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

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

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

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

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. 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 ~~October 26, 2017~~May 6, 2024 Common stock, ~~$0.01~~$0.0001 par value per share ~~137,227,782 shares~~102,481,240 shares.


	September 30,			December 31,			March 31,			December 31,
	2017			2016			2024			2023
ASSETS
Current assets:
Current assets:
Cash and cash equivalents	$	276,686		$	156,233		$	162,409		$	124,457
Accounts receivable, net of allowance for bad debts		271,390			247,028
Restricted cash								6,832			14,231
Accounts receivable								225,654			260,124
Less: allowance for credit losses								(5,731	)		(5,801	)
Accounts receivable, net								219,923			254,323
Prepaid expenses and other current assets		97,803			102,146			57,402			63,412
Assets held for sale		2,598			400

Asset held for sale								1,000			1,000
Total current assets		648,477			505,807			447,566			457,423
Drilling and other property and equipment, net of accumulated depreciation		5,432,689			5,726,935
Drilling and other property and equipment, net of
accumulated depreciation								1,153,040			1,156,368
Other assets		117,062			139,135			89,488			98,762

Total assets	$	6,198,228		$	6,371,877		$	1,690,094		$	1,712,553

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current liabilities:
Accounts payable	$	33,301		$	30,242		$	40,630		$	42,037
Accrued liabilities		140,233			182,159			185,132			203,336
Taxes payable		7,436			23,898			33,296			34,817
Short-term borrowings		—			104,200

Current finance lease liabilities								16,286			15,960
Total current liabilities		180,970			340,499			275,344			296,150
Long-term debt		1,971,852			1,980,884			534,009			533,514
Noncurrent finance lease liabilities								108,537			113,201
Deferred tax liability		124,929			197,011			15,472			10,966
Other liabilities		115,715			103,349			97,421			113,871

Commitments and contingencies (Note 7)
Total liabilities		2,393,466			2,621,743			1,030,783			1,067,702

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; 144,084,644 shares issued and 137,227,309 shares outstanding at September 30, 2017; 143,997,757 shares issued and 137,169,663 shares outstanding at December 31, 2016)		1,441			1,440
Stockholders’ equity:
Preferred stock (par value $0.0001, 50,000 shares authorized, none issued and outstanding at March 31, 2024 and December 31, 2023)								—			—
Common stock (par value $0.0001, 750,000 shares authorized; 103,399 shares issued and 102,479 shares outstanding at March 31, 2024 and 103,189 shares issued and 102,322 shares outstanding at December 31, 2023)								10			10
Additionalpaid-in capital		2,009,953			2,004,514			982,098			978,575
Retained earnings		1,996,438			1,946,765
Accumulated other comprehensive (loss) gain		(3	)		1
Treasury stock, at cost (6,857,335 and 6,828,094 shares of common stock at September 30, 2017 and December 31, 2016, respectively)		(203,067	)		(202,586	)

Treasury stock								(9,154	)		(8,493	)
Accumulated deficit								(313,649	)		(325,261	)
Accumulated other comprehensive income								6			20
Total stockholders’ equity		3,804,762			3,750,134			659,311			644,851

Total liabilities and stockholders’ equity	$	6,198,228		$	6,371,877		$	1,690,094		$	1,712,553

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,						Three Months Ended March 31,
	2017			2016			2017			2016			2024			2023
Revenues:
Contract drilling	$	357,683		$	339,636		$	1,113,410		$	1,140,568		$	258,770		$	214,383
Revenues related to reimbursable expenses		8,340			9,542			26,128			67,900			15,840			17,638

Total revenues		366,023			349,178			1,139,538			1,208,468			274,610			232,021

Operating expenses:
Contract drilling, excluding depreciation		198,072			186,654			597,812			597,831			184,205			173,490
Reimbursable expenses		8,220			7,965			25,488			51,283			15,266			17,213
Depreciation		83,281			86,473			262,492			295,729			31,354			27,906
General and administrative		17,806			15,237			54,299			48,774			18,576			19,585
Impairment of assets		—			—			71,268			678,145
Loss (gain) on disposition of assets		63			(1,222	)		(2,085	)		(2,265	)		3,396			(1,213	)

Total operating expenses		307,442			295,107			1,009,274			1,669,497			252,797			236,981

Operating income (loss)		58,581			54,071			130,264			(461,029	)		21,813			(4,960	)

Other income (expense):
Interest income		776			150			1,347			592			1,774			7
Interest expense, net of amounts capitalized		(28,562	)		(19,032	)		(83,409	)		(68,704	)		(15,346	)		(12,040	)
Loss on extinguishment of senior notes		(35,366	)		—			(35,366	)		—
Foreign currency transaction loss		(677	)		(712	)		(517	)		(7,833	)
Foreign currency transaction gain (loss)														231			(1,271	)
Other, net		1,447			269			1,322			(11,199	)		(71	)		(152	)

(Loss) income before income tax benefit (expense)		(3,801	)		34,746			13,641			(548,173	)
Income tax benefit (expense)		14,600			(20,819	)		36,646			59,588

Net income (loss)	$	10,799		$	13,927		$	50,287		$	(488,585	)

Earnings (loss) per share, Basic and Diluted	$	0.08		$	0.10		$	0.37		$	(3.56	)

Weighted-average shares outstanding:
Shares of common stock		137,227			137,170			137,208			137,167
Dilutive potential shares of common stock		14			84			29			—

Total weighted-average shares outstanding		137,241			137,254			137,237			137,167

Income (loss) before income tax benefit														8,401			(18,416	)
Income tax benefit														3,211			25,645
Net income													$	11,612		$	7,229
Earnings per share
Basic													$	0.11		$	0.07
Diluted													$	0.11		$	0.07
Weighted-average shares outstanding
Basic														102,440			101,331
Diluted														104,740			103,936

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

1. General Information

The unaudited condensed consolidated financial statements of Diamond Offshore Drilling, Inc. and subsidiaries, which we refer to as “Diamond Offshore,” “Company,” “we,” “us” or “our,” should be read in conjunction with our Annual Report on Form10-K for the year ended December 31, ~~2016 (FileNo. 1-13926).~~2023.

~~As of October 26, 2017, Loews Corporation owned approximately 53% of the outstanding shares of our common stock.~~

Interim Financial Information

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles ~~in the U.S., or GAAP,~~(or GAAP) for interim financial information and with the instructions to Form10-Q and Article 10 of RegulationS-X of the Securities and Exchange Commission. Accordingly, pursuant to such rules and regulations, they do not include all disclosures required by GAAP for ~~complete~~annual financial statements. The condensed consolidated financial information has not been audited but, in the opinion of management, includes all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of Diamond Offshore’s condensed consolidated balance sheets, statements of operations, statements of comprehensive income, 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.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.

Restricted Cash

~~Drilling~~We maintain a restricted cash bank account which is subject to restrictions pursuant to a management services agreement with an offshore drilling company. See Note 2 “Revenue from Contracts with Customers.”

We classify such restricted cash accounts in current assets if the restrictions are expected to expire or otherwise be resolved within one year or if such funds are considered to offset current liabilities. At March 31, 2024 and ~~Other Property and Equipment~~

We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income currently while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset are capitalized. During the nine-month period ended September 30, 2017 and the year ended December 31, ~~2016, we capitalized $33.7~~2023, our restricted cash was considered to be current and was recorded in “Restricted cash” in our unaudited Condensed Consolidated Balance Sheets.

Asset Held for Sale

We reported the $1.0 million ~~and $177.6 million, respectively, in replacements and betterments of our drilling fleet. See Note 6.~~

~~Impairment of Long-Lived Assets~~

We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, a decision to retire, scrap or cold stack a rig, contracted backlog of less than one year for a rig, or excess spending over budget on a newbuild construction project or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

~~dayrate by rig;~~

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

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

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

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

~~salvage value for each rig; and~~

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

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

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

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

~~Capitalized Interest~~

We capitalize interest cost for rig construction or upgrades, as well as other qualifying projects. A reconciliation of our total interest cost to “Interest expense, net of amounts capitalized” as reported in ourunaudited Condensed Consolidated ~~Statements~~Balance Sheets at March 31, 2024. The rig was sold in April 2024 for aggregate proceeds of ~~Operations is as follows:~~approximately $7.5 million.

Accounting Principles Not Yet Adopted

   Three Months Ended
September 30,    Nine Months Ended
September 30,
   2017    2016    2017    2016
   (In thousands)
Total interest cost, including amortization of debt issuance costs
   $ 28,590    $ 27,016    $ 83,440    $ 83,888
Capitalized interest
   (28 )    (7,984 )    (31 )    (15,184 )








Total interest expense as reported
   $ 28,562    $ 19,032    $ 83,409    $ 68,704

~~Stock-Based Compensation~~

In ~~March 2016,~~ December 2023, the Financial Accounting Standards Board ~~or FASB,~~(or FASB) issued Accounting Standards Update or(or ASU) No. 2023-09, Income Tax (Topic 740): Improvements to Income Tax Disclosures (or ASU~~No. 2016-09,~~~~Compensation - Stock Compensation (Topic 718)~~~~, or~~ 2023-09). ASU~~2016-09.~~ ~~ASU2016-09~~ 2023-09 requires ~~that all excess tax benefits and tax deficiencies be recognized~~business entities on an annual basis to (i) disclose specific categories in the ~~income statement as discrete tax~~rate reconciliation and (ii) provide additional information for reconciling items ~~when share-based awards vest or are settled.~~that meet certain quantitative thresholds. The update also clarifies the statement of cash flows presentation for certain components of share-based awards and provides for a policy election to either estimate the number of awards expected to vest or account for forfeitures when they occur. ASU~~2016-09~~new guidance is effective for public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. We are in the process of evaluating the impact of adopting this new guidance on our consolidated financial statement disclosures.

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (or ASU 2023-07). ASU 2023-07 modifies the disclosure and presentation requirements of reportable segments and requires the disclosure of significant segment expenses that are regularly

provided to the chief operating decision maker and included within each reported measure of segment profit and loss. In addition, the new guidance enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and contains other disclosure requirements. ASU 2023-07 is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, ~~2016 and was adopted by us on January 1, 2017.~~

The guidance requiring (i) excess tax benefits to be recorded in the condensed consolidated statement of operations, (ii) exclusion of excess tax benefits from the computation of assumed proceeds under the treasury stock method when calculating earnings per share, and (iii) presentation of excess tax benefits as an operating activity on the statement of cash flows, rather than as a financing activity, has been applied prospectively effective January 1, 2017. We have elected to account for forfeitures of share-based awards in the period in which such forfeitures occur

rather than using an estimated forfeiture rate and have adopted this change using a modified retrospective approach, which resulted in a $0.6 million reduction in opening retained earnings. The impact to our Condensed Consolidated Balance Sheets is as follows:

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




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

~~Recent Accounting Pronouncements~~

~~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~~2024, with respect to the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. This guidance is effective for interim and annual reporting periods beginning after December 15, 2017. We are currently evaluating our historical intra-group transactions for possible impact under the provisions of ASU~~2016-16.~~ ~~The guidance in ASU2016-16~~ will be applied effective January 1, 2018 using the modified retrospective approach whereby we will record the cumulative effect of applying the new standard as an adjustment to opening retained earnings with an offset to a deferred income tax liability.

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

~~In February 2016, the FASB issued ASUNo. 2016-02,~~~~Leases (Topic 842)~~~~, or ASU2016-02,~~ ~~which requires an entity to separate the lease components from thenon-lease~~ ~~components in a contract. The lease components are to be accounted for under ASU2016-02,~~ ~~which, under the guidance, may require recognition of lease assets and lease liabilities by lessees for most leases and derecognition of the leased asset and recognition of a net investment~~ in the ~~lease by the lessor. ASU2016-02~~ ~~also provides for additional disclosure requirements for both lessees and lessors.Non-lease~~ ~~components would be accounted for under ASU2014-09.~~ We have determined that under the new standard, our drilling contracts contain a lease component and therefore we will be required to separately recognize revenues associated with the lease and services components. Additionally, for transactions in which we are considered lessees, we will recognize a lease liability and rightprocess of ~~use asset based on our portfolio of leases as of the time of adoption. The guidance of ASU2016-02~~ ~~is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of ASU2016-02~~ ~~is permitted. We expect to adopt ASU2016-02~~ on January 1, 2019 using the modified retrospective approach. We are currently reviewing the requirements of the accounting standard with regards to arrangements under which we are either the lessor or lessee, to determineevaluating the impact of ~~ASU2016-02~~adopting this new guidance on our ~~financial position, results of operations, cash flows and disclosures contained in the notes to our condensed~~ consolidated financial ~~statements.~~statement disclosures.

~~In May 2014, the FASB issued ASUNo. 2014-09,~~2. Revenue from Contracts with Customers ~~(Topic 606)~~~~, or ASU2014-09.~~ ~~The new standard supersedes the industry-specific standards that currently exist under GAAP and provides a framework to address revenue recognition issues comprehensively for all~~

Our contracts with customers ~~regardless~~provide for an offshore drilling rig and drilling services on a dayrate contract basis. The integrated services provided under our contracts primarily include (i) provision of ~~industry-specific~~ an offshore drilling rig, the work crew and supplies of equipment and services necessary to operate the rig, (ii) mobilization and demobilization of the rig to and from the drill site and (iii) performance of rig preparation activities and/or transaction-specific fact patterns. Under the new guidance, companies recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchangemodifications required for ~~those goods or services. ASU2014-09~~ ~~provides a five-step analysis of transactions to determine when and how revenue is recognized and requires enhanced disclosures about revenue. In July 2015, the FASB issued ASU2015-14,~~ ~~which deferred the effective date of ASU2014-09.~~ ~~ASU2014-09~~ ~~is now effective for annual reporting periods beginning after December 15, 2017. We plan to adopt~~

each contract.

~~ASU2014-09~~ effective January 1, 2018 using the modified retrospective approach whereby we will record the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018 as an adjustment to opening retained earnings.

~~When applying the new standard, we plan to~~We account for the integrated services provided within our drilling contracts as a single performance obligation ~~composed~~satisfied over time, comprised of a series of distinct time increments in which ~~will be satisfied over time. We will determine the~~we provide drilling services. The total transaction price is recognized for each ~~individual~~drilling contract by estimating both fixed and variable consideration expected to be earned over the ~~term~~contract term.

Revenues Related to Managed Rigs

In 2021, we entered into an arrangement with an offshore drilling company whereby we would provide management and marketing services (or the MMSA) for certain of their rigs. The MMSA provided for (i) a daily fixed fee, based on status of the drilling rig, (ii) marketing fees based on a percentage of the earned dayrate of a drilling contract secured by us on behalf of the rig owner, (iii) a variable management fee and (iv) reimbursement of direct cost incurred. The fixed and variable fees were recognized in “Contract drilling” revenue in our unaudited Condensed Consolidated Statements of Operations. Revenue related to the reimbursement of expenses incurred and billed to the rig owner were recorded as “Revenues related to reimbursable expenses” in our unaudited Condensed Consolidated Statements of Operations.

We may enter into certain drilling contracts directly with a customer. We are considered principal or agent of these transactions and recognize revenue under the terms of the contract. ~~Consideration~~Such amounts are reported as “Contract drilling” revenue in our unaudited Condensed Consolidated Statements of Operations. In addition, we charter the related drilling rig from the rig owner to satisfy our performance obligation under the contract. We have determined that ~~does not relate~~the arrangement to ~~a distinct good or service, such~~charter the rig is an operating lease, and the related charter fee has been reported as ~~mobilization, demobilization,~~lease expense within "Contract drilling, excluding depreciation" in our unaudited Condensed Consolidated Statements of Operations.

The marketing arrangements for each of the managed rigs, the West Auriga and the West Vela, were terminated in 2023. Additionally, the management and charter agreements for the West Auriga were terminated in the first quarter of 2024, and the rig was returned to its owner at the end of February 2024. We also received notice of termination of the management agreement forthe West Vela in April 2024, which will become effective after 90 days. The termination of the management agreement will have no effect on the bareboat charter agreement for the West Vela, which provides that it will continue in accordance with its terms until the completion of the rig’s existing drilling contract and any option periods.

Contract Balances

The following table provides information about receivables, contract assets and contract ~~preparation revenue, will be allocated across the single performance obligation~~liabilities related to our contracts with customers (in thousands):


	March 31,			December 31,
	2024			2023
Trade receivables	$	206,830		$	253,367
Current contract assets (1)		2,565			2,575
Current contract liabilities (deferred revenue) (1)		(17,833	)		(12,634	)
Noncurrent contract liabilities (deferred revenue) (1)		(3,613	)		(3,947	)

(1)

Contract assets and ~~recognized ratably over the term of the contract. All other components of consideration within~~contract liabilities may reflect balances which have been netted together on a contract ~~including~~basis. Net current contract asset and liability balances are included in “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, and net noncurrent contract liability balances are included in “Other liabilities” in our unaudited Condensed Consolidated Balance Sheets.

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


	Contract			Contract
	Assets			Liabilities
Balance as of January 1, 2024	$	2,575		$	(16,581	)
Decrease due to amortization of revenue included in the beginning contract liability balance		—			3,185
Increase due to cash received, excluding amounts recognized as revenue during the period		—			(8,050	)
Increase due to revenue recognized during the period but contingent on future performance		391			—
Decrease due to transfer to receivables during the period		(323	)		—
Adjustments		(78	)		—
Balance as of March 31, 2024	$	2,565		$	(21,446	)

Transaction Price Allocated to Remaining Performance Obligations

The following table reflects revenue ~~will continue~~expected to be recognized in the ~~period when the services are performed. We expect our revenue recognition under ASU2014-09~~ to differ from our current revenue recognition pattern only as it relates to demobilization revenue. Such revenue, which is recognized upon completion of a contract under current GAAP, will be estimated at contract inception and recognized over the term of the contract under the new guidance. Additionally, we expect that the cumulative effect adjustment to opening retained earnings required by the modified retrospective adoption approach will not be significant as it will primarily consist of the impact of the timing differencefuture related to ~~recognition~~unsatisfied performance obligations as of ~~demobilization~~March 31, 2024 (in thousands):


	For the Year Ending December 31,
	2024 (1)			2025			2026			2027			Total
Mobilization and contract preparation revenue	$	(4,317	)	$	(1,365	)	$	(1,337	)	$	(1,271	)	$	(8,290	)
Capital modification revenue		(2,954	)		(142	)		—			—			(3,096	)
Blended rate/other revenue		(10,060	)		—			—			—			(10,060	)
Total	$	(17,331	)	$	(1,507	)	$	(1,337	)	$	(1,271	)	$	(21,446	)

(1)

Represents the nine-month period beginning April 1, 2024.

The revenue included above consists of expected fixed mobilization and upgrade revenue for ~~affected contracts. Not all contracts include a demobilization provision.~~

~~2. Impairment of Assets~~

~~During the third quarter of 2017, we evaluated six drilling rigs with indicators of impairment. Based on our assumptions~~both wholly and analyses, we determined that the carrying values of these rigs were not impaired. If market fundamentals in the offshore oil and gas industry deteriorate further or a market recovery is delayed, we may be required to recognize additional impairment losses in future periods.

~~During the second quarter of 2017, we evaluated seven of our drilling rigs with indicators of impairment. Due to the continued deterioration of market fundamentals in the contract drilling industry,~~partially unsatisfied performance obligations, as well as ~~newly-available market projections,~~expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which ~~indicated that a full market recovery is likely to occur further in the future than had previously~~has been estimated ~~we determined that~~for purposes of allocating across the ~~carrying values~~entire corresponding performance obligations. The actual timing of ~~one ultra-deepwater and one deepwater semisubmersible rig were impaired (we collectively refer to these two rigs as the 2017 Impaired Rigs).~~

~~We estimated the fair value~~recognition of the 2017 Impaired Rigs using an income approach, whereby the fair value of each rig was estimated based on a calculation of the rig’s future net cash flows. As described in Note 1, these calculations utilized significant unobservable inputs, including estimated proceeds thatsuch amounts may ~~be received on ultimate disposition of the rig, and are representative of Level 3 fair value measurements~~vary due to factors outside of our control. We have applied the ~~significant level of estimation involved~~disclosure practical expedient in FASB ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), and ~~lack of transparency as to the inputs used. During the second quarter of 2017, we recorded an impairment loss of $71.3 million~~its related amendments and have excluded estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our ~~2017 Impaired Rigs.~~contracts, including dayrate revenue.

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

3. Supplemental Financial Information

Unaudited CondensedConsolidated Balance Sheets Information

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


	September 30,			December 31,
	2017			2016			March 31,			December 31,
	(In thousands)						2024			2023
Trade receivables	$	265,476		$	236,040		$	206,830		$	253,367
Insurance claim receivable (1)								11,688			—
Value added tax receivables		10,425			14,639			6,167			5,256
Related party receivables		119			149			75			155
Other		829			1,659			894			1,346
								225,654			260,124
		276,849			252,487
Allowance for bad debts		(5,459	)		(5,459	)

Allowance for credit losses (2)								(5,731	)		(5,801	)
Total	$	271,390		$	247,028		$	219,923		$	254,323

(1)

See Note 8 “Ocean GreatWhite Insurance Claim” for a discussion of an insurance claim associated with an equipment incident on one of our rigs.

(2)

The allowance for credit losses at March 31, 2024 and December 31, 2023 represents our estimate of credit losses associated with our “Trade receivables” and “Current contract assets.” See Note 4 “Financial Instruments and Fair Value Disclosures” for a discussion of our concentrations of credit risk and allowance for credit losses.

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


	September 30,		December 31,		March 31,		December 31,
	2017		2016		2024		2023
	(In thousands)
Deferred contract costs					$	15,211	$	20,552
Collateral deposit						11,857		11,857
Prepaid taxes						7,526		10,868
Rig spare parts and supplies	$	30,598	$	25,343		6,981		4,694
Deferred rigstart-up costs		52,544		61,488
Prepaid BOP lease		3,873		3,873
Current contract assets						2,565		2,575
Prepaid insurance		3,808		3,771		2,117		3,437
Prepaid taxes		2,536		2,894
Prepaid rig costs						1,978		3,668
Software maintenance agreements and subscriptions						1,650		1,408
Deferred survey costs						1,386		1,418
Other		4,444		4,777		6,131		2,935

Total	$	97,803	$	102,146	$	57,402	$	63,412

Accrued liabilities consist of the ~~following:~~following (in thousands):


	September 30,		December 31,		March 31,		December 31,
	2017		2016		2024		2023
	(In thousands)
Rig operating expenses	$	35,612	$	33,732
Rig operating costs					$	47,316	$	42,893
Contract advances						33,225		63,618
Payroll and benefits		42,275		45,619		26,260		35,215
Interest payable						24,691		13,013
Deferred revenue		8,911		9,522		17,833		12,634
Personal injury and other claims						6,217		7,391
Current operating lease liability						8,171		8,436
Accrued capital project/upgrade costs		3,338		60,308		8,059		10,766
Interest payable		36,813		18,365
Personal injury and other claims		5,160		6,424
Deposit for equipment sale						5,902		1,977
Shorebase and administrative costs						4,967		5,699
Other		8,124		8,189		2,491		1,694

Total	$	140,233	$	182,159	$	185,132	$	203,336

Unaudited Condensed Consolidated Statements of Cash Flows Information

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


	Three Months Ended March 31,
	2024		2023
Accrued but unpaid capital expenditures at period end	$	8,059	$	11,697
Common stock withheld for payroll tax obligations (1)		661		134
Cash interest payments		—		7,488
Cash income taxes paid, net of (refunds):
Foreign		1,851		1,258
U.S. Federal		130		(8,966	)

   Nine Months Ended
September 30,
   2017    2016
   (In thousands)
Accrued but unpaid capital expenditures at period end
   $ 3,338    $ 65,286
Common stock withheld for payroll tax obligations⁽¹⁾
   481    181
Cash interest payments⁽²⁾
   60,253    53,433
Cash income taxes paid, net of (refunds):

Foreign
   37,884    33,479
State
   94    1

⁽¹⁾

~~Represents the cost of 29,241 shares and 7,923~~

(1)

Represents the cost of 302,833 and 10,946 shares of common stock withheld to satisfy payroll tax obligations incurred as a result of the vesting of restricted stock units in the nine months ended September 30, 2017 and 2016, respectively. These costs are presented as a deduction from stockholders’ equity in “Treasury stock” in our Condensed Consolidated Balance Sheets at September 30, 2017 and 2016.

⁽²⁾

~~Interest payments, net of amounts capitalized, were $60.2 million and $43.6 million for the nine-month periods ended September 30, 2017 and 2016, respectively.~~

~~4. Earnings Per Share~~

~~A reconciliation~~ of the ~~numerators~~vesting of restricted stock and restricted stock units during the ~~denominators of~~three-month periods ended March 31, 2024 and March 31, 2023, respectively, which is presented as a deduction from stockholders’ equity in “Treasury stock” in our ~~basic and dilutedper-share~~ ~~computations is as follows:~~unaudited Condensed Consolidated Balance Sheets.

   Three Months Ended
September 30,    Nine Months Ended
September 30,
   2017    2016    2017    2016
   (In thousands, except per share data)
Net income (loss) – basic and diluted numerator
   $ 10,799    $ 13,927    $ 50,287    $ (488,585 )








Weighted average shares – basic (denominator):
   137,227    137,170    137,208    137,167
Dilutive effect of stock-based awards
   14    84    29    —








Weighted average shares including conversions – diluted (denominator)
   137,241    137,254    137,237    137,167








Earnings (loss) per share:

Basic
   $ 0.08    $ 0.10    $ 0.37    $ (3.56 )








Diluted
   $ 0.08    $ 0.10    $ 0.37    $ (3.56 )

~~The following table sets forth the share effects of stock-based awards excluded from our computations of diluted earnings per share, or EPS, for the periods presented:~~

   Three Months Ended
September 30,    Nine Months Ended
September 30,
   2017    2016    2017    2016
   (In thousands)
Employee and director:

Stock options
   —      6    1    8
Stock appreciation rights
   1,297    1,469    1,330    1,519
Restricted stock units
   1,061    423    977    687

5.4. Financial Instruments and Fair Value Disclosures

Financial instruments that potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including residential mortgage-backed securities. We generally place our excess cash investments in U.S.

government-backed short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.

Concentrations of Credit Risk and Allowance for Credit Losses

Our credit risk ~~with respect to our~~arises primarily from trade ~~accounts receivable are limited primarily due to the entities comprising our customer base. Since the~~receivables. The market for our services is the offshore oil and gas industry, ~~this~~and our customer base ~~has consisted~~consists primarily of major and independent oil and gas companies, ~~and~~as well as government-owned oil companies. ~~Based on our current customer base and the geographic areas in which~~At March 31, 2024, we ~~operate, we do not believe~~believed that we ~~have any~~had potentially significant concentrations of credit risk ~~at September 30, 2017.~~due to the number of rigs we had contracted and our limited number of customers, as some of our customers have contracted for multiple rigs.

In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain, ~~to us,~~ we perform a credit review on that ~~company.~~customer, including a review of its credit ratings and financial statements. Based on ~~that analysis,~~our credit review, we may require that the customer ~~present~~have a bank issue a letter of credit on its behalf, prepay for the services in advance or provide other credit enhancements. We ~~record~~currently have one customer for which prepayments are required and full payment is due prior to commencement of the contract in the second half of 2024. At March 31, 2024, no amounts were owed by this customer.

Pursuant to FASB ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and its related amendments (or ASU 2016-13), we have reviewed our historical credit loss experience over a ~~provision for bad debts~~look-back period of ten years, which we deem to be representative of both up-turns and down-cycles in the offshore drilling industry. Based on this review, we developed a~~case-by-case~~ ~~basis when facts~~ credit loss factor using a weighted-average ratio of our actual credit losses to revenues during the look-back period. We also considered current and ~~circumstances indicate~~future anticipated economic conditions in determining our credit loss factor, including crude oil prices and liquidity of credit markets. In applying the requirements of ASU 2016-13 and its related amendments (or collectively, CECL), we determined that ~~a customer receivable may not~~it would be ~~collectible and, historically, losses on~~appropriate to segregate our trade receivables into three credit loss risk pools based on customer credit ratings, each of which represents a tier of increasing credit risk. We calculated a credit loss factor based on historical loss rate information and applied a multiple of our credit loss factor to each of these risk pools, considering the impact of current and future economic information and the level of risk associated with these pools, to calculate our current estimate of credit losses. Trade receivables that are fully covered by allowances for credit losses are excluded from these risk pools for purposes of calculating our current estimate of credit losses.

At March 31, 2024, $8.5 million in trade receivables were considered past due by 30 days or more, of which $5.4 million have been ~~infrequent occurrences.~~fully reserved. The remaining $3.1 million were less than a year past due and considered collectible. For purposes of calculating our current estimate of credit losses at March 31, 2024 and December 31, 2023, all trade receivables, except for those fully reserved, were deemed to be in a single risk pool based on their credit ratings at each respective period. Our total allowance for credit losses was $5.7 million and $5.8 million at March 31, 2024 and December 31, 2023, respectively, including $0.3 million for each period related to our current estimate of credit losses

under CECL. See Note 3 “Supplemental Financial Information — Unaudited Condensed Consolidated Balance Sheets Information.”

Fair Values

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

There are three levels of inputs that may be used to measure fair value:


Level 1		Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds and U.S. Treasury bills and notes. Our Level 1 assets at September 30, 2017 consisted of cash held in money market funds of $242.2 million and time deposits of $20.6 million. Our Level 1 assets at December 31, 2016 consisted of cash held in money market funds of $125.7 million and time deposits of $20.6 million.

Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. ~~Level 2 assets and liabilities may include residential mortgage-backed securities, corporate bonds purchased in a private placement offering andover-the-counter~~ foreign currency forward exchange contracts. Our Level 2 assets at September 30, 2017 and December 31, 2016 consisted solely of residential mortgage-backed securities, which were valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. The inputs used in our valuation are obtained from a Bloomberg curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected floating rate cash flows can be calculated. The valuation techniques underlying the models are widely accepted in the financial services industry and do not involve significant judgment.

Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. Our Level 3 assets at September 30, 2017 and December 31, 2016 consisted of nonrecurring measurements of certain of our drilling rigs and associated spare parts and supplies for which we recorded impairment losses in the second quarter of 2017 and during 2016.

Market conditions could cause an instrument to be reclassified among Levels 1, 2 and 3. Our policy regarding fair value measurements of financial instruments transferred into and out of levels is to reflect the transfers as having occurred at the beginning of the reporting period. There were no transfers between fair value levels during the nine-month period ended September 30, 2017 or the year ended December 31, 2016.

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. In addition, certain assets and liabilities may be recorded at fair value on a nonrecurring basis. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. We recorded impairment charges related to certain of our drilling rigs and related rig spare parts and supplies, which were measured at fair value on a nonrecurring basis, during each of the nine-month periods ended September 30, 2017 and 2016, of $71.3 million and $678.1 million, respectively.

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

   September 30, 2017
   Fair Value Measurements Using
   Level 1    Level 2    Level 3    Assets at
Fair Value    Total Losses
for Nine
Months
Ended
   (In thousands)
Recurring fair value measurements:

Assets:

Short-term investments
   $ 262,887    $ —      $ —      $ 262,887
Mortgage-backed securities
   —      4    —      4









Total assets
   $ 262,887    $ 4    $ —      $ 262,891









Nonrecurring fair value measurements:

Assets:

Impaired assets⁽¹⁾
   $ —      $ —      $ 2,000    $ 2,000    $ 71,268


	March 31, 2024
	Fair Value Measurements Using
	Level 1			Level 2		Level 3		Assets (Liabilities) at Fair Value			Total Losses for Three Months Ended (2)
Recurring fair value measurements:
Short-term investments (1)	$	63,880		$	—	$	—	$	63,880		$	—
Liability-classified Director restricted stock units (2)	$	(1,326	)	$	—	$	—	$	(1,326	)	$	(62	)

~~(1)~~

Represents the total book value as of September 30, 2017 of one ultra-deepwater rig and one deepwater semisubmersible rig, which were written down to their estimated recoverable amounts during the second quarter of 2017 and were reported as “Drilling and other property and equipment, net of accumulated depreciation,” in our Condensed Consolidated Balance Sheets at September 30, 2017.


	December 31, 2023
	Fair Value Measurements Using
	Level 1			Level 2		Level 3		Assets (Liabilities) at Fair Value			Total Losses for Year Ended (2)
Recurring fair value measurements:
Short-term investments (1)	$	92,308		$	—	$	—	$	92,308		$	—
Liability-classified Director restricted stock units (2)	$	(1,258	)	$	—	$	—	$	(1,258	)	$	(252	)

   December 31, 2016
   Fair Value Measurements Using
   Level 1    Level 2    Level 3    Assets at
Fair Value    Total Losses
for Year
Ended⁽¹⁾
   (In thousands)
Recurring fair value measurements:

Assets:

Short-term investments
   $ 146,360    $ —      $ —      $ 146,360
Mortgage-backed securities
   —      35    —      35









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









Nonrecurring fair value measurements:

Assets:

Impaired assets⁽²⁾
   $ —      $ —      $ 69,153    $ 69,153    $ 678,145

(1)

Represents short-term investments, with original maturities of three months or less, in debt securities classified as available for sale.

(2)

The fair value of restricted stock units was estimated based on the quoted market price of our common stock at the respective balance sheet date. The total loss for the period or year includes an increase in stock

~~(1)~~

Represents impairment losses of $8.1 million and $670.0 million recognized during the year ended December 31, 2016 related to our rig spare parts and supplies and certain impaired rigs, respectively.

~~(2)~~

Represents the total book value as of December 31, 2016 for 11 drilling rigs ($45.5 million) and for rig spare parts and supplies ($23.6 million), which were previously written down to their estimated recoverable amounts. Of the total fair value, $23.6 million, $0.4 million and $45.1 million were reported as “Prepaid expenses and other current assets,” “Assets held for sale” and “Drilling and other property and equipment, net of accumulated depreciation,” respectively, in our Condensed Consolidated Balance Sheets at December 31, 2016.

compensation expense due to the “marking-to-market” of liability-classified restricted stock units granted to our non-employee directors on a recurring basis.

We believe that the carrying amounts of our other financial assets and liabilities (excluding our long-term debt), which are not measured at fair value in our unaudited Condensed Consolidated Balance Sheets, approximate fair value based on the following assumptions:

•

Cash and cash equivalents and restricted cash – The carrying amounts approximate fair value because of the short maturity of these instruments.

•

Accounts receivable and accounts payable – The carrying amounts approximate fair value based on the nature of the instruments.

•

~~Cash and cash equivalents~~ ~~— The carrying amounts approximate fair value because of the short maturity of these instruments.~~

•

~~Accounts receivable and accounts payable~~ ~~— The carrying amounts approximate fair value based on the nature of the instruments.~~

•

~~Short-term borrowings~~ ~~— The carrying amounts approximate fair value because of the short term of these instruments.~~

~~We consider our senior notes to be Level 2 liabilities~~Our long-term debt is not measured at fair value on a recurring basis; however, under the GAAP fair value hierarchy, ~~and, accordingly, the~~such indebtedness would be considered Level 2 liabilities. The fair value of ~~our senior notes~~the instrument was derived using ~~a third-party pricing service~~valuation specialists at ~~September 30, 2017~~March 31, 2024 and December 31, 2016. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market for these instruments occurring generally within a~~10-day~~ ~~period of the report date.~~ 2023.

Fair values and related carrying values of our ~~senior notes~~Second Lien Notes (as defined below in Note 6 “Long-Term Debt”) are shown ~~below.~~below (in millions).

   September 30, 2017    December 31, 2016
   Fair Value    Carrying Value    Fair Value    Carrying Value
   (In millions)
5.875% Senior Notes due 2019
   $ —      $ —      $ 518.6    $ 499.8
3.45% Senior Notes due 2023
   225.0    249.3    215.0    249.3
7.875% Senior Notes due 2025
   528.8    496.4    —      —
5.70% Senior Notes due 2039
   411.3    497.1    392.5    497.1
4.875% Senior Notes due 2043
   562.5    748.9    532.7    748.9


	March 31, 2024				December 31, 2023
	Fair Value		Carrying Value		Fair Value		Carrying Value
Second Lien Notes	$	580.7	$	550.0	$	562.6	$	550.0

We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. ~~Considerable judgment is required~~Certain inputs and value drivers are observed and obtained in active markets from similar assets or liabilities while developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange.

6. Long-Term Debt

At March 31, 2024 and December 31, 2023, the carrying value of our long-term debt, net of unamortized discount, premium and debt issuance costs, was comprised as follows (in thousands):


	March 31,		December 31,
	2024		2023
$550 Million Senior Secured Second Lien Notes due 2030	$	534,009	$	533,514

Second Lien Notes

   September 30,    December 31,
   2017    2016
   (In thousands)
Drilling rigs and equipment
   $ 8,279,491    $ 8,950,385
Land and buildings
   63,309    64,449
Office equipment and other
   78,909    73,108




Cost
   8,421,709    9,087,942
Less: accumulated depreciation
   (2,989,020 )    (3,361,007 )




Drilling and other property and equipment, net
   $ 5,432,689    $ 5,726,935

~~During~~On September 21, 2023, Diamond Foreign Asset Company and Diamond Finance, LLC (collectively referred to as the ~~nine-month period ended September 30, 2017, we recognized an aggregate impairment loss of $71.3 million related to the 2017 Impaired Rigs. See Notes 1 and 2.~~

~~7. Senior Notes~~

~~In August 2017, we~~Issuers) issued ~~$500.0~~$550.0 million aggregate principal amount of ~~unsecured 7.875% senior notes~~8.5% Senior Secured Second Lien Notes due ~~2025, or 2025 Notes, and received net proceeds of $489.1 million after deducting underwriting discounts, commissions and estimated expenses. The 2025 Notes bear~~October 2030 (or the Second Lien Notes) with interest ~~at 7.875% per year and mature on August 15, 2025. Interest on the 2025 Notes is~~ payable ~~semiannually~~semi-annually in arrears on ~~February 15~~April 1 and ~~August 15~~October 1 of

each year, beginning ~~February 15, 2018. We used the net proceeds from the 2025 Notes, together with cash~~ on ~~hand, to fund the redemption of our 5.875% senior notes due 2019, or 2019 Notes.~~

April 1, 2024. The ~~2025~~Second Lien Notes are ~~unsecured obligations of~~fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by Diamond Offshore Drilling, Inc., (or DODI) and ~~rank equally in right of payment to all~~each of its existing restricted subsidiaries (other than the Issuers) and by certain of DODI’s future ~~senior indebtedness,~~restricted subsidiaries (other than the Issuers).

The Second Lien Notes obligate DODI and ~~are structurally subordinated~~its specified subsidiaries to comply with an indenture dated as of September 21, 2023 (or the Indenture) entered into by the Issuers, DODI and certain of its subsidiaries named therein and HSBC Bank USA, National Association. The Indenture contains covenants that, among other things, restrict DODI’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue certain preferred stock; (ii) incur or create liens; (iii) make certain dividends, distributions, investments and other restricted payments; (iv) sell or otherwise dispose of certain assets; (v) engage in certain transactions with affiliates; and (vi) merge, consolidate, amalgamate or sell, transfer, lease or otherwise dispose of all ~~existing and future obligations of our subsidiaries. We have the right to redeem some~~ or substantially all of ~~the 2025~~DODI’s assets. These covenants are subject to important exceptions and qualifications.

The Second Lien Notes were valued at ~~any time or from time to time, on~~par at ~~least 15 days but not more than 60 days prior written notice, at the applicable redemption price~~

~~specified in the governing indenture, plus accrued~~issuance and unpaid interest to, but excluding, the date of redemption. The 2025 Notes contain customary covenants including limitations on liens, mergers, consolidations and certain sales of assets and on entering into sale and lease-back transactions covering a drilling rig or drillship, as specified in the governing indenture.

In August 2017, we redeemed all of our outstanding 2019 Notes for a redemption price of $543.0 million in the aggregate, including accrued and unpaid interest to the date of redemption. We accounted for the redemption as an extinguishment of debt and have reported a corresponding loss of $35.4 million in our Condensed Consolidated Statements of Operations for the three-month and nine-month periods ended September 30, 2017.

~~At September 30, 2017, our outstanding senior notes~~ were ~~comprised of the following debt issues:~~

   Principal       Semiannual
   Amount       Interest Rate Interest Payment
Debt Issue
   (In millions)    Maturity Date    Coupon Effective Dates
3.45% Senior Notes due 2023
   $ 250.0    November 1, 2023    3.45 % 3.50 % May 1 and November 1
7.875% Senior Notes due 2025
   $ 500.0    August 15, 2025    7.875 % 8.00 % February 15 and August 15
5.70% Senior Notes due 2039
   $ 500.0    October 15, 2039    5.70 % 5.75 % April 15 and October 15
4.875% Senior Notes due 2043
   $ 750.0    November 1, 2043    4.875 % 4.89 % May 1 and November 1

~~At September 30, 2017, the carrying value of our outstanding senior notes,~~presented net of unamortized ~~discount and~~ debt issuance costs of $16.0 million and $16.5 million, at March 31, 2024 and December 31, 2023, respectively. At March 31, 2024, the effective interest rate on the Second Lien Notes was ~~as follows:~~9.10%.

Revolving Credit Agreement

   September 30,
2017
   (In thousands)
3.45% Senior Notes due 2023
   $ 248,090
7.875% Senior Notes due 2025
   489,200
5.70% Senior Notes due 2039
   492,930
4.875% Senior Notes due 2043
   741,632


Total senior notes, net
   $ 1,971,852

8.Our revolving credit agreement provides for a $300.0 million senior secured revolving credit facility (or RCF), which will mature on April 22, 2026. Borrowings under the RCF may be used to finance capital expenditures, pay fees, commissions and expenses in connection with the loan transactions, and for working capital and other general corporate purposes. Availability of borrowings under the RCF is subject to the satisfaction of certain conditions, including restrictions on borrowings if, after giving effect to any such borrowings and the application of the proceeds thereof, (i) the aggregate amount of Available Cash (as defined in the RCF) would exceed $125.0 million, (ii) the RCF Collateral Coverage Ratio (as defined in the RCF) would be less than 2.00 to 1.00 or (iii) the Total Collateral Coverage Ratio (as defined in the RCF) would be less than 1.30 to 1.00.

At March 31, 2024 and May 6, 2024, we had no borrowings outstanding under the RCF and had utilized $1.9 million of available borrowing capacity for the issuance of a letter of credit. The outstanding letter of credit will expire on maturity in May 2024, unless replaced. As of May 6, 2024, approximately $298.1 million was available for borrowings under the RCF subject to its terms and conditions.

There is no capacity for the issuance of new letters of credit under the RCF, but the RCF permits us to obtain up to $50.0 million in letters of credit outside the RCF. We have obtained a separate $25.0 million letter of credit facility; however, letters of credit thereunder must be cash collateralized.

At March 31, 2024, we were in compliance with all covenants under the Second Lien Notes and the RCF.

7. Commitments and Contingencies

Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a liability for the amount of the estimated loss at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims.

~~Patent Litigation~~. Non-Income Tax and Related Claims. We have ~~been~~received assessments related to, or otherwise have exposure to, non-income tax items such as sales-and-use tax, value-added tax, ad valorem tax, custom duties, and other similar taxes in discussions with Transocean Ltd., or Transocean, an offshore drilling contractor, with regard to United States patents previously owned by Transocean or its affiliates or employees pertaining to certain dual-activity drilling operations. On August 30, 2017, an affiliate of Transocean filed a lawsuit against us and one of our subsidiaries in the United States District Court for the Southern District of Texas, allegingvarious taxing jurisdictions. We have determined that we ~~infringed~~have a probable loss for certain of these taxes and the ~~Transocean patents by~~related penalties and interest and, accordingly, have recorded a $12.4 million and $12.7 million liability at March 31, 2024 and December 31, 2023, respectively, in “Other liabilities” in our unaudited Condensed Consolidated Balance Sheets. We intend to defend these matters vigorously; however, the ~~unauthorized sale, offer~~ultimate outcome of these assessments and exposures could result in additional taxes, interest and penalties for ~~sale, and importation and use of four of our drilling rigs (~~~~Ocean Blackhawk~~,~~Ocean BlackHornet~~,~~Ocean BlackRhino~~ ~~and~~~~Ocean BlackLion~~~~). In its lawsuit, Transocean’s affiliate is seeking unspecified monetary damages. The Transocean patents,~~ which ~~expired in May 2016, do not apply to drilling activities outside~~ the United States or to activities that occurred after the expiration of the patents. We are unable to estimate our potential exposure, if any, to this lawsuit at this time but do not believe that our ultimate liability, if any, resulting from this litigation willfully assessed amounts would have a material adverse effect on our ~~consolidated~~ financial condition, results of operations orand cash flows.

~~Asbestos Litigation~~.We are one of several unrelated defendants in lawsuits filed in Louisiana state courts alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. The manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted in the lawsuits pursuant to the terms of our 1989 asset purchase agreement15

with Diamond M Corporation. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations or cash flows.

Other Litigation.We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business, including a claim by one of our customers in Brazil, Petróleo Brasileiro S.A., or Petrobras, that it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities for our applicable portion of withholding taxes related to Petrobras’ charter agreements with its contractors.business. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of any claim, lawsuit or action cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of any litigation matter. Any claims against us, whether meritorious or not, could cause us to incur significant costs and expenses and require significant amounts of management and operational time and resources. In the opinion of our management, no such pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

~~NPI Arrangement.~~~~We received customer payments measured by a percentage net profits interest under an overriding royalty interest in certain developmentaloil-and-gas~~ producing properties, or NPI, which we believe is a real property interest. Our drilling program related to the NPI was completed in 2011, and the balance of the amounts due to us under the NPI was received in 2013. However, in August 2012, the customer that conveyed the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code. Certain parties (including the debtor) in the bankruptcy proceedings questioned whether our NPI, and certain amounts we received under it after the filing of the bankruptcy, should be included in the debtor’s estate under the bankruptcy proceeding. In 2013, we filed a declaratory judgment action in the bankruptcy court seeking a declaration that our NPI, and payments that we received from it after the filing of the bankruptcy, are not part of the bankruptcy estate. We agreed to a settlement with the company that purchased most of the debtor’s assets (including the debtor’s claims against our NPI) whereby the nature of our NPI will not be challenged by that party and our declaratory judgment action was dismissed. Following the settlement, the bankruptcy was converted to a Chapter 7 liquidation proceeding. Several lienholders who had previously intervened in the declaratory judgment action filed motions in the bankruptcy contending that their liens have priority and seeking disgorgement of $3.25 million of payments made to us after the bankruptcy was filed. We believe that our rights to the payments at issue are superior to these liens, and we filed motions to dismiss the claims. In November 2016, the court dismissed the lienholders’ claims, and the lienholders are appealing the ruling. In addition, the bankruptcy trustee filed counterclaims seeking disgorgement of a total of $30.0 million of~~pre-~~ and post-bankruptcy payments made to us under the original NPI. The bankruptcy court has dismissed all but one of the trustee’s disgorgement claims, which is limited in amount to $17.0 million. In December 2016, the company that purchased most of the debtor’s assets from bankruptcy also filed for bankruptcy. In October 2017, we reached agreement with the trustee to settle the remaining $17.0 million disgorgement claim for an immaterial amount. The settlement agreement has been submitted to the bankruptcy court for approval. We continue to expect the bankruptcy proceedings to be concluded with no further material impact to us.

Personal Injury ~~Claims~~. Claims. Under our current insurance policies, which renewed effective May 1, ~~2017, our deductibles for marine liability insurance coverage~~2024, we generally self-insure $1.0 million to $2.5 million per occurrence, depending on jurisdiction, with respect to personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, which primarily result from Jones Act liability in the U.S. Gulf of Mexico, are $10.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, dependingMexico. Depending on the nature, severity, and frequency of claims that might arise during the policy ~~year. Our deductible for personal injury claims arising due to named windstorms in~~year, if the ~~U.S. Gulf~~aggregate level of ~~Mexico is $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, we may self-insure up to ~~$100.0~~$100.0 million for each subsequent ~~occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.~~occurrence.

The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At ~~September 30, 2017~~March 31, 2024, our estimated liability for personal injury claims was ~~$31.2~~$11.8 million, of which ~~$4.8~~$6.2 million and ~~$26.4~~$5.6 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our unaudited Condensed Consolidated Balance Sheets. At December 31, ~~2016~~2023, our estimated liability for personal injury claims was ~~$32.9~~$14.6 million, of which ~~$6.1~~$7.4 million and ~~$26.8~~$7.2 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our unaudited Condensed

Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

•

the severity of personal injuries claimed;

•

significant changes in the volume of personal injury claims;

•

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

•

inconsistent court decisions; and

•

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

Purchase Obligations. At March 31, 2024, we had no purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.

Services Agreement. In February 2016, we entered into a ten-year agreement with a subsidiary of Baker Hughes Company (formerly named Baker Hughes, a GE company) to provide services with respect to certain blowout preventer and related well control equipment (or Well Control Equipment) on our drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. Future commitments under the contractual services agreements are estimated to be approximately $25.6 million annually. Total future commitments are projected to be $88.1 million in the aggregate over the remaining term of the agreement, including a $37.0 million commitment for the purchase of consumables and capital spare parts owned and controlled by the vendor at the end of the service arrangement.

In addition, we lease Well Control Equipment for our drillships under ten-year finance leases that commenced in 2016 that also include an option to purchase the leased equipment at the end of the respective lease term.

Letters of Credit and Other.~~We were contingently liable as~~As of ~~September 30, 2017~~March 31, 2024, an aggregate of $14.0 million in ~~the amount of $21.3 million under certain performance, tax, supersedeas, court and customs~~ bonds and letters of ~~credit. Agreements relating to~~credit had been issued on our behalf in connection with certain customs, tax assessment and tenant security deposit requirements. Of this amount, approximately ~~$15.6~~$12.1 million had been cash collateralized as of ~~tax, supersedeas, court and customs bonds can require collateral at any time. As~~March 31, 2024. An additional $1.9 million was collateralized by a letter of ~~September 30, 2017, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements~~credit issued under our RCF, which cannot require additional collateral except in events of ~~default.~~ default, or until its maturity in May 2024, if not replaced.

10. Segments and Geographic Area Analysis

~~Although we~~We provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic ~~locations,~~locations. However, 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.~~rigs and other qualitative factors such as (i) the nature of services provided (contract drilling), (ii) similarity in operations (interchangeable rig crews and shared management and marketing, engineering, marine and maintenance support), (iii) similar regulatory environment (depending on customer and/or location) and (iv) similar contractual arrangements with customers.

~~Revenues from contract drilling services by equipment type are listed below.~~

   Three Months Ended
September 30,    Nine Months Ended
September 30,
   2017    2016    2017    2016
   (In thousands)
Floaters:

Ultra-Deepwater
   $ 275,859    $ 217,275    $ 801,859    $ 757,338
Deepwater
   35,634    66,011    170,482    192,319
Mid-Water
   39,616    56,350    124,444    160,716








Total Floaters
   351,109    339,636    1,096,785    1,110,373
Jack-ups
   6,574    —      16,625    30,195








Total contract drilling revenues
   357,683    339,636    1,113,410    1,140,568
Revenues related to reimbursable expenses
   8,340    9,542    26,128    67,900








Total revenues
   $ 366,023    $ 349,178    $ 1,139,538    $ 1,208,468

~~Geographic Areas~~

Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At ~~September 30, 2017,~~March 31, 2024, our active drilling rigs were located offshore ~~in five~~four countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country ~~or areas~~ where the services were ~~performed.~~performed during the periods presented, which may not be indicative of where the rigs are currently located.

The following tables provide information about disaggregated revenue by country (in thousands):

   Three Months Ended
September 30,    Nine Months Ended
September 30,
   2017    2016    2017    2016
   (In thousands)
United States
   $ 171,476    $ 121,895    $ 481,933    $ 414,087
International:

South America
   58,750    105,614    272,929    333,803
Australia/Asia
   80,543    56,688    219,103    169,323
Europe
   48,680    63,117    148,948    253,287
Mexico
   6,574    1,864    16,625    37,968








Total revenues
   $ 366,023    $ 349,178    $ 1,139,538    $ 1,208,468


	Three Months Ended March 31, 2024
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	146,475	$	7,328	$	153,803
United Kingdom		32,568		4,233		36,801
Australia		27,360		2,463		29,823
Brazil		26,570		—		26,570
Senegal		25,797		1,816		27,613
Total	$	258,770	$	15,840	$	274,610


	Three Months Ended March 31, 2023
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	104,581	$	12,557	$	117,138
United Kingdom		17,702		1,060		18,762
Australia		19,309		840		20,149
Brazil		20,660		—		20,660
Senegal		52,131		3,181		55,312
Total	$	214,383	$	17,638	$	232,021

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 and ~~our audited consolidated financial statements (including the notes thereto), Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and~~ Item 1A, “Risk Factors” included in our Annual Report on Form10-K for the year ended December 31, ~~2016.~~2023. References to “Diamond Offshore,” “Company,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We provide contract drilling services to the energy industry around the globe with a fleet of ~~19 offshore drilling~~12 floater rigs ~~excluding five semisubmersible rigs that we plan to retire and scrap in the near future. These retired units, which are currently cold stacked, include the~~~~Ocean Baroness~~,~~Ocean Alliance~~,~~Ocean Vanguard~~,~~Ocean Nomad~~ ~~and~~~~Ocean Princess~~~~. As of the date of this report, our current fleet consists of four~~(four owned drillships, 14seven owned semisubmersibles and one~~jack-up~~ ~~rig. The~~~~Ocean Monarch~~~~, which had been in a shipyard for a survey and contract modifications since~~ managed rig). See “– Market Overview.”

During the first quarter of ~~2017, began operating under~~2024, oil commodity prices remained elevated above their 5-year average, primarily as a result of continued OPEC+ supply restraint, muted production growth in the United States, strong growth in oil demand and expanding manufacturing trends in the United States and China signaling global economic improvements. Oil and natural gas benchmark prices are expected to remain volatile as geopolitical uncertainty resulting from conflicts in Russia/Ukraine and the Middle East may affect supply and demand. Brent crude prices reached the high $80- to low $90-per barrel range in mid-April 2024, which are the highest levels reached since October 2023. This rebound represents an approximate 20% increase since the beginning of the year, according to pricing data published by the U.S. Energy Information Administration. Commodity prices are expected to remain at levels that are supportive of investment in deepwater exploration and development projects. As of mid-April 2024, dated Brent crude oil prices for the remainder of 2024 and 2025 were in the low-to-middle $80-per-barrel range according to industry data.

In the first quarter of ~~three contracts~~2024, growth in ~~Australia late~~offshore upstream capital expenditures continued to be supported by strong cash flows realized by oil and gas companies, continued expectations for growing demand, and breakeven costs well below current oil price forecasts. According to industry reports, analysts expect offshore upstream capital expenditures to increase approximately 3.3% annually, on average, from 2024 to 2027, rising to more than $230 billion by 2027, with exploration growing to approximately 12% of the capital expenditure total.

During the first quarter of 2024, the positive dynamics of increased offshore spending, coupled with the growing trend in long-cycle developments, production capacity expansions and exploration and appraisal activities, continued to drive growth in demand for floating drilling rigs. According to industry reports, on a trailing three-month basis, the volume of floating rig years contracted has grown month over month from November 2023 through February 2024, reaching its highest level since February 2023. According to data from S&P Global, in mid-April 2024 outstanding demand from floating rig tenders was approximately 56 rig years, compared to 42 rig years a year earlier, representing an increase of more than 33%. Most of this demand was concentrated in the ~~second quarter~~deepwater and ultra-deepwater regions of ~~2017.~~ the Gulf of Mexico, Brazil and West Africa, which are areas where we currently operate. The recent improvement in contracting activity has pushed dayrates for ultra-deepwater drilling rigs into the high $400 to low $500 thousand per day range.

This robust dayrate market, combined with anticipated growth in upstream capital spending, continues to drive further increases in rig demand and improves the economics for rig reactivations. However, supply chain constraints and inflationary pressures could limit the pace at which these additional rigs could return to the market, with some analysts estimating the average time for rig reactivations to be approximately 12 to 18 months, with costs approaching $100 million for idle rigs and $350 million for stranded rigs. The current inventory of idle rig capacity has decreased significantly and the owners of this remaining capacity have so far exhibited capital discipline as it relates to reactivation investments; however, the market could be adversely affected by the re-entry of this limited idle capacity.

Despite policy tightening by major central banks and a moderating pace of world economic expansion, inflationary pressures have generally remained elevated in the industry sector, though recent trends indicate possible moderation in some areas. Continued inflation may result in upward pressure on operating expenses for offshore drillers.

In addition to market factors, during the ~~five rigs~~first quarter of 2024, customer capital allocation decisions have continued to affect demand for our services. Customer investment mixes over time, coupled with energy demand and regulatory measures, could adversely impact demand for offshore drilling services in the long term. Notwithstanding this possibility, during the first quarter, global energy demand continued to be ~~scrapped, six~~strong and energy supply growth remained constrained. We expect increased investment in both traditional and renewable sources of ~~our rigs are currently cold stacked, consisting~~energy to be required in the future, some of ~~three ultra-deepwater~~which we expect to be invested in finding and ~~three deepwater semisubmersible rigs.~~ producing hydrocarbons in the offshore segment.

Industry experts continue to expect the world's demand for energy will increase and that hydrocarbons will continue to serve a major role in meeting the world's energy needs for the foreseeable future.

~~At the end of the third quarter of 2017, the spot price for Brent crude oil was $57.54 per barrel and had been fluctuating within a general range of$45-$58~~ ~~per barrel throughout the first nine months of 2017. Thisday-to-day~~ volatility in oil price is attributable to multiple factors, including fluctuations in the current and expected level of global oil inventories and estimates of global oil demand, production cuts by the Organization of the Petroleum Exporting Countries (which have been extended until the end of the first quarter of 2018) and the impact of hurricanes and tropical storms in the U.S. Gulf of Mexico. In addition, some U.S. shale producers have resumed drilling and production activities due to their ability to quickly and more cheaply bring oil reserves to production and therefore benefit from modestly-improved commodity prices. This has prevented crude oil prices from rising through typical supply and demand economics to a more sustainable level for offshore exploration and development. As a result, capital spending for offshore exploration and development continued to decline in 2017, with annual capital spending estimated by some industry analysts to be up to 20% lower than reduced 2016 capital spending levels. If these market estimates are realized, it would represent three consecutive years of decline in offshore spending.

Some industry analysts have predicted that the downturn is leveling off; however, the offshore drilling market has been slow to recover and is not yet at the recovery stage. Customer inquiries and new tenders have increased during 2017, compared to 2016, but are for offshore drilling opportunities in 2018 and beyond. Competition among offshore drillers remains intense as rig supply exceeds demand, despite the cold stacking and retirement or scrapping of over 100 rigs since 2014. Additionally, based on industry data as of the date of this report, more than 30 floater rigs currently remain on order, with scheduled deliveries from 2017 through 2021. The majority of these rigs are not currently contracted for future work, which further increases competition.

Dayrates continue to be depressed and, in some cases, have been negotiated at break-even or below cost levels in order to enable drilling contractors to recover a portion of operating costs for rigs that would otherwise be uncontracted or cold stacked. Discussions with our customers indicate a preference for “hot” rigs rather than the reactivation of cold-stacked rigs. This preference incentivizes drilling contractors to accept lower rates for the sole purpose of maintaining their rigs in an active state and allowing for at least partial cost recovery. Some industry analysts have predicted that demand for drilling rigs in the offshore market will slowly improve, but utilization growth may not be significant enough to impact dayrates for some time.

As a result of the continued pessimistic outlook for the offshore drilling industry in the near term, certain of our customers, as well as those of our competitors, have attempted to renegotiate or terminate existing drilling contracts. Such renegotiations have included requests to lower the contract dayrate, in some cases in exchange for additional contract term, shorten the term on one contracted rig in exchange for additional term on another rig, terminate a contract in exchange for a lump sum payout and many other possibilities. In addition to the potential for renegotiations, some of our drilling contracts permit the customer to terminate the contract early after specified notice periods, usually resulting in a requirement for the customer to pay a contractually specified termination amount, which may not fully compensate us for the loss of the contract. Some of our customers have also utilized such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under circumstances where we believe we are in compliance with the contracts.

Particularly during depressed market conditions, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. When a customer terminates our contract prior to the contract’s scheduled expiration, our contract backlog is also adversely impacted. When we cold stack or expect to scrap a rig, we evaluate the rig for impairment. See “– Contract Drilling Backlog”Backlog”for future commitments of our rigs during ~~2017~~the remainder of 2024 through ~~2020.~~2028.

~~The following table reflects~~We believe that our contract drilling backlog asprovides a useful indicator of ~~October 1, 2017 (based on information available at that time), January 1, 2017 (the date reported in~~ our ~~Annual Report on Form10-K~~ ~~for the year ended December 31, 2016), and October 1, 2016 (the date reported in our Quarterly Report on Form10-Q~~ ~~for the quarter ended September 30, 2016). Contract~~future revenue-earning opportunities. 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. The contract period is based on the number of stated days for fixed-term contracts or an estimated duration (in days) for contracts based on a fixed number of wells. 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~~may be different than the amounts and periods shown in the tables below due to various factors. ~~Utilization~~Our utilization rates, which generally ~~approach~~have been in the range of 92-98% during contracted periods, can be adversely impacted ~~by downtime~~ due to various operating factors including ~~but not limited to,~~unscheduled repairs and maintenance, weather conditions, and ~~unscheduled repairs and maintenance.~~other factors. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. ~~No revenue~~Revenue is generally not earned during periods of downtime for regulatory ~~surveys.~~surveys; however, certain contracts may provide for reduced revenue during the survey period. 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.

~~In August 2016,~~The backlog information presented below does not, nor is it intended to, align with the disclosures regarding revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 2 “Revenue from Contracts with Customers” to our ~~subsidiary~~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 “Revenue from Contracts with Customers” excludes dayrate revenue and reflects expected future revenue for mobilization, demobilization and capital modifications to our rigs, which are related to non-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 April 1, 2024 (based on information available at that time), January 1, 2024 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2023), and April 1, 2023 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2023) (in millions).

The following table reflects the amount of revenue related to our contract drilling backlog by year as of ~~October~~April 1, ~~2017.~~2024 (in millions).

The following table reflects the percentage of rig days per year committed ~~by year~~ as of ~~October~~April 1, ~~2017.~~2024. 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).

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

Regulatory Surveys and Planned Downtime.~~Our operating income is negatively impacted when we~~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~~rigs and an intermediate survey, which is performed every two-and-one-half years, for our North Sea ~~rigs~~rigs. Our operating income is~~two-and-one-half~~ ~~years.~~ negatively impacted when we perform these required regulatory surveys due to planned downtime during the inspection period. Our operating income is also reduced by planned downtime for upgrades, contract preparation and mobilization of rigs; however, in some cases, we may be compensated for all or a portion of this downtime. During the remainder of ~~2017,~~2024, we expect to ~~spend~~incur approximately 60220 days of planned downtime, including approximately (i) 100 days for a shipyard project, as well as mobilization and demobilization activities for the Ocean BlackRhino; (ii) 70 days for the Ocean GreatWhite’s lower marine riser package (or LMRP) repairs; (iii) 25 days for the Ocean Endeavor’s blowout preventer (or BOP) recertification; (iv) 20 days for the Ocean BlackHornet’s special survey and (v) five days for theOcean ~~Patriotafter completion of its current contract. In addition, we expect to spend approximately 35 days in 2018 for contract preparation and the~~Apex’s mobilization ~~of the~~~~Ocean Monarch~~ ~~in connection with a future contract offshore Victoria, Australia.~~activities. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, ~~planned~~repairs, contract preparation, rig mobilizations and other shipyard projects. See “ –— Contract Drilling Backlog.”

Physical Damage and Marine Liability Insurance.Under our primary insurance policies, which renewed effective May 1, 2024, we carry $50.0 million of U.S. Named Windstorm Coverage, as defined by the relevant insurance policy, for physical damage to our property and equipment with a $10.0 million deductible per accident or occurrence. 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.~~in excess of $50.0 million. 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, financial condition, and cash flows. Under our current insurance policy, ~~which renewed effective May 1, 2017,~~ 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~~$10.0 million per occurrence. ~~We do not typically retain~~In addition, we currently carry loss-of-hire insurance ~~policies~~on certain of our owned rigs to cover ~~our rigs.~~a portion of lost cash flow when a rig is damaged, which is a recoverable claim under the physical damage insurance but excludes named windstorms in the U.S. Gulf of Mexico.

In addition, ~~under our current insurance policy, which renewed effective May 1, 2017,~~ we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, collisions, and wreck removals, and generally covering liabilities arising out of or relating to pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore

drilling industry and is appropriate for our business. ~~Our deductibles for~~Under these marine liability ~~coverage related~~policies, we generally self-insure $1.0 million to ~~insurable events~~$2.5 million per occurrence, depending on jurisdiction, but up to $25.0 million for liabilities arising ~~due to~~out of named windstorms in the U.S. Gulf of Mexico is $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, dependingMexico.

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~~year, if the aggregate level of claims ~~not related to named windstorms in the U.S. Gulf of Mexico, are $10.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed~~exceeds certain thresholds, we may self-insure 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.~~occurrence.

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

Our significant accounting policies are discussed in Note 1 “General Information” of our notes to the audited consolidated financial statements included in our Annual Report on Form10-K for the year ended December 31, ~~2016. There were no material changes to these policies during the nine months ended September 30, 2017.~~

~~Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is~~We have elected to present a similarity of economic characteristics due to the nature of the revenue-earning process as it relates to the offshore drilling industry, over the operating lives of our drilling rigs. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with applicable accounting standards on segment reporting. However, for purposes of this discussion and analysiscomparison of our results of operations wefor the current quarter with that of the immediately preceding quarter, as permitted under Item 303(c)(2)(ii) of Regulation S-K. We believe this comparison is more useful in identifying business trends and provides a more meaningful analysis of our business as our results are largely driven by market changes rather than seasonal business activity. We continue to present the required comparison of current year-to-date results with the same period of the prior year.

Our operating results for contract drilling services are dependent on three primary metrics or key performance indicators: revenue-earning (or R-E) days, rig utilization and average daily revenue. We believe that R-E days provide ~~greater detail with respect to~~a comparative measurement of the ~~types~~activity level of ~~rigs in~~ our fleet, ~~to enhance the reader’s understanding~~rig utilization is an indicator of our ~~financial condition, changes in financial condition~~ability to secure work for and ~~results~~the operational efficiency of ~~operations.~~

~~Key~~our fleet and average daily revenue provides a comparative measure for our revenue-earning performance. We utilize these performance indicators ~~by equipment type~~in the review of our business and operating results and believe these are ~~listed below.~~

~~Comparative~~useful metrics for investors to utilize in evaluating our performance. The tables presented below include these three key performance indicators and other comparative data relating to our revenues and operating expenses for the respective periods (in thousands, except days, daily amounts and percentages) for the three-month periods ended March 31, 2024, December 31, 2023 and March 31, 2023.

Results for the Three-Month Periods Ended March 31, 2024, December 31, 2023 and March 31, 2023

Three Months Ended ~~September 30, 2017 and 2016~~March 31, 2024 Compared to Three Months Ended December 31, 2023

~~Operating Income (Loss).~~~~Total operating income for~~Contract Drilling Revenue. Contract drilling revenue decreased $20.9 million during the ~~third quarter of 2017 increased $4.5 million, or 8%,~~three months ended March 31, 2024 compared to the ~~same period of 2016,~~three months ended December 31, 2023, primarily due to incremental contract drilling revenue of $18.0 million, partially offset by higher contract drilling expense of $11.4 million. Comparing the two quarters, contract drilling revenue increased primarily due to an aggregate 192 incremental revenue-earning days for our rigs ($73.8 million), partially offset by lower ~~overall~~ average daily revenue earned ($~~55.8 million). The increase in contract drilling expense during the third quarter of 2017 was primarily the result of incremental operating costs for the~~~~Ocean GreatWhite~~~~($9.3~~9.2 million), ~~which began operating~~combined with a 37-day decrease in R-E days ($11.7 million).

The decrease in average daily revenue during the first quarter of ~~2017, and the~~ ~~Ocean BlackRhino~~ ~~($17.1 million) and~~~~Ocean Scepter~~~~($4.8 million), both of which operated during the third quarter of 2017,~~2024, compared to the ~~third~~fourth quarter of ~~2016 when they did not operate. The increase in total contract drilling expense for our fleet~~2023, was ~~partially offset by a net $19.8 million reduction in other rig operating and overhead costs,~~ primarily due to the ~~cold stacking~~absence of ~~the~~~~Ocean Victory~~ ~~and~~incremental revenue recognized in the ~~sale of six retired rigs subsequent to the third~~fourth quarter of ~~2016. In addition, we continue~~2023 related to ~~see~~ favorable ~~results from our cost control measures that were initiated~~settlements with customers regarding equipment issues and non-productive time, which had occurred earlier in ~~prior periods.~~2023, performance bonuses for the Ocean BlackHawk and Ocean BlackRhino and an early termination fee received by the Ocean Apex.

~~Interest Expense, Net of Amounts Capitalized.~~~~Interest expense increased $9.5 million~~R-Edays decreased during the ~~third~~first quarter of ~~2017 compared~~2024, primarily due to ~~the third quarter of 2016, primarily~~downtime as a result of the Ocean GreatWhite being out of service and in shipyard for repairs due to the LMRP incident (60 fewer R-E days), termination of the managed services agreement and charter of the West Auriga (30 fewer days), warm stacking of the Ocean Patriot between contracts (29 fewer R-E days) and aggregate net incremental downtime for repairs for other rigs in our fleet (14 fewer R-E days). The decrease in R-E days was partially offset by nearly full-quarter operations for the Ocean Courage and Ocean BlackHawk in 2024 (96 incremental days), compared to the fourth quarter of 2023 when both rigs completed shipyard projects in advance of their current contracts.

Contract Drilling Expense, Excluding Depreciation. Contract drilling expense, excluding depreciation decreased $4.6 million during the first quarter of 2024, compared to the fourth quarter of 2023. Lower expense in the 2024 period was primarily due to reduced charter costs for the managed rigs ($13.0 million), as well as lower other operating expense for the West Auriga, primarily due to the termination of the rig’s MMSA at the end of February 2024 ($5.3 million) and the absence of ~~interest capitalized during construction of the~~~~Ocean GreatWhite~~expense associated with an annual efficiency bonus recognized in the ~~2016 period~~fourth quarter of 2023 related to a services agreement for certain well control equipment on our drillships ($~~8.0~~6.0 million). ~~In addition, we incurred incremental interest expense~~The reduction in costs between periods was partially offset by higher operating expenses for the Ocean BlackHawk and Ocean Courage ($10.6 million), which operated under contract for nearly a full quarter in 2024, compared to being in shipyard during portions of ~~$1.4~~the fourth quarter of 2023, $7.6 million in non-recoverable expense (or a portion of the ~~third~~insurance deductible) associated with repairs for the Ocean GreatWhite attributable to the LMRP incident and a net increase in operating expense for the other rigs in our fleet ($1.5 million).

Loss on disposition of assets. We recorded a net loss on disposition of assets of $3.4 million for the first quarter of ~~2017 related to~~2024, which included $2.4 million in non-recoverable expense (or a portion of the ~~issuance of our 7.875% senior notes due 2025, or 2025 Notes, and redemption of our 5.875% senior notes due 2019, or 2019 Notes, in August 2017.~~insurance deductible) associated with capital repairs for the Ocean GreatWhite.

~~Loss on Extinguishment of Senior Notes.~~~~During the third quarter of 2017, we recorded a $35.4 million loss on extinguishment of our outstanding 2019 Notes.~~

Income Tax Benefit.We estimate our annual effective tax rate (or AETR) for continuing operations in recording our interim quarterly income tax provision, considering the various jurisdictions in which we operate. We exclude discrete tax adjustments from the computation of the AETR and record such adjustments in the quarter in which they occur.

We recorded a net income tax benefit of ~~$14.6~~$3.2 million for the ~~third quarter of 2017, compared to~~three months ended March 31, 2024. For the three months ended December 31, 2023, we recorded a net income tax expense of ~~$(20.8) million~~$174.3million. The effective tax rate for the ~~third~~ quarter ended March 31, 2024 resulted from the mix of ~~2016. The difference~~pre-tax income and loss across jurisdictions, increased profitability in jurisdictions which rigs are currently operating, and the ~~amount~~effect of ~~income~~discrete items, specifically a benefit on remeasurement of uncertain tax ~~benefit (expense) recognized~~positions in Egypt.

Contract Drilling Revenue. Contract drilling revenue increased $44.4 million during the ~~2017 period,~~three months ended March 31, 2024 compared to the ~~prior year period, was in large part due to the mix of our domestic and internationalpre-tax~~ earnings and losses, inclusive of the loss on extinguishment of debt recognized in the third quarter of 2017. Income tax expense for the third quarter of 2016 included approximately $6.0 million in expense attributable to return to provision adjustments related to prior period tax returns.

~~Operating Income (Loss).~~~~Total operating income for the first nine~~three months ~~of 2017 increased $591.3 million compared to the same period of 2016,~~ended March 31, 2023, primarily due to higher average daily revenue earned ($28.2 million), in addition to a ~~lower impairment loss recognized~~60-day increase in ~~the 2017 period~~R-E days ($~~606.9~~16.2 million) ~~and reduced depreciation expense ($33.2 million)~~. ~~These favorable variances were partially offset by the unfavorable effect of a $27.2 million decrease in contract drilling~~

Average daily revenue earned during the first ~~nine months~~quarter of ~~2017, compared to the same period of 2016, and the absence of $14.6 million in net reimbursable revenue earned by the~~~~Ocean Endeavor~~~~during the 2016 period. Depreciation expense decreased primarily due to a lower depreciable asset base in the 2017 period,~~2024 increased, compared to the first ~~nine months~~quarter of ~~2016, as a result~~2023, primarily due to higher dayrates earned by several rigs in the fleet, which operated under new contracts or extensions that commenced after the first quarter of ~~asset impairments recognized in 2016 and 2017.~~2023.

~~Contract drilling revenue decreased $27.2 million~~R-E days increased during the first ~~nine months~~quarter of ~~2017~~2024, compared to the first ~~nine months~~quarter of ~~2016,~~2023, primarily ~~as a result~~due to incremental operating days for the Ocean Endeavor, which completed shipyard repairs in the first quarter of ~~lower average daily revenue earned by multiple rigs~~2023, and the West Vela, which was warm stacked between contracts during the first quarter of 2023 (105 incremental days). The increase in ~~our fleet,~~R-E days during the 2024 period was partially offset by a net increase in downtime for repairs (20 fewer R-E days), the ~~favorable impact~~warm-stacking of ~~an aggregate 299 incremental revenue-earning days.~~rigs between contracts (26 fewer R-E days) and termination of the MMSA for the West Auriga (23 fewer R-E days). Comparing the ~~two nine-month periods, total contract drilling expense~~quarters, the Ocean GreatWhite had achieved 24 incremental R-E days prior to going out of service for ~~our fleet was flat.~~

~~Interest Expense, Net of Amounts Capitalized.~~~~Interest expense increased $14.7 million during the first nine months of 2017 compared to the same period of 2016, primarily~~repairs as a result of the ~~absence~~LMRP incident during the first quarter of ~~$15.2~~2024.

Contract Drilling Expense, Excluding Depreciation. Contract drilling expense, excluding depreciation increased $10.7 million during the first quarter of 2024, compared to the first quarter of 2023 and reflected higher net expense for the managed rigs ($5.8 million), primarily due to higher charter fees for both managed rigs, partially offset by lower repair and maintenance costs for the West Vela, and also included $7.6 million in ~~capitalized interest~~non-recoverable expense (or a portion of the insurance deductible) associated with repairs for ~~construction projects~~the Ocean GreatWhite. Comparing the periods, contract drilling expense was reduced by a net decrease in other operating costs across our owned rig fleet ($2.7 million) during the ~~2016 period. The increase~~first quarter of 2024.

Interest Expense. Interest expense increased $3.3 million during the first quarter of 2024, primarily due to higher average debt outstanding compared to the first quarter of 2023. Interest expense for the first quarter of 2024 included $12.2 million in expense related to our $550.0 million aggregate principal amount of senior secured second lien notes (or the Second Lien Notes), which bear interest ~~expense is also attributable to incremental~~at 8.5%, and the amortization of associated debt issuance costs. During the first quarter of 2023, we incurred interest expense of ~~$1.4~~$8.8 million ~~related~~on weighted average debt outstanding of approximately $354.0 million at an average interest rate of 9.5%, in addition to amortization of associated debt issuance costs and debt premium.

Loss (gain) on disposition of assets. We recorded a net loss on disposition of assets of $3.4 million for the ~~issuance~~first quarter of ~~our 2025 Notes and redemption~~2024, which included $2.4 million in non-recoverable expense (or a portion of ~~our 2019 Notes in August 2017, which was offset by reduced interest expense~~the insurance deductible) associated with ~~lower borrowings under our revolving credit agreement ($1.8 million).~~

~~Impairment of Assets~~capital repairs for the LMRP and related equipment on the Ocean GreatWhite. During the first ~~nine months~~quarter of ~~2017,~~2023, we recognized ~~an aggregate impairment~~a $1.2 million gain on disposition of surplus equipment.

Income Tax Benefit. We recorded a net income tax benefit of $3.2 million for the three months ended March 31, 2024, inclusive of a $12.2 million tax benefit on the revaluation of unrecognized tax liabilities in Egypt due to the significant weakening of the Egyptian pound. For the three months ended March 31, 2023, we recorded a net income tax benefit of $25.6 million. The effective tax rate for the three months ended March 31, 2024 was the result of the mix of pre-tax income and loss across jurisdictions, increased profitability in jurisdictions which rigs are currently operating, and the effect of ~~$71.3~~discrete items, specifically a benefit on remeasurement of uncertain tax positions in Egypt.

We have available a senior secured revolving credit agreement, which provides for a $300.0 million ~~compared~~senior secured revolving credit facility (or the RCF). The RCF is scheduled to ~~an aggregate impairment charge of $678.1 million during the first nine months of 2016.~~mature on April 22, 2026. See ~~Notes 1 and 2~~Note 6 “Long-Term Debt” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this ~~report.~~

~~Other, net.~~~~During the first nine months of 2016, we sold our investment in privately-placed corporate bonds~~report for a ~~total recognized loss~~discussion of ~~$12.1 million.~~our RCF.

~~Income Tax Benefit.~~~~We recorded~~At May 6, 2024, we had no borrowings outstanding under the RCF, and a ~~net income tax benefit~~$1.9 million letter of ~~$36.6~~credit had been issued thereunder. As of May 6, 2024, approximately $298.1 million was available for borrowings under the RCF subject to its terms and ~~$59.6 million~~conditions; however, the availability of borrowings under the RCF is subject to the satisfaction of certain conditions as specified in our revolving credit agreement, including restrictions on borrowings.

There is no capacity for the ~~nine months ended September 30, 2017 and 2016, respectively. The difference in~~issuance of new letters of credit under the ~~amount of income tax benefit recognized in~~RCF, but the ~~first nine months of 2017, compared~~RCF permits us to ~~the prior year period, was primarily due~~obtain up to ~~the mix of our domestic and internationalpre-tax~~ earnings and losses, inclusive of the impairment losses recognized in 2017 and 2016 and a loss on extinguishment of debt recognized in the 2017 period. Tax benefit for the first nine months of 2017 and 2016 included U.S. tax benefits of $24.9 million and $143.2 million, respectively, related to the impairment of assets in the U.S. tax jurisdiction. Income tax benefit for the nine months ended September 30, 2016 was net of additional tax expense associated with a valuation allowance of $61.1 million recognized during the period for current and prior year tax assets associated with foreign tax credits and return to provision adjustments of approximately $6.0 million.

~~Ultra-Deepwater Floaters.~~Revenue generated by our ultra-deepwater floaters increased $58.6 million during the third quarter of 2017, compared to the same quarter of 2016, primarily as a result of 197 incremental revenue-earning days ($88.7 million), partially offset by lower average daily revenue earned ($30.1 million). Revenue-earning days increased during the third quarter of 2017, primarily due to incremental revenue-earning days for the~~Ocean GreatWhite~~ ~~(92 days) and the~~~~Ocean BlackRhino~~(91 days), neither of which was operating under contract during the third quarter of 2016, combined with an aggregate of 14 incremental revenue-earning days for our other ultra-deepwater rigs. Average daily revenue decreased during the third quarter of 2017, compared to the prior year quarter, primarily due to a lower dayrate earned by the~~Ocean Monarch~~ ~~under a new contract that commenced in the second quarter of 2017.~~

Contract drilling expense for our ultra-deepwater floaters increased $15.5 million during the third quarter of 2017, compared to the same period in 2016, primarily due to incremental contract drilling expense for the~~Ocean GreatWhite($9.3 million) and~~~~Ocean BlackRhino~~ ($17.1 million), as well as higher costs associated with the mobilization of rigs ($3.4 million). These incremental costs were partially offset by lower costs for labor and personnel ($3.3 million), repairs and maintenance ($4.4 million), shorebase support and overhead ($3.5 million) and other costs ($3.1 million).

~~Deepwater Floaters.~~Revenue and contract drilling expense for our deepwater floaters decreased $30.4 million and $9.1 million, respectively, in the third quarter of 2017 compared to the same quarter in 2016. The reduction in revenue was primarily the result of cold stacking the~~Ocean Victory~~ ~~in the second quarter of 2017 after completion of its contract in Trinidad ($34.3 million), partially offset by 45 incremental revenue-earning days for the~~~~Ocean Valiant~~ during the third quarter of 2017, which operated at a lower average dayrate than in the prior year period ($1.9 million). Contract drilling expense for the third quarter of 2017 also declined, primarily due to reduced costs incurred by the~~Ocean Victory~~ ~~($8.6 million).~~

~~Mid-Water~~ ~~Floaters.~~~~Revenue generated by ourmid-water~~ ~~floaters during the third quarter of 2017 decreased $16.7 million compared to the same quarter of 2016, primarily due to the warm stacking of the~~~~Ocean Guardian~~ ~~between contracts for much of the third quarter of 2017 ($16.1 million). Contract drilling expense remained flat during the third quarter of 2017, compared to the prior year period.~~

~~Jack-ups.~~~~The~~~~Ocean Scepter~~, which was cold-stacked throughout the third quarter of 2016, returned to service under a new contract offshore Mexico in early 2017 and generated contract revenue and incurred incremental contract drilling expense of $6.6 million and $4.8 million, respectively, during the third quarter of 2017.

~~Ultra-Deepwater Floaters.~~Revenue generated by our ultra-deepwater floaters increased $44.5 million during the first nine months of 2017, compared to the same period of 2016, primarily as a result of 301 incremental revenue-earning days ($145.6 million), partially offset by lower average daily revenue earned ($101.1 million). Revenue-earning days increased primarily due to incremental revenue-earning days for the~~Ocean GreatWhite~~ ~~(260 days) and the~~~~Ocean BlackRhino,~~~~which was warm-stacked for much of the prior year period (184 days), and fewer days associated with downtime for repairs (56 days). The increase in 2017 revenue-earning days was partially offset~~

~~by incremental downtime for the~~~~Ocean Monarch~~, which was in the shipyard for a survey and contract modifications during the first half of 2017 (121 days), and the absence of revenue-earning days for cold-stacked rigs that had worked in the prior year period (78 days). Average daily revenue decreased during the 2017 period, primarily due to the absence of $40.0$50.0 million in ~~demobilization revenue recognized in 2016 for~~letters of credit outside the~~Ocean Endeavor, combined with the effect~~ RCF. We have obtained a $25.0 million letter of ~~lower dayrates earned under new contracts for both the~~~~Ocean Monarch~~~~and~~ ~~Ocean BlackRhino~~.credit facility; however, letters of credit thereunder must be cash collateralized.

Contract drilling expense for our ultra-deepwater floaters increased $43.1 million during the first nine months of 2017, compared to the same period of 2016, primarily due to incremental costs associated with the Pressure Control by the Hour^® ~~program on our drillships ($24.8 million) and incremental contract drilling expense for the~~~~Ocean GreatWhite~~($31.4 million). These incremental costs for our ultra-deepwater floaters were partially offset by a net $13.1 million decrease in contract drilling expense during the first nine months of 2017, compared to the prior year period, primarily due to lower expenses for our cold-stacked rigs ($14.3 million).

~~Deepwater Floaters.~~Revenue generated by our deepwater floaters decreased $21.8 million in the first nine months of 2017, compared to the same period in 2016, primarily due to a reduction in average daily revenue earned ($44.7 million), partially offset by the effect of 73 incremental revenue-earning days ($22.9 million). Average daily revenue decreased during the first nine months of 2017 primarily as a result of a lower dayrate being earned by the~~Ocean Valiant~~ under its current contract in the North Sea that commenced in the fourth quarter of 2016. Revenue-earning days increased primarily due to 180 incremental days for our active deepwater floaters, partially offset by 107 fewer days for the cold-stacked~~Ocean Victory, which had been under contract during the 2016 period.~~

Contract drilling expense for our deepwater floaters decreased $27.0 million during the first nine months of 2017, compared to the 2016 period, primarily due to a net reduction in costs associated with labor and personnel ($8.7 million), maintenance and repairs ($9.2 million), equipment rental ($2.3 million), freight ($1.2 million) and other rig operating and overhead costs ($5.6 million) attributable to various factors, including the cold stacking of rigs and implementation of cost control measures for our working rigs and shorebase operations in 2016.

~~Mid-Water~~ ~~Floaters.~~~~Revenue and contract drilling expense for ourmid-water~~ floaters decreased $36.3 million and $14.6 million, respectively, during the first nine months of 2017 compared to the same period of 2016. The decrease in revenue reflected 148 fewer revenue-earning days ($43.8 million), partially offset by an increase in average daily revenue earned ($7.5 million). The decrease in revenue-earning days primarily related to the completion of the final contract for the~~Ocean Ambassador~~ ~~in March 2016 prior to the rig being sold (78 days) and fewer days for the~~~~Ocean Guardian~~~~, which was warm stacked between contracts for much of the 2017 period (75 days). Only two of ourmid-water~~ ~~floaters operated during both periods, while the remainder of ourmid-water~~ ~~fleet remained cold stacked or was sold during 2016. The decrease in contract drilling expense was primarily due to reduced costs related to the~~~~Ocean Ambassador~~ ~~($8.5 million), and a reduction in labor and personnel ($4.2 million) and other costs ($1.9 million) for the remainder of the fleet.~~

~~Jack-ups.~~~~Contract drilling revenue attributable to our current and previously-ownedjack-up~~ ~~rigs decreased $13.6 million during the first nine months of 2017, compared to the same period in 2016. The~~~~Ocean Scepter~~, which had been idle since completion of its former contract offshore Mexico in 2016, commenced operations offshore Mexico in early 2017 at a lower dayrate than previously earned, and resulted in an $8.6 million reduction in contract drilling revenue, compared to the prior year period. In addition,Historically, we ~~recognized $4.9 million inloss-of-hire~~ ~~insurance proceeds during the first nine months of 2016. Contract drilling expense for ourjack-up~~ ~~rigs increased $3.7 million during the first nine months of 2017, compared to the 2016 period, primarily due to higher costs incurred by the~~~~Ocean Scepter~~ ~~for labor and personnel ($2.7 million) and repairs ($2.6 million), partially offset by reduced costs associated with sold rigs ($1.6 million).~~

~~We principally rely~~have relied on our cash flows from operations and cash reserves to meet our liquidity ~~needs. We may also utilize borrowings under our $1.5 billion syndicated revolving credit agreement, or Credit Agreement. See “ – Credit Agreement.”~~

~~Based on our cash available for current operations and contractual backlog of $2.6 billion as of October 1, 2017, of~~needs, which $0.3 billion is expected to be realized during the remainder of 2017, we believe future capital spending and debt service requirements will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement, as needed. See “– Sources and Uses of Cash – Capital Expenditures.”

~~Certain~~primarily include funding of our ~~international~~working capital requirements and capital expenditures, as well as the servicing of our debt repayments and interest payments. As of May 6, 2024, all of our rigs, excluding the managed rig, are

owned and operated, directly or indirectly, by Diamond Foreign Asset Company ~~or DFAC, and, as a result of our intention~~(or DFAC). Our management has determined that we will permanently reinvest foreign earnings, which restricts the ability to ~~indefinitely reinvest the earnings~~utilize cash flows of DFAC ~~and its foreign~~

subsidiaries to finance our foreign activities, we do not expect such earnings to be available for distribution to our stockholders or to finance our domestic activities. Although we do not intend to repatriate the earnings of DFAC, and have not provided U.S. income taxes for such earnings, except to the extent that such earnings were immediately subject to U.S. income taxes, these earnings could become subject to U.S. income tax if remitted, or if deemed remitted ason a ~~dividend; however, it is not practical to estimate this potential liability.~~

company-wide basis.To the extent ~~available,~~possible, we expect to utilize the operating cash flows ~~generated by~~ and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each ~~entity’s~~ respective entity's working capital requirements and capital commitments. ~~At September 30, 2017~~

From time to time, based on market conditions and ~~December 31, 2016,~~other factors, we ~~had cash available for current operations, including cash reserves of DFAC, as follows:~~

~~A substantial~~may seek to repay, refinance or restructure all or a portion of our ~~cash flows has historically been invested in the enhancement of our drilling fleet. We determine the amount of cash required to meet~~outstanding indebtedness or otherwise enter into transactions regarding our capital ~~commitments by evaluating~~structure to obtain more favorable terms, enhance flexibility in conducting our ~~rig construction obligations, the need~~business, increase liquidity or otherwise. We regularly evaluate capital markets to ~~upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We also make periodic assessments~~consider future opportunities for enhancements of our capital ~~spending programs based on current~~structure and ~~expected industry conditions and make adjustments thereto if required. See “– Sources and Uses of Cash – Capital Expenditures.”~~

~~We pay dividends at the discretion of~~may opportunistically pursue financing transactions to optimize our Board of Directors, or Board, and any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. We did not pay any dividends in 2016 or during the first nine months of 2017.

Depending on market and other conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not purchase any shares of our outstanding common stock during the nine-month periods ended September 30, 2017 and 2016.

~~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.~~structure. 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.~~control, and there can be no assurance that we would be able to complete any such offering of securities.

As of April 1, 2024, our contractual backlog was approximately $1.9 billion. At March 31, 2024, we had cash of $169.2 million, including $6.8 million that is subject to restrictions pursuant to the MMSA.

For the ~~nine-month~~three-month period ended ~~September 30, 2017,~~March 31, 2024, our ~~primary sources of cash were an aggregate $489.1 million in net proceeds from the issuance of our 2025 Notes, $366.6 million generated by~~ operating activities generated cash of $59.0 million. Cash receipts from contract drilling services ($315.7 million) were partially offset by cash expenditures for contract drilling, shorebase support, and ~~$4.0 million from the disposition of assets.~~ general and administrative costs ($256.6 million).

Cash ~~usage during the same period was primarily $534.4 million~~outlays for ~~the redemption of our 2019 Notes, $104.2 million for the net repayment of borrowings under our Credit Agreement and~~ capital expenditures ~~aggregating $100.6 million. See “– Senior Notes.”~~

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

~~Cash Flow~~~~from Operations.~~~~Cash flow from operations decreased $125.4 million~~ during the first ~~nine~~three months of ~~2017, compared~~2024 aggregated $27.9 million, primarily related to long-lead items for the ~~first nine months~~Ocean BlackRhino’s shipyard project and equipment updates scheduled for the second half of ~~2016, primarily due~~2024. We also made payments of $4.3 million under finance lease obligations related to ~~lower~~well control equipment on our owned drillships.

For the three-month period ended March 31, 2023, our operating activities used cash ~~receipts~~of $8.2 million. Cash expenditures for contract drilling, ~~services~~shorebase support, and general and administrative costs ($~~193.3~~232.9 million), were partially offset by cash receipts from contract drilling services ($217.0 million) and a net ~~decrease~~refund of cash income taxes ($7.7 million), primarily in the U.S. tax jurisdiction, during the three-month period.

Cash outlays for capital expenditures during the first quarter of 2023 aggregated $29.4 million (including capital outlays for the Ocean Endeavor and Ocean GreatWhite shipyard projects completed this year). We also repaid $15.0 million in outstanding draws under the RCF and made payments in connection with finance lease obligations aggregating $4.1 million related to our owned drillships.

On February 1, 2024, the Ocean GreatWhite, reported an equipment incident while located in the North Sea west of the Shetland Islands. The rig’s lower marine riser package (“LMRP”) and deployed riser string unintentionally separated from the rig at the slip joint tensioner ring and the LMRP and riser dropped to the seabed. We have safely recovered the LMRP from the seabed and are in a repair facility in Kishorn port, where repairs to the LMRP and any related work are underway.

We anticipate that the LMRP incident will be covered by our hull & machinery insurance policy and that all incremental costs, less our $10.0 million deductible, will be reimbursable under that policy. In addition, we carry loss-of-hire insurance on the Ocean GreatWhite to cover a portion of lost cash ~~payments~~flow under certain circumstances. After a 60-day waiting period, our loss-of-hire insurance provides $150,000 per day, for ~~contract drilling expenses, including personnel-related,~~up to 180 days, for each day of lost revenue as a result of a covered property loss claim. As of the date of this report, we estimate the cash flow impact of direct and incremental recovery, repairs and maintenance costs, and ~~overheads ($72.4 million). The decline in both~~replacement capital expenditures, offset by loss of hire insurance, to be approximately $25.0 million to $30.0 million dollars. However, we cannot fully predict the extent of such insurance coverage or the timing of such claims.

We have historically invested a significant portion of our cash ~~receipts and cash payments related to the performance of contract drilling services reflects continuing depressed market conditions~~flows in the ~~offshore drilling industry, as well as positive results~~enhancement of our ~~continuing focus~~drilling fleet and our ongoing rig equipment replacement and capital maintenance programs. 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 rig equipment enhancement, maintenance and replacement programs. We make periodic assessments of our capital spending programs based on ~~controlling costs.~~

~~Capital Expenditures.~~current and expected industry conditions and our cash flow forecast. As of the date of this report, we expect total capital expenditures for ~~2017~~2024 to ~~aggregate~~be approximately ~~$125.0~~$135.0 million ~~for our ongoing capital maintenance and replacement programs.~~to $145.0 million.

~~We had no other purchase obligations for major rig upgrades at September 30, 2017.~~Other Obligations

~~Other Obligations.~~As of ~~September 30, 2017,~~March 31, 2024, the amount of total net unrecognized tax benefits related to uncertain tax positions that could result in a future cash payment was ~~$65.0~~$40.3 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities. Included in the balance is $21.0 million related to prior years’ operations in Egypt.

At September 30, 2017, we had no borrowings outstanding under our Credit Agreement, and were in compliance with all covenants thereunder. As of October 26, 2017, we had $1.5 billion available under our Credit Agreement to provide liquidity for our payment obligations.

In August 2017, we issued $500.0 million aggregate principal amount of unsecured 2025 Notes and received net proceeds of $489.1 million after deducting underwriting discounts, commissions and estimated expenses. The 2025 Notes bear interest at 7.875% per year and mature on August 15, 2025. Interest on the 2025 Notes is payable semiannually in arrears on February 15 and August 15 of each year, beginning February 15, 2018.

We used the net proceeds from the 2025 Notes, together with cash on hand, to fund the redemption of our 5.875% senior notes due 2019. See Note 7 “Senior Notes” to our unaudited condensed consolidated financial statements included in Item 1 of Part 1 of this report.

~~On October 18, 2017, S&P Global Ratings, or S&P, downgraded our corporate credit rating to B+ fromBB-;~~ our outlook by S&P remains negative. On July 28, 2017, Moody’s Investor Services downgraded our corporate credit rating to Ba3 with a negative outlook from Ba2 with a stable outlook. Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered. Any downgrade in our credit ratings could adversely impact our cost of issuing additional debt and the amount of additional debt that we could issue, and could further restrict our access to capital markets and our ability to raise funds by issuing additional debt. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.

We were contingently liable as of September 30, 2017 in the amount of $21.3 million under certain performance, tax, supersedeas, bid and customs bonds and letters of credit. Agreements relating to approximately $15.6 million of tax, supersedeas, court and customs bonds can require collateral at any time. As of September 30, 2017, 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.

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

See Note ~~1 “General Information”~~ 7 “Commitments and Contingencies”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.~~certain of our other commercial commitments.

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(or the Exchange ~~Act.~~Act). All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “would,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, those described or referenced ~~under “Risk Factors”~~ in Item 1A, “Risk Factors” in our Annual Report on Form10-K for the year ended December 31, ~~2016.~~2023.

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 ~~each of~~ these reports isare 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.

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.

Interest Rate Risk. From time to time, we may have exposure to interest rate risk on our debt instruments that may arise from changes in the level or volatility of interest rates. As of March 31, 2024, we had no variable rate debt outstanding. Our Second Lien Notes have been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts.

There were no other material changes in our market risk components for the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2024. See “Quantitative and Qualitative Disclosures About Market Risk” included in Item 7A of our Annual Report on Form10-K for the year ended December 31, ~~2016~~2023 for further information.

We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.

Our Chief Executive Officer ~~or CEO,~~(or CEO) and Chief Financial Officer ~~or CFO,~~(or CFO) participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules

13a-15(e) and15d-15(e)) as of ~~September 30, 2017.~~March 31, 2024. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of ~~September 30, 2017.~~

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our ~~third~~first fiscal quarter of ~~2017~~2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Information related to certain legal proceedings is included in Note 87 “Commitments and Contingencies” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this ~~report.~~report, which is incorporated herein by reference.

Our Annual Report on Form10-K for the year ended December 31, ~~2016~~2023 includes a detailed discussion of certain material risk factors facing the Company. The risk factors included under Item 1A of our ~~company.~~Annual Report on Form 10-K for the year ended December 31, 2023 are incorporated herein by reference. No material changes have been made to such risk factors as of ~~September 30, 2017.~~March 31, 2024.

(c) ~~During~~On March 4, 2024, Bernie Wolford, Jr., President and Chief Executive Officer, entered into a pre-arranged stock trading plan (the “Wolford 10b5-1 Plan”). The Wolford 10b5-1 Plan was entered into during an open insider trading window and is intended to satisfy the ~~three months ended September 30, 2017,~~affirmative defense of Rule 10b5-1(c) of the Exchange Act and our policies regarding trading in ~~connection with~~our securities. The Wolford 10b5-1 Plan provides for the ~~vesting~~potential sale of ~~restricted stock units held by our officers and certain of our employees, which were awarded under an equity incentive compensation plan, we acquired~~up to 408,000 shares of ~~our~~the Company’s common stock between June 3, 2024 and May 30, 2025, subject to the terms and conditions of the plan.

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.


Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $0.0001 par value per share	DO	New York Stock Exchange


						PAGE NO.
				~~PAGE NO.~~
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			5
		Condensed Consolidated Statements of Stockholders’ Equity		6
		Condensed Consolidated Statements of Cash Flows			6	7

		Notes to Unaudited Condensed Consolidated Financial Statements			7
			8
~~ITEM 2.~~
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations			19


	ITEM 3.		Quantitative and Qualitative Disclosures About Market Risk			31
			29

	ITEM 4.		Controls and Procedures			31	29

PART II. OTHER INFORMATION					32
			31
~~ITEM 1.~~		~~Legal Proceedings~~			32

~~ITEM 1A.~~	ITEM 1.	~~Risk Factors~~Legal Proceedings			32
			31
~~ITEM 2.~~	ITEM 1A.	~~Unregistered Sales of Equity Securities and Use of Proceeds~~Risk Factors			32
			31
~~ITEM 6.~~		~~Exhibits~~			33
	ITEM 5.	Other Information		31
~~SIGNATURES~~	ITEM 6.	Exhibits		32
	34
SIGNATURES				33


	Nine Months Ended
	September 30,
	2017			2016
Operating activities:
Net income (loss)	$	50,287		$	(488,585	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation		262,492			295,729
Loss on impairment of assets		71,268			678,145
Loss on extinguishment of senior notes		35,366			—
Gain on disposition of assets		(2,085	)		(2,265	)
Loss on sale of marketable securities		—			12,146
Deferred tax provision		(73,873	)		(114,405	)
Stock-based compensation expense		4,806			3,754
Deferred income, net		8,379			(23,381	)
Deferred expenses, net		32,701			(1,099	)
Other assets, noncurrent		(2,806	)		(677	)
Other liabilities, noncurrent		(212	)		3,021
Other		2,387			1,997
Changes in operating assets and liabilities:
Accounts receivable		(25,743	)		131,388
Prepaid expenses and other current assets		(4,831	)		3,950
Accounts payable and accrued liabilities		17,787			(32,762	)
Taxes payable		(9,288	)		25,038

Net cash provided by operating activities		366,635			491,994

Investing activities:
Capital expenditures (including rig construction)		(100,613	)		(598,236	)
Proceeds from disposition of assets, net of disposal costs		4,017			169,038
Proceeds from sale and maturities of marketable securities		31			4,603

Net cash used in investing activities		(96,565	)		(424,595	)

Financing activities:
Redemption of senior notes		(500,000	)		—
Payment of debt extinguishment costs		(34,395	)		—
Proceeds from issuance of senior notes		496,360			—
Debt issuance costs and arrangement fees		(7,226	)		—
Net repayment of short-term borrowings		(104,200	)		(104,489	)
Other		(156	)		(609	)

Net cash used in financing activities		(149,617	)		(105,098	)

Net change in cash and cash equivalents		120,453			(37,699	)
Cash and cash equivalents, beginning of period		156,233			119,028

Cash and cash equivalents, end of period	$	276,686		$	81,329


	Three Months Ended March 31,
	2024			2023
Operating activities:
Net income	$	11,612		$	7,229
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation		31,354			27,906
Loss (gain) on disposition of assets		3,396			(1,213	)
Deferred tax provision		(7,525	)		(14,457	)
Stock-based compensation expense		3,590			4,414
Contract liabilities, net		4,865			297
Contract assets, net		10			(270	)
Deferred contract costs, net		5,867			(2,560	)
Other assets, noncurrent		860			(400	)
Other liabilities, noncurrent		(874	)		1,883
Other		963			706
Changes in operating assets and liabilities:
Accounts receivable		34,400			(15,023	)
Prepaid expenses and other current assets		(128	)		(4,229	)
Accounts payable and accrued liabilities		(29,300	)		(7,796	)
Taxes payable		(72	)		(4,664	)
Net cash provided by (used in) operating activities		59,018			(8,177	)
Investing activities:
Capital expenditures		(27,935	)		(29,413	)
Proceeds from disposition of assets, net of disposal costs		3,805			663
Net cash used in investing activities		(24,130	)		(28,750	)
Financing activities:
Repayments under revolving credit facility		—			(15,000	)
Principal payments of finance leases		(4,335	)		(4,079	)
Net cash used in financing activities		(4,335	)		(19,079	)
Net change in cash, cash equivalents and restricted cash		30,553			(56,006	)
Cash, cash equivalents and restricted cash, beginning of period		138,688			97,334
Cash, cash equivalents and restricted cash, end of period	$	169,241		$	41,328


	March 31,			December 31,
	2024			2023
Drilling rigs and equipment	$	1,272,564		$	1,244,798
Finance lease right of use asset		174,571			174,571
Land and buildings		10,064			10,040
Office equipment and other		5,317			5,180
Cost		1,462,516			1,434,589
Less: accumulated depreciation		(309,476	)		(278,221	)
Drilling and other property and equipment, net	$	1,153,040		$	1,156,368


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


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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Net income (loss)	$	10,799		$	13,927		$	50,287		$	(488,585	)

Other comprehensive (losses) gains, net of tax:
Derivative financial instruments:
Reclassification adjustment for gain included in net income (loss)		(1	)		—			(4	)		(3	)

Investments in marketable securities:
Unrealized holding loss		—			(1	)		—			(6,559	)
Reclassification adjustment for loss included in net income (loss)		—			—			—			11,600

Total other comprehensive (loss) gain		(1	)		(1	)		(4	)		5,038

Comprehensive income (loss)	$	10,798		$	13,926		$	50,283		$	(483,547	)


	Three Months Ended March 31, 2024

										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Accumulated			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Deficit			Income			Shares		Amount			Equity
January 1, 2024		102,322	$	10	$	978,575	$	(325,261	)	$	20			867	$	(8,493	)	$	644,851
Net income		—		—		—		11,612			—			—		—			11,612
Stock-based compensation, net of tax		157		—		3,523		—			—			53		(661	)		2,862
Unrealized loss on marketable securities		—		—		—		—			(14	)		—		—			(14	)
March 31, 2024		102,479	$	10	$	982,098	$	(313,649	)	$	6			920	$	(9,154	)	$	659,311


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

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


	September 30, 2017
	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Assets at Fair Value		Total Losses for Nine Months Ended
	(In thousands)
Recurring fair value measurements:
Assets:
Short-term investments	$	262,887	$	—	$	—	$	262,887
Mortgage-backed securities		—		4		—		4

Total assets	$	262,887	$	4	$	—	$	262,891

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


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

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

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


	Principal									Semiannual
	Amount			Interest Rate						Interest Payment
Debt Issue	(In millions)		Maturity Date	Coupon			Effective			Dates
3.45% Senior Notes due 2023	$	250.0	November 1, 2023		3.45	%		3.50	%	May 1 and November 1
7.875% Senior Notes due 2025	$	500.0	August 15, 2025		7.875	%		8.00	%	February 15 and August 15
5.70% Senior Notes due 2039	$	500.0	October 15, 2039		5.70	%		5.75	%	April 15 and October 15
4.875% Senior Notes due 2043	$	750.0	November 1, 2043		4.875	%		4.89	%	May 1 and November 1


	September 30, 2017
	(In thousands)
3.45% Senior Notes due 2023	$	248,090
7.875% Senior Notes due 2025		489,200
5.70% Senior Notes due 2039		492,930
4.875% Senior Notes due 2043		741,632

Total senior notes, net	$	1,971,852


	April 1, 2024		January 1, 2024		April 1, 2023
Contract Drilling Backlog (1)	$	1,877	$	1,424	$	1,596


	October 1, 2017		January 1, 2017		October 1, 2016
	(In thousands)
Contract Drilling Backlog
Ultra-Deepwater Floaters⁽¹⁾	$	2,413,000	$	3,215,000	$	3,614,000
Deepwater Floaters		86,000		197,000		258,000
Other Rigs⁽²⁾		118,000		152,000		210,000

Total	$	2,617,000	$	3,564,000	$	4,082,000


	For the Years Ending December 31,
	Total		2017⁽¹⁾		2018		2019		2020
	(In thousands)
Contract Drilling Backlog
Ultra-Deepwater Floaters⁽²⁾	$	2,413,000	$	290,000	$	1,109,000	$	845,000	$	169,000
Deepwater Floaters		86,000		32,000		54,000		—		—
Other Rigs⁽³⁾		118,000		13,000		42,000		45,000	��	18,000

Total	$	2,617,000	$	335,000	$	1,205,000	$	890,000	$	187,000


	For the Years Ending December 31,
	2017 ⁽¹⁾			2018			2019			2020
Rig Days Committed⁽²⁾
Ultra-Deepwater Floaters		62	%		63	%		47	%		9	%
Deepwater Floaters		33	%		16	%		—			—
Other Rigs⁽³⁾		15	%		18	%		17	%		6	%


			For the Years Ending December 31,
	Total		2017		2018
	(In thousands)
Other Commercial Commitments
Performance bonds	$	1,000	$	—	$	1,000
Supersedeas bond		9,189		9,189		—
Tax bond		5,852		—		5,852
Bid bond		3,200		—		3,200
Other		2,040		1,310		730

Total obligations	$	21,281	$	10,499	$	10,782


Exhibit No.		Description of Exhibit
~~Exhibit~~ ~~No.~~		~~Description of Exhibit~~
3.1
~~3.1~~		Fourth Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our ~~Quarterly~~Current Report on Form~~10-Q~~ ~~for the quarterly period ended June~~ ~~30, 2003) (SEC File No.~~ ~~1-13926)~~ 8-K filed on May 10, 2023).

3.2		Third Amended and Restated~~By-laws~~ ~~(as amended through October 4, 2013)~~ Bylaws of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form8-K filed ~~October 8, 2013)~~on February 10, 2023).

~~4.1~~ 10.1		~~Indenture, dated as~~Form of 2024 Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.23 to our Annual Report on Form 10-K filed on February ~~4, 1997, between Diamond Offshore Drilling, Inc. and The Bank~~ 28, 2024).

10.2		Form of New York Mellon Trust Company, N.A. (successor to The Bank of New York Mellon which was previously known as The Bank of New York) (as successor under the Base Indenture to The Chase Manhattan Bank), as Trustee2024 Executive Performance-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit ~~4.1~~10.24 to our Annual Report on Form10-K ~~for the fiscal year ended December~~ ~~31, 2001) (SEC File No.~~ ~~1-13926)~~ filed on February 28, 2024).

~~4.2~~ 31.1*		~~Ninth Supplemental Indenture, dated as of August~~ ~~15, 2017, between Diamond Offshore Drilling, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to our Current Report on Form8-K~~ ~~filed August~~ ~~16, 2017).~~

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

31.2*		Rule13a-14(a) Certification of the Chief Financial ~~Officer.~~Officer.

32.1*		Section 1350 Certification of the Chief Executive Officer and Chief Financial ~~Officer.~~Officer.

101.INS*		Inline XBRL Instance ~~Document.~~Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH*		Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Document.

101.CAL* 104*		The cover page of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, formatted in Inline XBRL ~~Taxonomy Calculation Linkbase Document.~~

101.LAB*		~~XBRL Taxonomy Label Linkbase Document.~~

101.PRE*		~~XBRL Presentation Linkbase Document.~~

101.DEF*		~~XBRL Definition Linkbase Document.~~(included with the Exhibit 101 attachments).


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

~~Date October 30, 2017~~		~~By:~~		~~/s/ Kelly Youngblood~~
					~~Kelly Youngblood~~ (Registrant)

Date May 8, 2024	By:		/s/ Dominic A. Savarino
			Dominic A. Savarino
			Senior Vice President and Chief Financial Officer

~~Date October 30, 2017~~				~~/s/ Beth G. Gordon~~
				~~Beth G. Gordon~~
				~~Vice President and Controller (Chief Accounting Officer)~~

Large accelerated filer

Accelerated filer

Non-accelerated filer

~~☐ (Do not check if a smaller reporting company)~~

Smaller reporting company

Emerging growth company