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

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2015

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

For the transition period from to

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

Delaware

76-0321760

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

15415 Katy Freeway

Houston, Texas

77094

(Address of principal executive offices)

(Zip Code)

(281) 492-5300

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

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

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

As of July 27, 2015 Common stock, $0.01 par value per share 137,158,706 shares

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2015


			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		23

	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk		40

	ITEM 4.	Controls and Procedures		40

PART II.	OTHER INFORMATION			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, 2015			December 31, 2014

ASSETS
Current assets:
Cash and cash equivalents	$	95,854		$	233,623
Marketable securities		15,953			16,033
Accounts receivable, net of allowance for bad debts		516,008			463,862
Prepaid expenses and other current assets		194,615			185,541

Total current assets		822,430			899,059
Drilling and other property and equipment, net of accumulated depreciation		6,930,329			6,945,953
Other assets		122,883			176,277

Total assets	$	7,875,642		$	8,021,289


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	83,584		$	138,444
Accrued liabilities		303,385			426,592
Taxes payable		21,759			41,648
Short-term borrowings		374,978			—
Current portion of long-term debt		250,000			249,962

Total current liabilities		1,033,706			856,646
Long-term debt		1,994,648			1,994,526
Deferred tax liability		407,808			530,394
Other liabilities		181,710			188,160

Total liabilities		3,617,872			3,569,726


Commitments and contingencies (Note 11)

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; 143,978,877 shares issued and 137,158,706 shares outstanding at June 30, 2015; 143,960,260 shares issued and 137,147,899 shares outstanding at December 31, 2014)		1,440			1,440
Additional paid-in capital		1,996,964			1,993,898
Retained earnings		2,462,386			2,661,999
Accumulated other comprehensive gain (loss)		(615	)		(3,605	)
Treasury stock, at cost (6,820,171 and 6,812,361 shares of common stock at June 30, 2015 and December 31, 2014, respectively)		(202,405	)		(202,169	)

Total stockholders’ equity		4,257,770			4,451,563

Total liabilities and stockholders’ equity	$	7,875,642		$	8,021,289

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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014

Revenues:
Contract drilling	$	617,442		$	649,554		$	1,217,019		$	1,334,862
Revenues related to reimbursable expenses		16,590			42,690			37,069			66,806

Total revenues		634,032			692,244			1,254,088			1,401,668


Operating expenses:
Contract drilling, excluding depreciation		342,869			395,376			693,527			765,166
Reimbursable expenses		16,336			42,290			36,428			65,956
Depreciation		123,329			108,906			260,628			215,917
General and administrative		16,548			20,478			34,000			43,305
Impairment of assets		—			—			358,528			—
Restructuring and separation costs		993			—			7,161			—
Gain on disposition of assets		(164	)		(8,572	)		(775	)		(8,719	)

Total operating expenses		499,911			558,478			1,389,497			1,081,625


Operating income (loss)		134,121			133,766			(135,409	)		320,043

Other income (expense):
Interest income		584			150			1,167			558
Interest expense, net of amounts capitalized		(25,468	)		(18,523	)		(49,450	)		(36,678	)
Foreign currency transaction gain (loss)		(3,473	)		(2,971	)		2,117			(4,149	)
Other, net		264			181			485			508


Income (loss) before income tax (expense) benefit		106,028			112,603			(181,090	)		280,282

Income tax (expense) benefit		(15,642	)		(22,890	)		15,767			(44,759	)


Net income (loss)	$	90,386		$	89,713		$	(165,323	)	$	235,523


Earnings (loss) per share, Basic and Diluted	$	0.66		$	0.65		$	(1.21	)	$	1.71


Weighted-average shares outstanding:
Shares of common stock		137,159			137,145			137,155			137,803
Dilutive potential shares of common stock		42			4			—			5

Total weighted-average shares outstanding		137,201			137,149			137,155			137,808


Cash dividends declared per share of common stock	$	0.125		$	0.875		$	0.25		$	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 (LOSS)

(Unaudited)

(In thousands)


	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015			2014

Net income (loss)	$	90,386	$	89,713			(165,323	)		235,523

Other comprehensive gains (losses), net of tax:
Derivative financial instruments:
Unrealized holding gain (loss)		293		2,882			(1,534	)		5,721
Reclassification adjustment for loss (gain) included in net income		1,230		(2,360	)		4,817			(2,537	)
Investments in marketable securities:
Unrealized holding gain (loss)		1,830		1			(293	)		39
Reclassification adjustment for gain included in net income		—		(18	)		—			(26	)

Total other comprehensive gain		3,353		505			2,990			3,197


Comprehensive income (loss)	$	93,739	$	90,218			(162,333	)		238,720

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,
	2015			2014

Operating activities:
Net (loss) income	$	(165,323	)	$	235,523
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		260,628			215,917
Loss on impairment of assets		358,528			—
Gain on disposition of assets		(775	)		(8,719	)
Loss (gain) on foreign currency forward exchange contracts		7,924			(5,007	)
Deferred tax provision		(124,353	)		6,523
Accretion of discounts on marketable securities		(235	)		(225	)
Stock-based compensation expense		2,186			2,421
Deferred income, net		(13,244	)		55,432
Deferred expenses, net		(47,630	)		(80,579	)
Long-term employee remuneration programs		298			3,952
Other assets, noncurrent		867			(144	)
Other liabilities, noncurrent		(990	)		2,334
(Payments for) proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges		(7,924	)		5,007
Bank deposits denominated in nonconvertible currencies		795			5,442
Other		1,123			1,119
Changes in operating assets and liabilities:
Accounts receivable		(51,751	)		(75,893	)
Prepaid expenses and other current assets		6,404			(18,857	)
Accounts payable and accrued liabilities		(90,883	)		40,948
Taxes payable		65,199			(17,867	)

Net cash provided by operating activities		200,844			367,327


Investing activities:
Capital expenditures (including rig construction)		(686,111	)		(817,375	)
Proceeds from disposition of assets, net of disposal costs		7,652			16,477
Proceeds from sale and maturities of marketable securities		23			5,800,033
Purchases of marketable securities		—			(4,399,889	)

Net cash provided by (used in) investing activities		(678,436	)		599,246


Financing activities:
Payment of dividends		(35,143	)		(244,364	)
Net proceeds from short-term borrowings		374,978			—
Purchase of treasury stock		—			(87,756	)
Other		(12	)		(647	)

Net cash provided by (used in) financing activities		339,823			(332,767	)


Net change in cash and cash equivalents		(137,769	)		633,806
Cash and cash equivalents, beginning of period		233,623			347,011

Cash and cash equivalents, end of period	$	95,854		$	980,817

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, 2014 (File No. 1-13926).

As of July 27, 2015, Loews Corporation owned 53.1 % 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.

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.

The effect of exchange rate changes on cash balances held in foreign currencies was not material for each of the three-month periods ended June 30, 2015 and 2014.

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 6.

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 12.

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 7 and 8.

Drilling and Other Property and Equipment

We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. Historically, the amount of capital additions requiring significant judgments, assumptions or estimates has not been significant. During the six months ended June 30, 2015 and the year ended December 31, 2014, we capitalized $176.4 million and $546.0 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $215 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.

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, but not limited to, cold stacking a rig, the expectation of cold stacking a rig in the near term, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

•

dayrate by rig;

•

utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);

•

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

•

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

•

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

•

salvage value for each rig; and

•

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

Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a projected probability- weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability.

The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rig’s age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment.

Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil and gas prices, cancelations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different. See Note 2.

Capitalized Interest

We capitalize interest cost for qualifying construction and upgrade projects. See Note 9. A reconciliation of our total interest cost to “Interest expense, net of amounts capitalized” as reported in our Consolidated Statements of Operations is as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
	(In thousands)
Total interest cost, including amortization of debt issuance costs	$	30,428		$	33,526		$	60,424		$	67,893
Capitalized interest		(4,960	)		(15,003	)		(10,974	)		(31,215	)

Total interest expense as reported	$	25,468		$	18,523		$	49,450		$	36,678

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, 2015, we recognized net foreign currency transaction gains (losses) of $(3.5) million and $2.1 million, respectively. 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. See Note 7.

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 May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or 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.

In July 2015, the FASB approved a one-year deferral of the effective date of ASU No. 2014-09. The FASB expects to issue a final ASU formally amending the effective date by the end of the third quarter of 2015.

2. Asset Impairments

In response to recently announced regulatory requirements in the U.S. Gulf of Mexico, as well as the continued deterioration of the market fundamentals in the oil and gas industry, including the dramatic decline in oil prices, significant cutbacks in customer capital spending plans and contract cancelations by customers, we evaluated most of our mid-water semisubmersible rigs, one drillship and five of our jack-up rigs for impairment during the first quarter of 2015. Using the undiscounted projected probability-weighted cash flow analysis described in Note 1, we determined that the carrying values of seven of our 12 mid-water semisubmersibles, as well as our older, 7,875-foot water depth rated drillship, which we refer to collectively as the “Impaired Rigs,” were impaired at March 31, 2015.

We determined the fair value of five of the Impaired Rigs using a market approach, which utilized the most recent contracted sales price for another of our previously impaired mid-water semisubmersible rigs. We determined the fair value of the three remaining rigs (which were under contract with a customer at that time) using an income approach, which utilized significant unobservable inputs, including assumptions related to estimated dayrate revenue, rig utilization and anticipated costs for the remainder of the current contract, as well as estimated proceeds that may be received on disposition of each rig. We consider each of these methodologies to be Level 3 fair value measurements due to the significant level of estimation involved and the lack of transparency as to the inputs used As a result of our valuations, we recognized an impairment loss aggregating $358.5 million for the six-month period ended June 30, 2015.

Of the Impaired Rigs, three semisubmersible rigs were sold for scrap in the second quarter of 2015 and another three rigs are currently cold stacked or are expected to be cold stacked in the near term. Two of the remaining Impaired Rigs are currently under contract and are expected to be cold stacked or sold for scrap at the end of their respective contracts. During the second quarter of

2015, we reviewed most of our mid-water semisubmersibles, which were not previously impaired, two ultra-deepwater semisubmersibles, one deepwater semisubmersible and five of our jack-up rigs for impairment. As of June 30, 2015, we determined that further impairment had not occurred. The aggregate fair value of the Impaired Rigs was $3.6 million at June 30, 2015 and is reported in “Drilling and other property and equipment, net of accumulated depreciation” in our Consolidated Balance Sheets. We did not record any impairment for the three-month periods ended June 30, 2015 and 2014 or the six-month period ended June 30, 2014. See Note 8 and Note 9.

Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation. The use of different assumptions could produce results that differ from those reported. The actual amount realized upon disposition of our drilling rigs may vary if, or when, such rigs are sold.

3. Supplemental Financial Information

Consolidated Balance Sheets Information

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


	June 30, 2015			December 31, 2014
	(In thousands)
Trade receivables	$	483,913		$	437,017
Value added tax receivables		23,105			24,853
Amounts held in escrow		13,494			6,450
Related party receivables		297			339
Other		923			927

		521,732			469,586
Allowance for bad debts		(5,724	)		(5,724	)

Total	$	516,008		$	463,862

Prepaid expenses and other current assets consist of the following:


	June 30, 2015		December 31, 2014
	(In thousands)
Rig spare parts and supplies	$	50,798	$	56,315
Deferred mobilization costs		77,569		53,206
Prepaid insurance		8,837		12,163
Deferred tax assets		15,612		15,612
Prepaid taxes		36,769		44,085
Other		5,030		4,160

Total	$	194,615	$	185,541

Accrued liabilities consist of the following:


	June 30, 2015		December 31, 2014
	(In thousands)
Rig operating expenses	$	88,654	$	85,897
Payroll and benefits		86,280		131,664
Deferred revenue		58,539		63,209
Accrued capital project/upgrade costs		27,721		103,123
Interest payable		24,458		18,365
Personal injury and other claims		9,149		8,570
FOREX contracts		355		5,439
Other		8,229		10,325

Total	$	303,385	$	426,592

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,
	2015			2014
	(In thousands)
Accrued but unpaid capital expenditures at period end	$	27,721		$	73,643
Common stock withheld for payroll tax obligations ⁽¹⁾		236			—
Cash interest payments⁽²⁾		51,531			63,560
Cash income taxes paid, net of (refunds):
U.S. federal		(3,344	)		—
Foreign		46,181			44,589
State		150			149

⁽¹⁾

Represents the cost of 7,810 shares of common stock withheld to satisfy the payroll tax obligation incurred as a result of the vesting of restricted stock units in the first quarter of 2015. This cost is presented as a deduction from stockholders’ equity in “Treasury stock” in our Consolidated Balance Sheets at June 30, 2015.

⁽²⁾

Interest payments, net of amounts capitalized, were $42.1 million and $33.3 million for the six months ended June 30, 2015 and 2014, respectively.

4. Stock-Based Compensation

In April 2015, we granted an aggregate of 311,145 restricted stock units, or RSUs, to employees under our Equity Incentive Compensation Plan, or Equity Plan, collectively referred to as the 2015 RSUs. RSUs are contractual rights to receive shares of our common stock in the future if the applicable vesting conditions are met. Our 2015 RSUs included both performance-vesting and time-vesting RSUs. Under the terms of the 2015 awards, the performance-vesting 2015 RSUs vest upon achievement of certain performance goals as set forth in the individual award agreements over the performance period from January 1, 2015 to December 31, 2017, and the shares of our common stock to be received upon the vesting of the performance-vesting RSUs will be delivered no later than March 15, 2018. 50% of the time-vesting 2015 RSUs will vest on April 1, 2017 and 50% will vest on April 1, 2018, conditioned upon continued employment through the applicable vesting date.

2015 RSUs awarded under the Equity Plan are summarized as follows:


Award Type	Number of RSUs		Weighted Average Fair Value per RSU
Performance-vesting (dividend entitled)		110,791	$	26.69
Performance-vesting		56,162	$	25.21
Time-vesting		144,192	$	25.21

We recognized compensation expense of $0.7 million and $0.9 million for the three-month and six-month periods ended June 30, 2015, respectively, in connection with RSUs awarded under our Equity Plan. In connection with RSUs awarded in 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.

During the six months ended June 30, 2015, under the Equity Plan we issued an aggregate of 91,250 stock appreciation rights to non-employee members of our board of directors and certain employees.

5. 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,
	2015		2014		2015			2014
	(In thousands, except per share data)
Net income (loss) – basic and diluted numerator	$	90,386	$	89,713	$	(165,323	)	$	235,523

Weighted average shares – basic (denominator):		137,159		137,145		137,155			137,803
Dilutive effect of stock-based awards		42		4		—			5

Weighted average shares including conversions – diluted (denominator)		137,201		137,149		137,155			137,808

Earnings (loss) per share:
Basic	$	0.66	$	0.65	$	(1.21	)	$	1.71

Diluted	$	0.66	$	0.65	$	(1.21	)	$	1.71

The following table sets forth the share effects of stock-based awards 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,
	2015		2014		2015		2014
	(In thousands)
Employee and director:
Stock options		30		31		32		32
Stock appreciation rights		1,557		1,475		1,573		1,444
Restricted stock units		37		—		200		—

6. 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 8.

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


	June 30, 2015
	Amortized Cost		Unrealized Gain (Loss)			Market Value
	(In thousands)
Corporate bonds	$	16,239	$	(396	)	$	15,843
Mortgage-backed securities		106		4			110

Total	$	16,345	$	(392	)	$	15,953


	December 31, 2014
	Amortized Cost		Unrealized Gain (Loss)			Market Value
	(In thousands)
Corporate bonds	$	16,003	$	(104	)	$	15,899
Mortgage-backed securities		130		4			134

Total	$	16,133	$	(100	)	$	16,033

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,
	2015		2014		2015		2014
	(In thousands)
Proceeds from maturities	$	—	$	3,625,000	$	—	$	5,800,000
Proceeds from sales		12		12		23		33
Gross realized gains		—		—		—		—
Gross realized losses		—		—		—		—

7. 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. Historically we have entered into FOREX contracts for future delivery of 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, 2015 and 2014, we settled FOREX contracts with aggregate notional values of approximately $88.8 million and $153.5 million, respectively, of which the entire aggregate amounts were designated as a cash flow accounting hedge.

The following table presents the aggregate amount of gain or loss recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as accounting hedges for the three-month and six-month periods ended June 30, 2015 and 2014.


	Three Months Ended June 30,					Six Months Ended June 30,
Location of (Loss) Gain Recognized in Income	2015			2014		2015			2014
	(In thousands)
Contract drilling expense	$	(1,534	)	$	4,496	$	(7,924	)	$	5,007

As of June 30, 2015, we had Mexican peso FOREX contracts outstanding in the aggregate notional amount of $2.7 million, which settle monthly through September 2015. As of June 30, 2015, all outstanding derivative contracts had been designated as cash flow hedges. See Note 8.

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, 2015, all of our FOREX contracts were with a single counterparty 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, 2015 and December 31, 2014; 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, 2015 and December 31, 2014.


Balance Sheet Location	Fair Value				Balance Sheet Location		Fair Value
	June 30, 2015		December 31, 2014				June 30, 2015			December 31, 2014
	(In thousands)						(In thousands)
Prepaid expenses and other current assets	$	—	$	—		Accrued liabilities	$	(355	)	$	(5,439	)

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, 2015 and 2014.


	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
	(In thousands)
*FOREX contracts:*
Amount of gain (loss) recognized in AOCGL on derivative (effective portion)	$	451		$	4,434	$	(2,359	)	$	8,802
Location of (loss) gain reclassified from AOCGL into income (effective portion)		Contract drilling expense			Contract drilling expense		Contract drilling expense			Contract drilling expense
Amount of (loss) gain reclassified from AOCGL into income (effective portion)	$	(1,894	)	$	3,630	$	(7,414	)	$	3,899
Location of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		Foreign currency transaction gain (loss)			Foreign currency transaction gain (loss)		Foreign currency transaction gain (loss)			Foreign currency transaction gain (loss)
Amount of gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)	$	8		$	—	$	(1	)	$	(1	)

*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		Interest Expense			Interest Expense
Amount of gain reclassified from AOCGL into income (effective portion)	$	2		$	2	$	4		$	4

As of June 30, 2015, the estimated amount of net unrealized gains (losses) associated with our FOREX contracts and treasury lock agreements that will be reclassified to earnings during the next twelve months was $(0.4) million and $8,000, respectively. The net unrealized gains (losses) associated with these derivative financial instruments will be reclassified to contract drilling expense and interest expense, respectively. During the six-month periods ended June 30, 2015 and 2014, we did not reclassify any amounts from AOCGL due to the probability of an underlying forecasted transaction not occurring.

8. Financial Instruments and Fair Value Disclosures

Financial instruments that 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 securitized corporate bonds whereby our credit risk is mitigated by the collateral. 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, 2015 and December 31, 2014, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government), or Petrobras, accounted for $107.5 million and $123.3 million, or 22% and 29%, 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.

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, 2015 consisted of cash held in money market funds of $65.6 million and time deposits of $20.3 million. Our Level 1 assets at December 31, 2014 consisted of cash held in money market funds of $197.5 million and time deposits of $20.3 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, corporate bonds purchased in a private placement offering and over-the-counter FOREX contracts. Our residential mortgage-backed securities and corporate bonds were valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. Our FOREX contracts are valued based on quoted market prices, which are derived from observable inputs including current spot and forward rates, less the contract rate multiplied by the notional amount. The inputs used in our valuation are obtained from a Bloomberg curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected floating rate cash flows can be calculated. The valuation techniques underlying the models are widely accepted in the financial services industry and do not involve significant judgment.


Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. Our Level 3 assets at June 30, 2015 consisted of nonrecurring measurements of four mid-water semisubmersible rigs and our older 7,875-foot water depth rated drillship for which we recorded an impairment loss during the first quarter of 2015. See Notes 1 and 2.

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 three-month and six-month periods ended June 30, 2015 and 2014.

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 recorded impairment charges related to assets measured at fair value on a nonrecurring basis of $358.5 million during the six-month period ended June 30, 2015. We did not record any such impairment charges during the three-month periods ended June 30, 2015 and 2014 or the six-month period ended June 30, 2014.

Assets and liabilities measured at fair value are summarized below:


	June 30, 2015
	Fair Value Measurements Using										Total Losses for Period Ended
	Level 1		Level 2			Level 3		Assets at Fair Value			Three Months		Six Months
	(In thousands)

Recurring fair value measurements:
Assets:
Short-term investments	$	85,853	$	—		$	—	$	85,853
Corporate bonds		—		15,843			—		15,843
Mortgage-backed securities		—		110			—		110

Total assets	$	85,853	$	15,953		$	—	$	101,806


Liabilities:
FOREX contracts	$	—	$	(355	)	$	—	$	(355	)


Nonrecurring fair value measurements:
Assets:
Impaired assets⁽¹⁾⁽²⁾	$	—	$	—		$	3,600	$	3,600		$	—	$	358,528

⁽¹⁾	Represents the carrying value as of June 30, 2015 of four mid-water semisubmersible rigs and one drillship, which were written down to their estimated recoverable amounts in the first quarter of 2015. See Note 2.

⁽²⁾

Reported value at June 30, 2015 is net of depreciation expense of $8.9 million recognized in the second quarter of 2015 for the Ocean Lexington, which was still under contract through early July 2015 and was written down to its estimated fair value using an income approach in March 2015. Excludes the fair values of the Ocean Saratoga, Ocean Yorktown and Ocean Worker, which were included in the March 2015 write-down, but were subsequently sold for scrap in the second quarter of 2015.


	December 31, 2014
	Fair Value Measurements Using
	Level 1		Level 2			Level 3		Assets at Fair Value
	(In thousands)

Recurring fair value measurements:
Assets:
Short-term investments	$	217,789	$	—		$	—	$	217,789
Corporate bonds		—		15,899			—		15,899
Mortgage-backed securities		—		134			—		134

Total assets	$	217,789	$	16,033		$	—	$	233,822


Liabilities:
FOREX contracts	$	—	$	(5,439	)	$	—	$	(5,439	)


Nonrecurring fair value measurements:
Assets:
Impaired assets⁽¹⁾	$	—	$	—		$	9,421	$	9,421

⁽¹⁾	Represents the book value as of December 31, 2014 of four of our mid-water semisubmersible rigs, which were written down to their estimated recoverable amounts in 2014. All four rigs were sold for scrap during the six months ended June 30, 2015.

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.

•

Commercial paper - The carrying amounts approximate fair value because of the short maturity of these 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, 2015 and December 31, 2014. 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, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
4.875% Senior Notes due 2015		250.0		250.0		255.0		250.0
5.875% Senior Notes due 2019		559.5		499.6		544.9		499.6
3.45% Senior Notes due 2023		236.4		249.1		232.0		249.1
5.70% Senior Notes due 2039		437.7		497.0		478.5		497.0
4.875% Senior Notes due 2043		594.4		748.9		638.9		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.

9. 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,
	2015			2014
	(In thousands)
Drilling rigs and equipment	$	10,209,479		$	10,555,314
Construction work-in-progress		235,629			439,206
Land and buildings		65,757			66,989
Office equipment and other		71,522			70,591

Cost		10,582,387			11,132,100
Less: accumulated depreciation		(3,652,058	)		(4,186,147	)

Drilling and other property and equipment, net	$	6,930,329		$	6,945,953

During the six months ended June 30, 2015, we sold for scrap seven rigs with an aggregate net book value of $4.0 million and recognized aggregate gains (losses) on sale of ($0.3 million) and $0.8 million for the three-month and six-month periods ended June 30, 2015, respectively. In addition, during the six-month period ended June 30, 2015, we recognized an impairment loss of $358.5 million. See Note 2.

Construction work-in-progress, including capitalized interest, at June 30, 2015 and December 31, 2014 is summarized as follows:


	June 30,		December 31,
	2015		2014
	(In thousands)
Ultra-deepwater semisubmersible—Ocean GreatWhite	$	235,629	$	213,801
Ultra-deepwater drillship—Ocean BlackLion		—		225,405

Total construction work-in-progress	$	235,629	$	439,206

The Ocean BlackLion was placed in service in June 2015 and is no longer reported as construction work-in-progress at June 30, 2015.

10. Debt

Commercial Paper. In February 2015, we established a commercial paper program with three commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5 billion. Proceeds from issuances under the commercial paper program may be used for general corporate purposes. The maturities of the notes may vary, but may not exceed 397 days from the date of issuance. The notes will be issued, at our option, either at a discounted price to their principal face value or will bear interest, which may be at a fixed or floating rate, at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The notes are not redeemable or subject to voluntary prepayment by us prior to maturity. Liquidity for our payment obligations in respect of the notes issued under the commercial paper program is provided under our revolving credit facility, and the aggregate amount of notes outstanding at any time will not exceed the amount available under the revolving credit agreement. During the quarter ended June 30, 2015, we added a fourth commercial paper dealer to our commercial paper program. As of June 30, 2015, we had $375.0 million in commercial paper notes outstanding with a weighted average interest rate of 0.49% and a weighted average remaining term of eight days.

4.875% Senior Notes due 2015. On July 1, 2015, we repaid $250.0 million in aggregate principal amount of our 4.875% Senior Notes due July 1, 2015, primarily with funds obtained through the issuance of additional commercial paper. These notes were presented as “Current portion of long-term debt” in our Consolidated Balance Sheets and June 30, 2015 and December 31, 2014.

As of July 31, 2015, we had an additional $910.8 million available under our revolving credit facility for the issuance of commercial paper.

11. 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 Mississippi, Louisiana and Missouri 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 from Murphy Exploration & Production Company with respect to many of the lawsuits 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, and Kaneb Management Co., L.L.C., or Kaneb, the successors to Diamond M Corporation, seeking a judicial determination that we did not assume liability for these claims. Trial of this declaratory judgment action is scheduled to commence in 2015. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations or cash flows.

Other Litigation. We have been named in various other lawsuits or threatened actions that are incidental to the ordinary course of our business. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of these lawsuits and actions cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of these lawsuits. Any claims against us, whether meritorious or not, could cause us to incur costs and expenses, require significant amounts of management time and result in the diversion of significant operational resources. 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 or cash flows.

Brazilian Withholding Contingency. In July 2014, Petrobras notified us, along with other industry participants, that it is 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. If necessary, we intend to defend any reimbursement claims against us vigorously. We are currently unable to estimate the range of loss, if any, that we would incur if Petrobras is ultimately assessed such taxes and if it is determined that Petrobras is entitled to obtain reimbursement from us. If Petrobras is assessed such taxes and we are ultimately required to pay such reimbursement, 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 that 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 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. In 2013, 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 agreed to a settlement with the company that purchased most of the debtor’s assets (including the debtor’s claims against our NPI) whereby the nature of our NPI will not be challenged by that party and our declaratory judgment action was dismissed. Following the settlement, the bankruptcy was converted to a Chapter 7 liquidation proceeding. Several lienholders who had previously intervened in the declaratory judgment action filed motions in the bankruptcy contending that their liens have priority and seeking disgorgement of $3.25 million of payments made to us after the bankruptcy was filed. We believe that our rights to the payments at issue are superior to these liens, and we have filed appropriate motions to dismiss these claims. In addition, the bankruptcy trustee filed counterclaims seeking disgorgement of a total of $30.0 million of pre- and post-bankruptcy payments made to us under the original NPI. We have filed motions to dismiss these counterclaims and still expect the bankruptcy proceedings to be concluded with no further material impact to us.

Personal Injury Claims. Under our current insurance policies that expire on May 1, 2016, 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, 2015 our estimated liability for personal injury claims was $39.3 million, of which $8.8 million and $30.5 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2014, our estimated liability for personal injury claims was $39.4 million, of which $8.2 million and $31.2 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

•

the severity of personal injuries claimed;

•

significant changes in the volume of personal injury claims;

•

the unpredictability of legal jurisdictions where the claims will ultimately be litigated;

•

inconsistent court decisions; and

•

the risks and lack of predictability inherent in personal injury litigation.

Purchase Obligations. 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 $764 million, including shipyard costs, capital spares, commissioning, project management and shipyard supervision. The contracted price to Hyundai Heavy Industries Co., Ltd. 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 second quarter of 2016.

At June 30, 2015, 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, 2015 in the amount of $68.4 million under certain performance, security, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $61.6 million of performance, security, supersedeas and customs bonds can require collateral at any time. As of June 30, 2015, 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.

12. Accumulated Other Comprehensive Gain (Loss)

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


	Unrealized (Loss) Gain on
	Derivative Financial Instruments			Marketable Securities			Total AOCGL
	(In thousands)
Balance at January 1, 2015	$	(3,504	)	$	(101	)	$	(3,605	)
Change in other comprehensive (loss) gain before reclassifications, after tax of $825 and $(1)		(1,534	)		(293	)		(1,827	)
Reclassification adjustments for items included in Net Income, after tax of $(2,593) and $0		4,817			—			4,817

Balance at June 30, 2015	$	(221	)	$	(394	)	$	(615	)

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


Major Category of AOCGL	Three Months Ended June 30,						Six Months Ended June 30,						Consolidated Statements of Operations Line Items
	2015			2014			2015			2014
	(In thousands)
Derivative Financial Instruments:
Unrealized loss (gain) on FOREX contracts	$	1,894		$	(3,630	)	$	7,414		$	(3,899	)	Contract drilling, excluding depreciation
Unrealized (gain) loss on treasury lock agreements		(2	)		(2	)		(4	)		(4	)	Interest expense
		(662	)		1,272			(2,593	)		1,366		Income tax expense

	$	1,230		$	(2,360	)	$	4,817		$	(2,537	)	Net of tax

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

	$	—		$	(18	)	$	—		$	(26	)	Net of tax

13. Restructuring and Separation Costs

In response to the continuing decline in the offshore drilling market, we reviewed our cost and organization structure, and, as a result, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities, also referred to as the Corporate Reduction Plan, in the first half of 2015. As of June 30, 2015, appropriate communications have been made to substantially all impacted personnel, and we recognized $1.0 million and $7.2 million in restructuring and employee separation related costs for the three-month and six-month periods ended June 30, 2015, respectively. Substantially all costs associated with the Corporate Reduction Plan had been paid as of June 30, 2015.

14. 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,
	2015		2014		2015		2014
	(In thousands)
Floaters:
Ultra-Deepwater	$	315,670	$	182,656	$	567,066	$	388,450
Deepwater		181,104		120,539		319,874		267,098
Mid-Water		96,926		300,902		273,283		586,881

Total Floaters		593,700		604,097		1,160,223		1,242,429
Jack-ups		23,742		45,457		56,796		92,433

Total contract drilling revenues		617,442		649,554		1,217,019		1,334,862
Revenues related to reimbursable expenses		16,590		42,690		37,069		66,806

Total revenues	$	634,032	$	692,244	$	1,254,088	$	1,401,668

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, 2015, our actively-marketed drilling rigs were en route to or located offshore seven 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,
	2015		2014		2015		2014
	(In thousands)
United States	$	112,709	$	128,639	$	189,867	$	243,508

International:
South America		238,640		262,072		431,715		549,996
Europe/Africa/Mediterranean		136,532		104,725		287,802		260,316
Australia/Asia		109,885		134,555		247,020		230,319
Mexico		36,266		62,253		97,684		117,529

Total revenues	$	634,032	$	692,244	$	1,254,088	$	1,401,668

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, 2014. 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 35 offshore drilling rigs. Our current fleet consists of eight ultra-deepwater, seven deepwater and nine mid-water semisubmersibles, five dynamically-positioned ultra-deepwater drillships and six jack-ups. Construction of our fourth newbuild ultra-deepwater drillship, the Ocean BlackLion, was completed in the second quarter of 2015, and the rig is currently in the Canary Islands, where we are preparing the rig for commencement of its engagement in the U.S. Gulf of Mexico, or GOM, later this year. One of our eight ultra-deepwater semisubmersibles, the Ocean GreatWhite, is currently under construction and is expected to be delivered in the second quarter of 2016. The Ocean GreatWhite is expected to commence a three-year drilling contract offshore Australia in late 2016.

Of our current fleet, one deepwater and four mid-water semisubmersible rigs and four jack-up rigs are cold stacked. We expect to cold stack an additional two floaters (one ultra-deepwater and one midwater semisubmersible) in the near term. Since the beginning of 2015, seven of our older mid-water semisubmersible rigs have been sold for scrap.

Market Overview

Current crude oil prices have declined significantly since the summer of 2014, and oil markets remain volatile and unpredictable due to a number of geopolitical and economic factors, including the proposed Iranian accord, which would result in the lifting of international sanctions. In reaction to the depressed fundamentals in the oil and gas industry, independent and national oil companies and exploration and production companies have announced significant reductions to their 2016 capital spending plans, on top of their already-reduced 2015 capital spending plans. Thus far in 2015, rig tenders have been infrequent and have generally been limited to short-term or well-to-well work. Competition for the limited number of drilling jobs continues to be intense, with numerous offshore drillers vying for the same opportunities, including some contractors bidding multiple rigs on the same bid, and in some cases bidding rigs of both high and lower specifications on the same bid. Operators are continuing to attempt to sublet previously contracted rigs for which capital spending programs have been delayed or canceled. In addition, newbuild floaters continue to enter the market, many of which are not contracted, adding to the oversupply of rigs. With the shortage of work and an oversupply of rigs available for work, price competition remains intense, and some industry analysts are predicting further weakening in dayrates across the floater markets.

In addition, as a result of the depressed market conditions and continued pessimistic outlook for the near term, certain of our customers, as well as those of our competitors, have attempted to renegotiate or terminate existing drilling contracts. Such renegotiations could include requests to lower the contract dayrate, lowering of a dayrate in exchange for additional contract term, shortening the term on one contracted rig in exchange for additional term on another rig, early termination of a contract in exchange for a lump sum margin payout and many other possibilities. In addition to the potential for renegotiations, some of our drilling contracts, permit the customer to terminate the contract early after specified notice periods or permit the customer to terminate the contract early in the event of excessive downtime, sometimes resulting in no payment to us or sometimes resulting in a contractually specified termination amount, which often does not fully compensate us for the loss of the contract. During depressed market conditions, certain customers have utilized such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under circumstances where we believe we are in compliance with the contracts. The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. When a customer terminates our contract prior to the contract’s scheduled expiration, our contract backlog is also adversely impacted. See “–Contract Drilling Backlog” below.

As previously disclosed, on February 20, 2015, a representative of PEMEX – Exploración y Producción, or PEMEX, verbally informed us of PEMEX’s intention to exercise its contractual right to terminate its drilling contracts on the Ocean Ambassador, the Ocean Nugget and the Ocean Summit, and to cancel its drilling contract on the Ocean

Lexington, which contract was scheduled to commence in September 2015. During the second quarter of 2015, PEMEX terminated the contract for the Ocean Nugget, and delivered to us a notice of termination of the contract on the Ocean Summit. During the second quarter of 2015, PEMEX rescinded its termination of the Ocean Summit contract, and we and PEMEX renegotiated the contracts for the Ocean Ambassador, Ocean Summit and Ocean Scepter at lower dayrates. In July 2015, PEMEX delivered to us a notice to initiate the rescission of the Ocean Lexington contract, which process is currently underway.

Also as previously disclosed, during the first quarter of 2015 Petróleo Brasileiro S.A., or Petrobras, notified us of its right to terminate the drilling contract on the Ocean Baroness and verbally informed us that it did not intend to continue to use the rig. During the second quarter of 2015, we received written notification from Petrobras to terminate the drilling contract on the Ocean Baroness, which became effective on May 31, 2015. The Ocean Baroness is currently demobilizing to the GOM, where the rig is expected to be cold stacked until market conditions improve.

Current depressed market conditions in the offshore drilling industry have materially impacted our results of operations and cash flows in the second quarter and first half of 2015. We currently expect that these adverse market conditions will continue for the foreseeable future. The continuation of these conditions could result in more of our rigs being without contracts and/or cold stacked or scrapped and could further materially and adversely affect our financial condition, results of operations and cash flows. When we cold stack a rig, we evaluate the rig for impairment. During the first half of 2015, we recognized a $358.5 million impairment charge related to eight rigs, for which we determined the carrying values to be impaired. See “ — Results of Operations—Overview—Six Months Ended June 30, 2015 and 2014—Impairment of Assets.”

As of July 20, 2015, 14 of our rigs were not subject to a drilling contract with a customer, including 11 rigs that have been cold stacked or are in the process of being cold stacked. See “– Contract Drilling Backlog”for future commitments of our rigs during 2015 through 2020.

Although these general market conditions impact all segments of the offshore drilling market, the following discussion addresses market conditions within segments of the floater market.

Floater Markets

Ultra-Deepwater and Deepwater Floaters. Globally, the ultra-deepwater and deepwater floater markets continue to be depressed. The continuing oversupply of rigs and diminished demand has resulted in further decline in dayrates and the stacking, and in some cases scrapping, of rigs in all asset classes. Industry analysts expect offshore drillers to continue to scrap older, lower specification rigs.

Newbuild rig deliveries and established rigs coming off contract continue to fuel an oversupply of floaters in both the ultra-deepwater and deepwater markets. In an effort to manage the oversupply of rigs and potentially avoid the cost of cold stacking newly-built rigs, which, in the case of dynamically-positioned rigs, can be significant, certain drilling contractors have recently exercised options to delay the delivery of certain rigs by the shipyard. As of the date of this report, based on industry data, there are approximately 52 competitive, or non-owner-operated, newbuild floaters on order. Based on industry reports, half of the 10 newbuilds scheduled for delivery in the second half of 2015, as well as 18 of the 27 newbuilds scheduled for delivery in 2016 and eight of the nine newbuilds scheduled for delivery in 2017 are not contracted for future work. There are currently six newbuilds on order for delivery between 2018 and 2020, only one of which has been contracted for future work. In addition, industry reports indicate that Petrobras, our largest single customer based on 2014 annual consolidated revenues, currently has 13-17 rigs under construction, with two scheduled for delivery in 2015. The influx of newbuilds into the market, combined with established rigs coming off contract during 2015, is expected to contribute to further weakening of the ultra-deepwater and deepwater floater markets.

Mid-Water Floaters. While conditions in the mid-water market vary slightly by region, mid-water rigs have generally been adversely impacted by (i) lower demand, (ii) declining dayrates, (iii) increased regulatory requirements, including more stringent design requirements for well control equipment, which could significantly increase the capital needed to comply with design requirements that would permit such rigs to work in U.S. waters, (iv) the challenges experienced by lower specification units in this segment as a result of more complex customer specifications, and (v) the intensified competition resulting from the migration of some deepwater and ultra-deepwater units to compete against mid-water units. To date the mid-water market has seen the highest number of cold-stacked and scrapped rigs. Additionally, as market conditions remain challenging, higher specification rigs may continue to take the place of lower specification units, leading to additional lower specification rigs being cold stacked or ultimately scrapped.

Contract Drilling Backlog

The following table reflects our contract drilling backlog as of July 1, 2015, February 9, 2015 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2014), and July 23, 2014 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014). Contract drilling backlog as presented below includes only firm commitments (typically represented by signed contracts, except as indicated in the footnotes to the tables below), 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.


	July 1, 2015		February 9, 2015		July 23, 2014
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽¹⁾	$	4,902,000	$	5,390,000	$	3,751,000
Deepwater ⁽²⁾		621,000		748,000		901,000
Mid-Water		378,000		611,000		1,375,000

Total Floaters		5,901,000		6,749,000		6,027,000
Jack-ups		33,000		91,000		216,000

Total	$	5,934,000	$	6,840,000	$	6,243,000

⁽¹⁾

Contract drilling backlog as of July 1, 2015 for our ultra-deepwater floaters includes (i) $1.1 billion attributable to our contracted operations offshore Brazil for the years 2015 to 2018 and (ii) $641.0 million for the years 2016 to 2019 attributable to future work for the semisubmersible Ocean GreatWhite, which is under construction.

⁽²⁾

Contract drilling backlog as of July 1, 2015 for our deepwater floaters includes $120.0 million attributable to our contracted operations offshore Brazil for the years 2015 to 2016.

The following table reflects the amount of our contract drilling backlog by year as of July 1, 2015.


	For the Years Ending December 31,
	Total		2015 ⁽¹⁾		2016		2017		2018 – 2020
	(In thousands)
Contract Drilling Backlog
Floaters:
Ultra-Deepwater ⁽²⁾	$	4,902,000	$	740,000	$	1,227,000	$	1,202,000	$	1,733,000
Deepwater ⁽³⁾		621,000		212,000		273,000		136,000		—
Mid-Water		378,000		104,000		153,000		121,000		—

Total Floaters		5,901,000		1,056,000		1,653,000		1,459,000		1,733,000
Jack-ups		33,000		25,000		8,000		—		—

Total	$	5,934,000	$	1,081,000	$	1,661,000	$	1,459,000	$	1,733,000

⁽¹⁾

Represents the six-month period beginning July 1, 2015.

⁽²⁾

Contract drilling backlog as of July 1, 2015 for our ultra-deepwater floaters includes (i) $228.0 million, $333.0 million, $332.0 million and $158.0 million for the years 2015, 2016, 2017 and 2018, respectively, attributable to our contracted operations offshore Brazil and (ii) $90.0 million for the year 2016, $214.0 million for the year 2017 and $337.0 million in the aggregate for the years 2018 to 2019 attributable to future work for the Ocean GreatWhite, which is under construction.

⁽³⁾

Contract drilling backlog as of July 1, 2015 for our deepwater floaters includes $62.0 million and $58.0 million for the years 2015 and 2016, respectively, attributable to our contracted operations offshore Brazil.

The following table reflects the percentage of rig days committed by year as of July 1, 2015. 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, including cold-stacked 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 GreatWhite, which is under construction.


	For the Years Ending December 31,
	2015 ⁽¹⁾			2016			2017			2018 – 2020
Rig Days Committed ⁽²⁾
Floaters:
Ultra-Deepwater		85	%		65	%		54	%		26	%
Deepwater		49	%		31	%		17	%		—
Mid-Water		30	%		13	%		9	%		—
All Floaters		58	%		40	%		31	%		12	%

Jack-ups		22	%		3	%		—			—

⁽¹⁾

Represents a six-month period beginning July 1, 2015.

⁽²⁾

As of July 1, 2015, includes approximately 290 and 314 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 2015 and for the year 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 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 older than 15 years that are located in the United Kingdom, or U.K., sector of the North Sea.

During the remainder of 2015, we expect to spend an additional approximately 290 days for the mobilization of rigs, contract modifications, acceptance testing and extended maintenance projects, including days associated with mobilization of and acceptance testing for the recently delivered Ocean BlackLion (approximately 159 days), which is not expected to commence drilling operations until the fourth 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.”

In April 2015, the Bureau of Safety and Environmental Enforcement (an agency established by the U.S. Department of the Interior that governs the offshore drilling industry on the Outer Continental Shelf) announced proposed rules, expected to be enacted into law following a 60-day comment period, which include more stringent design requirements for well control equipment used in offshore drilling operations. Based on our assessment of the proposed rules, we believe that we will need to incur significant capital cost to comply with the additional design requirements to enable our cold stacked mid-water semisubmersibles to return to work in U. S. waters.

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, 2016, 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. 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, 2016, 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.

Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. We ceased capitalization of interest on five qualifying projects as a result of their completion in 2014 and on the Ocean BlackLion upon its delivery in the second quarter of 2015. We continue to capitalize interest for our ultra-deepwater semisubmersible Ocean GreatWhite. Consequently, interest expense reported in our Consolidated Statements of Operations will increase in the second half of 2015, compared to the prior year and the first half of 2015, due to the completion of projects.

Impact of Changes in Tax Laws or Their Interpretation. 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 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.

Critical Accounting Estimates

Impairment of Long-Lived Assets

•

dayrate by rig;

•

utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);

•

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

•

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

•

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

•

salvage value for each rig; and

•

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

Our other 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, 2014. There were no material changes to these policies during the three months ended June 30, 2015.

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,
	2015			2014			2015			2014
REVENUE EARNING DAYS ⁽¹⁾
Floaters:
Ultra-Deepwater		654			420			1,160			933
Deepwater		402			281			687			624
Mid-Water		349			1,107			1,012			2,136
Jack-ups		287			464			645			965

UTILIZATION ⁽²⁾
Floaters:
Ultra-Deepwater		63	%		51	%		57	%		58	%
Deepwater		63	%		51	%		54	%		58	%
Mid-Water		32	%		68	%		42	%		66	%
Jack-ups		53	%		74	%		59	%		77	%

AVERAGE DAILY REVENUE ⁽³⁾
Floaters:
Ultra-Deepwater	$	483,000		$	435,000		$	489,000		$	416,500
Deepwater		450,900			429,300			465,700			428,000
Mid-Water		278,000			271,900			270,000			274,800
Jack-ups		82,800			98,000			88,100			95,800

⁽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 specified rigs in our fleet (including cold-stacked rigs, but excluding rigs under construction). As of June 30, 2015, our cold-stacked rigs included one deepwater semisubmersible, four mid-water semisubmersibles and four jack-up rigs.

⁽³⁾

Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet 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,
	2015			2014			2015			2014
	(In thousands)
CONTRACT DRILLING REVENUE
Floaters:
Ultra-Deepwater	$	315,670		$	182,656		$	567,066		$	388,450
Deepwater		181,104			120,539			319,874			267,098
Mid-Water		96,926			300,902			273,283			586,881

Total Floaters		593,700			604,097			1,160,223			1,242,429
Jack-ups		23,742			45,457			56,796			92,433

Total Contract Drilling Revenue	$	617,442		$	649,554		$	1,217,019		$	1,334,862


REVENUES RELATED TO REIMBURSABLE EXPENSES	$	16,590		$	42,690		$	37,069		$	66,806

CONTRACT DRILLING EXPENSE
Floaters:
Ultra-Deepwater	$	161,485		$	122,327		$	316,024		$	245,857
Deepwater		86,464			81,641			150,139			153,590
Mid-Water		66,735			148,931			166,055			282,977

Total Floaters		314,684			352,899			632,218			682,424
Jack-ups		20,873			29,851			42,443			57,880
Other		7,312			12,626			18,866			24,862

Total Contract Drilling Expense	$	342,869		$	395,376		$	693,527		$	765,166


REIMBURSABLE EXPENSES	$	16,336		$	42,290		$	36,428		$	65,956

OPERATING INCOME (LOSS)
Floaters:
Ultra-Deepwater	$	154,185		$	60,329		$	251,042		$	142,593
Deepwater		94,640			38,898			169,735			113,508
Mid-Water		30,191			151,971			107,228			303,904

Total Floaters		279,016			251,198			528,005			560,005
Jack-ups		2,869			15,606			14,353			34,553
Other		(7,312	)		(12,626	)		(18,866	)		(24,862	)
Reimbursable expenses, net		254			400			641			850
Depreciation		(123,329	)		(108,906	)		(260,628	)		(215,917	)
General and administrative expense		(16,548	)		(20,478	)		(34,000	)		(43,305	)
Gain on disposition of assets		164			8,572			775			8,719
Impairment of assets		—			—			(358,528	)		—
Restructuring and separation costs		(993	)		—			(7,161	)		—

Total Operating Income (Loss)	$	134,121		$	133,766		$	(135,409	)	$	320,043

Other income (expense):
Interest income		584			150			1,167			558
Interest expense, net of amounts capitalized		(25,468	)		(18,523	)		(49,450	)		(36,678	)
Foreign currency transaction gain (loss)		(3,473	)		(2,971	)		2,117			(4,149	)
Other, net		264			181			485			508

Income (loss) before income tax (expense) benefit		106,028			112,603			(181,090	)		280,282
Income tax (expense) benefit		(15,642	)		(22,890	)		15,767			(44,759	)


NET INCOME (LOSS)	$	90,386		$	89,713		$	(165,323	)	$	235,523

The following is a summary as of the date of this report of the most significant transfers of our rigs during 2015 and 2014 between the geographic areas in which we operate:


Rig	Rig Type	Relocation Details	Date
*Floaters⁽¹⁾:*
Ocean Confidence	Ultra-Deepwater	Angola to Cameroon	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 Monarch	Ultra-Deepwater	Indonesia to Malaysia (shipyard project)	September 2014
Ocean Clipper	Ultra-Deepwater	Colombia to Brazil	December 2014
Ocean BlackHornet	Ultra-Deepwater	South Korea to GOM (initial mobilization)	December 2014
Ocean BlackRhino	Ultra-Deepwater	South Korea to GOM (initial mobilization)	December 2014
Ocean BlackLion	Ultra-Deepwater	South Korea to Canary Islands (contract preparation)	May 2015

Ocean Monarch	Ultra-Deepwater	Malaysia to Australia	June 2015
Ocean Baroness	Ultra-Deepwater	Brazil to GOM	June 2015

Ocean Onyx	Deepwater	Placed in service (GOM)	January 2014
Ocean Star	Deepwater	Brazil to GOM (cold stacked April 2015)	September 2014
Ocean Apex	Deepwater	Singapore to Vietnam	December 2014
Ocean Onyx	Deepwater	GOM to Trinidad	March 2015
Ocean Victory	Deepwater	GOM to Trinidad	March 2015
Ocean Apex	Deepwater	Vietnam to Malaysia	April 2015

Ocean General	Mid-Water	Vietnam to Indonesia	March 2014
Ocean Quest	Mid-Water	Malaysia to Vietnam	May 2014
Ocean Patriot	Mid-Water	Singapore to U.K.	June 2014
Ocean Vanguard	Mid-Water	Norway to U.K. (cold stacked July 2014)	June 2014
Ocean General	Mid-Water	Indonesia to Malaysia (cold stacked October 2014)	September 2014
Ocean Quest	Mid-Water	Vietnam to Malaysia	April 2015

*Jack-ups*:
Ocean Titan	Jack-up	Mexico to GOM (cold stacked January 2015)	June 2014
Ocean Spur	Jack-up	Ecuador to Singapore (cold stacked June 2015)	April 2015
Ocean Nugget	Jack-up	Mexico to GOM (cold stacked June 2015)	June 2015

⁽¹⁾

The Ocean Concord, Ocean Yatzy and Ocean Epoch were sold for scrap in the first quarter of 2015. The Ocean Winner, Ocean Saratoga, Ocean Worker and Ocean Yorktown were sold for scrap in the second quarter of 2015.

Overview

Three Months Ended June 30, 2015 and 2014

Operating Income. Our operating results remained relatively flat, increasing $0.4 million during the second quarter of 2015, compared to the same period of 2014. Lower contract drilling expense ($52.5 million, or 13%) and general and administrative expense ($3.9 million) for the second quarter of 2015 were partially offset by a $32.1 million, or 5%, reduction in revenue, a $14.4 million increase in depreciation expense and the absence of an $8.8 million gain on sale of the Ocean Spartan in June 2014. Depreciation expense increased during the second quarter of 2015, primarily as a result of a higher depreciable asset base in 2015, which includes the Ocean Apex and three newbuild drillships that were placed in service after the second quarter of 2014.

Contract drilling revenue for our mid-water and jack-up fleets decreased $204.0 million and $21.7 million, respectively, during the second quarter of 2015 compared to the prior year period, primarily as a result of 758 and 177 fewer revenue earning days, respectively. In contrast, contract drilling revenue earned by our ultra-deepwater and deepwater floaters during the current year quarter increased $133.0 million and $60.6 million, respectively, compared to the second quarter of 2014, primarily due to higher average daily revenue earned by both our ultra-deepwater and deepwater fleets, including the effect of higher amortized mobilization and contract preparation fees, compared to the prior year, combined with an aggregate 355-day increase in revenue earning days.

Contract drilling expense decreased an aggregate of $52.5 million during the second quarter of 2015, compared to the same quarter of 2014, reflecting lower costs for labor and personnel ($24.7 million), repairs and maintenance ($27.8 million), inspections ($5.7 million), agency fees ($4.5 million), freight ($3.3 million), and a net decrease in other rig operating costs and overhead costs ($10.4 million), partially offset by higher rig mobilization costs ($23.9 million).

Interest Expense, Net of Amounts Capitalized. Interest expense increased $6.9 million during the second quarter of 2015, compared to the same period in 2014, primarily as a result of less interest capitalized in the current year quarter on our remaining construction projects ($10.0 million). This unfavorable impact was partially offset by the absence of $3.3 million of interest expense recognized in the prior year quarter related to our 5.15% Senior Notes, which we repaid in September 2014.

Income Tax Expense. Our effective tax rate for the three months ended June 30, 2015 was 14.9%, compared to a 20.3% effective tax rate for the three months ended June 30, 2014. The effective tax rate in the 2015 period was lower than in the same period of 2014 primarily due to the mix of our domestic and international pre-tax earnings and losses.

Six Months Ended June 30, 2015 and 2014

Operating (Loss) Income. Operating results decreased $455.5 million during the first half of 2015, compared to the same period of 2014, primarily due to a $358.5 million impairment loss, the effects of lower rig utilization during the current year period, primarily for our mid-water semisubmersible fleet, $7.2 million in restructuring and severance costs recognized in 2015 and the absence of an $8.8 million gain related to the sale of the Ocean Spartan in June 2014. Depreciation expense increased $44.7 million in the first six months of 2015, compared to the same period in 2014, primarily due to a higher depreciable asset base in 2015, which includes the Ocean Apex and three newbuild drillships, which were placed in service in 2014, and the Ocean BlackLion, which was delivered in May 2015.

These unfavorable results, which reduced operating income, were partially offset by the favorable impact of a $71.6 million, or 9%, net reduction in contract drilling expense, as a result of lower rig utilization, including the impact of cold stacked and retired rigs, and cost control efforts, and a $9.3 million reduction in general and administrative expense, primarily due to lower compensation costs, in the first half of 2015 compared to the prior year period. The decrease in contract drilling expense reflects lower costs for labor and personnel ($51.1 million), repairs and maintenance ($29.7 million), inspections ($5.9 million), freight ($3.7 million), and a net decrease in other rig operating, shorebase support and overhead costs ($9.2 million), partially offset by higher rig mobilization costs ($28.0 million).

Contract drilling revenue for our mid-water and jack-up fleets decreased $313.6 million and $35.6 million, respectively, during the first six months of 2015, compared to the prior year period, primarily as a result of 1,124 and 320 fewer revenue earning days, respectively, due to the cold stacking and sales of rigs in these fleets. In contrast, contract drilling revenue earned by our ultra-deepwater and deepwater floaters increased $178.6 million and $52.8 million, respectively, during the first half of 2015, compared to the same period of 2014, primarily due to higher average daily revenue earned by both our ultra-deepwater and deepwater fleets, including the effect of higher amortized mobilization and contract preparation fees, compared to the prior year period, combined with an aggregate 290-day increase in revenue earning days during the 2015 period.

Impairment of Assets. During the first six months of 2015, we determined that the carrying value of our 7,875-foot water depth rated drillship, the Ocean Clipper, and seven of our mid-water floaters, was impaired. We recorded an impairment loss aggregating $358.5 million in the first quarter of 2015. See “ —Critical Accounting Estimates—Impairment of Long-Lived Assets” and Notes 1 and 2 to our unaudited consolidated financial statements included in Item 1 of Part I of this report.

Restructuring and Separation Costs. In response to the continued decline in the offshore drilling market, we have reviewed our cost and organization structure. As a result, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities. During the six months ended June 30, 2015, we recognized $7.2 million in restructuring and employee separation related costs on behalf of separated employees.

Interest Expense, Net of Amounts Capitalized. Interest expense increased $12.8 million during the six-month period ended June 30, 2015, compared to the same period in 2014, primarily as a result of less interest capitalized during the first six months of 2015 on qualifying construction projects ($20.2 million) due to the completion of four projects in 2014. This unfavorable impact was partially offset by the absence of $6.4 million of interest expense recognized in the first half of 2014 related to our 5.15% Senior Notes, which we repaid in September 2014, combined with a $1.2 million reduction in interest expense recognized associated with uncertain tax positions.

Income Tax Expense. Our effective tax rate for the six months ended June 30, 2015 was 8.8%, compared to a 16.0% effective tax rate for the six months ended June 30, 2014. The effective tax rate in the 2015 period was lower than in the same period of 2014 primarily due to the mix of our domestic and international pre-tax earnings and losses, including asset impairments taken in various jurisdictions during 2015.

Contract Drilling Revenue and Expense by Equipment Type

Three Months Ended June 30, 2015 and 2014

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $133.0 million during the second quarter of 2015, compared to the same quarter of 2014, primarily as a result of 234 incremental revenue earning days ($101.7 million) and higher average daily revenue earned ($31.4 million). The increase in revenue earning days in the second quarter of 2015 was primarily attributable to incremental revenue earning days for our three newbuild drillships, the Ocean BlackHawk, Ocean BlackHornet and Ocean BlackRhino, and the Ocean Endeavor, which began drilling operations in Romania in the second half of 2014. These favorable contributions were partially offset by a decrease in revenue earning days due to downtime associated with a service-life extension project for the Ocean Confidence and operational issues with the Ocean Baroness during the second quarter of 2015. Average daily revenue for the second quarter of 2015 increased, compared to the second quarter of 2014, primarily due to a higher dayrate earned by the Ocean Endeavor offshore Romania, a February 2015 dayrate adjustment for the Ocean Courage, and incremental amortization of $5.6 million in rig mobilization and contract preparation fees.

Contract drilling expense for our ultra-deepwater floaters increased $39.2 million during the second quarter of 2015, compared to the same period of 2014, reflecting incremental contract drilling expense for our three newbuild drillships ($39.4 million) and the Ocean Endeavor ($7.3 million). Contract drilling expense for our other ultra-deepwater floaters decreased $7.5 million, primarily reflecting lower personnel related, maintenance and inspection costs, partially offset by higher rig mobilization costs.

Deepwater Floaters. Revenue generated by our deepwater floaters increased $60.6 million in the second quarter of 2015, compared to the same quarter in 2014, primarily due to 121 incremental revenue earning days ($51.9 million) and higher average daily revenue earned ($8.7 million) during the current year quarter. The increase in revenue earning days was the result of incremental revenue earning days for the Ocean Alliance (81 survey days in 2014 period) and the Ocean Valiant and Ocean Victory, which were both warm stacked between contracts in the second quarter of 2014 (129 additional days), partially offset by the cold stacking of the Ocean Star in the second quarter of 2015 (91 fewer days). Average daily revenue increased during the second quarter of 2015 primarily due to the recognition of a $10.0 million demobilization fee for the Ocean Apex upon completion of its initial contract in the second quarter of 2015.

Contract drilling expense incurred by our deepwater floaters increased $4.8 million during the second quarter of 2015, compared to the same period of 2014, primarily due to incremental contract drilling expense associated with contracts in the second quarter of 2015 for the Ocean Apex and Ocean Valiant ($22.0 million), incremental mobilization costs for the Ocean Onyx in connection with its Trinidad contract ($7.0 million) and higher contract drilling expense for our other deepwater rigs, including shorebase support costs ($5.3 million). The increase in contract drilling expense in the second quarter of 2015, compared to the second quarter of 2014, was partially offset by the Ocean Star, which was cold stacked in the second quarter of 2015 ($8.6 million) and the absence of costs associated with a 2014 five-year survey for the Ocean Alliance ($20.9 million).

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $204.0 million in the second quarter of 2015, compared to the same quarter in 2014, primarily due to 758 fewer revenue earning days ($206.1 million), which was the result of incremental downtime associated with cold-stacked and retired rigs (808 additional days) and planned downtime associated with a survey of the Ocean Guardian (42 additional days), partially offset by incremental revenue earning days for the Ocean Patriot, which resumed operations in the fourth quarter of 2014 after completion of an enhancement project (91 additional days).

Contract drilling expense decreased $82.2 million in the second quarter of 2015, compared to the prior year quarter, primarily due to reduced operating costs for our stacked or retired mid-water rigs ($95.3 million), partially offset by incremental costs incurred by the Ocean Patriot ($11.9 million).

Jack-ups. Contract drilling revenue and expense for our jack-up fleet decreased $21.7 million and $9.0 million, respectively, during the second quarter of 2015, compared to the prior year quarter, primarily due to decreased revenue and costs for the cold stacked Ocean King and Ocean Titan. Contract drilling revenue for the second quarter of 2015 was also negatively impacted by a dayrate reduction for the Ocean Scepter that was retroactive to the beginning of 2015 and reduced revenue for the current year quarter by $3.8 million.

Six Months Ended June 30, 2015 and 2014

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $178.6 million during the first six months of 2015, compared to the same period of 2014, primarily as a result of higher average daily revenue earned ($84.1 million), combined with 227 incremental revenue earning days ($94.5 million) in the first half of 2015. Average daily revenue increased during the first half of 2015, compared to the prior year period, primarily due to revenue associated with incremental operations for the Ocean Endeavor in Romania, a contract extension for the Ocean Rover at a higher dayrate than previously earned and a dayrate adjustment for the Ocean Courage, combined with incremental amortization of $13.2 million in mobilization and contract preparation fees and the operation of two additional drillships in the 2015 period. Total revenue earning days increased during the first half of 2015 primarily due to 239 incremental days earned by our newbuild drillships, the Ocean BlackHawk, Ocean BlackHornet, and Ocean BlackRhino and 150 incremental days associated with the Ocean Endeavor. These positive factors were partially offset by 90 fewer revenue earning days for the Ocean Confidence due to its service-life extension project and 78 fewer revenue earning days for the Ocean Baroness due to operational issues.

Contract drilling expense for our ultra-deepwater floaters increased $70.2 million during the first half of 2015, compared to the same period of 2014, reflecting incremental contract drilling expense for our newbuild drillships ($65.3 million) and the Ocean Endeavor ($20.6 million), partially offset by lower operating costs for the Ocean Confidence due to its service-life extension project ($9.0 million) and a net $6.7 million decrease in contract drilling expense for our other ultra-deepwater rigs.

Deepwater Floaters. Revenue generated by our deepwater floaters increased $52.8 million in the first half of 2015, compared to the same period in 2014, primarily due to 63 incremental revenue earning days ($26.9 million) in the current year period combined with higher average daily revenue earned ($25.9 million). Revenue earning days increased during the first six months of 2015 due to incremental revenue earning days for the Ocean Apex (72 additional days), which completed its major upgrade in late 2014, the Ocean Valiant (81 additional days) and the Ocean Alliance (128 fewer survey days), partially offset by 181 fewer revenue earning days for the Ocean Star, which has been idle since the third quarter of 2014, and incremental days associated with the mobilization of other deepwater rigs (54 days). Higher average daily revenue earned during the first half of 2015 reflected revenue earned by the Ocean Apex and incremental amortization of $15.1 million in mobilization and contract preparation fees.

Contract drilling expense incurred by our deepwater floaters decreased an aggregate $3.5 million during the first six months of 2015, compared to the same period of 2014, primarily due to reduced operating costs for the Ocean Star ($11.7 million), the absence of costs associated with a 2014 five-year survey for the Ocean Alliance ($20.9 million) and lower other operating and shorebase support costs ($3.8 million). These cost reductions were partially offset by incremental operating costs incurred by the Ocean Apex ($19.0 million) and increased mobilization costs for the Ocean Valiant and Ocean Onyx ($13.9 million) in the 2015 period.

Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $313.6 million in the first half of 2015, compared to the same period in 2014, primarily due to 1,124 fewer revenue earning days ($308.8 million), combined with the effect of lower average daily revenue earned ($4.8 million). The reduction in revenue earning days during the first six months of 2015 was the result of incremental downtime associated with ten cold-stacked or retired rigs (1,406 additional days), partially offset by incremental revenue earning days for the Ocean Patriot after completion of an enhancement project (181 additional days) and the Ocean Quest, which operated in Vietnam during the first half of 2015, compared to the prior year when the rig was warm stacked between contracts (57 additional days), and fewer aggregate incremental downtime days for rig mobilization, surveys and unpaid repairs (44 fewer days).

Contract drilling expense decreased $116.9 million in the first six months of 2015, compared to the prior year period, primarily due to reduced operating costs for our cold-stacked or retired mid-water rigs ($143.9 million), partially offset by incremental costs for the Ocean Patriot ($24.7 million).

Jack-ups. Contract drilling revenue and expense for our jack-up fleet decreased $35.7 million and $15.4 million, respectively, during the first half of 2015, compared to the prior year period, primarily due lower revenue and contract drilling expense for the cold-stacked Ocean Titan and Ocean King .

Liquidity and Capital Resources

We currently have available a syndicated Revolving Credit Agreement, or Credit Agreement, to meet our short-term and long-term liquidity needs.

At June 30, 2015 and December 31, 2014, we had cash available for current operations as follows:


	June 30,		December 31,
	2015		2014
	(In thousands)
Cash and equivalents	$	95,854	$	233,623
Marketable securities		15,953		16,033

Total cash available for current operations	$	111,807	$	249,656

As of July 1, 2015, our contract drilling backlog was approximately $5.9 billion, of which approximately $1.1 billion is expected to be realized in the second half of 2015.

Historically, a substantial portion of our cash flows has been 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 our wholly-owned subsidiary 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. To the extent available, 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 the remainder of 2015 and in 2016, we may also make use of our credit facility or commercial paper program to finance our capital expenditures and working capital requirements. 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, Senior Notes and Commercial Paper Program.”

We pay dividends at the discretion of our Board of Directors, or Board. During the six-month period ended June 30, 2015, we paid cash dividends totaling $34.3 million. 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. Our Board has adopted a policy of considering paying regular and special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. Our dividend policy may change from time to time, and there can be no assurance that we will continue to declare any cash dividends at all or in any particular amounts.

On July 31, 2015, we declared a regular cash dividend of $0.125 per share of our common stock, which is payable on September 1, 2015 to stockholders of record on August 14, 2015.

Depending on market and other conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not purchase any shares of our outstanding common stock during the six-month period ended June 30, 2015. However, during the six-month period ended June 30, 2015, in connection with the vesting of restricted stock units held by our chief executive officer, we withheld 7,810 shares of common stock, with a cost of $0.2 million, to satisfy the associated payroll tax obligation.

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. 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. During the six-month period ended June 30, 2015, Loews purchased 904,154 shares of our common stock. Loews did not purchase any shares of our outstanding common stock during the six-month period ended June 30, 2014.

Our primary source of cash during the six-month period ended June 30, 2015, was an aggregate $200.8 million generated from operating activities, $375.0 million from short-term borrowings under our commercial paper program and $7.7 million from the disposition of assets, including $4.8 million in proceeds from the sale of seven mid-water floaters for scrap during the period. Our primary uses of cash during the same period were $686.1 million towards the construction of new rigs and our ongoing rig equipment enhancement/replacement program, including payment of the final construction installment due on the Ocean BlackLion, and $35.1 million for the payment of dividends and anti-dilution adjustments to stock plan participants. See “ — Credit Agreement, Senior Notes and Commercial Paper Program — Commercial Paper Program.”

For 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.

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 credit ratings, 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, 2015 and 2014 were as follows:


	Six Months Ended June 30,
	2015		2014
	(In thousands)
Cash flow from operations	$	200,844	$	367,327

Cash capital expenditures:
Drillship construction	$	407,980	$	465,103
Construction of deepwater floaters		34,020		94,307
Construction of ultra-deepwater floater		21,828		7,703
Ocean Patriot enhancement project		1,448		66,239
Ocean Confidence service-life extension project		74,825		—
Rig equipment and replacement programs		146,010		184,023

Total capital expenditures	$	686,111	$	817,375

Cash Flow

Cash flow from operations decreased approximately $166.5 million during the first six months of 2015, compared to the first six months of 2014, primarily due to lower cash receipts from contract drilling services ($191.5 million), partially offset by a $23.3 million net decrease in cash payments for contract drilling and general and administrative expenses, including personnel-related, maintenance, mobilization and other rig operating costs.

Capital Expenditures

As of the date of this report, we expect our capital spending for 2015 to aggregate approximately $920.0 million, of which we expect to spend approximately $630.0 million on our current rig construction projects, including the Ocean Confidence service-life-extension project. During the first half of 2015, we incurred $484.6 million in project-related expenditures, including accrued expenditures. See “ — Contractual Cash Obligations — Rig Construction.” Our 2015 capital spending program also includes an estimated $290.0 million for our ongoing capital maintenance and replacement programs, of which $126.1 million had been incurred as of June 30, 2015.

Contractual Cash Obligations—Rig Construction

As of the date of this report, we have one rig, the Ocean GreatWhite, under construction in Ulsan, South Korea, for which we are obligated under a construction agreement with Hyundai Heavy Industries Co., Ltd. Construction of the Ocean GreatWhite continues with delivery expected in the second quarter of 2016. The estimated total project cost, including shipyard costs, capital spares, commissioning, project management and shipyard supervision, is $764.0 million, of which $212.9 million has been incurred as of June 30, 2015. See Note 11 “Commitments and Contingencies” to our unaudited consolidated financial statements included in Item 1 of Part I of this report for more information about this project.

We had no other purchase obligations for major rig upgrades or any other significant obligations at June 30, 2015, except for those related to our direct rig operations, which arise during the normal course of business.

Other Obligations

As of June 30, 2015, we had foreign currency forward exchange, or FOREX, contracts outstanding in the aggregate notional amount of $2.7 million. See further information regarding these contracts in Note 7 “Derivative Financial Instruments” to our unaudited consolidated financial statements included in Item 1 of Part I of this report.

As of June 30, 2015, the total unrecognized tax benefits related to uncertain tax positions was $53.5 million. In addition, we have recorded a liability, as of June 30, 2015, for potential penalties and interest of $39.8 million and $7.7 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, Senior Notes and Commercial Paper Program

Credit Agreement

Our Credit Agreement provides for a $1.5 billion senior unsecured revolving credit facility, for general corporate purposes, and matures on October 22, 2019, except for $40 million of commitments that mature on March 17, 2019. We also have the option to increase the revolving commitments under the Credit Agreement by up to an additional $500 million from time to time, upon receipt of additional commitments from new or existing lenders, and to request up to two additional one-year extensions of the maturity date. 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, 2015, there were no loans or letters of credit outstanding under the Credit Agreement, and we were in compliance with all covenant requirements under the Credit Agreement. See “ — Commercial Paper Program.”

Senior Notes

On July 1, 2015, we repaid $250.0 million in aggregate principal amount of our 4.875% Senior Notes due July 1, 2015, primarily with funds obtained through the issuance of additional commercial paper.

Commercial Paper Program

In February 2015, we established a commercial paper program with three commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5 billion. Proceeds from issuances under the commercial paper program may be used for general corporate purposes. The maturities of the notes may vary, but may not exceed 397 days from the date of issuance. The notes will be issued, at our option, either at a discounted price to their principal face value or will bear interest, which may be at a fixed or floating rate, at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The notes are not redeemable or subject to voluntary prepayment by us prior to maturity. Our Credit Agreement provides liquidity for our payment obligations in respect of the notes issued under the commercial paper program, and the aggregate amount of notes outstanding at any time will not exceed the amount available under the Credit Agreement. During the quarter ended June 30, 2015, we added a fourth commercial paper dealer to our commercial paper program. As of June 30, 2015, we had $375.0 million in commercial paper notes outstanding with a weighted average interest rate of 0.49% and a weighted average remaining term of eight days.

We continually assess our working capital availability and requirements and reevaluate our aggregate commercial paper position based on daily net working capital activity and short and long-term cash requirements, including the repayment of debt and our capital spending program. We expect to issue additional commercial paper, as necessary, to meet short-term liquidity needs, and to reduce our aggregate commercial paper position, as excess operating cash flow allows, maintaining our financial flexibility. However, we expect our short-term borrowings to increase over the next 12 months.

As of July 31, 2015, we had an additional $910.8 million available under the Credit Agreement for the issuance of commercial paper.

Credit Ratings

In April 2015, Standard & Poor’s Ratings Services, or S&P, revised its outlook on us from negative to stable and lowered our corporate credit and unsecured debt rating from A- to BBB+. Our current credit rating is A3 for Moody’s Investors Services, or Moody’s. In February 2015, Moody’s and S&P assigned short-term credit ratings of Prime-2 and A2, respectively, to our commercial paper program. Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered. A downgrade in our credit ratings could impact our cost of issuing additional debt and the amount of additional debt that we could issue. A series of downgrades or a substantial downgrade could restrict our access to capital markets and our ability to raise additional debt or rollover existing maturities. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.

Other Commercial Commitments – Letters of Credit

We were contingently liable as of June 30, 2015 in the amount of $68.4 million under certain performance, security, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $61.6 million of performance, security, supersedeas and customs bonds can require collateral at any time. As of June 30, 2015, 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		2015		2016		2017		2018
	(In thousands)
Other Commercial Commitments
Performance bonds	$	56,846	$	1,700	$	9,911	$	26,110	$	19,125
Supersedeas bond		9,189		9,189		—		—		—
Other		2,358		1,415		943		—		—

Total obligations	$	68,393	$	12,304	$	10,854	$	26,110	$	19,125

Off-Balance Sheet Arrangements

At June 30, 2015 and December 31, 2014, we had no off-balance sheet debt or other off-balance sheet arrangements.

Recent Accounting Pronouncements

See Note 1 “General Information” to our unaudited consolidated financial statements included 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 may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

•

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

•

sources and uses of and requirements for financial resources;

•

availability under our Credit Agreement and issuance of notes under our commercial paper program;

•

interest rate and foreign exchange risk;

•

contractual obligations;

•

operations outside the United States;

•

business strategy;

•

growth opportunities;

•

competitive position;

•

expected financial position;

•

cash flows and contract backlog;

•

declaration or payment of regular or special dividends;

•

financing plans;

•

market outlook;

•

tax planning;

•

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

•

budgets for capital and other expenditures;

•

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

•

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

•

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

•

plans and objectives of management;

•

idling drilling rigs or reactivating stacked rigs;

•

scrapping retired rigs;

•

assets held for sale;

•

asset impairments and impairment evaluations and any future use or disposition of impaired assets;

•

effective date and performance of contracts;

•

outcomes of legal proceedings;

•

compliance with applicable laws; and

•

availability, limits and adequacy of insurance or indemnification.

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

•

those described under “Risk Factors” in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014;

•

general economic and business conditions;

•

worldwide demand for oil and natural gas;

•

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

•

oil and natural gas price fluctuations and related market expectations;

•

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

•

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

•

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

•

the cancellation or renegotiation of contracts included in our reported contract backlog;

•

advances in exploration and development technology;

•

the worldwide political and military environment, including, for example, in oil-producing regions and locations where our rigs are operating or where we have rigs under construction;

•

casualty losses;

•

operating hazards inherent in drilling for oil and gas offshore;

•

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

•

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

•

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

•

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

•

competition;

•

changes in foreign, political, social and economic conditions;

•

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

•

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

•

customer or supplier bankruptcy or liquidation;

•

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

•

collection of receivables;

•

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

•

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

•

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

•

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

•

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

•

compliance with and liability under environmental laws and regulations;

•

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

•

development and exploitation of alternative fuels;

•

customer preferences;

•

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

•

cost, availability, limits and adequacy of insurance;

•

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

•

the results of financing efforts;

•

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.

There were no material changes in our market risk components for the six months ended June 30, 2015. See Quantitative and Qualitative Disclosures About Market Risk included in Item 7A of our Annual Report on Form 10-K filed with the Securities and Exchange Commission for the year ended December 31, 2014 for further information.

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, 2015. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2015.

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 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 6.

Exhibits.

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

SIGNATURES

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

DIAMOND OFFSHORE DRILLING, INC.

(Registrant)



Date	August 3, 2015	By:	\s\ Gary T. Krenek
			Gary T. Krenek
			Senior Vice President and Chief Financial Officer


Date	August 3, 2015		\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		Amendment to Employment Agreement, dated April 1, 2015, between Diamond Offshore Management Company and Beth G. Gordon (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015).

10.2*		Separation Agreement and General Release, dated March 30, 2015, between Diamond Offshore Management Company and John M. Vecchio.

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.