UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

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

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

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

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

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

     Yes þ No o

     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

     Yes þ No o

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

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

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

     Yes o No þ

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

     As of April 22, 2010 Common stock, $0.01 par value per share 139,026,178 shares

 

 

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED MARCH 31, 2010

		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		18
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		33
ITEM 4. Controls and Procedures		35
PART II. OTHER INFORMATION		35
ITEM 6. Exhibits		35
SIGNATURES		36
EXHIBIT INDEX		37
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

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

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

		March 31,				December 31,
		2010				2009
ASSETS
Current assets:
Cash and cash equivalents		$	306,054			$	376,417
Marketable securities			650,756				400,853
Accounts receivable, net of provision for bad debts			797,932				791,023
Prepaid expenses and other current assets			146,913				155,077
Total current assets			1,901,655				1,723,370
Drilling and other property and equipment, net of accumulated depreciation			4,414,387				4,432,052
Other assets			408,761				108,839
Total assets		$	6,724,803			$	6,264,261
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	67,250			$	75,015
Payable for purchase of marketable securities			99,989				—
Accrued liabilities			292,644				301,871
Taxes payable			360,628				32,410
Current portion of long-term debt			4,215				4,179
Total current liabilities			824,726				413,475
Long-term debt			1,495,428				1,495,375
Deferred tax liability			540,669				546,024
Other liabilities			220,837				178,745
Total liabilities			3,081,660				2,633,619
Commitments and contingencies (Note 10)			—				—
Stockholders’ equity:
Common stock (par value $0.01, 500,000,000 shares authorized, 143,942,978 shares issued and 139,026,178 shares outstanding at March 31, 2010 and December 31, 2009)			1,439				1,439
Additional paid-in capital			1,967,451				1,965,513
Retained earnings			1,788,013				1,776,498
Accumulated other comprehensive gain			653				1,605
Treasury stock, at cost (4,916,800 shares at March 31, 2010 and December 31, 2009)			(114,413	)			(114,413	)
Total stockholders’ equity			3,643,143				3,630,642
Total liabilities and stockholders’ equity		$	6,724,803			$	6,264,261

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,
		2010				2009
Revenues:
Contract drilling		$	844,438			$	855,708
Revenues related to reimbursable expenses			15,243				30,012
Total revenues			859,681				885,720
Operating expenses:
Contract drilling			305,127				297,747
Reimbursable expenses			14,705				29,715
Depreciation			97,402				85,062
General and administrative			16,654				16,315
Gain on disposition of assets			(884	)			(55	)
Total operating expenses			433,004				428,784
Operating income			426,677				456,936
Other income (expense):
Interest income			1,282				576
Interest expense			(22,321	)			(1,117	)
Foreign currency transaction gain (loss)			461				(4,125	)
Other, net			(87	)			1,067
Income before income tax expense			406,012				453,337
Income tax expense			(115,159	)			(104,756	)
Net income		$	290,853			$	348,581
Income per share:
Basic		$	2.09			$	2.51
Diluted		$	2.09			$	2.51
Weighted-average shares outstanding:
Shares of common stock			139,026				139,001
Dilutive potential shares of common stock			103				63
Total weighted-average shares outstanding assuming dilution			139,129				139,064
Cash dividends declared per share of common stock		$	2.00			$	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,
		2010				2009
Operating activities:
Net income		$	290,853			$	348,581
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			97,402				85,062
Gain on disposition of assets			(884	)			(55	)
Loss (gain) on sale of marketable securities, net			1				(597	)
(Gain) loss on foreign currency forward exchange contracts			(2,099	)			25
Deferred tax provision			(4,843	)			8,365
Accretion of discounts on marketable securities			(73	)			(311	)
Amortization/write-off of debt issuance costs			211				113
Amortization of debt discounts			89				62
Stock-based compensation expense			1,938				1,705
Deferred income, net			55,063				62,228
Deferred expenses, net			(30,246	)			(9,606	)
Other items, net			395				2,625
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges			2,099				—
Changes in operating assets and liabilities:
Accounts receivable			(44,875	)			(114,007	)
Prepaid expenses and other current assets			5,052				7,842
Accounts payable and accrued liabilities			(19,762	)			(29,142	)
Taxes payable			114,560				44,189
Net cash provided by operating activities			464,881				407,079
Investing activities:
Capital expenditures			(107,798	)			(130,408	)
Proceeds from disposition of assets, net of disposal costs			989				325
Proceeds from sale and maturities of marketable securities			1,200,053				1,348,964
Purchases of marketable securities			(1,349,900	)			(1,149,112	)
Cost of proceeds from settlement of foreign currency forward exchange contracts not designated as accounting hedges			—				(24,789	)
Net cash (used in) provided by investing activities			(256,656	)			44,980
Financing activities:
Debt issuance costs and arrangement fees			(98	)			—
Payment of dividends			(278,597	)			(278,257	)
Proceeds from stock plan exercises			107				—
Net cash used in financing activities			(278,588	)			(278,257	)
Net change in cash and cash equivalents			(70,363	)			173,802
Cash and cash equivalents, beginning of period			376,417				336,052
Cash and cash equivalents, end of period		$	306,054			$	509,854

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, 2009 (File No. 1-13926).

     As of April 22, 2010, 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.

Cash and Cash Equivalents, Marketable Securities

     We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents. See Note 5.

     We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in “Accumulated other comprehensive 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).”

Derivative Financial Instruments

     Our derivative financial instruments include foreign currency forward exchange, or FOREX, contracts. See Notes 4 and 5.

Supplementary Cash Flow Information

     We paid interest on long-term debt totaling $12.5 million in each of the three-month periods ended March 31, 2010 and 2009. During the three months ended March 31, 2010, we paid $0.9 million in interest on assessments from the Internal Revenue Service.

     We paid $0.5 million in U.S. federal income taxes during the three-month periods ended March 31, 2010. We paid $37.3 million and $47.8 million in foreign income taxes, net of foreign tax refunds, during the three months

ended March 31, 2010 and 2009, 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, 2010 included $64.9 million that was accrued but unpaid at December 31, 2009. Capital expenditures for the three months ended March 31, 2009 included $59.4 million that was accrued but unpaid at December 31, 2008. Capital expenditures that were accrued but not paid as of March 31, 2010 totaled $37.0 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at March 31, 2010.

     We recorded income tax benefits of $0.1 million related to employee stock plan exercises during the three months ended March 31, 2009.

Comprehensive Income

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

		Three Months Ended
		March 31,
		2010				2009
		(In thousands)
Net income		$	290,853			$	348,581
Other comprehensive gains (losses), net of tax:
FOREX contracts:
Unrealized holding gain			137				—
Reclassification adjustment for gain included in net income			(1,085	)			—
Investments in marketable securities:
Unrealized holding (loss) gain			(4	)			27
Reclassification adjustment for gain included in net income			—				(493	)
Comprehensive income		$	289,901			$	348,115

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

     The tax related to the change in unrealized holding loss on investments was approximately $2,000 for the three months ended March 31, 2010. The tax related to the change in unrealized holding gain on investments for the three months ended March 31, 2009 was approximately $15,000. The tax effect on the reclassification adjustment for net gains included in net income was approximately $265,000 for the three months ended March 31, 2009.

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, 2010 and 2009, we recognized net foreign currency exchange gains of $0.5 million and net foreign currency exchange losses of $4.1 million, respectively. See Note 4.

Revenue Recognition

     Revenue from our dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight line basis, over the term of the related drilling contracts (which is the period 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 two to 60 months) is consistent with the timing of net cash

flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized as incurred.

     From time to time, we may receive fees from our customers for capital improvements to our rigs (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.

2. Earnings Per Share

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

		Three Months Ended
		March 31,
		2010				2009
		(In thousands, except per share data)
Net income — basic (numerator):		$	290,853			$	348,581
Effect of dilutive potential shares
Zero Coupon Debentures			24				23
Net income including conversions — diluted (numerator)		$	290,877			$	348,604
Weighted average shares — basic (denominator):			139,026				139,001
Effect of dilutive potential shares
Zero Coupon Debentures			52				52
Stock options and SARs			51				11
Weighted average shares including conversions — diluted (denominator)			139,129				139,064
Earnings per share:
Basic		$	2.09			$	2.51
Diluted		$	2.09			$	2.51

     Our computation of diluted earnings per share, or EPS, for the three months ended March 31, 2010 excludes 441,037 stock appreciation rights, or SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period presented.

     Our computation of EPS for the three months ended March 31, 2009 excludes stock options representing 23,493 shares of common stock and 482,588 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the period presented.

3. Marketable Securities

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

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

		March 31, 2010
		Amortized				Unrealized				Market
		Cost				(Loss) Gain				Value
		(In thousands)
Due within one year		$	649,960			$	(2	)		$	649,958
Mortgage-backed securities			738				60				798
Total		$	650,698			$	58			$	650,756

		December 31, 2009
		Amortized				Unrealized				Market
		Cost				(Loss) Gain				Value
		(In thousands)
Due within one year		$	399,997			$	(1	)		$	399,996
Mortgage-backed securities			792				65				857
Total		$	400,789			$	64			$	400,853

     Marketable securities at March 31, 2010 include $100.0 million in U.S. Treasury Bills purchased on March 31, 2010 that did not settle until April 2010. The offsetting amount for this transaction has been reported as a $100.0 million “Payable for purchase of marketable securities” in our Consolidated Balance Sheets at March 31, 2010.

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

		Three Months Ended
		March 31,
		2010				2009
		(In thousands)
Proceeds from sales		$	53			$	1,448,943
Proceeds from maturities			1,200,000				—
Gross realized gains			—				732
Gross realized losses			(1	)			(135	)

Proceeds from sales of marketable securities for the three months ended March 31, 2009 include $100.0 million in securities sold on March 31, 2009 that did not settle until April 2009.

4. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

     Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. We may utilize FOREX contracts to reduce 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 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 losses and gains on the qualifying hedged positions.

     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.

     In May 2009, we began a hedging strategy and designated certain of our qualifying FOREX contracts as cash flow hedges. These hedges are expected to be highly effective, and therefore, adjustments to record the carrying value of the effective portion of our derivative financial instruments to their fair value is recorded as a component of “Accumulated other comprehensive 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.

     Realized gains or losses upon settlement of derivative contracts designated as cash flow hedges are reported as a component of “Contract drilling” expense in our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our expenditures in local foreign currencies in the countries in which we operate.

     For derivative contracts entered into prior to May 2009, we did not seek hedge accounting treatment under GAAP. Accordingly, prior to May 2009, all adjustments to record the carrying value of our derivative financial instruments at fair value were reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations.

     During the three months ended March 31, 2010, we settled FOREX contracts with an aggregate notional value of approximately $52.4 million, of which the entire aggregate amount was designated as an accounting hedge.

     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, 2010 and 2009.

		For the Three Months Ended March 31,
Location of Gain Recognized in Income		2010				2009
		(In thousands)
Contract drilling expense		$	2,099			$	—

     The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts not designated as hedging instruments for the three months ended March 31, 2010 and 2009.

		For the Three Months Ended March 31,
Location of Loss Recognized in Income		2010				2009
		(In thousands)
Foreign currency transaction loss		$	—			$	(25	)

     The amounts presented in the table above include net unrealized gains aggregating $24.8 million for the three months ended March 31, 2009 to record the carrying value of our derivative financial instruments to their fair value. There were no gains or losses associated with FOREX contracts not designated as accounting hedges during the three months ended March 31, 2010.

     As of March 31, 2010, we had FOREX contracts outstanding in the aggregate notional amount of $77.6 million, consisting of $30.1 million in Australian dollars, $27.6 million in Brazilian reais, $10.6 million in British pounds sterling, $4.0 million in Mexican pesos and $5.3 million in Norwegian kroner. These contracts generally settle monthly through September 2010. As of March 31, 2010, all outstanding derivative contracts had been designated as cash flow hedges. See Note 5.

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

Assets

Liabilities

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

(In

(In

thousands)

thousands)

Derivatives designated as hedging instruments:

FOREX contracts

Prepaid expenses and other current assets

$

1,505

Accrued liabilities

$

(560

)

     The following table presents the fair values of our derivative financial instruments at December 31, 2009.

Assets

Liabilities

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

(In

(In

thousands)

thousands)

Derivatives designated as hedging instruments:

FOREX contracts

Prepaid expenses and other current assets

$

2,634

Accrued liabilities

$

(230

)

     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, 2010.

						Location of Gain
Amount of						Recognized in Income		Amount of Gain
Pre-Tax Gain		Location of		Amount of		on Derivative		Recognized in Income on
Recognized in		Pre-Tax Gain		Pre-Tax Gain		(Ineffective Portion		Derivative (Ineffective
AOCG on		Reclassified from		Reclassified from		and Amount Excluded		Portion and Amount
Derivative		AOCG into Income		AOCG into Income		from Effectiveness		Excluded from
(Effective Portion)		(Effective Portion)		(Effective Portion)		Testing)		Effectiveness Testing)
(In thousands)				(In thousands)				(In thousands)
$212		Contract drilling expense		$1,670		Foreign currency transaction gain		$—

     As of March 31, 2010, the estimated amount of net unrealized gains associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $0.9 million. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense.

5. Financial Instruments and Fair Value Disclosures

Concentrations of Credit and Market Risk

     Financial instruments which potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including 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. 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.

     Our business has experienced negative effects of the current economic downturn such as customer credit problems, customers attempting to renegotiate or terminate contracts, and one customer seeking bankruptcy protection. We provide allowances for potential credit losses on a specific customer basis when necessary; however, we have not historically experienced significant losses on our trade receivables. At March 31, 2010 and December 31, 2009, our allowance for doubtful accounts receivable was $40.6 million and $41.7 million, respectively, related to our operations in Egypt and the insolvency of one of our customers in the United Kingdom. No additional allowances were deemed necessary for the periods presented.

     During 2009, we amended an existing contractual agreement at a customer’s request to provide short-term financial relief. The amended contract obligates the customer to pay us, over the term of the six-well drilling program, $75,000 per day 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, through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties. Based on the current production payout estimate, we anticipate that the first payment from the conveyance of the NPI will commence in the second quarter of 2010. Payment of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices.

     At March 31, 2010, the $94.5 million portion of this trade receivable payable from the NPI is presented as “Accounts Receivable” in our Consolidated Balance Sheets. At March 31, 2010, we believe that collectability of the amount owed pursuant to the NPI arrangement is reasonably assured.

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, 2010								December 31, 2009
		Fair Value				Carrying Value				Fair Value				Carrying Value
		(In millions)
Zero Coupon Debentures		$	4.6			$	4.2			$	5.1			$	4.2
4.875% Senior Notes			268.5				249.7				257.5				249.7
5.15% Senior Notes			269.6				249.7				263.3				249.7
5.70% Senior Notes			487.0				496.7				490.4				496.7
5.875% Senior Notes			539.2				499.3				530.6				499.3

     We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management as of March 31, 2010 and December 31, 2009, 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, 2010 and December 31, 2009, 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, 2010 and December 31, 2009, respectively.

•

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 closing market price on March 31, 2010 and December 31, 2009, respectively, from brokers of these instruments. The fair value of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon

Debentures, was based on the closing market price of our common stock on March 31, 2010 and December 31, 2009, respectively, and the stated conversion rate for these debentures.

     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, 2010 consisted of cash held in money market funds of $282.1 million and investments in U.S. Treasury Bills of $650.0 million. Our Level 1 assets at December 31, 2009 consisted of cash held in money market funds of $337.8 million and investments in U.S. Treasury Bills of $400.0 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 measured at fair value on a recurring basis are summarized below:

		March 31, 2010
		Fair Value Measurements Using												Assets at Fair
		Level 1				Level 2				Level 3				Value
		(In thousands)
Assets:
Short-term investments		$	932,090			$	—			$	—			$	932,090
FOREX contracts			—				1,505				—				1,505
Mortgage-backed securities			—				798				—				798
Total assets		$	932,090			$	2,303			$	—			$	934,393
Liabilities:
FOREX contracts		$	—			$	(560	)		$	—			$	(560	)

		December 31, 2009
		Fair Value Measurements Using												Assets at Fair
		Level 1				Level 2				Level 3				Value
		(In thousands)
Assets:
Short-term investments		$	737,830			$	—			$	—			$	737,830
FOREX contracts			—				2,634				—				2,634
Mortgage-backed securities			—				857				—				857
Total assets		$	737,830			$	3,491			$	—			$	741,321
Liabilities:
FOREX contracts		$	—			$	(230	)		$	—			$	(230	)

6. Prepaid Expenses and Other Current Assets

     Prepaid expenses and other current assets consist of the following:

		March 31,				December 31,
		2010				2009
		(In thousands)
Rig spare parts and supplies		$	51,551			$	49,122
Deferred mobilization costs			71,584				45,502
Prepaid insurance			3,725				11,478
Deferred tax assets			7,235				7,235
Deposits			3,540				3,562
Prepaid taxes			676				26,109
FOREX contracts			1,505				2,634
Other			7,097				9,435
Total		$	146,913			$	155,077

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,
		2010				2009
		(In thousands)
Drilling rigs and equipment		$	7,025,047			$	6,950,303
Land and buildings			48,283				44,640
Office equipment and other			39,554				38,203
Cost			7,112,884				7,033,146
Less: accumulated depreciation			(2,698,497	)			(2,601,094	)
Drilling and other property and equipment, net		$	4,414,387			$	4,432,052

8. Accrued Liabilities

     Accrued liabilities consist of the following:

		March 31,				December 31,
		2010				2009
		(In thousands)
Accrued project/upgrade expenses		$	73,744			$	115,778
Payroll and benefits			62,236				69,065
Deferred revenue			74,625				46,666
Rig operating expenses			32,462				29,141
Interest payable			30,055				22,710
Personal injury and other claims			11,814				10,018
FOREX contracts			560				230
Other			7,148				8,263
Total		$	292,644			$	301,871

9. Long-Term Debt

     Long-term debt consists of the following:

		March 31,				December 31,
		2010				2009
		(In thousands)
Zero Coupon Debentures (due 2020)		$	4,215			$	4,179
5.15% Senior Notes (due 2014)			249,697				249,682
4.875% Senior Notes (due 2015)			249,684				249,671
5.875% Senior Notes (due 2019)			499,307				499,292
5.70% Senior Notes (due 2039)			496,740				496,730
			1,499,643				1,499,554
Less: Current maturities			4,215				4,179
Total		$	1,495,428			$	1,495,375

     At March 31, 2010, there was $6.0 million aggregate principal amount at maturity, or $4.2 million accreted, or carrying value, of our Zero Coupon Debentures outstanding.

     Certain of our long-term debt payments may be accelerated due to rights that the holders of our debt securities have to put the securities to us. The holders of our outstanding Zero Coupon Debentures have the right to require us to purchase all or a portion of their outstanding debentures on June 6, 2010.

     The aggregate maturities of long-term debt for each of the five years subsequent to March 31, 2010, are as follows:

(Dollars in thousands)
2010		$	4,215
2011			—
2012			—
2013			—
2014			249,697
Thereafter			1,245,731
			1,499,643
Less: Current maturities			4,215
Total		$	1,495,428

10. 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 deductible for liability coverage for personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, is currently $5.0 million per occurrence, with no aggregate deductible. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models. At March 31, 2010, our estimated liability for personal injury claims was $33.6 million, of which $11.2 million and $22.4 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2009, our estimated liability for personal injury claims was $32.1 million, of which $9.2 million and $22.9 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. As of March 31, 2010 and December 31, 2009, we had no 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, 2010 in the amount of $171.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $63.1 million in letters of credit issued under our $285 million, syndicated, senior unsecured revolving credit facility. At March 31, 2010, we had purchased five of our outstanding bonds, totaling $82.4 million, from a related party in previous years after obtaining competitive quotes. Agreements relating to approximately $82.4 million of performance bonds can require collateral at any time. As of March 31, 2010, 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.

11. 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,
		2010				2009
		(In thousands)
High-Specification Floaters		$	383,788			$	312,134
Intermediate Semisubmersibles			380,701				417,000
Jack-ups			79,949				126,574
Total contract drilling revenues			844,438				855,708
Revenues related to reimbursable expenses			15,243				30,012
Total revenues		$	859,681			$	885,720

Geographic Areas

     At March 31, 2010, our drilling rigs were located offshore twelve countries in addition to the United States. As a result, we are exposed to the risk of changes in social, political and economic conditions inherent in international operations and our results of operations and the value of our international assets are affected by fluctuations in foreign currency exchange rates. Revenues by geographic area are presented below by attributing revenues to the individual country or areas where the services were performed.

		Three Months Ended
		March 31,
		2010				2009
		(In thousands)
United States		$	238,547			$	356,315
International:
South America			283,115				124,701
Australia/Asia/Middle East			158,929				174,225
Europe/Africa/Mediterranean			136,606				149,832
Mexico			42,484				80,647
Total revenues		$	859,681			$	885,720

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, 2009. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

     We provide contract drilling services to the energy industry around the globe and are a leader in offshore drilling with a fleet of 47 offshore rigs currently consisting of 32 semisubmersibles, 14 jack-ups and one drillship.

Overview

Industry Conditions

     The global economy remained relatively weak in the first quarter of 2010 and although oil prices improved to the low $80 per barrel range they remained volatile. Dayrates we receive for new contracts are no longer at the peak levels achieved at the height of the most recent up-cycle. Given the unpredictable economic environment, the demand for our services and the dayrates we are able to command could soften further. This volatility and uncertainty could continue until the global economy improves. Absent global economic improvement the decline in drilling activity could be further exacerbated by the influx of new-build rigs over the next several years, particularly in regard to jack-up units.

     Early in the economic downturn, we experienced negative effects of the market such as customer credit problems, customers attempting to renegotiate or terminate contracts, and one customer seeking bankruptcy protection. More recently, we have experienced some declines in dayrates for new contracts with industry-wide floater utilization stable at approximately 91%. During the first quarter of 2010, we signed 14 new contracts totaling approximately $1.5 billion in backlog and ranging in length from one well to five years. As a result, at the end of the first quarter of 2010 our contract backlog was approximately $9.1 billion, which we expect to help mitigate the impact of the current market on us in 2010.

     Floaters

     Our intermediate and high-specification floater rigs account for approximately 89% of our revenue. Approximately 89% of the time on our intermediate and high-specification floater rigs is committed for 2010. Additionally, 63% of the time on our floating rigs is committed in 2011.

     International Jack-ups

     During the first quarter of 2010, demand was weak but stable, while dayrates softened internationally as existing rigs rolled off contract and met competition from un-contracted new-build jack-ups that came to market. With industry-wide jack-up utilization standing at only about 76%, this oversupply of jack-up rigs could have an increasingly negative impact on the international sector throughout 2010 and beyond.

     U.S. Gulf of Mexico Jack-ups

     In the domestic jack-up sector, lower natural gas prices have negatively impacted both demand and dayrates. In response, to reduce costs, we have cold-stacked three of our lower-end jack-up units, and they are not being actively marketed. Our four remaining higher-specification jack-ups in the U.S. Gulf of Mexico, or GOM, are largely working under short-term contracts. Absent a sustained improvement in energy prices, weakness in the GOM jack-up market is likely to continue in 2010, with the possibility of additional rigs being cold-stacked by the industry in an effort to help bring equipment supply and demand into equilibrium.

Contract Drilling Backlog

     The following table reflects our contract drilling backlog as of April 19, 2010, February 1, 2010 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2009) and April 15, 2009 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2009). 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 19,				February 1,				April 15,
		2010(1) (2)				2010				2009
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters (1)		$	5,175,000			$	4,177,000			$	4,059,000
Intermediate Semisubmersibles (2)			3,767,000				4,030,000				5,148,000
Jack-ups			185,000				249,000				390,000
Total		$	9,127,000			$	8,456,000			$	9,597,000

     The following table reflects the amount of our contract drilling backlog by year as of April 19, 2010.

		For the Years Ending December 31,
		Total				2010(1)				2011				2012				2013 - 2016
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters (2)		$	5,175,000			$	1,315,000			$	1,569,000			$	944,000			$	1,347,000
Intermediate Semisubmersibles (3)			3,767,000				1,133,000				1,030,000				860,000				744,000
Jack-ups			185,000				144,000				41,000				—				—
Total		$	9,127,000			$	2,592,000			$	2,640,000			$	1,804,000			$	2,091,000

     The following table reflects the percentage of rig days committed by year as of April 19, 2010. 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,
		2010(1)				2011				2012				2013 - 2016
Rig Days Committed (2)
High-Specification Floaters			97	%			76	%			48	%			18	%
Intermediate Semisubmersibles			83	%			54	%			44	%			10	%
Jack-ups			39	%			7	%			—				—

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 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.

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

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

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

     Operating Income. Our operating income is primarily affected by revenue factors, but is also a function of varying levels of operating expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment. The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate.

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

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

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

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

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

     During the remainder of 2010, five of our rigs will require 5-year surveys, and we expect that they will be out of service for approximately 325 days in the aggregate. We also expect to spend an additional approximately 400 days during the remainder of 2010 for intermediate surveys, the mobilization of rigs, commissioning and contract acceptance testing 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 or cash flows. However, under our current insurance policy that expires on May 1, 2010, we continue to carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico, for which our deductible for physical damage is $25.0 million per occurrence.

     We are in the process of renewing our principal insurance coverages to be effective May 1, 2010. We expect our coverage and policy limits for physical damage insurance and our policy limits for liability insurance to be similar to our current policy. However, we expect our deductibles for marine liability coverage, including for personal injury claims, to be $10.0 million for the first occurrence and to 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 upon the nature, severity and frequency of claims which might arise during the policy year.

Critical Accounting Estimates

     Our significant accounting policies are discussed in Note 1 of our notes to consolidated financial statements included in Item 1 of Part I of this report and in Note 1 of our notes to audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009. There were no material changes to these policies during the three months ended March 31, 2010.

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, 2010 and 2009

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

		Three Months Ended
		March 31,								Favorable/
		2010				2009				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	383,788			$	312,134			$	71,654
Intermediate Semisubmersibles			380,701				417,000				(36,299	)
Jack-ups			79,949				126,574				(46,625	)
Total Contract Drilling Revenue		$	844,438			$	855,708			$	(11,270	)
Revenues Related to Reimbursable Expenses		$	15,243			$	30,012			$	(14,769	)
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	109,155			$	93,628			$	(15,527	)
Intermediate Semisubmersibles			138,599				130,715				(7,884	)
Jack-ups			52,528				68,918				16,390
Other			4,845				4,486				(359	)
Total Contract Drilling Expense		$	305,127			$	297,747			$	(7,380	)
Reimbursable Expenses		$	14,705			$	29,715			$	15,010
OPERATING INCOME
High-Specification Floaters		$	274,633			$	218,506			$	56,127
Intermediate Semisubmersibles			242,102				286,285				(44,183	)
Jack-ups			27,421				57,656				(30,235	)
Other			(4,845	)			(4,486	)			(359	)
Reimbursable expenses, net			538				297				241
Depreciation			(97,402	)			(85,062	)			(12,340	)
General and administrative expense			(16,654	)			(16,315	)			(339	)
Gain on disposition of assets			884				55				829
Total Operating Income		$	426,677			$	456,936			$	(30,259	)
Other income (expense):
Interest income			1,282				576				706
Interest expense			(22,321	)			(1,117	)			(21,204	)
Foreign currency transaction gain (loss)			461				(4,125	)			4,586
Other, net			(87	)			1,067				(1,154	)
Income before income tax expense			406,012				453,337				(47,325	)
Income tax expense			(115,159	)			(104,756	)			(10,403	)
NET INCOME		$	290,853			$	348,581			$	(57,728	)

     During the first quarter of 2010, the weak global economy continued to negatively impact our industry despite an improvement in oil prices from the same time a year ago. Although our contracted revenue backlog enabled us to partially mitigate the impact of these market conditions, our operating income decreased 7%, or $30.3 million, compared to the first quarter of 2009. Aggregate revenues for the first quarter of 2010 decreased $11.3 million, or 1%, compared to the first quarter of 2009, and average utilization for our overall fleet decreased from 80% during the first quarter of 2009 to 74% during the first quarter of 2010. Revenues generated by our intermediate

semisubmersible and jack-up fleets decreased $82.9 million, primarily due to a reduction in utilization compared to the first quarter of 2009. However, this decline in revenues was partially offset by a $71.7 million increase in revenues generated by our high-specification floater fleet. In response to a contraction in demand for our drilling services, as of the date of this report, we have cold stacked our three mat-supported rigs in the GOM and one intermediate semisubmersible rig, and currently are not actively marketing these rigs.

     Total contract drilling expense increased $7.4 million, or 2%, during the first quarter of 2010 compared to the same period in 2009, primarily due to higher amortized mobilization expenses and higher operating costs due to several of our rigs operating internationally compared to operating in the GOM in the first quarter of 2009. This increase was partially offset by lower costs resulting from fewer regulatory surveys and maintenance projects.

     Depreciation expense increased $12.3 million to $97.4 million during the first quarter of 2010, or 14% compared to the first quarter of 2009, due to a higher depreciable asset base.

High-Specification Floaters.

		Three Months Ended
		March 31,								Favorable/
		2010				2009				(Unfavorable)
		(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM		$	190,120			$	244,874			$	(54,754	)
Australia/Asia/Middle East			40,080				34,660				5,420
Europe/Africa/Mediterranean			56,321				—				56,321
South America			97,267				32,600				64,667
Total Contract Drilling Revenue		$	383,788			$	312,134			$	71,654
CONTRACT DRILLING EXPENSE
GOM		$	41,941			$	65,174			$	23,233
Australia/Asia/Middle East			9,238				7,409				(1,829	)
Europe/Africa/Mediterranean			11,001				—				(11,001	)
South America			46,975				21,045				(25,930	)
Total Contract Drilling Expense		$	109,155			$	93,628			$	(15,527	)
OPERATING INCOME		$	274,633			$	218,506			$	56,127

     GOM. Revenues generated by our high-specification floaters operating in the GOM decreased $54.8 million during the first quarter of 2010 compared to the same period in 2009. Beginning late in the first quarter of 2009 through early 2010, we relocated four of our high-specification semisubmersible rigs from the GOM to other international locations. The Ocean Quest (relocated late first quarter 2009) and Ocean Star (relocated early first quarter 2010) are currently operating offshore Brazil, and the Ocean Valiant (relocated early third quarter 2009) is currently operating offshore Angola. The Ocean America is in transit to Australia (relocated late first quarter 2010) with an expected arrival in mid-second quarter 2010. The effect of these rig relocations was a net $92.8 million reduction in revenues in the first quarter of 2010 compared to the same quarter in 2009.

     Partially offsetting the negative effect of the rig relocations discussed above was the operation of the Ocean Monarch for the entire first quarter of 2010, compared to only 17 days during the first quarter of 2009 following its major upgrade. The Ocean Monarch contributed an additional $32.2 million in revenues during the first three months of 2010.

     Total operating costs during the first quarter of 2010 for our high-specification floaters in the GOM decreased $23.2 million, primarily as a result of a reduction in normal operating costs for the four rigs transferred out of the GOM, as well as a reduction in costs associated with a 2009 special survey for the Ocean America. The decrease in operating costs, comparing the quarters, was partially offset by increased costs associated with normal operations of the Ocean Monarch in the GOM for the entire first quarter of 2010 compared to only a portion of the quarter in 2009.

     Australia/Asia/Middle East. During the first quarter of 2010, the Ocean Rover, our high-specification rig operating offshore Malaysia, generated $5.4 million in additional revenues compared to the first quarter of 2009.

The increase in revenues was primarily due to an increase in the average operating dayrate from $389,700 earned during the first quarter of 2009 to $451,100 during the first quarter of 2010.

     Europe/Africa/Mediterranean. The Ocean Valiant, which began operating offshore Angola in mid-September 2009, generated revenues of $56.3 million and incurred normal operating costs of $11.0 million during the first quarter of 2010.

     South America. Revenues earned by our high-specification floaters operating offshore Brazil in the first quarter of 2010 increased $64.7 million compared to the first quarter of 2009. The relocated Ocean Quest and Ocean Star generated revenues of $52.9 million offshore Brazil during the first quarter of 2010. The Ocean Courage, which began operating late in the first quarter of 2010, generated $15.3 million in revenues.

     Contract drilling expense for our operations in Brazil increased $25.9 million during the first quarter of 2010 compared to the same period in 2009, primarily due to the inclusion of normal operating costs for the Ocean Quest, Ocean Star and Ocean Courage during the first quarter of 2010. Operating costs for the first quarter of 2010 also included costs to mobilize the Ocean Alliance to a shipyard for an intermediate survey and other shipyard work expected to be completed in the second quarter of 2010.

Intermediate Semisubmersibles.

		Three Months Ended
		March 31,								Favorable/
		2010				2009				(Unfavorable)
		(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM		$	19,552			$	51,300			$	(31,748	)
Mexico			23,752				53,930				(30,178	)
Australia/Asia/Middle East			85,028				116,352				(31,324	)
Europe/Africa/Mediterranean			66,537				124,166				(57,629	)
South America			185,832				71,252				114,580
Total Contract Drilling Revenue		$	380,701			$	417,000			$	(36,299	)
CONTRACT DRILLING EXPENSE
GOM		$	6,428			$	12,210			$	5,782
Mexico			10,852				10,964				112
Australia/Asia/Middle East			24,824				26,203				1,379
Europe/Africa/Mediterranean			22,421				32,518				10,097
South America			74,074				48,820				(25,254	)
Total Contract Drilling Expense		$	138,599			$	130,715			$	(7,884	)
OPERATING INCOME		$	242,102			$	286,285			$	(44,183	)

     GOM. Revenues for our rigs working in the GOM decreased $31.7 million in the first quarter of 2010 compared to the same quarter of 2009, primarily due to the relocation of the Ocean Ambassador to Brazil early in the third quarter of 2009 ($25.6 million). In addition, a decrease in the average operating dayrate for the Ocean Saratoga from $285,000 in the first quarter of 2009 to $206,600 during the first quarter of 2010 further reduced revenues by $7.1 million.

     Contract drilling expense in the GOM decreased by $5.8 million primarily due to the relocation of the Ocean Ambassador, which incurred $7.6 million in operating costs during the first quarter of 2009. The decline in operating costs was partially offset by incremental costs for the Ocean Voyager, which returned to the GOM late in the first quarter of 2010 after completion of its contract with PEMEX — Exploración Y Producción, or PEMEX.

     Mexico. Operating revenue offshore Mexico decreased $30.2 million for the first quarter of 2010 compared to the prior year quarter, primarily due to the completion of the Ocean Voyager’s contract early in the first quarter of 2010 ($25.8 million). Additionally, the average operating dayrate earned by the Ocean New Era decreased from $261,700 in the first quarter of 2009 to $221,100 during the first quarter of 2010, reducing revenues by $3.6 million. We currently have one semisubmersible rig operating offshore Mexico.

     Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working in the Australia/Asia/Middle East region decreased $31.3 million in the first quarter of 2010 compared to the same period of 2009, primarily due to the stacking of the Ocean Bounty after completion of its contract offshore Australia at the beginning of the third quarter of 2009.

     Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region decreased $57.6 million in the first quarter of 2010 compared to the same period in 2009. We currently have three rigs located in the North Sea (both U.K. and Norwegian sectors) compared to five rigs during the first quarter of 2009. Subsequent to the first quarter of 2009, we relocated the Ocean Lexington to Brazil (third quarter of 2009) and the Ocean Guardian to the Falkland Islands (first quarter of 2010), resulting in a $31.7 million reduction in revenues generated in the region during the first quarter of 2010 compared to the prior year quarter. Revenues were further impacted by the early termination of a drilling contract for the Ocean Nomad in 2009, resulting in a $30.2 million reduction in revenues for the first quarter of 2010.

     Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets decreased $10.1 million in the first quarter of 2010 compared to the first quarter of 2009, primarily due to the relocation of the Ocean Lexington and Ocean Guardian from the region.

     South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $114.6 million in the first quarter of 2010 compared to the same period in 2009. Currently we have nine rigs operating in this region, including the Ocean Guardian in the Falkland Islands, compared to six rigs operating in the region during the first quarter of 2009. The three rigs transferred to the region subsequent to the first quarter of 2009 generated $56.4 million in additional revenues during the first quarter of 2010.

     Average operating revenue per day for our other intermediate semisubmersible rigs which operated offshore Brazil during both the 2009 and 2010 periods was $242,300 during the first quarter of 2010 compared to $181,400 during the first quarter of 2009, which generated $21.0 million in additional revenues. Utilization for these rigs increased from 71% during the first quarter of 2009 to 97% during the first quarter of 2010 and generated $36.9 million in incremental revenues.

     The $25.3 million increase in operating costs in the region for the first quarter of 2010, compared to the same quarter of 2009, was primarily the result of two additional rigs operating offshore Brazil and the Ocean Guardian operating in the Falkland Islands during the current year quarter.

Jack-Ups.

		Three Months Ended
		March 31,								Favorable/
		2010				2009				(Unfavorable)
		(In thousands)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM		$	13,632			$	30,129			$	(16,497	)
Mexico			18,732				26,718				(7,986	)
Australia/Asia/Middle East			33,821				23,211				10,610
Europe/Africa/Mediterranean			13,748				25,666				(11,918	)
South America			16				20,850				(20,834	)
Total Contract Drilling Revenue		$	79,949			$	126,574			$	(46,625	)
CONTRACT DRILLING EXPENSE
GOM		$	20,117			$	24,957			$	4,840
Mexico			11,043				8,059				(2,984	)
Australia/Asia/Middle East			11,762				14,032				2,270
Europe/Africa/Mediterranean			8,402				10,674				2,272
South America			1,204				11,196				9,992
Total Contract Drilling Expense		$	52,528			$	68,918			$	16,390
OPERATING INCOME		$	27,421			$	57,656			$	(30,235	)

     GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $16.5 million during the first quarter of 2010 compared to the first quarter of 2009. Average utilization decreased to 40% during the first quarter of 2010 from 56% during the prior year quarter and resulted in a $10.0 million reduction in revenues. In addition, average revenue per day for our GOM jack-up fleet decreased to $54,600 for the first quarter of 2010 from $86,100 during the first quarter of 2009, resulting in an additional $11.7 million reduction in revenues. The overall revenue decrease was partially offset by the favorable impact of relocating two rigs to the GOM subsequent to the first quarter of 2009 (the Ocean Columbia from Mexico and the Ocean Scepter from Argentina), which generated $5.2 million in incremental revenues in the GOM.

     Contract drilling expense for our jack-ups operating in the GOM decreased $4.8 million during the first quarter of 2010, compared to the same period in 2009, primarily due to a reduction in operating costs for our three mat-supported jack-up units that were cold stacked in the second quarter of 2009 and the absence of costs for the Ocean Summit which relocated to Mexico in the third quarter of 2009. This decrease in costs was partially offset by normal operating, mobilization and survey and related costs for the Ocean Columbia and Ocean Scepter, which were incremental to the region in the first quarter of 2010.

     Mexico. Revenue generated by our jack-up fleet operating offshore Mexico during the first quarter of 2010 decreased $8.0 million compared to same quarter in 2009, primarily due to the relocation of the Ocean Columbia to the GOM after completion of its contract with PEMEX in the fourth quarter of 2009 and unpaid downtime for an intermediate survey of the Ocean Nugget. The overall negative impact on revenues was partially offset by incremental revenue generated by the Ocean Summit during the first quarter of 2010.

     The $3.0 million increase in operating costs during the first quarter of 2010, compared to the first quarter of 2009, was primarily attributable to the inclusion of normal operating costs for the Ocean Summit, partially offset by a reduction in operating costs resulting from the relocation of the Ocean Columbia to the GOM during the first quarter of 2010.

     Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the Australia/Asia/Middle East region increased $10.6 million in the first quarter of 2010 compared to the same period in 2009. The increase in revenues generated in the region was primarily due to an increase in utilization for the Ocean Sovereign, which operated the entire current year quarter compared to the first quarter of 2009 when the rig incurred 59 days of unpaid downtime for a regulatory survey and shipyard projects.

     Contract drilling expense for our jack-up rigs operating in the Australia/Asia/Middle East region decreased $2.3 million in the first quarter of 2010 due to a reduction in costs associated with the 2009 survey of the Ocean Sovereign, partially offset by an increase in operating costs for the Ocean Shield.

     Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region decreased $11.9 million during the first quarter of 2010 compared to the same period in 2009. The decrease in revenue was primarily due to lower dayrates earned by each of our jackup-rigs in the region, compared to those earned during the same quarter of the prior year. Average operating revenue per day decreased from $118,900 during the first quarter of 2009 to $61,300 for the first quarter of 2010.

     Operating costs in the Europe/Africa/Mediterranean region decreased $2.3 million during the first quarter of 2010, compared to the same quarter in 2009, primarily due to the absence of costs associated with a survey and repairs for the Ocean Heritage during the prior year quarter.

     South America. Contract drilling revenues and expenses decreased in the first quarter of 2010 compared to same period in 2009. Our sole jack-up rig in the South America region, the Ocean Scepter, completed its contract offshore Argentina in the third quarter of 2009 and was subsequently relocated to the GOM at the end of 2009.

Depreciation.

     Depreciation expense increased $12.3 million to $97.4 million during the first quarter of 2010 compared to $85.1 million during the same period in 2009, primarily due to depreciation associated with capital additions in 2009 and 2010, including depreciation of our recently acquired Ocean Courage that was placed in service in September 2009.

Interest Expense.

     Interest expense for the quarters ended March 31, 2010 and 2009 relates primarily to interest accrued on our outstanding indebtedness and our liabilities for uncertain tax positions. During the first quarter of 2010, interest expense included $7.3 million related to our 5.875% Senior Notes due 2019, issued in May 2009, and $7.1 million related to our 5.70% Senior Notes due 2039. During the first quarter of 2009, we reversed $5.5 million of previously accrued interest expense related to an uncertain tax position for which the statute of limitations had expired.

Income Tax Expense.

     Our estimated annual effective tax rate for the three months ended March 31, 2010 was 28.6%, compared to the 25.1% estimated annual effective tax rate for the same period in 2009. The higher effective tax rate in the current quarter is a result of differences in the mix of our domestic and international pre-tax earnings and losses, respectively, as well as the mix of international tax jurisdictions in which we operate. Also contributing to the higher effective tax rate in the current period was the expiration on December 31, 2009 of a tax law provision which allowed us to defer recognition of certain foreign earnings for U.S. income tax purposes. The United States Congress currently has a bill pending to extend this tax law provision for an additional year which, if passed, is expected to be retroactive to January 1, 2010 and would allow us to defer recognition of certain foreign earnings for U.S. income tax purposes. However, our estimated annual effective tax rate for the three months ended March 31, 2010 reflects applicable tax law as of March 31, 2010 as the pending legislation has not been enacted.

     During the three months ended March 31, 2009, we reversed $5.5 million of previously accrued interest expense and $5.9 million of previously accrued tax expense ($0.8 million of which had been accrued for penalties) due to the expiration of the statute of limitations related to a 2003 uncertain tax position.

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, 2010, we had $306.1 million in “Cash and cash equivalents” and $650.8 million in “Investments and marketable securities,” representing our investment of cash available for current operations. Our Consolidated Balance Sheets at March 31, 2010 also included a $100.0 million “Payable for purchase of marketable securities” relating to an investment in U.S. Treasury Bills that did not settle until the subsequent month.

     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 and restrictions in the credit market, 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.

     During 2009, we amended an existing contractual agreement at a customer’s request to provide short-term financial relief. The amended contract obligates the customer to pay us over the term of the six-well drilling program, $75,000 per day 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, through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties. Based on the current production payout estimate, we anticipate that the first payment from the conveyance of the NPI will commence in the second quarter of 2010. Payment of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices.

     At March 31, 2010, the $94.5 million portion of this trade receivable payable from the NPI is presented as “Accounts receivable” in our Consolidated Balance Sheets included in Item 1 Part I of this report. At March 31, 2010, we believe that collectability of the amount owed pursuant to the NPI arrangement is reasonably assured.

     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, 2009.

     $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 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, 2010, the applicable margin on LIBOR loans would have been 0.24%. As of March 31, 2010, there were no loans outstanding under the Credit Facility; however $63.1 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 and by evaluating our ongoing rig equipment replacement and enhancement programs, including water depth and drilling capability upgrades. We believe that our operating cash flows and cash reserves will be sufficient to meet 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.

     At March 31, 2010, we had foreign currency forward exchange, or FOREX, contracts outstanding in the aggregate notional amount of $77.6 million outstanding. See further information regarding these contracts in Item 3, “Quantitative and Qualitative Disclosures About Market Risk — Foreign Exchange Risk” and Note 4 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 1 of Part I of this report.

     As of March 31, 2010, the total unrecognized tax benefit related to uncertain tax positions was $34.3 million. 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 purchase obligations for major rig upgrades or any other significant obligations at March 31, 2010, 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, 2010 in the amount of $171.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $63.1 million in letters of credit issued under our Credit Facility. We purchased five of these bonds totaling $82.4 million from a related party after obtaining competitive quotes. Agreements relating to approximately $82.4 million of performance bonds can require collateral at any time. As of March 31, 2010, 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 March 31,
		Total				2010				2011				Thereafter
		(In thousands)
Other Commercial Commitments
Customs bonds		$	47,085			$	47,085			$	—			$	—
Performance bonds			96,121				49,535				34,762				11,824
Other			28,422				27,422				1,000				—
Total obligations		$	171,628			$	124,042			$	35,762			$	11,824

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 $435 million on capital expenditures for 2010 associated with our ongoing rig equipment replacement and enhancement programs, equipment required for our long-term international contracts and other corporate requirements. In addition, we expect to spend approximately $75 million in 2010 towards the commissioning and outfitting for service of the recently acquired Ocean Courage and Ocean Valor. During the first quarter of 2010, we spent approximately $107.8 million towards these programs. We expect to finance our 2010 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, 2010 and December 31, 2009, 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, 2010 compared to the three months ended March 31, 2009.

Net Cash Provided by Operating Activities.

		Three Months Ended March 31,
		2010				2009				Change
		(In thousands)
Net income		$	290,853			$	348,581			$	(57,728	)
Net changes in operating assets and liabilities			54,975				(91,118	)			146,093
Proceeds from settlement of FOREX contracts designated as accounting hedges			2,099				—				2,099
Gain on sale and disposition of assets			(884	)			(55	)			(828	)
Loss (gain) on sale of marketable securities			1				(597	)			598
(Gain) loss on FOREX contracts			(2,099	)			25				(2,124	)
Deferred tax provision			(4,843	)			8,365				(13,208	)
Depreciation and other non-cash items, net			124,779				141,878				(17,100	)
		$	464,881			$	407,079			$	57,802

     Our cash flows from operations during the first three months of 2010 increased $57.8 million, or 14%, compared to the same period in 2009, primarily due to a decrease in net cash needed to satisfy our working capital needs partially offset by a decrease in earnings in 2010 compared to 2009. We used $146.1 million less cash to satisfy our working capital requirements during the first quarter of 2010 compared to the first quarter of 2009. Trade and other receivables used cash of $44.8 million during the first three months of 2010 compared to $114.0 million during the comparable period of 2009. The reduction in working capital requirements in the first quarter of 2010 also reflects an increase in U.S. and foreign income taxes payable on earnings during the first quarter of 2010 compared to the same period of the prior year, which contributed an aggregate $70.4 million to net cash flows from operations. 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. During the first three months of 2009, we paid foreign income taxes net of refunds of $47.8 million.

Net Cash Used in Investing Activities.

		Three Months Ended March 31,
		2010				2009				Change
		(In thousands)
Purchase of marketable securities		$	(1,349,900	)		$	(1,149,112	)		$	(200,788	)
Proceeds from sale and maturities of marketable securities			1,200,053				1,348,964				(148,911	)
Capital expenditures			(107,798	)			(130,408	)			22,610
Proceeds from disposition of assets			989				325				664
Cost of settlement of FOREX contracts			—				(24,789	)			24,789
		$	(256,656	)		$	44,980			$	(301,636	)

     Our investing activities used $256.7 million during the first three months of 2010 compared to providing $45.0 million during the comparable period in 2009. During the first quarter of 2010 we purchased marketable securities, net of sales, of $149.8 million compared to net sales of $199.9 million during the same period in 2009. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets.

     During the first three months of 2010, we spent approximately $107.8 million related to ongoing capital maintenance programs, including rig modifications to meet contractual requirements, and commissioning/outfitting the Ocean Courage and Ocean Valor, compared to $130.4 million during the same period in 2009.

     Prior to May 2009, we entered into FOREX contracts as economic hedges of our foreign currency requirements; however, we did not designate these contracts as accounting hedges. During the latter part of 2008 and during the first quarter of 2009, the strengthening U.S. dollar (or, conversely, the weakening foreign currency) negatively impacted these expiring FOREX contracts and resulted in aggregate, net realized losses of $24.8 million for the first quarter of 2009. We have presented the settlement of these contracts within “Net Cash Used in Investing Activities.”

Net Cash Used in Financing Activities.

		Three Months Ended March 31,
		2010				2009				Change
		(In thousands)
Payment of dividends		$	(278,597	)		$	(278,257	)		$	(340	)
Other			9				—				9
		$	(278,588	)		$	(278,257	)		$	(331	)