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 ☑☒ 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 RegulationS-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section ~~7(a)(2)(B)~~13(a) of the ~~Securities~~Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined inRule 12b-2 of the Exchange Act). Yes ☐ No ☑☒

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, ~~2017~~2018 Common stock, $0.01 par value per share ~~137,226,991~~137,434,458 shares


	June 30,			December 31,			June 30,			December 31,
	2017			2016			2018			2017
ASSETS
Current assets:
Cash and cash equivalents	$	160,969		$	156,233		$	144,168		$	376,037
Marketable securities								274,671			—
Accounts receivable, net of allowance for bad debts		311,517			247,028			203,131			256,730
Prepaid expenses and other current assets		107,690			102,146			154,408			157,625
Asset held for sale		—			400
Assets held for sale								67,815			96,261

Total current assets		580,176			505,807			844,193			886,653
Drilling and other property and equipment, net of accumulated depreciation		5,490,158			5,726,935			5,197,197			5,261,641
Other assets		122,929			139,135			71,389			102,276

Total assets	$	6,193,263		$	6,371,877		$	6,112,779		$	6,250,570

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current liabilities:
Accounts payable	$	32,717		$	30,242		$	54,717		$	38,755
Accrued liabilities		110,702			182,159			130,123			154,655
Taxes payable		13,672			23,898			14,522			29,878
Short-term borrowings		—			104,200

Total current liabilities		157,091			340,499			199,362			223,288
Long-term debt		1,981,458			1,980,884			1,973,059			1,972,225
Deferred tax liability		143,619			197,011			124,350			167,299
Other liabilities		119,277			103,349			105,278			113,497

Total liabilities		2,401,445			2,621,743			2,402,049			2,476,309

Commitments and contingencies (Note 7)
Stockholders’ equity:
Commitments and contingencies (Note 9)

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; 144,080,636 shares issued and 137,224,156 shares outstanding at June 30, 2017; 143,997,757 shares issued and 137,169,663 shares outstanding at December 31, 2016)		1,441			1,440
Common stock (par value $0.01, 500,000,000 shares authorized; 144,374,006 shares issued and 137,430,916 shares outstanding at June 30, 2018; 144,085,292 shares issued and 137,227,782 shares outstanding at December 31, 2017)								1,444			1,441
Additional paid-in capital		2,007,798			2,004,514			2,013,862			2,011,397
Retained earnings		1,985,640			1,946,765			1,899,735			1,964,497
Accumulated other comprehensive (loss) gain		(2	)		1
Treasury stock, at cost (6,856,480 and 6,828,094 shares of common stock at June 30, 2017 and December 31, 2016, respectively)		(203,059	)		(202,586	)
Accumulated other comprehensive income (loss)								23			(5	)
Treasury stock, at cost (6,943,090 and 6,857,510 shares of common stock at June 30, 2018 and December 31, 2017, respectively)								(204,334	)		(203,069	)

Total stockholders’ equity		3,791,818			3,750,134			3,710,730			3,774,261

Total liabilities and stockholders’ equity	$	6,193,263		$	6,371,877		$	6,112,779		$	6,250,570

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


	Three Months Ended						Six Months Ended						Three Months Ended						Six Months Ended
	June 30,						June 30,						June 30,						June 30,
	2017			2016			2017			2016			2018			2017			2018			2017
Revenues:
Contract drilling	$	392,170		$	357,409		$	755,727		$	800,932		$	265,353		$	392,170		$	553,279		$	755,727
Revenues related to reimbursable expenses		7,119			31,338			17,788			58,358			3,508			7,119			11,092			17,788

Total revenues		399,289			388,747			773,515			859,290			268,861			399,289			564,371			773,515

Operating expenses:
Contract drilling, excluding depreciation		196,217			198,336			399,740			411,177			189,321			196,217			374,010			399,740
Reimbursable expenses		6,790			16,527			17,268			43,318			3,414			6,790			10,884			17,268
Depreciation		85,982			105,016			179,211			209,256			81,825			85,982			163,650			179,211
General and administrative		19,010			18,139			36,493			33,537			18,236			19,010			36,749			36,493
Impairment of assets		71,268			678,145			71,268			678,145			27,225			71,268			27,225			71,268
Restructuring and separation costs														1,265			—			4,276			—
Gain on disposition of assets		(802	)		(747	)		(2,148	)		(1,043	)		(50	)		(802	)		(560	)		(2,148	)

Total operating expenses		378,465			1,015,416			701,832			1,374,390			321,236			378,465			616,234			701,832

Operating income (loss)		20,824			(626,669	)		71,683			(515,100	)
Operating (loss) income														(52,375	)		20,824			(51,863	)		71,683

Other income (expense):
Interest income		396			269			571			442			2,001			396			3,638			571
Interest expense, net of amounts capitalized		(27,251	)		(24,156	)		(54,847	)		(49,672	)		(29,585	)		(27,251	)		(57,903	)		(54,847	)
Foreign currency transaction (loss) gain		(927	)		(3,513	)		160			(7,121	)
Foreign currency transaction gain (loss)														411			(927	)		858			160
Other, net		(62	)		(12,046	)		(125	)		(11,468	)		262			(62	)		842			(125	)

(Loss) income before income tax benefit		(7,020	)		(666,115	)		17,442			(582,919	)		(79,286	)		(7,020	)		(104,428	)		17,442

Income tax benefit		22,969			76,178			22,046			80,407			10,012			22,969			54,475			22,046

Net income (loss)	$	15,949		$	(589,937	)	$	39,488		$	(502,512	)
Net (loss) income													$	(69,274	)	$	15,949		$	(49,953	)	$	39,488

Earnings (loss) per share, Basic and Diluted	$	0.12		$	(4.30	)	$	0.29		$	(3.66	)
(Loss) earnings per share, Basic and Diluted													$	(0.50	)	$	0.12		$	(0.36	)	$	0.29

Weighted-average shares outstanding:
Shares of common stock		137,224			137,170			137,199			137,166			137,429			137,224			137,362			137,199
Dilutive potential shares of common stock		3			—			36			—			—			3			—			36

Total weighted-average shares outstanding		137,227			137,170			137,235			137,166			137,429			137,227			137,362			137,235

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


		Six Months Ended						Six Months Ended
		June 30,						June 30,
		2017			2016			2018			2017
Operating activities:	Operating activities:
Net income (loss)		$	39,488		$	(502,512	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net (loss) income								$	(49,953	)	$	39,488
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation			179,211			209,256			163,650			179,211
Loss on impairment of assets			71,268			678,145			27,225			71,268
Restructuring and separation costs									2,184			—
Gain on disposition of assets			(2,148	)		(1,043	)		(560	)		(2,148	)
Loss on sale of marketable securities			—			12,146
Deferred tax provision			(54,425	)		(162,531	)		(61,160	)		(54,425	)
Stock-based compensation expense			2,651			2,829			2,468			2,651
Deferred income, net			11,524			(16,363	)
Deferred expenses, net			16,866			4,751
Contract liabilities, net									(3,255	)		11,524
Contract assets, net									(956	)		—
Deferred contract costs, net									24,703			16,866
Other assets, noncurrent			(1,619	)		(900	)		742			(1,619	)
Other liabilities, noncurrent			407			4,189			(3,849	)		407
Other			1,202			1,484			393			1,202
Changes in operating assets and liabilities:	Changes in operating assets and liabilities:
Accounts receivable			(64,489	)		80,782			53,451			(64,489	)
Prepaid expenses and other current assets			(6,154	)		2,281			28			(6,154	)
Accounts payable and accrued liabilities			(12,291	)		(59,788	)		(21,466	)		(12,291	)
Taxes payable			(4,610	)		52,744			(2,878	)		(4,610	)

Net cash provided by operating activities			176,881			305,470			130,767			176,881

Investing activities:
Capital expenditures (including rig construction)			(71,889	)		(533,412	)
Capital expenditures									(90,432	)		(71,889	)
Proceeds from maturities of marketable securities									300,000			—
Purchase of marketable securities									(573,837	)		—
Proceeds from disposition of assets, net of disposal costs			4,077			167,298			1,723			4,077
Proceeds from sale and maturities of marketable securities			23			4,592
Other									—			23

Net cash used in investing activities			(67,789	)		(361,522	)		(362,546	)		(67,789	)

Financing activities:
Net (repayment of) proceeds from short-term borrowings			(104,200	)		40,711
Net repayment of short-term borrowings									—			(104,200	)
Other			(156	)		(408	)		(90	)		(156	)

Net cash (used in) provided by financing activities			(104,356	)		40,303
Net cash used in financing activities									(90	)		(104,356	)

Net change in cash and cash equivalents			4,736			(15,749	)		(231,869	)		4,736
Cash and cash equivalents, beginning of period			156,233			119,028			376,037			156,233

Cash and cash equivalents, end of period		$	160,969		$	103,279		$	144,168		$	160,969

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

The unaudited condensed 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 Form10-K for the year ended December 31, ~~2016~~2017 (FileNo. 1-13926).

As of July 27, ~~2017,~~2018, Loews Corporation owned approximately 53% of the outstanding shares of our common stock.

The accompanying unaudited condensed 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 Form10-Q and Article 10 of RegulationS-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~~annual financial statements. The condensed consolidated financial information has not been audited but, in the opinion of management, includes all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of Diamond Offshore’s condensed 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.

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.

We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income currently while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset are capitalized. During the six-month period ended June 30, 2017 and the year ended December 31, 2016, we capitalized $9.3 million and $177.6 million, respectively, in replacements and betterments of our drilling fleet. See Note 6.

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, a decision to retire, scrap or cold stack a rig, contracted backlog of less than one year for a rig, or excess spending over budget on a newbuild construction project or major rig upgrade)Revenue Recognition. ~~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:~~

Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we assign 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 the rig’s future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance, inspection and reactivation costs, are estimated using historical data adjusted for known developments, cost projections for re-entry of rigs into the market 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.

We capitalize interest cost for rig construction or upgrades, as well as other qualifying projects. A reconciliation of our total interest cost to “Interest expense, net of amounts capitalized” as reported in our Condensed Consolidated Statements of Operations is as follows:

In ~~March 2016,~~May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU,No. ~~2016-09,~~2014-09,~~Compensation - Stock Compensation~~Revenue from Contracts with Customers(Topic 606), or ASU2014-09, which supersedes the revenue recognition requirements in ASU Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services.

We adopted ASU2014-09 and its related amendments, or collectively Topic 606, effective January 1, 2018 using the modified retrospective implementation method. Accordingly, we have applied the five-step method outlined in Topic 606 for determining when and how revenue is recognized to all contracts that were not completed as of the date of adoption. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. For contracts that were modified before the effective date, we have considered the modification guidance within the new standard and determined that the revenue recognized and contract balances recorded prior to adoption for such contracts were not impacted. While Topic 606 requires additional disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact on the measurement or recognition of our revenues.

Our adoption of ASU2014-09 represents a change in accounting principle and therefore, we have recorded the cumulative effect of adopting Topic 606 as an increase to opening retained earnings on January 1, 2018. This adjustment represents an accrual for the earned portion of demobilization revenue expected to be received for contracts not completed as of December 31, 2017, which was not recordable under previous revenue recognition guidance until completion of the demobilization activities. See Note 2.

Income Taxes. In October 2016, the FASB issued ASUNo. 2016-16,Income Taxes (Topic ~~718)~~740): Intra-Entity Transfers of Assets Other Than Inventory, or ASU2016-16. ASU2016-16 amends the guidance in Topic 740 with respect to the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. We have evaluated our historical intra-group transactions for impact under the provisions of ASU2016-16 and have adopted the guidance thereof effective January 1, 2018 using the modified retrospective approach. We have recorded the $17.4 million cumulative effect of applying the new standard as a decrease to opening retained earnings with an offset to deferred income tax liability. See Note 11.

The aggregate impact of the changes in accounting principles, as discussed above, to our unaudited Condensed Consolidated Balance Sheet on January 1, 2018 was as follows (in thousands):

In February 2018, the FASB issued ASUNo. 2018-02,Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, or ASU ~~2016-09.~~2018-02. ASU ~~2016-09 requires that all excess tax benefits and tax deficiencies be recognized in~~2018-02 provides for entities to make aone-time election to reclassify the income ~~statement as discrete~~ tax effects of the Tax Cuts and Jobs Act enacted in December 2017, or the Tax Reform Act, on items ~~when share-based awards vest or are settled.~~within accumulated other comprehensive income to retained earnings. The ~~update also clarifies the statement~~guidance of cash flows presentation for certain components of share-based awards and provides for a policy election to either estimate the number of awards expected to vest or account for forfeitures when they occur. ASU ~~2016-09~~2018-02 is effective for fiscal years beginning after December 15, ~~2016~~2018, including interim periods within that reporting period. Early adoption of ASU2018-02 is permitted. We have early adopted ASU2018-02 and ~~was adopted by us on January 1, 2017.~~

~~The guidance requiring (i) excess tax benefits to be recorded~~have reclassified the effect of the change in the ~~condensed consolidated statement of operations, (ii) exclusion of excess~~U.S. federal corporate income tax ~~benefits from the computation of assumed proceeds under the treasury stock method when calculating earnings per share, and (iii) presentation of excess tax benefits as an operating activity~~rate on ~~the statement of cash flows, rather than as a financing activity, has been applied prospectively effective January 1, 2017. We have elected to account for forfeitures of share-based awards~~deferredtax-related items remaining in the period in which such forfeitures occur rather than using an estimated forfeiture rate and have adopted this change using a modified retrospective approach, which resulted in a $0.6 million reduction in opening retained earnings.accumulated other comprehensive loss. The impact ~~to our Condensed Consolidated Balance Sheets is as follows:~~

   Retained
Earnings    Additional
Paid-in Capital
   (In thousands)
Balance as of January 1, 2017 before adoption
   $ 1,946,765    $ 2,004,514
Adjustment for making election to account for forfeitures as they occur
   (634 )    634




Balance as of January 1, 2017 after adoption
   $ 1,946,131    $ 2,005,148

~~Recent Accounting Pronouncements~~of adoption of ASU2018-02 was not significant.

In August 2016, the FASB issued ASUNo. 2016-15,Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, or ASU2016-15. ASU2016-15 provides specific guidance on eight cash flow classification issues not specifically addressed by GAAP: debt prepayment or debt extinguishment costs; settlement ofzero-coupon debt instruments; contingent consideration payments; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments in ASU 2016-15 are effective for interim and annual periods beginning after December 15, 2017. ASU 2016-15 should be applied using a retrospective transition method, unless it is impracticable to do so for some of the issues. In such case, the amendments for those issues would be applied prospectively as of the earliest date practicable. Early adoption ~~is permitted. We are currently evaluating the provisions~~ of ASU2016-15 ~~but do~~ did not ~~expect ASU 2016-15 to~~ have a significant impact on the presentation of cash receipts and cash payments within our condensed consolidated statements of cash flows.

In February 2016, the FASB issued ASUNo. 2016-02,Leases (Topic 842), or ASU2016-02, which (i) requires ~~an entity~~lessees to ~~separate the lease components from the non-lease components in~~recognize a ~~contract. The lease components are to be accounted for under ASU 2016-02, which, under the guidance, may require recognition~~right of ~~lease assets and lease liabilities by lessees for most leases and derecognition of the leased~~use asset and a lease liability on the balance sheet for virtually all leases, (ii) updates previous accounting standards for lessors to align certain requirements with the updates to lessee accounting standards and the revenue recognition accounting standards and (iii) requires enhanced disclosure of ~~a net investment in~~qualitative and quantitative information about the lease by the lessor. ASU 2016-02 also provides for additional disclosure requirements for both lessees and lessors. Non-lease components would be accounted for under ASU 2014-09. The guidance of ASU 2016-02entity’s leasing arrangements. This update is effective for annual ~~reporting~~and interim periods beginning after December 15, 2018, ~~including interim periods within that reporting period. Early~~with early adoption permitted. During our evaluation of ASU2016-02, ~~is permitted. We expect to adopt ASU 2016-02~~ we concluded that our drilling contracts contain a lease component based on ~~January 1, 2019. We are currently reviewing~~ the ~~provisions~~updated definition of ~~the accounting standard, but have not yet determined the impact of ASU 2016-02 on our financial position, results of operations or cash flows or our expected transition method.~~

~~In May 2014,~~a lease. On March 28, 2018, the FASB ~~issued~~held a meeting to approve certain additional amendments to ASU ~~No. 2014-09,~~2016-02, including a revision to the practical expedient that would allow a lessor to account for the combined lease andnon-lease components under Topic 606,Revenue from Contracts with Customers ~~(Topic 606)~~, ~~or ASU 2014-09. The new standard supersedes~~when the ~~industry-specific standards that currently exist under GAAP and provides a framework~~non-lease component is the predominant element of the combined component. As this content is still pending, we are not yet able to ~~address~~determine what, if any, impact our adoption will have on our revenue recognition ~~issues comprehensively for all contracts with customers regardless~~patterns and related disclosures.

With respect to leases whereby we are the lessee, we expect to recognize lease liabilities and offsetting right of ~~industry-specific or transaction-specific fact patterns. Under~~use assets corresponding to, at a minimum, our currently identified, undiscounted future minimum lease commitments of approximately $490 million, primarily related to certain leased subsea equipment. However, we are still evaluating the ~~new guidance, companies recognize revenue~~overall impact and will continue to ~~depict~~refine our estimate prior to adoption of the ~~transfer of promised goods or services~~ASU. We

currently expect to ~~customers~~elect the transition practical expedient package available 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 provides a five-step analysis of transactions to determine when and how revenue is recognized and requires enhanced disclosures about revenue. In July 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09. ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017. We plan to adopt ASU 2014-09 effective January 1, 2018 using the modified retrospective approach whereby we will ~~record~~not reassess (i) whether any of our expired or existing contracts contain a lease, (ii) the ~~cumulative effect~~classification for any expired or existing leases and (iii) initial direct costs for any existing leases.

The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of ~~applying the new standard to all outstanding contracts as of January 1, 2018 as an adjustment to opening retained earnings.~~

~~When applying the new standard, we plan to~~dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for ~~the~~these integrated services provided within our drilling contracts as a single performance obligation ~~composed~~satisfied over time and comprised of a series of distinct time increments in which ~~will~~we provide drilling services.

Consideration for activities that are not distinct within the context of our contracts and do not correspond to a distinct time increment within the contract term are allocated across the single performance obligation and recognized ratably as time elapses over the initial term of the contract (which is the period we estimate to be ~~satisfied over time. We will determine~~benefited from the corresponding activities and generally ranges from two to 60 months). Consideration for activities that correspond to a distinct time increment within the contract term is recognized in the period when the services are performed. The total transaction price is determined for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. ~~Consideration~~See below for further discussion regarding the allocation of the transaction price to the remaining performance obligations.

The amount estimated for variable consideration may be constrained (reduced) and is only included in the transaction price to the extent that ~~does not relate to~~it is probable that a ~~distinct good or service, such as mobilization, demobilization, and contract preparation~~significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, management considers whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates arere-assessed each reporting period as required.

Dayrate Drilling Revenue.Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated ~~across~~to the ~~single~~distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.

Mobilization/Demobilization Revenue.We may receive fees (on either a fixedlump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.

In some contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, contractual provisions may require that a rig demobilize a certain distance before the demobilization revenue is payable or the amount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the wellsite. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

Contract Preparation Revenue.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 fixedlump-sum or variable dayrate basis). These activities are not considered to be distinct within the context of the contract. We record a contract liability for contract preparation fees received, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contract.

Capital Modification Revenue. From time to time, we may receive fees from our customers for capital improvements or upgrades to our rigs to meet contractual requirements (on either a fixedlump-sum or variable dayrate basis). The activities related to these capital modifications are not considered to be distinct within the context of our contracts. We record a contract liability for such fees and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.

Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our unaudited Condensed Consolidated Statements of Operations. Such amounts are recognized ratably over the period within the contract term during which the corresponding goods and services are to be consumed.

Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Contract asset balances consist primarily of demobilization revenue that we expect to receive and is recognized ratably throughout the contract term, but invoiced upon completion of the demobilization activities. Once the demobilization revenue is invoiced, the corresponding contract asset is transferred to accounts receivable. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract. ~~All other components of consideration within~~

Contract balances are netted at a contract ~~including~~level, such that deferred revenue for mobilization, contract preparation and capital modifications (contract liabilities) is netted with any accrued demobilization revenue (contract asset) for each applicable contract.

The following table provides information about receivables, contract assets and contract liabilities from our contracts with customers (in thousands):

Significant changes in the ~~dayrate~~contract assets and the contract liabilities balances during the period are as follows (in thousands):

Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Such deferred contract costs in the amount of $56.1 million and $25.1 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our unaudited Condensed Consolidated Balance Sheet at June 30, 2018. During the three-month andsix-month periods ended June 30, 2018, the amount of amortization of such costs was $14.3 million and $27.2 million, respectively. There was no impairment loss in relation to capitalized costs.

Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement.

The following table reflects revenue ~~will continue~~expected to be recognized in the ~~period when~~future related to unsatisfied performance obligations as of June 30, 2018 (in thousands):

The revenue included above consists primarily of expected fixed mobilization, demobilization, and upgrade revenue for both wholly and partially unsatisfied performance obligations as well as expected variable mobilization, demobilization, and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the ~~services~~entire corresponding performance obligations. The amounts are ~~performed.~~derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at June 30, 2018. The actual timing of recognition of such amounts may vary due to factors outside of our control. We ~~expect~~have applied the disclosure practical expedient in ASC606-10-50-14A(b) and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue.

Our revenue recognition pattern under Topic 606 is similar to revenue recognition under ~~ASU 2014-09 to differ from our current revenue~~the previous guidance, except for the recognition ~~pattern only as it relates to~~of demobilization revenue. Such revenue, which iswas recognized upon completion of a contract under ~~current GAAP, will be~~the previous guidance, is now estimated at contract inception and recognized ratably as contract drilling revenue over the term of the contract with an offset to a contract asset under Topic 606.

The following tables summarize the ~~new guidance. Additionally, we expect that~~impacts of adopting Topic 606 on our selected unaudited Condensed Consolidated Balance Sheets, Statements of Operations and Statements of Cash Flows information, as of and for the cumulative effect adjustment to opening retained earnings required by the modified retrospective adoption approach will not be significant as it will primarily consist of the impact of the timing difference related to recognition of demobilization revenue for affected contracts. Not all contracts include a demobilization provision.

2018 Impairment.During the second quarter of 2018, we recorded an impairment loss of $27.2 million to recognize a reduction in fair value of theOcean Scepter, ajack-up rig that was reported in “Assets held for sale” in our unaudited Condensed Consolidated Balance Sheets at June 30, 2018 and December 31, 2017. We estimated the fair value of the impairedjack-up rig using a market approach based on a signed agreement to sell the rig, including estimated costs to sell. We consider this valuation approach to be a Level 3 fair value measurement due to the level of estimation involved as the sale had not yet been completed at the time of our analysis. TheOcean Scepter was sold in July 2018.

During the second quarter of 2018, we evaluated four of our drilling rigs with indicators of impairment. Based on our assumptions and analysis at that time, we determined that the undiscounted probability-weighted cash flow for each rig was in excess of its respective carrying value. As a result, we concluded that no impairment of these rigs had occurred at June 30, 2018.

As of June 30, 2018, there were nine rigs in our drilling fleet, not previously written down to scrap, for which there were no current indicators that their carrying amounts may not be recoverable and, thus, were not evaluated for impairment. If market fundamentals in the offshore oil and gas industry deteriorate further or a projected market recovery is further delayed, we may be required to recognize additional impairment losses in future periods.

2017 Impairments.During the second quarter of 2017, we evaluated seven of our drilling rigs with indicators of impairment. Due to the continued deterioration of market fundamentals in the contract drilling industry, as well as newly-available market projections, which indicated that a full market recovery is likely to occur further in the future than had previously been estimated, weimpairment and determined that the carrying values of one ultra-deepwater and one deepwater semisubmersible rig were impaired (we collectively refer to these two rigs as the “2017 Impaired Rigs”).

We estimated the fair value of the 2017 Impaired Rigs using an income approach, whereby the fair value of each rig was estimated based on a calculation of the rig’s future net cash flows. ~~As described in Note 1, these~~These calculations utilized significant unobservable inputs, including estimated proceeds that may be received on ultimate disposition of the rig, and are representative of Level 3 fair value measurements due to the significant level of estimation involved and lack of transparency as to the inputs used. During the second quarter of 2017, we recorded an impairment loss of $71.3 million related to our 2017 Impaired Rigs.

In the second quarter of 2016, we evaluated 15 of our drilling rigs with indicators of impairment. Based on our assumptions and analyses at that time, we determined that the carrying values of eight of these rigs, consisting of three ultra-deepwater, three deepwater and two mid-water semisubmersible rigs, were impaired (we collectively refer to these eight rigs as the “2016 Impaired Rigs”). During the second quarter of 2016, we recorded impairment losses of $670.0 million and $8.1 million related to our 2016 Impaired Rigs and related rig spare parts and supplies, respectively.

As of June 30, 2017, there were nine rigs in our drilling fleet for which there were no current indicators that their carrying amounts may not be recoverable and, thus, were not evaluated for impairment at that time. If market fundamentals in the offshore oil and gas industry deteriorate further or a projected market recovery is further delayed, we may be required to recognize additional impairment losses in future periods.

Accounts receivable, net of allowance for bad debts, consist of the ~~following:~~following (in thousands):


	June 30,			December 31,
	2017			2016			June 30,			December 31,
	(In thousands)						2018			2017
Trade receivables	$	299,180		$	236,040		$	194,425		$	247,453
Value added tax receivables		16,509			14,639			13,645			14,067
Related party receivables		194			149			113			205
Other		1,093			1,659			407			464

		316,976			252,487			208,590			262,189
Allowance for bad debts		(5,459	)		(5,459	)		(5,459	)		(5,459	)

Total	$	311,517		$	247,028		$	203,131		$	256,730

Prepaid expenses and other current assets consist of the ~~following:~~following (in thousands):


	June 30,		December 31,
	2018		2017
Rig spare parts and supplies	$	23,887	$	28,383
Deferred contract costs		56,110		51,297
Prepaid BOP lease		3,873		3,873
Prepaid insurance		4,407		3,091
Prepaid taxes		58,417		67,212
Other		7,714		3,769

Total	$	154,408	$	157,625


	June 30,		December 31,
	2017		2016		June 30,		December 31,
	(In thousands)				2018		2017
Rig operating expenses	$	28,524	$	33,732	$	30,055	$	48,894
Payroll and benefits		36,686		45,619		32,929		46,560
Deferred revenue		9,871		9,522		10,173		11,371
Accrued capital project/upgrade costs		3,649		60,308		12,714		3,698
Interest payable		18,365		18,365		28,234		28,234
Personal injury and other claims		5,037		6,424		6,048		5,699
Other		8,570		8,189		9,970		10,199

Total	$	110,702	$	182,159	$	130,123	$	154,655

Includes $2.2 million and $13.6 million in accrued costs at June 30, 2018 and December 31, 2017, respectively, related to a restructuring plan that was implemented in late 2017. See Note 10.

Noncash investing activities excluded from the unaudited Condensed Consolidated Statements of Cash Flows and other supplemental cash flow information is as ~~follows:~~follows (in thousands):


	Six Months Ended June 30,
	2017		2016		Six Months Ended June 30,
	(In thousands)				2018		2017
Accrued but unpaid capital expenditures at period end	$	3,649	$	70,800	$	12,714	$	3,649
Common stock withheld for payroll tax obligations⁽¹⁾		473		181		1,265		473
Cash interest payments⁽²⁾		51,603		52,491
Cash interest payments						56,531		51,603
Cash income taxes paid, net of (refunds):
Foreign		33,319		33,485		4,035		33,319
State		94		1		2		94

A reconciliation of the numerators and the denominators of our basic and dilutedper-share computations is as ~~follows:~~follows (in thousands, except per share data):


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended June 30,					Six Months Ended June 30,
	2017		2016			2017		2016			2018			2017		2018			2017
	(In thousands, except per share data)
Net income (loss) – basic and diluted numerator	$	15,949	$	(589,937	)	$	39,488	$	(502,512	)
Net (loss) income – basic and diluted numerator											$	(69,274	)	$	15,949	$	(49,953	)	$	39,488

Weighted average shares – basic (denominator):		137,224		137,170			137,199		137,166			137,429			137,224		137,362			137,199
Dilutive effect of stock-based awards		3		—			36		—			—			3		—			36

Weighted average shares including conversions – diluted (denominator)		137,227		137,170			137,235		137,166			137,429			137,227		137,362			137,235

Earnings (loss) per share:
(Loss) earnings per share:
Basic	$	0.12	$	(4.30	)	$	0.29	$	(3.66	)	$	(0.50	)	$	0.12	$	(0.36	)	$	0.29

Diluted	$	0.12	$	(4.30	)	$	0.29	$	(3.66	)	$	(0.50	)	$	0.12	$	(0.36	)	$	0.29

The following table sets forth the share effects of stock-based awards excluded from ~~our~~the computations of diluted (loss) earnings per share, ~~or EPS,~~as the inclusion of such potentially dilutive shares would have been antidilutive for the periods ~~presented:~~presented (in thousands):

We report our investments as current assets in our unaudited Condensed Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations. See Note 7.

   Three Months Ended
June 30,    Six Months Ended
June 30,
   2017    2016    2017    2016
   (In thousands)
Employee and director:

Stock options
   —      8    1    8
Stock appreciation rights
   1,301    1,536    1,355    1,536
Restricted stock units
   1,274    739    933    658

5.Our investments in marketable securities are classified as available for sale and are summarized as follows (in thousands):

Proceeds from maturities of U.S. Treasury bills were $300.0 million during the three-month andsix-month periods ended June 30, 2018. There were no sales of U.S. Treasury bills during the three-month andsix-month periods ended June 30, 2018.

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. Treasury bills and 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.

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 has consisted primarily of major and independent oil and gas companies and government-owned oil companies. Based on our current customer base and the geographic areas in which we operate, we do not believe that we have any significant concentrations of credit risk at June 30, ~~2017.~~2018.

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 acase-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 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:

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 thesix-month period ended June 30, ~~2017~~2018 or the year ended December 31, ~~2016.~~2017.

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 certain of our drilling rigs, ~~and related rig spare parts and supplies,~~ which were measured at fair value on a nonrecurring basis, during ~~each of~~ the ~~three-month periods~~six-month period ended June 30, 2018 and the year ended December 31, 2017 ~~and 2016,~~ of ~~$71.3~~$27.2 million and ~~$678.1~~$99.3 million, respectively.

Assets and liabilities measured at fair value are summarized ~~below.~~below (in thousands).


	June 30, 2017
	Fair Value Measurements Using										June 30, 2018
	Level 1		Level 2		Level 3		Assets at Fair Value		Total Losses for Six Months Ended		Fair Value Measurements Using
	(In thousands)										Level 1		Level 2		Level 3		Assets at Fair Value		Total Losses for Period Ended⁽¹⁾
Recurring fair value measurements:
Assets:
Short-term investments	$	144,907	$	—	$	—	$	144,907			$	409,616	$	—	$	—	$	409,616
Mortgage-backed securities		—		12		—		12

Total assets	$	144,907	$	12	$	—	$	144,919

Nonrecurring fair value measurements:
Assets:
Impaired assets⁽¹⁾	$	—	$	—	$	2,000	$	2,000	$	71,268
Impaired assets⁽²⁾											$	—	$	—	$	67,815	$	67,815	$	27,225


	December 31, 2016
	Fair Value Measurements Using										December 31, 2017
	Level 1		Level 2		Level 3		Assets at Fair Value		Total Losses for Year Ended⁽¹⁾		Fair Value Measurements Using
	(In thousands)										Level 1		Level 2		Level 3		Assets at Fair Value		Total Losses for Year Ended⁽¹⁾
Recurring fair value measurements:
Assets:
Short-term investments	$	146,360	$	—	$	—	$	146,360			$	358,019	$	—	$	—	$	358,019
Mortgage-backed securities		—		35		—		35

Total assets	$	146,360	$	35	$	—	$	146,395

Nonrecurring fair value measurements:
Assets:
Impaired assets⁽²⁾	$	—	$	—	$	69,153	$	69,153	$	678,145	$	—	$	—	$	97,261	$	97,261	$	99,313

⁽¹⁾

Represents impairment losses of ~~$8.1~~$71.3 million and ~~$670.0~~$28.0 million recognized during the ~~year ended December 31, 2016~~second and fourth quarters of 2017, respectively, related to ~~our rig spare parts and supplies and certain impaired~~three drilling rigs ~~respectively.~~whose carrying values were impaired. See Note 3.

⁽²⁾

Represents the total book value as of December 31, ~~2016 for 11 drilling rigs ($45.5 million) and for rig spare parts and supplies ($23.6 million),~~2017 of two floaters, which were ~~previously~~ written down to their estimated ~~recoverable amounts.~~fair values during the second quarter of 2017, and onejack-up rig, which was written down to its estimated fair value during the fourth quarter of 2017. Of the total fair value, ~~$23.6 million, $0.4~~$96.3 million and ~~$45.1~~$1.0 million were reported as ~~“Prepaid expenses and other current assets,” “Asset~~“Assets held for sale” and “Drilling and other property and equipment, net of accumulated depreciation,” respectively, in our unaudited Condensed Consolidated Balance ~~Sheets~~Sheet at December 31, ~~2016.~~2017. See Note 3.

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 unaudited Condensed Consolidated Balance Sheets, approximate fair value based on the following assumptions:

We consider our senior notes 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, ~~2017~~2018 and December 31, ~~2016.~~2017. 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 a10-day period of the report date. Fair values and related carrying values of our senior notes are shown ~~below.~~below (in millions).


	June 30, 2017				December 31, 2016				June 30, 2018				December 31, 2017
	Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value
	(In millions)
5.875% Senior Notes due 2019	$	513.8	$	499.8	$	518.6	$	499.8
3.45% Senior Notes due 2023		217.5		249.3		215.0		249.3	$	221.9	$	249.4	$	223.1	$	249.4
7.875% Senior Notes due 2025										518.1		496.6		523.1		496.5
5.70% Senior Notes due 2039		377.5		497.1		392.5		497.1		400.0		497.2		405.0		497.2
4.875% Senior Notes due 2043		487.5		748.9		532.7		748.9		540.0		748.9		547.5		748.9

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.

Cost and accumulated depreciation of drilling and other property and equipment are summarized as ~~follows:~~follows (in thousands):


	June 30,			December 31,
	2017			2016			June 30,			December 31,
	(In thousands)						2018			2017
Drilling rigs and equipment	$	8,887,448		$	8,950,385		$	8,064,663		$	7,971,406
Land and buildings		63,279			64,449			63,554			63,309
Office equipment and other		75,754			73,108			87,702			82,691

Cost		9,026,481			9,087,942			8,215,919			8,117,406
Less: accumulated depreciation		(3,536,323	)		(3,361,007	)		(3,018,722	)		(2,855,765	)

Drilling and other property and equipment, net	$	5,490,158		$	5,726,935		$	5,197,197		$	5,261,641

~~During the three-month and six-month periods ended June 30, 2017, we recognized an aggregate impairment loss of $71.3 million related to the 2017 Impaired Rigs. See Notes 1 and 2.~~

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,~~reasonably estimated, we record a liability for the amount of the reasonably 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.

Patent Litigation. On August 30, 2017, an affiliate of Transocean Ltd., or Transocean, an offshore drilling contractor, filed a lawsuit against us and one of our subsidiaries in the United States District Court for the Southern District of Texas, alleging that we infringed certain United States patents previously owned by Transocean or its affiliates or employees pertaining to certain dual-activity drilling operations. The lawsuit alleges that we infringed the patents by the unauthorized sale, offer for sale, and importation and use of four of our drilling rigs (Ocean BlackHawk,Ocean BlackHornet,Ocean BlackRhino andOcean BlackLion) and is seeking unspecified monetary damages. The Transocean patents, which expired in May 2016, do not apply to drilling activities outside the United States or to activities that occurred after the expiration of the patents. On June 1, 2018, we filed petitions with the Patent Trial and Appeal Board to challenge the validity of each of the Transocean patents through an administrative process referred to as an Inter Partes Review. We are unable to estimate our potential exposure, if any, to the Transocean lawsuit 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.

Asbestos Litigation~~. We~~.We are one of several unrelated defendants in lawsuits filed in Louisiana 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 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 in the lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation. 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 claims, lawsuits or threatened actions that are incidental to the ordinary course of our business, including a claim by one of our customers in Brazil, Petróleo Brasileiro S.A., or Petrobras, that it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities for our applicable portion of withholding taxes related to Petrobras’ charter agreements with its contractors. We intend to defend these matters vigorously; however, ~~all~~ litigation is inherently unpredictable, and the ultimate outcome or effect of any claim, lawsuit or action cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of any litigation matter. Any claims against us, whether meritorious or not, could cause us to incur significant costs and expenses and require significant amounts of management and operational time and 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.

~~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, in August 2012, the customer that conveyed the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code. Certain parties (including the debtor) in the bankruptcy proceedings questioned whether our NPI, and certain amounts we received under it after 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 after 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 filed motions to dismiss the claims. In November 2016, the court dismissed the lienholders’ claims, and the lienholders are appealing the ruling. 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. The bankruptcy court has dismissed all but one of the trustee’s disgorgement claims, which is limited in amount to $17.0 million. In December 2016, the company that purchased most of the debtor’s assets from bankruptcy also filed for bankruptcy. We continue to pursue available defenses and available protections, and still expect the bankruptcy proceedings to be concluded with no further material impact to us.

Personal Injury Claims. Under our current insurance policies, which renewed effective May 1, ~~2017,~~2018, our deductibles for marine liability insurance coverage with respect to personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, which primarily result from Jones Act liability in the U.S. Gulf of Mexico, are $10.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year. Our ~~deductible~~deductibles for

personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico isare $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $25.0 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, ~~2017~~2018 our estimated liability for personal injury claims was ~~$32.3~~$29.0 million, of which ~~$4.6~~$5.3 million and ~~$27.7~~$23.7 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our unaudited Condensed Consolidated Balance Sheets. At December 31, ~~2016~~2017 our estimated liability for personal injury claims was ~~$32.9~~$30.9 million, of which ~~$6.1~~$5.2 million and ~~$26.8~~$25.7 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our ~~Condensed~~ Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

Letters of Credit and Other.We were contingently liable as of June 30, ~~2017~~2018 in the amount of ~~$18.3~~$11.2 million under certain performance, tax, ~~supersedeas, court~~bid and customs bonds and letters of credit. Agreements relating to approximately ~~$15.4~~$5.5 million of tax ~~supersedeas, court~~ and customs bonds can require collateral at any time. As of June 30, ~~2017,~~2018, 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~~Banks have issued letters of credit on our behalf securing certain of these bonds.

In late 2017, our management approved and initiated a plan to restructure our worldwide operations, which included a reduction in workforce at our corporate facilities and onshore bases that we refer to as the 2017 Reduction Plan. During the three-month andsix-month periods ended June 30, 2018, we incurred an additional $1.3 million and $4.3 million, respectively, in severance and related costs for redundant employees identified in 2018. As of June 30, 2018, accrued costs related to severance payments to former employees were $2.2 million, of which $0.7 million is payable during the remainder of 2018 and $1.5 million is payable in 2019.

Effective January 1, 2018, we adopted ASU2016-16, which required us to record the income tax consequences of two historical intra-entity transfers of rigs, for which previous accounting guidance precluded us from recognizing such income tax effects. We adopted the new accounting guidance using the modified retrospective approach, whereby we recorded the $17.4 million cumulative effect of applying the new standard as an adjustment to opening retained earnings with an offset to a deferred income tax liability. See Note 1.

Additionally, in response to our interpretation of the Tax Reform Act, which was signed into law in late December 2017, we recorded a provisional net tax expense of $1.1 million during the fourth quarter of 2017, which included a charge relating to theone-time mandatory repatriation of previously deferred earnings of certainnon-US subsidiaries that are owned either wholly or partially by our U.S. subsidiaries, inclusive of the utilization of certain tax attributes offset by a provisional liability for uncertain tax positions related to such attributes. Due to the timing of the enactment of the Tax Reform Act, there has been and continues to be a significant amount of uncertainty as to the appropriate application of a number of the underlying provisions, pending further guidance and clarification from the relevant authorities. In 2018, the U.S. Department of the Treasury and Internal Revenue Service issued additional guidance which we believe clarified certain of our tax positions taken in 2017 and, consequently, we reversed a $43.3 million liability for an uncertain tax position related to the toll charge in accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin No. 118, or SAB 118. SAB 118 allowed companies to report the income tax effects of the Tax Reform Act as a provisional amount based on a reasonable estimate, subject to adjustment during a reasonable measurement period, not to exceed twelve months, until the accounting and analysis under Topic 740 is complete.

We are still in the process of evaluating our estimate as it relates to the tax effect of (i) the mandatory, deemed repatriation aspect of the Tax Reform Act, (ii) the amount of deferred tax assets and liabilities subject to the income tax rate change from 35% to 21% and (iii) the ability to more likely than not realize the benefit of deferred tax assets, including net operating losses and foreign tax credits. We will continue to monitor developments in these areas and adjust our estimates throughout 2018, as and if necessary, as additional guidance and clarification becomes available.

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.~~

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, ~~2017,~~2018, our active drilling rigs were located offshore ~~in five~~four 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
June 30,    Six Months Ended
June 30,
   2017    2016    2017    2016
   (In thousands)
United States
   $ 164,188    $ 130,609    $ 310,456    $ 292,191
International:

South America
   111,498    106,702    214,179    228,189
Australia/Asia
   72,883    47,662    138,561    112,636
Europe
   44,533    87,551    100,268    190,170
Mexico
   6,187    16,223    10,051    36,104








Total revenues
   $ 399,289    $ 388,747    $ 773,515    $ 859,290

The following tables provide information about disaggregated revenue by equipment-type and primary geographical market (in thousands):

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

The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements (including the notes thereto) included in Item 1 of Part I of this report and our audited consolidated financial statements (including 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 Form10-K for the year ended December 31, ~~2016.~~2017. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We provide contract drilling services to the energy industry around the globe with a fleet of ~~19 offshore drilling rigs, excluding five semisubmersibles rigs that we plan to retire and scrap in the near future. These retired units,~~17 floaters, of which ~~are currently cold stacked, include the~~~~Ocean Baroness~~,~~Ocean Alliance~~,~~Ocean Vanguard~~,~~Ocean Nomad~~ ~~and~~~~Ocean Princess~~~~. As of the date of this report, our current fleet consists of~~ four ~~drillships, 14 semisubmersibles and one jack-up rig. The~~~~Ocean Monarch~~, which had been in a shipyard for a survey and contract modifications since the first quarter of 2017, began operating under the first of three contracts in Australia late in the second quarter of 2017. Six of our rigs are currently ~~cold-stacked,~~cold-stacked. TheOcean Scepter was sold in ~~addition to the five rigs to be scrapped, consisting of three ultra-deepwater and three deepwater semisubmersible rigs.~~July 2018. See “– Contract Drilling Backlog.”

AtOil prices rose during the first half of 2018, closing above$70-per-barrel at the end of the second ~~quarter of 2017,~~quarter. Despite the ~~spot~~recovering commodity price, ~~for Brent crude oil was $47.08 per barrel, having fluctuated within a general range of $45-$55 per barrel throughout~~ the ~~first half of 2017. This day-to-day volatility~~offshore contract drilling market continues to stagnate, as the increase in oil ~~price is attributable to multiple factors, including fluctuations~~prices has not yet resulted in ~~the current and expected level of global oil inventories and estimates of global oil demand. Production cuts by the Organization of the Petroleum Exporting Countries,~~a measurable increase in demand for offshore contract drilling services or OPEC, which have now been extended until the end of the first quarter of 2018, initially buoyed oil prices from previous lows in 2016; however, the favorable price impact of the OPEC cuts is currently being negated by increased production by U.S. shale producers and other non-OPEC producing countries, resulting in volatile commodity prices.higher dayrates. Capital spending for offshore exploration and development remained at a relatively low level during the first half of 2018.

In addition, the recovery of the offshore contract drilling industry continues to be challenged by an oversupply of drilling rigs, which has ~~continued to decline, with 2017 capital spending estimated~~not yet been equalized by ~~some industry analysts to decrease up to 20% from 2016 levels. If these market estimates are realized, it would represent three consecutive years~~an increase in demand or through the retirement of ~~decline in offshore spending. Some industry analysts have also reported~~rigs. Industry reports indicate that there ~~has~~remain approximately 40 newbuild floaters, most of which have not yet been contracted for future work, and may continue to be a shift in capital spending towards land-based activity. However, customer inquiries and new tenders have increased in 2017, compared to 2016, for offshore rig availability in 2018 and beyond.

Competition among offshore drillers remains intense as rig supply exceeds demand, despite the cold stacking and retirement of numerous rigs during 2016. Additionally, based on industry data as of the date of this report, there are in excess of 30 floaterover 90 speculativejack-up rigs currently on order with scheduled deliveries ~~from 2017 through~~between 2018 and 2021. ~~The majority~~In addition, contract rollovers of ~~these~~currently contracted rigs are ~~not currently contracted~~expected to add to the oversupply of rigs, if options for future work ~~which~~are not exercised or further ~~increases competition.~~work is not secured for these rigs. Industry analysts currently report that there could be nearly 50 contract rollovers in the second half of 2018.

~~Dayrates continue to be depressed and, in~~Given the oversupply of rigs, competition for the limited number of offshore drilling jobs remains intense. In some cases, dayrates have been negotiated at break-even or ~~below cost~~below-cost levels in order to enable the drilling ~~contractors~~contractor to recover a portion of operating costs for rigs that would otherwise be uncontracted or ~~cold~~ stacked. ~~Discussions with our customers indicate~~Customers have also indicated a preference for “hot” rigs rather than ~~the reactivation of~~reactivated cold-stacked rigs. This preference incentivizes the drilling ~~contractors~~contractor to ~~accept~~contract rigs at lower rates for the sole purpose of maintaining ~~their~~the rigs in an active state and allowing for at least partial cost recovery. ~~Some industry analysts~~Higher specification floaters are also being bid in all markets to keep those rigs active and avoid the higher stacking costs for such rigs. Despite these factors, certain drilling contractors have ~~predicted that demand~~announced the reactivation of stacked rigs or plans to reactivate certain rigs if contracts are awarded.

Looking forward, the number of rig tenders, primarily for ~~drilling rigs~~work in the ~~offshore market will slowly improve, but utilization growth will not~~North Sea and Australia floater markets commencing in 2019 and beyond, has increased. However, many of these tenders are limited to single-well jobs, with options for future wells. Although some geographic areas appear to be ~~significant enough to impact dayrates for some time.~~

~~As a result of~~Given the current ~~depressed~~ market conditions, incontract drillers continue to seek ways to improve operating efficiencies, decreasenon-productive time and ultimately reduce the cost of drilling and enhance cash flow for both the offshore ~~drilling industry~~driller 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 have included requests to lower the contract dayrate, in some cases in exchange for additional contract term, shorten the term on one contracted rig in exchange for additional term on another rig, terminate a contract in exchange for a lump sum 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, usually resulting in a requirement for the customer to pay a contractually specified termination amount, which may not fully compensate us for the loss of the contract. Some of our customers have also 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.customer.

Particularly during depressed market conditions, 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. When we cold stack or expect to scrap a rig, we evaluate the rig for impairment. See “– Contract Drilling Backlog”for future commitments of our rigs during ~~2017~~2018 through ~~2020.~~2022.

The following table reflects our contract drilling backlog as of July 1, 2017 (based on information available at that time), January 1, 2017 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2016), and August 1, 2016 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2016). Contract drilling backlog, as presented below, includes only firm commitments (typically represented by signed contracts) and is calculated by multiplying the contracted operating dayrate by the firm contract period. 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 approach92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our contracts, which could adversely affect our reported backlog.

The backlog information presented below does not, nor is it intended to, align with the disclosures related to revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 2 “Revenue from Contracts with Customers” to our ~~subsidiary received notice~~unaudited condensed consolidated financial statements included in Item 1 of ~~termination of its drilling contract from Petróleo Brasileiro S.A., or Petrobras, the customer for the~~~~Ocean Valor~~. We do not believe that Petrobras had a valid or lawful basis for terminating the contract and in August 2016, we filed a lawsuit in Brazil, claiming that Petrobras’ purported termination of the contract was unlawful and requested an injunction to prohibit the contract termination. In September 2016, a Brazilian court issued a preliminary injunction, suspending Petrobras’ purported termination of the contract and ordering that the contract remain in effect until the end of the term or further court order. Petrobras appealed the granting of the injunction, but in March 2017, the court ruled against Petrobras’ appeal and upheld the injunction. As a result of the favorable ruling, both the injunction and the~~Ocean Valor~~ contract remain in effect. Petrobras has the right to seek to appeal the ruling to the Superior Court of Justice. We intend to continue to defend our rights under the contract, which is estimated to conclude in accordance with its terms in October 2018. However, litigation is inherently unpredictable, and there can be no assurance as to the ultimate outcomePart I of this ~~matter.~~ report. Contract drilling backlog includes only future dayrate revenue as described above, while the disclosure in Note 2 excludes dayrate revenue and reflects expected future revenue for mobilization, demobilization and capital modifications to our rigs, which are related tonon-distinct promises within our signed contracts. See “– Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows.”

The ~~rig is currently~~following table reflects our contract drilling backlog as of July 1, 2018 (based on ~~standby earning a reduced dayrate.~~information available at that time), January 1, 2018 (the date reported in our Annual Report on Form10-K for the year ended December 31, 2017), and July 1, 2017 (the date reported in our Quarterly Report on Form10-Q for the quarter ended June 30, 2017) (in thousands).

The following table reflects the amount of our contract drilling backlog by year as of July 1, ~~2017.~~2018 (in thousands).

The following table reflects the percentage of rig days committed by year as of July 1, ~~2017.~~2018. 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).

Recent Agreements with Anadarko and BP. We recently entered into a series of contracts with each of Anadarko Petroleum Corporation, or Anadarko, and BP Exploration & Production Inc. and certain of its affiliates, or, collectively, BP. We agreed with Anadarko to extend the existing contract for theOcean BlackHawk, which was scheduled to expire in June 2019, until April 2021. The operating dayrate under the extended contract will remain at $495,000 until April 2020, when it will adjust to a lower rate that is subject to a possible one-time capped increase based on then-prevailing market rates. Anadarko retains its option to extend the contract further subject to notice and mutually agreed rates. Commencing on March 1, 2019, Anadarko will temporarily suspend dayrate payments for theOcean BlackHawk until the rig completes regulatory maintenance and equipment re-certifications. We and Anadarko also agreed to the early termination of the existing contract for theOcean BlackHornet, which was scheduled to expire in April 2020, to be effective when theOcean BlackHawk completes its regulatory maintenance and equipment re-certifications, expected by the end of June 2019.

BP agreed to contract theOcean BlackHornet and another drillship to be named later, each for a term of at least two years plus two one-year unpriced options, commencing after completion of the respective drillship’s current contract and subsequent special survey, shipyard period, verification and/or any other necessary assurance activities. The operating dayrate for each contract will be within an agreed range of dayrates and will be determined within the range based on then-prevailing market rates. We and BP also agreed to the early termination of the existing contract for theOcean GreatWhite (which was scheduled to expire in January 2020) effective July 1, 2018, and for BP to pay us a fee to be recorded by us in the fiscal quarter ending September 30, 2018. In addition to such fee and new drilling contracts, BP agreed to either pay us a total of $135 million through a series of designated payments during 2019 through 2023 or contract one or more additional drilling units owned by us so that we receive gross margin at least equal to the respective designated payment amount.

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

Revenue Recognition. Effective January 1, 2018, we adopted Accounting Standards Update, or ASU,No. 2014-09,Revenue from Contracts with Customers(Topic 606), or ASU2014-09, which supersedes the revenue recognition requirements in ASU Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance.

Revenue recognition under ASU2014-09 differs from our previous revenue recognition pattern only as it relates to demobilization revenue. Such revenue, which was previously recognized upon completion of a contract, will be estimated at contract inception and recognized ratably over the term of the contract under the new revenue recognition guidance. See “– Critical Accounting Policies,” Note 1 “General Information - Changes in Accounting Principles- Revenue Recognition” and Note 2 “Revenue from Contracts with Customers” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

Regulatory Surveys and Planned Downtime.Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs istwo-and-one-half years. During the remainder of ~~2017,~~2018, we expect to spend approximately 6055 days for a special survey and rig upgrades for theOcean ~~Patriot~~Apex~~after completion of its current contract.~~and 145 days for a special survey, reactivation activities and contract preparation for theOcean Endeavor. In ~~addition,~~2019, we expect to spend approximately 65an additional 90 days ~~in 2018~~ for contract preparation for theOcean Endeavorprior to its contract commencement, an aggregate of 200 days for special surveys and rig upgrades for theOcean BlackHawk andOcean BlackHornet and an aggregate of 50 days for the ~~mobilization~~mobilization/demobilization of theOcean Apex and theOcean Monarch ~~in connection with a future contract~~ offshore ~~Victoria,~~ Australia. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ – Contract Drilling Backlog.”

Physical Damage and Marine Liability Insurance.We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico, as defined by the relevant insurance policy. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows. Under our current insurance policy, which renewed effective May 1, ~~2017,~~2018, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retainloss-of-hire insurance policies to cover our rigs.

In addition, ~~under our current insurance policy, which renewed effective May 1, 2017,~~ we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, and generally covering liabilities arising out of or relating to 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 related to insurable events arising due to named windstorms in the U.S. Gulf of Mexico isare $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $25.0 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. Our deductibles for other marine liability coverage, including personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.

~~Patent Discussions~~. From time to time, third parties contact us to inquire as to whether our services have infringed upon their intellectual property rights. We were recently contacted by a representative of another offshore drilling contractor, Transocean Ltd., or Transocean, with inquiries about our drillships (~~Ocean BlackHawk Ocean BlackHornet~~,~~Ocean BlackRhino~~ ~~and~~~~Ocean BlackLion~~) with regard to three United States patents previously owned by Transocean pertaining to certain dual-activity drilling operations. We have cooperated with Transocean to provide the requested information. The Transocean patents, which expired in May 2016, do not apply to drilling activities outside the United States or to activities that occurred after the expiration of the patents. In the past, Transocean has used the patents as a basis to file patent infringement lawsuits against a number of oil and gas drilling companies, including most recently against Seadrill Americas, Inc., Noble Corporation plc and Pacific Drilling, Inc. Foreign counterparts of the Transocean patents have been invalidated in various countries around the world, including Norway and South Korea.

~~Capitalization of Interest.~~We capitalize interest cost for rig construction or upgrades, as well as other qualifying projects, in accordance with accounting principles generally accepted in the U.S. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use. The capitalization period ends when the asset is substantially complete and ready for its intended use. During 2016, we ceased capitalizing interest related to the construction of the~~Ocean GreatWhite~~ and do not currently have any ongoing rig construction projects for which we capitalized interest costs during the first half of 2017. At this time, we expect the capitalization of interest costs to be minimal in 2017, relating primarily to qualifying software development projects.

Our significant accounting policies are discussed in Note 1 of our notes to audited consolidated financial statements included in our Annual Report on Form10-K for the year ended December 31, ~~2016.~~2017. Effective January 1, 2018, we adopted ASU2014-09, which supersedes the revenue recognition requirements in ASU Topic 605, Revenue Recognition, and ASUNo. 2016-16,Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory. See “ – Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows” and Note 1 “General Information - Changes in Accounting Principles,” Note 2 “Revenue from Contracts with Customers” and Note 11 “Income Taxes” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report. There were no other material changes to these policies during the six months ended June 30, ~~2017.~~2018.

~~Although we perform~~Our operating results for contract drilling services ~~with different types of drilling rigs~~are dependent on three primary metrics or key performance indicators: revenue-earning days, rig utilization and in many geographic locations, there is a 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. 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~~average daily revenue. The following table presents these three key performance indicators ~~by equipment type are listed below.~~and other comparative data relating to our revenues and operating expenses for the three-month andsix-month periods ended June 30, 2018 and 2017.

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

~~Operating Income (Loss).~~~~Operating~~Net results for the second quarter of 2018 decreased $85.2 million compared to the second quarter of 2017, ~~increased $647.5 million~~reflecting lower margins from our contract drilling services, primarily driven by lower contract drilling revenue and a lower tax benefit recognized. The reduction in net results was partially offset by the favorable impact of lower depreciation expense and lower impairment charges recognized in the second quarter of 2018, compared to the same period of ~~2016,~~2017. Contract drilling services contributed operating income of $76.0 million for the second quarter of 2018, compared to operating income of $196.0 million in the second quarter of 2017.

Operating Results.Contract drilling revenue decreased $126.8 million during the second quarter of 2018 compared to the second quarter of 2017, primarily due to 244 fewer revenue-earning days ($89.8 million), combined with the effect of lower average daily revenue earned ($40.6 million). Comparing the two quarters, revenue-earning days decreased primarily due to fewer revenue-earning days for previously-owned and currentlyheld-for-sale rigs that operated during the second quarter of 2017 (148 days), an increase innon-productive days (65 days) and incremental downtime for planned shipyard projects, including related mobilization days (31 days). Average daily revenue decreased during the second quarter of 2018, compared to the same period of 2017, primarily due to substantially lower dayrates earned by theOcean Valor, which is earning a ~~lower impairment loss recognized~~reduced standby rate until October 2018, and theOcean Patriot,which began working under a new contract in the ~~2017 period ($606.9 million), higher utilization~~North Sea during the first quarter of ~~our fleet and a $19.0 million decrease in depreciation expense.~~2018. The decrease in revenue was partially offset by $3.6 million inloss-of-hire insurance proceeds related to contract terminations of twojack-up rigs in a prior year, which were recognized during the second quarter of 2018.

Contract drilling expense, excluding depreciation, decreased $6.9 million during the second quarter of 2018 compared to the second quarter of 2017, reflecting reduced costs for currently cold-stacked and previously-owned rigs, which had incurred contract drilling expense ~~was~~in the second quarter of 2017 ($18.7 million), partially offset by increased costs for our current rig fleet ($11.8 million). The increase in contract drilling expense during the second quarter of 2018 for our current floater fleet related primarily to higher maintenance and repair costs ($16.0 million), which included incremental costs for theOcean Courage and costs associated with theOcean Valiant’s special survey, combined with higher costs for fuel and inspections ($5.2 million) and other ($0.5 million). These costs were partially offset by reductions in overhead and shorebase support costs ($3.3 million), labor and related costs ($2.4 million), agency fees ($2.1 million) as a result of the termination of our agency arrangement in Brazil in December 2017 and amortized mobilization and moving costs ($2.1 million). Depreciation expense decreased $4.2 million during the second quarter of 2018, compared to the same period of 2017, primarily due to a lower depreciable asset base ~~in the second quarter of 2017, compared to the second quarter of 2016,~~ as a result of asset impairments ~~taken in 2016. During the second quarter of 2016, we~~ recognized ~~$14.6 million in net reimbursable revenue associated with the completion of the~~~~Ocean Endeavor~~~~’s demobilization from the Black Sea.~~

~~Contract drilling revenue increased $34.8 million, or 10%,~~ during the second quarter of 2017, compared to the second quarter of 2016, primarily as a result of an aggregate of 134 incremental revenue-earning days for our fleet, of which 91 additional days were attributable to the recently completed~~Ocean GreatWhite, which commenced its first contract in the first quarter of~~ 2017. Comparing the two quarters, contract drilling expense remained relatively flat across our fleet, decreasing an aggregate of $2.1 million during the second quarter of 2017. Incremental contract drilling expense for the~~Ocean GreatWhite~~ ($10.5 million) was more than offset by lower overall operating costs for the fleet, primarily for labor and personnel ($8.6 million) and an aggregate net decrease in other rig operating and overhead costs ($4.0 million), as we continue to see results from our cost control measures initiated in prior periods.

Impairment of Assets. During the second quarter of 2017, we evaluated seven of our drilling rigs with indicators of impairment and determined that the carrying values of two rigs (one ultra-deepwater and one deepwater semisubmersible rig) were impaired. As a result,2018, we recorded an ~~aggregate~~ impairment loss of ~~$71.3~~$27.2 million to ~~write down these rigs~~recognize a reduction in fair value (less costs to ~~their estimated scrap values~~sell) of theOcean Scepter, ajack-up rig that was reported in ~~the second quarter of~~“Assets held for sale” in our unaudited Condensed Consolidated Balance Sheets at June 30, 2018 and December 31, 2017. TheOcean Scepter was sold in July 2018. During the second quarter of ~~2016,~~2017, we recognized an aggregate impairment charge of ~~$678.1~~$71.3 million with respect to the carrying values of two ~~mid-water, three deepwater, and three ultra-deepwater~~ semisubmersible ~~rigs, including related rig spares and supplies.~~floaters, one of which was sold during the first quarter of 2018. See Notes 1 and 23 to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

~~Other, net.~~Restructuring and Separation Costs.In late 2017, our management approved and initiated a plan to restructure our worldwide operations, which also included a reduction in workforce at our corporate facilities and onshore bases. During the second quarter of ~~2016,~~2018, we ~~sold~~recognized $1.3 million in restructuring and other employee separation related costs for redundant employees, including additional personnel identified in 2018.

Interest Expense, Net of Amounts Capitalized.Interest expense increased $2.3 million during the second quarter of 2018 compared to the second quarter of 2017, primarily as a result of incremental interest expense associated with our ~~investment~~senior notes issued in ~~privately-held corporate bonds for~~August 2017 at a ~~total realized loss~~higher interest rate than the senior notes that were retired in the third quarter of ~~$12.1 million.~~2017.

Income Tax Benefit.We recorded a net income tax ~~benefits~~benefit of ~~$23.0 million and $76.2~~$10.0 million for the ~~three months ended June 30, 2017 and 2016, respectively.~~second quarter of 2018, compared to $23.0 million for the same quarter of 2017. The difference ~~in the amount of income tax benefit recognized in the 2017 period, compared to the prior year period,~~ was in large part due to the mix of our domestic and internationalpre-tax earnings and losses ~~inclusive~~for the periods, combined with the effect of a lower U.S. statutory tax rate as a result of the Tax Cuts and Jobs Act enacted in December 2017, or the Tax Reform Act, and the income tax treatment of impairment losses recognized in the second quarters of ~~2017~~2018 and 2016. The income tax benefit for the second quarter of 2017 included a $24.9 million tax benefit related to asset impairments in the U.S. tax jurisdiction. The income tax benefit for the second quarter of 2016 included a tax benefit of $143.1 million related to asset impairments during the quarter in the U.S. tax jurisdiction, partially offset by a valuation allowance of $77.3 million for current and prior year tax assets associated with foreign tax credits.2017.

~~Operating Income (Loss).~~~~Operating~~Net results for the first six months of 2018 decreased $89.4 million compared to the first six months of 2017, ~~increased $586.8~~primarily driven by lower contract drilling revenue, partially offset by the favorable impact of reduced depreciation expense, a lower impairment charge and a higher income tax benefit recorded during the first half of 2018. Contract drilling services contributed operating income of $179.3 million for the first half of 2018, compared to operating income of $356.0 million in the same period of 2017, reflecting continued challenges in the contract drilling market during the first half of 2018.

Operating Results.Contract drilling revenue decreased $202.4 million during the first six months of 2018 compared to the first six months of 2017, primarily due to 470 fewer revenue-earning days ($169.3 million), combined with the effect of lower average daily revenue earned ($41.5 million). Revenue-earning days decreased during the first six months of 2018, primarily due to fewer revenue-earning days for previously-owned and currentlyheld-for-sale rigs that operated during the first half of 2017 (289 days), incremental downtime attributable to the warm stacking of rigs between contracts (158 days) and an increase innon-productive days (38 days), partially offset by incremental revenue earning days for fewer planned shipyard projects, including related mobilization days (15 days). Average daily revenue decreased during the first six months of 2018, compared to the same period of ~~2016,~~2017, primarily due to a lower ~~impairment loss recognized~~dayrates earned by theOcean Valor and theOcean Patriot during the first six months of 2018. The decrease in ~~the 2017 period ($606.9 million), lower contract drilling expense ($11.4 million) and reduced depreciation expense ($30.0 million). These favorable variances were~~revenue was partially offset by ~~the unfavorable effect of a $45.2~~$8.4 million ~~decrease~~ in ~~contract drilling revenue~~loss-of-hire insurance proceeds recognized during the first half of 2018 related to contract terminations for twojack-up rigs in a prior year.

Contract drilling expense, excluding depreciation, decreased $25.7 million during the first six months of 2018 compared to the same period in 2017, primarily due to reduced costs for currently cold-stacked and previously-owned rigs, which had incurred contract drilling expense in the first six months of 2017 ($33.9 million), partially offset by increased costs for our current rig fleet. Contract drilling expense for our current fleet increased $8.2 million during the first six months of 2018, reflecting increased costs for fuel, repairs and maintenance, including costs for theOcean Courage, and costs associated with our Pressure Control by the Hour^® program. Contract drilling expense for the first half of 2018 also reflected reductions in labor and personnel costs, agency fees, amortized rig mobilization costs, shorebase support costs and overhead, primarily as a result of our continuing cost control initiatives. Depreciation expense decreased $15.6 million during the first half of 2018 compared to the same period of ~~2016, and the recognition of $14.6 million in net reimbursable income for the~~~~Ocean Endeavor~~~~during the 2016 period. Depreciation expense decreased~~2017, primarily due to a lower depreciable asset base ~~in 2017, compared to the first half of 2016,~~ as a result of asset impairments ~~taken in 2016.~~recognized during 2017.

~~Contract drilling revenue decreased $45.2~~Interest Expense, Net of Amounts Capitalized.Interest expense increased $3.1 million ~~or 6%,~~ during the first half of 2017, compared to the first half of 2016, primarily as a result of lower average daily revenue earned by most of the rigs in our fleet, partially offset by the favorable impact of an aggregate of 107 incremental revenue-earning days.

~~Total contract drilling expense decreased $11.4 million during the first six months of 2017~~2018 compared to the same period of ~~2016. Excluding~~2017, primarily as a result of incremental ~~contract drilling~~interest expense ~~for~~of $5.2 million associated with our senior notes issued in August 2017 at a higher interest rate than the~~Ocean GreatWhite~~ ~~($22.1 million), aggregate contract drilling expense decreased $33.5 million, reflecting lower costs for labor and personnel ($18.2 million), repairs and maintenance ($14.5 million) and a net decrease~~ senior notes that were retired in ~~other rig operating and overhead costs ($0.8 million).~~

~~Other, net.~~~~During~~ the ~~second~~third quarter of ~~2016, we sold~~2017. Higher interest cost associated with our ~~investment~~senior notes was partially offset by the reversal of contingent interest associated with a Braziliannon-income tax contingency for which the statute of limitations expired and interest capitalized in ~~privately-held corporate bonds for a total recognized loss of $12.1 million.~~connection with certain qualifying software implementation projects.

Income Tax Benefit.We recorded a net income tax ~~benefits~~benefit of ~~$22.0~~$54.5 million ~~and $80.4~~for thesix-month period ended June 30, 2018, compared to $22.0 million for the ~~six months ended June 30,~~comparable 2017 period. Income tax benefit for the 2018 period included a tax benefit of $43.3 million due to the reversal of an uncertain tax position related to the toll charge recognized in the fourth quarter of 2017 for the deemed repatriation of previously deferred earnings of ournon-U.S. subsidiaries in response to the Tax Reform Act. Further guidance issued by the Internal Revenue Service in 2018 clarified certain of our tax positions taken and, ~~2016, respectively. The~~consequently, we reversed our liability for an uncertain tax position related to the toll charge. Notwithstanding the reversal of the uncertain tax position, the difference in the amount of income tax benefit recognized in the ~~first half of 2017,~~2018 period, compared to the ~~prior year~~comparable period of 2017, was ~~primarily~~in large part due to the mix of our domestic and internationalpre-tax earnings and losses ~~inclusive~~for the periods, combined with the effect of a lower U.S. statutory tax rate as a result of the Tax Reform Act and the income tax treatment of impairment losses recognized in the second quarters of ~~2017~~2018 and 2016. The net tax benefit for the first six months of 2017 and 2016 included U.S. tax benefits of $24.9 million and $143.1 million, respectively, related to the impairment of assets in the U.S. tax jurisdiction. The income tax benefit for the six months ended June 30, 2016 was net of additional tax expense associated with a valuation allowance of $77.3 million recognized during the period for current and prior year tax assets associated with foreign tax credits.

~~Ultra-Deepwater Floaters.~~Revenue generated by our ultra-deepwater floaters increased $68.4 million during the second quarter of 2017, compared to the same quarter of 2016, primarily as a result of 175 incremental revenue-earning days ($79.0 million), partially offset by lower average daily revenue earned ($10.6 million). Revenue-earning days increased in the second quarter of 2017, primarily due to incremental revenue-earning days for the~~Ocean GreatWhite~~ ~~(91 days), the~~~~Ocean BlackRhino~~, which was between contracts during the prior year quarter (84 days), and less unplanned downtime for repairs (61 days) to our other ultra-deepwater rigs. The increase in revenue-earning days was partially offset by fewer revenue-earning days for the~~Ocean Monarch~~, which was in the shipyard for a survey and contract modifications during the second quarter of 2017 prior to beginning a new contract in June (61 days). Average daily revenue decreased during the second quarter of 2017, compared to the second quarter of 2016, primarily due to the~~Ocean Valor~~ ~~earning a reduced, standby dayrate during 2017 and a lower dayrate earned by the~~~~Ocean Monarch~~ ~~under its new contract.~~

Contract drilling expense for our ultra-deepwater floaters increased $9.5 million during the second quarter of 2017, compared to the second quarter of 2016, primarily due to incremental costs associated with our Pressure Control by the Hour^® ~~program, or PCbtH program, that has now been implemented on all of our drillships ($8.0 million), incremental contract drilling expense for the~~~~Ocean GreatWhite~~($10.5 million) and higher costs associated with the mobilization of rigs ($4.3 million). These incremental costs were partially offset by lower costs for labor and personnel ($2.9 million), repairs and maintenance ($2.7 million), shorebase support and overhead ($6.2 million) and other costs ($1.5 million).

~~Deepwater Floaters.~~Revenue and contract drilling expense for our deepwater floaters decreased $0.3 million and $3.4 million, respectively, in the second quarter of 2017 compared to the same period in 2016. The reduction in revenue during the second quarter of 2017 resulted from lower average daily revenue earned ($7.5 million), offset by the effect of 24 incremental revenue-earning days ($7.2 million). Contract drilling expense for the second quarter of 2017 also declined, reflecting lower costs for labor and personnel ($0.7 million), maintenance and repairs ($2.2 million), equipment rentals ($1.0 million) and other rig operating and overhead costs ($1.4 million), partially offset by an increase in costs related to the mobilization of rigs ($1.9 million).

~~Mid-Water Floaters.~~~~Revenue generated by our mid-water floaters during the second quarter of 2017 decreased $20.2 million compared to the same quarter of 2016, primarily due to the warm-stacking of the~~~~Ocean Guardian~~ after completion of its contract in early April 2017 ($18.5 million). Contract drilling expense for our mid-water floaters decreased $10.1 million during the second quarter of 2017, compared to the prior year quarter, due to reduced costs incurred by the~~Ocean Guardian~~ ~~($4.4 million) combined with lower contract drilling expense ($5.7 million) for our other mid-water rigs, including rigs that were sold after the first half of 2016.~~

~~Jack-ups.~~~~Subsequent to the second quarter of 2016, we sold four cold-stacked jack-up rigs and currently own one jack-up rig, the~~~~Ocean Scepter~~. Contract drilling revenue attributable to our current and previously-owned jack-up rigs decreased $13.2 million during the second quarter of 2017, compared to the prior year quarter, while contract drilling expense remained flat. Contract drilling revenue decreased primarily due to a reduced dayrate earned by the~~Ocean Scepter~~ ($14.4 million), which began operating under a new contract offshore Mexico in 2017, and the absence of loss of hire insurance proceeds recognized in the second quarter of 2016 ($4.9 million). These reductions in revenue were partially offset by the favorable impact of 24 incremental revenue-earning days for the~~Ocean Scepter~~ ~~($6.1 million) in the second quarter of~~ 2017.

~~Ultra-Deepwater Floaters.~~Revenue generated by our ultra-deepwater floaters decreased $14.1 million during the first half of 2017, compared to the same period of 2016, primarily as a result of lower average daily revenue earned ($66.1 million), partially offset by 104 incremental revenue-earning days for our ultra-deepwater fleet ($52.0 million). Average daily revenue decreased during the first half of 2017, primarily due to the absence of $40.0 million in demobilization revenue recognized in the first quarter of 2016 for the~~Ocean Endeavor, combined with the effect of lower dayrates earned under new contracts for both the~~~~Ocean Monarch~~~~(June 2017) and~~ ~~Ocean BlackRhino~~~~(February 2017). The increase in revenue-earning days was primarily due to incremental revenue-earning days for the~~~~Ocean GreatWhite~~ ~~(168 days), the~~~~Ocean BlackRhino,~~which was warm stacked for much of the prior year period (93 days), and reduced downtime for repairs (58 days). The increase in revenue-earning days was partially offset by incremental downtime for the~~Ocean Monarch, which was in the shipyard for a survey and contract modifications during much of the first half of 2017 (136 days) and the cold stacking of other rigs (79 days).~~

Contract drilling expense for our ultra-deepwater floaters increased $27.6 million during the first six months of 2017, compared to the first half of 2016, primarily due to incremental costs associated with the PCbtH program on our drillships ($20.3 million) and incremental contract drilling expense for the~~Ocean GreatWhite~~($22.1 million). Excluding these incremental costs, contract drilling expense for our ultra-deepwater floaters decreased $14.8 million in the first half of 2017, compared to the prior year period, primarily due to lower contract drilling expense attributable to cold-stacked rigs ($13.2 million).

~~Deepwater Floaters.~~Revenue generated by our deepwater floaters increased $8.5 million in the first half of 2017, compared to the same period in 2016, primarily due to 108 incremental revenue-earning days ($34.1 million), partially offset by a reduction in average daily revenue earned ($25.6 million). The increase in revenue-earning days resulted primarily from 140 incremental days for the~~Ocean Apex~~, which operated through the first six months of 2017 under a contract that commenced in the second quarter of 2016. Average daily revenue decreased during the first half of 2017, primarily as a result of a lower dayrate being earned by the~~Ocean Valiant~~ ~~under its current contract in the North Sea, which commenced in the fourth quarter of 2016.~~

Contract drilling expense for our deepwater floaters decreased $17.9 million during the first half 2017, compared to the first half of 2016, primarily due to a net reduction in costs associated with labor and personnel ($3.5 million), maintenance and repairs ($8.4 million), equipment rental ($2.0 million) and other rig operating and overhead costs ($4.0 million) attributable to various factors, including the cold stacking of rigs and implementation of cost control measures for our working rigs and shorebase operations in 2016.

~~Mid-Water Floaters.~~Revenue and contract drilling expense for our mid-water floaters decreased $19.5 million and $14.7 million, respectively, during the first half 2017 compared to the same period of 2016. The decrease in revenue reflects 90 fewer revenue-earning days ($25.9 million), partially offset by an increase in average daily revenue earned ($6.4 million). The decrease in revenue-earning days primarily relates to the completion of the final contract for the~~Ocean Ambassador~~ in March 2016 prior to the rig being sold. Only two of our mid-water floaters operated during both periods, while the remainder of our mid-water fleet remained cold stacked or was sold during 2016. The decrease in contract drilling expense was primarily due to reduced costs related to the~~Ocean Ambassador~~ ~~($8.3 million) and a reduction in labor and personnel costs for the remainder of the fleet ($4.2 million).~~

~~Jack-ups.~~Contract drilling revenue attributable to our current and previously-owned jack-up rigs decreased $20.1 million during the first half of 2017, compared to the first half of 2016, while contract drilling expense remained stable, decreasing $0.6 million. As of the beginning of the second quarter of 2017, we had sold all but one jack-up rig. The~~Ocean Scepter~~, which had been idle since completion of its contract in Mexico during May 2016, commenced operations offshore Mexico in February 2017 under a new contract. The decrease in contract drilling revenue was primarily due to 15 fewer revenue-earning days and lower average daily revenue earned by the rig during the first half of 2017, compared to the prior year period ($15.2 million), as well as the absence of $4.9 million in loss of hire insurance proceeds recognized in the second half of 2016.

We principally rely on our cash flows from operations and cash reserves to meet our liquidity needs. We may also utilize borrowings under our $1.5 billion syndicated revolving credit agreement, or Credit ~~Agreement.~~Agreement, all of which was available to provide liquidity for our payment obligations as of July 27, 2018. See “ – Credit Agreement.”

~~Based on our cash available for current operations and contractual backlog of $2.9 billion~~ In addition, as of July 1, ~~2017,~~2018, our contractual backlog was $2.2 billion of which ~~$0.7~~$0.5 billion is expected to be realized during the remainder of 2017, we believe future capital spending and debt service requirements will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement, as needed. See “– Sources and Uses of Cash – Capital Expenditures.”2018.

Certain of our international rigs are owned and operated, directly or indirectly, by our Cayman Islands subsidiary Diamond Foreign Asset Company, or DFAC. As of December 31, 2017, all unremitted earnings of DFAC ~~and,~~were deemed repatriated as a result of ~~our intention~~the Tax Reform Act, and U.S. taxes were provided for those earnings. We intend to indefinitely reinvest ~~the~~ earnings of DFAC and its foreign subsidiaries 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. ~~Although we do not intend to repatriate the earnings~~Earnings of DFAC ~~and have not provided U.S. income taxes for such earnings, except~~subsequent to ~~the extent that such earnings were immediately subject to U.S. income taxes, these earnings~~December 31, 2017 could become subject to U.S. income tax if remitted, or if deemed remitted as a dividend; however, it is not practical to estimate this potential liability.

To the extent available, we expect to utilize the operating cash flows generated by and cash reserves of DFAC 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. At June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, we had cash available for current operations ~~including cash reserves~~ of ~~DFAC, as follows:~~$144.2 million and $376.0 million, respectively. We also had investments in U.S. Treasury bills of $274.7 million at June 30, 2018, which mature at various times through August 2018.

~~A substantial~~We have historically invested a significant portion of our cash flows ~~has historically been invested~~ in the enhancement of our drilling fleet. ~~We determine the~~The amount of cash required to meet our capital commitments is determined by evaluating ~~our rig construction obligations,~~ the need to upgrade our rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We ~~also~~ make periodic assessments of our capital spending programs based on current and expected industry conditions and make adjustments thereto if required.

Based on our cash available for current operations and contractual backlog, we believe future capital spending and debt service requirements will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement, as needed. See “– Sources and Uses of Cash –Capital ~~Expenditures.~~Expenditures.”

We pay dividends at the discretion of our Board of Directors, or Board, and 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. We did not pay any dividends in ~~2016~~2017 or induring the first half of ~~2017.~~2018.

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 thesix-month periods ended June 30, ~~2017~~2018 and ~~2016.~~2017.

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.

During thesix-month period ended June 30, ~~2017,~~2018, our primary sources of cash were an aggregate ~~$176.9~~$130.8 million generated by operating activities and ~~$4.1~~proceeds of $1.7 million, primarily from the ~~disposition~~sale of ~~assets.~~theOcean Victory in January 2018. Cash usage during the ~~same~~six-month period ended June 30, 2018 was primarily ~~$104.2~~$273.8 million for ~~the~~purchases of marketable securities, net ~~repayment~~ of ~~borrowings under our Credit Agreement~~maturities, and for capital expenditures aggregating ~~$71.9~~$90.4 million.

~~Our cash flow from operations and capital expenditures for the six-month periods ended June 30, 2017 and 2016 were as follows:~~

Cash Flowfrom Operations.Cash flow from operations for thesix-month period ended June 30, 2018 decreased ~~$128.6~~$46.1 million ~~during the first six months of 2017,~~ compared to the ~~first six months of 2016,~~six-month period ended June 30, 2017, primarily due to lower cash receipts for contract drilling services ($~~202.8~~103.9 million), partially offset by a net decrease in cash ~~payments~~expenditures for contract drilling ~~expenses, including personnel-related, repairs and maintenance, overheads~~services and other ~~rig operating costs~~working capital requirements ($~~74.2~~28.4 million)~~. The decline in both cash receipts~~ and ~~cash~~lower income tax payments, ~~related to the performance~~net of ~~contract drilling services reflects continuing depressed market conditions in the offshore drilling industry, as well as positive results of our continuing focus on controlling costs.~~refunds ($29.4 million).

Capital Expenditures.As of the date of this report, we expect total capital expenditures for ~~2017~~2018 to aggregate approximately ~~$145.0~~$220.0 million for our ~~ongoing~~ capital maintenance and replacement programs.

WeAt June 30, 2018, we had no ~~other~~significant purchase obligations, except for ~~major~~those related to our direct rig ~~upgrades at June 30, 2017.~~operations, which arise during the normal course of business.

Other Obligations. As of June 30, ~~2017,~~2018, the total net unrecognized tax benefits related to uncertain tax positions was ~~$63.2~~$63.3 million. 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.

At June 30, ~~2017,~~2018, we had no borrowings outstanding under our Credit Agreement, and were in compliance with all covenants thereunder. ~~As of July 27, 2017, we had $1.5 billion available under our Credit Agreement to provide liquidity for our payment obligations.~~

~~On July 28, 2017,~~Our current credit rating is Ba3 from Moody’s Investor Services ~~downgraded our corporate credit rating to Ba3~~and B+ from S&P Global Ratings with a negative outlook from ~~Ba2 with a stable outlook. Our current corporate credit rating by S&P Global Ratings remains BB- with a negative outlook.~~both. Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered. AAny downgrade in our credit ratings could adversely impact our cost of issuing additional debt and the amount of additional debt that we could issue, and could further restrict our access to capital markets and our ability to raise funds by issuing additional debt. 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.

We were contingently liable as of June 30, ~~2017~~2018 in the amount of ~~$18.3~~$11.2 million under certain performance, tax, ~~supersedeas,~~bid and customs bonds and letters of credit. Agreements relating to approximately ~~$15.4~~$5.5 million of tax ~~supersedeas, court~~ and customs bonds can require collateral at any time. As of June 30, ~~2017,~~2018, 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.~~expiration (in thousands).


			For the Years Ending December 31,
	Total		2017		2018				For the Years Ending December 31,
	(In thousands)						Total		2018		2019
Other Commercial Commitments
Performance bonds	$	1,000	$	—	$	1,000	$	1,000	$	—	$	1,000
Supersedeas bond		9,189		9,189		—
Tax bond		5,639		5,639		—		5,326		5,326		—
Bid bond								3,200		3,200		—
Other		2,518		1,310		1,208		1,677		810		867

Total obligations	$	18,346	$	16,138	$	2,208	$	11,203	$	9,336	$	1,867

At June 30, ~~2017~~2018 and December 31, ~~2016,~~2017, we had nooff-balance sheet debt or otheroff-balance sheet arrangements.

See Note 1 “General Information” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of recently issued accounting pronouncements.

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,” “would,” “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:

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, those described or referenced under “Risk Factors” in Item 1A in our Annual Report on Form10-K for the year ended December 31, ~~2016.~~2017.

The risks and uncertainties referenced above are not exhaustive. Other sections of this report and our other filings with the Securities and Exchange Commission 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. In addition, in certain places in this report, we may refer to reports published by third parties that purport to describe trends or developments in energy production or drilling and exploration activity. ~~We do so for~~While we believe that these reports are reliable, we have not independently verified the ~~convenience of our investors and potential investors and~~information included in ~~an effort to provide information available in the market intended to lead to a better understanding of the market environment in which we operate.~~such reports. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

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

At June 30, 2018, we had investments in U.S. Treasury bills of $274.7 million, which expose us to interest rate risk arising from changes in the level or volatility of interest rates. We monitor our sensitivity to interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on stockholders’ equity. The analysis provides the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over aone-year period.

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on June 30, 2018, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant. Based on this analysis, our estimated market risk exposure related to our investment in U.S. Treasury bills would have been $0.1 million.

The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.

There were no other material changes in our market risk components for the six months ended June 30, ~~2017.~~2018. See “Quantitative and Qualitative Disclosures About Market Risk” included in Item 7A of our Annual Report on Form10-K for the year ended December 31, ~~2016~~2017 for further information.

We maintain a system of disclosure controls and procedures that 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 Rules13a-15(e) and15d-15(e)) as of June 30, ~~2017.~~2018. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, ~~2017.~~2018.

~~Other than with respect to the remediation procedures detailed below for the previously identified material weakness, there~~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 ~~2017~~2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

As previously discussed in our 2016 Annual Report on Form 10-K, as of December 31, 2016, we identified a material weakness in the design of our controls over the application of changes in foreign exchange rates when measuring our liability for uncertain tax positions denominated in foreign currencies. These liabilities for uncertain tax positions are considered monetary liabilities and are required to be revalued in accordance with Accounting Standards Codification 830 –~~Foreign Currency Matters~~. We had historically utilized a manual (non-system) calculation to revalue our foreign liability for uncertain tax positions, as appropriate. Prior to the completion of our year-end financial reporting process for fiscal year 2016, it was discovered that our revaluation of our liability for uncertain tax positions did not properly reflect appropriate changes for current foreign exchange rates. This omission resulted in an improper measurement of certain of our liabilities for uncertain tax positions. As a result, we concluded that we failed to adequately design and operate our internal controls over the application of changes in foreign exchange rates in revaluation of liabilities for foreign uncertain tax positions to mitigate the risk of a material error.

We have designed and implemented new controls and processes to remediate the underlying cause of the material weakness discussed above. Specifically, during the first fiscal quarter of 2017, we implemented the following actions:

During the second fiscal quarter of 2017, we completed our testing of the operational effectiveness of the actions discussed above. We have concluded that the enhanced control processes have now been operating for a sufficient period of time so as to provide reasonable assurance as to their effectiveness, and, as a result, that the material weakness described above was remediated as of June 30, 2017.

Information related to certain legal proceedings is included in Note 79 to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

Our Annual Report on Form10-K for the year ended December 31, ~~2016~~2017 includes a detailed discussion of certain material risk factors facing our company. No material changes have been made to such risk factors as of June 30, ~~2017.~~2018.

(c) During the three months ended June 30, ~~2017,~~2018, in connection with the vesting of restricted stock units held by our officers and certain of our employees, which were awarded under an equity incentive compensation plan, we acquired shares of our common stock in satisfaction of tax withholding obligations that were incurred on the vesting date. The date of acquisition, number of shares and average effective acquisition price per share were as follows:

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

~~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.~~

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.


					PAGE NO.

COVER PAGE			1

TABLE OF CONTENTS			2

PART I. FINANCIAL INFORMATION			3

ITEM 1.	~~ITEM 1.~~	Financial Statements (Unaudited)
		Condensed Consolidated Balance Sheets		3
		Condensed Consolidated Statements of Operations		4
		Condensed Consolidated Statements of Comprehensive Income (Loss)		5
		Condensed Consolidated Statements of Cash Flows		6
		Notes to Unaudited Condensed Consolidated Financial Statements		7

ITEM 2.	~~ITEM 2.~~	Management’s Discussion and Analysis of Financial Condition and Results of Operations		1721

ITEM 3.	~~ITEM 3.~~	Quantitative and Qualitative Disclosures About Market Risk		2930

ITEM 4.	~~ITEM 4.~~	Controls and Procedures		2930

PART II. OTHER INFORMATION			3031

ITEM 1.	~~ITEM 1.~~	Legal Proceedings		3031

ITEM 1A.	~~ITEM 1A.~~	Risk Factors		3031

ITEM 2.	~~ITEM 2.~~	Unregistered Sales of Equity Securities and Use of Proceeds		31

ITEM 6.	~~ITEM 6.~~	Exhibits		3132

SIGNATURES			31

~~EXHIBIT INDEX~~				3233


	Retained Earnings			Prepaid Expenses and Other Current Assets		Other Assets		Deferred Tax Liability
Balance as of January 1, 2018 before adoption	$	1,964,497		$	157,625	$	102,276	$	167,299
Adjustments for adoption of:
Topic 606		2,590			611		2,107		128
ASU2016-16		(17,401	)		—		—		17,401

Balance as of January 1, 2018 after adoption	$	1,949,686		$	158,236	$	104,383	$	184,828


	June 30,			January 1,
	2018			2018
Trade receivables	$	194,425		$	247,453
Current contract assets⁽¹⁾		1,567			611
Noncurrent contract assets⁽¹⁾		2,107			2,107
Current contract liabilities (deferred revenue)⁽¹⁾		(10,173	)		(11,371	)
Noncurrent contract liabilities (deferred revenue)⁽¹⁾		(6,915	)		(8,972	)


	Net Contract Balances
Contract assets at January 1, 2018	$	2,718
Contract liabilities at January 1, 2018		(20,343	)

Net balance at January 1, 2018		(17,625	)
Decrease due to amortization of revenue that was included in the beginning contract liability balance		7,048
Increase due to cash received, excluding amounts recognized as revenue during the period		(4,670	)
Increase due to revenue recognized during the period but contingent on future performance		2,306
Decrease due to transfer to receivables during the period		(611	)
Adjustments		138

Net balance at June 30, 2018	$	(13,414	)

Contract assets at June 30, 2018	$	3,674
Contract liabilities at June 30, 2018		(17,088	)


	Retained Earnings			Additional Paid-in Capital
	(In thousands)
Balance as of January 1, 2017 before adoption	$	1,946,765		$	2,004,514
Adjustment for making election to account for forfeitures as they occur		(634	)		634

Balance as of January 1, 2017 after adoption	$	1,946,131		$	2,005,148


	For the Years Ending December 31,
	2018⁽¹⁾		2019		2020		2021		Total
Mobilization and contract preparation revenue	$	9,115	$	9,043	$	81	$	—	$	18,239
Capital modification revenue		6,598		9,170		387		—		16,155
Demobilization revenue		2,170		—		—		—		2,170
Other deferred revenue		343		681		681		194		1,899

Total	$	18,226	$	18,894	$	1,149	$	194	$	38,463


	June 30, 2018
	Balances as reported			Adjustments			Balances without adoption of Topic 606
Unaudited Condensed Consolidated Balance Sheets
Prepaid and other current assets	$	154,408		$	(1,174	)	$	153,234
Other assets		71,389			(2,107	)		69,282
Accrued liabilities		130,123			739			130,862
Deferred tax liability		124,350			(402	)		123,948
Retained earnings		1,899,735			(3,619	)		1,896,116

Unaudited Condensed Consolidated Statements of Operations
Contract drilling revenue	$	553,279		$	(1,303	)	$	551,976
Income tax benefit		54,475			274			54,749
Loss per share, Basic and Diluted		(0.36	)		(0.01	)		(0.37	)

Unaudited Condensed Consolidated Statements of Cash Flows
Cash flow from operating activities:
Net loss	$	(49,953	)	$	(1,029	)	$	(50,982	)
Adjustments to reconcile net loss to net cash
Deferred tax provision		(61,160	)		(274	)		(61,434	)
Contract liabilities		(3,255	)		739			(2,516	)
Contract assets		(956	)		564			(392	)


	June 30, 2018
	Amortized Cost		Unrealized Gain		Market Value
U.S. Treasury bills (due within one year)	$	274,636	$	35	$	274,671


Level 1		Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds and U.S. Treasury ~~bills and notes.~~bills. Our Level 1 assets at June 30, 2018 consisted of cash held in money market funds of $114.0 million, time deposits of $20.9 million and investments in U.S. Treasury bills of $274.7 million. Our Level 1 assets at December 31, 2017 consisted of cash held in money market funds of ~~$124.3~~$337.1 million and time deposits of ~~$20.6 million. Our Level 1 assets at December 31, 2016 consisted of cash held in money market funds of $125.7 million and time deposits of $20.6~~$20.9 million.

Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. We had no Level 2 assets ~~and~~or liabilities ~~may include residential mortgage-backed securities, corporate bonds purchased in a private placement offering and over-the-counter foreign currency forward exchange contracts. Our Level 2 assets at~~as of June 30, ~~2017 and~~2018 or December 31, 2016 consisted solely of residential mortgage-backed securities, which were valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. 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.2017.

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, ~~2017~~2018 and December 31, ~~2016~~2017 consisted of nonrecurring measurements of certain of our drilling rigs ~~and associated spare parts and supplies~~ for which we recorded impairment losses ~~in the second quarter of 2017~~during 2018 and ~~during 2016.~~2017.


	Three Months Ended June 30, 2018
	Floater Rigs		Jack-up Rigs⁽¹⁾		Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	158,554	$	3,648	$	162,202	$	1,172	$	163,374
South America		26,288		—		26,288		—		26,288
Europe		18,738		—		18,738		1,742		20,480
Australia/Asia		58,125		—		58,125		594		58,719

Total	$	261,705	$	3,648	$	265,353	$	3,508	$	268,861


	Six Months Ended June 30, 2018
	Floater Rigs		Jack-up Rigs⁽¹⁾		Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	318,228	$	8,413	$	326,641	$	3,309	$	329,950
South America		80,556		—		80,556		1		80,557
Europe		30,130		—		30,130		3,120		33,250
Australia/Asia		115,952		—		115,952		4,662		120,614

Total	$	544,866	$	8,413	$	553,279	$	11,092	$	564,371


	Three Months Ended June 30, 2017
	Floater Rigs		Jack-up Rigs		Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses			Total
United States	$	157,069	$	—	$	157,069	$	2,335		$	159,404
South America		111,498		—		111,498		(240	)		111,258
Europe		44,533		—		44,533		1,194			45,727
Australia/Asia		72,883		—		72,883		3,593			76,476
Mexico		—		6,187		6,187		237			6,424

Total	$	385,983	$	6,187	$	392,170	$	7,119		$	399,289


	Six Months Ended June 30, 2017
	Floater Rigs		Jack-up Rigs		Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses			Total
United States	$	292,668	$	—	$	292,668	$	4,456		$	297,124
South America		214,179		—		214,179		(222	)		213,957
Europe		100,268		—		100,268		3,159			103,427
Australia/Asia		138,561		—		138,561		10,009			148,570
Mexico		��		10,051		10,051		386			10,437

Total	$	745,676	$	10,051	$	755,727	$	17,788		$	773,515


	July 1, 2017		January 1, 2017		August 1, 2016
	(In thousands)
Contract Drilling Backlog
Ultra-Deepwater Floaters⁽¹⁾	$	2,705,000	$	3,215,000	$	3,875,000
Deepwater Floaters		82,000		197,000		291,000
Other Rigs⁽²⁾		156,000		152,000		250,000

Total	$	2,943,000	$	3,564,000	$	4,416,000


	July 1, 2018⁽¹⁾		January 1, 2018		July 1, 2017
Contract Drilling Backlog
Floaters	$	2,211,000	$	2,417,000	$	2,787,000
Jack-ups		—		—		156,000

Total	$	2,211,000	$	2,417,000	$	2,943,000


	For the Years Ending December 31,
	Total		2017⁽¹⁾		2018		2019		2020
	(In thousands)
Contract Drilling Backlog
Ultra-Deepwater Floaters⁽²⁾	$	2,705,000	$	582,000	$	1,112,000	$	842,000	$	169,000
Deepwater Floaters		82,000		68,000		14,000		—		—
Other Rigs⁽³⁾		156,000		57,000		34,000		45,000		20,000

Total	$	2,943,000	$	707,000	$	1,160,000	$	887,000	$	189,000


	For the Years Ending December 31,
	2017 ⁽¹⁾			2018			2019			2020
Rig Days Committed⁽²⁾
Ultra-Deepwater Floaters		62	%		64	%		45	%		9	%
Deepwater Floaters		33	%		4	%		—			—
Other Rigs⁽³⁾		21	%		14	%		17	%		7	%


				For the Years Ending December 31,
	2018 ⁽¹⁾			2019			2020			2021-2022
Rig Days Committed⁽²⁾		59	%		50	%		34	%		9	%


	~~DIAMOND OFFSHORE DRILLING, INC.~~
			~~(Registrant)~~

~~Date July 31, 2017~~		~~By:~~	~~/s/ Kelly Youngblood~~
			~~Kelly Youngblood~~
			~~Senior Vice President and Chief Financial Officer~~


Exhibit No.		Description of Exhibit

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~~By-Laws (as amended through ~~October 4, 2013)~~July 23, 2018) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form8-K filed ~~October 8, 2013)~~July 24, 2018).

10.1*		The Diamond Offshore Drilling, Inc. Incentive Compensation Plan (Amended and Restated as of January 1, 2018, as amended June 28, 2018).

10.2		Executive Retention Agreement, dated June 29, 2018, between Diamond Offshore Drilling, Inc. and Ronald Woll (incorporated by reference to Exhibit 10.1 to our Current Report on Form8-K filed July 2, 2018).

31.1*		Rule13a-14(a) Certification of the Chief Executive Officer.

31.2*		Rule13a-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.


Date July 30, 2018	By:	/s/ Scott Kornblau
		Scott Kornblau
		Senior Vice President and Chief Financial Officer

		/s/ Beth G. Gordon
Date July 30, 2018		Beth G. Gordon
		Vice President and Controller (Chief Accounting Officer)

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