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~~ 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 13(a) of the 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, 2018~~April 25, 2019 Common stock, $0.01 par value per share ~~137,434,458~~137,690,627 shares

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

	Three Months Ended March 31, 2018
										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity
December 31, 2017		144,085,292	$	1,441	$	2,011,397	$	1,964,497		$	(5	)		6,857,510	$	(203,069	)	$	3,774,261
Impact of change in accounting principle		—		—		—		(14,812	)		—			—		—			(14,812	)
Adjusted balance at January 1, 2018		144,085,292	$	1,441	$	2,011,397	$	1,949,685		$	(5	)		6,857,510	$	(203,069	)	$	3,759,449
Net income		—		—		—		19,321			—			—		—			19,321
Stock-based compensation, net of tax		164,271		1		1,596		—			—			49,082		(733	)		864
Net loss on derivative financial instruments		—		—		—		—			(2	)		—		—			(2	)
March 31, 2018		144,249,563	$	1,442	$	2,012,993	$	1,969,006		$	(7	)		6,906,592	$	(203,802	)	$	3,779,632

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

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, ~~2017~~2018 (FileNo. 1-13926).

As of ~~July 27, 2018,~~April 25, 2019, 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 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 or loss, statements of stockholders’ equity 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.

~~Revenue Recognition~~. In ~~May 2014,~~February 2016, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU,No. ~~2014-09,~~2016-02, Leases~~Revenue from Contracts with Customers(Topic 606)~~ (Topic 842), or ASU~~2014-09,~~ 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 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 ASU~~2016-16~~ 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):~~

the severity of personal injuries claimed;

significant changes in the volume of personal injury claims;

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

inconsistent court decisions; and

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

Letters of Credit and Other.We were contingently liable as of ~~June 30, 2018~~March 31, 2019 in the amount of ~~$11.2~~$25.7 million under certain customs, performance, tax ~~bid~~ and ~~customs~~VAT bonds and letters of credit. Agreements relating to approximately ~~$5.5~~$17.1 million of tax and customs bonds can require collateral at any time. As of ~~June 30, 2018,~~March 31, 2019, 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.

9. Leases and Lease Commitments

~~10. Restructuring~~Our leasing activities primarily consist of operating leases for shorebase offices, office and ~~Separation Costs~~information technology equipment, employee housing, vehicles, onshore storage yards and certain rig equipment and tools. Our leases have terms ranging from one month to ten years, some of which include options to extend the lease for up to five years and/or to terminate the lease within one year.

Additionally, we are participants in four sale and leaseback arrangements with a subsidiary of GE Oil & Gas, or GE, pursuant to the 2016 sale of certain blowout preventers and related well control equipment, or Well Control Equipment, on our drillships and corresponding agreements to lease back that equipment under ten-year operating leases for approximately $26 million per year with renewal options for two successive five-year periods. At the time of the transactions with GE, the carrying value of the Well Control Equipment exceeded the aggregate proceeds received from the sale, resulting in the recognition of prepaid rent, which was being amortized over the respective terms of the leases. On January 1, 2019, as a result of the adoption of ASU 2016-02, the aggregate remaining prepaid rent balances of $3.9 million and $10.6 million, previously recorded as “Prepaid expenses and other current assets” and “Other assets,” respectively, were reclassified to a right-of-use lease asset within “Other assets” in our unaudited Condensed Consolidated Balance Sheets and continue to be amortized over the remaining terms of the leases. In connection with the sale and leaseback transactions, we also entered into a ten-year service agreement with another GE affiliate pertaining to the Well Control Equipment. Such services include management of maintenance, certification and reliability with respect to such equipment.

In ~~late 2017,~~applying the standard, we utilize an exemption for short-term leases whereby we do not record leases with terms of one year or less on the balance sheet. We have also made an accounting policy election to not separate lease components from non-lease components for each of our ~~management approved~~classes of underlying assets, except for subsea equipment, which includes the Well Control Equipment discussed above. At inception, the consideration for the overall Well Control Equipment arrangement was allocated between the lease and ~~initiated a plan~~service components based on an estimation of stand-alone selling price of each component, which maximized observable inputs. The costs associated with the service portion of the agreement are accounted for separately from the cost attributable to ~~restructure~~the equipment leases based on that allocation and thus, are not included in our ~~worldwide operations, which included a reduction~~right-of-use lease asset or lease liability balances. The non-lease components for each of our other classes of assets generally relate to maintenance, monitoring and security services and are not separated from their respective lease components.

The lease term used for calculating our right-of-use assets and lease liabilities is determined by considering the noncancelable lease term, as well as any extension options that we are reasonably certain to exercise. The determination to include option periods is generally made by considering the activity in ~~workforce~~the region or for the rig corresponding to the respective lease, among other contract-based and market-based factors. We have used our incremental borrowing rate to discount future lease payments as the rate implicit in our leases is not readily determinable. To arrive at our ~~corporate facilities~~incremental borrowing rate, we consider our unsecured borrowings and ~~onshore bases that we refer~~then adjust those rates to asassume full collateralization and to factor in the ~~2017 Reduction Plan. During~~individual lease term and payment structure.

Total operating lease expense for the ~~three-month andsix-month~~ ~~periods~~three months 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 $2.2March 31, 2019 was $9.4 million, of which ~~$0.7~~$1.3 million ~~is payable during the remainder of 2018 and $1.5 million is payable in 2019.~~

~~11. Income Taxes~~

~~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 the~~one-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~~short-term leases. Total operating lease expense for the three months ended March 31, 2018 was $7.6 million.

Supplemental information related to ~~the timing~~leases is as follows (in thousands, except weighted-average data):

	Three Months Ended March 31, 2019
Operating cash flows used for operating leases	$	11,302
Right-of-use assets obtained in exchange for lease liabilities		714
Weighted-average remaining lease term	7.0 years
Weighted-average discount rate		9.24	%

Future minimum rental payments under noncancelable operating leases as of ~~the enactment~~December 31, 2018 were as follows (in thousands):

2019	$	28,373
2020		27,144
2021		26,565
2022		26,281
2023		26,280
Thereafter		64,062
Total lease payments	$	198,705

Maturities of ~~the Tax Reform Act, there has been and continues to be a significant amount~~lease liabilities as of ~~uncertainty~~March 31, 2019 are 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 positionfollows (in thousands):

2019 (excluding three months ended March 31, 2019)	$	23,739
2020		27,865
2021		26,545
2022		26,296
2023		26,280
2024		26,352
Thereafter		37,710
Total lease payments		194,787
Less: interest		(51,737	)
Total lease liability	$	143,050
Amounts recognized in unaudited Condensed Consolidated Balance Sheet:
Accrued liabilities	$	29,334
Other liabilities		113,716
Total operating lease liability	$	143,050

Operating lease assets, including prepaid rent balances related to the ~~toll charge~~GE transaction, totaling $157.0 million are included in ~~accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin No. 118, or SAB 118. SAB 118 allowed companies~~“Other assets” in our unaudited Condensed Consolidated Balance Sheets as of March 31, 2019.

As of March 31, 2019, we have three additional operating leases for mooring equipment to ~~report the income tax effects~~be used on our rigs that have not yet commenced. These agreements provide for fixed lease payments of approximately $12 million to be paid over each of the ~~Tax Reform Act as~~respective lease terms, or an aggregate of approximately $36 million. These leases are expected to commence in April, May and September of 2019, and each is expected to have 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.lease term of approximately ten years.

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.17

~~12.~~10. Segments and Geographic Area Analysis

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

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, 2018,~~March 31, 2019, our active drilling rigs were located offshore ~~four~~three 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.~~performed and, unless otherwise noted, reflect earnings attributable to our floater rigs (drillships and semisubmersibles).

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


	Three Months Ended June 30, 2018										Three Months Ended March 31, 2019
	Floater Rigs		Jack-up Rigs⁽¹⁾		Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total		Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	158,554	$	3,648	$	162,202	$	1,172	$	163,374	$	138,632	$	1,946	$	140,578
South America		26,288		—		26,288		—		26,288		53,284		30		53,314
Europe		18,738		—		18,738		1,742		20,480		24,609		1,907		26,516
Australia/Asia		58,125		—		58,125		594		58,719

Australia												10,172		2,962		13,134
Total	$	261,705	$	3,648	$	265,353	$	3,508	$	268,861	$	226,697	$	6,845	$	233,542

	Three Months Ended March 31, 2018
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States⁽¹⁾	$	164,439	$	2,137	$	166,576
South America		54,268		1		54,269
Europe		11,392		1,378		12,770
Australia/Asia		57,827		4,068		61,895
Total	$	287,926	$	7,584	$	295,510

⁽¹⁾

~~Loss-of-hire~~Includes $4.8 million in loss-of-hire insurance proceeds received in 2018 related to early contract terminations in prior years for twojack-up rigs that previously worked in Mexico.

   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

⁽¹⁾

~~Loss-of-hire~~ ~~insurance proceeds related to early contract terminations for twojack-up~~ ~~rigs that previously worked in Mexico.~~

11 . Income Taxes

In response to our interpretation of the Tax Cuts and Jobs Act, commonly referred to as theTax 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 the one-time mandatory repatriation of previously deferred earnings of certain non-U.S. 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, or IRS, issued additional guidance which we believe clarified certain of our tax positions taken in 2017 and, consequently, during the first quarter of 2018, we reversed a $43.3 million liability for an uncertain tax position related to the deemed repatriation of accumulated non-U.S. earnings 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 benefits 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 12 months, until the accounting and analysis under the FASB’s Accounting Standards Codification No. 740, Income Taxes is complete.

   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

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

The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements (including the notes thereto) included in Item 1 of Part I of this report, Item 1A, “Risk Factors,” included in Part II 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, ~~2017.~~2018. 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 ~~17 floaters,~~16 floater rigs (four drillships and 12 semisubmersibles), of which ~~four~~three rigs are currently cold-stacked. ~~The~~In late 2018, we initiated the reactivation and upgrade of the Ocean ~~Scepter~~ ~~was sold~~Onyx, which we expect to complete in ~~July 2018. See “– Contract Drilling Backlog.”~~the latter part of 2019. The Ocean Guardian is excluded from our current fleet count as its sale is currently pending and is expected to close in the second quarter of 2019.

Market Overview

~~Oil prices rose during~~

Brent crude oil closed in the ~~first half of 2018, closing above$70-per-barrel~~high $60-per-barrel level at the end of the ~~second~~first quarter of 2019, averaging mid-$60 per barrel for the quarter. ~~Despite~~Demand and offshore utilization continued to increase during the ~~recovering commodity price,~~first quarter of 2019, with industry-wide floater utilization averaging near 65% at the ~~offshore contract drilling market continues~~end of March 2019, based on analyst reports. However, dayrates remain low compared to ~~stagnate,~~previous periods, as the increase in oil prices from earlier lows has not ~~yet~~ resulted in ~~a measurable~~significantly higher dayrates. Industry analysts indicate that, historically, utilization rates must increase ~~in demand for~~to the 80%-range before pricing power shifts to the drilling contractor from the customer. There is some optimism within the industry, and among analysts, that offshore contract drilling ~~services or higher dayrates. Capital spending for~~activity will increase over the next two years, as additional capital investments in offshore ~~exploration~~projects are made and ~~development remained at a relatively low level during the first half of 2018.~~cost efficiencies are achieved.

~~In addition, the recovery of the offshore contract drilling industry continues to be challenged by an oversupply of drilling rigs, which~~

During 2018 and continuing into 2019, there has ~~not yet~~ been ~~equalized by~~ an increase in ~~demand or through the retirement of rigs. Industry reports indicate that there remain approximately 40 newbuild floaters, most of which have not yet been contracted~~contract tenders for ~~future work,~~2020 and ~~over 90 speculative~~2021 floater project commencements~~jack-up~~ rigs currently on order with scheduled deliveries between 2018 and 2021. In addition, contract rollovers of currently contracted rigs are expected to add to the oversupply of rigs, if options for future work are not exercised or further 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.

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 levels in order to enable the drilling contractor to recover a portion of operating costs for rigs that would otherwise be uncontracted or stacked. Customers have also indicated a preference for “hot” rigs rather than reactivated cold-stacked rigs. This preference incentivizes the drilling contractor to contract rigs at lower rates for the sole purpose of maintaining the rigs in an active state and allowing for at least partial cost recovery. 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 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 work in the North Sea and Australia ~~floater~~ markets ~~commencing~~. Industry analysts also predict that there will be additional opportunities in ~~2019 and beyond, has increased. However,~~the West Africa market in the near term. Presently, many of these tenders ~~are~~have been limited to single-well jobs, with options for future wells. Although some geographic areas appear to be improving, other markets show little or no sign of ~~recovery.~~recovery at this time.

~~Given~~

From a supply perspective, industry analysts have reported that despite a decrease in the ~~current market conditions, contract drillers continue to seek ways to improve operating efficiencies, decreasenon-productive~~ ~~time and ultimately reduce~~global supply of floater rigs over the ~~cost of drilling and enhance cash flow for both~~past four years, the offshore ~~driller~~contract drilling market remains oversupplied. Rig attrition has slowed in 2019, with only three floaters having been retired during 2019 as of the date of this report. Industry reports indicate that approximately 40 newbuild floaters remain on order with deliveries currently scheduled between 2019 and 2022, most of which have not yet been contracted for future work, and more than 50 projected contracted floater rollovers are estimated to occur during the ~~customer.~~remainder of 2019. In addition, several rig reactivations were announced during 2018 and in early 2019, including the recent and ongoing reactivations of our Ocean Endeavor and Ocean Onyx, respectively. These factors provide for a continued, challenging offshore drilling market in the near term.

See “– Contract Drilling Backlog”for future commitments of our rigs during ~~2018~~2019 through 2022.

Contract Drilling Backlog

~~Contract~~Our 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~~Our 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 unaudited condensed consolidated financial statements included in Item 1 of Part I of this 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 following table reflects our contract drilling backlog as of ~~July~~April 1, ~~2018~~2019 (based on information available at that time), January 1, ~~2018~~2019 (the date reported in our Annual Report on Form10-K for the year ended December 31, ~~2017)~~2018), and ~~July~~April 1, ~~2017 (the~~2018 (the date reported in our Quarterly Report on Form10-Q for the quarter ended ~~June 30, 2017)~~March 31, 2018) (in thousands).

   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

April 1,

2019 ⁽¹⁾

January 1,

2019 (1)

April 1,

2018

Contract Drilling Backlog

1,762,000

1,973,000

2,177,000

⁽¹⁾

Contract drilling backlog as of ~~July~~April 1, ~~2018~~2019 and January 1, 2019 excludes future commitment amounts totaling $135.0 million payable by a customer in the form of a guarantee of gross margin to be earned on future contracts or by direct payment, pursuant to terms of an existing contract.

The following table reflects the amount of our contract drilling backlog by year as of ~~July~~April 1, ~~2018~~2019 (in thousands).

   For the Years Ending December 31,
   Total    2018⁽¹⁾    2019    2020    2021-2022
Contract Drilling Backlog⁽²⁾
   $ 2,211,000    $ 521,000    $ 847,000    $ 575,000    $ 268,000

	For the Years Ending December 31,
	Total		2019 ⁽¹⁾		2020		2021		2022
Contract Drilling Backlog ⁽²⁾	$	1,762,000	$	652,000	$	811,000	$	256,000	$	43,000

⁽¹⁾

Represents the~~six-month~~ nine-month period beginning ~~July~~April 1, ~~2018.~~2019.

⁽²⁾

Contract drilling backlog as of ~~July~~April 1, ~~2018~~2019 excludes future ~~commitment amounts~~gross margin commitments of $30.0 million for 2019, $30.0 million for 2020 and an aggregate $75.0 million for the 2021 through 2023 period payable by a customer in the form of a guarantee of gross margin to be earned on future contracts or by direct payment at the end of each of the three respective periods, pursuant to terms of an existing contract.

The following table reflects the percentage of rig days committed by year as of ~~July~~April 1, ~~2018.~~2019. 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).

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

	For the Years Ending December 31,
	2019 ⁽¹⁾			2020			2021			2022
Rig Days Committed ⁽²⁾		72	%		64	%		20	%		3	%

⁽¹⁾

Represents the~~six-month~~ nine-month period beginning ~~July~~April 1, ~~2018.~~2019.

⁽²⁾

As of ~~July~~April 1, ~~2018,~~2019, includes approximately ~~200, 340~~635 days, 130 days and 9545 days currently known and scheduled ~~days~~ for contract preparation, mobilization of rigs, surveys and extended repair and maintenance projects for the remainder of ~~2018~~2019 and for the years ~~2019~~2020 and ~~2020,~~2021, respectively.

~~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 the~~Ocean 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 the~~Ocean 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 the~~~~Ocean BlackHornet~~~~, which was scheduled to expire in April 2020, to be effective when the~~~~Ocean BlackHawk~~ ~~completes its regulatory maintenance and equipment re-certifications, expected by the end of June 2019.~~21

~~BP agreed to contract the~~~~Ocean 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 the~~Ocean 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 2018,~~2019, we expect to spend approximately 55635 days for ~~a special survey~~contract preparation, reactivation of rigs, mobilization of rigs, upgrades and ~~rig upgrades for the~~~~Ocean Apex~~~~and 145~~surveys, including an aggregate of approximately 295 days for ~~a special survey,~~upgrades, reactivation activities and contract preparation for theOcean Endeavor~~. In 2019, we~~and Ocean Onyx prior to their contract commencements. We also expect to spend ~~approximately an additional 90 days for contract preparation for the~~~~Ocean Endeavor~~~~prior to its contract commencement,~~ an aggregate of ~~200~~approximately 205 days for special surveys and rig upgrades for theOcean BlackHawk ~~and~~, Ocean BlackHornetand Ocean BlackRhino, approximately 60 days for a special survey and upgrades for the Ocean Courage and an aggregate of 50approximately 75 days for the ~~mobilization/demobilization~~mobilization of theOcean Apex and theOcean Monarch ~~offshore 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~~is scheduled to renew on May 1, ~~2018,~~2019, 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, 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 primary insurance policies are scheduled to renew effective May 1, 2019. Under these policies our deductibles for marine liability coverage related to insurable events arising due to named windstorms in the U.S. Gulf of Mexico ~~are~~will remain $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~~expected to be $5.0 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.

Critical Accounting Policies

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, ~~2017.~~2018. Effective January 1, ~~2018,~~2019, we adopted the Financial Accounting Standards Board Accounting Standards Update No. 2016-02, Leases (Topic 842), or ASU~~2014-09,~~ 2016-02, which, ~~supersedes the revenue recognition requirements in ASU Topic 605, Revenue Recognition,~~among other things, requires lessees to recognize a right of use asset and ~~ASUNo. 2016-16,~~~~Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory~~.a lease liability for virtually all leases. See ~~“ – Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows” and~~ Note 1 “General Information - ~~Changes in~~Recently Adopted Accounting ~~Principles~~,Pronouncements” ~~Note 2 “Revenue from Contracts with Customers”~~ and Note ~~11 “Income Taxes”~~9 “Leases and Lease Commitments” 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~~three months ended ~~June 30, 2018.~~

March 31, 2019.

Results of Operations

Our operating results for contract drilling services are dependent on three primary metrics or key performance indicators: revenue-earning days, rig utilization and average daily revenue. The following table presents these three key performance indicators and other comparative data relating to our revenues and operating expenses for the three-month ~~andsix-month~~periods ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017.~~.

   Three Months Ended
June 30, Six Months Ended
June 30,
   2018 2017 2018 2017
   (In thousands, except day amounts and percentages)
REVENUE-EARNING DAYS⁽¹⁾

Floaters
   825 987 1,633 1,969
Jack-ups
   —   82 —   134
UTILIZATION⁽²⁾

Floaters
   53 % 47 % 53 % 47 %
Jack-ups
   —   86 % —   49 %
AVERAGE DAILY REVENUE⁽³⁾

Floaters
   $ 317,200 $ 390,900 $ 333,700 $ 378,600
Jack-ups
   —   74,900 —   74,900
REVENUE RELATED TO CONTRACT DRILLING SERVICES
   $ 265,353 $ 392,170 $ 553,279 $ 755,727
REVENUE RELATED TO REIMBURSABLE EXPENSES
   3,508 7,119 11,092 17,788


TOTAL REVENUES
   $ 268,861 $ 399,289 $ 564,371 $ 773,515


CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION
   $ 189,321 $ 196,217 $ 374,010 $ 399,740
REIMBURSABLE EXPENSES
   $ 3,414 $ 6,790 $ 10,884 $ 17,268
OPERATING (LOSS) INCOME

Contract drilling services, net
   $ 76,032 $ 195,953 $ 179,269 $ 355,987
Reimbursable expenses, net
   94 329 208 520
Depreciation
   (81,825 ) (85,982 ) (163,650 ) (179,211 )
General and administrative expense
   (18,236 ) (19,010 ) (36,749 ) (36,493 )
Impairment of assets
   (27,225 ) (71,268 ) (27,225 ) (71,268 )
Restructuring and separation costs
   (1,265 ) —   (4,276 ) —
Gain on disposition of assets
   50 802 560 2,148


Total Operating (Loss) Income
   $ (52,375 ) $ 20,824 $ (51,863 ) $ 71,683


Other income (expense):

Interest income
   2,001 396 3,638 571
Interest expense, net of amounts capitalized
   (29,585 ) (27,251 ) (57,903 ) (54,847 )
Foreign currency transaction loss (gain)
   411 (927 ) 858 160
Other, net
   262 (62 ) 842 (125 )


(Loss) income before income tax benefit
   (79,286 ) (7,020 ) (104,428 ) 17,442
Income tax benefit
   10,012 22,969 54,475 22,046


NET (LOSS) INCOME
   $ (69,274 ) $ 15,949 $ (49,953 ) $ 39,488

	Three Months Ended March 31,
	2019			2018
	(In thousands, except days, daily amounts and percentages)
REVENUE-EARNING DAYS ⁽¹⁾		734			808
UTILIZATION ⁽²⁾		48	%		52	%
AVERAGE DAILY REVENUE ⁽³⁾	$	309,000		$	350,600
REVENUE RELATED TO CONTRACT DRILLING SERVICES	$	226,697		$	287,926
REVENUE RELATED TO REIMBURSABLE EXPENSES		6,845			7,584
TOTAL REVENUES	$	233,542		$	295,510
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION	$	167,429		$	184,689
REIMBURSABLE EXPENSES	$	6,743		$	7,470
OPERATING (LOSS) INCOME
Contract drilling services, net	$	59,268		$	103,237
Reimbursable expenses, net		102			114
Depreciation		(86,898	)		(81,825	)
General and administrative expense		(17,312	)		(18,513	)
Restructuring and separation costs		-			(3,011	)
(Loss) gain on disposition of assets		(4,287	)		510
Total Operating (Loss) Income	$	(49,127	)	$	512
Other income (expense):
Interest income		2,414			1,637
Interest expense, net of amounts capitalized		(29,925	)		(28,318	)
Foreign currency transaction (loss) gain		(1,085	)		447
Other, net		333			580
Loss before income tax benefit		(77,390	)		(25,142	)
Income tax benefit		4,062			44,463
NET (LOSS) INCOME	$	(73,328	)	$	19,321

⁽¹⁾

A revenue-earning day is defined as a24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

⁽²⁾

Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all specified rigs in our fleet (including three and five ~~and ten~~ cold-stacked ~~floater~~ rigs at ~~June 30,~~March 31, 2019 and 2018, ~~and 2017,~~ respectively).

⁽³⁾

Average daily revenue is defined as total contract drilling revenue for all of the ~~specified~~ rigs in our fleet per revenue-earning day.

Three Months Ended ~~June 30,~~March 31, 2019 and 2018 ~~and 2017~~

Net results for the ~~second~~first quarter of ~~2018~~2019 decreased ~~$85.2~~$92.6 million compared to the ~~second~~first quarter of ~~2017,~~2018, reflecting lower margins from our contract drilling services, primarily driven by lower contract drilling ~~revenue and~~revenue. Contract drilling services contributed operating income of $59.3 million during the first quarter of 2019, compared to $103.2 million in the first quarter of 2018. Our results for the first quarter of 2019 were also negatively impacted by a lower tax benefit ~~recognized. The reduction~~recognized, compared to the prior year quarter, a $4.3 million loss on the sale of scrapped rig equipment recognized in ~~net results was~~the first quarter of 2019 and higher depreciation expense of $5.1 million, primarily due to capital expenditures made in the latter part of 2018 and the completion of software implementation projects.

Operating Results. Contract drilling revenue decreased $61.2 million during the first quarter of 2019 compared to the first quarter of 2018, primarily due to lower average daily revenue earned ($30.5 million), the effect of 74 fewer revenue-earning days ($25.9 million) and the absence of $4.8 million in loss of hire insurance proceeds recognized during the first quarter of 2018 related to contract terminations for two jack-up rigs in a prior year. Comparing the two quarters, average daily revenue decreased primarily due to lower dayrates earned by some of our rigs as a result of renegotiating certain existing contracts during 2018 and a lower dayrate earned by the Ocean GreatWhite, which commenced operations under a new contract in the U.K. during the first quarter of 2019. Revenue-earning days decreased, compared to the prior year quarter, due to incremental downtime for planned shipyard projects (96 days) and fewer revenue-earning days for the Ocean Guardian, which is currently classified as held for sale (30 days), partially offset by the favorable impact of ~~lower depreciation expense~~fewer mobilization and lower impairment charges recognized in the second quarter of 2018, compared to the same period of 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~~non-productive 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 currently~~held-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~~(52 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 the~~~~Ocean Valor~~~~, which is earning a reduced standby rate until October 2018, and the~~~~Ocean Patriot,~~~~which began working under a new contract in the North Sea during the first quarter of 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~~$17.3 million during the ~~second~~first quarter of ~~2018~~2019 compared to the ~~second~~same quarter ~~of 2017,~~in 2018, reflecting reduced costs for currently cold-stacked and previously-owned rigs, which had incurred contract drilling expense in the ~~second~~first quarter of ~~2017~~2018 ($~~18.7 million), partially offset by increased costs for our current rig fleet ($11.8~~9.3 million). ~~The increase in contract~~Contract drilling expense ~~during the second quarter of 2018~~ for our current floater fleet reflected reduced labor and related ~~primarily to higher maintenance and repair costs~~expenses ($~~16.0~~7.7 million), ~~which included incremental costs~~primarily due to the utilization of personnel for ~~the~~~~Ocean Courage~~ ~~and costs associated with the~~~~Ocean Valiant~~~~’s special survey, combined with higher costs for~~capitalizable shipyard projects, fuel ~~and inspections~~ ($~~5.2~~3.6 million) and other rig operating expenses ($~~0.5~~1.7 million). ~~These costs~~Cost reductions in the first quarter of 2019 were partially offset by ~~reductions~~an increase in costs for repairs and maintenance ($2.2 million), rig mobilization ($1.1 million) and 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 ($2.11.7 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 as a result of asset impairments recognized during 2017.

~~Impairment of Assets~~~~. During the second quarter of 2018, we recorded an impairment loss of $27.2 million to recognize a reduction in fair value (less costs to sell) of the~~~~Ocean 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. The~~~~Ocean Scepter~~ was sold in July 2018. During the second quarter of 2017, we recognized an aggregate impairment charge of $71.3 million with respect to the carrying values of two semisubmersible floaters, one of which was sold during the first quarter of 2018. See Notes 1 and 3 to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

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~~first quarter of 2018, we recognized ~~$1.3~~and paid $3.0 million in restructuring and other employee separation related costs for additional redundant employees ~~including additional personnel~~that were identified in early 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~~ Restructuring activities associated with ~~our senior notes issued~~the plan were substantially completed in ~~August 2017 at a higher interest rate than the senior notes that were retired in the third quarter of 2017.~~2018.

Income Tax ~~Benefit.~~Benefit. We recorded a net income tax benefit of ~~$10.0~~$4.1 million for the ~~second~~first quarter of ~~2018,~~2019, compared to ~~$23.0~~an income tax benefit of $44.5 million for the same quarter of ~~2017. The difference was in large part due to~~2018. During the ~~mix of our domestic and internationalpre-tax~~ earnings and losses 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 quartersfirst quarter of 2018, ~~and 2017.~~

~~Six Months Ended June 30, 2018 and 2017~~

Net results for the first six months of 2018 decreased $89.4 million compared to the first six months of 2017, 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 currently~~held-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 2017, primarily due to lower dayrates earned by the~~Ocean Valor~~ ~~and the~~~~Ocean Patriot~~ ~~during the first six months of 2018. The decrease in revenue was partially offset by $8.4 million inloss-of-hire~~ ~~insurance proceeds~~we 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 the~~Ocean 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 2017, primarily due to a lower depreciable asset base as a result of asset impairments recognized during 2017.

~~Interest Expense, Net of Amounts Capitalized.~~Interest expense increased $3.1 million during the first half of 2018 compared to the same period of 2017, primarily as a result of incremental interest expense of $5.2 million associated with our senior notes issued in August 2017 at a higher interest rate than the senior notes that were retired in the third quarter of 2017. Higher interest cost associated with our senior notes was partially offset by the reversal of contingent interest associated with a Brazilian~~non-income~~ ~~tax contingency for which the statute of limitations expired and interest capitalized in connection with certain qualifying software implementation projects.~~

~~Income Tax Benefit.~~~~We recorded a net income tax benefit of $54.5 million for thesix-month~~ ~~period ended June 30, 2018, compared to $22.0 million for the 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~~Cuts and Jobs Act enacted in ~~2018 clarified certain of our tax positions taken and, consequently, we reversed our liability for an uncertain tax position related to the toll charge. Notwithstanding~~December 2017. Other than the reversal of the uncertain tax position, the difference in the amount of ~~income~~ tax benefit recognized inbetween the ~~2018 period, compared to the comparable period of 2017,~~periods was in large part due to the mix of our domestic and internationalpre-tax earnings and losses 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 2018 and 2017.periods.

Liquidity and Capital Resources

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~~credit agreements that provide for maximum borrowings of up to $1.235 billion, ~~syndicated revolving credit agreement, or Credit Agreement,~~ all of which was available to ~~provide liquidity for our payment obligations~~us as of ~~July 27, 2018. See “ – Credit Agreement.”~~April 25, 2019. In addition, as of ~~July~~April 1, ~~2018,~~2019, our contractual backlog was ~~$2.2~~$1.8 billion, of which ~~$0.5~~$0.7 billion is expected to be realized during the remainder of ~~2018.~~

2019.

~~Certain~~Our worldwide earnings and cash balances are available to finance both our domestic and foreign activities. We record the withholding income tax impact, if any, associated with the potential distribution of earnings of our foreign subsidiaries; however, we have not provided income tax on the outside basis difference 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 were deemed repatriatedsubsidiaries as ~~a result of the Tax Reform Act, and U.S. taxes were provided for those earnings. We~~management does not intend to ~~indefinitely reinvest earnings~~dispose of DFAC and its foreign subsidiaries to finance our foreign activities. Earnings of DFAC subsequent to 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~~these subsidiaries. We expect to utilize ~~the operating cash flows generated by and cash reserves of DFAC and the operating cash flows available~~existing structuring alternatives to ~~and cash reserves of Diamond Offshore Drilling, Inc. to meet each entity’s respective working capital requirements and capital commitments.~~ mitigate any potential liability should a disposition take place.

At ~~June 30, 2018 and December~~March 31, ~~2017,~~2019, we had cash available for current operations of ~~$144.2~~$122.8 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.~~$249.9 million.

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

Based on our cash available ~~for current operations~~ and ~~contractual~~contract drilling backlog, we believe ~~future~~our 2019 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,~~credit agreements, as needed. We expect, based on our current forecast, that we will utilize a portion of the availability under our credit agreements in the latter part of 2019 to meet our short-term liquidity requirements. See “– Sources and Uses of Cash –Rig Reactivation, Upgrades and Other Capital 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 2017 or during the first half of 2018.24

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not purchase any shares of our outstanding common stock during the~~six-month~~ ~~periods~~ three-month period ended ~~June 30, 2018 and 2017.~~March 31, 2019.

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. We have an effective automatic shelf registration statement under which we may publicly issue debt, equity or hybrid securities. 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.

Sources and Uses of Cash

During the~~six-month~~ three-month period ended ~~June 30, 2018,~~March 31, 2019, our ~~primary sources of cash were an aggregate $130.8 million generated by~~ operating activities ~~and proceeds of $1.7~~generated $2.9 million, ~~primarily from~~while cash usage for the ~~sale of the~~~~Ocean Victory~~ ~~in January 2018. Cash usage during thesix-month~~three-month period ended ~~June 30, 2018~~March 31, 2019 was primarily ~~$273.8 million for purchases of marketable securities, net of maturities, and~~ for capital expenditures aggregating ~~$90.4~~$85.9 million.

Cash Flowfrom Operations.Cash flow from operations for the~~six-month~~ three-month period ended ~~June 30, 2018~~March 31, 2019 decreased ~~$46.1~~$80.9 million compared to the~~six-month~~ three-month period ended ~~June 30, 2017,~~March 31, 2018, primarily due to lower cash receipts for contract drilling services ($~~103.9~~129.0 million), partially offset by a net decrease in cash expenditures for contract drilling services and other working capital requirements ($~~28.4~~37.3 million) and lower income tax payments, net of refunds ($~~29.4~~10.7 million). The decline in operating cash flow is reflective of the continued stagnation of the offshore contract drilling market during the first quarter of 2019.

Rig Reactivation, Upgrades and Other Capital ~~Expenditures.~~Expenditures. As of the date of this report, we expect ~~total~~ capital expenditures in 2019 to be approximately $340 million to $360 million. Projects for ~~2018 to aggregate~~2019 include (i) approximately ~~$220.0~~$110 million ~~for~~in capitalized costs associated with the reactivation and upgrade of the Ocean Onyx, (ii) approximately $20 million associated with the reactivation of the Ocean Endeavor and (iii) other capital expenditures under our capital maintenance and replacement ~~programs.~~programs, including equipment upgrades for the Ocean BlackHawk, Ocean BlackHornet and Ocean Courage.

At ~~June 30, 2018,~~March 31, 2019, we had no significant purchase obligations, except for those related to our direct rig operations, which arise during the normal course of business.

Other Obligations. As of ~~June 30, 2018,~~March 31, 2019, the total net unrecognized tax benefits related to uncertain tax positions was ~~$63.3~~$82.8 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.

~~Credit Agreement~~

~~At June 30, 2018, we had no borrowings outstanding under~~We have various obligations corresponding to our ~~Credit Agreement,~~lease arrangements. See Note 9 “Leases and ~~were~~Lease Commitments” to our unaudited condensed consolidated financial statements included in ~~compliance with all covenants thereunder.~~Item 1 of Part I of this report.

Credit Ratings

Our current corporate credit ~~rating is Ba3 from Moody’s Investor Services and B+~~ratings from S&P Global Ratings, ~~with a negative~~or S&P, and Moody’s Investor Services, or Moody’s, are B and B2, respectively, and our current senior unsecured notes credit rating from Moody’s is B3. The rating outlook from ~~both. Market conditions~~both S&P and ~~other factors, many of which are outside of our control, could cause our~~Moody’s is negative. These credit ratings ~~to be lowered. Any downgrade in our credit ratings~~are below investment grade and could ~~adversely impact~~raise 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.~~financing. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.

Other Commercial Commitments - Letters of Credit

WeThere were ~~contingently liable~~no material changes to our commercial commitments as of ~~June 30,~~March 31, 2019. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018 ~~in the amount of $11.2 million under certain performance, tax, bid~~for further information.

Off-Balance Sheet Arrangements

At March 31, 2019 and ~~customs bonds and letters of credit. Agreements relating to approximately $5.5 million of tax and customs bonds can require collateral at any time. As of June 30,~~December 31, 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 (in thousands).

      For the Years Ending
December 31,
   Total    2018    2019
Other Commercial Commitments

Performance bonds
   $ 1,000    $ —      $ 1,000
Tax bond
   5,326    5,326    —
Bid bond
   3,200    3,200    —
Other
   1,677    810    867






Total obligations
   $ 11,203    $ 9,336    $ 1,867

~~Off-Balance~~ ~~Sheet Arrangements~~

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

New Accounting Pronouncements

See Note 1 “General ~~Information”~~Information – Recently Adopted Accounting Pronouncements” 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.

Forward-Looking Statements

We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, ~~or the Securities Act,~~ and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “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:

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

sources and uses of and requirements for financial resources and sources of liquidity;

contractual obligations and future contract negotiations;

interest rate and foreign exchange risk;

operations outside the United States;

business strategy;

growth opportunities;

competitive position, including without limitation, competitive rigs entering the market;

expected financial position;

cash flows and contract backlog;

•

~~the extension of the~~~~Ocean BlackHawk~~ ~~contract, including~~future amounts payable by a customer in the form of a guarantee of gross margin to be earned on future ~~dayrates, revenues and extensions, and the timing of future maintenance activities and the early release of the~~~~Ocean BlackHornet~~ ~~contract;~~

~~new drilling~~ contracts ~~with and future payments from BP,~~or by direct payment, pursuant to terms of an existing contract, including the timing ~~duration, commencement, dayrates~~ and revenue associated ~~therewith and any future drilling contracts;~~therewith;

idling drilling rigs or reactivating stacked rigs;

outcomes of litigation and legal proceedings;

declaration and payment of dividends;

financing plans;

market outlook;

tax planning and effects of the Tax Reform Act;

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

budgets for capital and other expenditures;

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

timing and cost of completion of capital projects;

delivery dates and drilling contracts related to capital projects or rig acquisitions;

the reactivation of and future contracts for the Ocean Endeavor and Ocean Onyx;

the sale of the Ocean Guardian;

plans and objectives of management;

scrapping retired rigs;

~~assets held for sale;~~

purchasing or constructing rigs;

asset impairments and impairment evaluations;

our internal controls and internal control over financial reporting;

performance of contracts;

purchases of our securities;

compliance with applicable laws; and

availability, limits and adequacy of insurance or indemnification.

These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, those described or referenced under “Risk Factors” in Item 1A in our Annual Report on Form10-K for the year ended December 31, ~~2017.~~2018 and Item 1A, “Risk Factors,” included in Part II of this report .

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. While we believe that these reports are reliable, we have not independently verified the information included in such reports. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

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 a~~one-year~~ ~~period.~~

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on June 30, 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~~three months ended ~~June 30, 2018.~~March 31, 2019. 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, ~~2017~~2018 for further information.

ITEM 4. Controls and Procedures.

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, 2018.~~March 31, 2019. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of ~~June 30, 2018.~~March 31, 2019.

~~There~~There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our ~~second~~first fiscal quarter of ~~2018~~2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings.

Information related to certain legal proceedings is included in Note 98 to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

ITEM 1A. Risk Factors.

Our Annual Report on Form10-K for the year ended December 31, ~~2017~~2018 includes a detailed discussion of certain material risk factors facing our company. NoThe information presented below describes a restatement of one such risk factor and should be read in conjunction with the Risk Factors included under Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2018. Except as presented below, no material changes have been made to such risk factors as of ~~June 30, 2018.~~March 31, 2019.

~~ITEM 2. Unregistered Sales~~We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of ~~Equity Securities and Use~~contract drilling revenue will be ultimately realized.

Our customers may terminate our drilling contracts under certain circumstances, such as the destruction or loss of ~~Proceeds.~~a drilling rig, our suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment, excessive downtime for repairs, failure to meet minimum performance criteria (including customer acceptance testing) or, in some cases, due to other events beyond the control of either party.

~~Items 2(a) and 2(b)~~In addition, some of our drilling contracts permit the customer to terminate the contract after specified notice periods, often by tendering contractually specified termination amounts, which may not fully compensate us for the loss of the contract. In some cases, our drilling contracts may permit the customer to terminate the contract without cause, upon little or no notice or without making an early termination payment to us. During depressed market conditions, such as those currently in effect, certain customers have utilized such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under circumstances where we believe we are ~~not applicable.~~

~~(c) During the three months ended June 30, 2018,~~ in ~~connection~~compliance with the ~~vesting~~contracts. Additionally, because of depressed commodity prices, restricted ~~stock units held by~~credit markets, economic downturns, changes in priorities or strategy or other factors beyond our ~~officers and certain~~control, a customer may no longer want or need a rig that is currently under contract or may be able to obtain a comparable rig at a lower dayrate. For these reasons, customers may seek to renegotiate the terms of our ~~employees, which were awarded~~existing drilling contracts, terminate our contracts without justification or repudiate or otherwise fail to perform their obligations under our contracts. As a result of such contract renegotiations or terminations, our contract backlog may be adversely impacted. We might not recover any compensation (or any recovery we obtain may not fully compensate us for the loss of the contract) and we may be required to idle one or more rigs for an ~~equity incentive compensation plan, we acquired shares~~extended period of time. Each of these results could have a material adverse effect on our ~~common stock in satisfaction~~financial condition, results of ~~tax withholding obligations that were incurred on the vesting date. The date of acquisition, number of shares~~operations and ~~average effective acquisition price per share were as follows:~~

~~Issuer Purchases of Equity Securities~~cash flows.

Period
   Total Number of
Shares Acquired    Average Price
Paid per Share    Total Number of
Shares Purchased as
Part of Publicly
Announced Plans or
Programs    Maximum Number
of Shares that May
Yet Be Purchased
Under the Plans or
Programs
April 1, 2018 through April 30, 2018
   36,498    $ 14.66    N/A    N/A
May 1, 2018 through May 31, 2018
   —      —      N/A    N/A
June 1, 2018 through June 30, 2018
   —      —      N/A    N/A








Total
   36,498    $ 14.66    N/A    N/A

ITEM 6. ~~Exhibits.~~Exhibits.


Exhibit No.		Description of Exhibit

~~3.1~~ 10.1		~~Amended and Restated By-Laws (as amended through July~~ ~~23, 2018) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form8-K~~ ~~filed July~~ ~~24, 2018).~~

10.1*		~~The~~Specimen Cash Incentive Award Agreement for executive officers under the Diamond Offshore Drilling, Inc. Incentive Compensation Plan (Amended and Restated as of January 1, 2018, as amended on 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)~~March 20, 2019).

31.1* 10.2		Specimen Cash Incentive Award Agreement for the Chief Executive Officer under the Diamond Offshore Drilling, Inc. Incentive Compensation Plan (Amended and Restated as of January 1, 2018, as amended on June 28, 2018) (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed March 20, 2019).

10.3		Specimen Restricted Stock Unit Award Agreement for executive officers under the Diamond Offshore Drilling, Inc. Equity Incentive Compensation Plan (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed March 20, 2019).

10.4		Specimen Restricted Stock Unit Award Agreement for the Chief Executive Officer under the Diamond Offshore Drilling, Inc. Equity Incentive Compensation Plan (incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed March 20, 2019).

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.

*	Filed or furnished herewith.

~~SIGNATURES~~SIGNATURES

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


			DIAMOND OFFSHORE DRILLING, INC.
			(Registrant)


Date ~~July 30, 2018~~April 29, 2019	By:	~~By:~~		/s/ Scott Kornblau
				Scott Kornblau
				Senior Vice President and Chief Financial Officer


Date April 29, 2019			/s/ Beth G. Gordon
~~Date July 30, 2018~~				Beth G. Gordon
				Vice President and Controller (Chief Accounting Officer)

3331


	June 30,			December 31,			March 31,			December 31,
	2018			2017			2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	144,168		$	376,037		$	122,840		$	154,073
Marketable securities		274,671			—			249,858			299,849
Accounts receivable, net of allowance for bad debts		203,131			256,730			189,381			168,620
Prepaid expenses and other current assets		154,408			157,625			170,232			163,396
Assets held for sale		67,815			96,261			491			—

Total current assets		844,193			886,653			732,802			785,938
Drilling and other property and equipment, net of accumulated depreciation		5,197,197			5,261,641
Drilling and other property and equipment, net of
accumulated depreciation								5,170,858			5,184,222
Other assets		71,389			102,276			208,824			65,534

Total assets	$	6,112,779		$	6,250,570		$	6,112,484		$	6,035,694

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current liabilities:
Accounts payable	$	54,717		$	38,755		$	60,284		$	43,933
Accrued liabilities		130,123			154,655			197,877			172,228
Taxes payable		14,522			29,878			15,096			20,685

Total current liabilities		199,362			223,288			273,257			236,846
Long-term debt		1,973,059			1,972,225			1,974,365			1,973,922
Deferred tax liability		124,350			167,299			97,810			104,380
Other liabilities		105,278			113,497			255,176			135,893

Total liabilities		2,402,049			2,476,309			2,600,608			2,451,041

Commitments and contingencies (Note 9)

Stockholders’ equity:
Commitments and contingencies (Note 8)
Stockholders’ equity:
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding)		—			—			—			—
Common stock (par value $0.01, 500,000,000 shares authorized; 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
Common stock (par value $0.01, 500,000,000 shares authorized; 144,606,992 shares issued and 137,580,203 shares outstanding at March 31, 2019; 144,383,662 shares issued and 137,438,353 shares outstanding at December 31, 2018)								1,446			1,444
Additionalpaid-in capital		2,013,862			2,011,397			2,019,555			2,018,143
Retained earnings		1,899,735			1,964,497			1,696,087			1,769,415
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	)

Accumulated other comprehensive gain								2			21
Treasury stock, at cost (7,026,789 and 6,945,309 shares of common stock at March 31, 2019 and December 31, 2018, respectively)								(205,214	)		(204,370	)
Total stockholders’ equity		3,710,730			3,774,261			3,511,876			3,584,653

Total liabilities and stockholders’ equity	$	6,112,779		$	6,250,570		$	6,112,484		$	6,035,694


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

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

Investing activities:
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		1,723			4,077
Other		—			23

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

Financing activities:
Net repayment of short-term borrowings		—			(104,200	)
Other		(90	)		(156	)

Net cash used in financing activities		(90	)		(104,356	)

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

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

	Three Months Ended
	March 31,
	2019			2018
Operating activities:
Net (loss) income	$	(73,328	)	$	19,321
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation		86,898			81,825
Loss (gain) on disposition of assets		4,287			(510	)
Deferred tax provision		(7,769	)		(49,089	)
Stock-based compensation expense		1,414			1,597
Contract liabilities, net		11,980			(500	)
Contract assets, net		(1,922	)		611
Deferred contract costs, net		(6,244	)		10,827
Other assets, noncurrent		98			228
Other liabilities, noncurrent		(570	)		(1,811	)
Other		(1,517	)		3,182
Changes in operating assets and liabilities:
Accounts receivable		(20,761	)		56,962
Prepaid expenses and other current assets		604			2,381
Accounts payable and accrued liabilities		13,329			(36,542	)
Taxes payable		(3,637	)		(4,713	)
Net cash provided by operating activities		2,862			83,769
Investing activities:
Capital expenditures		(85,890	)		(31,483	)
Proceeds from maturities of marketable securities		1,000,000			—
Purchase of marketable securities		(948,298	)		—
Proceeds from disposition of assets, net of disposal costs		95			1,427
Net cash used in investing activities		(34,093	)		(30,056	)
Financing activities:
Other		(2	)		(66	)
Net cash used in financing activities		(2	)		(66	)
Net change in cash and cash equivalents		(31,233	)		53,647
Cash and cash equivalents, beginning of period		154,073			376,037
Cash and cash equivalents, end of period	$	122,840		$	429,684


	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


				PAGE NO.
~~COVER PAGE~~			1

COVER PAGE				1

TABLE OF CONTENTS					2


PART I. FINANCIAL INFORMATION					3


	ITEM 1.		Financial Statements (Unaudited)				3
		Condensed Consolidated Balance Sheets			3
		Condensed Consolidated Statements of Operations			4
		Condensed Consolidated Statements of Comprehensive Income or Loss		5
		Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~Stockholders’ Equity			5	6
		Condensed Consolidated Statements of Cash Flows			6	7
		Notes to Unaudited Condensed Consolidated Financial Statements			7
			8

	ITEM 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
			20

	ITEM 3.		Quantitative and Qualitative Disclosures About Market Risk			30
			27

	ITEM 4.		Controls and Procedures			30
			28

PART II. OTHER INFORMATION					31
			29

	ITEM 1.	Legal Proceedings	~~Legal Proceedings~~			31
			29

	ITEM 1A.		Risk Factors			31
			29
~~ITEM 2.~~		~~Unregistered Sales of Equity Securities and Use of Proceeds~~			31

	ITEM 6.	Exhibits	~~Exhibits~~			32
			30

SIGNATURES					33	31


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended March 31,
	2018			2017			2018			2017			2019			2018
Net (loss) income	$	(69,274	)	$	15,949		$	(49,953	)	$	39,488		$	(73,328	)	$	19,321

Other comprehensive gains (losses), net of tax:
Derivative financial instruments:
Reclassification adjustment for gain included in net income		(1	)		(1	)		(3	)		(3	)
Reclassification adjustment for gain included in net (loss) income														(1	)		(2	)
Investments in marketable securities:
Unrealized holding gain		31			—			31			—			14			-

Total other comprehensive gain (loss)		30			(1	)		28			(3	)

Reclassification adjustment for gain included in net (loss) income														(32	)		-
Total other comprehensive loss														(19	)		(2	)
Comprehensive (loss) income	$	(69,244	)	$	15,948		$	(49,925	)	$	39,485		$	(73,347	)	$	19,319


	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	)

	Net Contract
	Balances
Contract assets at January 1, 2019	$	8,939
Contract liabilities at January 1, 2019		(20,526	)
Net balance at January 1, 2019		(11,587	)
Decrease due to amortization of revenue included in the beginning contract liability balance		2,049
Increase due to cash received, excluding amounts recognized as revenue during the period		(14,029	)
Increase due to revenue recognized during the period but contingent on future performance		1,922
Net balance at March 31, 2019	$	(21,645	)
Contract assets at March 31, 2019	$	10,862
Contract liabilities at March 31, 2019		(32,507	)


	For the Years Ending December 31,										For the Years Ending December 31,
	2018⁽¹⁾		2019		2020		2021		Total		2019(1)		2020		2021		2022		Total
Mobilization and contract preparation revenue	$	9,115	$	9,043	$	81	$	—	$	18,239	$	2,691	$	351	$	510	$	124	$	3,676
Capital modification revenue		6,598		9,170		387		—		16,155		5,651		4,524		—		—		10,175
Demobilization revenue		2,170		—		—		—		2,170
Other deferred revenue		343		681		681		194		1,899

Blended rate revenue												—		11,118		11,427		—		22,545
Total	$	18,226	$	18,894	$	1,149	$	194	$	38,463	$	8,342	$	15,993	$	11,937	$	124	$	36,396


	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. Our Level 1 assets at ~~June 30,~~March 31, 2019 consisted of cash held in money market funds of $109.1 million and investments in U.S. Treasury bills of $249.9 million. Our Level 1 assets at December 31, 2018 consisted of cash held in money market funds of ~~$114.0 million, time deposits of $20.9~~$135.8 million and investments in U.S. Treasury bills of ~~$274.7~~$299.8 million. ~~Our Level 1 assets at December 31, 2017 consisted of cash held in money market funds of $337.1 million and time deposits of $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 or liabilities as of ~~June 30, 2018~~March 31, 2019 or December 31, ~~2017.~~2018.


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~~We had no Level 3 assets ~~at June 30, 2018 and~~as of March 31, 2019 or December 31, ~~2017 consisted of nonrecurring measurements of certain of our drilling rigs for which we recorded impairment losses during 2018 and 2017.~~2018.


	June 30, 2018
	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Assets at Fair Value		Total Losses for Period Ended⁽¹⁾
Recurring fair value measurements:
Assets:
Short-term investments	$	409,616	$	—	$	—	$	409,616

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

	March 31, 2019
	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Assets at Fair Value
Recurring fair value measurements:
Short-term investments	$	359,027	$	—	$	—	$	359,027

	December 31, 2018
	Fair Value Measurements Using
	Level 1		Level 2		Level 3			Assets at Fair Value
Recurring fair value measurements:
Short-term investments	$	435,671	$	—	$	—	��	$	435,671


	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, 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,
	2018 ⁽¹⁾			2019			2020			2021-2022
Rig Days Committed⁽²⁾		59	%		50	%		34	%		9	%


			For the Years Ending December 31,
	Total		2018		2019
Other Commercial Commitments
Performance bonds	$	1,000	$	—	$	1,000
Tax bond		5,326		5,326		—
Bid bond		3,200		3,200		—
Other		1,677		810		867

Total obligations	$	11,203	$	9,336	$	1,867

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