UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

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

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

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

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

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

     Yes þ      No o

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

     Yes þ      No o

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

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

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

     Yes o      No þ

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

As of October 21, 2010		Common stock, $0.01 par value per share		139,026,824 shares

 

 

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED SEPTEMBER 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			20
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk			44
ITEM 4. Controls and Procedures			46
PART II. OTHER INFORMATION			47
ITEM 1A. Risk Factors			47
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 share and per share data)

		September 30,				December 31,
		2010				2009
ASSETS
Current assets:
Cash and cash equivalents		$	184,434			$	376,417
Marketable securities			800,593				400,853
Accounts receivable, net of provision for bad debts			600,368				791,023
Prepaid expenses and other current assets			185,264				155,077
Total current assets			1,770,659				1,723,370
Drilling and other property and equipment, net of accumulated depreciation			4,283,708				4,432,052
Long-term receivable			48,822				—
Other assets			397,500				108,839
Total assets		$	6,500,689			$	6,264,261
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	75,496			$	75,015
Accrued liabilities			348,435				301,871
Taxes payable			81,987				32,410
Current portion of long-term debt			—				4,179
Total current liabilities			505,918				413,475
Long-term debt			1,495,538				1,495,375
Deferred tax liability			560,666				546,024
Other liabilities			200,853				178,745
Total liabilities			2,762,975				2,633,619
Commitments and contingencies (Note 10)			—				—
Stockholders’ equity:
Common stock (par value $0.01, 500,000,000 shares authorized, 143,943,624 shares issued and 139,026,824 shares outstanding at September 30, 2010 and 143,942,978 shares issued and 139,026,178 shares outstanding at December 31, 2009)			1,439				1,439
Additional paid-in capital			1,970,365				1,965,513
Retained earnings			1,879,232				1,776,498
Accumulated other comprehensive gain (loss)			1,091				1,605
Treasury stock, at cost (4,916,800 shares at September 30, 2010 and December 31, 2009)			(114,413	)			(114,413	)
Total stockholders’ equity			3,737,714				3,630,642
Total liabilities and stockholders’ equity		$	6,500,689			$	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								Nine Months Ended
		September 30,								September 30,
		2010				2009				2010				2009
Revenues:
Contract drilling		$	748,998			$	885,281			$	2,405,175			$	2,664,447
Revenues related to reimbursable expenses			50,726				23,094				76,833				76,055
Total revenues			799,724				908,375				2,482,008				2,740,502
Operating expenses:
Contract drilling, excluding depreciation			348,507				304,146				1,002,605				906,746
Reimbursable expenses			50,313				22,873				75,397				75,019
Depreciation			99,117				86,485				297,265				256,978
General and administrative			16,999				15,628				50,502				48,109
Gain on disposition of assets			(32,392	)			(217	)			(33,425	)			(365	)
Total operating expenses			482,544				428,915				1,392,344				1,286,487
Operating income			317,180				479,460				1,089,664				1,454,015
Other income (expense):
Interest income			395				1,879				2,154				3,645
Interest expense			(22,567	)			(14,031	)			(66,221	)			(26,436	)
Foreign currency transaction gain			3,724				8,313				194				17,921
Other, net			(166	)			(336	)			(287	)			315
Income before income tax expense			298,566				475,285				1,025,504				1,449,460
Income tax expense			(100,042	)			(111,151	)			(311,734	)			(349,305	)
Net income		$	198,524			$	364,134			$	713,770			$	1,100,155
Income per share:
Basic		$	1.43			$	2.62			$	5.13			$	7.91
Diluted		$	1.43			$	2.62			$	5.13			$	7.91
Weighted-average shares outstanding:
Shares of common stock			139,027				139,005				139,026				139,003
Dilutive potential shares of common stock			10				98				55				80
Total weighted-average shares outstanding			139,037				139,103				139,081				139,083
Cash dividends declared per share of common stock		$	0.875			$	2.00			$	4.375			$	6.00

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)

		Nine Months Ended
		September 30,
		2010				2009
Operating activities:
Net income		$	713,770			$	1,100,155
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation			297,265				256,978
(Gain) on disposition of assets			(33,425	)			(365	)
(Gain) loss on sale of marketable securities, net			5				(619	)
(Gain) on foreign currency forward exchange contracts			(1,924	)			(11,852	)
Deferred tax provision			14,918				57,984
Accretion of discounts on marketable securities			(421	)			(631	)
Amortization/write-off of debt issuance costs			665				466
Amortization of debt discounts			222				211
Stock-based compensation expense			4,821				4,824
Deferred income, net			41,768				70,340
Deferred expenses, net			(77,372	)			(21,195	)
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges			1,924				3,046
Other assets, noncurrent			7,804				1,750
Other liabilities, noncurrent			10,413				9,007
Changes in operating assets and liabilities:
Accounts receivable			141,726				(198,131	)
Prepaid expenses and other current assets			(16,023	)			(15,524	)
Accounts payable and accrued liabilities			10,146				(54,881	)
Taxes payable			(166,389	)			(65,131	)
Net cash provided by operating activities			949,893				1,136,432
Investing activities:
Capital expenditures			(312,995	)			(309,737	)
Rig acquisitions			—				(950,024	)
Proceeds from disposition of assets, net of disposal costs			186,333				1,391
Deposits received on sale of rigs			—				6,000
Proceeds from sale and maturities of marketable securities			3,700,176				4,098,868
Purchases of marketable securities			(4,099,525	)			(3,698,627	)
Cost to settle foreign currency forward exchange contracts not designated as accounting hedges			—				(28,772	)
Net cash used in investing activities			(526,011	)			(880,901	)
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	)			(3,923	)
Payment of dividends			(611,668	)			(836,621	)
Proceeds from stock plan exercises			139				527
Net cash used in financing activities			(615,865	)			(340,762	)
Net change in cash and cash equivalents			(191,983	)			(85,231	)
Cash and cash equivalents, beginning of period			376,417				336,052
Cash and cash equivalents, end of period		$	184,434			$	250,821

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 October 21, 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).”

     The effect of exchange rate changes on cash balances held in foreign currencies was not material for the nine months ended September 30, 2010 and 2009.

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 $54.6 million and $25.1 million for the nine months ended September 30, 2010 and 2009, respectively. During the nine months ended September 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 $362.5 million and $192.0 million during the nine months ended September 30, 2010 and 2009, respectively. We paid $88.5 million and $141.4 million in foreign income taxes, net of foreign tax refunds, during the nine months ended September 30, 2010 and 2009, respectively. We paid state income taxes, net of refunds, of $1.0 million during the nine months ended September 30, 2010. We paid state income taxes of $0.2 million during the nine months ended September 30, 2009.

     Capital expenditures for the nine months ended September 30, 2010 included $64.9 million that was accrued but unpaid at December 31, 2009. Capital expenditures for the nine months ended September 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 September 30, 2010 totaled $53.8 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at September 30, 2010.

     We recorded income tax benefits of $0 and $32,000 related to employee stock plan exercises during the nine months ended September 30, 2010 and 2009, respectively.

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 September 30, 2010, we evaluated two rigs, the Ocean New Era and the Ocean Spartan, an intermediate semisubmersible rig and an independent-leg, cantilevered jackup rig, respectively, both of which were cold-stacked in the U.S. Gulf of Mexico, or GOM, late in the third quarter of 2010 after completion of their respective contracts. We evaluated these rigs for impairment using the probability-weighted cash flow analysis discussed above. Based on these analyses, we determined that the probability-weighted cash flows for each of the rigs exceeded the carrying value of the individual rigs.

     At September 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, including those that had been previously cold-stacked.

     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								Nine Months Ended
		September 30,								September 30,
		2010				2009				2010				2009
		(In thousands)
Net income		$	198,524			$	364,134			$	713,770			$	1,100,155
Other comprehensive gains (losses), net of tax:
FOREX contracts:
Unrealized holding gain			3,608				1,361				348				5,192
Reclassification adjustment for gain included in net income			(116	)			(1,459	)			(845	)			(1,459	)
Investments in marketable securities:
Unrealized holding (loss) gain			(9	)			(2	)			(31	)			34
Reclassification adjustment for loss (gain) included in net income			13				4				14				(503	)
Comprehensive income		$	202,020			$	364,038			$	713,256			$	1,103,419

     The tax related to the change in unrealized holding gains on FOREX contracts was approximately $1.9 million and $0.2 million for the three-month and nine-month periods ended September 30, 2010, respectively. The tax related to the change in unrealized holding gains on our FOREX contracts for the three-month and nine-month periods ended September 30, 2009 was approximately $0.7 million and $2.8 million, respectively. The tax related to the reclassification adjustment for FOREX contracts included in net income was approximately $62,000 and $0.5 million for the three-month and nine-month periods ended September 30, 2010, respectively. The tax related to the reclassification adjustment for FOREX contracts included in net income for each of the three-month and nine-month periods ended September 30, 2009 was $0.8 million.

     The tax related to the change in unrealized holding loss on investments was approximately $5,000 and $17,000 for the three-month and nine-month periods ended September 30, 2010, respectively. The tax related to the change in unrealized holding (loss) gain on investments was approximately $1,000 and $18,000 for the three-month and nine-month periods ended September 30, 2009, respectively. The tax effect on the reclassification adjustment for net losses included in net income was approximately $7,000 and $8,000 for the three-month and nine-month periods ended September 30, 2010, respectively. The tax effect on the reclassification adjustment for net gains on investments included in net income for the three-month period ended September 30, 2009 was approximately $2,000 and the tax effect on the reclassification adjustment for net losses on investments included in net income for the nine-month period ended September 30, 2009 was approximately $0.3 million.

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” in our Consolidated Statements of Operations. For the three and nine months ended September 30, 2010, we recognized net foreign currency exchange gains of $3.7 million and $0.2 million, respectively. For the three and nine months ended September 30, 2009, we recognized net foreign currency exchange gains of $8.3 million and $17.9 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.

Recently Issued Accounting Pronouncements

     In July 2010, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2010-20, “Receivables (Topic 310): Disclosures about the Credit Quality of Financing Receivables and the Allowance for Credit Losses,” or ASU 2010-20, that requires additional or enhanced disclosures in annual and interim financial statements to assist the users of such financial statements in assessing an entity’s credit risk exposures and evaluating the adequacy of its allowance for credit losses. The provisions of ASU 2010-20 apply to all entities with financing receivables, excluding short-term accounts receivable or receivables measured at fair value or lower of cost or fair value. The content of ASU 2010-20 relating to disclosures as of the end of a reporting period is effective for the first interim or annual reporting period ending on or after December 15, 2010, while the content relating to disclosures about activity that occurs during a reporting period is effective for the first interim or annual reporting period beginning on or after December 15, 2010. We are in the process of reviewing this ASU and will incorporate any additional disclosures in our annual financial statements for the year ending December 31, 2010.

2. Earnings Per Share

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2010				2009				2010				2009
		(In thousands, except per share data)
Net income — basic (numerator):		$	198,524			$	364,134			$	713,770			$	1,100,155
Effect of dilutive potential shares
Zero Coupon Debentures			—				24				56				70
Net income including conversions - diluted (numerator)		$	198,524			$	364,158			$	713,826			$	1,100,225
Weighted average shares — basic (denominator):			139,027				139,005				139,026				139,003
Effect of dilutive potential shares
Zero Coupon Debentures			—				52				28				52
Stock options and SARs			10				46				27				28
Weighted average shares including conversions -diluted (denominator)			139,037				139,103				139,081				139,083
Earnings per share:
Basic		$	1.43			$	2.62			$	5.13			$	7.91
Diluted		$	1.43			$	2.62			$	5.13			$	7.91

     Our computation of diluted earnings per share, or EPS, for the three months ended September 30, 2010 excludes stock options representing 18,837 shares of common stock and 621,144 stock appreciation rights, or SARs. Our computation of diluted EPS for the nine months ended September 30, 2010 excludes stock options representing 9,015 shares of common stock and 578,791 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 September 30, 2009 excludes stock options representing 2,000 shares of common stock and 360,823 SARs. Our computation of diluted EPS for the nine months ended September 30, 2009 excludes stock options representing 11,086 shares of common stock and 430,575

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:

		September 30, 2010
		Amortized				Unrealized				Market
		Cost				Gain (Loss)				Value
		(In thousands)
U.S. Treasury Bills (due within one year)		$	799,945			$	(13	)		$	799,932
Mortgage-backed securities			610				51				661
Total		$	800,555			$	38			$	800,593

		December 31, 2009
		Amortized				Unrealized				Market
		Cost				Gain (Loss)				Value
		(In thousands)
U.S. Treasury Bills (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								Nine Months Ended
		September 30,								September 30,
		2010				2009				2010				2009
		(In thousands)
Proceeds from sales		$	88			$	100,039			$	176			$	2,548,868
Proceeds from maturities			1,150,000				800,000				3,700,000				1,550,000
Gross realized gains			—				22				—				790
Gross realized losses			(3	)			(2	)			(5	)			(171	)

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 nine months ended September 30, 2010, we settled FOREX contracts with an aggregate notional value of approximately $251.1 million, of which the entire aggregate amount was designated as an accounting hedge. During the nine months ended September 30, 2009, we settled foreign currency exchange contracts with an aggregate notional value of approximately $279.3 million, of which an aggregate notional value of $61.1 million was designated as an accounting hedge.

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

		Amount of Gain Recognized in Income
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
Location of Gain Recognized in Income		2010				2009				2010				2009
		(In thousands)
Contract drilling expense		$	1,467			$	3,047			$	1,924			$	3,047

     The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts not designated as hedging instruments for the three-month and nine-month periods ended September 30, 2010 and 2009.

		Amount of Gain Recognized in Income
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
Location of Gain Recognized in Income		2010				2009				2010				2009
		(In thousands)
Foreign currency transaction gain		$	—			$	238			$	—			$	8,806

     The amounts presented in the table above include unrealized gains of $147,000 and $37.6 million for the three months and nine months ended September 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 nine months ended September 30, 2010.

     As of September 30, 2010, we had FOREX contracts outstanding, in the aggregate notional amount of $26.6 million, consisting of $15.3 million in Australian dollars, $7.3 million in British pounds sterling, $1.9 million in Mexican pesos and $2.1 million in Norwegian kroner. These contracts generally settle monthly through November 2010. As of September 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 September 30, 2010.

Assets

Liabilities

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

(In thousands)

(In thousands)

Derivatives designated as hedging instruments:

FOREX contracts

Prepaid expenses and other current assets

$

1,649

Accrued liabilities

$

(9

)

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

Assets

Liabilities

Balance Sheet

Balance Sheet

Location

Fair Value

Location

Fair Value

(In thousands)

(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 nine-month periods ended September 30, 2010.

Location of

Gain

Recognized in

Location of

Income on

Gain

Derivative

Reclassified

(Ineffective

Amount of Gain

from

Portion and

Recognized in Income on

Amount of Gain

AOCGL into

Amount of Gain

Amount

Derivative (Ineffective

Recognized in AOCGL

Income

Reclassified from

Excluded from

Portion and Amount

on Derivative (Effective

(Effective

AOCGL into Income

Effectiveness

Excluded from

Portion)

Portion)

(Effective Portion)

Testing)

Effectiveness Testing)

Three

Nine

Three

Nine

Three

Nine

Months

Months

Months

Months

Months

Months

Ended

Ended

Ended

Ended

Ended

Ended

September

September

September

September

September

September

30, 2010

30, 2010

30, 2010

30, 2010

30, 2010

30, 2010

(In thousands)

(In thousands)

(In thousands)

$5,550

$535

Contract drilling expense

$178

$1,300

Foreign currency transaction gain (loss)

$—

$—

     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 nine-month periods ended September 30, 2009.

Location of Loss

Recognized in

Location of

Income on

Gain

Derivative

Reclassified

(Ineffective

Amount of Loss

from

Portion and

Recognized in Income on

Amount of Gain

AOCGL into

Amount of Gain

Amount

Derivative (Ineffective

Recognized in AOCGL

Income

Reclassified from

Excluded from

Portion and Amount

on Derivative (Effective

(Effective

AOCGL into Income

Effectiveness

Excluded from

Portion)

Portion)

(Effective Portion)

Testing)

Effectiveness Testing)

Three

Nine

Three

Nine

Three

Nine

Months

Months

Months

Months

Months

Months

Ended

Ended

Ended

Ended

Ended

Ended

September

September

September

September

September

September

30, 2009

30, 2009

30, 2009

30, 2009

30, 2009

30, 2009

(In thousands)

(In thousands)

(In thousands)

$2,093

$7,987

Contract drilling expense

$2,244

$2,244

Foreign currency transaction loss

$(269)

$—

     As of September 30, 2010, the estimated amount of net unrealized gains associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $1.6 million. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense.

5. Financial Instruments and Fair Value Disclosures

Concentrations of Credit and Market Risk

     Financial instruments which potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including 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, an aggregate drilling rate of $560,000 per day, consisting of $75,000 per day payable in accordance with our normal credit terms (due 30 days after receipt of invoice) and the remainder of the contractual dayrate, $485,000 per day, payable through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties. We began receiving monthly payments from the conveyance of the NPI in July 2010. Based on current production payout estimates, we expect to collect $42.2 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 September 30, 2010, $91.0 million was payable to us from the NPI, of which $42.2 million and $48.8 million are presented as “Accounts receivable” and “Long-term receivable,” respectively, in our Consolidated Balance Sheets. At September 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:

		September 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			277.8				249.7				257.5				249.7
5.15% Senior Notes			277.1				249.7				263.3				249.7
5.70% Senior Notes			519.8				496.8				490.4				496.7
5.875% Senior Notes			568.9				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 September 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 September 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 September 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 September 30, 2010 consisted of cash held in money market funds of $155.6 million and investments in U.S. Treasury Bills of $799.9 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:

		September 30, 2010
		Fair Value Measurements Using												Assets at Fair
		Level 1				Level 2				Level 3				Value
		(In thousands)
Assets:
Short-term investments		$	955,553			$	—			$	—			$	955,553
FOREX contracts			—				1,649				—				1,649
Mortgage-backed securities			—				661				—				661
Total assets		$	955,553			$	2,310			$	—			$	957,863
Liabilities:
FOREX contracts		$	—			$	(9	)		$	—			$	(9	)

		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:

		September 30,				December 31,
		2010				2009
		(In thousands)
Rig spare parts and supplies		$	53,226			$	49,122
Deferred mobilization costs			90,462				45,502
Prepaid insurance			16,184				11,478
Deferred tax assets			7,235				7,235
Deposits			934				3,562
Prepaid taxes			4,118				27,679
FOREX contracts			1,649				2,634
Other			11,456				7,865
Total		$	185,264			$	155,077

7. Drilling and Other Property and Equipment

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

		September 30,				December 31,
		2010				2009
		(In thousands)
Drilling rigs and equipment		$	7,071,867			$	6,950,303
Land and buildings			53,262				44,640
Office equipment and other			43,401				38,203
Cost			7,168,530				7,033,146
Less: accumulated depreciation			(2,884,822	)			(2,601,094	)
Drilling and other property and equipment, net		$	4,283,708			$	4,432,052

     On July 7, 2010, we completed the sale of the Ocean Shield for a gross purchase price of $186.0 million and recorded a net gain on sale of approximately $31.6 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 was able to comply with all obligations under the drilling contract and the drilling contract could be assigned to the successor owner. The bareboat charter arrangement was terminated in August 2010.

8. Accrued Liabilities

     Accrued liabilities consist of the following:

		September 30,				December 31,
		2010				2009
		(In thousands)
Accrued project/upgrade expenses		$	94,013			$	115,778
Payroll and benefits			81,173				69,065
Deferred revenue			84,851				46,666
Rig operating expenses			39,416				29,141
Interest payable			29,501				22,710
Personal injury and other claims			12,292				10,018
Other			7,189				8,493
Total		$	348,435			$	301,871

9. Long-Term Debt

     Long-term debt consists of the following:

		September 30,				December 31,
		2010				2009
		(In thousands)
Zero Coupon Debentures (due 2020)		$	—			$	4,179
5.15% Senior Notes (due 2014)			249,729				249,682
4.875% Senior Notes (due 2015)			249,711				249,671
5.875% Senior Notes (due 2019)			499,336				499,292
5.70% Senior Notes (due 2039)			496,762				496,730
			1,495,538				1,499,554
Less: Current maturities			—				4,179
Total		$	1,495,538			$	1,495,375

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

(Dollars in thousands)
2011			—
2012			—
2013			—
2014			249,729
2015			249,711
Thereafter			996,098
Total		$	1,495,538

Redemption of Zero Coupon Debentures

     On May 28, 2010, we redeemed 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 redemption price of $706.28 per $1,000 principal amount at maturity for cash. At September 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 deductibles for marine liability coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently $10.0 million per the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year. The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate reserve for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate reserve to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At September 30, 2010, our estimated liability for personal injury claims was $36.4 million, of which $11.5 million and $24.9 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 September 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 September 30, 2010 in the amount of $130.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $19.7 million in letters of credit issued under our $285 million, syndicated, senior unsecured revolving credit facility. At September 30, 2010, four of our outstanding bonds, totaling $79.2 million, had been purchased from a related party in a previous year after obtaining competitive quotes. Agreements relating to approximately $79.2 million of performance bonds can require collateral at any time. As of September 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 FASB Accounting Standards Codification Topic 280, Segment Reporting.

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

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2010				2009				2010				2009
		(In thousands)
High-Specification Floaters		$	305,335			$	353,318			$	1,029,510			$	999,979
Intermediate Semisubmersibles			380,438				421,145				1,150,233				1,303,907
Jack-ups			63,133				110,818				225,305				360,561
Other			92				—				127				—
Total contract drilling revenues			748,998				885,281				2,405,175				2,664,447
Revenues related to reimbursable expenses			50,726				23,094				76,833				76,055
Total revenues		$	799,724			$	908,375			$	2,482,008			$	2,740,502

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 September 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								Nine Months Ended
		September 30,								September 30,
		2010				2009				2010				2009
		(In thousands)
United States		$	146,229			$	285,665			$	573,796			$	975,844
International:
South America			318,117				191,044				913,440				488,454
Australia/Asia/Middle East			181,550				169,910				482,942				543,368
Europe/Africa/Mediterranean			120,113				179,588				396,796				490,390
Mexico			33,715				82,168				115,034				242,446
Total revenues		$	799,724			$	908,375			$	2,482,008			$	2,740,502

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, Item 1A of Part II, “Risk Factors,” included in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2010 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 were successfully completed in September 2010.

     In the near-term aftermath of the Macondo incident, on May 30, 2010, the U.S. government imposed a six-month 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 October 12, 2010, the U.S. government lifted the moratorium subject to compliance with enhanced safety requirements including those set forth in Notices to Lessees 2010-N05 and 2010-N06, both of which were implemented during the drilling ban. Additionally, all drilling in the GOM will be required to comply with the Interim Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management Systems, both of which were issued on September 30, 2010, once they become final. We continue to evaluate these new measures to ensure that our rigs and equipment are in full compliance, where applicable. Additional requirements could be forthcoming based on further recommendations by regulatory agencies investigating the Macondo incident. We are not able to predict the likelihood, nature or extent of additional rulemaking or when the interim rules, or any future rules, could become final. Nor are we able to predict when the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEM, will issue drilling permits to our customers. We are not able to predict the future impact of these events on our operations. Even with the drilling ban lifted, certain deepwater drilling activities remain suspended until the BOEM resumes its regular permitting of those activities.

     It has been reported that the industry currently has 35 floating rigs in the GOM that have been impacted by the moratorium and that four floating rigs have left the GOM since the imposition of the moratorium, two of which were Diamond Offshore rigs. As of the date of this report, we have two semisubmersible units under contract in the GOM, in addition to the Ocean Monarch, whose contract the operator has sought to terminate as discussed below, as well as two jack-up units. Given the continuing uncertainty with respect to drilling activity in the GOM, our customers may seek to move additional rigs to locations outside of the GOM or perform activities which are allowed under the enhanced safety requirements. One of our customers has asserted force majeure as a basis for its termination of the drilling contract for the Ocean Monarch, which has a remaining term of approximately thirty months, and the operator has also filed suit against us in U.S. District Court in Houston seeking a declaratory judgment that its termination of the drilling contract is warranted under the contract. We do not believe the events cited by the operator come within the definition of force majeure under the drilling contract, and we do not believe that the operator has the right to terminate the drilling contract on this basis. Although we cannot predict with certainty the results of any such litigation, and there can be no assurance as to its ultimate outcome, we intend to vigorously defend this litigation and challenge the operator’s attempt to terminate the drilling contract.

     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 assertion will ultimately be resolved in our favor. In addition, given the ongoing uncertainty with respect to drilling activity and other industry factors in the GOM, we have cold stacked two intermediate floaters and four jack-up rigs in the GOM.

     Outside the GOM, the global economy remained relatively flat in the third 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. While dayrates for our international floater units appear to have stabilized, given the unpredictable economic environment, the demand for our services and the dayrates we are able to command could soften further. The volatility and economic uncertainty are being further exacerbated by the continuing regulatory uncertainty in the GOM. If we, or others, move additional rigs out of the GOM to international locations, the increased supply of available rigs entering the international market, coupled with un-contracted new-build rigs scheduled for delivery between now and the end of 2010, could create downward pressure on dayrates unless demand improves sufficiently to absorb the new supply.

     Since June 30, 2010 through the date of this report, we have entered into eight new drilling contracts totaling approximately $76.2 million in backlog and ranging in duration from one well to one year. At the end of the third quarter of 2010, our contract backlog was approximately $7.5 billion, of which our contracts in the GOM (including approximately $394.0 million related to the contract for the Ocean Monarch discussed above) represented approximately $546.0 million, or 7%, 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 nine months of 2010. Approximately 89% of the time on our intermediate and high-specification floater rigs is committed for the remainder of 2010. Additionally, 67% of the time on our floating rigs is committed in 2011.

     International Jack-ups

     During the third quarter of 2010, demand for our international jack-ups remained weak but stable. However, the high-specification new-build equipment coming to market is enjoying a significantly higher utilization rate than older existing equipment, and the oversupply of jack-up rigs could have an increasingly negative impact on the international sector throughout 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 third quarter of 2010, we cold-stacked a fourth jack-up unit to reduce costs. As planned, our high-specification jack-up, the Ocean Scepter, mobilized to Brazil in August under a one-year term contract. Our two remaining higher-specification jack-ups in the GOM are largely working under short-term contracts and could experience significant downtime unless permitting activity increases. 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 the remainder of 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 October 18, 2010, February 1, 2010 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2009) and October 22, 2009 (the date reported in our Quarterly Report on Form 10-Q for the quarterly period ended September 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.

		October 18,				February 1,				October 22,
		2010				2010				2009
						(In thousands)
Contract Drilling Backlog
High-Specification Floaters (1)		$	4,371,000			$	4,177,000			$	4,450,000
Intermediate Semisubmersibles (2)			3,009,000				4,030,000				4,061,000
Jack-ups (3)			122,000				249,000				249,000
Total		$	7,502,000			$	8,456,000			$	8,760,000

     The following table reflects the amount of our contract drilling backlog by year as of October 18, 2010.

		For the Years Ending December 31,
		Total				2010(1)				2011				2012				2013 - 2016
		(In thousands)
Contract Drilling Backlog
High-Specification Floaters (2)		$	4,371,000			$	450,000			$	1,653,000			$	912,000			$	1,356,000
Intermediate Semisubmersibles (3)			3,009,000				383,000				1,010,000				860,000				756,000
Jack-ups (4)			122,000				36,000				86,000				—				—
Total		$	7,502,000			$	869,000			$	2,749,000			$	1,772,000			$	2,112,000

     The following table reflects the percentage of rig days committed by year as of October 18, 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 (3)			99	%			82	%			47	%			18	%
Intermediate Semisubmersibles			83	%			57	%			44	%			10	%
Jack-ups			40	%			17	%			—				—

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 fully predict the financial impact of new regulations that have been adopted subsequent to the Macondo incident in April 2010 for rigs operating in the GOM, or any new regulations that may arise as the investigation into the incident continues or as a result of further recommendations by regulatory agencies. 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 or to obtain the required inspections or certifications as prescribed under such regulations.

     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, two of our rigs are expected to complete 5-year surveys, and we expect that they will be out of service for approximately 85 days in the aggregate during the final quarter of 2010. We also expect to spend an additional approximately 140 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. Under our insurance policy that expires on May 1, 2011, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.

     In addition, under our insurance policy that expires on May 1, 2011, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine liability coverage, including for personal injury claims, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims which might arise during the policy year, which under the current policy commences on May 1 of each year. As a result of the Macondo incident, insurance costs across the industry are expected to increase and in the future, certain insurance coverage is likely to become more costly, and may become less available or not available at all.

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 nine months ended September 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 September 30, 2010 and 2009

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

		Three Months Ended
		September 30,								Favorable/
		2010				2009				(Unfavorable)
		(In thousands)
CONTRACT DRILLING REVENUE
High-Specification Floaters		$	305,335			$	353,318			$	(47,983	)
Intermediate Semisubmersibles			380,438				421,145				(40,707	)
Jack-ups			63,133				110,818				(47,685	)
Other			92				—				92
Total Contract Drilling Revenue		$	748,998			$	885,281			$	(136,283	)
Revenues Related to Reimbursable Expenses		$	50,726			$	23,094			$	27,632
CONTRACT DRILLING EXPENSE
High-Specification Floaters		$	148,503			$	103,258			$	(45,245	)
Intermediate Semisubmersibles			153,683				142,156				(11,527	)
Jack-ups			42,940				52,559				9,619
Other			3,381				6,173				2,792
Total Contract Drilling Expense		$	348,507			$	304,146			$	(44,361	)
Reimbursable Expenses		$	50,313			$	22,873			$	(27,440	)
OPERATING INCOME
High-Specification Floaters		$	156,832			$	250,060			$	(93,228	)
Intermediate Semisubmersibles			226,755				278,989				(52,234	)
Jack-ups			20,193				58,259				(38,066	)
Other			(3,289	)			(6,173	)			2,884
Reimbursable expenses, net			413				221				192
Depreciation			(99,117	)			(86,485	)			(12,632	)
General and administrative expense			(16,999	)			(15,628	)			(1,371	)
Gain on disposition of assets			32,392				217				32,175
Total Operating Income		$	317,180			$	479,460			$	(162,280	)
Other income (expense):
Interest income			395				1,879				(1,484	)
Interest expense			(22,567	)			(14,031	)			(8,536	)
Foreign currency transaction gain			3,724				8,313				(4,589	)
Other, net			(166	)			(336	)			170
Income before income tax expense			298,566				475,285				(176,719	)
Income tax expense			(100,042	)			(111,151	)			11,109
NET INCOME		$	198,524			$	364,134			$	(165,610	)

     During the third quarter of 2010, our operating results were negatively impacted by the drilling moratorium in the GOM, as well as the relatively flat global economy. Although our contracted revenue backlog enabled us to partially mitigate the impact of these market conditions, our operating income decreased 34%, or $162.3 million, compared to the third quarter of 2009. Contract drilling revenue for the third quarter of 2010 decreased $136.3

million, or 15%, compared to the third quarter of 2009. Average utilization for our overall fleet decreased from 76% during the third quarter of 2009 to 65% during the third quarter of 2010.

     In response to continued, depressed market conditions, we have elected to cold stack certain rigs within our drilling fleet. As of the end of the third quarter of 2010, we had cold stacked one cantilevered and three mat-supported jack-up rigs (all in the GOM) and three intermediate semisubmersible rigs (two in the GOM and one in Malaysia).

     Total contract drilling expense increased $44.4 million, or 15%, during the third quarter of 2010 compared to the same period in 2009, primarily due to higher maintenance costs and higher amortized mobilization costs, as well as the inclusion of operating and start-up costs for the latest additions to our drilling fleet, the Ocean Courage and Ocean Valor.

High-Specification Floaters.

		Three Months Ended
		September 30,								Favorable/
		2010				2009				(Unfavorable)
		(In thousands)
HIGH-SPECIFICATION FLOATERS:
CONTRACT DRILLING REVENUE
GOM		$	61,707			$	237,635			$	(175,928	)
Australia/Asia/Middle East			74,385				40,936				33,449
Europe/Africa/Mediterranean			45,250				10,499				34,751
South America			123,993				64,248				59,745
Total Contract Drilling Revenue		$	305,335			$	353,318			$	(47,983	)
CONTRACT DRILLING EXPENSE
GOM		$	29,199			$	60,116			$	30,917
Australia/Asia/Middle East			21,335				8,203				(13,132	)
Europe/Africa/Mediterranean			18,147				3,008				(15,139	)
South America			79,822				31,931				(47,891	)
Total Contract Drilling Expense		$	148,503			$	103,258			$	(45,245	)
OPERATING INCOME		$	156,832			$	250,060			$	(93,228	)