Edgar Filing: DIAMOND OFFSHORE DRILLING INC

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended June 30, 2010


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

For the transition period from to

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)


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

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

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

Yes þ No o

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

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the 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 (Do not check if a smaller reporting company)		Smaller reporting company o

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

Yes o No þ

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

As of July 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 JUNE 30, 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		19

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		43

ITEM 4. Controls and Procedures		44

PART II. OTHER INFORMATION		45

ITEM 1A. Risk Factors		45

ITEM 6. Exhibits		47

SIGNATURES		48

EXHIBIT INDEX		49
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

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


	June 30,			December 31,
	2010			2009
ASSETS
Current assets:
Cash and cash equivalents	$	525,119		$	376,417
Marketable securities		250,691			400,853
Accounts receivable, net of provision for bad debts		636,572			791,023
Prepaid expenses and other current assets		170,819			155,077
Asset held for sale		152,280			—

Total current assets		1,735,481			1,723,370
Drilling and other property and equipment, net of accumulated depreciation		4,299,215			4,432,052
Long-term receivable		57,254			—
Other assets		423,015			108,839

Total assets	$	6,514,965		$	6,264,261


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	77,881		$	75,015
Accrued liabilities		358,851			301,871
Taxes payable		147,851			32,410
Current portion of long-term debt		—			4,179

Total current liabilities		584,583			413,475

Long-term debt		1,495,483			1,495,375
Deferred tax liability		555,786			546,024
Other liabilities		222,239			178,745

Total liabilities		2,858,091			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 June 30, 2010 and December 31, 2009)		1,439			1,439
Additional paid-in capital		1,969,232			1,965,513
Retained earnings		1,803,021			1,776,498
Accumulated other comprehensive gain (loss)		(2,405	)		1,605
Treasury stock, at cost (4,916,800 shares at June 30, 2010 and December 31, 2009)		(114,413	)		(114,413	)

Total stockholders’ equity		3,656,874			3,630,642

Total liabilities and stockholders’ equity	$	6,514,965		$	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						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
Revenues:
Contract drilling	$	811,739		$	923,458		$	1,656,177		$	1,779,166
Revenues related to reimbursable expenses		10,864			22,949			26,107			52,961

Total revenues		822,603			946,407			1,682,284			1,832,127


Operating expenses:
Contract drilling, excluding depreciation		348,971			304,853			654,098			602,600
Reimbursable expenses		10,379			22,431			25,084			52,146
Depreciation		100,746			85,431			198,148			170,493
General and administrative		16,849			16,166			33,503			32,481
Gain on disposition of assets		(149	)		(93	)		(1,033	)		(148	)

Total operating expenses		476,796			428,788			909,800			857,572


Operating income		345,807			517,619			772,484			974,555

Other income (expense):
Interest income		477			1,190			1,759			1,766
Interest expense		(21,333	)		(11,288	)		(43,654	)		(12,405	)
Foreign currency transaction gain (loss)		(3,991	)		13,733			(3,530	)		9,608
Other, net		(34	)		(416	)		(121	)		651


Income before income tax expense		320,926			520,838			726,938			974,175

Income tax expense		(96,533	)		(133,398	)		(211,692	)		(238,154	)


Net income	$	224,393		$	387,440		$	515,246		$	736,021


Income per share:
Basic	$	1.61		$	2.79		$	3.71		$	5.30

Diluted	$	1.61		$	2.79		$	3.70		$	5.29


Weighted-average shares outstanding:
Shares of common stock		139,026			139,002			139,026			139,001
Dilutive potential shares of common stock		53			79			78			72

Total weighted-average shares outstanding		139,079			139,081			139,104			139,073


Cash dividends declared per share of common stock	$	1.50		$	2.00		$	3.50		$	4.00

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)


	Six Months Ended
	June 30,
	2010			2009
Operating activities:
Net income	$	515,246		$	736,021
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		198,148			170,493
(Gain) on disposition of assets		(1,033	)		(148	)
(Gain) loss on sale of marketable securities, net		2			(599	)
(Gain) on foreign currency forward exchange contracts		(457	)		(8,837	)
Deferred tax provision		11,921			37,910
Accretion of discounts on marketable securities		(200	)		(503	)
Amortization/write-off of debt issuance costs		449			274
Amortization of debt discounts		167			134
Stock-based compensation expense		3,719			3,376
Deferred income, net		56,593			66,716
Deferred expenses, net		(52,311	)		(2,257	)
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges		457			—
Other assets, noncurrent		5,788			(16,713	)
Other liabilities, noncurrent		7,712			6,175
Changes in operating assets and liabilities:
Accounts receivable		109,118			(166,449	)
Prepaid expenses and other current assets		(20,045	)		(25,108	)
Accounts payable and accrued liabilities		8,666			(49,073	)
Taxes payable		(149,635	)		(46,014	)

Net cash provided by operating activities		694,305			705,398


Investing activities:
Capital expenditures		(221,890	)		(226,284	)
Rig acquisition		—			(460,000	)
Proceeds from disposition of assets, net of disposal costs		1,258			453
Deposits received on sale of rigs		18,600			6,000
Proceeds from sale and maturities of marketable securities		2,550,088			3,198,829
Purchases of marketable securities		(2,399,760	)		(2,998,780	)
Cost to settle foreign currency forward exchange contracts not designated as accounting hedges		—			(28,862	)

Net cash used in investing activities		(51,704	)		(508,644	)


Financing activities:
Redemption of zero coupon debentures		(4,238	)		—
Issuance of 5.875% senior unsecured notes		—			499,255
Debt issuance costs and arrangement fees		(98	)		(3,752	)
Payment of dividends		(489,670	)		(558,036	)
Proceeds from stock plan exercises		107			155

Net cash used in financing activities		(493,899	)		(62,378	)


Net change in cash and cash equivalents		148,702			134,376
Cash and cash equivalents, beginning of period		376,417			336,052

Cash and cash equivalents, end of period	$	525,119		$	470,428

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 July 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.

Reclassifications

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

Cash and Cash Equivalents, Marketable Securities

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

We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in “Accumulated other comprehensive gain (loss)” 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 $42.0 million and $12.5 million for the six months ended June 30, 2010 and 2009, respectively. During the six months ended June 30, 2010, we paid $0.9 million in interest on assessments from the Internal Revenue Service.

We made estimated U.S. federal income tax payments of $254.5 million and $140.0 million during the six months ended June 30, 2010 and 2009, respectively. We paid $76.2 million and $106.1 million in foreign income taxes, net of foreign tax refunds, during the six months ended June 30, 2010 and 2009, respectively. We paid state income taxes, net of refunds, of $0.1 million during the six months ended June 30, 2010. We paid state income taxes of $0.2 million during the six months ended June 30, 2009.

Capital expenditures for the six months ended June 30, 2010 included $64.9 million that was accrued but unpaid at December 31, 2009. Capital expenditures for the six months ended June 30, 2009 included $59.4 million that was accrued but unpaid at December 31, 2008. Capital expenditures that were accrued but not paid as of June 30, 2010 totaled $60.9 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at June 30, 2010.

We recorded income tax benefits of $0 and $2,000 related to employee stock plan exercises during the six months ended June 30, 2010 and 2009, respectively.

Asset Held for Sale

At June 30, 2010, we had transferred the $152.3 million net book value of the Ocean Shield to “Asset held for sale” in our Consolidated Balance Sheets. Pursuant to the purchase and sale agreement, we received an $18.6 million deposit from the purchaser, which we recorded in “Accrued liabilities” in our Consolidated Balance Sheets at June 30, 2010.

On July 7, 2010, we completed the sale of this rig for a gross purchase price of $186.0 million. In conjunction with the sale of the rig, we entered into a bareboat charter with the successor owner of the rig at a charter rate of $20,000 per day until such time that the successor owner can comply with all obligations under the drilling contract and the drilling contract can be assigned to the successor owner.

Impairment of Long-Lived Assets

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

	•		dayrate by rig;

	•		utilization rate by rig (expressed as the actual percentage of time per year that the rig would be used);

	•		the per day operating cost for each rig if active, ready-stacked or cold-stacked; and

	•		salvage value for each rig.

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

As of June 30, 2010, we evaluated the Ocean Voyager, an intermediate semisubmersible rig in the U.S. Gulf of Mexico, or GOM, that was cold stacked late in the second quarter of 2010, for impairment. We evaluated the rig for impairment using the probability-weighted cash flow analysis discussed above. Based on this analysis, we determined that the probability-weighted cash flows exceeded the carrying value of the rig.

At June 30, 2010, we do not believe that current circumstances indicated that there was an impairment of any of our other drilling rigs in the GOM or elsewhere.

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

Comprehensive Income

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)
Net income	$	224,393		$	387,440		$	515,246		$	736,021
Other comprehensive gains (losses), net of tax:
FOREX contracts:
Unrealized holding (loss) gain		(3,397	)		3,831			(3,260	)		3,831
Reclassification adjustment for loss (gain) included in net income		356			—			(729	)		—

Investments in marketable securities:
Unrealized holding (loss) gain		(18	)		9			(22	)		36
Reclassification adjustment for loss (gain) included in net income		1			(14	)		1			(507	)

Comprehensive income	$	221,335		$	391,266		$	511,236		$	739,381

The tax related to the change in unrealized holding loss on FOREX contracts was approximately $1.8 million for each of the three-month and six-month periods ended June 30, 2010. The tax related to the change in unrealized holding gains on our FOREX contracts was approximately $2.1 million for each of the three-month and six-month periods ended June 30, 2009. The tax related to the reclassification adjustment for FOREX contracts included in net income was approximately $192,000 and $393,000 for the three months and six months ended June 30, 2010, respectively.

The tax related to the change in unrealized holding loss on investments was approximately $10,000 and $12,000 for the three months and six months ended June 30, 2010, respectively. The tax related to the change in unrealized holding gains on investments was approximately $5,000 and $19,000 for the three months and six months ended June 30, 2009, respectively. The tax effect on the reclassification adjustment for net losses included in net income was approximately $1,000 for each of the three-month and six-month periods ended June 30, 2010. The tax effect on the reclassification adjustment for net gains included in net income was approximately $8,000 and $273,000 for the three months and six months ended June 30, 2009, respectively.

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 and six months ended June 30, 2010, we recognized net foreign currency exchange losses of $4.0 million and $3.5 million, respectively. For the three and six months ended June 30, 2009, we recognized net foreign currency exchange gains of $13.7 million and $9.6 million, respectively. See Note 4.

Revenue Recognition

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

From time to time, we may receive fees from our customers for capital improvements to our rigs. We defer such fees received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize

these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the asset.

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

2. Earnings Per Share

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(In thousands, except per share data)
Net income — basic (numerator):	$	224,393	$	387,440	$	515,246	$	736,021
Effect of dilutive potential shares
Zero Coupon Debentures		32		24		56		46

Net income including conversions — diluted (numerator)	$	224,425	$	387,464	$	515,302	$	736,067


Weighted average shares — basic (denominator):		139,026		139,002		139,026		139,001
Effect of dilutive potential shares
Zero Coupon Debentures		32		52		42		52
Stock options and SARs		21		27		36		20

Weighted average shares including conversions — diluted (denominator)		139,079		139,081		139,104		139,073

Earnings per share:
Basic	$	1.61	$	2.79	$	3.71	$	5.30

Diluted	$	1.61	$	2.79	$	3.70	$	5.29

Our computation of diluted earnings per share, or EPS, for the three months ended June 30, 2010 excludes stock options representing 8,000 shares of common stock and 672,214 stock appreciation rights, or SARs. Our computation of diluted EPS for the six months ended June 30, 2010 excludes stock options representing 4,022 shares of common stock and 557,264 SARs. The inclusion of such potentially dilutive shares in the computation of diluted EPS would have been antidilutive for the periods presented.

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

3. Marketable Securities

We report our investments as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations. See Note 5.

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


	June 30, 2010
	Amortized		Unrealized			Market
	Cost		Gain (Loss)			Value
	(In thousands)
Due within one year	$	249,958	$	(20	)	$	249,938
Mortgage-backed securities		701		52			753

Total	$	250,659	$	32		$	250,691


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

Total	$	400,789	$	64		$	400,853

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010			2009
	(In thousands)
Proceeds from sales	$	35		$	999,886		$	88		$	2,448,829
Proceeds from maturities		1,350,000			750,000			2,550,000			750,000
Gross realized gains		—			36			—			768
Gross realized losses		(1	)		(34	)		(2	)		(169	)

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 are recorded as a component of “Accumulated other comprehensive gain (loss),” or AOCGL, in our Consolidated Financial Statements. The effective portion of the cash flow hedge will remain in AOCGL 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 six months ended June 30, 2010, we settled FOREX contracts with an aggregate notional value of approximately $147.2 million, of which the entire aggregate amount was designated as an accounting hedge. During the six months ended June 30, 2009, we settled foreign currency exchange contracts with an aggregate notional value of approximately $214.6 million, of which none were designated as accounting hedges.

The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as accounting hedges for the quarters and six-month periods ended June 30, 2010 and 2009.


	Amount of (Loss) Gain Recognized in Income
	Three Months Ended					Six Months Ended
	June 30,					June 30,
Location of (Loss) Gain Recognized in Income	2010			2009		2010		2009
	(In thousands)
Contract drilling expense	$	(1,643	)	$	—	$	457	$	—

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 quarters and six-month periods ended June 30, 2010 and 2009


	Amount of Gain Recognized in Income
	Three Months Ended				Six Months Ended
	June 30,				June 30,
Location of Gain Recognized in Income	2010		2009		2010		2009
	(In thousands)
Foreign currency transaction gain	$	—	$	8,594	$	—	$	8,568

The amounts presented in the table above include unrealized gains of $12.6 million and $37.4 million for the three months and six months ended June 30, 2009, respectively, to record the carrying value of our derivative financial instruments to their fair value. There were no gains or losses associated with FOREX contracts not designated as accounting hedges during the three months and six months ended June 30, 2010.

As of June 30, 2010, we had FOREX contracts outstanding, in the aggregate notional amount of $118.7 million, consisting of $46.4 million in Australian dollars, $38.1 million in Brazilian reais, $21.8 million in British pounds sterling, $5.2 million in Mexican pesos and $7.2 million in Norwegian kroner. These contracts generally settle monthly through November 2010. As of June 30, 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 June 30, 2010.

Assets

Liabilities

Balance Sheet

Location

Fair Value

Location

Fair Value

(In

thousands)

Derivatives designated as hedging instruments:

FOREX contracts

Prepaid expenses and
other current assets

422

Accrued liabilities

(4,155

)

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

Assets

Liabilities

Balance Sheet

Location

Fair Value

Location

Fair Value

(In

thousands)

Derivatives designated as hedging instruments:

FOREX contracts

Prepaid expenses and
other current assets

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-month and six-month periods ended June 30, 2010.

Location of Gain

Amount of

Recognized in Income

Amount of Gain

Loss

Location of

Amount of

on Derivative

Recognized in Income on

Recognized in

(Loss) Gain

(Ineffective Portion

Derivative (Ineffective

AOCGL on

Reclassified from

and Amount Excluded

Portion and Amount

Derivative

AOCGL into Income

from Effectiveness

Excluded from

(Effective Portion)

Testing)

Effectiveness Testing)

Three

Six

Three

Six

Three

Six

Months

Ended

June 30,

2010

(In thousands)

$(5,226)

(5,015

)

Contract drilling
expense

(548

)

1,122

Foreign currency
transaction gain (loss)

—

Location of Gain

Amount of

Recognized in Income

Amount of Gain

Gain

Location of

Amount of

on Derivative

Recognized in Income on

Recognized in

Gain

(Ineffective Portion

Derivative (Ineffective

AOCGL on

Reclassified from

and Amount Excluded

Portion and Amount

Derivative

AOCGL into Income

from Effectiveness

Excluded from

(Effective Portion)

Testing)

Effectiveness Testing)

Three

Six

Three

Six

Months

Six Months

Months

Ended

June 30,

2009

(In thousands)

$ 5,894

5,894

Contract drilling
expense

—

Foreign currency
transaction gain (loss)

269

As of June 30, 2010, the estimated amount of net unrealized losses associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $3.7 million. The net unrealized losses 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 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 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.

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. We received our first payment from the conveyance of the NPI in July 2010. Based on current production payout estimates, we expect to collect $37.2 million of the receivable within the next twelve months. However, payment of such amounts, and the timing of such payments, are contingent upon such production and upon energy sale prices.

At June 30, 2010, $94.5 million was payable to us from the NPI, of which $37.2 million and $57.3 million are presented as “Accounts receivable” and “Long-term receivable,” respectively, in our Consolidated Balance Sheets. At June 30, 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:


	June 30, 2010				December 31, 2009
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
Zero Coupon Debentures	$	—	$	—	$	5.1	$	4.2
4.875% Senior Notes		260.4		249.7		257.5		249.7
5.15% Senior Notes		262.8		249.7		263.3		249.7
5.70% Senior Notes		450.0		496.8		490.4		496.7
5.875% Senior Notes		519.9		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 June 30, 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 June 30, 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 June 30, 2010 and December 31, 2009, respectively.

	•		Long-term receivable — The carrying amount approximates fair value based on the nature of the instrument.

	•		Long-term debt — The fair value of our 5.70% Senior Notes due 2039, 5.875% Senior Notes due 2019, 4.875% Senior Notes due July 1, 2015, and 5.15% Senior Notes due September 1, 2014 was based on the quoted market prices from brokers of these instruments. 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 December 31, 2009, 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 June 30, 2010 consisted of cash held in money market funds of $516.9 million and investments in U.S. Treasury Bills of $249.9 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.

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


	June 30, 2010
	Fair Value Measurements Using							Assets at Fair
	Level 1		Level 2			Level 3		Value
	(In thousands)
Assets:
Short-term investments	$	766,820	$	—		$	—	$	766,820
FOREX contracts		—		422			—		422
Mortgage-backed securities		—		753			—		753

Total assets	$	766,820	$	1,175		$	—	$	767,995


Liabilities:

FOREX contracts	$	—	$	(4,155	)	$	—	$	(4,155	)


	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:


	June 30,		December 31,
	2010		2009
	(In thousands)
Rig spare parts and supplies	$	51,420	$	49,122
Deferred mobilization costs		73,205		45,502
Prepaid insurance		22,255		11,478
Deferred tax assets		7,235		7,235
Deposits		2,158		3,562
Prepaid taxes		4,617		27,679
FOREX contracts		422		2,634
Other		9,507		7,865

Total	$	170,819	$	155,077

7. Drilling and Other Property and Equipment

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


	June 30,			December 31,
	2010			2009
	(In thousands)
Drilling rigs and equipment	$	6,991,366		$	6,950,303
Land and buildings		51,475			44,640
Office equipment and other		42,080			38,203

Cost		7,084,921			7,033,146
Less: accumulated depreciation		(2,785,706	)		(2,601,094	)

Drilling and other property and equipment, net	$	4,299,215		$	4,432,052

8. Accrued Liabilities

Accrued liabilities consist of the following:


	June 30,		December 31,
	2010		2009
	(In thousands)
Accrued project/upgrade expenses	$	100,772	$	115,778
Payroll and benefits		71,895		69,065
Deferred revenue		84,656		46,666
Rig operating expenses		40,599		29,141
Interest payable		21,298		22,710
Personal injury and other claims		11,723		10,018
FOREX contracts		4,155		230
Deposit for asset sale		18,600		—
Other		5,153		8,263

Total	$	358,851	$	301,871

9. Long-Term Debt

Long-term debt consists of the following:


	June 30,		December 31,
	2010		2009
	(In thousands)
Zero Coupon Debentures (due 2020)	$	—	$	4,179
5.15% Senior Notes (due 2014)		249,714		249,682
4.875% Senior Notes (due 2015)		249,698		249,671
5.875% Senior Notes (due 2019)		499,321		499,292
5.70% Senior Notes (due 2039)		496,750		496,730

		1,495,483		1,499,554
Less: Current maturities		—		4,179

Total	$	1,495,483	$	1,495,375

The aggregate maturities of long-term debt for each of the five years subsequent to June 30, 2010, are as follows:


(Dollars in thousands)
2010	$	—
2011		—
2012		—
2013		—
2014		249,714
Thereafter		1,245,769

Total	$	1,495,483

Redemption of Zero Coupon Debentures

On May 28, 2010, we repurchased the then outstanding $4.2 million accreted value, or $6.0 million in aggregate principal amount at maturity, of our Zero Coupon Debentures at a purchase price of $706.28 per $1,000 principal amount at maturity for cash. At June 30, 2010, there were no Zero Coupon Debentures outstanding.

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 $10.0 million per the first occurrence, with no aggregate deductible, and varies in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models. At June 30, 2010, our estimated liability for personal injury claims was $37.8 million, of which $11.1 million and $26.7 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 June 30, 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 June 30, 2010 in the amount of $136.4 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $23.9 million in letters of credit issued under our $285 million, syndicated, senior unsecured revolving credit facility. At June 30, 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 June 30, 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				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(In thousands)
High-Specification Floaters	$	340,387	$	334,527	$	724,175	$	646,661
Intermediate Semisubmersibles		389,094		465,762		769,795		882,762
Jack-ups		82,223		123,169		162,172		249,743
Other		35		—		35		—

Total contract drilling revenues		811,739		923,458		1,656,177		1,779,166
Revenues related to reimbursable expenses		10,864		22,949		26,107		52,961

Total revenues	$	822,603	$	946,407	$	1,682,284	$	1,832,127

Geographic Areas

Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At June 30, 2010, our drilling rigs were located offshore twelve countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
	(In thousands)
United States	$	189,019	$	333,865	$	427,566	$	690,180

International:
South America		312,207		172,708		595,323		297,409
Australia/Asia/Middle East		142,463		199,232		301,392		373,457
Europe/Africa/Mediterranean		140,078		160,970		276,683		310,802
Mexico		38,836		79,632		81,320		160,279

Total revenues	$	822,603	$	946,407	$	1,682,284	$	1,832,127

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 and Item 1A of Part II, “Risk Factors,” included in this report. 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 46 offshore rigs currently consisting of 32 semisubmersibles, 13 jack-ups and one drillship. On July 7, 2010, we completed the sale of one of our high-performance, premium jack-up drilling rigs, the Ocean Shield.

Overview

Industry Conditions

On April 20, 2010, the Macondo well being drilled by BP plc in the U.S. Gulf of Mexico, or GOM, experienced a blowout and immediately began flowing oil into the GOM. Efforts to permanently plug and abandon the well and contain the spill are ongoing at the time of this report.

In the aftermath of this event, on May 30, 2010, the U.S. government imposed a moratorium on certain drilling activities in water deeper than 500 feet in the GOM and subsequently implemented enhanced safety requirements applicable to all drilling activity in the GOM, including drilling activities in water shallower than 500 feet. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana granted a temporary injunction which immediately prohibited enforcement of the moratorium. The U.S. government appealed the ruling and the District Court’s decision and requested that the U.S. Court of Appeals for the Fifth Circuit Court stay the injunction pending appeal. The Fifth Circuit denied the government’s stay motion. While the appeal is pending, the government has rescinded the moratorium and ordered a new suspension through November 30, 2010, subject to modifications by the government under certain circumstances, of drilling activities using subsea blowout preventers, or BOPs, or surface BOPs on floating facilities. Further proceedings with respect to the moratorium and the new suspension are pending. We currently have six rigs (three floaters and three jack-ups) under contract in the GOM.

The practical effects in the GOM of the uncertainty caused by the drilling moratorium and the suspension have been a freeze on nearly all floater activity and, given a dramatically slower permitting process, a reduction of jack-up activity. It has been reported that the industry currently has 32 floating rigs in the GOM that have been impacted by the suspension, of which we have three semisubmersible units under contract. All three of these rigs have subsea BOPs. Two other of our semisubmersible units, the Ocean Confidence and the Ocean Endeavor, formerly working in the GOM, are mobilizing to international locations. We are working towards compliance with the various new regulations put in place since May 30, 2010. However, the overall regulatory environment in the GOM remains very fluid, with frequent changes. We are not able to predict the outcome of the various legal proceedings, whether enforcement of the moratorium will be permanently enjoined, whether the suspension will remain in place, or whether the government will seek to implement additional restrictions on or prohibitions of drilling activities in the GOM; and we are not able to predict the impact of these events on our operations.

Given the continuing uncertainty with respect to drilling activity in the GOM, our customers may seek to move rigs to locations outside of the GOM, perform activities which are allowed under the enhanced safety requirements and not prohibited by the moratorium or the suspension, or attempt to terminate our contracts pursuant to their respective force majeure provisions. These agreements generally provide for a force majeure dayrate that extends for a specified period of time and varies from contract to contract. Several customers have either asserted force majeure, including with respect to the Ocean Monarch, or indicated that they may assert force majeure under their relevant contracts. We are assessing each situation on an individual basis as it arises.

In an effort to preserve our contract revenue backlog, we have reached agreements with two of our customers to mobilize two of our high-specification floaters to international locations. The Ocean Endeavor is mobilizing to Egypt under a term contract ending June 30, 2011, plus an option period. This new contract for the Ocean Endeavor will help us preserve backlog, and will allow the previous operator of the rig to satisfy certain contractual obligations. The new contract, combined with a $31 million early termination fee paid by the previous operator of the rig, is expected to generate combined maximum total revenue of approximately $100 million.

The Ocean Confidence is mobilizing to the Republic of Congo under a restructured term agreement with the current operator. Under the agreement, the original contract in the GOM has been suspended and restructured into a one-year commitment in the GOM that is expected to recommence when our customer is satisfied that it can obtain the necessary permits and can meet any new regulatory requirements. The new international contract is a three-well commitment, plus an option for additional work, and includes an obligation for the customer to mobilize the rig to and from the Republic of Congo. The remaining one-year GOM commitment and new international commitment are expected to generate combined maximum total revenue of approximately $234 million.

We are continuing to actively seek international opportunities to keep our rigs employed. However, we can provide no assurance that we will be successful in our efforts to employ our remaining impacted rigs in the GOM in the near term or that the force majeure assertions will ultimately be resolved in our favor.

In addition, given the uncertainty with respect to drilling activity in the GOM, we elected to cold stack our intermediate rig Ocean Voyager when it rolled off contract in June 2010.

Maximum contract revenue as stated above assumes 100% rig utilization. Generally, rig utilization rates approach 95-98% during contracted periods; however, utilization rates can be adversely impacted by additional downtime due to unscheduled repairs, maintenance and weather.

Outside the GOM, the global economy remained relatively flat in the second quarter of 2010, with oil prices averaging in the mid $70s. 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 is being further exacerbated by the uncertainty in the GOM. If we, or others, move rigs out of the GOM to international locations, the increased supply of available rigs entering the international market, coupled with un-contracted new-build rigs scheduled for delivery this year and next, could create downward pressure on dayrates unless demand improves sufficiently to absorb the new supply.

In addition to the contracts for the Ocean Endeavor and Ocean Confidence discussed above, we signed six new contracts during the second quarter of 2010 totaling approximately $137 million in backlog and ranging in length from one well to one year. At the end of the second quarter of 2010, our contract backlog was approximately $8.2 billion, of which our contracts in the GOM represented approximately $795.0 million, or 10% of our total contract backlog.

Floaters

Our intermediate and high-specification floater rigs, both domestic and international, accounted for approximately 88% of our revenue during the first six months of 2010. Approximately 87% of the time on our intermediate and high-specification floater rigs is committed for the remainder of 2010. Additionally, 66% of the time on our floating rigs is committed in 2011.

International Jack-ups

During the second quarter of 2010, demand for our international jack-ups remained weak but stable. Dayrates softened internationally as existing rigs rolled off contract and met competition from un-contracted new-build jack-ups that came to market. The high-specification new-build equipment coming to market is enjoying a significantly higher utilization rate than older existing equipment, and the oversupply of jack-up rigs could have an increasingly negative impact on the international sector throughout 2010 and beyond.

U.S. Gulf of Mexico Jack-ups

In addition to the delay in issuance of jack-up permits in the GOM, lower natural gas prices have negatively impacted both demand and dayrates. During the second quarter of 2009, we cold-stacked three of our lower-end jack-up units to reduce costs, and they are not being actively marketed. Our four remaining higher-specification jack-ups in the GOM are largely working under short-term contracts. One of these rigs, the Ocean Scepter, has received a contract for a one-year term in Brazil, and is expected to mobilize in early August 2010. Absent an increase in permitting activity and 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 us and others in the industry.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of July 22, 2010, February 1, 2010 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2009) and July 20, 2009 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 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.


	July 22,		February 1,		July 20,
	2010		2010		2009
	(In thousands)
Contract Drilling Backlog
High-Specification Floaters ⁽¹⁾	$	4,705,000	$	4,177,000	$	4,016,000
Intermediate Semisubmersibles⁽²⁾		3,322,000		4,030,000		4,391,000
Jack-ups⁽³⁾		139,000		249,000		311,000

Total	$	8,166,000	$	8,456,000	$	8,718,000


(1)		Contract drilling backlog as of July 22, 2010 for our high-specification floaters includes (i) $3.1 billion attributable to our contracted operations offshore Brazil for the remainder of 2010 and for the years 2011 to 2016 and (ii) $724.0 million attributable to our contracted operations in the GOM for the remainder of 2010 and for the years 2011 to 2013.

(2)		Contract drilling backlog as of July 22, 2010 for our intermediate semisubmersibles includes (i) $2.6 billion attributable to our contracted operations offshore Brazil for the remainder of 2010 and for the years 2011 to 2015 and (ii) $64.0 million attributable to our contracted operations in the GOM for the remainder of 2010 and for the year 2011.

(3)		Contract drilling backlog as of July 22, 2010 for our jack-ups includes (i) $49.0 million attributable to our contracted operations offshore Brazil for the remainder of 2010 and for the year 2011 and (ii) $7.0 million attributable to our contracted operations in the GOM for the remainder of 2010.

The following table reflects the amount of our contract drilling backlog by year as of July 22, 2010.


	For the Years Ending December 31,
	Total		2010⁽¹⁾		2011		2012		2013 - 2016
	(In thousands)
Contract Drilling Backlog
High-Specification Floaters ⁽²⁾	$	4,705,000	$	855,000	$	1,619,000	$	914,000	$	1,317,000
Intermediate Semisubmersibles ⁽³⁾		3,322,000		723,000		996,000		860,000		743,000
Jack-ups ⁽⁴⁾		139,000		70,000		69,000		—		—

Total	$	8,166,000	$	1,648,000	$	2,684,000	$	1,774,000	$	2,060,000


(1)		Represents a six-month period beginning July 1, 2010.

(2)		Contract drilling backlog as of July 22, 2010 for our high-specification floaters includes (i) $392.0 million, $803.0 million and $667.0 million for the remainder of 2010 and for the years 2011 and 2012, respectively, and $1.3 billion in the aggregate for the years 2013 to 2016, attributable to our contracted operations offshore Brazil and (ii) $123.0 million, $386.0 million, $183.0 million and $32.0 million for the remainder of 2010 and for the years 2011, 2012 and 2013, respectively, attributable to our contracted operations in the GOM.

(3)		Contract drilling backlog as of July 22, 2010 for our intermediate semisubmersibles includes (i) $371.0 million, $764.0 million and $732.0 million for the remainder of 2010 and for the years 2011 and 2012, respectively, and $687.0 million in the aggregate for the years 2013 to 2016, attributable to our contracted operations offshore Brazil and (ii) $28.0 million and $36.0 million for the remainder of 2010 and for the year 2011, respectively, attributable to our contracted operations in the GOM.

(4)		Contract drilling backlog as of July 22, 2010 for our jack-ups includes (i) $4.0 million and $45.0 million for the remainder of 2010 and for the year 2011, respectively, attributable to our contracted operations


		offshore Brazil and (ii) $7.0 million for the remainder of 2010 attributable to our contracted operations in the GOM.

The following table reflects the percentage of rig days committed by year as of July 22, 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		96	%		80	%		47	%		18	%
Intermediate Semisubmersibles		80	%		55	%		44	%		10	%
Jack-ups		33	%		11	%		—			—


(1)		Represents a six-month period beginning July 1, 2010.

(2)		Includes approximately 647 and 410 scheduled shipyard, survey and mobilization days for 2010 and 2011, respectively.

General

The two most significant variables affecting our revenues are dayrates for rigs and rig utilization rates, each of which is a function of rig supply and demand in the marketplace. Demand for drilling services is dependent upon the level of expenditures set by oil and gas companies for offshore exploration and development, as well as a variety of political 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.

Our operating costs are also impacted by the regulatory environments in which we operate. The adoption of new regulations could result in additional inspection and certification costs, as well as require additional capital investment to comply with regulatory requirements. Accordingly, we cannot predict the financial impact of new regulations for rigs operating in the GOM that may be adopted relating to the investigation into the Macondo well blowout. We are in the process of complying with the new regulations and requirements which have been promulgated subsequent to May 30, 2010 for our six impacted rigs; however, new regulations and restrictions are expected to be issued as the investigation into the well blowout continues. New laws or regulations may require an increase in our capital spending for additional equipment to comply with such requirements. Our business could be negatively impacted by additional downtime which may be required to obtain necessary equipment and to install such equipment once the drilling moratorium and suspension are lifted.

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.

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

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

During the remainder of 2010, six of our rigs will either require or complete 5-year surveys, and we expect that they will be out of service for approximately 253 days in the aggregate during the second half of 2010. We also expect to spend an additional approximately 280 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, 2011, we continue to carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico, with coverage and policy limits similar to our previous policy, for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.

In addition, under our current insurance policy that expires on May 1, 2011, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance, which remains similar to the limit under our previous policy, is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine liability coverage, including for personal injury claims, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and,

if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year, which under the current policy commences on May 1 of each year.

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 six months ended June 30, 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 June 30, 2010 and 2009

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


	Three Months Ended
	June 30,						Favorable/
	2010			2009			(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters	$	340,387		$	334,527		$	5,860
Intermediate Semisubmersibles		389,094			465,762			(76,668	)
Jack-ups		82,223			123,169			(40,946	)
Other		35			—			35

Total Contract Drilling Revenue	$	811,739		$	923,458		$	(111,719	)


Revenues Related to Reimbursable Expenses	$	10,864		$	22,949		$	(12,085	)

CONTRACT DRILLING EXPENSE
High-Specification Floaters	$	134,500		$	98,991		$	(35,509	)
Intermediate Semisubmersibles		157,446			132,696			(24,750	)
Jack-ups		48,919			66,233			17,314
Other		8,106			6,933			(1,173	)

Total Contract Drilling Expense	$	348,971		$	304,853		$	(44,118	)


Reimbursable Expenses	$	10,379		$	22,431		$	12,052

OPERATING INCOME
High-Specification Floaters	$	205,887		$	235,536		$	(29,649	)
Intermediate Semisubmersibles		231,648			333,066			(101,418	)
Jack-ups		33,304			56,936			(23,632	)
Other		(8,071	)		(6,933	)		(1,138	)
Reimbursable expenses, net		485			518			(33	)
Depreciation		(100,746	)		(85,431	)		(15,315	)
General and administrative expense		(16,849	)		(16,166	)		(683	)
Gain on disposition of assets		149			93			56

Total Operating Income	$	345,807		$	517,619		$	(171,812	)


Other income (expense):
Interest income		477			1,190			(713	)
Interest expense		(21,333	)		(11,288	)		(10,045	)
Foreign currency transaction gain		(3,991	)		13,733			(17,724	)
Other, net		(34	)		(416	)		382

Income before income tax expense		320,926			520,838			(199,912	)
Income tax expense		(96,533	)		(133,398	)		36,865

NET INCOME	$	224,393		$	387,440		$	(163,047	)

During the second quarter of 2010, the relatively flat global economy continued to 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 33%, or $171.8 million compared to the second quarter of 2009. Contract drilling revenues for the second quarter of 2010 decreased $111.7 million, or 12%, compared to the second quarter of 2009, and average utilization for our overall fleet decreased from

80% during the second quarter of 2009 to 76% during the second quarter of 2010. Revenues generated by our intermediate semisubmersible and jack-up rigs decreased $117.6 million, primarily due to a reduction in utilization for our intermediate semisubmersible rigs, as well as a decrease in average operating dayrates for both our intermediate semisubmersible and jack-up fleets compared to the second quarter of 2009.

We currently have three mat-supported jack-up rigs in the GOM and two intermediate semisubmersible rigs (one in the GOM and the other in Malaysia) that are cold-stacked and no longer being actively marketed.

Total contract drilling expense increased $44.1 million, or 14%, during the second quarter of 2010 compared to the same period in 2009, primarily due to higher amortized mobilization expenses and higher operating costs due to more of our rigs exiting the GOM to operate internationally, where the operating cost structure is generally higher than that of the GOM, and also due to the inclusion of normal operating costs for the Ocean Courage which began operating early in the first quarter of 2010.

Depreciation expense increased $15.3 million to $100.7 million during the second quarter of 2010, or 18% compared to the second quarter of 2009, due to a higher depreciable asset base, primarily due to the 2009 acquisitions of the Ocean Courage and Ocean Valor.

High-Specification Floaters.


	Three Months Ended
	June 30,				Favorable/
	2010		2009		(Unfavorable)
	(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM	$	124,677	$	247,657	$	(122,980	)
Australia/Asia/Middle East		46,179		38,988		7,191
Europe/Africa/Mediterranean		56,386		—		56,386
South America		113,145		47,882		65,263

Total Contract Drilling Revenue	$	340,387	$	334,527	$	5,860


CONTRACT DRILLING EXPENSE
GOM	$	39,203	$	68,857	$	29,654
Australia/Asia/Middle East		12,372		8,342		(4,030	)
Europe/Africa/Mediterranean		11,232		—		(11,232	)
South America		71,693		21,792		(49,901	)

Total Contract Drilling Expense	$	134,500	$	98,991	$	(35,509	)



OPERATING INCOME	$	205,887	$	235,536	$	(29,649	)

GOM. Revenues generated by our high-specification floaters operating in the GOM decreased $123.0 million during the second quarter of 2010 compared to the same period in 2009. Since the second quarter of 2009, we have relocated four of our high-specification semisubmersible rigs from the GOM to international locations. During the first quarter of 2010, we relocated the Ocean Star to Brazil and the Ocean America to Australia, and the Ocean Baroness was en route to Brazil at the end of the second quarter of 2010. The Ocean Valiant was relocated to Angola early in the third quarter of 2009. The effect of these rig departures from the GOM was a net $108.2 million reduction in revenues in the second quarter of 2010 compared to same period in 2009.

For our remaining fleet in the GOM, average operating revenue per day decreased from $422,300 during the second quarter of 2009 to $365,600 during the current year period, reducing revenues by $17.8 million. Average utilization of these rigs during the second quarter of 2010 increased slightly to 94% and contributed additional revenues of $3.1 million, which partially offset the revenue decline associated with lower average dayrates.

Contract drilling expense for our high-specification floaters in the GOM decreased $29.7 million compared to the second quarter of 2009, primarily due to a reduction in normal operating costs for our four rigs that relocated from the GOM after the second quarter of 2009, as well as a reduction in costs associated with a 2009 special survey for the Ocean America. The overall decrease in operating costs, comparing the quarters, was partially offset by incremental costs associated with a 2010 regulatory survey for the Ocean Confidence and higher maintenance project costs for the Ocean Endeavor.

Australia/Asia/Middle East. During the second quarter of 2010, our revenues and contract drilling expenses in this region increased $7.2 million and $4.0 million, respectively, compared to the second quarter of 2009, primarily due to the relocation of the Ocean America to offshore Australia during the first quarter of 2010.

Europe/Africa/Mediterranean. The Ocean Valiant began operating offshore Angola in mid-September 2009 and, during the second quarter of 2010, generated revenues of $56.4 million and incurred operating costs of $11.2 million.

South America. Revenues earned by our high-specification floaters operating offshore Brazil in the second quarter of 2010 increased $65.3 million compared to the second quarter of 2009, primarily due to the operation of the Ocean Star ($33.0 million) and the Ocean Courage ($33.6 million), both of which began operating offshore Brazil in the first quarter of 2010.

Contract drilling expense for our operations in Brazil increased $49.9 million during the second quarter of 2010 compared to the same period in 2009, primarily due to the inclusion of normal operating costs for the Ocean Star and the Ocean Courage, including amortized mobilization costs associated with the mobilization of these rigs to Brazil. Operating costs during the second quarter of 2010 also included incremental costs associated with an intermediate survey and shipyard project for the Ocean Alliance and higher maintenance and labor costs for the fleet.

Intermediate Semisubmersibles.


	Three Months Ended
	June 30,				Favorable/
	2010		2009		(Unfavorable)
	(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM	$	32,464	$	46,260	$	(13,796	)
Mexico		14,379		55,951		(41,572	)
Australia/Asia/Middle East		77,064		121,226		(44,162	)
Europe/Africa/Mediterranean		66,548		138,581		(72,033	)
South America		198,639		103,744		94,895

Total Contract Drilling Revenue	$	389,094	$	465,762	$	(76,668	)


CONTRACT DRILLING EXPENSE
GOM	$	15,403	$	9,243	$	(6,160	)
Mexico		5,714		12,286		6,572
Australia/Asia/Middle East		24,752		31,188		6,436
Europe/Africa/Mediterranean		28,789		33,174		4,385
South America		82,788		46,805		(35,983	)

Total Contract Drilling Expense	$	157,446	$	132,696	$	(24,750	)



OPERATING INCOME	$	231,648	$	333,066	$	(101,418	)

GOM. Revenues generated by our intermediate semisubmersible rigs working in the GOM during the second quarter of 2010 decreased $13.8 million compared to the second quarter of 2009, primarily due to the relocation of the Ocean Ambassador to Brazil early in the third quarter of 2009 ($22.3 million) and a decrease in the average operating dayrate earned by the Ocean Saratoga ($5.7 million). The Ocean Voyager, which returned to the GOM from Mexico in the first quarter of 2010, generated revenues of $13.7 million during the second quarter of 2010.

Contract drilling expense in the GOM increased $6.2 million during the second quarter of 2010 compared to the second quarter of 2009, primarily due to the inclusion of normal operating expenses and amortized mobilization costs for the Ocean Voyager ($10.7 million). The increase in contract drilling expense in the second quarter of 2010 was partially offset by the absence of operating costs for the Ocean Ambassador ($4.6 million).

Mexico. Operating revenue and expenses for our Mexico operations decreased $41.6 million and $6.6 million, respectively, in the second quarter of 2010 compared to the second quarter of 2009 primarily due to the completion of the Ocean Voyager’s contract in the first quarter of 2010 and its subsequent relocation to the GOM. In addition, operating revenues for our remaining rig offshore Mexico, the Ocean New Era, decreased $10.9 million due to a

reduction in dayrate earned by the rig after the rig completed its initial contract in the first quarter of 2010 and its contract was extended at a lower operating dayrate.

Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working in the Australia/Asia/Middle East region decreased $44.2 million in the second quarter of 2010 compared to the same period in 2009, primarily due to the stacking of the Ocean Bounty after completing its contract at the beginning of the third quarter of 2009 ($34.3 million). Revenues for our rigs operating offshore Australia for the second quarter of 2010 were further reduced by the effect of 28 days of unpaid incremental downtime, compared to the same quarter in 2009 ($10.1 million).

Contract drilling expense for our rigs operating in the Australia/Asia/Middle East region decreased $6.4 million primarily due to a reduction in operating costs as a result of the stacking of the Ocean Bounty.

Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region decreased $72.0 million in the second quarter of 2010 compared to the same period in 2009. Subsequent to the second quarter of 2009, we relocated the Ocean Lexington to Brazil (in the third quarter of 2009) and the Ocean Guardian to the Falkland Islands (in the first quarter of 2010), which reduced second quarter 2010 revenues by $40.6 million compared to the same quarter of 2009.

Average operating revenue per day and average utilization for our three rigs currently located in the North Sea (both U.K. and Norwegian sectors) decreased to $305,800 and 80%, respectively, for the second quarter of 2010 from $359,200 and 100%, respectively, for the second quarter of 2009, reducing revenues by a combined $31.5 million. The reduction in utilization during the second quarter of 2010 is primarily due to 48 days of unpaid downtime associated with the Ocean Vanguard’s special survey.

Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets decreased $4.4 million in the second quarter of 2010 compared to the second quarter of 2009, primarily due to the relocation of the Ocean Lexington and Ocean Guardian from the region partially offset by an increase in costs associated with the 2010 survey of the Ocean Vanguard.

South America. Revenues generated by our intermediate semisubmersibles working in the South American region increased $94.9 million in the second quarter of 2010 compared to the same period in 2009. We currently have nine intermediate semisubmersible rigs operating in this region, including the Ocean Guardian in the Falkland Islands, compared to six such rigs operating in this region during the second quarter of 2009. The three additional rigs transferred to the region subsequent to the second quarter of 2009 generated revenues of $80.5 million in the second quarter of 2010.

Our six intermediate semisubmersible rigs that operated offshore Brazil during both the 2009 and 2010 periods earned average operating revenue per day of $265,800 during the second quarter of 2010, compared to $213,800 during the second quarter of 2009, and generated $17.7 million in additional revenues. Revenues were partially offset by a decrease in utilization for these rigs from 89% during the second quarter of 2009 to 81% during the second quarter of 2010, which reduced revenues by $3.3 million.

Contract drilling expense in the South American region increased $36.0 million in the second quarter of 2010 compared to the second quarter of 2009 primarily due to incremental costs for the Ocean Ambassador, Ocean Lexington and Ocean Guardian operating in the region in the second quarter of 2010. Operating costs during the second quarter of 2010 were also negatively impacted by incremental costs associated with a special survey of the Ocean Winner and higher maintenance and labor costs for the fleet.

Jack-Ups.


	Three Months Ended
	June 30,				Favorable/
	2010		2009		(Unfavorable)
	(In thousands)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM	$	20,980	$	16,998	$	3,982
Mexico		24,456		23,679		777
Australia/Asia/Middle East		19,220		39,021		(19,801	)
Europe/Africa/Mediterranean		17,143		22,389		(5,246	)
South America		424		21,082		(20,658	)

Total Contract Drilling Revenue	$	82,223	$	123,169	$	(40,946	)


CONTRACT DRILLING EXPENSE
GOM	$	21,062	$	25,368	$	4,306
Mexico		9,003		7,747		(1,256	)
Australia/Asia/Middle East		11,974		12,248		274
Europe/Africa/Mediterranean		6,624		9,377		2,753
South America		256		11,493		11,237

Total Contract Drilling Expense	$	48,919	$	66,233	$	17,314



OPERATING INCOME	$	33,304	$	56,936	$	(23,632	)

GOM. Revenues generated by our jack-up rigs operating in the GOM increased $4.0 million during the second quarter of 2010 compared to the second quarter of 2009. The relocation of two rigs to the GOM subsequent to the second quarter of 2009 (the Ocean Columbia from Mexico and the Ocean Scepter from Argentina) contributed $11.3 million to current period revenues. The Ocean Scepter completed its contract in the GOM in July 2010 and will be returning to the South America region.

Contract drilling revenues in the GOM for the second quarter of 2010, compared to the same period in 2009, were partially reduced due to a decrease in the average operating revenue per day for the Ocean Titan from $130,000 during the second quarter of 2009 to $66,600 during the second quarter of 2010 ($5.4 million) and the 2009 cold-stacking of our three mat-supported jack-up rigs ($3.7 million).

Contract drilling expense for our jack-ups operating in the GOM decreased $4.3 million during the second quarter of 2010 compared to the same period in 2009, primarily due to a reduction in operating costs for our three cold stacked rigs and the absence of contract preparation costs for the Ocean Summit, which we relocated to Mexico following the second quarter of 2009. This overall decrease in costs was partially offset by normal operating and amortized mobilization costs for the Ocean Columbia and Ocean Scepter.

Australia/Asia/Middle East. Revenues generated by our jack-up rigs operating in the Australia/Asia/Middle East region decreased $19.8 million in the second quarter of 2010 compared to the same period in 2009 primarily due to a decrease in the average operating revenue per day from $202,500 during the second quarter of 2009 to $105,600 during the second quarter of 2010.

Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region decreased $5.2 million during the second quarter of 2010 compared to the same period in 2009. The decrease in revenue was primarily due to a decrease in the average operating revenue per day from $107,900 during the second quarter of 2009 to $62,800 during the second quarter of 2010, which reduced revenues by $9.0 million. This decrease was partially offset by an improvement in utilization for the Ocean Heritage which operated the entire second quarter of 2010 compared to only 23 days during the second quarter of 2009.

Contract drilling expense for our rigs operating in the Europe/Africa/Mediterranean region decreased $2.8 million in the second quarter of 2010 compared to the second quarter of 2009 primarily due to the collection of a customer receivable that had previously been reserved.

South America. Contract drilling revenues and expenses decreased during the second quarter of 2010 compared to the same period in 2009. Our only jack-up rig in this 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 $15.3 million to $100.7 million during the second quarter of 2010 compared to $85.4 million during the same period in 2009, primarily due to depreciation associated with capital additions in 2009 and 2010, including depreciation of our two high-specification floaters acquired in 2009, the Ocean Courage and Ocean Valor, which were placed in service in September 2009 and March 2010, respectively.

Interest Expense.

Interest expense for the quarters ended June 30, 2010 and 2009 relates primarily to interest accrued on our outstanding indebtedness and our liabilities for uncertain tax positions. During the second quarter of 2010, interest expense included $7.3 million related to our 5.875% Senior Notes due 2019, or 5.875% Senior Notes, issued in May 2009, compared to only $4.7 in the same period in 2009. During the second quarter of 2010, interest expense also included $7.1 million related to our 5.70% Senior Notes due 2039, or 5.70% Senior Notes, issued in October 2009.

Foreign Currency Transaction Gain (Loss).

Foreign currency transaction gains (losses) fluctuate based on the level of transactions in foreign currencies, as well as fluctuations in such currencies, and also include gains and losses from the settlement of foreign currency forward exchange, or FOREX, contracts not designated as accounting hedges. During the second quarter of 2010, we recognized net foreign currency exchange losses of $4.0 million. During the second quarter of 2009, we recognized net foreign currency exchange gains of $13.7 million, including $8.9 million in net gains on FOREX contracts not designated as accounting hedges.

Income Tax Expense.

Our estimated annual effective tax rate for the three months ended June 30, 2010 was 29.2%, compared to the 25.5% 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 June 30, 2010 reflects applicable tax law as of June 30, 2010 as the pending legislation has not been enacted.

Six Months Ended June 30, 2010 and 2009

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


	Six Months Ended
	June 30,						Favorable/
	2010			2009			(Unfavorable)
	(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters	$	724,175		$	646,661		$	77,514
Intermediate Semisubmersibles		769,795			882,762			(112,967	)
Jack-ups		162,172			249,743			(87,571	)
Other		35			—			35

Total Contract Drilling Revenue	$	1,656,177		$	1,779,166		$	(122,989	)


Revenues Related to Reimbursable Expenses	$	26,107		$	52,961		$	(26,854	)

CONTRACT DRILLING EXPENSE
High-Specification Floaters	$	243,655		$	192,619		$	(51,036	)
Intermediate Semisubmersibles		296,045			263,411			(32,634	)
Jack-ups		101,447			135,151			33,704
Other		12,951			11,419			(1,532	)

Total Contract Drilling Expense	$	654,098		$	602,600		$	(51,498	)


Reimbursable Expenses	$	25,084		$	52,146		$	27,062

OPERATING INCOME
High-Specification Floaters	$	480,520		$	454,042		$	26,478
Intermediate Semisubmersibles		473,750			619,351			(145,601	)
Jack-ups		60,725			114,592			(53,867	)
Other		(12,916	)		(11,419	)		(1,497	)
Reimbursable expenses, net		1,023			815			208
Depreciation		(198,148	)		(170,493	)		(27,655	)
General and administrative expense		(33,503	)		(32,481	)		(1,022	)
Gain on disposition of assets		1,033			148			885

Total Operating Income	$	772,484		$	974,555		$	(202,071	)


Other income (expense):
Interest income		1,759			1,766			(7	)
Interest expense		(43,654	)		(12,405	)		(31,249	)
Foreign currency transaction gain		(3,530	)		9,608			(13,138	)
Other, net		(121	)		651			(772	)

Income before income tax expense		726,938			974,175			(247,237	)
Income tax expense		(211,692	)		(238,154	)		26,462

NET INCOME	$	515,246		$	736,021		$	(220,775	)

Throughout the first half of 2010, the weak global economy continued to impact our industry despite an improvement in oil prices from the first half of the prior year. While our contracted revenue backlog enabled us to partially mitigate the impact of the weak market conditions, our operating income decreased 21%, or $202.1 million, compared to the first half of 2009. Contract drilling revenues for the first half of 2010 decreased $123.0 million, or 7%, compared to the first half of 2009, and average utilization for our overall fleet decreased from 81% during the first half of 2009 to 79% during the first half of 2010. Revenues generated by our intermediate semisubmersible and jack-up rigs decreased $200.5 million, primarily due to a reduction in utilization for our intermediate semisubmersible rigs and a decrease in operating dayrates for our jack-up rigs compared to the same period in 2009. The decrease in overall revenues was partially offset by $48.9 million in revenues earned by the Ocean Courage, which we purchased in June 2009.

Total contract drilling expense increased $51.5 million, or 9%, during the first half of 2010 compared to the same period in 2009, primarily due to higher amortized mobilization expenses and higher overall operating expenses due to more of our rigs operating internationally, where the operating cost structure is generally higher than that of the GOM, and also due to the inclusion of normal operating costs for the Ocean Courage which began operating early in the first quarter of 2010.

Depreciation expense increased $27.7 million to $198.1 million during the first half of 2010, or 16% compared to the first half of 2009, due to a higher depreciable asset base, primarily due to the 2009 acquisitions of the Ocean Courage and Ocean Valor.

High-Specification Floaters.


	Six Months Ended
	June 30,				Favorable/
	2010		2009		(Unfavorable)
	(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM	$	314,797	$	492,531	$	(177,734	)
Australia/Asia/Middle East		86,259		73,648		12,611
Europe/Africa/Mediterranean		112,707		—		112,707
South America		210,412		80,482		129,930

Total Contract Drilling Revenue	$	724,175	$	646,661	$	77,514


CONTRACT DRILLING EXPENSE
GOM	$	81,144	$	134,031	$	52,887
Australia/Asia/Middle East		21,610		15,751		(5,859	)
Europe/Africa/Mediterranean		22,233		—		(22,233	)
South America		118,668		42,837		(75,831	)

Total Contract Drilling Expense	$	243,655	$	192,619	$	(51,036	)



OPERATING INCOME	$	480,520	$	454,042	$	26,478

GOM. Revenues generated by our high-specification floaters operating in the GOM decreased $177.7 million during the first half of 2010 compared to the same period in 2009, primarily due to the relocation of five of our high-specification rigs to international markets. Since early 2009, we have relocated the Ocean Quest (late in the first quarter of 2009), the Ocean Star (early in the first quarter of 2010) and the Ocean Baroness (in May 2010) to Brazil, the Ocean Valiant to offshore Angola (early in the third quarter of 2009) and the Ocean America to offshore Australia (late in the first quarter of 2010). The effect of these rigs exiting the GOM was a net $196.1 million reduction in revenues for the first six months of 2010 compared to the first six months of 2009.

Our remaining high-specification floater fleet in the GOM operated an additional 89 days in the first half of 2010 compared to the same period in 2009, primarily due to the return to service of the upgraded Ocean Monarch in the second quarter of 2009, and resulted in the generation of $38.3 million in additional revenues in 2010. Average operating revenue per day for these rigs decreased from $413,400 during the first six months of 2009 to $386,200 for the comparable period in 2010 and resulted in a $20.0 million reduction in revenues in the first half of 2010.

Total contract drilling expense during the first half of 2010 for our high-specification floaters in the GOM decreased $52.9 million compared to the same period in 2009, primarily due to a reduction in normal operating costs for the five rigs transferred out of the GOM ($62.0 million). The net decrease in operating costs comparing the periods was partially offset by an increase in operating costs for the Ocean Monarch due to its full utilization during the first six months of 2010 and survey and repair costs for the Ocean Confidence.

Australia/Asia/Middle East. During the first half of 2010, our revenues from our high-specification rigs operating in the Australia/Asia/Middle East region increased $12.6 million compared to the first half of 2009. Our rig operating offshore Malaysia, the Ocean Rover, generated $7.1 million in additional revenues primarily due to an increase in the average operating revenue per day from $416,100 during the first six months of 2009 to $451,100 during the first six months of 2010. In addition, the Ocean America generated $5.5 million in additional revenues offshore Australia following its relocation from the GOM during the first quarter of 2010.

Contract drilling expense for our operations in the Australia/Asia/Middle East region increased $5.9 million in the first half of 2010 compared to the first half of 2009 primarily due to the inclusion of normal operating and contract preparation costs for the Ocean America and higher labor, inspection and shore base support costs for the Ocean Rover.

Europe/Africa/Mediterranean. The Ocean Valiant began operating offshore Angola in mid-September 2009 and generated revenues of $112.7 million and incurred normal operating costs of $22.1 million during the first half of 2010.

South America. Revenues earned by our high-specification floaters operating offshore Brazil in the first half of 2010 increased $129.9 million compared to the first half of 2009. The increase in revenue was primarily due to the relocation of the Ocean Quest ($44.6 million) and the Ocean Star ($50.9 million) from the GOM and the Ocean Courage which began operations late in the first quarter of 2010 ($48.9 million). During the first half of 2010 the Ocean Alliance spent 121 days in a shipyard for an intermediate survey and shipyard projects which resulted in a $19.0 million reduction in current year revenues.

Contract drilling expense for our operations in Brazil increased $75.8 million during the first half of 2010 compared to the same period in 2009, primarily due to the additional rigs operating in the region in the first half of 2010 and additional survey and shipyard costs for the Ocean Alliance.

Intermediate Semisubmersibles.


	Six Months Ended
	June 30,				Favorable/
	2010		2009		(Unfavorable)
	(In thousands)
INTERMEDIATE SEMISUBMERSIBLES:
CONTRACT DRILLING REVENUE
GOM	$	52,016	$	97,560	$	(45,544	)
Mexico		38,131		109,881		(71,750	)
Australia/Asia/Middle East		162,092		237,578		(75,486	)
Europe/Africa/Mediterranean		133,085		262,747		(129,662	)
South America		384,471		174,996		209,475

Total Contract Drilling Revenue	$	769,795	$	882,762	$	(112,967	)


CONTRACT DRILLING EXPENSE
GOM	$	21,831	$	21,453	$	(378	)
Mexico		16,566		23,250		6,684
Australia/Asia/Middle East		49,576		57,391		7,815
Europe/Africa/Mediterranean		51,210		65,692		14,482
South America		156,862		95,625		(61,237	)

Total Contract Drilling Expense	$	296,045	$	263,411	$	(32,634	)



OPERATING INCOME	$	473,750	$	619,351	$	(145,601	)

GOM. Revenues generated from our rigs operating in the GOM during the first half of 2010 decreased $45.5 million primarily due to the relocation of the Ocean Ambassador to Brazil early in the second half of 2009 ($47.9 million) and a decrease in the average operating dayrate earned by the Ocean Saratoga from $276,200 during the first six months of 2009 to $206,600 during the first six months of 2010 ($12.8 million). The Ocean Voyager returned to the GOM from Mexico early in the first half of 2010 and generated revenues of $14.6 million.

Mexico. Contract drilling revenue from our Mexico operations decreased $71.8 million in the first six months of 2010 compared to the same period in 2009, primarily due to the completion of the Ocean Voyager’s contract early in the first half of 2010 ($56.5 million). In addition, the Ocean New Era earned an average operating dayrate of $265,000 in the first half of 2009 compared to $200,800 in the first half of 2010, further reducing revenues by $10.3 million. The Ocean New Era is currently our only semisubmersible rig operating offshore Mexico.

Contract drilling expense in Mexico decreased by $6.7 million in the first half of 2010 compared to the first half of 2009 primarily due to the relocation of the Ocean Voyager to the GOM.

Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working in the Australia/Asia/Middle East region decreased $75.5 million in the first half of 2010 compared to the same period in 2009 primarily due to the stacking the Ocean Bounty after completion of its contract at the beginning of the second half of 2009 ($64.8 million). Additionally, revenues were reduced by $9.6 million as a result of approximately 29

days of unpaid incremental downtime for our rigs operating in this region during the first half of 2010 compared to the same period a year earlier.

Contract drilling expense for our rigs operating in the Australia/Asia/Middle East region decreased $7.8 million in the first half of 2010 compared to the first half of 2009 primarily due to the stacking of the Ocean Bounty, partially offset by higher labor, maintenance, inspection and shore-base support costs for the Ocean Epoch and Ocean General in the current year.

Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working in the Europe/Africa/Mediterranean region decreased $129.7 million in the first half of 2010 compared to the same period in 2009. Subsequent to June 30, 2009, we relocated the Ocean Lexington to Brazil and the Ocean Guardian to the Falkland Islands, which reduced revenues earned in the region during the first six months of 2010 by $72.3 million. Revenues for our three rigs currently operating in the U.K. and Norwegian sectors of the North Sea declined $57.4 million in the first half of 2010 compared to the first half of 2009, primarily due to a decline in average operating revenue per day from $341,300 in the first half of 2009 to $334,700 for the same period in 2010 combined with a reduction in average utilization from 98% in the first half of 2009 to 73% in the first half of 2010. The lower utilization in the first six months of 2010 reflects 48 days of downtime for a special survey on the Ocean Vanguard as well as unplanned downtime for the Ocean Nomad due to the early termination of a contract.

Contract drilling expense for our intermediate semisubmersible rigs operating in the Europe/Africa/Mediterranean markets decreased $14.5 million in the first half of 2010 compared to the first half of 2009, primarily due to the relocation of the Ocean Lexington and Ocean Guardian to the South America region, partially offset by incremental costs associated with the survey of the Ocean Vanguard.

South America. Revenues generated by our intermediate semisubmersibles working in the South America region increased $209.5 million in the first half of 2010 compared to the first half of 2009. We currently have nine rigs operating in this region, including the Ocean Guardian in the Falkland Islands, compared to six rigs operating in this region during the first half of 2009. The three additional rigs transferred into the region subsequent to June 30, 2009 generated $136.8 million during the first half of 2010.

Average operating revenue per day for our other intermediate semisubmersible rigs that operated offshore Brazil during both the 2009 and 2010 periods increased from $197,000 during the first half of 2009 to $247,900 during the first half of 2010 and generated $39.2 million in additional revenues. Utilization for these rigs also increased from 80% during the first half of 2009 to 89% during the first half of 2010 and generated $33.1 million in additional revenues during the current year period.

Contract drilling expense in the South America region increased $61.2 million in the first half of 2010 compared to the first half of 2009, primarily due to the inclusion of normal operating costs for the three additional rigs in the region. Costs associated with a special survey of the Ocean Winner and higher operating costs for our other rigs offshore Brazil also contributed to the increase in contract drilling expenses during the current year.

Jack-Ups.


	Six Months Ended
	June 30,				Favorable/
	2010		2009		(Unfavorable)
	(In thousands)
JACK-UPS:
CONTRACT DRILLING REVENUE
GOM	$	34,612	$	47,127	$	(12,515	)
Mexico		43,188		50,397		(7,209	)
Australia/Asia/Middle East		53,041		62,232		(9,191	)
Europe/Africa/Mediterranean		30,891		48,055		(17,164	)
South America		440		41,932		(41,492	)

Total Contract Drilling Revenue	$	162,172	$	249,743	$	(87,571	)


CONTRACT DRILLING EXPENSE
GOM	$	41,179	$	50,325	$	9,146
Mexico		20,046		15,806		(4,240	)
Australia/Asia/Middle East		23,736		26,280		2,544
Europe/Africa/Mediterranean		15,026		20,051		5,025
South America		1,460		22,689		21,229

Total Contract Drilling Expense	$	101,447	$	135,151	$	33,704



OPERATING INCOME	$	60,725	$	114,592	$	(53,867	)

GOM. During the first half of 2009, we had six jack-up rigs operating in the GOM. In June 2009, we cold stacked our three mat-supported jack-up rigs and the Ocean Summit was in a GOM shipyard preparing for its relocation to the Mexican Gulf of Mexico, or Mexican GOM; these rigs generated revenues of $22.3 million during the first half of 2009. In early 2010, the Ocean Scepter relocated from Argentina and the Ocean Columbia relocated from Mexico, joined our GOM jack-up fleet and generated $16.5 million in revenues during the first half of 2010. Revenues for our remaining GOM jack-up fleet decreased an aggregate $6.8 million in the first half of 2010 compared to the first half of 2009 as a result of lower dayrates earned and 92 days of combined, incremental downtime in the 2010 period.

Contract drilling expense for our jack-ups operating in the GOM decreased $9.1 million during the first half of 2010 compared to the same period in 2009, primarily due to a reduction in operating costs for our three cold stacked rigs and the absence of contract preparation costs for the Ocean Summit prior to its departure to the Mexican GOM in the second half of 2009. This overall decrease in costs was partially offset by normal operating and amortized mobilization costs for the Ocean Columbia and Ocean Scepter, as well as incremental survey and repair costs for the Ocean Titan during the first six months of 2010.

Mexico. Revenues generated by our jack-up rigs operating offshore Mexico during the first half of 2010 decreased $7.2 million compared to the same period in 2009, primarily due to a decrease in average operating revenue per day from $142,400 during the first half of 2009 to $138,200 during the first half of 2010 ($2.7 million). In addition, average utilization decreased during the first half of 2010, primarily due to unpaid downtime for an intermediate survey of the Ocean Nugget, and resulted in a $4.2 million reduction in revenues for the 2010 period.

Contract drilling expense for our jack-up rigs operating offshore Mexico increased $4.2 million during the first half of 2010 compared to the first half of 2009 primarily due to the inclusion of amortized mobilization expenses for, and other costs associated with customer acceptance of, the Ocean Summit in the 2010 period.

Australia/Asia/Middle East. Revenues generated by our jack-up rigs operating in the Australia/Asia/Middle East region decreased $9.2 million in the first half of 2010 compared to the same period in 2009, primarily due to a decrease in the average operating revenue per day from $226,300 during the first half of 2009 to $146,500 during the first half of 2010 ($21.1 million). Revenues for the first six months of 2010 were also negatively impacted by a reduction in amortized mobilization revenue of $3.7 million compared to the same period in 2009. Utilization for the first half of 2010 improved to 100% compared to 76% during the first half of 2009 and generated $15.6 million in additional revenues during 2010.

Contract drilling expense for our rigs operating in the Australia/Asia/Middle East region decreased $2.5 million during the first six months of 2010 compared to the first six months of 2009 primarily due to the absence of costs associated with the 2009 survey of the Ocean Sovereign.

Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the Europe/Africa/Mediterranean region decreased $17.2 million during the first half of 2010 compared to the same period in 2009. The decrease in revenue was primarily due to a reduction in average operating revenue per day from $114,900 during the first half of 2009 to $61,700 during the first half of 2010 ($23.1 million), partially offset by improved utilization for the Ocean Heritage during the first half of 2010 compared to the same period in 2009 ($6.5 million).

Contract drilling expense for our rigs operating in the Europe/Africa/Mediterranean region decreased $5.0 million in the first half of 2010 compared to the first half of 2009 primarily due to the collection of a customer receivable that had previously been written off.

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

Depreciation.

Depreciation expense increased $27.7 million to $198.1 million during the first six months of 2010 compared to $170.5 million for the same period in 2009, primarily due to depreciation associated with capital additions in 2009 and 2010, including depreciation of our two high-specification floaters acquired in 2009, the Ocean Courage and Ocean Valor, which were placed in service in September 2009 and March 2010, respectively.

Interest Expense.

Interest expense for the six months ended June 30, 2010 and 2009 relates primarily to interest accrued on our outstanding indebtedness and our liabilities for uncertain tax positions. During the first six months of 2010, interest expense included $14.7 million related to our 5.875% Senior Notes compared to only $4.7 million for the same period in 2009. During the first half of 2010, interest expense also included $14.2 million related to our 5.70% Senior Notes issued in October 2009. During the first half 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.

Foreign Currency Transaction Gain (Loss).

Foreign currency transaction gains (losses) fluctuate based on the level of transactions in foreign currencies, as well as fluctuations in such currencies, and also include gains and losses from the settlement of FOREX contracts not designated as accounting hedges. During the first half of 2010, we recognized net foreign currency exchange losses of $3.5 million. During the first half of 2009, we recognized net foreign currency exchange gains of $9.6 million, including $8.8 million in net gains on FOREX contracts.

Income Tax Expense.

Our estimated annual effective tax rate for the six months ended June 30, 2010 was 29.2%, compared to 25.5% for the same period in 2009. The higher effective tax rate in the current period 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 six months ended June 30, 2010 reflects applicable tax law as of June 30, 2010 as the pending legislation has not been enacted.

On March 31, 2009, the statute of limitations relative to a 2003 uncertain tax position in Mexico expired. As a consequence, in March 2009, we reversed $5.5 million of previously accrued interest expense and $5.9 million of previously accrued tax expense. There was no comparable accrual reversal in the six months ended June 30, 2010.

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 June 30, 2010, we had $525.1 million in “Cash and cash equivalents” and $250.7 million in “Investments and marketable securities,” representing our investment of cash available for current operations.

Cash Flows from Operations. Our cash flows from operations are impacted by the ability of our customers to weather instability in the U.S. and global economies 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. As of June 30, 2010 we had drilled four wells for this customer and were owed $94.5 million payable through the NPI. We received our first payment from the conveyance of the NPI in July 2010. Further payment of amounts owed to us through the NPI, and the timing of such payments, is contingent upon production from the properties subject to the NPI and upon energy sale prices.

Based on current production payout estimates, we expect to collect $37.2 million of the receivable within the next twelve months. We currently anticipate that the remaining $57.3 million of the receivable will be repaid following the next twelve months.

These external factors which affect our cash flows from operations, many of which are not within our control, are difficult to predict. For a description of other factors that could affect our cash flows from operations, including the impact of the offshore drilling moratorium, see “— Overview — Industry Conditions,” “— Overview — General,” “ — Forward-Looking Statements,” and “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009 and Item 1A of Part II, “Risk Factors,” in this report.

$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 June 30, 2010, the applicable margin on LIBOR loans would have been .24%. As of June 30, 2010, there were no loans outstanding under the Credit Facility; however, $23.9 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. We may also make use of our Credit Facility to finance capital expenditures or for other general corporate purposes.

Contractual Cash Obligations.

At June 30, 2010, we had FOREX contracts outstanding in the aggregate notional amount of $118.7 million. 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 June 30, 2010, the total unrecognized tax benefit related to uncertain tax positions was $34.8 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 June 30, 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 June 30, 2010 in the amount of $136.4 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $23.9 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 June 30, 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 December 31,
	Total		2010		2011		Thereafter
	(In thousands)
Other Commercial Commitments
Customs bonds	$	5,058	$	5,050	$	8	$	—
Performance bonds		100,604		49,002		35,310		16,292
Other		30,772		30,022		750		—

Total obligations	$	136,434	$	84,074	$	36,068	$	16,292

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 $485 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 $70 million in 2010 towards the commissioning and outfitting for service of the recently acquired Ocean Courage and Ocean Valor. During the first six months of 2010, we spent approximately $221.9 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 June 30, 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 six months ended June 30, 2010 compared to the six months ended June 30, 2009.

Net Cash Provided by Operating Activities.


	Six Months Ended June 30,
	2010			2009			Change
	(In thousands)
Net income	$	515,246		$	736,021		$	(220,775	)
Net changes in operating assets and liabilities		(51,896	)		(286,644	)		234,748
Proceeds from settlement of FOREX contracts designated as accounting hedges		457			—			457
(Gain) on sale and disposition of assets		(1,033	)		(148	)		(885	)
(Gain) loss on sale of marketable securities		2			(599	)		601
(Gain) on FOREX contracts		(457	)		(8,837	)		8,380
Deferred tax provision		11,921			37,910			(25,989	)
Depreciation and other non-cash items, net		220,065			227,695			(7,630	)

	$	694,305		$	705,398		$	(11,093	)

Our cash flows from operations during the first six months of 2010 decreased $11.1 million compared to the same period in 2009. This decrease is primarily due to lower earnings resulting from an aggregate reduction in average utilization of and dayrates earned by our fleet and increased mobilization costs, offset by a decrease in net cash required to satisfy working capital requirements in 2010 compared to 2009.

We used $234.7 million less to satisfy our working capital needs during the first half of 2010 compared to the first half of 2009. Trade and other receivables generated cash of $109.1 million during the first six months of 2010 compared to using cash of $166.5 million during the comparable period of 2009. During the first six months of 2010, we made estimated U.S. federal income tax payments and paid foreign income taxes, net of refunds, of $254.5 million and $76.2 million, respectively. During the first six months of 2009, we made estimated U.S. federal income tax payments and paid foreign income taxes, net of refunds, of $140.0 million and $106.1 million, respectively.

Net Cash Used in Investing Activities.


	Six Months Ended June 30,
	2010			2009			Change
	(In thousands)
Purchase of marketable securities	$	(2,399,760	)	$	(2,998,780	)	$	599,020
Proceeds from sale of marketable securities		2,550,088			3,198,829			(648,741	)
Capital expenditures (including rig acquisition)		(221,890	)		(686,284	)		464,394
Proceeds from disposition of assets		1,258			453			805
Deposits received on sale of rig		18,600			6,000			12,600
Cost to settle FOREX contracts not designated as accounting hedges		—			(28,862	)		28,862

	$	(51,704	)	$	(508,644	)	$	456,940

Our investing activities used $51.7 million during the first six months of 2010 compared to $508.6 million during the comparable period of 2009. During the first half of 2010, we sold marketable securities, net of purchases, of $150.3 million compared to net sales of $200.0 million during the first half of 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.

We spent approximately $221.9 million related to ongoing capital maintenance programs, including rig modifications to meet contractual requirements, during the first six months of 2010 compared to $226.3 million during the same period in 2009. Additionally, in June 2009, we purchased the Ocean Courage, a newbuild, dynamically positioned, semisubmersible drilling rig, for $460.0 million.

During the first six months of 2010, we received an $18.6 million deposit in connection with the sale of the Ocean Shield, which was completed in July 2010 for a total selling price of $186.0 million. During the first six months of 2009, we received $6.0 million in deposits in connection with the sale of the Ocean Tower, which was completed in the third quarter of 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 half 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 $28.9 million for the first half of 2009. We have presented the settlement of these contracts within “Net Cash Used in Investing Activities.”

Net Cash Used in Financing Activities.


	Six Months Ended June 30,
	2010			2009			Change
	(In thousands)
Redemption of zero coupon debentures	$	(4,238	)	$	—		$	(4,238	)
Issuance of 5.875% Senior Notes, net of issuance costs		—			495,503			(495,503	)
Payment of dividends		(489,670	)		(558,036	)		68,366
Proceeds from stock options exercised		107			155			(48	)
Other		(98	)		—			(98	)

	$	(493,899	)	$	(62,378	)	$	(431,521	)

During the first six months of 2010, we paid cash dividends totaling $489.7 million, consisting of aggregate regular cash dividends totaling $34.8 million, or $0.125 per share of our common stock per quarter, and aggregate special cash dividends totaling $454.9 million, or $1.875 and $1.375 per share of our common stock in the first quarter and the second quarter of 2010, respectively. During the first six months of 2009, we paid cash dividends totaling $558.0 million, consisting of aggregate regular cash dividends totaling $34.7 million, or $0.125 per share of our common stock per quarter, and aggregate special cash dividends totaling $523.3 million, or $1.875 per share of our common stock per quarter.

On July 21, 2010, we declared a regular cash dividend and a special cash dividend of 0.125 and $0.75, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on September 1, 2010 to stockholders of record on August 2, 2010.

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

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not repurchase any shares of our outstanding common stock during the six months ended June 30, 2010 or 2009.

Forward-Looking Statements

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

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

	•		future uses of and requirements for financial resources;

	•		interest rate and foreign exchange risk;

	•		future contractual obligations;

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

	•		effects of the Macondo well blowout, including, without limitation, the moratorium and suspension of drilling in the U.S. Gulf of Mexico and related regulations and market developments;

	•		business strategy;

	•		growth opportunities;

	•		competitive position;

	•		expected financial position;

	•		future cash flows and contract backlog;

	•		future regular or special dividends;

	•		financing plans;

	•		market outlook;

	•		tax planning;

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

	•		budgets for capital and other expenditures;

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

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

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

	•		plans and objectives of management;

	•		idling drilling rigs or reactivating stacked rigs;

	•		performance of contracts;

	•		outcomes of legal proceedings;

	•		compliance with applicable laws; and

	•		adequacy of insurance or indemnification.

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

	•		those described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2009 and in Item 1A of Part II of this report;

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

	•		worldwide demand for oil and natural gas;

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

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

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

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

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

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

	•		advances in exploration and development technology;

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

	•		casualty losses;

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

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

	•		industry fleet capacity;

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

	•		competition;

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

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

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

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

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

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

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

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

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

	•		compliance with environmental laws and regulations;

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

	•		development and exploitation of alternative fuels;

	•		customer preferences;

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

	•		cost, availability and adequacy of insurance;

	•		the results of financing efforts;

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

	•		adequacy of our sources of liquidity;

	•		risks resulting from our indebtedness;

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

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

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

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

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at June 30, 2010 and December 31, 2009, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

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

Interest Rate Risk

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

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on June 30, 2010 and December 31, 2009, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.

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

Loans under our $285 million syndicated, senior unsecured revolving Credit Facility bear interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) LIBOR plus an applicable margin, varying from 0.20% to 0.525%, based on our current credit ratings. As of June 30, 2010 and December 31, 2009, there were no loans outstanding under the Credit Facility (however, $23.9 million and $63.3 million in letters of credit were issued and outstanding under the Credit Facility at June 30, 2010 and December 31, 2009, respectively).

Our long-term debt, as of June 30, 2010 and December 31, 2009, is denominated in U.S. dollars. Our debt has been primarily issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $109.6 million and $121.3 million as of June 30, 2010 and December 31, 2009, respectively. A 100-basis point decrease would result in an increase in market value of $126.3 million and $136.2 million as of June 30, 2010 and December 31, 2009, respectively.

Foreign Exchange Risk

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

of business. These contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for certain contracts is the average spot rate for the contract period. As of June 30, 2010 we had FOREX contracts outstanding in the aggregate notional amount of $118.7 million, consisting of $46.4 million in Australian dollars, $38.1 million in Brazilian reais, $21.8 million in British pounds sterling, $5.2 million in Mexican pesos and $7.2 million in Norwegian kroner. These contracts settle at various times through November 2010.

At June 30, 2010, we have presented the fair value of our outstanding FOREX contracts as a current asset of $0.4 million in “Prepaid expenses and other current assets” and a current liability of $4.2 million in “Accrued liabilities” in our Consolidated Balance Sheets.

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

Fair Value Asset (Liability)

Market Risk

June 30,

December 31,

June 30,

December 31,

2010

2009

2010

2009

(In thousands)

Interest rate:

Marketable securities

250,700

(a)

400,900

(a)

(200

) (c)

(300

) (c)

Long-term debt

(1,493,000

) (b)

(1,546,900

) (b)

—

Foreign Exchange:

FOREX contracts — asset positions

400

(d)

2,600

(d)

(5,400

) (e)

(17,600

) (e)

FOREX contracts — liability positions

(4,200

) (d)

(200

) (d)

(15,900

) (e)

(3,700

) (e)


(a)		The fair market value of our investment in marketable securities is based on the quoted closing market prices on June 30, 2010 and December 31, 2009.

(b)		The fair values of our 4.875% Senior Notes due July 1, 2015, 5.15% Senior Notes due September 1, 2014, 5.875% Senior Notes due May 1, 2019 and 5.70% Senior Notes due October 15, 2039 are based on quoted market prices.

(c)		The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at June 30, 2010 and December 31, 2009.

(d)		The fair value of our FOREX contracts is based on both quoted market prices and valuations derived from pricing models on June 30, 2010 and December 31, 2009.

(e)		The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their values at June 30, 2010 and December 31, 2009, with all other variables held constant.

ITEM 4. Controls and Procedures.

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

Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2010. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2010.

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our second fiscal quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1A. Risk Factors.

Our Annual Report on Form 10-K for the year ended December 31, 2009 includes a detailed discussion of certain material risk factors facing our company. The information presented below describes updates and additions to such risk factors and should be read in conjunction with the risk factors and information disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009.

The risk factor in our Annual Report on Form 10-K for the year ended December 31, 2009 captioned “Our business involves numerous operating hazards, and we are not fully insured against all of them.” is amended and restated in its entirety as follows:

“Our business involves numerous operating hazards which could expose us to significant losses and significant damage claims. We are not fully insured against all of these risks and our contractual indemnity provisions may not fully protect us.

Our operations are subject to the significant hazards inherent in drilling for oil and gas offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any of these types of events could result in the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death to rig personnel, damage to producing or potentially productive oil and gas formations, and oil spillage, oil leaks, well blowouts and extensive uncontrolled fires, any of which could cause significant environmental damage. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. Any of the foregoing events could result in significant damage or loss to our properties and assets, significant loss of revenues, and significant damage claims against us, which could have a material adverse effect on our results of operations, financial condition and cash flows.

We maintain liability insurance, which includes coverage for environmental damage; however, because of contractual provisions and policy limits, our insurance coverage may not adequately cover our losses and claim costs. In addition, pollution and environmental risks are generally not fully insurable when they are determined to be the result of criminal acts. Also, we do not typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work. Accordingly, it is possible that our losses from the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.

Operations also may be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages.

Generally our contracts with our customers contain contractual rights to indemnity from our customer for, among other things, pollution originating from the well, while we retain responsibility for pollution originating from the rig. However, our contractual rights to indemnification may be unenforceable or limited due to negligent or willful acts of commission or omission by us, our subcontractors and/or suppliers and our customers may dispute, or be unable to meet, their contractual indemnification obligations to us.

We believe that the policy limit under our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. However, if an accident or other event occurs that exceeds our coverage limits or is not an insurable event under our insurance policies, or is not fully covered by contractual indemnity, it could have a material adverse effect on our results of operations, financial position and cash flows. There can be no assurance that we will continue to carry the insurance we currently maintain, that our insurance will cover all types of losses or that those parties with contractual obligations to indemnify us will necessarily be financially able to indemnify us against all of these risks. In addition, no assurance can be made that we will be able to maintain adequate insurance in the future at rates we consider to be reasonable or that we will be able to obtain insurance against some risks.

Accordingly, the occurrence of any of the hazards we face could have a material adverse effect on our results of operations, financial condition and cash flows.”

The risk factor in our Annual Report on Form 10-K for the year ended December 31, 2009 captioned “Governmental laws and regulations may add to our costs or limit our drilling activity.” is amended and restated in its entirety as follows:

“Governmental laws and regulations, both domestic and international, may add to our costs or limit our drilling activity.

Our operations are affected from time to time in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally. We may be required to make significant capital expenditures to comply with governmental laws and regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or may significantly limit drilling activity.

Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas industries. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities.

As awareness of climate change issues increases, governments around the world are beginning to address the matter. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws or regulations pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations encouraging or mandating the use of alternative energy sources, such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. In addition, new laws or regulations may require an increase in our capital spending for additional equipment to comply with such requirements and could also result in a reduction in revenues associated with downtime required to install such equipment.”

The risk factor in our Annual Report on Form 10-K for the year ended December 31, 2009 captioned “We are controlled by a single stockholder, which could result in potential conflicts of interest.” is amended and restated in its entirety as follows:

“We are controlled by a single stockholder, which could result in potential conflicts of interest.

Loews Corporation, which we refer to as Loews, beneficially owned approximately 50.4% of our outstanding shares of common stock as of July 22, 2010 and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. One of those, James S. Tisch, the Chairman of the Board of our company, is also the Chief Executive Officer and a director of Loews. We have also entered into a services agreement and a registration rights agreement with Loews and we may in the future enter into other agreements with Loews.

Loews is a holding company. In addition to us, its principal subsidiaries are CNA Financial Corporation, a 90% owned subsidiary engaged in commercial property and casualty insurance; HighMount Exploration & Production LLC, a wholly owned subsidiary engaged in exploration, production and marketing of natural gas and natural gas liquids; Boardwalk Pipeline Partners, LP, a 66% owned subsidiary engaged in the operation of interstate natural gas transmission pipeline systems; and Loews Hotels Holding Corporation, a wholly owned subsidiary engaged in the operation of hotels. Loews and its subsidiaries and we are generally engaged in businesses sufficiently different from each other as to make conflicts as to possible corporate opportunities unlikely. However, it is possible that Loews may in some circumstances be in direct or indirect competition with us, including competition with respect to certain business strategies and transactions that we may propose to undertake. In addition, potential conflicts of interest exist or could arise in the future for our directors who are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations. We cannot assure you that these conflicts of interest will not materially adversely affect us.”

The following new risk factors are added:

“The moratorium on offshore drilling in the U.S. Gulf of Mexico and new regulations adopted as a result of the investigation into the Macondo well blowout could negatively impact us.

On May 30, 2010, following the April 20, 2010 blowout of the Macondo well being drilling by BP plc in the U.S. Gulf of Mexico, or GOM, the U.S. government imposed a six-month moratorium on certain drilling activities in water deeper than 500 feet in the GOM and implemented enhanced safety requirements applicable to all drilling activity in the GOM, including drilling activities in water shallower than 500 feet. On June 22, 2010, the U.S. District Court for the Eastern District of Louisiana granted a temporary injunction which immediately prohibited enforcement of the moratorium, which was subsequently upheld by the Fifth Circuit Court of Appeals in New Orleans. The U.S. Department of the Interior, or DOI, issued a second drilling moratorium on July 12, 2010 suspending drilling operations on the basis of drilling configurations and technologies regardless of water depth.

In conjunction with the drilling moratorium imposed on May 30, 2010, the DOI issued a new set of recommendations in a 30-Day Safety Alert for offshore energy companies, which provided for, among other things, the recertification of all blowout preventers, enhanced well control practices, blowout prevention and intervention procedures, more rigorous inspections for deepwater drilling operations and expanded safety and training programs for rig workers. These recommendations are being implemented in the form of new regulations by the Bureau of Ocean Energy Management, Regulation and Enforcement (formerly known as the Minerals Management Service) under direction of the DOI and are being communicated by means of Notices to Lessees, or NTLs. At the date of this report, we have received two NTLs and a safety alert from the U.S. Coast Guard. We have complied with the terms of the safety alert and, at the date of this report, are in the process complying with one of the two NTLs issued thus far. We believe that the second NTL applies to the lease operator and not the drilling contractor.

The drilling moratorium could result in a number of rigs being, or becoming available to be, moved to locations outside of the GOM, which could potentially put downward pressure on global dayrates and adversely affect our ability to contract our floating rigs that are currently uncontracted or coming off contract. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations, and escalating costs borne by our customers, along with permitting delays, could reduce exploration and development activity in the GOM and therefore demand for our services. In addition, insurance costs across the industry are expected to increase as a result of the Macondo well blowout, and in the future certain insurance coverage is likely to become more costly, and may become less available or not available at all.

We cannot predict the ultimate duration of the latest drilling moratorium or the potential impact of new regulations that may be adopted relating to the investigation into the Macondo well blowout. The inability to redeploy our rigs impacted by the drilling moratorium, or to obtain dayrates sufficient to cover our additional operating expenses and mobilization costs if such impacted rigs are redeployed in international waters, could adversely affect our financial position, results of operations and cash flows. In addition, implementation of additional regulations may subject us to increased costs of operating and/or a reduction in the area of operation in the GOM.

We may be adversely affected by negative publicity.

Press coverage and other public statements that assert some form of wrongful act or omission by us, regardless of the factual basis for the assertions being made, may result in negative publicity or investigation by regulators. Responding to such negative publicity or such an investigation, regardless of the ultimate outcome, is time consuming and costly and can divert the time and attention of our senior management from our business. Adverse publicity can also have a negative impact on our reputation and on the morale and performance of our employees, all of which could adversely affect our business and results of operations.”

ITEM 6. Exhibits.

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

SIGNATURES

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


	DIAMOND OFFSHORE DRILLING, INC. (Registrant)
Date July 29, 2010	By:	\s\ Gary T. Krenek
		Gary T. Krenek
		Senior Vice President and Chief Financial Officer

Date July 29, 2010		\s\ Beth G. Gordon
		Beth G. Gordon
		Controller (Chief Accounting Officer)

EXHIBIT INDEX


Exhibit No.		Description

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

	3.2	Amended and Restated By-Laws (as amended through October 22, 2007) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 26, 2007).

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

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

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

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema Document.

101.CAL**		XBRL Taxonomy Calculation Linkbase Document

101.LAB**		XBRL Label Linkbase Document.

101.PRE**		XBRL Presentation Linkbase Document.

101.DEF**		XBRL Taxonomy Extension Definition.


*		Filed or furnished herewith.

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