DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2013 June (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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, 2013

¨	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 25, 2013 Common stock, $0.01 par value per share 139,035,448 shares

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2013


	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		22

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk		36

ITEM 4. Controls and Procedures		38

PART II. OTHER INFORMATION		38

ITEM 6. Exhibits		38

SIGNATURES		39

EXHIBIT INDEX		40

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,			December 31,
	2013			2012
ASSETS
Current assets:
Cash and cash equivalents	$	369,972		$	335,432
Marketable securities		850,232			1,150,158
Accounts receivable, net of allowance for bad debts		485,878			499,660
Prepaid expenses and other current assets		145,111			136,099
Assets held for sale		11,594			11,594

Total current assets		1,862,787			2,132,943
Drilling and other property and equipment, net of accumulated depreciation		5,239,231			4,864,972
Other assets		210,484			237,371

Total assets	$	7,312,502		$	7,235,286

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	74,489		$	96,631
Accrued liabilities		334,360			324,434
Taxes payable		23,735			64,481

Total current liabilities		432,584			485,546
Long-term debt		1,496,192			1,496,066
Deferred tax liability		511,492			490,946
Other liabilities		186,067			186,334

Total liabilities		2,626,335			2,658,892

Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding)		—			—
Common stock (par value $0.01, 500,000,000 shares authorized; 143,952,248 shares issued and 139,035,448 shares outstanding at June 30, 2013; 143,948,370 shares issued and 139,031,570 shares outstanding at December 31, 2012)		1,440			1,439
Additional paid-in capital		1,985,843			1,983,957
Retained earnings		2,819,144			2,702,915
Accumulated other comprehensive gain (loss)		(5,847	)		2,496
Treasury stock, at cost (4,916,800 shares of common stock at June 30, 2013 and December 31, 2012)		(114,413	)		(114,413	)

Total stockholders’ equity		4,686,167			4,576,394

Total liabilities and stockholders’ equity	$	7,312,502		$	7,235,286

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,
	2013			2012			2013			2012
Revenues:
Contract drilling	$	744,898		$	726,261		$	1,444,871		$	1,481,416
Revenues related to reimbursable expenses		13,120			11,927			42,888			25,414

Total revenues		758,018			738,188			1,487,759			1,506,830

Operating expenses:
Contract drilling, excluding depreciation		369,036			405,252			744,130			802,354
Reimbursable expenses		12,805			11,637			42,094			24,788
Depreciation		97,143			99,469			193,964			200,862
General and administrative		16,435			18,741			33,250			36,327
Bad debt recovery		—			(400	)		—			(1,018	)
Gain on disposition of assets		(260	)		(53,695	)		(2,264	)		(79,077	)

Total operating expenses		495,159			481,004			1,011,174			984,236

Operating income		262,859			257,184			476,585			522,594
Other income (expense):
Interest income		271			1,496			888			3,279
Interest expense		(7,951	)		(12,731	)		(16,020	)		(28,060	)
Foreign currency transaction gain		448			1,083			607			979
Other, net		674			(274	)		420			(599	)

Income before income tax expense		256,301			246,758			462,480			498,193
Income tax expense		(70,967	)		(45,297	)		(101,157	)		(111,563	)

Net income	$	185,334		$	201,461		$	361,323		$	386,630

Income per share:
Basic	$	1.33		$	1.45		$	2.60		$	2.78

Diluted	$	1.33		$	1.45		$	2.60		$	2.78

Weighted-average shares outstanding:
Shares of common stock		139,035			139,029			139,034			139,028
Dilutive potential shares of common stock		37			11			43			11

Total weighted-average shares outstanding		139,072			139,040			139,077			139,039

Cash dividends declared per share of common stock	$	0.875		$	0.875		$	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,
	2013			2012			2013			2012
Net income	$	185,334		$	201,461		$	361,323		$	386,630
Other comprehensive gains (losses), net of tax:
Foreign currency forward exchange contracts:
Unrealized holding (loss) gain		(6,799	)		(1,250	)		(6,516	)		2,906
Reclassification adjustment for loss (gain) included in net income		(253	)		258			(1,704	)		1,577
Investments in marketable securities:
Unrealized holding gain (loss)		2			26			9			(11	)
Reclassification adjustment for loss (gain) included in net income		(49	)		64			(132	)		84

Total other comprehensive (loss) gain		(7,099	)		(902	)		(8,343	)		4,556

Comprehensive income	$	178,235		$	200,559		$	352,980		$	391,186

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,
	2013			2012
Operating activities:
Net income	$	361,323		$	386,630
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		193,964			200,862
Gain on disposition of assets		(2,264	)		(79,077	)
(Gain) loss on foreign currency forward exchange contracts		(2,772	)		2,977
Deferred tax provision		24,996			(1,101	)
Accretion of discounts on marketable securities		(514	)		3,626
Stock-based compensation expense		1,777			2,500
Deferred income, net		(22,595	)		(7,517	)
Deferred expenses, net		7,030			46,379
Long-term employee remuneration programs		4,319			4,014
Other assets, noncurrent		(4,413	)		2,310
Other liabilities, noncurrent		(4,185	)		472
Proceeds from (payments of) settlement of foreign currency forward exchange contracts designated as accounting hedges		2,772			(2,977	)
Other		939			526
Changes in operating assets and liabilities:
Accounts receivable		13,895			31,424
Prepaid expenses and other current assets		(5,916	)		(16,188	)
Accounts payable and accrued liabilities		(32,859	)		(7,087	)
Taxes payable		(15,375	)		45,572

Net cash provided by operating activities		520,122			613,345

Investing activities:
Capital expenditures (including rig construction)		(542,923	)		(384,693	)
Proceeds from disposition of assets, net of disposal costs		2,478			136,618
Proceeds from sale and maturities of marketable securities		1,750,038			1,400,050
Purchases of marketable securities		(1,449,745	)		(1,477,115	)

Net cash used in investing activities		(240,152	)		(325,140	)

Financing activities:
Payment of dividends		(245,567	)		(245,732	)
Other		137			121

Net cash used in financing activities		(245,430	)		(245,611	)

Net change in cash and cash equivalents		34,540			42,594
Cash and cash equivalents, beginning of period		335,432			333,765

Cash and cash equivalents, end of period	$	369,972		$	376,359

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, 2012 (File No. 1-13926).

As of July 25, 2013, 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),” or AOCGL, 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, 2013 and 2012.

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 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. See Note 9.

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.

Assets Held For Sale

In 2012, our management adopted a plan to actively market for sale three cold-stacked mid-water semisubmersibles (the Ocean Epoch, Ocean New Era and the Ocean Whittington) and one cold-stacked jack-up rig (the Ocean Spartan). In connection with the reclassification of these rigs to “Assets held for sale,” we measured the fair value of each rig in the disposal group using a probability-weighted cash flow analysis that utilized significant unobservable inputs, representing a Level 3 fair value measurement, which included assumptions for estimated proceeds that may be received upon disposition of the rig and estimated costs to sell. For our three mid-water semisubmersibles in the disposal group, we determined that, due to the expected resale market for rigs of this type and age, the highest and best use of these rigs would be for sale as scrap. Based on our analyses, we determined that the carrying values of the mid-water semisubmersible rigs in the disposal group were impaired as the carrying value for each exceeded its aggregate fair value and recognized an impairment loss in the fourth quarter of 2012. We determined that the carrying value of the Ocean Spartan was not impaired. At both June 30, 2013 and December 31, 2012, we reported “Assets held for sale” aggregating $11.6 million in our Consolidated Balance Sheets. See Note 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, 2013 and the year ended December 31, 2012, we capitalized $124.4 million and $220.3 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $60 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 three 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,
	2013			2012			2013			2012
	(In thousands)
Total interest cost, including amortization of debt issuance costs	$	25,089		$	21,228		$	48,994		$	43,636
Capitalized interest		(17,138	)		(8,497	)		(32,974	)		(15,576	)

Total interest expense as reported	$	7,951		$	12,731		$	16,020		$	28,060

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. There were no cold-stacked rigs at June 30, 2013 that were not being marketed for sale.

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, 2013, we recognized net foreign currency transaction gains of $0.4 million and $0.6 million, respectively. 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. See Note 5.

Revenue Recognition

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

Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (either lump-sum or dayrate). These fees are generally earned as services are performed over the initial term of the related drilling contracts. We defer contract preparation fees received as well as direct and incremental costs associated with the contract preparation activities and amortize each, on a straight-line basis, over the term of the related drilling contracts (which we estimate to be benefited from the contract preparation activity).

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 improvement.

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.

Recent Accounting Pronouncements

In July 2013, the Financial Accounting Standards Board issued Accounting Standards Update 2013-11, or ASU 2013-11, which eliminates diversity in practice for the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward is available to reduce the taxable income or tax payable that would result from disallowance of a tax position. ASU 2013-11 affects only the presentation of such amounts in an entity’s balance sheet and is effective for fiscal years beginning after December 15, 2013 and interim periods within those years. Early adoption is permitted. We are evaluating the impact, if any, of the adoption of ASU 2013-11 on our consolidated balance sheets.

2. Supplemental Financial Information

Consolidated Balance Sheets Information

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


	June 30,			December 31,
	2013			2012
	(In thousands)
Trade receivables	$	463,802		$	478,992
Value added tax receivables		9,827			13,884
Amounts held in escrow		17,264			11,555
Related party receivables		351			527
Other		92			160

		491,336			505,118
Allowance for bad debts		(5,458	)		(5,458	)

Total	$	485,878		$	499,660

Prepaid expenses and other current assets consist of the following:


	June 30,		December 31,
	2013		2012
	(In thousands)
Rig spare parts and supplies	$	50,738	$	57,558
Deferred mobilization costs		32,054		38,074
Prepaid insurance		28,244		12,549
Deferred tax assets		8,619		8,619
Prepaid taxes		17,429		5,950
FOREX contracts		1,204		3,627
Other		6,823		9,722

Total	$	145,111	$	136,099

Accrued liabilities consist of the following:


	June 30,		December 31,
	2013		2012
	(In thousands)
Rig operating expenses	$	74,761	$	70,078
Payroll and benefits		75,336		88,612
Deferred revenue		54,435		71,699
Accrued capital project/upgrade costs		82,109		56,595
Interest payable		21,219		21,219
Personal injury and other claims		11,170		10,312
FOREX contracts		10,353		29
Other		4,977		5,890

Total	$	334,360	$	324,434

Consolidated Statements of Cash Flows Information

Noncash investing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information is as follows:


	Six Months Ended June 30,
	2013		2012
	(In thousands)
Accrued but unpaid capital expenditures at period end	$	82,109	$	24,253
Cash interest payments⁽¹⁾⁽²⁾		41,469		41,656
Cash income taxes paid, net of refunds:
U.S. federal		47,000		33,000
Foreign		42,211		41,463
State		160		212

(1)	Interest payments, net of amounts capitalized, were $9.5 million and $26.3 million for the six months ended June 30, 2013 and 2012, respectively.

(2)	Interest paid included $0.2 million in interest on Internal Revenue Service assessments during the six months ended 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,
	2013		2012		2013		2012
	(In thousands, except per share data)
Net income – basic and diluted numerator:	$	185,334	$	201,461	$	361,323	$	386,630

Weighted average shares – basic (denominator):		139,035		139,029		139,034		139,028
Effect of dilutive potential shares
Stock options and stock appreciation rights		37		11		43		11

Weighted average shares including conversions – diluted (denominator)		139,072		139,040		139,077		139,039

Earnings per share:
Basic	$	1.33	$	1.45	$	2.60	$	2.78

Diluted	$	1.33	$	1.45	$	2.60	$	2.78

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,
	2013		2012		2013		2012
	(In thousands)
Employee and director:
Stock options		18		18		10		18
Stock appreciation rights		863		835		854		802

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, 2013
	Amortized Cost		Unrealized Gain (Loss)		Market Value
	(In thousands)
U.S. Treasury Bills and Notes (due within one year)	$	849,967	$	15	$	849,982
Mortgage-backed securities		237		13		250

Total	$	850,204	$	28	$	850,232


	December 31, 2012
	Amortized Cost		Unrealized Gain (Loss)		Market Value
	(In thousands)
U.S. Treasury Bills and Notes (due within one year)	$	1,149,707	$	150	$	1,149,857
Mortgage-backed securities		276		25		301

Total	$	1,149,983	$	175	$	1,150,158

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
Proceeds from maturities	$	1,025,000	$	750,000	$	1,750,000	$	1,250,000
Proceeds from sales		23		50,017		37		150,050
Gross realized gains		—		—		—		—
Gross realized losses		—		—		—		(5	)

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 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 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, 2013 and 2012, we settled FOREX contracts with aggregate notional values of approximately $157.0 million and $157.9 million, respectively, of which the entire aggregate amounts were designated as a cash flow accounting hedge. During the six-month periods ended June 30, 2013 and 2012, we did not enter into or settle any FOREX contracts that were not designated as accounting hedges.

The following table presents the aggregate amount of gain (loss) 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, 2013 and 2012.


	Three Months Ended June 30,					Six Months Ended June 30,
Location of Gain (Loss) Recognized in Income	2013		2012			2013		2012
	(In thousands)
Contract drilling expense	$	337	$	(1,199	)	$	2,772	$	(2,977	)

As of June 30, 2013, we had FOREX contracts outstanding in the aggregate notional amount of $222.3 million, consisting of $23.7 million in Australian dollars, $131.8 million in Brazilian reais, $28.6 million in British pounds sterling, $18.3 million in Mexican pesos and $19.9 million in Norwegian kroner. These contracts generally settle monthly through June 2014. As of June 30, 2013, all outstanding derivative contracts had been designated as cash flow hedges. See Note 6.

We have International Swap Dealers Association, or ISDA, contracts which are standardized master legal arrangements that establish key terms and conditions, which govern certain derivative transactions. These ISDA contracts contain standard credit-risk related contingent provisions, including the right to request early termination and net settlement of any outstanding derivative liability positions. Our ISDA arrangements also include master netting agreements to further manage counterparty credit risk associated with our FOREX contracts. We have elected not to offset the fair value amounts recorded for our FOREX contracts under these agreements in our Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012; however, there would have been no significant difference in our Consolidated Balance Sheets if the estimated fair values were presented on a net basis for these periods. At June 30, 2013, our FOREX contracts were with two counterparties, and we had no requirements to post collateral with the counterparties nor did we hold any collateral associated with our outstanding FOREX contracts.

The following table presents the fair values of our derivative FOREX contracts designated as hedging instruments at June 30, 2013 and December 31, 2012.


Balance Sheet Location	Fair Value				Balance Sheet Location	Fair Value
	June 30, 2013		December 31, 2012			June 30, 2013			December 31, 2012
	(In thousands)					(In thousands)
Prepaid expenses and other current assets	$	1,204	$	3,627	Accrued liabilities	$	(10,353	)	$	(29	)

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, 2013 and 2012.


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands)
Amount of (loss) gain recognized in AOCGL on derivative (effective portion)	$	(10,460	)	$	(1,923	)	$	(10,025	)	$	4,471
Location of gain (loss) reclassified from AOCGL into income (effective portion)		Contract drilling expense			Contract drilling expense			Contract drilling expense			Contract drilling expense
Amount of gain (loss) reclassified from AOCGL into income (effective portion)	$	389		$	(397	)	$	2,621		$	(2,427	)
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)	$	(116	)	$	(23	)	$	(118	)	$	(39	)

As of June 30, 2013, the estimated amount of net unrealized losses associated with our FOREX contracts that will be reclassified to earnings during the next twelve months was $9.0 million. The net unrealized losses associated with these derivative financial instruments will be reclassified to contract drilling expense. During the three-month and six-month periods ended June 30, 2013 and 2012, we did not reclassify any amounts from AOCGL due to the probability of an underlying forecasted transaction not occurring.

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 $119.7 million and $22.7 million, or 26% and 5%, respectively, of our total consolidated gross trade accounts receivable balances as of June 30, 2013, and $116.4 million and $80.3 million, or 24% and 17%, respectively, as of December 31, 2012.

At December 31, 2012, $17.2 million in trade accounts receivable was payable to us from a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing properties, which we believe is a real property interest. Our drilling program related to the NPI arrangement was completed in 2011, and the balance of the trade receivable due to us under the NPI arrangement was received in 2013. However, the customer who conveyed the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code on August 17, 2012. Certain parties (including the debtor) in the bankruptcy proceedings have questioned whether our NPI, and certain amounts we have received under it since the filing of the bankruptcy, should be included in the debtor’s estate under the bankruptcy proceeding. We have filed a declaratory judgment action in the bankruptcy court seeking a

declaration that our NPI, and payments that we have received from it since the filing of the bankruptcy, are not part of the bankruptcy estate, and we will vigorously defend our rights and pursue our interests in this matter.

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 at both June 30, 2013 and December 31, 2012. 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, 2013 consisted of cash held in money market funds of $329.6 million, time deposits of $20.0 million and investments in U.S. Treasury securities of $850.0 million. Our Level 1 assets at December 31, 2012 consisted of cash held in money market funds of $284.9 million and investments in U.S. Treasury securities of $1,149.9 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. Our Level 3 assets at June 30, 2013 and December 31, 2012 consisted of nonrecurring measurements of certain rigs held for sale for which we recorded an impairment loss in 2012. The value of these rigs was determined using a present value technique which utilized unobservable inputs such as assumptions for estimated proceeds that may be received on disposition of each rig and estimated costs to sell. See Note 1.

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. There were no transfers between fair value levels during the six-month periods ended June 30, 2013 and 2012.

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. In addition, certain assets and liabilities may be recorded at fair value on a nonrecurring basis. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. We did not record any impairment charges related to assets measured at fair value on a nonrecurring basis during the three-month and six-month periods ended June 30, 2013 and 2012.

Assets and liabilities measured at fair value are summarized below:


	June 30, 2013
	Fair Value Measurements Using							Assets at Fair Value
	Level 1		Level 2			Level 3		Assets at Fair Value
	(In thousands)
Recurring fair value measurements:
Assets:
Short-term investments	$	1,199,559	$	—		$	—	$	1,199,559
FOREX contracts		—		1,204			—		1,204
Mortgage-backed securities		—		250			—		250

Total assets	$	1,199,559	$	1,454		$	—	$	1,201,013

Liabilities:
FOREX contracts	$	—	$	(10,353	)	$	—	$	(10,353	)

Nonrecurring fair value measurements:
Assets:
Assets held for sale	$	—	$	—		$	3,900	$	3,900


	December 31, 2012
	Fair Value Measurements Using							Assets at Fair Value
	Level 1		Level 2			Level 3		Assets at Fair Value
	(In thousands)
Recurring fair value measurements:
Assets:
Short-term investments	$	1,434,751	$	—		$	—	$	1,434,751
FOREX contracts		—		3,627			—		3,627
Mortgage-backed securities		—		301			—		301

Total assets	$	1,434,751	$	3,928		$	—	$	1,438,679

Liabilities:
FOREX contracts	$	—	$	(29	)	$	—	$	(29	)

Nonrecurring fair value measurements:
Assets:
Assets held for sale	$	—	$	—		$	3,900	$	3,900

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 derived using a third-party pricing service at June 30, 2013 and December 31, 2012. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market 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, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
4.875% Senior Notes	$	269.5	$	249.9	$	275.5	$	249.8
5.15% Senior Notes		262.6		249.9		269.0		249.9
5.70% Senior Notes		587.0		496.9		641.4		496.9
5.875% Senior Notes		587.6		499.5		617.1		499.5

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,
	2013			2012
	(In thousands)
Drilling rigs and equipment	$	7,231,454		$	7,107,279
Construction work-in-progress		1,431,408			990,964
Land and buildings		64,643			64,296
Office equipment and other		63,187			60,239

Cost		8,790,692			8,222,778
Less: accumulated depreciation		(3,551,461	)		(3,357,806	)

Drilling and other property and equipment, net	$	5,239,231		$	4,864,972

During May 2013, we entered into a contract for the construction of a new ultra-deepwater semisubmersible rig. See Note 8. Construction work-in-progress, including capitalized interest, at June 30, 2013 and December 31, 2012 is summarized as follows:


	June 30,		December 31,
	2013		2012
	(In thousands)
Drillships	$	794,870	$	741,059
Ultra-deepwater semisubmersible		189,475		—
Deepwater semisubmersibles:
Ocean Onyx		264,583		167,403
Ocean Apex		182,480		82,502

Total construction work-in-progress	$	1,431,408	$	990,964

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 appealed the trial court’s decision, and the appellate court has remanded the case to trial. 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, 2013, our estimated liability for personal injury claims was $33.3 million, of which $9.4 million and $23.9 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2012, our estimated liability for personal injury claims was $36.1 million, of which $9.9 million and $26.2 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

Ultra-Deepwater Floater Construction. In May 2013, we entered into an agreement with Hyundai Heavy Industries, Co., Ltd., or Hyundai, for the construction of a 10,000 foot dynamically positioned, harsh environment semisubmersible drilling rig. The new rig will be constructed in South Korea at an estimated cost of $755 million, including capital spares, commissioning and shipyard supervision, and is expected to be delivered in the first quarter of 2016. The contracted price to Hyundai totaling $628.5 million is payable in two installments, of which the first installment of $188.6 million has been paid. The final installment is due upon delivery of the rig.

Drillship Construction. We are financially obligated under four separate turnkey construction contracts with Hyundai for the construction of four ultra-deepwater drillships. We expect the aggregate cost of the construction of our drillships, including commissioning, capital spares and project management costs, 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, aggregating $647.6 million. The Ocean BlackHawk and Ocean BlackHornet are expected to be delivered in the third and fourth quarters of 2013, respectively, and, at those times, the second installment of approximately $394 million will be payable to Hyundai for each rig. The Ocean BlackRhino and Ocean BlackLion are expected to be delivered in the second and fourth quarters of 2014, respectively, at which times approximately $395 million will be payable to Hyundai for each rig.

Ocean Onyx Construction. We are obligated under a vessel modification agreement with Keppel AmFELS, L.L.C., or Keppel, for the construction of the Ocean Onyx, a moored semisubmersible deepwater rig, which is expected to be delivered in the third quarter of 2013. We estimate the aggregate cost for the construction of the Ocean Onyx to be approximately $335.0 million, including commissioning, capital spares and project management costs. 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. To date, we have paid the first eight installments, of which $43.8 million and $65.7 million was paid in 2013 and 2012, respectively. The balance payable to Keppel under the construction agreement of $36.5 million is payable in the third quarter of 2013.

Ocean Apex Construction. We are obligated under a vessel modification agreement with Jurong Shipyard Pte Ltd, or Jurong, for the construction of the Ocean Apex, a moored semisubmersible deepwater rig, which is expected to be delivered in the second quarter of 2014 at an aggregate cost of approximately $370 million, including commissioning, capital spares and project management costs. The contracted price due to Jurong is payable in 12 installments based on the occurrence of certain events as detailed in the vessel modification agreement. We have paid the first four installments, of which $27.0 million was paid in each of 2013 and 2012.

Ocean Patriot Enhancements. In February 2013, we entered into a vessel modification agreement with Keppel FELS Limited, or Keppel Singapore, for enhancements to the Ocean Patriot that will enable the rig to work in the North Sea. We estimate the cost of the enhancement project to be approximately $120 million, including shipyard costs, owner-furnished equipment and labor, commissioning and capital spares. Construction work is expected to begin in Singapore in the third quarter of 2013 and to be completed in the first quarter of 2014. The contracted price due Keppel Singapore is approximately $29 million, payable in seven installments based on the occurrence of certain events as detailed in the vessel modification agreement. We paid the first installment due to Keppel Singapore in the amount of $5.8 million in March 2013.

At June 30, 2013 and December 31, 2012, 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, 2013 in the amount of $44.3 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit. Agreements relating to approximately $82.2 million of performance bonds can require collateral at any time. As of June 30, 2013, 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. Accumulated Other Comprehensive Gain (Loss)

The components of our AOCGL and related changes thereto are as follows:


	Unrealized Gain (Loss) on
	FOREX Contracts			Marketable Securities			Total AOCGL
	(In thousands)
Balance at January 1, 2013	$	2,350		$	146		$	2,496
Change in other comprehensive gain (loss) before reclassifications, after tax of $3,509 and $6		(6,516	)		9			(6,507	)
Reclassification adjustments for items included in Net Income, after tax of $917 and $18		(1,704	)		(132	)		(1,836	)

Balance at June 30, 2013	$	(5,870	)	$	23		$	(5,847	)

The following table presents the line items in our Consolidated Statements of Operations affected by reclassification adjustments out of AOCGL.


Major Category of AOCGL	Three Months Ended			Six Months Ended			Consolidated Statements of Operations Line Items
	June 30, 2013
	(In thousands)
Unrealized (gain) loss on FOREX contracts	$	(389	)	$	(2,621	)	Contract drilling, excluding depreciation
		136			917		Income tax expense

	$	(253	)	$	(1,704	)	Net of tax

Unrealized (gain) loss on marketable securities	$	(53	)	$	(150	)	Other, net
		4			18		Income tax expense

	$	(49	)	$	(132	)	Net of tax

10. Segments and Geographic Area Analysis

Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics due to the nature of the revenue earnings process as it relates to the offshore drilling industry over the operating lives of our drilling rigs.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
	(In thousands)
Floaters:
Ultra-Deepwater	$	231,101	$	233,071	$	422,458	$	477,659
Deepwater		184,105		142,565		348,525		288,568
Mid-Water		288,860		310,462		594,081		629,057

Total Floaters		704,066		686,098		1,365,064		1,395,284
Jack-ups		40,832		40,163		79,807		86,132

Total contract drilling revenues		744,898		726,261		1,444,871		1,481,416
Revenues related to reimbursable expenses		13,120		11,927		42,888		25,414

Total revenues	$	758,018	$	738,188	$	1,487,759	$	1,506,830

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, 2013, our actively-marketed drilling rigs were en route to or located offshore 12 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,
	2013		2012		2013		2012
	(In thousands)
United States	$	78,267	$	49,960	$	184,027	$	96,566
International:
South America		300,756		347,748		584,321		723,593
Australia/Asia		129,285		126,667		245,674		267,390
Europe/Africa/Mediterranean		201,249		160,397		373,955		321,905
Mexico		48,461		53,416		99,782		97,376

Total revenues	$	758,018	$	738,188	$	1,487,759	$	1,506,830

11. 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, we have not made a provision for U.S. income taxes on such earnings except to the extent that such earnings were immediately subject to U.S. income taxes.

During the first quarter of 2013, our tax expense was reduced by $27.5 million as a result of the American Taxpayer Relief Act of 2012, or the Act, which was signed into law on January 2, 2013. The Act extends through 2013 several expired temporary business provisions, commonly referred to as “extenders,” which were retroactively extended to the beginning of 2012. As required by GAAP, we recorded the retroactive effect of the extenders when the Act was signed into law.

Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions include years 2003 to 2012. We are currently under audit in several of these jurisdictions. We do not anticipate that any adjustments resulting from the tax audit of any of these years will have a material impact on our consolidated results of operations, financial condition and cash flows.

Mexico Tax Jurisdiction. The tax authorities in Mexico previously audited our income tax returns for the years 2004 and 2006 and had issued assessments for tax years 2004 and 2006 of approximately $22.9 million and $24.4 million, respectively, including interest and penalties, which we had appealed. In 2013 the Mexican tax authorities initiated a tax amnesty program whereby income tax assessments, including penalties and interest, could be partially or completely waived. Under the tax amnesty we were able to settle our tax liabilities for the years 2004 and 2006 for a net cash cost of $3.7 million but, primarily due to resulting increases in uncertain tax positions for later years, we recorded an additional $13.2 million of expense, including $5.0 million of interest and $2.7 million of penalties.

Due to the expiration of the statute of limitations in Mexico for the 2007 tax year at the end of June 2013, during the second quarter of 2013, we reversed our $4.3 million accrual for this uncertain tax position, of which $1.5 million was interest and $0.6 million was penalty.

On June 13, 2013 we received official notification that the Mexican tax authorities will be auditing the 2008 income tax return of one of our Mexican subsidiaries.

U.S. Tax Jurisdiction. In May 2013, we were notified by the Department of the Treasury that the Internal Revenue Service audit of our 2010 corporate tax return was completed without adjustment.

Brazil Tax Jurisdiction. In March 2013, the Brazilian tax authorities began an audit of our income tax returns for the years 2009 and 2010. We are continuing to defend tax assessments by the Brazilian tax authorities for the years 2000, 2004, 2005 and 2007.

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, 2012. 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. In May 2013, we announced the construction of a 10,000 foot, dynamically positioned, harsh environment semisubmersible rig, which will be constructed at an estimated cost of $755 million, including capital spares, commissioning and shipyard supervision costs. The rig will be constructed in South Korea and is expected to be delivered in the first quarter of 2016. The rig has been contracted for future operations offshore the coast of South Australia commencing in the second half of 2016. The addition of this rig will increase our total rig count to 45 offshore drilling rigs, consisting of 33 semisubmersibles, of which three are held for sale, seven jack-ups, of which one is held for sale, and five dynamically positioned drillships, four of which are under construction.

With respect to our other fleet expansion projects, we expect the first of our new drillships, the Ocean BlackHawk, to be delivered late in the third quarter of 2013 and a second unit, the Ocean BlackHornet, to be delivered near the end of 2013. We expect these rigs to be operating under contract in the GOM in the first and second quarters of 2014, respectively. The deepwater floater Ocean Onyx is expected to be delivered in the third quarter of 2013 and available for drilling service in the middle of the fourth quarter of 2013. Our remaining two newbuild drillships, the Ocean BlackRhino and Ocean BlackLion, are expected to be delivered in the second and fourth quarters of 2014, respectively. The deepwater floater Ocean Apex is expected to be delivered in the second quarter of 2014. Construction work pursuant to the North Sea rig enhancement project for the Ocean Patriot is expected to commence in the third quarter of 2013 with completion of the rig in the first quarter of 2014. The rig will then mobilize to the United Kingdom, or U.K., sector of the North Sea, for a contract commencing in the second quarter of 2014.

Market Overview

Floater Markets

Ultra-Deepwater and Deepwater Floaters. The ultra-deepwater and deepwater floater markets are generally firm. Expected industry-wide ultra-deepwater utilization for 2013 is near capacity, inclusive of the expected 2013 newbuild deliveries, as only two newbuild deliveries for 2013 have not yet been contracted. However, despite the strength of these markets, our ability to meet demand in the near term is limited due to our contracted backlog for the remainder of 2013 (100% and 97% for our ultra-deepwater and deepwater fleets, respectively). See “– Contract Drilling Backlog.”

Regionally, the offshore basins of West Africa, Brazil and the Gulf of Mexico continue to be an area of significant ultra-deepwater and deepwater activity where demand is firm, and in which dayrates are expected to remain steady throughout 2013. Discoveries in the pre-salt and post-salt formations offshore Brazil and pre-salt formation offshore West Africa, primarily Angola and Nigeria, have led to increased deepwater interest in these regions. On the Outer Continental Shelf of the Gulf of Mexico, drilling activity has surpassed pre-Macondo levels, and industry analysts predict that the market will continue to strengthen in 2013 and beyond, particularly in the ultra-deepwater market. Demand in the deeper waters of the U.S. Gulf of Mexico, or GOM, is tending more to newer deepwater and ultra-deepwater rigs due to a more rigorous regulatory environment, stronger focus on safety and prevention and more challenging formations. Three of our newest rigs, the Ocean BlackHawk, Ocean Onyx and Ocean BlackHornet, are contracted to work in the GOM.

As a result of the robust outlook for the ultra-deepwater and deepwater markets, there are a significant number of newbuild floaters on order by established drilling contractors, as well as new entrants into the industry, which is expected to lead to increased competition. As of the date of this report, based on industry reports, the total number of newbuild floaters on order or announced was reported to be in excess of 100 rigs, including an estimated 28 rigs to be built on behalf of Petrobras, which is currently our most significant customer. Excluding the Brazil-ordered rigs, over half of the newbuilds scheduled for delivery in 2014 through 2016 are not yet contracted for future work, including two of our drillships, the Ocean BlackRhino and Ocean BlackLion, and the deepwater floater Ocean Apex. Industry reports also indicate that several of the ultra-deepwater rigs are being contracted for operations in the deepwater market, which could lead to increased competition between ultra-deepwater and deepwater rigs.

Mid-Water Floaters. Market demand for mid-water floaters is generally stable. In both the U.K. and Norway sectors of the North Sea, the mid-water market is particularly strong. The mid-water market in other regions remains mixed but relatively stable. In the Mediterranean region, demand remains solid, although tempered by instability in Libya and Egypt. The Southeast Asia and Australia markets also remain steady with indications of possible strengthening.

As of the date of this report, our mid-water floaters in the aggregate were committed for 79% and 51% of the remainder of 2013 and of 2014, respectively. See “– Contract Drilling Backlog.”

Jack-up Market

We have six actively-marketed jack-up rigs, four of which are currently operating in the Mexican waters of the Gulf of Mexico, where drilling activity remains stable and additional tendering activity is ongoing, and another jack-up rig is contracted under a two-year bareboat charter offshore Ecuador through August 2014. Our sixth marketed jack-up rig began working under contract in the GOM during the second quarter of 2013, where contracts are generally well-to-well or short-term in duration.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of July 24, 2013, February 1, 2013 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2012), and July 16, 2012 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2012). 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 24, 2013		February 1, 2013		July 16, 2012
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽¹⁾	$	4,967,000	$	4,422,000	$	4,571,000
Deepwater⁽²⁾		987,000		1,229,000		1,218,000
Mid-Water⁽³⁾		2,178,000		2,649,000		2,599,000

Total Floaters		8,132,000		8,300,000		8,388,000
Jack-ups		229,000		272,000		226,000

Total	$	8,361,000	$	8,572,000	$	8,614,000

(1)

Contract drilling backlog as of July 24, 2013 for our ultra-deepwater floaters includes (i) $1.1 billion attributable to our contracted operations offshore Brazil for the years 2013 to 2015, (ii) $1.8 billion attributable to future work for two of our drillships under construction for the years 2013 to 2019 and (iii) $641.0 million attributable to future work for our ultra-deepwater semisubmersible rig under construction for the years 2016 to 2019.

(2)

Contract drilling backlog as of July 24, 2013 for our deepwater floaters includes (i) $431.0 million attributable to our contracted operations offshore Brazil for the years 2013 to 2016, including $49.0 million attributable to future work for OGX Petróleo e Gás Ltda, or OGX, 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 24, 2013 for our mid-water floaters includes $663.0 million attributable to our contracted operations offshore Brazil for the years 2013 to 2015, including $47.0 million attributable to future work for OGX.

As of the date of this report, $9.4 million of the $22.7 million owed to us at June 30, 2013 by OGX was past due. See Note 6 “Financial Instruments and Fair Value Disclosures” to our Consolidated Financial Statements in Item 1 of Part I of this report.

The following table reflects the amount of our contract drilling backlog by year as of July 24, 2013.


	For the Years Ending December 31,
	Total		2013 ⁽¹⁾		2014		2015		2016 - 2019
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽²⁾	$	4,967,000	$	501,000	$	1,167,000	$	1,332,000	$	1,967,000
Deepwater⁽³⁾		987,000		252,000		483,000		190,000		62,000
Mid-Water⁽⁴⁾		2,178,000		638,000		958,000		388,000		194,000

Total Floaters		8,132,000		1,391,000		2,608,000		1,910,000		2,223,000
Jack-ups		229,000		86,000		73,000		48,000		22,000

Total	$	8,361,000	$	1,477,000	$	2,681,000	$	1,958,000	$	2,245,000

(1)

Represents a six-month period beginning July 1, 2013.

(2)

Contract drilling backlog as of July 24, 2013 for our ultra-deepwater floaters includes (i) $263.0 million, $473.0 million and $324.0 million for the years 2013 to 2015, respectively, attributable to our contracted operations offshore Brazil, (ii) $256.0 million and $361.0 million for the years 2014 and 2015, respectively, and $1.2 billion in the aggregate for the years 2016 to 2019, attributable to future work for two of our drillships under construction and (iii) $641.0 million in the aggregate for the years 2016 to 2019 attributable to future work for our ultra-deepwater semisubmersible rig under construction.

(3)

Contract drilling backlog as of July 24, 2013 for our deepwater floaters includes (i) $89.0 million, $146.0 million, $134.0 million and $62.0 million for the years 2013 to 2016, respectively, attributable to our contracted operations offshore Brazil, including $34.0 million and $15.0 million for the years 2013 and 2014, respectively, attributable to future work for OGX, and (ii) $15.0 million and $164.0 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 24, 2013 for our mid-water floaters includes $243.0 million, $342.0 million and $79.0 million for the years 2013 to 2015, respectively, attributable to our contracted operations offshore Brazil, including $47.0 million in the remainder of 2013 attributable to future work for OGX.

The following table reflects the percentage of rig days committed by year as of July 24, 2013. 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 Apex, Ocean BlackRhino, Ocean BlackLion and our ultra-deepwater, harsh environment semisubmersible rig, which are all under construction.


	For the Years Ending December 31,
	2013 ⁽¹⁾			2014			2015			2016 - 2019
Rig Days Committed ⁽²⁾
Floaters:
Ultra-Deepwater		100	%		94	%		70	%		21	%
Deepwater		97	%		48	%		19	%		2	%
Mid-Water		79	%		51	%		17	%		2	%
All Floaters		88	%		63	%		35	%		8	%
Jack-ups		74	%		40	%		20	%		2	%

(1)

Represents a six-month period beginning July 1, 2013.

(2)

As of July 24, 2013, includes approximately 827, 1,125, 34 and 196 currently known, scheduled shipyard days for rig commissioning, contract preparation, surveys and extended maintenance projects, as well as rig mobilization days for the remainder of 2013, and for the years 2014, 2015 and 2016, 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 U.K. and Norwegian sectors of the North Sea.

During the final two quarters of 2013, seven of our rigs are expected to complete or undergo 5-year surveys. We expect these rigs to be out of service for approximately 440 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 230 days during the remainder of 2013 for the mobilization of rigs, contract acceptance testing and extended maintenance projects, excluding days associated with commissioning and contract preparation work for the Ocean BlackHawk and Ocean Onyx, which are under construction. 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 “ – 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, 2014, 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. Our policy’s war risk insurance excludes certain nationalization and deprivation coverage for the loss of use of rigs and equipment. We are evaluating the availability and cost of obtaining separate insurance coverage for these risks, although there is no assurance that we can obtain adequate insurance coverage for such events at rates we consider to be reasonable. 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, 2014, 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. During the second half of 2013, we expect to capitalize interest on qualifying expenditures related to the construction of our four new drillships, the Ocean Onyx, the Ocean Apex and our recently announced ultra-deepwater, harsh environment semisubmersible rig. We will continue to capitalize interest pursuant to these projects until such time, after the delivery of each rig, that activities related to making each respective vessel ready for service are no longer ongoing.

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, 2012. There were no material changes to these policies during the six months ended June 30, 2013.

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,
	2013			2012			2013			2012
REVENUE EARNING DAYS ⁽¹⁾
Floaters:
Ultra-Deepwater		672			649			1,198			1,269
Deepwater		451			377			873			777
Mid-Water		1,058			1,142			2,099			2,266
Jack-ups ⁽²⁾		469			419			918			941
UTILIZATION ⁽³⁾
Floaters:
Ultra-Deepwater		92	%		89	%		83	%		87	%
Deepwater		99	%		83	%		97	%		85	%
Mid-Water		65	%		66	%		64	%		66	%
Jack-ups ⁽⁴⁾		74	%		49	%		72	%		46	%
AVERAGE DAILY REVENUE ⁽⁵⁾
Floaters:
Ultra-Deepwater	$	341,800		$	354,000		$	350,000		$	359,000
Deepwater		408,600			371,600			399,200			365,000
Mid-Water		271,300			262,200			266,500			264,200
Jack-ups		88,400			94,100			86,800			90,000

⁽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⁾

Revenue earning days for the three and six months ended June 30, 2012 included approximately 0 and 87 days, respectively, earned by certain of our jack-up rigs during the period prior to being sold in 2012.

⁽³⁾

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).

⁽⁴⁾

Utilization for our jack-up rigs would have been 66% and 67%, respectively, for the three and six months ended June 30, 2012, excluding revenue earning days and total calendar days associated with rigs that we sold in 2012.

⁽⁵⁾

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, 2013 and 2012


	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
	(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater	$	231,101		$	233,071		$	422,458		$	477,659
Deepwater		184,105			142,565			348,525			288,568
Mid-Water		288,860			310,462			594,081			629,057

Total Floaters		704,066			686,098			1,365,064			1,395,284
Jack-ups		40,832			40,163			79,807			86,132

Total Contract Drilling Revenue	$	744,898		$	726,261		$	1,444,871		$	1,481,416

Revenues Related to Reimbursable Expenses	$	13,120		$	11,927		$	42,888		$	25,414
CONTRACT DRILLING EXPENSE
Floaters:
Ultra-Deepwater	$	128,147		$	137,087		$	263,923		$	277,048
Deepwater		60,126			68,653			116,562			127,375
Mid-Water		139,252			160,642			282,899			323,292

Total Floaters		327,525			366,382			663,384			727,715
Jack-ups		27,377			29,240			57,044			60,683
Other		14,134			9,630			23,702			13,956

Total Contract Drilling Expense	$	369,036		$	405,252		$	744,130		$	802,354

Reimbursable Expenses	$	12,805		$	11,637		$	42,094		$	24,788
OPERATING INCOME
Floaters:
Ultra-Deepwater	$	102,954		$	95,984		$	158,535		$	200,611
Deepwater		123,979			73,912			231,963			161,193
Mid-Water		149,608			149,820			311,182			305,765

Total Floaters		376,541			319,716			701,680			667,569
Jack-ups		13,455			10,923			22,763			25,449
Other		(14,134	)		(9,630	)		(23,702	)		(13,956	)
Reimbursable expenses, net		315			290			794			626
Depreciation		(97,143	)		(99,469	)		(193,964	)		(200,862	)
General and administrative expense		(16,435	)		(18,741	)		(33,250	)		(36,327	)
Bad debt recovery		—			400			—			1,018
Gain on disposition of assets		260			53,695			2,264			79,077

Total Operating Income	$	262,859		$	257,184		$	476,585		$	522,594

Other income (expense):
Interest income		271			1,496			888			3,279
Interest expense		(7,951	)		(12,731	)		(16,020	)		(28,060	)
Foreign currency transaction gain (loss)		448			1,083			607			979
Other, net		674			(274	)		420			(599	)

Income before income tax expense		256,301			246,758			462,480			498,193
Income tax expense		(70,967	)		(45,297	)		(101,157	)		(111,563	)

NET INCOME	$	185,334		$	201,461		$	361,323		$	386,630

The following is a summary as of the date of this report of the most significant transfers of our rigs during 2013 and 2012 between the geographic areas in which we operate:


Rig	Rig Type	Relocation Details	Date
*Floaters:*
Ocean Monarch	Ultra-Deepwater	Vietnam to Singapore (shipyard survey)	August 2012
Ocean Confidence	Ultra-Deepwater	Congo to Angola	January 2013
Ocean Guardian	Mid-Water	Falkland Islands 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 ^(a)	May 2012
Ocean Apex	Mid-Water	Singapore shipyard ^{(b )}	September 2012
Ocean Ambassador	Mid-Water	Brazil to GOM	October 2012
Ocean Lexington	Mid-Water	Brazil to Trinidad	March 2013
Ocean Patriot	Mid-Water	Vietnam to Philippines	May 2013
*Jack-ups:*
Ocean Columbia	Jack-up	Sold	March 2012
Ocean Heritage	Jack-up	Sold	April 2012
Ocean Drake	Jack-up	Sold (cold stacked June 2009)	May 2012
Ocean Champion	Jack-up	Sold (cold stacked June 2009)	May 2012
Ocean Crusader	Jack-up	Sold (cold stacked June 2009)	May 2012
Ocean Sovereign	Jack-up	Sold (cold stacked October 2011)	June 2012
Ocean Spur	Jack-up	Egypt to Ecuador; two year bareboat charter	August 2012
Ocean King	Jack-up	Montenegro to GOM	December 2012

(a)

Rig held for sale at December 31, 2012.

(b)

Rig formerly operated as the Ocean Bounty and was cold stacked in July 2009. Rig has been used in the construction of a deepwater floater in Singapore.

Overview

Three Months Ended June 30, 2013 and 2012

Operating Income. Operating income rose $5.7 million, or 2%, during the second quarter of 2013, compared to the same period of 2012, due to the combined effect of an $18.6 million, or 3%, increase in contract drilling revenue earned, a $36.2 million, or 9%, decrease in contract drilling expense incurred and reductions in depreciation and general and administrative expense ($4.6 million), partially offset by lower recognition of gains on disposition of assets in the 2013 period. Results for the second quarter of 2012 included an aggregate gain of $51.7 million on the sale of five of our jack-up rigs.

Contract drilling revenue for the second quarter of 2013 increased compared to the prior year quarter, primarily as a result of an increase in both revenue earning days and average daily revenue earned by our deepwater fleet ($41.5 million), partially offset by an 84-day decrease in revenue earning days for our mid-water fleet ($22.1 million). Contract drilling expense for our entire rig fleet decreased during the second quarter of 2013 compared to the same quarter in the prior year, reflecting lower costs associated with repairs, maintenance and mobilization of rigs, partially offset by higher labor costs.

Interest Expense. Interest expense decreased $4.8 million during the second quarter of 2013, compared to the same period in 2012, primarily due to an $8.6 million increase in interest capitalized on eligible construction projects during the second quarter of 2013 partially offset by a $3.8 million increase in interest expense, primarily related to an additional $3.6 million of interest expense associated with changes in uncertain tax positions in the Mexico tax jurisdiction. See “—Income Tax Expense.”

Income Tax Expense. Our effective tax rate for the three months ended June 30, 2013 was 27.7%, compared to an 18.4% effective tax rate for the three months ended June 30, 2012. The effective tax rate in the 2013 period was higher than in the same period of 2012 partially due to the mix of our domestic and international pre-tax earnings and losses but also as a result of the sale of two jack-up rigs at a zero tax rate during the 2012 period. Additionally, tax expense for the three months ended June 30, 2013 included $11.9 million of tax expense associated with settling

the 2004 and 2006 tax years in Mexico under an amnesty program which was partially offset by the reversal of $2.8 million of tax expense associated with the expiration of the statute of limitations in Mexico for the 2007 tax year.

Six Months Ended June 30, 2013 and 2012

Operating Income. Operating income decreased $46.0 million, or 9%, during the first half of 2013 compared to the same period of 2012, primarily due to a $36.5 million reduction in contract drilling revenue earned during the period, partially offset by reductions in contract drilling expense ($58.2 million) and depreciation expense ($6.9 million) attributable to the sale of six rigs in 2012 and the transfer of four rigs to assets held for sale at the end of 2012. Operating income for the first six months of 2012 included an aggregate gain of $79.1 million related to the sale of six of our jack-up rigs. Contract drilling revenue for our ultra-deepwater, mid-water and jack-up fleets decreased a combined $96.5 million during the first six months of 2013, compared to the prior year period, while revenue earned by our deepwater floaters increased $60.0 million. The decrease in contract drilling expense for the first six months of 2013 reflects lower mobilization and maintenance and repair costs for our fleet, partially offset by additional labor costs associated with crews for our newbuild drillships.

Interest Expense. Interest expense decreased $12.0 million during the six-month period ended June 30, 2013, compared to the same period in 2012, primarily due to a $17.4 million increase in interest capitalized on eligible construction projects during 2013 partially offset by a $5.4 million increase in interest expense during the period, primarily related to an additional $3.4 million in interest expense associated with uncertain tax positions in the Mexico tax jurisdiction. See “—Income Tax Expense.”

Income Tax Expense. Our effective tax rate for the six months ended June 30, 2013 was 21.9%, compared to a 22.4% effective tax rate for the six months ended June 30, 2012. The lower effective tax rate in the 2013 period was partially the result of a $27.5 million reduction in tax expense during the current period as a result of the American Taxpayer Relief Act of 2012 which was signed into law on January 2, 2013. However, tax expense for the period also included $11.9 million of tax expense associated with settling the 2004 and 2006 tax years in Mexico under an amnesty program which was partially offset by the reversal of $2.8 million of tax expense associated with the expiration of the statute of limitations in Mexico for the 2007 tax year. The effective tax rate for the six months ended June 30, 2012 was favorably impacted by the sale of two jack-up rigs at a zero tax rate during the second quarter of 2012.

Contract Drilling Revenue and Expense by Equipment Type

Three Months Ended June 30, 2013 and 2012

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters remained stable during the second quarter of 2013, decreasing $2.0 million from the prior year quarter, as a result of a decline in average daily revenue earned ($8.2 million) and a $2.0 million reduction in recognized mobilization revenue, partially offset by a 23-day increase in revenue earning days ($8.2 million) during the current year quarter. Contract drilling expense incurred by our ultra-deepwater floaters during the second quarter of 2013 decreased $8.9 million, reflecting reduced costs for repairs and maintenance, inspections, freight, and lower amortization of mobilization costs, partially offset by higher personnel costs, than in the comparable quarter of 2012.

Deepwater Floaters. Revenue generated by our deepwater floaters increased $41.5 million in the second quarter of 2013, compared to the same quarter in 2012, as a result of 74 incremental revenue earning days ($27.3 million), primarily due to the absence of downtime associated with the Ocean Star’s 5-year survey in 2012, and an increase in average daily revenue earned ($16.7 million) due to the Ocean Valiant and Ocean Victory currently working at significantly higher dayrates than those earned during the second quarter of 2012. However, these increases in contract drilling revenue, compared to the second quarter of 2012, were partially offset by lower recognized mobilization revenue ($2.4 million) during the 2013 period. Contract drilling expense incurred by our deepwater floaters decreased $8.5 million during the second quarter of 2013, compared to the second quarter of 2012, primarily due to lower amortized mobilization costs in the current quarter and the absence of costs associated with the Ocean Star’s 2012 survey.

Mid-Water Floaters. Revenue and contract drilling expense for our mid-water floaters decreased $21.6 million and $21.4 million, respectively, during the second quarter of 2013, compared to the same quarter in 2012. The reduction in revenue during the second quarter of 2013 was primarily due to 84 fewer revenue earning days ($22.1 million) and a $9.0 million decrease in recognized mobilization revenue, partially offset by an increase in average daily revenue earned ($9.6 million), compared to the prior year quarter. Revenue earning days declined during the second quarter of 2013 primarily as a result of 83 additional days of planned downtime for shipyard projects.

Contract drilling expense decreased in the second quarter of 2013, compared to the same quarter in 2012, primarily due to reduced costs for the Ocean Whittington and Ocean Ambassador ($13.7 million), both of which completed contracts in Brazil during 2012 and were relocated to the GOM, where the former rig is cold stacked and marketed for sale and the latter rig is ready stacked. In addition, contract drilling expense for the Ocean Guardian declined in the second quarter of 2013, compared to the same period of the prior year, due to the absence of incremental costs associated with a 2012 shipyard project and equipment recertifications after the rig’s return to the North Sea from the Falkland Islands ($10.9 million).

Jack-ups. Revenue earned by our jack-up rigs remained consistent, increasing $0.7 million in the second quarter of 2013, compared to the same period in 2012, while contract drilling expense decreased $1.9 million comparing the same periods.

Six Months Ended June 30, 2013 and 2012

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters decreased $55.2 million during the first half of 2013, compared to the same period in 2012, primarily due to 71 fewer revenue earning days ($25.6 million) as a result of incremental unplanned downtime for repairs, a $19.0 million reduction in amortized mobilization revenue and lower average daily revenue earned ($10.6 million). The reduction in mobilization revenue was primarily due to the recognition in the six-month period of 2012 of $16.2 million in amortized revenue associated with the Ocean Monarch’s mobilization to Vietnam and $4.0 million associated with the Ocean Rover’s demobilization from Indonesia to Malaysia. Contract drilling expense incurred by our ultra-deepwater floaters decreased $13.1 million during the first six months of 2013, compared to the same period of 2012, primarily due to lower amortized mobilization costs ($17.9 million) and lower freight costs ($6.3 million), partially offset by higher labor costs ($13.3 million).

Deepwater Floaters. Revenue generated by our deepwater floaters increased $60.0 million during the first six months of 2013, compared to the same period in 2012, as a result of higher average daily revenue earned ($29.8 million) and 96 incremental revenue earning days ($35.1 million), partially offset by lower amortized mobilization revenue ($4.9 million). Average daily revenue earned by our deepwater floaters increased primarily due to the Ocean Valiant and Ocean Victory both currently working at significantly higher dayrates than those rigs earned during the first half of 2012. The Ocean Star contributed 103 incremental revenue earning days in the first half of 2013, compared to the first half of 2012 when the rig had planned downtime for a special survey and shipyard project. Contract drilling expense declined $10.8 million in the first half of 2013, compared to the same period in 2012, reflecting lower costs for mobilization ($8.2 million), repairs, maintenance and inspections ($10.5 million) and freight ($2.3 million), partially offset by increases in personnel costs ($6.2 million) and shorebase support ($3.2 million).

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $35.0 million during the first half of 2013, compared to the same period in 2012, primarily as a result of 167 fewer revenue earning days ($44.1 million), partially offset by the effect of slightly higher average daily revenue earned ($4.8 million) and incremental recognition of mobilization and contract preparation fees ($4.3 million) during the first six months 2013. The decrease in revenue earning days was primarily the result of an increase in planned downtime for shipyard projects (220 additional days) and incremental downtime days for cold stacked rigs (100 additional days), partially offset by fewer mobilization days (102 fewer days) during which revenue was deferred and a reduction in unplanned downtime for repairs (68 fewer days).

Contract drilling expense decreased $40.4 million during the first six months of 2013, compared to the same period in 2012, primarily due to reduced costs for the stacked Ocean Whittington and Ocean Ambassador ($33.4 million), as well as for the Ocean Lexington, which also completed its contract in Brazil and subsequently relocated to Trinidad where it underwent contract preparation activities prior to beginning work under a new contract in mid-June 2013. Certain costs associated with contract preparation work for the rig have been deferred and will be recognized over the term of the contract in Trinidad. Additionally, the reduction in contract drilling expense in the first half of 2013, compared to same period in 2012, reflected the absence of costs associated with the 2012 demobilization of the Ocean Guardian from the Falkland Islands ($14.2 million) and repair and maintenance activities after arriving in the U.K. ($9.0 million). The reduction in contract drilling expense during the first half of 2013 was partially offset by incremental costs associated with surveys and shipyard projects for several rigs ($29.9 million).

Jack-ups. Revenue and contract drilling expense for our jack-up rigs decreased $6.3 million and $3.6 million, respectively, in the first six months of 2013, compared to the same period in 2012, primarily due to the sale of six jack-up rigs in 2012. Prior to being sold, these six rigs earned aggregate revenue and incurred contract drilling expense of $5.3 million and $7.3 million, respectively, during the first half of 2012. The decrease in contract drilling expense attributable to the rigs that were sold was partially offset by $4.7 million in incremental mobilization costs related to the return of the Ocean King to the GOM in early 2013.

Liquidity and Capital Resources

We have historically relied principally on our cash flows from operations and cash reserves to meet liquidity needs and fund our cash requirements. In addition, we currently have available a $750 million credit facility, or Credit Facility, to meet our short-term and long-term liquidity needs. See “ – Credit Facility.” As of July 24, 2013, our contract drilling backlog was $8.4 billion, of which $1.5 billion is expected to be earned in the last half of 2013.

At June 30, 2013 and December 31, 2012, we had cash available for current operations as follows:


	June 30,		December 31,
	2013		2012
	(In thousands)
Cash and equivalents	$	369,972	$	335,432
Marketable securities		850,232		1,150,158

Total cash available for current operations	$	1,220,204	$	1,485,590

A substantial portion of our cash flows has been and is expected to continue to be invested in the enhancement of our drilling fleet. We determine the amount of cash required to meet our capital commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs.

We pay dividends at the discretion of our Board of Directors, or Board, and, in recent years, we have a history of paying both regular quarterly and special cash dividends. During the six-month period ended June 30, 2013, we paid regular and special cash dividends totaling $34.8 million and $210.8 million, respectively. During the six-month period ended June 30, 2012, we paid regular and special cash dividends totaling $34.7 million and $211.0 million, respectively. Our Board has adopted a policy to consider paying special cash dividends, in amounts to be determined, on a quarterly basis. Our Board may, in subsequent quarters, consider paying additional special cash dividends, in amounts to be determined. Any determination to declare a special cash dividend, as well as the amount of any special cash dividend which may be declared, will be based on our financial position, earnings, earnings outlook, capital spending plans and other factors that our Board considers relevant at that time.

On July 24, 2013, we declared a regular cash dividend and a special cash dividend of $0.125 and $0.75, respectively, per share of our common stock. Both the quarterly and special cash dividends are payable on September 3, 2013 to stockholders of record on August 6, 2013.

Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Offshore International Limited, or DOIL, and, as a result of our intention to indefinitely reinvest the earnings of 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.

During the six-month period ended June 30, 2013, our primary source of cash was an aggregate $520.1 million generated from operating activities and $300.3 million in proceeds, primarily from the maturity of marketable securities, net of purchases. Our primary uses of cash during the same period were $542.9 million towards the construction of new rigs and our ongoing rig equipment enhancement/replacement program and $245.6 million for the payment of dividends.

During the six-month period ended June 30, 2012, our primary source of cash was an aggregate $613.3 million generated from operating activities and $136.6 million of proceeds, primarily from the sale of six of our jack-up rigs. Our primary uses of cash during the same period were $384.7 million towards the construction of new rigs and our

ongoing rig equipment enhancement/replacement program, $77.1 million toward the purchase of marketable securities, net of sales, and $245.7 million for the payment of dividends.

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.

Cash Flow, Capital Expenditures and Contractual Obligations

Our cash flow from operations and capital expenditures for the six-month periods ended June 30, 2013 and 2012 were as follows:


	Six Months Ended June 30,
	2013		2012
	(In thousands)
Cash flow from operations	$	520,122	$	613,345
Capital expenditures:
Drillship construction	$	55,139	$	190,159
Construction of deepwater floaters		219,020		49,284
Construction of ultra-deepwater floater		189,475		—
Ocean Patriot enhancement project		7,033		—
Rig equipment and replacement programs		72,256		145,250

Total capital expenditures	$	542,923	$	384,693

Cash Flow

Cash flow from operations decreased approximately $93.2 million during the first six months of 2013, compared to the first six months of 2012, primarily due to a $58.2 million decrease in cash receipts from contract drilling services, higher cash payments related to contract drilling expenses of $20.3 million and higher cash income taxes paid, net of refunds, of $14.7 million, primarily in the U.S. federal jurisdiction.

Capital Expenditures

At the date of this report, we expect capital expenditures for 2013 to aggregate approximately $1.9 billion, of which approximately $1.6 billion will be spent towards our rig construction projects. See “ — Contractual Cash Obligations — Rig Construction.” During the first six months of 2013, we spent $470.7 million toward these projects. We expect to fund our 2013 capital expenditures from 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. From time to time, however, we may also make use of our Credit Facility to finance our capital expenditures. See “—Credit Facility.”

Contractual Cash Obligations—Rig Construction

In May 2013, we entered into an agreement with Hyundai Heavy Industries, Co., Ltd., or Hyundai, for the construction of a 10,000 foot, dynamically positioned, harsh environment semisubmersible drilling rig. The new rig will be constructed in South Korea at an estimated cost of $755 million, including capital spares, commissioning and shipyard supervision, and is expected to be delivered in the first quarter of 2016. The contracted price to Hyundai totaling $628.5 million is payable in two installments, of which the first installment of $188.6 million has been paid. The final installment is due upon delivery of the rig.

In addition, we are financially obligated under other agreements with several shipyards in connection with the construction of four ultra-deepwater drillships, the deepwater floater Ocean Onyx, the deepwater floater Ocean Apex and the Ocean Patriot North Sea enhancement project. See Note 8 “Commitments and Contingencies” to our Consolidated Financial Statements included in Item 1 of Part I of this report for further discussion of these projects. We had no other purchase obligations for major rig upgrades or any other significant obligations at June 30, 2013, except for those related to our direct rig operations, which arise during the normal course of business.

The following is a summary of our construction projects as of June 30, 2013, including estimated expenditures to be made during the second half of 2013:


Project	Expected Delivery Date ⁽¹⁾		Total Project Cost ⁽²⁾		Total Project Expenditures ⁽³⁾		Capitalized Interest		Estimated Remaining Expenditures in 2013 ^{(4) (5)}
			(In millions)
New Rig Construction:
Drillships:
Ocean BlackHawk		Q3 2013	$	635	$	216	$	19	$	438
Ocean BlackHornet		Q4 2013		635		204		19		429
Ocean BlackRhino		Q2 2014		645		194		19		15
Ocean BlackLion		Q4 2014		655		180		11		6

				2,570		794		68		888
Ultra-Deepwater Floater		Q1 2016		755		189		1		6
Deepwater Floaters:
Ocean Onyx		Q3 2013		335		265		9		80
Ocean Apex		Q2 2014		370		182		3		96

			$	4,030	$	1,430	$	81	$	1,070
Ocean Patriot enhancement		Q1 2014	$	120	$	9	$	—	$	65

⁽¹⁾	Represents expected delivery date of vessel from shipyard and does not include additional non-operating days for commissioning, contract preparation and mobilization to initial area of operation, which will occur prior to the rig being placed in service.

⁽²⁾	Total project costs include contractual payments for shipyard construction, commissioning, capital spares and project management costs; amount does not include capitalized interest.

⁽³⁾	Includes project to date capitalized interest.

⁽⁴⁾	Excludes estimated interest to be capitalized in 2013.

⁽⁵⁾

Includes $393.5 million payable to Hyundai in each of the third and fourth quarters of 2013 upon delivery of the Ocean BlackHawk and Ocean BlackHornet, respectively. Includes construction milestone payments aggregating $36.5 million payable to Keppel AmFELS, L.L.C. in the third quarter of 2013 in connection with the construction of the Ocean Onyx.

Other Obligations

At June 30, 2013, we had foreign currency forward exchange, or FOREX, contracts in the aggregate notional amount of $222.3 million outstanding. See further information regarding these contracts in “Quantitative and Qualitative Disclosures About Market Risk – Foreign Exchange Risk” in Item 3 of Part I of this report and Note 5 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 1 of Part I of this report.

As of June 30, 2013, the total unrecognized tax benefits related to uncertain tax positions was $51.0 million. In addition, we have recorded a liability, as of June 30, 2013, for potential penalties and interest of $23.8 million and $11.6 million, respectively. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

Credit Facility

We have available to us a syndicated 5-year revolving credit agreement, or Credit Facility, that provides for a $750 million senior unsecured revolving credit facility, for general corporate purposes, which matures on September 28, 2017. The entire amount of the facility is available for revolving loans. Up to $250 million of the facility is available for the issuance of performance or other standby letters of credit and up to $75 million is available for swingline loans. As of June 30, 2013, there were no loans or letters of credit outstanding under the Credit Facility.

Credit Ratings

Our current credit rating is A3 for Moody’s Investors Services and 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.

Other Commercial Commitments—Letters of Credit

We were contingently liable as of June 30, 2013 in the amount of $97.3 million under certain performance, bid, supersedeas, tax appeal and custom bonds and letters of credit. Agreements relating to approximately $82.2 million of performance and tax appeal bonds can require collateral at any time. As of June 30, 2013, 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		2013		2014		Thereafter
	(In thousands)
Other Commercial Commitments
Customs bonds	$	1,651	$	843	$	808	$	—
Performance bonds		42,058		4,004		16,893		21,161
Other		590		590		—		—

Total obligations	$	44,299	$	5,437	$	17,701	$	21,161

Off-Balance Sheet Arrangements

At June 30, 2013 and December 31, 2012, we had no off-balance sheet debt or other arrangements.

Recent Accounting Pronouncements

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, without limitation, 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;

•

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 and 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, our ultra-deepwater floater under construction, the Ocean Onyx and the Ocean Apex) and other capital projects (including, without limitation, the Ocean Patriot enhancements);

•

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

•

plans and objectives of management;

•

idling drilling rigs or reactivating stacked rigs;

•

assets held for sale;

•

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, 2012;

•

general economic and business conditions, including, without limitation, 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, for example, in oil-producing regions and locations where our rigs are operating or where we have rigs under construction;

•

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, without limitation, 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, 2013 and December 31, 2012, 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, 2013 and December 31, 2012, 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, 2013 and December 31, 2012, 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 $114.1 million and $131.4 million as of June 30, 2013 and December 31, 2012, respectively. A 100-basis point decrease would result in an increase in market value of $132.8 million and $151.1 million as of June 30, 2013 and December 31, 2012, respectively.

Foreign Exchange Risk

Foreign exchange rate risk arises from the possibility that changes in foreign currency exchange rates will impact the value of financial instruments. It is customary for us to enter into FOREX contracts in the normal course of business. These contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period. As of June 30, 2013, we had FOREX contracts outstanding in the aggregate notional amount of $222.3 million, consisting of $23.7 million in Australian dollars, $131.8 million in Brazilian reais, $28.6 million in British pounds sterling, $18.3 million in Mexican pesos and $19.9 million in Norwegian kroner. These contracts generally settle monthly through June 2014.

At June 30, 2013, we presented the fair value of our outstanding FOREX contracts as a current asset of $1.2 million in “Prepaid expenses and other current assets” and a current liability of $(10.4) million in “Accrued liabilities” in our Consolidated Balance Sheets. At December 31, 2012, we presented the fair value of our outstanding FOREX contracts as a current asset of $3.6 million in “Prepaid expenses and other current assets” and a current liability of $(29,137) 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,
2013

December 31,
2012

June 30,
2013

December 31,
2012

(In thousands)

Interest rate:

Marketable securities

$850,200 (a)

$1,150,200 (a)

$(800) (b)

$(2,200) (b)

Foreign Exchange:

FOREX contracts – receivable positions

1,200 (c)

3,600 (c)

(17,200) (d)

(21,600) (d)

FOREX contracts – liability positions

(10,400) (c)

(29) (c)

(20,000) (d)

(4,900) (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, 2013 and December 31, 2012.

(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, 2013 and December 31, 2012.

(c)	The fair value of our FOREX contracts is based on both quoted market prices and valuations derived from pricing models on June 30, 2013 and December 31, 2012.

(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, 2013 and December 31, 2012, 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, 2013. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2013.

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 2013 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 31, 2013		By:	\s\ Gary T. Krenek
			Gary T. Krenek
			Senior Vice President and Chief Financial Officer

Date July 31, 2013			\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.