected to be approximately $1.2 billion. We also have a fixed-price option from Hyundai for the purchase of a third drillship, which expires in May 2011.

We expect to finance our 2011 capital expenditures through the use of our existing cash balances or internally generated funds. From time to time, however, we may also make use of our Credit Facility to finance capital expenditures.

Off-Balance Sheet Arrangements.

At March 31, 2011 and December 31, 2010, we had no off-balance sheet debt or other arrangements.

Historical Cash Flows

The following is a discussion of our historical cash flows from operating, investing and financing activities for the three months ended March 31, 2011 compared to the three months ended March 31, 2010.

Net Cash Provided by Operating Activities.


	Three Months Ended March 31,
	2011			2010			Change
	(In thousands)
Net income	$	250,612		$	290,853		$	(40,241	)
Net changes in operating assets and liabilities		58,218			54,975			3,243
Proceeds from settlement of FOREX contracts designated as accounting hedges		1,826			2,099			(273	)
Gain on sale and disposition of assets		(2,641	)		(884	)		(1,757	)
Loss (gain) on sale of marketable securities		(783	)		1			(784	)
(Gain) on FOREX contracts		(1,826	)		(2,099	)		273
Deferred tax provision		(14,774	)		(4,843	)		(9,931	)
Depreciation and other non-cash items, net		115,847			124,779			(8,932	)

	$	406,479		$	464,881		$	(58,402	)

Our cash flows from operations during the first three months of 2011 decreased $58.4 million compared to the same period in 2010. This decrease is primarily due to lower earnings resulting from an aggregate reduction in average utilization of and dayrates earned by our drilling fleet.

We used $3.2 million less cash to satisfy our working capital requirements during the first quarter of 2011 compared to the first quarter of 2010. Trade and other receivables generated cash of $79.8 million during the first three months of 2011 compared to using cash of $44.9 million during the comparable period of 2010. We used cash of $32.8 million and $19.8 million during the first three months of 2011 and 2010, respectively, to satisfy accounts payable and accrued liability needs. During the first three months of 2011, we made no U.S. federal income tax payments and paid foreign income taxes, net of refunds, of $48.5 million. During the first three months of 2010, we made U.S. federal income tax payments and paid foreign income taxes, net of refunds, of $0.5 million and $37.3 million, respectively.

Net Cash Used in Investing Activities.


	Three Months Ended March 31,
	2011			2010			Change
	(In thousands)
Purchase of marketable securities	$	(1,249,835	)	$	(1,349,900	)	$	100,065
Proceeds from sale and maturities of marketable securities		1,362,016			1,200,053			161,963
Capital expenditures		(61,743	)		(107,798	)		46,055
Deposits for construction of new rigs		(308,854	)		—			(308,854	)
Proceeds from disposition of assets		2,786			989			1,797

	$	(255,630	)	$	(256,656	)	$	1,026

Our investing activities used $255.6 million during the first three months of 2011 compared to $256.7 million during the comparable period in 2010. During the first quarter of 2011 we had sales of marketable securities, net of purchases, of $112.2 million compared to net purchases of $149.8 million during the same period in 2010. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets.

During the first quarter of 2011, we paid $308.9 million to Hyundai as first installments for the construction of the Ocean BlackHawk and Ocean BlackHornet. See “Liquidity and Capital Requirements — Contractual Cash Obligations.”

We spent approximately $61.7 million during the first three months of 2011 related to ongoing capital maintenance programs, including rig modifications to meet contractual requirements, compared to $107.8 million during the same period in 2010. Capital expenditures during the first three months of 2010 included commissioning and initial outfitting costs of the Ocean Courage and Ocean Valor.

Net Cash Used in Financing Activities.


	Three Months Ended March 31,
	2011			2010			Change
	(In thousands)
Payment of dividends	$	(122,021	)	$	(278,597	)	$	156,576
Other		—			9			(9	)

	$	(122,021	)	$	(278,588	)	$	156,567

During the first three months of 2011, we paid cash dividends totaling $122.0 million, consisting of a regular cash dividend of $17.4 million, or $0.125 per share of our common stock, and a special cash dividend of $104.6 million, or $0.75 per share of our common stock. During the first three months of 2010, we paid cash dividends totaling $278.6 million, consisting of a regular cash dividend of $17.4 million, or $0.125 per share of our common stock, and a special cash dividend of $261.2 million, or $1.875 per share of our common stock.

On April 20, 2011, we declared a regular quarterly cash dividend and a special cash dividend of $0.125 and $0.75, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on June 1, 2011 to stockholders of record on May 2, 2011.

Our Board of Directors has adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Our Board of Directors may, in subsequent quarters, consider paying additional special cash dividends, in amounts to be determined, if it believes that our financial position, earnings, earnings outlook, capital spending plans and other relevant factors warrant such action at that time.

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not repurchase any shares of our outstanding common stock during the three-month periods ended March 31, 2011 and 2010.

Forward-Looking Statements

We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

	•		future market conditions and the effect of such conditions on our future results of operations;

	•		future uses of and requirements for financial resources;

	•		interest rate and foreign exchange risk;

	•		future contractual obligations;

	•		future operations outside the United States including, without limitation, our operations in Mexico, Egypt and Brazil;

	•		effects of the Macondo well blowout, including, without limitation, the impact of the moratorium and its aftermath on drilling in the U.S. Gulf of Mexico, related delays in permitting activities and related regulations and market developments;

	•		business strategy;

	•		growth opportunities;

	•		competitive position;

	•		expected financial position;

	•		future cash flows and contract backlog;

	•		future regular or special dividends;

	•		financing plans;

	•		market outlook;

	•		tax planning;

	•		debt levels, including impacts of the financial crisis and restrictions in the credit market;

	•		budgets for capital and other expenditures;

	•		our customer’s termination of the drilling contract for the Ocean Monarch and the related litigation;

	•		timing and duration of required regulatory inspections for our drilling rigs;

	•		timing and cost of completion of rig upgrades, construction projects and other capital projects;

	•		delivery dates and drilling contracts related to rig conversion or upgrade projects, construction projects or rig acquisitions;

	•		plans and objectives of management;

	•		idling drilling rigs or reactivating stacked rigs;

	•		asset impairment evaluations;

	•		performance of contracts;

	•		outcomes of legal proceedings;

	•		compliance with applicable laws; and

	•		availability, limits and adequacy of insurance or indemnification.

These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following:

	•		those described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2010;

	•		general economic and business conditions, including the extent and duration of the recent financial crisis and restrictions in the credit market, the worldwide economic downturn and recession;

	•		worldwide demand for oil and natural gas;

	•		changes in foreign and domestic oil and gas exploration, development and production activity;

	•		oil and natural gas price fluctuations and related market expectations;

	•		the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing, and the level of production in non-OPEC countries;

	•		policies of various governments regarding exploration and development of oil and gas reserves;

	•		our inability to obtain contracts for our rigs that do not have contracts;

	•		the cancellation of contracts included in our reported contract backlog;

	•		advances in exploration and development technology;

	•		the worldwide political and military environment, including in oil-producing regions;

	•		casualty losses;

	•		operating hazards inherent in drilling for oil and gas offshore;

	•		the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico;

	•		industry fleet capacity;

	•		market conditions in the offshore contract drilling industry, including dayrates and utilization levels;

	•		competition;

	•		changes in foreign, political, social and economic conditions;

	•		risks of international operations, compliance with foreign laws and taxation policies and expropriation or nationalization of equipment and assets;

	•		risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;

	•		the ability of customers and suppliers to meet their obligations to us and our subsidiaries;

	•		the risk that a letter of intent may not result in a definitive agreement;

	•		foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;

	•		risks of war, military operations, other armed hostilities, terrorist acts and embargoes;

	•		changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness;

	•		regulatory initiatives and compliance with governmental regulations including, without limitation, regulations pertaining to climate change, carbon emissions or energy use;

	•		compliance with environmental laws and regulations;

	•		potential changes in accounting policies by the Financial Accounting Standards Board, the Securities and Exchange Commission, or SEC, or regulatory agencies for our industry which may cause us to revise our financial accounting and/or disclosures in the future, and which may change the way analysts measure our business or financial performance;

	•		development and exploitation of alternative fuels;

	•		customer preferences;

	•		effects of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts;

	•		cost, availability, limits and adequacy of insurance;

	•		invalidity of assumptions used in the design of our controls and procedures;

	•		the results of financing efforts;

	•		the risk that future regular or special dividends may not be declared;

	•		adequacy of our sources of liquidity;

	•		risks resulting from our indebtedness;

	•		public health threats;

	•		negative publicity;

	•		impairments of assets;

	•		the availability of qualified personnel to operate and service our drilling rigs; and

	•		various other matters, many of which are beyond our control.

The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at March 31, 2011 and December 31, 2010, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

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

Interest Rate Risk

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

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on March 31, 2011 and December 31, 2010, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.

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

Loans under our $285 million syndicated, senior unsecured revolving Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) LIBOR plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. As of March 31, 2011 and December 31, 2010, there were no loans outstanding under the Credit Facility (however, $10.6 million and $21.9 million in letters of credit were issued and outstanding under the Credit Facility at March 31, 2011 and December 31, 2010, respectively).

Our long-term debt, as of March 31, 2011 and December 31, 2010, is denominated in U.S. dollars. Our debt has been primarily issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $114.3 million and $117.0 million as of March 31, 2011 and December 31, 2010, respectively. A 100-basis point decrease would result in an increase in market value of $132.4 million and $135.5 million as of March 31, 2011 and December 31, 2010, respectively.

Foreign Exchange Risk

Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. It is customary for us to enter into foreign currency forward exchange, or

FOREX, contracts in the normal course of business. These contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for certain contracts is the average spot rate for the contract period. As of March 31, 2011, we had FOREX contracts outstanding in the aggregate notional amount of $142.3 million, consisting of $7.8 million in Australian dollars, $103.7 million in Brazilian reais, $22.7 million in British pounds sterling, $1.4 million in Mexican pesos and $6.7 million in Norwegian kroner. These contracts generally settle monthly through December 2011.

At March 31, 2011, we have presented the fair value of our outstanding FOREX contracts as a current asset of $6.8 million in “Prepaid expenses and other current assets” and a current liability of $(0.1) million in “Accrued liabilities” in our Consolidated Balance Sheets. At December 31, 2010, we have presented the fair value of our outstanding FOREX contracts as a current asset of $4.3 million in “Prepaid expenses and other current assets” and a current liability of $(0.1) million in “Accrued liabilities” in our Consolidated Balance Sheets.

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

Fair Value Asset (Liability)

Market Risk

March 31,

December 31,

March 31,

December 31,

2011

2010

2011

2010

(In thousands)

Interest rate:

Marketable securities

500,600

(a)

612,300

(a)

(300

) (b)

(1,100

) (b)

Foreign Exchange:

FOREX contracts — receivable positions

6,800

(c)

4,300

(c)

(23,500

) (d)

(23,500

) (d)

FOREX contracts — liability positions

(100

) (c)

(100

) (c)

(2,200

) (d)

(2,100

) (d)


(a)		The fair market value of our investment in marketable securities, excluding repurchase agreements, is based on the quoted closing market prices on March 31, 2011 and December 31, 2010.

(b)		The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at March 31, 2011 and December 31, 2010.

(c)		The fair value of our FOREX contracts is based on both quoted market prices and valuations derived from pricing models on March 31, 2011 and December 31, 2010.

(d)		The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their values at March 31, 2011 and December 31, 2010, with all other variables held constant.

ITEM 4. Controls and Procedures.

We maintain a system of disclosure controls and procedures which are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.

Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2011. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2011.

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our first fiscal quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 6. Exhibits.

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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	DIAMOND OFFSHORE DRILLING, INC. (Registrant)
Date April 27, 2011	By:	\s\ Gary T. Krenek
		Gary T. Krenek
		Senior Vice President and Chief Financial Officer

Date April 27, 2011		\s\ Beth G. Gordon
		Beth G. Gordon
		Controller (Chief Accounting Officer)

EXHIBIT INDEX


Exhibit No.		Description

3.1		Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003) (SEC File No. 1-13926).

3.2		Amended and Restated By-laws (as amended through March 15, 2011) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed March 16, 2011).

31.1*		Rule 13a-14(a) Certification of the Chief Executive Officer.

31.2*		Rule 13a-14(a) Certification of the Chief Financial Officer.

32.1*		Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema Document.

101.CAL**		XBRL Taxonomy Calculation Linkbase Document.

101.LAB**		XBRL Taxonomy Label Linkbase Document.

101.PRE**		XBRL Presentation Linkbase Document.


*		Filed or furnished herewith.

**		The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise, not subject to liability under these sections.

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