DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2012 June (Form 10-Q)

DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2012 June (Form 10-Q)

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2012

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

For the transition period from to

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

Delaware

76-0321760

(State or other jurisdiction of

incorporation or organization)

(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 x No ¨

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 x No ¨

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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

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 19, 2012 Common stock, $0.01 par value per share 139,029,786 shares

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2012


		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 Comprehensive Income	5
	Consolidated Statements of Cash Flows	6
	Notes to Unaudited Consolidated Financial Statements	7

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	35

ITEM 4.	Controls and Procedures	36

PART II. OTHER INFORMATION		36

ITEM 6.	Exhibits	36

SIGNATURES		37

EXHIBIT INDEX		38

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)


	June 30, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	376,359		$	333,765
Marketable securities		975,947			902,414
Accounts receivable, net of allowance for bad debts		532,302			563,934
Prepaid expenses and other current assets		160,012			192,570

Total current assets		2,044,620			1,992,683
Drilling and other property and equipment, net of accumulated depreciation		4,780,747			4,667,469
Other assets		257,530			304,005

Total assets	$	7,082,897		$	6,964,157

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	63,953		$	64,147
Accrued liabilities		303,718			336,400
Taxes payable		24,787			26,744

Total current liabilities		392,458			427,291

Long-term debt		1,495,943			1,495,823
Deferred tax liability		535,965			536,815
Other liabilities		176,539			171,165

Total liabilities		2,600,905			2,631,094

Commitments and contingencies (Note 8)

Stockholders’ equity:
Common stock (par value $0.01, 500,000,000 shares authorized; 143,946,586 shares issued and 139,029,786 shares outstanding at June 30, 2012; 143,944,009 shares issued and 139,027,209 shares outstanding at December 31, 2011)		1,439			1,439
Additional paid-in capital		1,980,980			1,978,369
Retained earnings		2,614,072			2,472,310
Accumulated other comprehensive gain (loss)		(86	)		(4,642	)
Treasury stock, at cost (4,916,800 shares at June 30, 2012 and December 31, 2011)		(114,413	)		(114,413	)

Total stockholders’ equity		4,481,992			4,333,063

Total liabilities and stockholders’ equity	$	7,082,897		$	6,964,157

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,
	2012			2011			2012			2011
Revenues:
Contract drilling	$	726,261		$	869,646		$	1,481,416		$	1,658,519
Revenues related to reimbursable expenses		11,927			19,850			25,414			37,366

Total revenues		738,188			889,496			1,506,830			1,695,885

Operating expenses:
Contract drilling, excluding depreciation		405,252			388,006			802,354			750,370
Reimbursable expenses		11,637			19,287			24,788			36,237
Depreciation		99,469			101,175			200,862			202,348
General and administrative		18,741			16,372			36,327			34,097
Bad debt recovery		(400	)		(1,700	)		(1,018	)		(10,147	)
Gain on disposition of assets		(53,695	)		(1,240	)		(79,077	)		(3,881	)

Total operating expenses		481,004			521,900			984,236			1,009,024

Operating income		257,184			367,596			522,594			686,861

Other income (expense):
Interest income		1,496			1,091			3,279			1,541
Interest expense		(12,731	)		(22,226	)		(28,060	)		(44,270	)
Foreign currency transaction gain (loss)		1,083			(1,555	)		979			(3,161	)
Other, net		(274	)		(880	)		(599	)		(96	)

Income before income tax expense		246,758			344,026			498,193			640,875

Income tax expense		(45,297	)		(77,440	)		(111,563	)		(123,677	)

Net income	$	201,461		$	266,586		$	386,630		$	517,198

Income per share:
Basic	$	1.45		$	1.92		$	2.78		$	3.72

Diluted	$	1.45		$	1.92		$	2.78		$	3.72

Weighted-average shares outstanding:
Shares of common stock		139,029			139,027			139,028			139,027
Dilutive potential shares of common stock		11			25			11			25

Total weighted-average shares outstanding		139,040			139,052			139,039			139,052

Cash dividends declared per share of common stock	$	.875		$	.875		$	1.75		$	1.75

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net income	$	201,461		$	266,586		$	386,630		$	517,198

Other comprehensive gains (losses), net of tax:
Foreign currency forward exchange contracts:
Unrealized holding (loss) gain		(1,250	)		4,643			2,906			7,683
Reclassification adjustment for loss (gain) included in net income		258			(3,541	)		1,577			(4,949	)

Investments in marketable securities:
Unrealized holding gain (loss)		26			(5	)		(11	)		1
Reclassification adjustment for loss (gain) included in net income		64			(5	)		84			(379	)

Total other comprehensive (loss) gain		(902	)		1,092			4,556			2,356

Comprehensive income	$	200,559		$	267,678		$	391,186		$	519,554

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,
	2012			2011
Operating activities:
Net income	$	386,630		$	517,198
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		200,862			202,348
Gain on disposition of assets		(79,077	)		(3,881	)
Loss (gain) on foreign currency forward exchange contracts		2,977			(7,231	)
Deferred tax provision		(1,101	)		(15,623	)
Accretion of discounts on marketable securities		3,626			(231	)
Stock-based compensation expense		2,500			2,920
Deferred income, net		(7,517	)		(32,490	)
Deferred expenses, net		46,379			54,789
Other assets, noncurrent		2,310			(217	)
Other liabilities, noncurrent		4,486			424
(Payments of) proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges		(2,977	)		7,231
Other		526			(229	)
Changes in operating assets and liabilities:
Accounts receivable		31,424			51,147
Prepaid expenses and other current assets		(16,188	)		(24,137	)
Accounts payable and accrued liabilities		(7,087	)		(33,070	)
Taxes payable		45,572			4,691

Net cash provided by operating activities		613,345			723,639

Investing activities:
Capital expenditures (including rig construction)		(384,693	)		(578,841	)
Proceeds from disposition of assets, net of disposal costs		136,618			4,205
Proceeds from sale and maturities of marketable securities		1,400,050			3,312,089
Purchases of marketable securities		(1,477,115	)		(3,399,797	)

Net cash used in investing activities		(325,140	)		(662,344	)

Financing activities:
Payment of dividends		(245,732	)		(245,812	)
Other		121			—

Net cash used in financing activities		(245,611	)		(245,812	)

Net change in cash and cash equivalents		42,594			(184,517	)
Cash and cash equivalents, beginning of period		333,765			464,393

Cash and cash equivalents, end of period	$	376,359		$	279,876

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, 2011 (File No. 1-13926).

As of July 19, 2012, 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, statements of comprehensive income 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.

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) – Other, net.” See Note 4.

The effect of exchange rate changes on cash balances held in foreign currencies was not material for each of the three and six-month periods ended June 30, 2012 and 2011.

Provision for Bad Debts

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

Derivative Financial Instruments

Our derivative financial instruments consist of foreign currency forward exchange, or FOREX, contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative contract is stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for and is designated as an accounting hedge, the gains and losses are reflected in income in the same period as offsetting gains and losses on the qualifying hedged positions. Designated 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 Balance Sheets. 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. We report such realized gains and losses as a component of “Contract drilling, excluding depreciation” expense in our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our expenditures in local foreign currencies in the countries in which we operate.

Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to fair value and realized gains or losses upon settlement of derivative contracts not designated as cash flow hedges are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. See Notes 5 and 6.

Drilling and Other Property and Equipment

We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. Historically, the amount of capital additions requiring significant judgments, assumptions or estimates has not been significant. During the six months ended June 30, 2012 and the year ended December 31, 2011, we capitalized $99.8 million and $269.5 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $50 million per project.

Costs incurred for major rig upgrades and/or the construction of rigs are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade or newbuild is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations as “Gain on disposition of assets.” Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from 3 to 30 years.

Capitalized Interest

We capitalize interest cost for qualifying construction and upgrade projects. See Note 7. A reconciliation of our total interest cost to “Interest expense” as reported in our Consolidated Statements of Operations is as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
	(In thousands)
Total interest cost, including amortization of debt issuance costs	$	21,228		$	22,226	$	43,636		$	44,270
Capitalized interest		(8,497	)		—		(15,576	)		—

Total interest expense as reported	$	12,731		$	22,226	$	28,060		$	44,270

Impairment of Long-Lived Assets

We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as cold stacking a rig or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize a probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

•

dayrate by rig;

•

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

•

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

•

the estimated annual cost for rig replacements and/or enhancement programs;

•

the estimated maintenance, inspection or other costs associated with a rig returning to work;

•

salvage value for each rig; and

•

estimated proceeds that may be received on disposition of the rig.

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

A summary of the number and net book value of our cold-stacked rigs at June 30, 2012 and December 31, 2011 is as follows:


	June 30,		December 31,
	2012		2011
	(In millions, except number of rigs)
Mid-Water floaters		3		3
Jack-ups		1		5

Total		4		8

Aggregate net book value	$	46.1	$	76.5

We performed an impairment review for each of these rigs at December 31, 2011 using the methodology described above. Based on our analyses, we concluded that these rigs were not subject to impairment at December 31, 2011. Four of the eight rigs cold stacked at December 31, 2011 were sold in the first half of 2012 at prices in excess of net book value.

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.

Foreign Currency

Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations and include, when applicable, unrealized gains and losses to record the carrying value of our FOREX contracts not designated as accounting hedges, as well as realized gains and losses from the settlement of such contracts. For the three-month and six-month periods ended June 30, 2012, we recognized net foreign currency transaction gains of $1.1 million and $1.0 million, respectively. For the three-month and six-month periods ended June 30, 2011, we recognized net foreign currency transaction (losses) of $(1.6) million and $(3.2) million, respectively. See Note 5.

Revenue Recognition

Revenue from our dayrate drilling contracts is recognized as services are performed. In connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the mobilization of equipment. These fees are earned as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight line basis, over the term of the related drilling contracts (which is the period we estimate to be benefited from the mobilization activity). Straight line amortization of mobilization revenues and related costs over the initial term of the related drilling contracts (which generally range from 2 to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized as incurred.

From time to time, we may receive fees from our customers for capital improvements to our rigs (either lump-sum or dayrate). We defer such fees received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the asset.

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

2. Supplemental Financial Information

Consolidated Balance Sheets Information

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


	June 30,			December 31,
	2012			2011
	(In thousands)
Trade receivables	$	520,326		$	555,451
Value added tax receivables		9,282			11,615
Interest receivable		707			2,540
Related party receivables		454			577
Other		7,003			618

		537,772			570,801
Allowance for bad debts		(5,470	)		(6,867	)

Total	$	532,302		$	563,934

During the three-month and six-month periods ended June 30, 2012, we recovered $0.4 million and $1.0 million, respectively, associated with the reserves for bad debts recorded in previous years. In addition, during the first six months of 2012, we offset $0.4 million in previously reserved trade receivables against the allowance for bad debts. During the three-month and six-month periods ended June 30, 2011, we recovered $1.7 million and $10.1 million, respectively, associated with the reserves for bad debts recorded in previous years. No additional allowances were deemed necessary for each of the three-month and six-month periods ended June 30, 2012 and 2011.

Prepaid expenses and other current assets consist of the following:


	June 30,		December 31,
	2012		2011
	(In thousands)
Rig spare parts and supplies	$	52,022	$	52,637
Deferred mobilization costs		47,895		74,659
Prepaid insurance		27,558		12,417
Deferred tax assets		6,800		6,800
Prepaid taxes		15,162		37,612
FOREX contracts		2,542		1,262
Other		8,033		7,183

Total	$	160,012	$	192,570

Accrued liabilities consist of the following:


	June 30,		December 31,
	2012		2011
	(In thousands)
Rig operating expenses	$	105,297	$	108,342
Payroll and benefits		64,276		77,055
Deferred revenue		65,259		67,894
Accrued capital project/upgrade costs		24,253		22,725
Interest payable		21,219		21,406
Construction milestone payments		—		14,600
Personal injury and other claims		11,345		10,536
Other		12,069		13,842

Total	$	303,718	$	336,400

At December 31, 2011, we had accrued $14.6 million for the first milestone payment related to the construction of the Ocean Onyx.

Consolidated Statements of Cash Flows Information

We paid interest on long-term debt totaling $41.5 million for each of the six-month periods ended June 30, 2012 and 2011. We paid $0.2 million in interest on Internal Revenue Service assessments during the six-month period ended June 30, 2012.

We made estimated U.S. federal income tax payments of $33.0 million and $49.0 million during the six-month periods ended June 30, 2012 and 2011, respectively. We paid $41.5 million and $96.5 million in foreign income taxes, net of foreign tax refunds, during the six months ended June 30, 2012 and 2011, respectively. We paid state income taxes, net of refunds, of $0.2 million during the six months ended June 30, 2012.

Cash payments for capital expenditures for the six months ended June 30, 2012 included $37.3 million that was accrued but unpaid at December 31, 2011. Capital expenditures for the six months ended June 30, 2011 included $28.9 million that was accrued but unpaid at December 31, 2010. Capital expenditures that were accrued but not paid as of June 30, 2012 totaled $24.3 million. We have included this amount in “Accrued liabilities” in our Consolidated Balance Sheets at June 30, 2012.

3. Earnings Per Share

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands, except per share data)
Net income – basic and diluted numerator:	$	201,461	$	266,586	$	386,630	$	517,198

Weighted average shares – basic (denominator):		139,029		139,027		139,028		139,027
Effect of dilutive potential shares Stock options and stock appreciation rights		11		25		11		25

Weighted average shares including conversions – diluted (denominator)		139,040		139,052		139,039		139,052

Earnings per share:

Basic	$	1.45	$	1.92	$	2.78	$	3.72

Diluted	$	1.45	$	1.92	$	2.78	$	3.72

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
	(In thousands)
Employee and director:
Stock options		18		8		18		8
Stock appreciation rights		835		693		802		669

4. Marketable Securities

We report our investments as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations. See Note 6.

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


	June 30, 2012
	Amortized Cost		Unrealized Gain (Loss)			Market Value
	(In thousands)
U.S. Treasury Bills and Notes (due within one year)	$	975,528	$	42		$	975,570
Mortgage-backed securities		346		31			377

Total	$	975,874	$	73		$	975,947


	December 31, 2011
	Amortized Cost		Unrealized Gain (Loss)			Market Value
	(In thousands)
U.S. Treasury Bills and Notes (due within one year)	$	902,042	$	(59	)	$	901,983
Mortgage-backed securities		394		37			431

Total	$	902,436	$	(22	)	$	902,414

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,
	2012		2011			2012			2011
	(In thousands)
Proceeds from maturities	$	750,000	$	1,950,000		$	1,250,000		$	3,300,000
Proceeds from sales		50,017		73			150,050			12,089
Gross realized gains		—		—			—			784
Gross realized losses		—		(1	)		(5	)		(2	)

5. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. We may utilize FOREX contracts to manage our foreign exchange risk. Our FOREX contracts may obligate us to exchange predetermined amounts of foreign currencies on specified dates or to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period.

We enter into FOREX contracts when we believe market conditions are favorable to purchase contracts for future settlement with the expectation that such contracts, when settled, will reduce our exposure to foreign currency gains and losses on future foreign currency expenditures. 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.

During the six months ended June 30, 2012 and 2011, we settled FOREX contracts with aggregate notional values of approximately $157.9 million and $145.5 million, respectively, of which the entire aggregate amounts were designated as an accounting hedge. During the six-month periods ended June 30, 2012 and 2011, we did not enter into or settle any FOREX contracts that were not designated as accounting hedges.

The following table presents the amounts recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as accounting hedges for the three-month and six-month periods ended June 30, 2012 and 2011.


	Amount of (Loss) Gain Recognized in Income
	Three Months Ended June 30,					Six Months Ended June 30,
	2012			2011		2012			2011
Location of (Loss) Gain Recognized in Income	(In thousands)
Contract drilling expense	$	(1,199	)	$	5,405	$	(2,977	)	$	7,231

As of June 30, 2012, we had FOREX contracts outstanding in the aggregate notional amount of $218.7 million, consisting of $21.6 million in Australian dollars, $119.6 million in Brazilian reais, $31.7 million in British pounds sterling, $31.4 million in Mexican pesos and $14.4 million in Norwegian kroner. These contracts settle monthly through September 2013. As of June 30, 2012, all outstanding derivative contracts had been designated as cash flow hedges. See Note 6.

The following table presents the fair values of our derivative FOREX contracts designated as hedging instruments at June 30, 2012 and December 31, 2011.


Balance Sheet Location	Fair Value				Balance Sheet Location		Fair Value
	June 30, 2012		December 31, 2011				June 30, 2012			December 31, 2011
	(In thousands)						(In thousands)
Prepaid expenses and other current assets	$	2,542	$	1,262		Accrued liabilities	$	(2,792	)	$	(8,454	)

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, 2012 and 2011.


	For The Three Months Ended June 30,					For The Six Months Ended June 30,
	2012			2011		2012			2011
	(In thousands)
Amount of (loss) gain recognized in AOCGL on derivative (effective portion)	$	(1,923	)	$	7,143	$	4,471		$	11,820

Location of (loss) gain reclassified from AOCGL into income (effective portion)		Contract drilling expense			Contract drilling expense		Contract drilling expense			Contract drilling expense

Amount of (loss) gain reclassified from AOCGL into income (effective portion)	$	(397	)	$	5,448	$	(2,427	)	$	7,615

Location of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		Foreign currency transaction gain (loss)			Foreign currency transaction gain (loss)		Foreign currency transaction gain (loss)			Foreign currency transaction gain (loss)

Amount of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	$	(23	)	$	—	$	(39	)	$	—

As of June 30, 2012, the estimated amount of net unrealized losses associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $0.2 million. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense.

6. Financial Instruments and Fair Value Disclosures

Financial instruments which potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including residential mortgage-backed securities. We generally place our excess cash investments in U.S. government-backed 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.

Most of our investments in debt securities are U.S. government securities with minimal credit risk. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.

Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies and government-owned oil companies. Our two largest customers in Brazil, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government) and OGX Petróleo e Gás Ltda. (a privately owned Brazilian oil and natural gas company), accounted for $109.2 million and $62.4 million, or 20% and 12%, respectively, of our total consolidated gross trade accounts receivable balances as of June 30, 2012, and $110.4 million and $69.4 million, or 20% and 12%, respectively, as of December 31, 2011.

At June 30, 2012 and December 31, 2011, $50.1 million and $95.8 million, respectively, in trade accounts receivable was payable to us from a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties. The drilling program related to the NPI arrangement was completed in 2011.

In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. Historically, we have not experienced significant losses on our trade receivables. We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. Our allowance for bad debts was $5.5 million and $6.9 million at June 30, 2012 and December 31, 2011, respectively. See Note 2.

Fair Values

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, U.S. Treasury Bills and Treasury notes. Our Level 1 assets at June 30, 2012 consisted of cash held in money market funds of $355.6 million and investments in U.S. Treasury securities of $975.6 million. Our Level 1 assets at December 31, 2011 consisted of cash held in money market funds of $303.9 million and investments in U.S. Treasury securities of $902.0 million.

Level 2

Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 assets and liabilities include residential mortgage-backed securities and over-the-counter FOREX contracts. Our residential mortgage-backed securities were valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. Our FOREX contracts are valued based on quoted market prices, which are derived from observable inputs including current spot and forward rates, less the contract rate multiplied by the notional amount. The inputs used in our valuation are obtained from a Bloomberg curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected floating rate cash flows can be calculated. The valuation techniques underlying the models are widely accepted in the financial services industry and do not involve significant judgment.

Level 3

Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.

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

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. Assets and liabilities measured at fair value on a recurring basis are summarized below:


	June 30, 2012
	Fair Value Measurements Using							Assets at Fair Value
	Level 1		Level 2			Level 3		Assets at Fair Value
	(In thousands)
Assets:
Short-term investments	$	1,331,149	$	—		$	—	$	1,331,149
FOREX contracts		—		2,542			—		2,542
Mortgage-backed securities		—		377			—		377

Total assets	$	1,331,149	$	2,919		$	—	$	1,334,068

Liabilities:
FOREX contracts	$	—	$	(2,792	)	$	—	$	(2,792	)


	December 31, 2011
	Fair Value Measurements Using							Assets at Fair Value
	Level 1		Level 2			Level 3		Assets at Fair Value
	(In thousands)
Assets:
Short-term investments	$	1,205,925	$	—		$	—	$	1,205,925
FOREX contracts		—		1,262			—		1,262
Mortgage-backed securities		—		431			—		431

Total assets	$	1,205,925	$	1,693		$	—	$	1,207,618

Liabilities:
FOREX contracts	$	—	$	(8,454	)	$	—	$	(8,454	)

We believe that the carrying amounts of our other financial assets and liabilities (excluding long-term debt), which are not measured at fair value in our Consolidated Balance Sheets, approximate fair value based on the following assumptions:

•

Cash and cash equivalents — The carrying amounts approximate fair value because of the short maturity of these instruments.

•

Accounts receivable and accounts payable — The carrying amounts approximate fair value based on the nature of the instruments.

We consider our long-term debt to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our 5.70% Senior Notes due 2039, 5.875% Senior Notes due 2019, 4.875% Senior Notes due July 1, 2015, and 5.15% Senior Notes due September 1, 2014 was based on the quoted closing market prices from brokers of these instruments at June 30, 2012 and December 31, 2011. We corroborate these broker quotes using observable market data consisting of trade activity for these instruments occurring around the report date. Fair values and related carrying values of our long-term debt instruments are shown below.


	June 30, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
4.875% Senior Notes	$	271.9	$	249.8	$	272.9	$	249.8
5.15% Senior Notes		269.0		249.8		272.7		249.8
5.70% Senior Notes		588.5		496.8		555.0		496.8
5.875% Senior Notes		587.8		499.4		575.4		499.4

We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. 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.

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,
	2012			2011
	(In thousands)
Drilling rigs and equipment	$	7,300,051		$	7,431,713
Construction work-in-progress		773,229			504,805
Land and buildings		61,664			60,926
Office equipment and other		51,667			49,035

Cost		8,186,611			8,046,479
Less: accumulated depreciation		(3,405,864	)		(3,379,010	)

Drilling and other property and equipment, net	$	4,780,747		$	4,667,469

In May 2012, we entered into a contract for the construction of a fourth drillship, the Ocean BlackLion, and paid the first installment of $169.3 million due under the construction contract. Construction work-in-progress, including capitalized interest, at June 30, 2012 included $682.9 million and $90.3 million related to the construction of our four new drillships and the Ocean Onyx, respectively.

During the first six months of 2012, we sold six of our jack-up rigs for an aggregate pre-tax gain of approximately $76.6 million and retired the aggregate net book value of $55.4 million.

8. Commitments and Contingencies

Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a liability for the amount of the estimated loss at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals 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 state courts 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. The manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted and we expect to receive complete defense and indemnity with respect to a majority of the lawsuits from Murphy Exploration & Production Company pursuant to the terms of our 1992 asset purchase agreement with them. We also believe that we are not liable for the damages asserted in the remaining lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation, and we filed a declaratory judgment action in Texas state court against NuStar Energy LP , or NuStar, the successor to Diamond M Corporation, seeking a judicial determination that we did not assume liability for these claims. We obtained summary judgment on our claims in the declaratory judgment action, but NuStar has appealed the court’s decision. 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 effect on our consolidated 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 insurance coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently $10.0 million for 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 liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At June 30, 2012, our estimated liability for personal injury claims was $37.3 million, of which $10.6 million and $26.7 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2011, our estimated liability for personal injury claims was $32.7 million, of which $10.1 million and $22.6 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. During May 2012, we entered into a fourth turnkey contract with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of an additional ultra deepwater drillship with delivery scheduled for the fourth quarter of 2014. We expect the aggregate cost of the construction of our four drillships, including commissioning, spares and project management to be approximately $2.6 billion. The contracted price of each drillship is payable to Hyundai in two installments, with final payment due on delivery of each drillship. We have paid the first installment for each of the four drillships, for which we paid an aggregate of $478.3 million and $169.3 million in 2011 and 2012, respectively.

We are also obligated under a vessel modification agreement with Keppel AmFELS, L.L.C., or Keppel, for the construction of the Ocean Onyx. We estimate the aggregate cost for the construction of the Ocean Onyx to be approximately $300.0 million. The contracted price due to Keppel is payable in 11 installments based on the occurrence of certain events as detailed in the vessel modification agreement, and we paid the first three installments, aggregating $36.5 million, during the first six months of 2012.

At June 30, 2012 and December 31, 2011, we had no other purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.

Letters of Credit and Other. We were contingently liable as of June 30, 2012 in the amount of $125.4 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit. Agreements relating to approximately $107.0 million of performance bonds can require collateral at any time. As of June 30, 2012, 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.

9. 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.

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2012		2011		2012		2011
	(In thousands)
Floaters:
Ultra-Deepwater	$	233,071	$	233,271	$	477,660	$	432,001
Deepwater		142,565		192,791		288,568		325,043
Mid-Water		310,462		383,067		629,057		792,650

Total Floaters		686,098		809,129		1,395,285		1,549,694
Jack-ups		40,163		60,512		86,131		108,730
Other		—		5		—		95

Total contract drilling revenues		726,261		869,646		1,481,416		1,658,519
Revenues related to reimbursable expenses		11,927		19,850		25,414		37,366

Total revenues	$	738,188	$	889,496	$	1,506,830	$	1,695,885

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, 2012, our drilling rigs were located offshore eleven 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,
	2012		2011		2012		2011
	(In thousands)
United States	$	49,960	$	101,221	$	96,566	$	151,495

International:
South America		347,748		441,221		723,593		885,324
Australia/Asia		126,667		118,454		267,390		223,122
Europe/Africa/Mediterranean		160,397		209,102		321,905		399,150
Mexico		53,416		19,498		97,376		36,794

Total revenues	$	738,188	$	889,496	$	1,506,830	$	1,695,885

10. Income Taxes

Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned and operated, directly or indirectly, by one of our wholly owned foreign subsidiaries. It is our intention to indefinitely reinvest future earnings of this subsidiary to finance foreign activities. Accordingly, U.S. income taxes have not been provided on such earnings. In 2011, we were able to defer certain other foreign earnings for U.S. tax purposes. However, due to the expiration of a tax law provision at the end of 2011, such deferral is unavailable in 2012. In the six months ended June 30, 2012, we provided U.S. income taxes on these other foreign earnings.

In 2012, the Brazilian tax authorities concluded their audit of our income tax return for the 2007 year. On February 29, 2012, we received an assessment of R$35.1 million (approximately equal to USD $17 million at June 30, 2012) for income tax, including interest and penalties. We contested the tax assessment in March 2012 and are awaiting the outcome. We have not accrued any tax expense related to this assessment.

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, 2011. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We provide contract drilling services to the energy industry around the globe and are a leader in offshore drilling. Our fleet of 44 offshore drilling rigs, including cold-stacked units, consists of 32 semisubmersibles, seven jack-ups and five dynamically positioned drillships, four of which are under construction. We expect two of our new drillships to be delivered in the second and fourth quarters of 2013 and the remaining two drillships under construction to be delivered in the second and fourth quarters of 2014. Our semisubmersible fleet also includes the Ocean Onyx, which is under construction in Brownsville, Texas.

During the first half of 2012, we sold six of our jack-up rigs, including four rigs that had been cold stacked in previous periods, for aggregate cash proceeds of $133.5 million. At June 30, 2012, our fleet included three mid-water semisubmersibles and one jack-up that are cold stacked.

Overview

International Floater Market

Internationally, the ultra-deepwater and deepwater floater markets are generally strong and continue to show signs of further strengthening, particularly in the ultra-deepwater segment where there are few uncontracted rigs available to work in 2012, with the market remaining tight into early 2013. We believe that the decreasing availability of rigs in this market will continue to put upward pressure on dayrates during the remainder of 2012. However, due to our contracted backlog in 2012 and 2013, we have limited availability in this market (see – Contract Drilling Backlog). In addition, based on second quarter 2012 analyst data, there are over 90 floater rigs, primarily ultra-deepwater and deepwater units, on order or under construction, including 33 rigs reportedly awarded for construction by Petróleo Brasileiro S.A., or Petrobras. Over half of these rigs are expected to be delivered and enter the market during the remainder of 2012 through 2014. Not counting the 33 rigs Petrobras has announced it intends to have built, many of the floaters scheduled for delivery after 2012 are not yet contracted for future work, including two of our drillships under construction.

Market strength for ultra-deepwater and deepwater rigs varies among geographic regions, but generally is strong or nearing current rig capacity. As a result of successful exploration and development programs offshore Brazil and West Africa, there continues to be a robust market for deepwater and ultra-deepwater rigs in those regions. Significant pre-salt oil and gas discoveries offshore Brazil have reportedly led to strong demand for deepwater rigs as Petrobras and others seek to develop these finds. In response, Petrobras has reportedly awarded 33 ultra-deepwater rigs for construction. These rigs, to be built domestically in Brazil, are scheduled for delivery between 2016 and 2020. However, additional demand for ultra-deepwater rigs could develop if Brazilian drilling programs, including those of Petrobras, are accelerated prior to delivery of domestically-constructed rigs or if construction delays are encountered by the Brazilian shipyards.

Market strength for mid-water floaters is stable or improving depending on the geographic market. In the North Sea, the mid-water market is strong, with signs of increasing dayrates, and, in the Mediterranean region, demand remains solid. The Southeast Asia and Australia markets also remain steady.

As of the date of this report, industry-wide floater utilization is reported to be greater than 90%, and, as of July 16, 2012, our floating rigs were committed for approximately 82% of the days remaining in 2012 and 66% of 2013.

International Jack-up Market

Four of our marketed jack-up rigs are currently operating in the Mexican waters of the Gulf of Mexico, where drilling activity remains stable and additional tendering activity is ongoing. Of our two remaining marketed international jack-ups, one is contracted for a two-year bareboat charter offshore Ecuador, which is expected to commence in the third quarter of 2012. Our other international jack-up rig is located offshore Montenegro and is actively seeking work.

GOM Floater and Jack-up Market

Drilling activity on the Outer Continental Shelf of the Gulf of Mexico continues to strengthen and is at or near pre-Macondo levels according to industry analysts. However, many of our rigs that previously operated in the U.S. Gulf of Mexico, or GOM, have been relocated to international markets and continue to work outside the GOM on long-term contracts. We currently have one deepwater semisubmersible contracted in the GOM, and are actively marketing one mid-water unit. The Ocean Onyx, which is currently under construction, is expected to commence its one-year contract, plus potential option periods, beginning in the third quarter of 2013 in the GOM. Our only remaining jack-up rig in the GOM is cold stacked.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of July 16, 2012, February 1, 2012 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2011), and July 21, 2011 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2011). 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 92-98% 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 16, 2012		February 1, 2012		July 21, 2011
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽¹⁾	$	4,571,000	$	4,926,000	$	4,557,000
Deepwater⁽²⁾		1,218,000		1,081,000		1,246,000
Mid-Water⁽³⁾		2,599,000		2,348,000		2,588,000

Total Floaters		8,388,000		8,355,000		8,391,000

Jack-ups		226,000		277,000		259,000

Total	$	8,614,000	$	8,632,000	$	8,650,000

(1)

Contract drilling backlog as of July 16, 2012 for our ultra-deepwater floaters includes (i) $1.6 billion attributable to our contracted operations offshore Brazil for the years 2012 to 2015 and (ii) $1.8 billion attributable to future work for two of our drillships under construction for the years 2013 to 2019.

(2)

Contract drilling backlog as of July 16, 2012 for our deepwater floaters includes (i) $689.0 million attributable to our contracted operations offshore Brazil for the years 2012 to 2016 and (ii) $179.0 million for the years 2013 to 2014 attributable to future work for the Ocean Onyx, which is under construction.

(3)

Contract drilling backlog as of July 16, 2012 for our mid-water floaters includes $1.2 billion attributable to our contracted operations offshore Brazil for the years 2012 to 2015.

The following table reflects the amount of our contract drilling backlog by year as of July 16, 2012.


	For the Years Ending December 31,
	Total		2012 ⁽¹⁾		2013		2014		2015 - 2019
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽²⁾	$	4,571,000	$	430,000	$	904,000	$	1,138,000	$	2,099,000
Deepwater⁽³⁾		1,218,000		314,000		440,000		268,000		196,000
Mid-Water⁽⁴⁾		2,599,000		603,000		955,000		801,000		240,000

Total Floaters		8,388,000		1,347,000		2,299,000		2,207,000		2,535,000

Jack-ups		226,000		67,000		108,000		38,000		13,000

Total	$	8,614,000	$	1,414,000	$	2,407,000	$	2,245,000	$	2,548,000

(1)

Represents a six-month period beginning July 1, 2012.

(2)

Contract drilling backlog as of July 16, 2012 for our ultra-deepwater floaters includes (i) $258.0 million, $524.0 million, $524.0 million and $324.0 million for the years 2012 to 2015, respectively, attributable to our contracted operations offshore Brazil and (ii) $3.0 million and $274.0 million for the years 2013 and 2014, respectively, and $1.5 billion in the aggregate for the years 2015 to 2019, attributable to future work for two of our drillships under construction.

(3)

Contract drilling backlog as of July 16, 2012 for our deepwater floaters includes (i) $122.0 million, $222.0 million and $149.0 million for the years 2012 to 2014, respectively, and $196.0 million in the aggregate for the years 2015 to 2016, attributable to our contracted operations offshore Brazil and (ii) $59.0 million and $120.0 million for the years 2013 and 2014, respectively, attributable to future work for the Ocean Onyx, which is under construction.

(4)

Contract drilling backlog as of July 16, 2012 for our mid-water floaters includes $287.0 million, $477.0 million, $368.0 million and $86.0 million for the years 2012 to 2015, respectively, attributable to our contracted operations offshore Brazil.

The following table reflects the percentage of rig days committed by year as of July 16, 2012. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs multiplied by the number of days in a particular year). Total available days have been calculated based on the expected final commissioning dates for the Ocean BlackHawk, Ocean Onyx, Ocean BlackHornet, Ocean BlackRhino and Ocean BlackLion, which are all under construction.


	For the Years Ending December 31,
	2012 ⁽¹⁾			2013			2014			2015 - 2019
Rig Days Committed ⁽²⁾
Floaters:
Ultra-Deepwater		97	%		91	%		78	%		30	%
Deepwater		100	%		66	%		30	%		9	%
Mid-Water		71	%		55	%		39	%		8	%
All Floaters		82	%		66	%		49	%		15	%

Jack-ups		70	%		53	%		23	%		5	%

(1)

Represents a six-month period beginning July 1, 2012.

(2)

As of July 16, 2012, includes approximately 550 and 600 currently known, scheduled shipyard, survey and mobilization days for 2012 and 2013, respectively.

Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows

Regulatory Surveys and Planned Downtime. 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 generally performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.

In addition, operating income may also 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 remaining two quarters of 2012, eight of our rigs will require 5-year surveys. We expect these rigs to be out of service for approximately 325 days in the aggregate to complete the inspections and any shipyard projects scheduled concurrently with the surveys. We also expect to spend an additional approximately 225 days during the remainder of 2012 for the mobilization of rigs, 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.”

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations and cash flows. Under our insurance policy that expires on May 1, 2013, 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, 2013, 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.

Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. We are currently capitalizing interest on qualifying expenditures related to the construction of our four new drillships and the Ocean Onyx. We expect to capitalize interest pursuant to these projects throughout 2012.

Critical Accounting Estimates

Our significant accounting policies are discussed in Note 1 of our notes to unaudited consolidated financial statements included in Item 1 of Part I of this report and in Note 1 of our notes to audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011. There were no material changes to these policies during the six months ended June 30, 2012.

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 to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.

Key performance indicators by equipment type are listed below.


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUE EARNING DAYS ⁽¹⁾
Floaters:
Ultra-Deepwater		649			666			1,269			1,222
Deepwater		377			444			777			816
Mid-Water		1,142			1,410			2,266			2,868
Jack-ups		419			714			941			1,269

UTILIZATION ⁽²⁾
Floaters:
Ultra-Deepwater		89	%		92	%		87	%		84	%
Deepwater		83	%		98	%		85	%		90	%
Mid-Water		66	%		77	%		66	%		79	%
Jack-ups		49	%		60	%		46	%		54	%

AVERAGE DAILY REVENUE ⁽³⁾
Floaters:
Ultra-Deepwater	$	354,000		$	339,600		$	359,000		$	341,200
Deepwater		371,600			421,900			365,000			385,700
Mid-Water		262,200			265,200			264,200			269,900
Jack-ups		94,100			81,600			90,000			81,900

⁽¹⁾

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

⁽²⁾

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

⁽³⁾

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

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

Three and Six Months Ended June 30, 2012 and 2011


	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater	$	233,071		$	233,271		$	477,659		$	432,001
Deepwater		142,565			192,791			288,568			325,043
Mid-Water		310,462			383,067			629,057			792,650

Total Floaters		686,098			809,129			1,395,284			1,549,694
Jack-ups		40,163			60,512			86,132			108,730
Other		—			5			—			95

Total Contract Drilling Revenue	$	726,261		$	869,646		$	1,481,416		$	1,658,519

Revenues Related to Reimbursable Expenses	$	11,927		$	19,850		$	25,414		$	37,366

CONTRACT DRILLING EXPENSE
Floaters:
Ultra-Deepwater	$	137,087		$	132,907		$	277,048		$	241,552
Deepwater		68,653			59,658			127,375			117,767
Mid-Water		160,642			149,773			323,292			301,793

Total Floaters		366,382			342,338			727,715			661,112
Jack-ups		29,240			38,552			60,683			80,652
Other		9,630			7,116			13,956			8,606

Total Contract Drilling Expense	$	405,252		$	388,006		$	802,354		$	750,370

Reimbursable Expenses	$	11,637		$	19,287		$	24,788		$	36,237

OPERATING INCOME
Floaters:
Ultra-Deepwater	$	95,984		$	100,364		$	200,611		$	190,449
Deepwater		73,912			133,133			161,193			207,276
Mid-Water		149,820			233,294			305,765			490,857

Total Floaters		319,716			466,791			667,569			888,582
Jack-ups		10,923			21,960			25,449			28,078
Other		(9,630	)		(7,111	)		(13,956	)		(8,511	)
Reimbursable expenses, net		290			563			626			1,129
Depreciation		(99,469	)		(101,175	)		(200,862	)		(202,348	)
General and administrative expense		(18,741	)		(16,372	)		(36,327	)		(34,097	)
Bad debt recovery		400			1,700			1,018			10,147
Gain on disposition of assets		53,695			1,240			79,077			3,881

Total Operating Income	$	257,184		$	367,596		$	522,594		$	686,861

Other income (expense):
Interest income		1,496			1,091			3,279			1,541
Interest expense		(12,731	)		(22,226	)		(28,060	)		(44,270	)
Foreign currency transaction gain (loss)		1,083			(1,555	)		979			(3,161	)
Other, net		(274	)		(880	)		(599	)		(96	)

Income before income tax expense		246,758			344,026			498,193			640,875
Income tax expense		(45,297	)		(77,440	)		(111,563	)		(123,677	)

NET INCOME	$	201,461		$	266,586		$	386,630		$	517,198

The following is a summary of the most significant transfers of our rigs during 2012 and 2011 between the geographic areas in which we operate:


Rig	Rig Type	Relocation Details	Date
*Floaters:*
Ocean Monarch	Ultra-Deepwater	GOM to Vietnam	September 2011

Ocean Epoch	Mid-Water	Cold stacked (Malaysia)	February 2011
Ocean Yorktown	Mid-Water	Brazil to GOM	August 2011
Ocean Yorktown	Mid-Water	GOM to Mexico	December 2011
Ocean Guardian	Mid-Water	Falklands to U.K.	January 2012
Ocean Saratoga	Mid-Water	GOM to Guyana	January 2012
Ocean Saratoga	Mid-Water	Guyana to GOM	May 2012
Ocean Whittington	Mid-Water	Brazil to GOM	May 2012

*Jack-ups:*
Ocean Sovereign	Jack-up	Cold stacked (Malaysia)	October 2011
Ocean Scepter	Jack-up	Brazil to GOM	October 2011
Ocean Titan	Jack-up	GOM to Mexico	November 2011
Ocean Scepter	Jack-up	GOM to Mexico	December 2011
Ocean Columbia	Jack-up	Sold	March 2012
Ocean Heritage	Jack-up	Sold	April 2012
Ocean Drake	Jack-up	Sold	May 2012
Ocean Champion	Jack-up	Sold	May 2012
Ocean Crusader	Jack-up	Sold	May 2012
Ocean Sovereign	Jack-up	Sold	June 2012

Overview

Three Months Ended June 30, 2012 and 2011

Operating Income. Operating income decreased $110.4 million, or 30%, during the second quarter of 2012, compared to the same period of 2011, due to the combined effect of a reduction in contract drilling revenue earned and an increase in contract drilling expense incurred. Aggregate revenue for our floater and jack-up fleets decreased $143.4 million, or 16%, compared to the second quarter of 2011, while contract drilling expense increased $17.2 million, or 4%, compared to the same period. Contract drilling revenue for the second quarter of 2012 was negatively impacted by an aggregate 647-day decrease in revenue earning days for our fleet, as well as a decrease in average daily revenue earned by our deepwater and mid-water floater fleets, compared to the second quarter of 2011. In the first half of 2012, we sold six of our jack-up rigs, three of which were operating under contract during the second quarter of 2011. We recognized an aggregate pre-tax gain of $51.7 million on the sale of five of these rigs during the second quarter of 2012.

Contract drilling expense for our combined floater fleet increased $24.0 million during the second quarter of 2012, compared to the same quarter of the prior year, reflecting higher repair and inspection costs and was partially offset by a $9.3 million reduction in contract drilling expense for our jack-up fleet, primarily due to the absence of operating costs during the second quarter of 2012 for the recently sold jack-up rigs.

Interest Expense. Interest expense decreased $9.5 million during the three-month period ended June 30, 2012 compared to the same period in 2011, primarily due to $8.5 million of interest capitalized in 2012 related to the construction of our four new drillships and the Ocean Onyx.

Income Tax Expense Our effective tax rate for the three months ended June 30, 2012 was 18.4%, compared to a 22.5% effective tax rate for the three months ended June 30, 2011. The lower effective tax rate in the 2012 period was primarily the result of differences in the mix of our domestic and international pre-tax earnings and losses, as well as the sale, in the second quarter of 2012, of two of our jack-up rigs at a zero tax rate. The reduction in effective tax rate for the second quarter of 2012, compared to the prior year quarter, was partially offset by the impact of a tax law provision that expired at the end of 2011. This provision allowed us to defer recognition of certain foreign earnings for U.S. tax purposes during the three months ended June 30, 2011; such deferral was unavailable in the comparable period of 2012.

Six Months Ended June 30, 2012 and 2011

Operating Income. Operating income decreased $164.3 million, or 24%, during the first six months of 2012, compared to the same period of 2011, due to the combined effect of an 11% decline in total contract drilling revenue and a 7% increase in contract drilling expense. Both revenue earning days and average daily revenue earned by our deepwater and mid-water floaters declined during the first half of 2012, compared to the first six months of 2011, resulting in a $200.1 million reduction in revenue, while favorable market conditions for our ultra deepwater floaters resulted in a $45.7 million increase in contract drilling revenue. Revenue for our jack-up fleet decreased $22.6 million during the first half of 2012, compared to the first half of 2011, primarily due to the sale of six of our jack-up rigs during the first half of 2012, three of which were operating in the first half of 2011. However, the sale of these six rigs resulted in the recognition of an aggregate pre-tax gain of $76.6 million in the first six months of 2012.

The increase in contract drilling expense for the first half of 2012 primarily reflects higher repair, inspection and mobilization costs as well as an increase in other costs associated with operating rigs internationally, including costs to comply with laws and practices relevant to the international locations in which we operate, such as freight and customs duties, non-income based taxes, revenue-based agency fees and other personnel-related costs, as well as costs associated with maintaining shorebase support functions, sometimes in remote areas. These increases were partially offset by a reduction in contract drilling expense incurred by our jack-up fleet, primarily as a result of the recently sold rigs. In addition, costs related to our worldwide rig staffing, training and rotation programs, primarily labor and related costs, have increased during the first six months of 2012, compared to the same period in 2011, as we continue to hire and train our employees to meet additional staffing requirements in advance of the completion of our newbuild drillships and the Ocean Onyx.

During the six-month periods ended June 30, 2012 and 2011, we recovered $1.0 million and $10.1 million, respectively, of previously recorded reserves for bad debts.

Interest Expense. Interest expense decreased $16.2 million during the six-month period ended June 30, 2012 compared to the same period in 2011, primarily due to $15.6 million of interest capitalized in 2012 related to the construction of our four new drillships and the Ocean Onyx.

Income Tax Expense Our effective tax rate for the six months ended June 30, 2012 was 22.4%, compared to a 19.3% effective tax rate for the six months ended June 30, 2011. The effective tax rate in the first half of 2012 was primarily the result of differences in the mix of our domestic and international pre-tax earnings and losses, as well as the mix of international tax jurisdictions in which we operate. Also contributing to our higher effective tax rate in the first half of 2012, compared to the first half of 2011, was the impact of a tax law provision that expired at the end of 2011. This provision allowed us to defer recognition of certain foreign earnings for U.S. tax purposes during the six months ended June 30, 2011; such deferral was unavailable in the comparable period of 2012.

Income tax expense for the six months ended June 30, 2011 also included a $15.0 million reversal of U.S. income taxes that had been provided in 2010 on certain of our foreign earnings that we had planned to repatriate. In 2011, we reassessed our intention to repatriate these foreign earning to the U.S. subsequent to our 2011 decisions to build three new drillships overseas.

Contract Drilling Revenue and Expense by Equipment Type

Three Months Ended June 30, 2012 and 2011

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters remained stable during the second quarter of 2012, decreasing only $0.2 million from the prior year quarter. The decline in revenue was primarily due to 17 fewer revenue earning days ($5.8 million) during the current year quarter, resulting from 51 days of incremental downtime for surveys and shipyard projects, partially offset by 34 fewer non-operating days for repairs, and a $3.7 million decrease in mobilization revenue recognized in the second quarter of 2012 compared to the same period of 2011. These negative factors were partially offset by an increase in average daily revenue earned ($9.3 million) by our ultra-deepwater floaters during the second quarter of 2012, primarily due to a higher dayrate earned by the Ocean Monarch operating offshore Vietnam in the second quarter of 2012 compared to the rate earned by the rig operating in the GOM in the second quarter of 2011. Contract drilling expense incurred by our ultra-deepwater floaters during the second quarter of 2012 increased $4.2 million, reflecting higher personnel related costs, inspection costs, freight, travel and shorebase support costs, including costs associated with maintaining support offices in West Africa and Vietnam, partially offset by lower amortized mobilization costs than in the comparable quarter of 2011.

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $50.2 million in the second quarter of 2012, compared to the same quarter in 2011, as a result of 67 fewer revenue earning days ($28.4 million), primarily due to downtime associated with the Ocean Star’s 5-year survey, combined with a reduction in average daily revenue earned ($19.0 million). The decrease in average daily revenue earned during the second quarter of 2012 was primarily due to the Ocean Valiant and Ocean Victory currently working at significantly lower dayrates than those earned during the second quarter of 2011. In addition, we recognized $2.8 million less mobilization revenue in the second quarter of 2012 than in the second quarter of 2011. Contract drilling expense incurred by our deepwater floaters increased $9.0 million during the second quarter of 2012, compared to the second quarter of 2011, primarily due to incremental mobilization, repair and inspection costs associated with the Ocean Star’s 2012 survey.

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $72.6 million during the second quarter of 2012, compared to the same quarter in 2011, primarily due to 268 fewer revenue earning days ($71.1 million). The decline in revenue earning days during the second quarter of 2012 was primarily attributable to unplanned downtime for repairs and the warm stacking of rigs between contracts (162 additional days), as well as planned downtime for the mobilization of rigs and shipyard projects (105 additional days). Contract drilling expense increased $10.9 million during the second quarter of 2012, compared to the same quarter in 2011, primarily due to costs associated with a shipyard project and equipment certifications for the Ocean Guardian subsequent to returning to the North Sea from the Falkland Islands.

Jack-ups. Revenue and contract drilling expense recognized by our jack-up rigs decreased $20.3 million and $10.9 million, respectively, in the second quarter of 2012, compared to the same period in 2011, primarily due to the sale of six jack-up rigs in the first half of 2012, including three rigs that were fully utilized during the second quarter of 2011. The impact of the sale of these rigs during the second quarter of 2012 was an incremental reduction in revenue and contract drilling expense of $15.4 million and $8.1 million, respectively, compared to the prior year period. Revenue for the second quarter of 2012 was further reduced by a decrease in dayrate for one of our jack-up rigs operating offshore Mexico due to a contract renewal at a lower dayrate than previously earned by the rig ($4.5 million).

Six Months Ended June 30, 2012 and 2011

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $45.7 million during the first half of 2012, compared to the same period in 2011, primarily due to the effects of higher average daily revenue earned by our aggregate fleet ($22.4 million) and 47 incremental revenue earning days ($16.2 million) during the first six months of 2012. The increase in revenue earning days was primarily due to the inclusion of 112 incremental revenue earnings days for the Ocean Monarch during the first half of 2012, compared to the same period in 2011 when the rig incurred unplanned downtime due to a force majeure assertion by a customer, which was ultimately settled in the second quarter of 2011. The increase in revenue earning days attributable to the Ocean Monarch was partially offset by downtime days for surveys and shipyard projects, as well as unscheduled downtime for repairs for other rigs in our ultra-deepwater fleet during the first half of 2012. We also recognized an additional $7.0 million in deferred mobilization revenue in the first six months of 2012, compared to the same period in 2011, primarily due to the recognition of revenue associated with the Ocean Monarch’s mobilization to Vietnam ($16.2 million), partially offset by a reduction in revenue recognized by our other ultra-deepwater rigs due to the full amortization of fees associated with other rigs moving out of the GOM prior to 2012.

Contract drilling expense incurred by our ultra-deepwater floaters increased $35.5 million during the first six months of 2012, compared to the first six months of 2011, and included $14.1 million in incremental costs incurred by the Ocean Monarch. The increase in contract drilling expense for our other ultra-deepwater floaters reflects higher personnel-related, inspection, freight, customs and duties and shorebase support costs incurred during the first six months of 2012 compared to the same period of 2011. Many of these costs are unpredictable in nature and vary based on the local laws and practices in the international locations in which our ultra-deepwater floaters operate.

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $36.5 million in the first six months of 2012, compared to the same period in 2011, as a result of lower average daily revenue earned ($16.0 million), 39 fewer revenue earning days ($15.1 million), and lower recognition of amortized mobilization revenue ($5.4 million) in the first half of 2012. Average daily revenue earned during the first half of 2012 was negatively impacted by the completion of the Ocean Valiant’s initial contract offshore Angola in the third quarter of 2011 which was at a significantly higher dayrate than the rig is currently earning, partially offset by the effect of each of our other deepwater floaters earning a higher average daily revenue during the first six months of 2012 than in the prior year period. Contract drilling expense incurred by our deepwater floaters increased $9.6 million during the first half of 2012, compared to the same period of 2011, primarily due to the incremental repair and inspection costs incurred by the Ocean Star during the rig’s survey and shipyard project during the second quarter of 2012.

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $163.6 million during the first half of 2012, compared to the same period in 2011, primarily due to 602 fewer revenue earning days ($162.5 million), reflecting an increase in planned downtime for mobilization and shipyard projects (235 additional days), as well as unplanned downtime for repairs and the warm stacking of rigs between contracts (293 additional days). The decrease in revenue earning days during the first half of 2012 was partially offset by 91 fewer cold-stacked days during the period as a result of our decision to upgrade the Ocean Onyx at the end of 2011 for deepwater service, offset by the cold stacking of the Ocean Epoch in the first quarter of 2011. Additionally, the decline in average daily revenue earned ($13.0 million) during the first six months of 2012 was partially offset by the recognition of an additional $11.9 million in mobilization revenue, including an aggregate $18.0 million in mobilization fees recognized for the Ocean Guardian and the Ocean Saratoga associated with their now completed contracts in the Falkland Islands and offshore Guyana, respectively. Contract drilling expense increased $21.5 million during the first half of 2012, compared to the same period in 2011, primarily due to the recognition of costs associated with the 2012 demobilization and subsequent shipyard project for the Ocean Guardian, the mobilization of the Ocean Saratoga to Guyana and subsequent return and the demobilization of the Ocean Whittington to the GOM ($25.1 million), partially offset by reduced contract drilling expense attributable to the cold stacking of the Ocean Epoch in early 2011.

Jack-ups. Revenue and contract drilling expense recognized by our jack-up rigs decreased $22.6 million and $20.0 million, respectively, in the first six months of 2012 compared to the same period in 2011, primarily due to the sale of our six jack-up rigs in the first half of 2012, which resulted in an incremental reduction in revenue and contract drilling expense of $20.2 million and $15.3 million, respectively, comparing the two periods. Contract drilling expense for the first six months of 2012 declined an additional $4.7 million, compared to the first six months of 2011, primarily due to lower catering, mobilization, freight and inspection costs, partially offset by higher maintenance costs and agency fees for our actively marketed jack-up rigs.

Sources of Liquidity and Capital Resources

Our principal sources of liquidity and capital resources are cash flows from our operations and our cash reserves. At June 30, 2012, we had $376.4 million in “Cash and cash equivalents” and $975.9 million in “Marketable securities,” representing our investment of cash available for current operations.

Liquidity and Capital Requirements

Our liquidity and capital requirements are primarily a function of our working capital needs, capital expenditures and debt service requirements. We determine the amount of cash required to meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer requirements, our ongoing rig equipment replacement and enhancement programs, and our obligations relating to the construction of our four new drillships and the Ocean Onyx. As a result of our intention to indefinitely reinvest the earnings of our wholly owned subsidiary, Diamond Offshore International Limited, or DOIL, to finance our foreign activities, we do not expect such earnings to be available for distribution to our stockholders or to finance our domestic activities. However, we believe that the operating cash flows generated by and cash reserves of DOIL, and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc., will be sufficient to meet their respective working capital requirements and capital commitments over the next twelve months. We will, however, 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.

Contractual Cash Obligations.

The following table sets forth our contractual cash obligations at June 30, 2012.


	Payments Due By Period
	Total		Less than 1 year		1 – 3 years		4 – 5 years		After 5 years
	(In thousands)
Contractual Obligations
Long-term debt (principal and interest)	$	2,564,221	$	41,469	$	415,876	$	377,938	$	1,728,938
Construction contracts		1,686,883		43,800		1,643,083		—		—
Operating leases		3,700		1,800		1,800		100		—

Total obligations	$	4,254,804	$	87,069	$	2,060,759	$	378,038	$	1,728,938

We are currently obligated under a vessel modification agreement with Keppel AmFELS, L.L.C., or Keppel, for the construction of the Ocean Onyx, and four separate turnkey contracts with Hyundai Heavy Industries Co., Ltd., or Hyundai, for the construction of four ultra-deepwater drillships. See Note 8 “Commitments and Contingencies – Purchase Obligations” to our Consolidated Financial Statements in Item 1 of Part I of this report.

The above table excludes foreign currency forward exchange, or FOREX, contracts in the aggregate notional amount of $218.7 million outstanding at June 30, 2012. See further information regarding these contracts in Item 3 “Quantitative and Qualitative Disclosures About Market Risk — Foreign Exchange Risk” and Note 5 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 1 of Part I of this report.

As of June 30, 2012, the total unrecognized tax benefit related to uncertain tax positions was $43.2 million. In addition, we have recorded a liability, as of June 30, 2012, for potential penalties and interest of $22.5 million and $9.9 million, respectively, related to the tax benefit related to uncertain tax positions. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in this balance, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

We had no other purchase obligations for major rig upgrades or any other significant obligations at June 30, 2012, 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, 2012 in the amount of $125.4 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit. Agreements relating to approximately $107.0 million of performance bonds can require collateral at any time. As of June 30, 2012, 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		2012		2013		Thereafter
	(In thousands)
Other Commercial Commitments
Customs bonds	$	1,442	$	842	$	600	$	—
Performance bonds		68,668		4,450		18,671		45,547
Other		55,329		75		55,254		—

Total obligations	$	125,439	$	5,367	$	74,525	$	45,547

Credit Ratings.

On June 28, 2012, Moody’s Investors Services upgraded our current credit rating from Baa1 to A3. Our current credit rating remains at A- for Standard & Poor’s. Although our long-term ratings continue at investment grade levels, lower ratings could result in higher interest rates on future debt issuances.

Capital Expenditures.

During 2012, we expect to spend approximately $400.0 million for capital expenditures associated with the construction of our four new drillships and the Ocean Onyx. During the first six months of 2012, we spent $239.4 million towards construction, including $169.3 million as the first installment due under the construction contract for our fourth drillship.

We expect to spend approximately $320.0 million for capital expenditures associated with our ongoing rig equipment replacement and enhancement programs and other corporate requirements during 2012. During the first six months of 2012, we spent approximately $145.3 million toward these programs.

We expect to finance our 2012 capital expenditures through the use of our existing cash balances or internally generated funds.

Off-Balance Sheet Arrangements.

At June 30, 2012 and December 31, 2011, 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, 2012 compared to the six months ended June 30, 2011.

Net Cash Provided by Operating Activities.


	Six Months Ended June 30,
	2012			2011			Change
	(In thousands)
Net income	$	386,630		$	517,198		$	(130,568	)
Net changes in operating assets and liabilities		53,721			(1,369	)		55,090
Cost of proceeds from settlement of FOREX contracts designated as accounting hedges		(2,977	)		7,231			(10,208	)
Gain on sale and disposition of assets		(79,077	)		(3,881	)		(75,196	)
Loss (Gain) on FOREX contracts		2,977			(7,231	)		10,208
Deferred tax provision		(1,101	)		(15,623	)		14,522
Depreciation and other non-cash items, net		253,172			227,314			25,858

	$	613,345		$	723,639		$	(110,294	)

Our cash flows from operations for the first six months of 2012 decreased $110.3 million compared to the same period in 2011, primarily due to lower earnings in the first half of 2012. Total non-cash adjustments to net income during the first six months of 2012 were $173.0 million compared to $207.8 million during the first six months of 2011 and included a gain of $76.6 million on the sale of six jack-up rigs during the first half of 2012.

We used $55.1 million less cash to satisfy our working capital requirements during the first half of 2012 compared to the first half of 2011, primarily due to lower estimated income taxes paid. During the first half of 2012, we made U.S. federal income tax payments and paid foreign income taxes, net of refunds, of $33.0 million and $41.5 million, respectively. During the first half of 2011, we made U.S. federal income tax payments and paid foreign income taxes, net of refunds, of $49.0 million and $96.5 million, respectively. Trade and other receivables generated cash of $31.4 million during the first six months of 2012, compared to $51.1 million in cash generated during the same period of 2011. We also used $26.0 million less cash during the first six months of 2012 to satisfy our accounts payable and accrued liability needs compared to the first six months of 2011.

Net Cash Used in Investing Activities.


	Six Months Ended June 30,
	2012			2011			Change
	(In thousands)
Purchase of marketable securities	$	(1,477,115	)	$	(3,399,797	)	$	1,922,682
Proceeds from sale and maturities of marketable securities		1,400,050			3,312,089			(1,912,039	)
Capital expenditures (including rig construction)		(384,693	)		(578,841	)		194,148
Proceeds from disposition of assets		136,618			4,205			132,413

	$	(325,140	)	$	(662,344	)	$	337,204

Our investing activities used $325.1 million during the first six months of 2012 compared to $662.3 million during the same period in 2011. During the first six months of 2012 we purchased marketable securities, net of sales or maturities, of $77.1 million compared to net purchases of $87.7 million during the same period in 2011. Our level of investment activity is dependent on our working capital and other capital requirements during the year, as well as a response to actual or anticipated events or conditions in the securities markets.

During the first six months of 2012, we spent $268.4 million towards the construction of the Ocean Onyx and our four new drillships, including $169.3 million as a first installment on the Ocean BlackLion. Capital expenditures during the first six months of 2011 included payments aggregating $478.3 million as first installments for the construction of three of our four drillships. See “Liquidity and Capital Requirements — Contractual Cash Obligations” and “Liquidity and Capital Requirements – Capital Expenditures.”

We spent approximately $116.3 million during the first six months of 2012 related to our ongoing capital maintenance programs, including rig modifications to meet contractual requirements, compared to $100.5 million during the same period in 2011.

During the first six months of 2012, we sold six of our jack-up rigs for net cash proceeds of $132.0 million.

Net Cash Used in Financing Activities.


	Six Months Ended June 30,
	2012			2011			Change
	(In thousands)
Payment of dividends	$	(245,732	)	$	(245,812	)	$	80
Other		121			—			121

	$	(245,611	)	$	(245,812	)	$	201

During the first six months of 2012, we paid cash dividends totaling $245.7 million, consisting of regular and special cash dividends of $34.7 million and $211.0 million, respectively. During the first six months of 2011, we paid cash dividends totaling $245.8 million, consisting of regular and special cash dividends of $34.8 million and $211.0 million, respectively.

On July 18, 2012 we declared a regular quarterly cash dividend and a special cash dividend of $0.125 and $0.75, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on September 4, 2012 to stockholders of record on August 1, 2012.

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-month periods ended June 30, 2012 and 2011.

Forward-Looking Statements

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

•

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

•

future uses of and requirements for financial resources;

•

interest rate and foreign exchange risk;

•

future contractual obligations;

•

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

•

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

•

business strategy;

•

growth opportunities;

•

competitive position;

•

expected financial position;

•

future cash flows and contract backlog;

•

future regular or special dividends;

•

financing plans;

•

market outlook;

•

tax planning;

•

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

•

budgets for capital and other expenditures;

•

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

•

timing and cost of completion of rig upgrades, construction projects (including, without limitation, our four drillships under construction and the Ocean Onyx) and other capital projects;

•

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

•

plans and objectives of management;

•

idling drilling rigs or reactivating stacked rigs;

•

asset impairment evaluations;

•

performance of contracts;

•

outcomes of legal proceedings;

•

compliance with applicable laws; and

•

availability, limits and adequacy of insurance or indemnification.

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

•

those described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2011;

•

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

•

worldwide demand for oil and natural gas;

•

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

•

oil and natural gas price fluctuations and related market expectations;

•

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

•

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

•

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

•

the cancellation of contracts included in our reported contract backlog;

•

advances in exploration and development technology;

•

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

•

casualty losses;

•

operating hazards inherent in drilling for oil and gas offshore;

•

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

•

industry fleet capacity, including construction of new drilling rig capacity in Brazil;

•

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

•

competition;

•

changes in foreign, political, social and economic conditions;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

compliance with environmental laws and regulations;

•

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

•

development and exploitation of alternative fuels;

•

customer preferences;

•

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

•

cost, availability, limits and adequacy of insurance;

•

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

•

the results of financing efforts;

•

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

•

adequacy of our sources of liquidity;

•

risks resulting from our indebtedness;

•

public health threats;

•

negative publicity;

•

impairments of assets;

•

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

•

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

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

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk.

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

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at June 30, 2012 and December 31, 2011, 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, 2012 and December 31, 2011, 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.

Our long-term debt, as of June 30, 2012 and December 31, 2011, was denominated in U.S. dollars. Our existing debt has been 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 $124.4 million and $122.0 million as of June 30, 2012 and December 31, 2011, respectively. A 100-basis point decrease would result in an increase in market value of $145.7 million and $142.4 million as of June 30, 2012 and December 31, 2011, respectively.

Foreign Exchange Risk

Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. It is customary for us to enter into foreign currency forward exchange, or FOREX, contracts in the normal course of business. These contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which for certain contracts is the average spot rate for the contract period. As of June 30, 2012, we had FOREX contracts outstanding in the aggregate notional amount of $218.7 million, consisting of $21.6 million in Australian dollars, $119.6 million in Brazilian reais, $31.7 million in British pounds sterling, $31.4 million in Mexican pesos and $14.4 million in Norwegian kroner. These contracts settle monthly through September 2013.

At June 30, 2012, we presented the fair value of our outstanding FOREX contracts as a current asset of $2.5 million in “Prepaid expenses and other current assets” and a current liability of $(2.8) million in “Accrued liabilities” in our Consolidated Balance Sheets. At December 31, 2011, we presented the fair value of our outstanding FOREX contracts as a current asset of $1.3 million in “Prepaid expenses and other current assets” and a current liability of $(8.5) 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,

2012

2011

2012

2011

(In thousands)

Interest rate:

Marketable securities

975,900

(a)

902,400

(a)

(2,500

)(b)

(4,100

)(b)

Foreign Exchange:

FOREX contracts – receivable positions

2,500

(c)

1,300

(c)

(28,700

)(d)

(11,400

)(d)

FOREX contracts – liability positions

(2,800

)(c)

(8,500

)(c)

(9,400

)(d)

(14,700

)(d)

(a)	The fair market value of our investment in marketable securities, excluding repurchase agreements, is based on the quoted closing market prices on June 30, 2012 and December 31, 2011.

(b)	The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at June 30, 2012 and December 31, 2011.

(c)	The fair value of our FOREX contracts is based on both quoted market prices and valuations derived from pricing models on June 30, 2012 and December 31, 2011.

(d)	The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their values at June 30, 2012 and December 31, 2011, 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, 2012. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2012.

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 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 6.

Exhibits.

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

SIGNATURES

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


	DIAMOND OFFSHORE DRILLING, INC.
		(Registrant)

Date July 26, 2012	By:	/s/ Gary T. Krenek
		Gary T. Krenek
		Senior Vice President and Chief Financial Officer

Date July 26, 2012		/s/ Beth G. Gordon
		Beth G. Gordon
		Controller (Chief Accounting Officer)

EXHIBIT INDEX


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

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

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

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

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

101.INS**		XBRL Instance Document.

101.SCH**		XBRL Taxonomy Extension Schema Document.

101.CAL**		XBRL Taxonomy Calculation Linkbase Document.

101.LAB**		XBRL Taxonomy Label Linkbase Document.

101.PRE**		XBRL Presentation Linkbase Document.

101.DEF**		XBRL Definition Linkbase Document.

*	Filed or furnished herewith.

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company