Edgar Filing: DIAMOND OFFSHORE DRILLING INC

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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, 2014

¨	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		(I.R.S. Employer
of incorporation or organization)		Identification No.)

15415 Katy Freeway

Houston, Texas

77094

(Address of principal executive offices)

(Zip Code)

(281) 492-5300

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes 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 23, 2014		Common stock, $0.01 par value per share		137,145,889 shares

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2014


		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		39

ITEM 4.	Controls and Procedures		40

PART II. OTHER INFORMATION			41

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds		41

ITEM 6.	Exhibits		41

SIGNATURES			42

EXHIBIT INDEX			43

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,
	2014			2013
ASSETS
Current assets:
Cash and cash equivalents	$	980,817		$	347,011
Marketable securities		350,156			1,750,053
Accounts receivable, net of allowance for bad debts		545,024			469,355
Prepaid expenses and other current assets		200,867			143,997
Asset held for sale		—			7,694

Total current assets		2,076,864			2,718,110
Drilling and other property and equipment, net of accumulated depreciation		6,055,990			5,467,227
Other assets		229,468			206,097

Total assets	$	8,362,322		$	8,391,434

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	121,164		$	94,151
Accrued liabilities		417,477			370,671
Taxes payable		11,583			30,806
Current portion of long-term debt		249,992			249,954

Total current liabilities		800,216			745,582
Long-term debt		2,244,336			2,244,189
Deferred tax liability		533,788			525,541
Other liabilities		237,034			238,864

Total liabilities		3,815,374			3,754,176

Commitments and contingencies (Note 10)
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; 143,958,250 shares issued and 137,145,889 shares outstanding at June 30, 2014; 143,952,248 shares issued and 139,035,448 shares outstanding at December 31, 2013)		1,440			1,440
Additional paid-in capital		1,991,293			1,988,720
Retained earnings		2,752,837			2,761,161
Accumulated other comprehensive gain (loss)		3,547			350
Treasury stock, at cost (6,812,361 and 4,916,800 shares of common stock at June 30, 2014 and December 31, 2013, respectively)		(202,169	)		(114,413	)

Total stockholders’ equity		4,546,948			4,637,258

Total liabilities and stockholders’ equity	$	8,362,322		$	8,391,434

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,
	2014			2013			2014			2013
Revenues:
Contract drilling	$	649,554		$	744,898		$	1,334,862		$	1,444,871
Revenues related to reimbursable expenses		42,690			13,120			66,806			42,888

Total revenues		692,244			758,018			1,401,668			1,487,759

Operating expenses:
Contract drilling, excluding depreciation		395,376			369,036			765,166			744,130
Reimbursable expenses		42,290			12,805			65,956			42,094
Depreciation		108,906			97,143			215,917			193,964
General and administrative		20,478			16,435			43,305			33,250
Gain on disposition of assets		(8,572	)		(260	)		(8,719	)		(2,264	)

Total operating expenses		558,478			495,159			1,081,625			1,011,174

Operating income		133,766			262,859			320,043			476,585
Other income (expense):
Interest income		150			271			558			888
Interest expense		(18,523	)		(7,951	)		(36,678	)		(16,020	)
Foreign currency transaction gain (loss)		(2,971	)		448			(4,149	)		607
Other, net		181			674			508			420

Income before income tax expense		112,603			256,301			280,282			462,480
Income tax expense		(22,890	)		(70,967	)		(44,759	)		(101,157	)

Net income .	$	89,713		$	185,334		$	235,523		$	361,323

Earnings per share, Basic and Diluted	$	0.65		$	1.33		$	1.71		$	2.60

Weighted-average shares outstanding:
Shares of common stock		137,145			139,035			137,803			139,034
Dilutive potential shares of common stock		4			37			5			43

Total weighted-average shares outstanding		137,149			139,072			137,808			139,077

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,
	2014			2013			2014			2013
Net income	$	89,713		$	185,334		$	235,523		$	361,323
Other comprehensive gains (losses), net of tax:
Derivative financial instruments:
Unrealized holding gain (loss)		2,882			(6,799	)		5,721			(6,516	)
Reclassification adjustment for gain included in net income		(2,360	)		(253	)		(2,537	)		(1,704	)
Investments in marketable securities:
Unrealized holding gain		1			2			39			9
Reclassification adjustment for gain included in net income		(18	)		(49	)		(26	)		(132	)

Total other comprehensive gain (loss)		505			(7,099	)		3,197			(8,343	)

Comprehensive income	$	90,218		$	178,235		$	238,720		$	352,980

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,
	2014			2013
Operating activities:
Net income	$	235,523		$	361,323
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		215,917			193,964
Gain on disposition of assets		(8,719	)		(2,264	)
Gain on foreign currency forward exchange contracts		(5,007	)		(2,772	)
Deferred tax provision		6,523			24,996
Accretion of discounts on marketable securities		(225	)		(514	)
Stock-based compensation expense		2,421			1,777
Deferred income, net		55,432			(22,595	)
Deferred expenses, net		(80,579	)		7,030
Long-term employee remuneration programs		3,952			4,319
Other assets, noncurrent		(144	)		(4,413	)
Other liabilities, noncurrent		2,334			(4,185	)
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges		5,007			2,772
Bank deposits denominated in nonconvertible currencies		5,442			—
Other		1,119			939
Changes in operating assets and liabilities:
Accounts receivable		(75,893	)		13,895
Prepaid expenses and other current assets		(18,857	)		(5,916	)
Accounts payable and accrued liabilities		40,948			(32,859	)
Taxes payable		(17,867	)		(15,375	)

Net cash provided by operating activities		367,327			520,122

Investing activities:
Capital expenditures (including rig construction)		(817,375	)		(542,923	)
Proceeds from disposition of assets, net of disposal costs		16,477			2,478
Proceeds from sale and maturities of marketable securities		5,800,033			1,750,038
Purchases of marketable securities		(4,399,889	)		(1,449,745	)

Net cash provided by (used in) investing activities		599,246			(240,152	)

Financing activities:
Payment of dividends		(244,364	)		(245,567	)
Purchase of treasury stock		(87,756	)		—
Other		(647	)		137

Net cash used in financing activities		(332,767	)		(245,430	)

Net change in cash and cash equivalents		633,806			34,540
Cash and cash equivalents, beginning of period		347,011			335,432

Cash and cash equivalents, end of period	$	980,817		$	369,972

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, 2013 (File No. 1-13926).

As of July 23, 2014, Loews Corporation owned 51.1 % 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

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 had bank deposits denominated in Egyptian pounds totaling $7.9 million and $14.3 million at June 30, 2014 and December 31, 2013, respectively. However, the local currency is not readily convertible into U.S. dollars or other currencies at this time. While we believe that a portion of these amounts will be used to fund local obligations in Egyptian pounds in the short term, we have reported $7.3 million and $12.7 million as “Other assets” in our Consolidated Balance Sheets at June 30, 2014 and December 31, 2013, respectively.

The effect of exchange rate changes on cash balances held in foreign currencies was not material for each of the three-month and six-month periods ended June 30, 2014 and 2013.

Marketable Securities

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 5.

Derivative Financial Instruments

Our derivative financial instruments consist primarily 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 11.

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 6 and 7.

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 three months ended June 30, 2014 and the year ended December 31, 2013, we capitalized $215.8 million and $302.0 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $70 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 ready for its intended use. 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.

Asset Held For Sale and 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. At December 31, 2013, we had four cold-stacked rigs, consisting of three mid-water semisubmersible rigs and one jack-up rig, the Ocean Spartan, which was reported as an “Asset held for sale” in our Consolidated Balance Sheets at a carrying value of $7.7 million. We sold the Ocean Spartan in June 2014 for an aggregate selling price of $16.5 million and recognized a net gain of $8.5 million on the transaction.

The three mid-water semisubmersible rigs remain cold stacked at June 30, 2014. We did not record any impairment with respect to our cold-stacked rigs for the three-month and six-month periods ended June 30, 2014 and 2013.

Treasury Stock

We account for the purchase of treasury stock using the cost method, which reports the cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated Balance Sheets. Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. During the six months ended June 30, 2014, we repurchased 1,895,561 shares of common stock at a cost of $87.8 million.

Capitalized Interest

We capitalize interest cost for qualifying construction and upgrade projects. See Note 8. 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,
	2014			2013			2014			2013
	(In thousands)
Total interest cost, including amortization of debt issuance costs	$	33,526		$	25,089		$	67,893		$	48,994
Capitalized interest		(15,003	)		(17,138	)		(31,215	)		(32,974	)

Total interest expense as reported	$	18,523		$	7,951		$	36,678		$	16,020

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, 2014, we recognized net foreign currency transaction (losses) of $(3.0) million and $(4.1) million, respectively. 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. See Note 6.

Revenue Recognition

We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive fees (on either a lump-sum or dayrate basis) 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 (on either a lump-sum or dayrate basis). 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 June 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2014-12, Compensation—Stock Compensation (Topic 718), or ASU 2014-12. The new standard amends existing standards to provide specific guidance on how to account for share-based payment awards that provide for

the achievement of a performance target after an employee completes the requisite service period (e.g., the employee is eligible to vest in the award regardless of whether the employee is rendering service on the date the performance target is achieved). ASU 2014-12 is effective for annual and interim periods within those annual periods beginning after December 15, 2015. Earlier adoption is permitted. We are currently evaluating the provisions of ASU 2014-12 and have not yet determined its impact on our financial position, results of operations or cash flows.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09. The new standard supersedes the industry-specific standards that currently exist under GAAP and provides a framework to address revenue recognition issues comprehensively for all contracts with customers regardless of industry-specific or transaction-specific fact patterns. Under the new guidance, companies recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. ASU 2014-09 also provides for additional disclosure requirements. ASU 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and may be adopted using a retrospective or modified retrospective approach. Early adoption is not permitted. We are currently evaluating the provisions of ASU 2014-09 and have not yet determined its impact on our financial position, results of operations or cash flows.

2. Supplemental Financial Information

Consolidated Balance Sheets Information

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


	June 30,			December 31,
	2014			2013
	(In thousands)
Trade receivables	$	539,732		$	473,013
Value added tax receivables		15,462			19,407
Amounts held in escrow		17,052			3,066
Related party receivables		459			587
Other		153			622

		572,858			496,695
Allowance for bad debts		(27,834	)		(27,340	)

Total	$	545,024		$	469,355

Prepaid expenses and other current assets consist of the following:


	June 30,		December 31,
	2014		2013
	(In thousands)
Rig spare parts and supplies	$	56,197	$	52,439
Deferred mobilization costs		51,826		20,274
Prepaid insurance		26,864		12,503
Deferred tax assets		10,222		10,221
Prepaid taxes		44,117		42,058
FOREX contracts		5,600		1,562
Other		6,041		4,940

Total	$	200,867	$	143,997

Accrued liabilities consist of the following:


	June 30,		December 31,
	2014		2013
	(In thousands)
Rig operating expenses	$	117,993	$	87,307
Payroll and benefits		104,386		121,387
Deferred revenue		72,382		26,975
Accrued capital project/upgrade costs		73,643		86,274
Interest payable		28,750		28,324
Personal injury and other claims		8,042		9,687
FOREX contracts		176		1,143
Other		12,105		9,574

Total	$	417,477	$	370,671

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,
	2014		2013
	(In thousands)
Accrued but unpaid capital expenditures at period end	$	73,643	$	82,109
Cash interest payments⁽¹⁾		63,560		41,469
Cash income taxes paid, net of refunds:
U.S. federal		—		47,000
Foreign		44,589		42,211
State		149		160

⁽¹⁾

Interest payments, net of amounts capitalized, were $33.3 million and $9.5 million for the six months ended June 30, 2014 and 2013, respectively.

3. Stock-Based Compensation

In March 2014, our Board of Directors adopted our Equity Incentive Compensation Plan, or Equity Plan, which amended and restated our Second Amended and Restated 2000 Stock Option Plan, or Stock Plan. The Equity Plan was approved by our stockholders in May 2014.

The Equity Plan amended the Stock Plan by, among other things:

•

increasing the number of shares of our common stock available for issuance under the Equity Plan from 1,500,000 shares to 7,500,000 shares;

•

increasing the annual limit on the number of shares of our common stock with respect to which awards may be granted to any single individual from 200,000 shares to 500,000 shares;

•

providing performance goals upon which the awards under the Equity Plan may be conditioned; and

•

providing for the grant of other stock-based awards (in addition to options and stock appreciation rights) that may be granted under the Equity Plan, including awards of restricted stock, restricted stock units, or RSUs, performance shares and units and other stock-based awards.

In March 2014, we awarded 52,581 in targeted performance RSUs, with a volume weighted average price of our common stock preceding the grant date of $47.52 per share, to our Chief Executive Officer, or CEO, in connection with his commencement of service with us on March 3, 2014, subject to stockholder approval of the Equity Plan. RSUs are contractual rights to receive shares of our common stock in the future if the applicable vesting conditions are met. Targeted RSUs will become earned RSUs upon achievement of certain performance goals as set forth in the award certificate. Earned RSUs granted to our CEO will vest in one-third increments annually, over three years, commencing on the first anniversary of his hire date, with the first year being prorated for the portion of 2014 during which he was employed.

Because the stock-based compensation awarded to our CEO is a fixed monetary amount at the date of grant (the target value of $3.0 million on a prorated basis) with variances based on actual achievement of a performance goal, the award is being recorded as a share-based liability. Compensation cost will be recognized over the requisite service period as specified in the award. In connection with the targeted RSUs granted in March 2014, we recognized $0.2 million and $0.3 million in compensation expense for the three-month and six-month periods ended June 30, 2014, respectively. As of June 30, 2014, the targeted performance goal, as set forth in the award certificate, had not been met, but its achievement was deemed probable.

4. 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,
	2014		2013		2014		2013
	(In thousands, except per share data)
Net income – basic and diluted numerator	$	89,713	$	185,334	$	235,523	$	361,323

Weighted average shares – basic (denominator):		137,145		139,035		137,803		139,034
Effect of dilutive potential shares
Stock options and stock appreciation rights		4		37		5		43

Weighted average shares including conversions – diluted (denominator)		137,149		139,072		137,808		139,077

Earnings per share:
Basic	$	0.65	$	1.33	$	1.71	$	2.60

Diluted	$	0.65	$	1.33	$	1.71	$	2.60

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,
	2014		2013		2014		2013
	(In thousands)
Employee and director:
Stock options		31		18		32		10
Stock appreciation rights		1,475		863		1,444		854

5. 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 7.

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


	June 30, 2014
	Amortized Cost		Unrealized Gain (Loss)		Market Value
	(In thousands)
U.S. Treasury Bills and Notes (due within one year)	$	349,993	$	1	$	349,994
Mortgage-backed securities		155		7		162

Total	$	350,148	$	8	$	350,156


	December 31, 2013
	Amortized Cost		Unrealized Gain (Loss)			Market Value
	(In thousands)
U.S. Treasury Bills and Notes (due within one year)	$	1,749,879	$	(22	)	$	1,749,857
Mortgage-backed securities		188		8			196

Total	$	1,750,067	$	(14	)	$	1,750,053

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


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands)
Proceeds from maturities	$	3,625,000	$	1,025,000	$	5,800,000	$	1,750,000
Proceeds from sales		12		23		33		37
Gross realized gains		—		—		—		—
Gross realized losses		—		—		—		—

6. 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 are 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, 2014 and 2013, we settled FOREX contracts with aggregate notional values of approximately $153.5 million and $157.0 million, respectively, of which the entire aggregate amounts were designated as a cash flow accounting hedge. During the six-month periods ended June 30, 2014 and 2013, 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 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, 2014 and 2013.


	Three Months Ended June 30,				Six Months Ended June 30,
Location of Gain Recognized in Income	2014		2013		2014		2013
	(In thousands)
Contract drilling expense	$	4,496	$	337	$	5,007	$	2,772

As of June 30, 2014, we had FOREX contracts outstanding in the aggregate notional amount of $167.2 million, consisting of $20.2 million in Australian dollars, $73.7 million in Brazilian reais, $47.1 million in British pounds sterling, $19.1 million in Mexican pesos and $7.1 million in Norwegian kroner. These contracts generally settle monthly through March 2015. As of June 30, 2014, all outstanding derivative contracts had been designated as cash flow hedges. See Note 7.

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. At June 30, 2014, all of our FOREX contracts were with two counterparties and were governed under such ISDA contracts. There are no requirements to post collateral under these contracts; however, they do contain credit-risk related contingent provisions including credit support provisions and the net settlement of amounts owed in the event of early terminations. Additionally, should our credit rating fall below a specified rating immediately following the merger of Diamond Offshore with another entity, the counterparty may require all outstanding derivatives under the ISDA contract to be settled immediately at current market value. 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, 2014 and December 31, 2013; 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.

The following table presents the fair values of our derivative FOREX contracts designated as hedging instruments at June 30, 2014 and December 31, 2013.


	Fair Value				Balance Sheet Location	Fair Value
Balance Sheet Location	June 30, 2014		December 31, 2013			June 30, 2014			December 31, 2013
	(In thousands)					(In thousands)
Prepaid expenses and other current assets	$	5,600	$	1,562	Accrued liabilities	$	(176	)	$	(1,143	)

The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated Statements of Operations related to our derivative financial instruments designated as cash flow hedges for the three-month and six-month periods ended June 30, 2014 and 2013, respectively.


	Three Months Ended June 30,					Six Months Ended June 30,
	2014		2013			2014			2013
	(In thousands)
*FOREX contracts:*
Amount of gain (loss) recognized in AOCGL on derivative (effective portion)	$	4,434	$	(10,460	)	$	8,802		$	(10,025	)
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)	$	3,630	$	389		$	3,899		$	2,621
Location of gain (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 gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	$	—	$	(116	)	$	(1	)	$	(118	)
*Treasury lock agreements:*
Amount of gain recognized in AOCGL on derivative (effective portion)		—		—			—			—
Location of gain reclassified from AOCGL into income (effective portion)		Interest Expense		—			Interest Expense			—
Amount of gain reclassified from AOCGL into income (effective portion)	$	2	$	—		$	4		$	—

As of June 30, 2014, the estimated amount of net unrealized gains associated with our FOREX contracts and treasury lock agreements that will be reclassified to earnings during the next twelve months was $5.4 million and $8,052, respectively. The net unrealized gains associated with these derivative financial instruments will be reclassified to contract drilling expense and interest expense, respectively. During the three-month and six-month periods ended June 30, 2014 and 2013, we did not reclassify any amounts from AOCGL due to the probability of an underlying forecasted transaction not occurring.

7. 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. At June 30, 2014 and December 31, 2013, our largest customer in Brazil, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government), accounted for $122.1 million and $154.5 million, or 24% and 35%, respectively, of our total consolidated net trade accounts receivable balance.

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. 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 and, historically, losses on our trade receivables have been infrequent occurrences.

In June 2014, we received $14.7 million from Niko Resources Ltd. pursuant to a settlement agreement entered into at the end of 2013 with respect to certain unpaid obligations under dayrate contracts. We recognized the entire $14.7 million as revenue in the second quarter of 2014, as revenue had not been previously recognized. At June 30, 2014, $40.3 million remained outstanding under the settlement agreement, payable at various times through March 2017.

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, 2014 consisted of cash held in money market funds of $945.1 million, time deposits of $20.1 million and investments in U.S. Treasury securities of $350.0 million. Our Level 1 assets at December 31, 2013 consisted of cash held in money market funds of $281.3 million, time deposits of $30.0 million and investments in U.S. Treasury securities of $1,749.9 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.

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, 2014 and 2013.

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, 2014 and 2013.

Assets and liabilities measured at fair value are summarized below:


	June 30, 2014
	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	$	1,315,258	$	—		$	—	$	1,315,258
FOREX contracts		—		5,600			—		5,600
Mortgage-backed securities		—		162			—		162

Total assets	$	1,315,258	$	5,762		$	—	$	1,321,020

Liabilities:
FOREX contracts	$	—	$	(176	)	$	—	$	(176	)


	December 31, 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	$	2,061,154	$	—		$	—	$	2,061,154
FOREX contracts		—		1,562			—		1,562
Mortgage-backed securities		—		197			—		197

Total assets	$	2,061,154	$	1,759		$	—	$	2,062,913

Liabilities:
FOREX contracts	$	—	$	(1,143	)	$	—	$	(1,143	)

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 senior notes, including current maturities, to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our senior notes was derived using a third-party pricing service at June 30, 2014 and December 31, 2013. 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 generally within a 10-day period of the report date. Fair values and related carrying values of our senior notes are shown below.


	June 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
5.15% Senior Notes due 2014	$	252.0	$	250.0	$	257.4	$	250.0
4.875% Senior Notes due 2015		261.1		249.9		265.7		249.9
5.875% Senior Notes due 2019		582.3		499.6		578.1		499.6
3.45% Senior Notes due 2023		250.7		249.0		241.4		249.0
5.70% Senior Notes due 2039		567.1		496.9		543.1		496.9
4.875% Senior Notes due 2043		757.0		748.8		736.1		748.8

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.

8. 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,
	2014			2013
	(In thousands)
Drilling rigs and equipment	$	8,649,093		$	7,412,066
Construction work-in-progress		1,232,313			1,668,211
Land and buildings		66,039			65,627
Office equipment and other		68,232			65,799

Cost		10,015,677			9,211,703
Less: accumulated depreciation		(3,959,687	)		(3,744,476	)

Drilling and other property and equipment, net	$	6,055,990		$	5,467,227

Construction work-in-progress, including capitalized interest, at June 30, 2014 and December 31, 2013 is summarized as follows:


	June 30,		December 31,
	2014		2013
	(In thousands)
Ultra-deepwater drillships	$	690,483	$	868,908
Ultra-deepwater semisubmersible:
Ocean GreatWhite		203,282		195,578
Deepwater semisubmersibles:
Ocean Onyx		—		339,129
Ocean Apex		338,548		264,596

Total construction work-in-progress	$	1,232,313	$	1,668,211

In January and February of 2014, the deepwater semisubmersible Ocean Onyx and the ultra-deepwater drillship Ocean BlackHawk, respectively, were placed in service and are no longer reported as construction work-in-progress at June 30, 2014.

9. Credit Agreement

We have a syndicated 5-Year Revolving Credit Agreement, or Credit Agreement, with Wells Fargo Bank, National Association, as administrative agent and swingline lender. Effective March 17, 2014, we entered into a commitment increase agreement and second amendment to the Credit Agreement, which, among other things, provided for a $250.0 million increase in the aggregate commitment under the revolving credit facility and an approximately six-month extension of the maturity date with all of the existing lenders. The Credit Agreement provides for a $1.0 billion senior unsecured revolving credit facility for general corporate purposes, maturing on March 17, 2019. The entire amount of the facility is available, subject to its terms, for revolving loans. Up to $250 million of the facility may be used for the issuance of performance or other standby letters of credit and up to $100 million may be used for swingline loans.

At June 30, 2014, we had no amounts outstanding under the Credit Agreement.

10. Commitments and Contingencies

Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. 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.

Asbestos 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 many 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.

Brazilian Withholding Contingency. Petróleo Brasileiro S.A., or Petrobras has notified us, along with other industry participants, that it is currently challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs for its operations in Brazil during the years 2008 and 2009. Petrobras has also notified us that if Petrobras is ultimately assessed and must pay such withholding taxes, it will seek reimbursement from us for the portion allocable to our drilling rigs. We dispute any basis for Petrobras to obtain such reimbursement, and we have notified Petrobras of our position. We will, if necessary, vigorously defend our rights. We are unable to estimate the amount of loss or range of loss, if any, at this time, should Petrobras ultimately be assessed such taxes and it be determined that Petrobras is entitled to obtain reimbursement from us. If we were required to pay such reimbursement, however, the amount of such reimbursement could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.

NPI Arrangement. We received customer payments measured by a percentage net profits interest (primarily of 27%) under an overriding royalty interest in certain developmental oil-and-gas producing properties, or NPI, which we believe is a real property interest. Our drilling program related to the NPI was completed in 2011, and the balance of the amounts due to us under the NPI 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 in August 2012. Certain parties (including the debtor) in the bankruptcy proceedings have questioned whether our NPI, and certain

amounts we received under it since the filing of the bankruptcy, should be included in the debtor’s estate under the bankruptcy proceeding. We filed a declaratory judgment action in the bankruptcy court seeking a declaration that our NPI, and payments that we received from it since the filing of the bankruptcy, are not part of the bankruptcy estate. We expect that once discovery is concluded in the bankruptcy court, the federal district court will hold a trial to determine the nature of our NPI. We will vigorously defend our rights and pursue our interests in this matter.

Personal Injury Claims. Under our current insurance policies that expire on May 1, 2015, our deductibles for marine liability insurance coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are $25.0 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 that 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, 2014, our estimated liability for personal injury claims was $36.4 million, of which $7.8 million and $28.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2013, our estimated liability for personal injury claims was $35.5 million, of which $9.5 million and $26.0 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. The Ocean GreatWhite, a 10,000 foot dynamically positioned, harsh environment semisubmersible drilling rig, is under construction in South Korea at an estimated cost of $755 million, including shipyard costs, capital spares, commissioning and shipyard supervision. The contracted price to Hyundai Heavy Industries Co., Ltd., or 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 of $439.9 million is due upon delivery of the rig, which is expected to occur in the first quarter of 2016.

Drillship Construction. At June 30, 2014, we had three remaining ultra-deepwater drillships under construction at Hyundai for an estimated aggregate cost of $1.9 billion, including shipyard costs, commissioning, capital spares and project management costs. 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 our drillships currently under construction, aggregating $493.2 million. The Ocean BlackHornet, Ocean BlackRhino and Ocean BlackLion are expected to be delivered in the third and fourth quarters of 2014 and the first quarter of 2015, respectively, at which times approximately $390 million will be payable to Hyundai for each rig.

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 fourth quarter of 2014 at an aggregate cost of approximately $370.0 million, including shipyard costs, 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 eight installments, in the aggregate amount of $87.8 million. The remaining $47.3 million in aggregate milestone payments are payable to Jurong during 2014 as construction milestones are met.

At June 30, 2014 and December 31, 2013, 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, 2014 in the amount of $99.6 million under certain performance, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $90.0 million of performance, supersedeas and customs bonds can require collateral at any time. As of June 30, 2014, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.

11. Accumulated Other Comprehensive Gain (Loss)

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


	Unrealized Gain (Loss) on
	Derivative Financial Instruments			Marketable Securities			Total AOCGL
	(In thousands)
Balance at January 1, 2014	$	357		$	(7	)	$	350
Change in other comprehensive gain (loss) before reclassifications, after tax of $(3,081) and $(16)		5,721			39			5,760
Reclassification adjustments for items included in Net Income, after tax of $1,366 and $7		(2,537	)		(26	)		(2,563	)

Balance at June 30, 2014	$	3,541		$	6		$	3,547

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


	Three Months Ended June 30,						Six Months Ended June 30,						Consolidated Statements of Operations Line Items
	2014			2013			2014			2013
Major Category of AOCGL	(In thousands)
Derivative Financial Instruments:
Unrealized (gain) loss on FOREX contracts	$	(3,630	)	$	(389	)	$	(3,899	)	$	(2,621	)	Contract drilling, excluding depreciation
Unrealized (gain) loss on Treasury Lock Agreements		(2	)		—			(4	)		—		Interest expense
		1,272			136			1,366			917		Income tax expense

	$	(2,360	)	$	(253	)	$	(2,537	)	$	(1,704	)	Net of tax

Marketable Securities:
Unrealized (gain) loss on marketable securities	$	(24	)	$	(53	)	$	(33	)	$	(150	)	Other, net
		6			4			7			18		Income tax expense

	$	(18	)	$	(49	)	$	(26	)	$	(132	)	Net of tax

12. 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 earning 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				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
	(In thousands)
Floaters:
Ultra-Deepwater	$	182,656	$	231,101	$	388,450	$	422,458
Deepwater		120,539		184,105		267,098		348,525
Mid-Water		300,902		288,860		586,881		594,081

Total Floaters		604,097		704,066		1,242,429		1,365,064
Jack-ups		45,457		40,832		92,433		79,807

Total contract drilling revenues		649,554		744,898		1,334,862		1,444,871
Revenues related to reimbursable expenses		42,690		13,120		66,806		42,888

Total revenues	$	692,244	$	758,018	$	1,401,668	$	1,487,759

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, 2014, our actively-marketed drilling rigs were en route to or located offshore 11 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,
	2014		2013		2014		2013
	(In thousands)
United States	$	128,639	$	78,267	$	243,508	$	184,027
International:
South America		262,072		300,756		549,996		584,321
Europe/Africa/Mediterranean		104,725		201,249		260,316		245,674
Australia/Asia		134,555		129,285		230,319		373,955
Mexico		62,253		48,461		117,529		99,782

Total revenues	$	692,244	$	758,018	$	1,401,668	$	1,487,759

13. 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.

Egypt Tax Jurisdiction. During 2013, we were under audit by the Egyptian tax authorities for the tax years 2006 through 2010. In December 2013, after receiving notification that the Egyptian government had concluded the income tax audit for the period 2006 to 2008 and proposed a $1.2 billion increase to taxable income, we accrued an additional $56.9 million of expense for uncertain tax positions in Egypt for all open years. During the first quarter of 2014, we settled certain disputes for the years 2006 through 2008 with the Egyptian tax authorities, which resulted in an aggregate $17.2 million reduction in tax expense, comprised of a $23.2 million reversal of uncertain tax positions, partially offset by $6.0 million in current income tax expense. One issue for the 2006 through 2008 period remains open, which we appealed. During the second quarter of 2014, the Appeals Committee in Egypt issued a decision regarding this open item, with which we disagree. In July 2014, we filed an objection with the Egyptian courts to continue disputing the matter. We are also seeking assistance from an agency of the U.S. Treasury Department, pursuant to international tax treaties, and continue to believe that our position will, more likely than not, be sustained. However, if our position is not sustained, tax expense and related penalties would increase by approximately $50 million related to this issue for the 2006 through 2008 tax years as of June 30, 2014.

United Kingdom Tax Jurisdiction. The U.K. Finance Act of 2014, or the Finance Act, was enacted in July 2014 with an effective date retroactive to April 1, 2014. Certain provisions of the Finance Act will limit the amount of tax deductions available with respect to our rigs working in the U.K. under bareboat charter arrangements, which could significantly increase our income tax expense in the U.K. We are actively reviewing various alternative arrangements under which our U.K. rigs could operate in order to minimize the impact of this legislative change.

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, 2013. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We are a leader in offshore drilling, providing contract drilling services to the energy industry around the globe with a fleet of 44 offshore drilling rigs, including five rigs under construction. Our fleet consists of 33 semisubmersibles, two of which are under construction, six jack-ups and five dynamically positioned drillships, three of which are under construction. As of the date of this report, three of our mid-water semisubmersible drilling rigs are cold stacked.

The recently completed deepwater floater Ocean Onyx has been working under a one-year contract in the U.S. Gulf of Mexico, or GOM, since mid-January, and the ultra-deepwater drillship Ocean BlackHawk recently began drilling operations under a five-year contract in the GOM.

During the latter half of 2014, we expect to take delivery of two additional ultra-deepwater drillships, the Ocean BlackHornet and Ocean BlackRhino, as well as the deepwater floater Ocean Apex. The remaining ultra-deepwater drillship, the Ocean BlackLion, and the harsh environment, ultra-deepwater semisubmersible Ocean GreatWhite are expected to be delivered in 2015 and 2016, respectively. Of these rigs, the Ocean BlackLion is not yet contracted.

The North Sea enhancement project for the Ocean Patriot was completed late in the second quarter of 2014 and the rig is en route to Hartlepool, England, where the rig will make final preparations for its three-year contract in the North Sea, which is expected to commence in the fourth quarter of 2014. The Ocean Confidence is currently undergoing a service-life-extension project in the Canary Islands, which is expected to keep the rig out of drilling service until early in the second quarter of 2015. We transferred nine months of contracted backlog from the Ocean Confidence to our third newbuild drillship, the Ocean BlackRhino, which we expect to commence in early 2015 in the GOM.

Market Overview

Floater Markets

Floater markets, in general, continue to weaken, and industry analysts predict that a depressed market will continue at least through 2015.

Ultra-Deepwater Floaters. Newbuild rig deliveries and established rigs coming off contract continue to fuel an oversupply of floaters in both the ultra-deepwater and deepwater markets. The oversupply of rigs, exacerbated by cutbacks and/or delays in customer drilling programs, has led to fierce competition for a limited number of jobs, resulting in lower contracted dayrates, the execution of shorter-term contracts and, in some cases, the idling of rigs. There have been few bidding opportunities during the first half of 2014, and the outlook for the remainder of the year and into 2015 is generally pessimistic. Dayrates may decline further, as some industry analysts predict that lower rates may be exchanged for utilization of newbuilds and higher specification rigs.

Deepwater Floaters. The market for deepwater floaters has continued to trend downward in tandem with the ultra-deepwater market. Demand in this market is intermittent, with limited bidding opportunities. As a result, multiple existing units face pockets of idle time in 2014 and 2015, and newbuild rigs may also have challenges securing work. Dayrates have also declined, compared to prior peak markets, and are projected by industry analysts to continue to soften in 2014.

Mid-Water Floaters. Conditions in the mid-water market varies by region. Market analysts predict further decline in contracted dayrates in most geographic markets. Frontier markets across Southeast Asia and South America, including Colombia, Myanmar, Nicaragua, Peru and Trinidad and Tobago, remain areas of future, possible market demand. Certain of our rigs are either currently working or contracted for future work in Colombia and Trinidad and Tobago; however, future opportunities in these areas are not expected to emerge quickly.

Impact of Newbuild Rigs and Other Challenges Facing the Offshore Drilling Industry

Since the beginning of 2014, nine newbuild floaters were ordered, based on industry data, adding to the supply of rigs competing in the offshore drilling market. As of the date of this report, based on industry data, there are approximately 65 competitive, or non-owner-operated, newbuild floaters on order, and, in addition, an estimated 29 rigs potentially to be built on behalf of Petróleo Brasileiro S.A., which is currently our largest single customer based on annual consolidated revenues. Of the competitive rigs, 26 of the 47 newbuilds scheduled for delivery in the second half of 2014 through 2015, including one of our drillships that we expect to be delivered in 2015, as well as over half of the 11 newbuilds scheduled for delivery in 2016, are not yet contracted for future work. Six of the seven newbuilds on order with an estimated delivery in 2017 have not yet been contracted. The influx of newbuilds into the market, combined with established rigs coming off contract in 2014 and 2015, is expected to contribute to the further weakening of the ultra-deepwater and deepwater floater markets.

In addition, the offshore drilling industry is challenged by growing regulatory demands and more complex customer specifications, which could disadvantage the marketability of some lower specification rigs. Customer focus on completing existing projects, possible reduction or deferral of new investment, reallocation of budgets away from offshore projects and particular customer requirements in certain markets could also displace, or reduce, demand and result in the migration of some ultra-deepwater rigs to work in deepwater and, likewise, some deepwater rigs to compete against mid-water units.

See “– Contract Drilling Backlog” for future commitments of our rigs during 2014 through 2020.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of July 23, 2014, February 5, 2014 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2013), and July 24, 2013 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2013). Contract drilling backlog as presented below includes only firm commitments (typically represented by signed contracts) and 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 generally 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.

In the second quarter of 2014, Statoil ASA, or Statoil, terminated its contract for the mid-water semisubmersible Ocean Vanguard. The contract, which provided for a dayrate of approximately $454,000, was estimated to conclude in accordance with its terms in late February 2015. We dispute Statoil’s basis for terminating the contract and intend to vigorously defend our rights under the contract. Contract drilling backlog for our mid-water floaters no longer includes an aggregate of approximately $107.0 million in previously reported backlog for the third quarter of 2014 through 2015, associated with Statoil’s contract for the Ocean Vanguard.


	July 23, 2014		February 5, 2014		July 24, 2013
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽¹⁾	$	3,751,000	$	4,111,000	$	4,967,000
Deepwater⁽²⁾		901,000		794,000		987,000
Mid-Water⁽³⁾		1,375,000		1,744,000		2,178,000

Total Floaters		6,027,000		6,649,000		8,132,000
Jack-ups		216,000		180,000		229,000

Total	$	6,243,000	$	6,829,000	$	8,361,000

⁽¹⁾

Contract drilling backlog as of July 23, 2014 for our ultra-deepwater floaters includes (i) $545.0 million attributable to our contracted operations offshore Brazil for the years 2014 to 2015, (ii) $904.0 million attributable to future work for the Ocean BlackHornet, which is under construction, for the years 2014 to 2020, (iii) $146.0 million attributable to future work for the Ocean BlackRhino, which is under construction, for 2015 and (iv) $641.0 million attributable to future work for the semisubmersible Ocean GreatWhite, which is also under construction, for the years 2016 to 2020.

⁽²⁾

Contract drilling backlog as of July 23, 2014 for our deepwater floaters includes (i) $275.0 million attributable to our contracted operations offshore Brazil for the years 2014 to 2016 and (ii) $36.0 million in 2015 attributable to future work for the Ocean Apex, which is under construction.

⁽³⁾

Contract drilling backlog as of July 23, 2014 for our mid-water floaters includes $237.0 million attributable to our contracted operations offshore Brazil for the years 2014 to 2015.

The following table reflects the amount of our contract drilling backlog by year as of July 23, 2014.


	For the Years Ending December 31,
	Total		2014 ⁽¹⁾		2015		2016		2017 - 2020
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽²⁾	$	3,751,000	$	552,000	$	1,191,000	$	499,000	$	1,509,000
Deepwater⁽³⁾		901,000		256,000		401,000		208,000		36,000
Mid-Water⁽⁴⁾		1,375,000		464,000		503,000		218,000		190,000

Total Floaters		6,027,000		1,272,000		2,095,000		925,000		1,735,000
Jack-ups		216,000		75,000		109,000		32,000		—

Total	$	6,243,000	$	1,347,000	$	2,204,000	$	957,000	$	1,735,000

⁽¹⁾	Represents a six-month period beginning July 1, 2014.

⁽²⁾

Contract drilling backlog as of July 23, 2014 for our ultra-deepwater floaters includes (i) $221.0 million and $324.0 million for the years 2014 and 2015, respectively, attributable to our contracted operations offshore Brazil, (ii) $180.0 million and $181.0 million for the years 2015 and 2016, respectively, and $543.0 million in the aggregate for the years 2017 to 2020, attributable to future work for the Ocean BlackHornet, which is under construction, (iii) $146.0 million for 2015 attributable to future work for the Ocean BlackRhino, which is under construction, and (iv) $107.0 million for the year 2016 and $534.0 million in the aggregate for the years 2017 to 2020 attributable to future work for the Ocean GreatWhite, which is also under construction.

⁽³⁾

Contract drilling backlog as of July 23, 2014 for our deepwater floaters includes (i) $79.0 million, $134.0 million and $62.0 million for the years 2014 to 2016, respectively, attributable to our contracted operations offshore Brazil and (ii) $36.0 million in 2015 attributable to future work for the Ocean Apex, which is under construction.

⁽⁴⁾	Contract drilling backlog as of July 23, 2014 for our mid-water floaters includes $158.0 million and $79.0 million for the years 2014 and 2015, respectively, attributable to our contracted operations offshore Brazil.

The following table reflects the percentage of rig days committed by year as of July 23, 2014. 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 BlackHornet, Ocean Apex, Ocean BlackRhino, Ocean BlackLion and Ocean GreatWhite, all of which are under construction.


	For the Years Ending December 31,
	2014 ⁽¹⁾			2015			2016			2017 - 2019
Rig Days Committed ⁽²⁾
Floaters:
Ultra-Deepwater		87	%		67	%		26	%		20	%
Deepwater		57	%		39	%		21	%		1	%
Mid-Water		58	%		28	%		12	%		4	%
All Floaters		66	%		42	%		18	%		9	%
Jack-ups		62	%		39	%		11	%		—

⁽¹⁾

Represents a six-month period beginning July 1, 2014.

⁽²⁾

As of July 23, 2014, includes approximately 503, 40 and 238 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 2014 and for the years 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 shipyard time, except for rigs, generally older than 15 years, that are located in the United Kingdom, or U.K., sector of the North Sea.

During the remainder of 2014, three of our rigs are expected to undergo 5-year surveys. We expect these rigs to be out of service for an estimated 136 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 342 days during the remainder of 2014 for intermediate surveys, the mobilization of rigs, contract acceptance testing and extended maintenance projects, including mobilization of the Ocean Patriot to the U.K. and contract preparation work (approximately 90 days) and our service-life-extension project for the Ocean Confidence (approximately 180 days in 2014), which is expected to be completed early in the second quarter of 2015. 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 GOM. If a named windstorm in the GOM 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 current insurance policies that expire on May 1, 2015, we carry physical damage insurance for certain losses, other than those caused by named windstorms in the GOM, for which our deductible for physical damage is $25.0 million per occurrence. Our policy’s war risk insurance excludes from coverage certain risks of loss of use of rigs and equipment in connection with nationalization and deprivation. We currently retain separate insurance coverage for these risks in certain countries in which we operate. Additionally, we may, from time to time, seek to obtain insurance coverage for such risks in additional countries in which we may operate in the future to the extent such coverage is available. There is no assurance, however, that we will be able to retain or obtain, as the case may be, adequate levels of such coverage for such events at rates and with deductibles that we consider to be reasonable, or that we will continue to retain such coverage in the future or obtain such coverage in any particular jurisdiction. We do not typically retain loss-of-hire insurance policies to cover our rigs.

In addition, under our current insurance policies that expire on May 1, 2015, 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 $25.0 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 that might arise during the policy year, which under the current policy commences on May 1.

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 first half of 2014, we ceased capitalization of interest related to the construction of the Ocean Onyx and Ocean BlackHawk as a result of the completion of these projects, but will continue to capitalize interest during the remainder of 2014 for our remaining three drillships under construction, the Ocean Apex and the Ocean GreatWhite. Capitalization of interest will continue for these construction 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.

Consequently, we expect our reported interest expense to increase in 2014, compared to the previous year, as a result of fewer projects qualifying for capitalization of interest in 2014, combined with the impact of additional interest expense associated with fourth quarter of 2013 debt issuances.

U.K. Finance Act. The U.K. Finance Act of 2014, or the Finance Act, was enacted in July 2014 with an effective date retroactive to April 1, 2014. Certain provisions of the Finance Act will limit the amount of tax deductions available with respect to our rigs working in the U.K. under bareboat charter arrangements, which could significantly increase our income tax expense in the U.K. We are actively reviewing various alternative arrangements under which our U.K. rigs could operate in order to minimize the impact of this legislative change.

Impact of Changes in Tax Laws or Their Interpretation or Enforcement. We operate through our various subsidiaries in a number of countries throughout the world. As a result, we are subject to highly complex tax laws, treaties and regulations in the jurisdictions in which we operate, which may change and are subject to interpretation. Changes in laws, treaties and regulations and the interpretation or enforcement of such laws, treaties and regulations may put us at risk for future tax assessments and liabilities which could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.

For example, Petróleo Brasileiro S.A., or Petrobras has notified us, along with other industry participants, that it is currently challenging assessments by Brazilian tax authorities of withholding taxes associated with the provision of drilling rigs for its operations in Brazil during the years 2008 and 2009. Petrobras has also notified us that if Petrobras is ultimately assessed and must pay such withholding taxes, it will seek reimbursement from us for the portion allocable to our drilling rigs. We dispute any basis for Petrobras to obtain such reimbursement, and we have notified Petrobras of our position. We will, if necessary, vigorously defend our rights. We are unable to estimate the amount of loss or range of loss, if any, at this time, should Petrobras ultimately be assessed such taxes and it be determined that Petrobras is entitled to obtain reimbursement from us. If we were required to pay such reimbursement, however, the amount of such reimbursement could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows. See Note 10 “Commitments and Contingencies” to our Consolidated Financial Statements included in Item 1 of Part I of this report.

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, 2013. There were no material changes to these policies during the six months ended June 30, 2014.

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,
	2014			2013			2014			2013
REVENUE EARNING DAYS ⁽¹⁾
Floaters:
Ultra-Deepwater		420			672			933			1,198
Deepwater		281			451			624			873
Mid-Water		1,107			1,058			2,136			2,099
Jack-ups		464			469			965			918
UTILIZATION ⁽²⁾
Floaters:
Ultra-Deepwater		51	%		92	%		58	%		83	%
Deepwater		51	%		99	%		58	%		97	%
Mid-Water		68	%		65	%		66	%		64	%
Jack-ups		74	%		74	%		77	%		72	%
AVERAGE DAILY REVENUE ⁽³⁾
Floaters:
Ultra-Deepwater	$	402,800		$	341,800		$	394,100		$	350,000
Deepwater		418,400			408,600			418,300			399,200
Mid-Water		265,600			271,300			270,700			266,500
Jack-ups		96,700			88,400			94,800			86,800

⁽¹⁾

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

⁽²⁾

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

⁽³⁾

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014			2013
	(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater	$	182,656		$	231,101		$	388,450		$	422,458
Deepwater		120,539			184,105			267,098			348,525
Mid-Water		300,902			288,860			586,881			594,081

Total Floaters		604,097			704,066			1,242,429			1,365,064
Jack-ups		45,457			40,832			92,433			79,807

Total Contract Drilling Revenue	$	649,554		$	744,898		$	1,334,862		$	1,444,871

Revenues Related to Reimbursable Expenses	$	42,690		$	13,120		$	66,806		$	42,888
CONTRACT DRILLING EXPENSE
Floaters:
Ultra-Deepwater	$	122,327		$	128,147		$	245,857		$	263,923
Deepwater		81,641			60,126			153,590			116,562
Mid-Water		148,931			139,252			282,977			282,899

Total Floaters		352,899			327,525			682,424			663,384
Jack-ups		29,851			27,377			57,880			57,044
Other		12,626			14,134			24,862			23,702

Total Contract Drilling Expense	$	395,376		$	369,036		$	765,166		$	744,130

Reimbursable Expenses	$	42,290		$	12,805		$	65,956		$	42,094
OPERATING INCOME
Floaters:
Ultra-Deepwater	$	60,329		$	102,954		$	142,593		$	158,535
Deepwater		38,898			123,979			113,508			231,963
Mid-Water		151,971			149,608			303,904			311,182

Total Floaters		251,198			376,541			560,005			701,680
Jack-ups		15,606			13,455			34,553			22,763
Other		(12,626	)		(14,134	)		(24,862	)		(23,702	)
Reimbursable expenses, net		400			315			850			794
Depreciation		(108,906	)		(97,143	)		(215,917	)		(193,964	)
General and administrative expense		(20,478	)		(16,435	)		(43,305	)		(33,250	)
Gain on disposition of assets		8,572			260			8,719			2,264

Total Operating Income	$	133,766		$	262,859		$	320,043		$	476,585

Other income (expense):
Interest income		150			271			558			888
Interest expense		(18,523	)		(7,951	)		(36,678	)		(16,020	)
Foreign currency transaction gain (loss)		(2,971	)		448			(4,149	)		607
Other, net		181			674			508			420

Income before income tax expense		112,603			256,301			280,282			462,480
Income tax expense		(22,890	)		(70,967	)		(44,759	)		(101,157	)

NET INCOME	$	89,713		$	185,334		$	235,523		$	361,323

The following is a summary as of the date of this report of the most significant transfers of our rigs during 2014 and 2013 between the geographic areas in which we operate:


Rig	Rig Type	Relocation Details	Date
*Floaters:*
Ocean Confidence	Ultra-Deepwater	Congo to Angola	January 2013
Ocean Confidence	Ultra-Deepwater	Angola to Cameroon	February 2014
Ocean Endeavor	Ultra-Deepwater	Egypt to Romania	February 2014
Ocean BlackHawk	Ultra-Deepwater	South Korea to GOM (initial mobilization)	February 2014
Ocean Confidence	Ultra-Deepwater	Cameroon to Canary Islands (life-extension project)	April 2014
Ocean Clipper	Ultra-Deepwater	Brazil to Colombia	June 2014
Ocean America	Deepwater	Australia to Singapore (shipyard survey)	July 2013
Ocean Valiant	Deepwater	Cameroon to Canary Islands (shipyard survey)	October 2013
Ocean America	Deepwater	Singapore to Australia	November 2013
Ocean Onyx	Deepwater	Placed in service (GOM)	January 2014
Ocean Lexington	Mid-Water	Brazil to Trinidad	March 2013
Ocean Patriot	Mid-Water	Vietnam to Philippines	May 2013
Ocean Saratoga	Mid-Water	GOM to Nicaragua	August 2013
Ocean Quest	Mid-Water	Brazil to Malaysia	November 2013
Ocean Patriot	Mid-Water	Philippines to Singapore (shipyard upgrade)	November 2013
Ocean Saratoga	Mid-Water	Nicaragua to GOM	December 2013
Ocean General	Mid-Water	Vietnam to Indonesia	March 2014
Ocean Patriot	Mid-Water	Singapore to U.K.	June 2014
Ocean Vanguard	Mid-Water	Norway to U.K.	June 2014
*Jack-ups:*
Ocean Titan	Jack-up	Mexico to GOM	June 2014
Ocean Spartan	Jack-up	Sold	June 2014

Overview

Three Months Ended June 30, 2014 and 2013

Operating Income. Operating income decreased $129.1 million, or 49%, during the second quarter of 2014, compared to the same period of 2013, primarily due to a $95.3 million, or 13%, reduction in contract drilling revenue combined with the negative effect of higher contract drilling costs ($26.3 million), depreciation ($11.8 million) and general and administrative expense ($4.0 million). Depreciation expense increased during the current year quarter primarily due to a higher depreciable asset base in 2014, compared to 2013, that includes the Ocean Onyx and Ocean BlackHawk, which were placed in service during the first quarter of 2014. General and administrative expense for the second quarter of 2014 reflects higher compensation and professional services costs than those incurred during the second quarter of 2013. These unfavorable results were partially offset by an $8.8 million net gain on the sale of the previously held for sale jack-up rig Ocean Spartan during the second quarter of 2014.

Contract drilling revenue for our ultra-deepwater and deepwater fleets decreased $112.0 million during the second quarter of 2014, compared to the same quarter of 2013, primarily as a result of an aggregate of 422 fewer revenue earning days while, comparing the same periods, revenue earned by our mid-water floaters and jack-up rigs increased an aggregate $16.7 million. These results include $14.7 million in revenue recognized during the second quarter of 2014 pursuant to a settlement agreement executed with Niko Resources Ltd., or Niko, in late 2013 with respect to certain obligations under previously terminated dayrate contracts for the Ocean Monarch and Ocean Lexington.

Contract drilling expense for our rig fleet increased by an aggregate of $26.3 million during the second quarter of 2014, compared to the same quarter of the prior year, primarily as a result of increased costs for rig repairs and maintenance ($11.0 million), rig mobilizations ($8.8 million) and regulatory inspections ($5.7 million).

Interest Expense. Interest expense increased $10.6 million during the second quarter of 2014, compared to the same period in 2013, primarily due to incremental interest expense of $11.5 million related to $1.0 billion in senior unsecured notes that we issued in November 2013, combined with a decrease in capitalized interest of $2.1 million due to the completed construction of the Ocean BlackHawk and Ocean Onyx in 2014. The increase in interest expense was partially offset by the absence of $3.6 million of interest expense recognized in the prior year quarter associated with changes in uncertain tax positions in the Mexico tax jurisdiction.

Income Tax Expense. Our effective tax rate for the three months ended June 30, 2014 was 20.3%, compared to a 27.7% effective tax rate for the three months ended June 30, 2013. The effective tax rate in the 2014 period was lower compared to the same period in 2013 primarily due to the mix of our domestic and international pre-tax earnings and losses. The 2013 period also included an aggregate $9.1 million of income tax expense to close several prior tax years in Mexico.

Six Months Ended June 30, 2014 and 2013

Operating Income. Operating income decreased $156.5 million, or 33%, during the first six months of 2014, compared to the same period of 2013, primarily due to a $110.0 million, or 8%, reduction in contract drilling revenue combined with increases in contract drilling expense ($21.0 million), depreciation expense ($22.0 million), and general and administrative expense ($10.1 million). Depreciation expense increased during the current year period primarily due to a higher depreciable asset base in 2014, compared to 2013. Higher compensation costs and professional fees contributed to the increase in general and administrative expense for the first half of 2014. The decline in operating income during the first six months of 2014 was partially offset by $6.5 million in incremental gains recognized on the sale of assets, including $8.8 million related to the sale of the Ocean Spartan in June 2014.

Contract drilling revenue for our floater fleet decreased by an aggregate of $122.6 million during the first half of 2014, compared to the same period of 2013, primarily as a result of an aggregate of 477 fewer revenue earning days ($151.8 million) and lower mobilization and contract preparation fees ($16.9 million). The decline in contract drilling revenue was partially offset by higher average daily revenue earned by our floater rigs in the aggregate ($31.4 million) and $14.7 million in revenue recognized during the first half of 2014 pursuant to the Niko settlement agreement. In contrast, contract drilling revenue earned by our jack-up rigs increased by an aggregate of $12.6 million during the first six months of 2014, compared to the prior year period, attributable to a 47-day increase in revenue earning days combined with higher average daily revenue earned during the current year period.

Contract drilling expense for our rig fleet increased by an aggregate of $21.0 million during the first six months of 2014, compared to the same period of the prior year, primarily as a result of higher costs associated with labor and personnel ($4.5 million), rig repair and maintenance ($7.6 million), rig mobilization ($4.6 million), inspections ($2.7 million) and overhead ($9.9 million), partially offset by lower freight costs ($5.5 million) and agency fees ($4.7 million).

Interest Expense. Interest expense increased $20.7 million during the six-month period ended June 30, 2014, compared to the same period in 2013, primarily due to incremental interest expense of $22.8 million related to our November 2013 debt issuance, combined with a decrease in capitalized interest of $1.8 million as a result of rig construction projects completed in 2014. The increase in interest expense was partially offset by the absence of $3.4 million of interest expense recognized in the prior year period associated with changes in uncertain tax positions in the Mexico tax jurisdiction.

Income Tax Expense. Our effective tax rate for the six months ended June 30, 2014 was 16.0%, compared to a 21.9% effective tax rate for the six months ended June 30, 2013. The effective tax rate in the 2014 period was lower than in the same period of 2013 primarily due to the mix of our domestic and international pre-tax earnings and losses. The 2014 period also included the settlement of certain disputes in Egypt for the years 2006 through 2008, resulting in an aggregate $17.2 million reduction in tax expense. During the 2013 period we recognized the impact of The American Taxpayer Relief Act of 2012, which reduced 2013 income tax expense by $27.5 million. This favorable 2013 impact was partially offset by an aggregate $9.1 million increase in income tax expense to close several prior tax years in Mexico.

Contract Drilling Revenue and Expense by Equipment Type

Three Months Ended June 30, 2014 and 2013

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters decreased $48.4 million in the second quarter of 2014, compared to the prior year quarter, as a result of 252 fewer revenue earning days ($86.3 million), partially offset by the favorable effect of higher average daily revenue earned ($25.6 million) and $11.2 million in revenue recognized during the current year quarter under the settlement agreement with Niko. The reduction in revenue earning days in the second quarter of 2014, compared to the second quarter of 2013, was primarily due to downtime associated with planned shipyard projects and inspections (176 incremental days),

mobilization of rigs (49 incremental days) and unplanned downtime between contracts (63 incremental days), partially offset by less downtime for unscheduled repairs (36 fewer days). Average daily revenue increased primarily due to a contract extension for the Ocean Rover, effective at the end of the first quarter of 2014, at a significantly higher dayrate than previously earned.

Contract drilling expense for our ultra-deepwater floaters decreased $5.8 million during the second quarter of 2014, compared to the same quarter of 2013, reflecting lower costs incurred for labor and benefits ($15.5 million) and the mobilization of rigs ($3.9 million), partially offset by incremental operating costs for our new drillship, the Ocean BlackHawk ($6.4 million), and increased costs for rig repairs and maintenance ($5.1 million) and inspections ($3.1 million). Reductions in personnel costs in the second quarter of 2014 relate primarily to a change in staffing requirements for three of our ultra-deepwater floaters that were in a shipyard during the 2014 period for extensive projects.

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $63.6 million in the second quarter of 2014, compared to the same quarter in 2013, primarily due to 170 fewer revenue earning days ($69.4 million) in the current year quarter, partially offset by higher average daily revenue earned ($2.8 million) and recognition of $3.0 million in deferred revenue associated with rig mobilizations and capital upgrades. The reduction in revenue earning days was the result of incremental unplanned downtime for the warm stacking of rigs between contracts (182 additional days) and scheduled downtime for surveys (81 additional days), partially offset by 91 revenue earning days for the Ocean Onyx, which was placed in service in January 2014.

Contract drilling expense incurred by our deepwater floaters increased $21.5 million during the second quarter of 2014, compared to the same quarter of 2013, primarily related to the inclusion of operating costs for the Ocean Onyx ($7.9 million) and incremental costs for the Ocean Alliance, primarily associated with its 5-year survey in 2014 ($14.4 million).

Mid-Water Floaters. Revenue generated by our mid-water floaters increased $12.0 million in the second quarter of 2014, compared to the same quarter in 2013, primarily due to 49 incremental revenue earning days ($13.4 million), recognition of $3.6 million in revenue under the settlement agreement with Niko, and higher mobilization and contract preparation revenue ($1.4 million) in the second quarter of 2014. The increase in revenue earning days during the second quarter of 2014 reflected reduced downtime for planned shipyard inspections and projects (133 fewer days) and unplanned downtime between contracts (57 fewer days), partially offset by planned downtime for the Ocean Patriot’s North Sea enhancement project (91 incremental days) and unexpected downtime for the Ocean Vanguard as a result of the early termination of its contract offshore Norway (53 days). Comparing the two quarters, average daily revenue earned decreased in the second quarter of 2014 ($6.3 million), as most of our mid-water fleet, excluding our North Sea rigs, are currently working at lower dayrates than those previously earned in 2013.

Contract drilling expense for our mid-water fleet increased by an aggregate of $9.7 million in the second quarter of 2014, compared to the prior year quarter. Excluding the Ocean Patriot, which was out of service for the entire second quarter of 2014, contract drilling expense increased, compared to the prior year quarter, due to higher labor and personnel-related costs ($9.5 million) and increased mobilization costs ($7.0 million). Contract drilling expense for the Ocean Patriot decreased $6.6 million in the second quarter of 2014 due to reduced operating costs while in the shipyard.

Jack-ups. Contract drilling revenue and expense for our jack-up fleet increased $4.6 million and $2.5 million, respectively, during the second quarter of 2014, compared to the prior year quarter. The increase in revenue was primarily due to higher average daily revenue earned ($3.9 million) due to several of our jack-up rigs currently operating at higher dayrates than those earned during the prior year quarter.

Six Months Ended June 30, 2014 and 2013

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters decreased $34.0 million in the first six months of 2014, compared to the prior year period, as a result of 265 fewer revenue earning days ($92.9 million), partially offset by the favorable effects of higher average daily revenue earned ($41.1 million) combined with the recognition of $11.2 million in revenue under the settlement agreement with Niko during the current year period. The reduction in revenue earning days in the first half of 2014, compared to the prior year period, was primarily due to incremental downtime for planned inspections and shipyard projects (173 additional days), including the Ocean Confidence life-extension project, non-revenue earning days between contracts (153 additional days) and rig mobilizations (73 additional days), partially offset by less unscheduled downtime for repairs (116 fewer days) and 17 revenue earning days for the Ocean BlackHawk, which was placed in service in the first quarter

of 2014. Average daily revenue increased primarily due to significantly higher dayrates earned by the Ocean Confidence offshore Cameroon throughout the first quarter of 2014 and the Ocean Rover under a contract extension beginning in March 2014, compared to dayrates previously earned by these rigs in the first half of 2013.

Contract drilling expense for our ultra-deepwater floaters decreased $18.1 million during the first half of 2014, compared to the same period of 2013, reflecting lower costs incurred for labor and benefits ($17.5 million), the mobilization of rigs ($7.6 million), agency fees ($2.8 million) and freight ($2.0 million), partially offset by incremental operating costs for our new drillship, the Ocean BlackHawk ($7.5 million), and higher shorebase and overhead costs ($5.2 million). Reductions in personnel costs in the first half of 2014 relate primarily to a change in staffing requirements for three of our ultra-deepwater floaters that were in a shipyard during the 2014 period for extensive projects.

Deepwater Floaters. Revenue generated by our deepwater floaters decreased $81.4 million in the first half of 2014, compared to the same period in 2013, primarily due to 249 fewer revenue earning days ($99.5 million) in the current year period, partially offset by higher average daily revenue earned ($11.9 million) and recognition of $6.1 million in mobilization and contract preparation revenue. The reduction in revenue earning days was the result of incremental downtime for planned surveys and shipyard projects (146 additional days) combined with unplanned downtime associated with the warm stacking of rigs between contracts (265 additional days), partially offset by 152 revenue earning days for the Ocean Onyx. The increase in average daily revenue earned was primarily attributable to the Ocean America, which began work under a new contract in December 2013 at a significantly higher dayrate than previously earned.

Contract drilling expense incurred by our deepwater floaters increased $37.0 million during the first six months of 2014, compared to the same period of 2013, primarily due to incremental operating costs for the Ocean Onyx ($15.5 million) and incremental contract drilling expense for the Ocean Alliance, primarily associated with its five-year survey ($19.8 million).

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $7.2 million during the first six months of 2014, compared to the same period in 2013, while contract drilling expense remained relatively unchanged. The decrease in revenue during the first six months of 2014 was primarily attributable to lower mobilization and contract preparation revenue earned ($29.6 million), partially offset by the favorable effects of 37 incremental revenue earning days ($9.8 million), higher average daily revenue earned ($9.1 million) and recognition of $3.6 million in revenue under the settlement agreement with Niko. The increase in revenue earning days during the current year period reflects the net impact of fewer downtime days for planned repairs, regulatory inspections and rig mobilizations (230 fewer days), partially offset by an increase in downtime associated with the North Sea enhancement project for the Ocean Patriot (165 additional days) and incremental unplanned downtime (28 days). The increase in average daily revenue earned during the current year period resulted primarily from the Ocean Guardian and Ocean Vanguard operating at higher contracted dayrates during the first half of 2014, compared to the prior year period.

Jack-ups. Contract drilling revenue and expense for our jack-up fleet increased $12.6 million and $1.0 million, respectively, during the first six months of 2014, compared to the prior year period. The increase in revenue was primarily due to $12.9 million in contract drilling revenue earned by the Ocean King, which had been warm stacked in Montenegro, Italy, and did not begin operating in the GOM until the second quarter of 2013. The increase in contract drilling expense during the first six months of 2014, compared to the same period in 2013, primarily resulted from higher labor and personnel-related costs ($3.9 million) and incremental costs of regulatory inspections ($1.6 million), partially offset by the absence of costs associated with the 2013 mobilization of the Ocean King to the GOM ($4.5 million).

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 $1.0 billion credit facility to meet our short-term and long-term liquidity needs. See “ – Credit Agreement.” As of July 23, 2014, our contract drilling backlog was $6.2 billion, of which $1.3 billion is expected to be realized in the last half of 2014.

At June 30, 2014 and December 31, 2013, we had cash available for current operations as follows:


	June 30,		December 31,
	2014		2013
	(In thousands)
Cash and equivalents	$	980,817	$	347,011
Marketable securities		350,156		1,750,053

Total cash available for current operations	$	1,330,973	$	2,097,064

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.

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. We expect to utilize 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. to meet each entity’s respective working capital requirements and capital commitments. However, in light of the significant cash requirements of our capital expansion program in 2014 and 2015, we may also make use of our credit facility to finance our capital expenditures, working capital requirements and/or to maintain a certain level of operating cash reserves. In addition, we will make periodic assessments of our capital spending programs based on industry conditions and make adjustments thereto if required. See “ — Cash Flow, Capital Expenditures and Contractual Obligations — Contractual Cash Obligations — Rig Construction” and “—Credit Agreement.”

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, 2014, we paid regular and special cash dividends totaling $34.5 million and $209.9 million, respectively. 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. 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 23, 2014, 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 2, 2014 to stockholders of record on August 6, 2014.

Depending on market and other conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. During the six-month period ended June 30, 2014, we purchased 1,895,561 shares of our common stock at an aggregate cost of $87.8 million. See Item 2, “Unregistered Sales of Equity Securities and Use of Proceeds” in Part II of this report. We did not purchase any shares of our outstanding common stock during the six-month period ended June 30, 2013. In addition, Loews Corporation, or Loews, has informed us that, depending on market and other conditions, it may, from time to time, purchase shares of our common stock in the open market or otherwise. Loews did not purchase any shares of our outstanding common stock during the six-month periods ended June 30, 2014 or 2013.

During the six-month period ended June 30, 2014, our primary source of cash was an aggregate $367.3 million generated from operating activities, $1.4 billion in proceeds, primarily from the maturity of marketable securities, net of purchases, and $16.5 million from the disposition of assets, primarily from the sale of the Ocean Spartan in June 2014. Our primary uses of cash during the same period were $817.4 million towards the construction of new rigs and our ongoing rig equipment enhancement/replacement program, $244.4 million for the payment of dividends and $87.8 million for the repurchase of shares.

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.

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, 2014 and 2013 were as follows:


	Six Months Ended June 30,
	2014		2013
	(In thousands)
Cash flow from operations	$	367,327	$	520,122
Cash capital expenditures:
Drillship construction	$	465,103	$	55,139
Construction of deepwater floaters		94,307		219,020
Construction of ultra-deepwater floater		7,703		189,475
Ocean Patriot enhancement project		66,239		7,033
Rig equipment and replacement programs		184,023		72,256

Total capital expenditures	$	817,375	$	542,923

Cash Flow

Cash flow from operations decreased approximately $152.8 million during the first six months of 2014, compared to the first six months of 2013, primarily due to lower cash receipts from contract drilling services ($97.9 million) and an increase in cash payments for contract drilling expenses ($99.5 million), primarily for expenditures associated with rig mobilizations and contract preparation work, partially offset by lower cash income taxes paid, net of refunds ($44.6 million).

Capital Expenditures

As of the date of this report, we expect our capital spending for 2014 to aggregate approximately $2.0 billion, of which approximately $1.5 billion and $135.0 million will be spent on our rig construction projects and a service-life-extension project for the Ocean Confidence, respectively. During the first six months of 2014, we incurred $689.5 million in project-related expenditures, including accrued expenditures. See “ — Contractual Cash Obligations — Rig Construction.” Our 2014 capital spending program also includes an estimated $282.0 million for our ongoing capital maintenance and replacement programs of which $115.2 million had been incurred as of June 30, 2014.

Contractual Cash Obligations—Rig Construction

As of the date of this report, we have five ongoing rig construction/enhancement projects at three shipyards to which we are financially obligated. Four rigs are being constructed in South Korea and one project is underway in Singapore. See Note 10 “Commitments and Contingencies” to our Consolidated Financial Statements included in Item 1 of Part I of this report for further discussion of these projects.

The following is a summary of our construction projects as of June 30, 2014, including estimated expenditures to be made during the remaining six months of 2014:


	Actual Inception-to-Date
Project	Expected Delivery ⁽¹⁾		Total Project Cost ⁽²⁾		Project Expenditures ⁽³⁾		Capitalized Interest		Last Six Months of 2014 ^{(4) (5)}
			(In millions)
New Rig Construction:
Drillships:
Ocean BlackHornet		Q3 2014	$	635	$	222	$	31	$	415
Ocean BlackRhino		Q4 2014		645		209		31		437
Ocean BlackLion		Q1 2015		655		177		21		24

				1,935		608		83		876
Ultra-Deepwater Floater:
Ocean GreatWhite		Q1 2016		755		192		11		6
Deepwater Floater:
Ocean Apex		Q4 2014		370		324		15		54

			$	3,060	$	1,124	$	109	$	936

⁽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⁾	Represents total project expenditures from inception of project to June 30, 2014, excluding project-to-date capitalized interest.

⁽⁴⁾	Estimated expenditures for the remaining six months of 2014, including construction milestone payments, are based on current expected delivery dates for the rigs under construction, and exclude expected capitalized interest costs.

⁽⁵⁾	Construction milestone payments expected to be paid in the remainder of 2014 include:

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$47.3 million payable to Jurong Shipyard Pte Ltd. in connection with the construction of the Ocean Apex; and

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approximately $390 million payable to Hyundai Heavy Industries Co., Ltd. for each rig upon delivery of the Ocean BlackHornet and Ocean BlackRhino in the third and fourth quarters of 2014, respectively.

We had no other purchase obligations for major rig upgrades or any other significant obligations at June 30, 2014, except for those related to our direct rig operations, which arise during the normal course of business.

Contractual Cash Obligations—Retirement of Senior Notes

Our 5.15% Senior Notes due September 1, 2014, or 5.15% Senior Notes, in the aggregate principal amount of $250.0 million, will mature on September 1, 2014.

Other Obligations

As of June 30, 2014, we had foreign currency forward exchange, or FOREX, contracts outstanding in the aggregate notional amount of $167.2 million. 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 6 “Derivative Financial Instruments” to our Consolidated Financial Statements in Item 1 of Part I of this report.

As of June 30, 2014, the total unrecognized tax benefits related to uncertain tax positions was $70.9 million. In addition, we have recorded a liability, as of June 30, 2014, for potential penalties and interest of $47.6 million and $14.1 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 Agreement

We have a syndicated 5-Year Revolving Credit Agreement, or Credit Agreement, that provides for a $1.0 billion senior unsecured revolving credit facility, for general corporate purposes, maturing on March 17, 2019. The entire amount of the facility is available, subject to its terms, for revolving loans. Up to $250 million of the facility may be used for the issuance of performance or other standby letters of credit and up to $100 million may be used for swingline loans. As of June 30, 2014, there were no loans or letters of credit outstanding under the Credit Agreement. See Note 9 “Credit Agreement” to our Consolidated Financial Statements in Item 1 of Part I of this report.

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, 2014 in the amount of $99.6 million under certain performance, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $90.0 million of performance, supersedeas and customs bonds can require collateral at any time. As of June 30, 2014, 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		2014		2015		Thereafter
	(In thousands)
Other Commercial Commitments
Customs bonds	$	1,518	$	1,291	$	227	$	—
Performance bonds		88,131		3,686		22,674		61,771
Other		9,955		9,319		636		—

Total obligations	$	99,604	$	14,296	$	23,537	$	61,771

Off-Balance Sheet Arrangements

At June 30, 2014 and December 31, 2013, we had no off-balance sheet debt or other arrangements.

Recent Accounting Pronouncements

See Note 1 “General Information” to our Consolidated Financial Statements in Item 1 of Part I of this report for a discussion of recently issued 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:

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

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sources and uses of and requirements for financial resources;

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interest rate and foreign exchange risk;

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contractual obligations;

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operations outside the United States;

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effects of the Macondo well blowout;

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business strategy;

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growth opportunities;

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competitive position;

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expected financial position;

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cash flows and contract backlog;

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regular or special dividends;

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financing plans;

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market outlook;

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tax planning;

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debt levels and the impact of changes in the credit markets and credit ratings for our debt;

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budgets for capital and other expenditures;

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

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timing and cost of completion of rig upgrades, construction projects and other capital projects;

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

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plans and objectives of management;

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idling drilling rigs or reactivating stacked rigs;

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assets held for sale;

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asset impairment evaluations;

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performance of contracts;

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outcomes of legal proceedings;

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compliance with applicable laws; and

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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:

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those described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013;

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general economic and business conditions;

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worldwide demand for oil and natural gas;

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

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oil and natural gas price fluctuations and related market expectations;

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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;

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

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

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the cancellation of contracts included in our reported contract backlog;

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advances in exploration and development technology;

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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;

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casualty losses;

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operating hazards inherent in drilling for oil and gas offshore;

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the risk of physical damage to rigs and equipment caused by named windstorms in the GOM;

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industry fleet capacity, including, without limitation, construction of new drilling rig capacity in Brazil;

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market conditions in the offshore contract drilling industry, including, without limitation, dayrates and utilization levels;

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competition;

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changes in foreign, political, social and economic conditions;

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risks of international operations, compliance with foreign laws and taxation policies and seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of equipment and assets;

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

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

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

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

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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, greenhouse gases, carbon emissions or energy use;

•

compliance with and liability under environmental laws and regulations;

•

potential changes in accounting policies by the FASB, 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 and availability 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, 2014 and December 31, 2013, 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, 2014 and December 31, 2013, 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 is 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 $224.4 million and $221.5 million as of June 30, 2014 and December 31, 2013, respectively. A 100-basis point decrease would result in an increase in market value of $268.7 million and $264.5 million as of June 30, 2014 and December 31, 2013, 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, 2014, we had FOREX contracts outstanding in the aggregate notional amount of $167.2 million, consisting of $20.2 million in Australian dollars, $73.7 million in Brazilian reais, $47.1 million in British pounds sterling, $19.1 million in Mexican pesos and $7.1 million in Norwegian kroner. These contracts generally settle monthly through March 2015.

At June 30, 2014, we presented the fair value of our outstanding FOREX contracts as a current asset of $5.6 million in “Prepaid expenses and other current assets” and a current liability of $(0.2) million in “Accrued liabilities” in our Consolidated Balance Sheets. At December 31, 2013, we presented the fair value of our outstanding FOREX contracts as a current asset of $1.6 million in “Prepaid expenses and other current assets” and a current liability of $(1.1) million in “Accrued liabilities” in our Consolidated Balance Sheets.

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

Fair Value Asset (Liability)

Market Risk

June 30,

December 31,

June 30,

December 31,

2014

2013

2014

2013

(In thousands)

Interest rate:

Marketable securities

350,200

(a)

1,750,100

(a)

(300

)(b)

(2,200

)(b)

Foreign exchange:

FOREX contracts – receivable positions

5,600

(c)

1,600

(c)

(29,900

)(d)

(4,200

)(d)

FOREX contracts – liability positions

(200

)(c)

(1,100

)(c)

(1,100

)(d)

(16,000

)(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, 2014 and December 31, 2013.

(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, 2014 and December 31, 2013.

(c)	The fair value of our FOREX contracts is based on both quoted market prices and valuations derived from pricing models on June 30, 2014 and December 31, 2013.

(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, 2014 and December 31, 2013, 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, 2014. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2014.

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 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Items 2(a) and 2(b) are inapplicable.

(c) The following table sets forth information regarding our purchases of shares of our common stock on a monthly basis during the second quarter of 2014:

Issuer Purchases of Equity Securities

Period

Total Number of
Shares Purchased

Average Price
Paid per Share

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs

Maximum Number of
Shares that May Yet Be
Purchased Under the
Plans or Programs

April 1, 2014 through April 30, 2014

30,250

45.97

N/A

May 1, 2014 through May 31, 2014

—

N/A

June 1, 2014 through June 30, 2014

—

N/A

30,250

(a)

45.97

N/A

(a)

As previously disclosed, depending on market and other conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. During the three months ended June 30, 2014, we purchased 30,250 shares of our common stock in open-market transactions, none of which shares were purchased pursuant to a publicly announced share repurchase program.

ITEM 6. Exhibits.

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

SIGNATURES

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


	DIAMOND OFFSHORE DRILLING, INC.
	(Registrant)

Date July 29, 2014	By:	\s\ Gary T. Krenek
		Gary T. Krenek
		Senior Vice President and Chief Financial Officer

Date July 29, 2014		\s\ Beth G. Gordon
		Beth G. Gordon
		Controller (Chief Accounting Officer)

EXHIBIT INDEX


Exhibit No.		Description

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

3.2		Amended and Restated By-laws (as amended through October 4, 2013) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 8, 2013).

10.1*		Separation Agreement and General Release, dated June 11, 2014, between Diamond Offshore Management Company and William C. Long.

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.