UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended ~~September~~March 3031, ~~2023~~2024


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

For the transition period from to

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

    Delaware

    76-0321760

    (State or other jurisdiction of incorporation
or organization)

    (I.R.S. Employer
Identification No.)

~~15415~~777 ~~Katy~~N. ~~Freeway~~Eldridge Parkway, Suite 1100

Houston, Texas

~~77094~~77079

(Address of principal executive offices)

(Zip Code)

(281) 492-5300

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Exchange Act:


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

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 every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-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 Rule 12b-2 of the Exchange Act.

Large accelerated filer ☐☒ Accelerated filer ☒☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 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 ~~November~~May 36, ~~2023~~2024 Common stock, $0.0001 par value per share 102,~~322~~481,~~002~~240 shares.

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED ~~SEPTEMBER~~MARCH 3031, ~~2023~~2024

			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 (Loss) Income	6
		Condensed Consolidated Statements of Comprehensive Income	5
		Condensed Consolidated Statements of Stockholders’ Equity	76
		Condensed Consolidated Statements of Cash Flows	97
		Notes to Unaudited Condensed Consolidated Financial Statements	108
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2619
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	3929
	ITEM 4.	Controls and Procedures	3929
PART II. OTHER INFORMATION			4031
	ITEM 1.	Legal Proceedings	4031
	ITEM 1A.	Risk Factors	4031
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
	ITEM 5.	Other Information	31
	ITEM 5.	Other Information	40
	ITEM 6.	Exhibits	32
	ITEM 6.	Exhibits	41
SIGNATURES			33
SIGNATURES			42

PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except par value amounts)

	September 30,			December 31,
	March 31,			December 31,
	2023			2022
	2024			2023
ASSETS
Current assets:
Cash and cash equivalents	$	~~146~~162,~~826~~409		$	63124,~~041~~457
Restricted cash		256,~~556~~832			3414,~~293~~231
Accounts receivable		~~177~~225,~~123~~654			~~177~~260,~~675~~124
Less: allowance for credit losses		(5,~~698~~731	)		(5,~~622~~801	)
Accounts receivable, net		~~171~~219,~~425~~923			~~172~~254,~~053~~323
Prepaid expenses and other current assets		~~136~~57,~~211~~402			4863,~~695~~412
Asset held for sale		1,000			—1,000
Total current assets		~~481~~447,~~018~~566			~~318~~457,~~082~~423
Drilling and other property and equipment, net of
accumulated depreciation		1,~~157~~153,~~337~~040			1,~~141~~156,~~908~~368
Other assets		~~167~~89,~~453~~488			6798,~~966~~762
Total assets	$	1,~~805~~690,~~808~~094		$	1,~~527~~712,~~956~~553
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	5440,~~927~~630		$	4742,~~647~~037
Accrued liabilities		~~163~~185,~~412~~132			~~166~~203,~~785~~336
Taxes payable		2733,~~491~~296			3034,~~264~~817
Current finance lease liabilities		1516,~~655~~286			1615,~~965~~960
Total current liabilities		~~261~~275,~~485~~344			~~261~~296,~~661~~150
Long-term debt		~~535~~534,~~194~~009			~~360~~533,~~644~~514
Noncurrent finance lease liabilities		~~117~~108,~~889~~537			~~131~~113,~~393~~201
Deferred tax liability		~~702~~15,472			~~700~~10,966
Other liabilities		~~103~~97,~~377~~421			93113,~~888~~871
Commitments and contingencies (Note 7)
Total liabilities		1,~~018~~030,~~647~~783			~~848~~1,~~286~~067,702
Stockholders’ equity:
Preferred stock (par value $0.0001, 50,000 shares authorized, none issued and outstanding at September 30, 2023 and December 31, 2022)		—			—
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; 103,189 shares issued and 102,322 shares outstanding at September 30, 2023 and 101,884 shares issued and 101,320 shares outstanding at December 31, 2022)		10			10
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
Additional paid-in capital		~~975~~982,~~177~~098			~~964~~978,~~467~~575
Treasury stock		(89,~~493~~154	)		(48,~~252~~493	)
Accumulated deficit		(~~179~~313,~~559~~649	)		(~~280~~325,~~555~~261	)
Accumulated other comprehensive income		266			—20
Total stockholders’ equity		~~787~~659,~~161~~311			~~679~~644,~~670~~851
Total liabilities and stockholders’ equity	$	1,~~805~~690,~~808~~094		$	1,~~527~~712,~~956~~553

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share data)

	Three Months Ended September 30,
	Three Months Ended March 31,
	2023			2022
	2024			2023
Revenues:
Contract drilling	$	~~224~~258,~~929~~770		$	~~189~~214,~~861~~383
Revenues related to reimbursable expenses		2015,~~029~~840			3617,~~212~~638
Total revenues		~~244~~274,~~958~~610			~~226~~232,~~073~~021
Operating expenses:
Contract drilling, excluding depreciation		~~181~~184,~~954~~205			~~155~~173,~~567~~490
Reimbursable expenses		1815,~~662~~266			3517,~~765~~213
Depreciation		2731,~~785~~354			2627,~~069~~906
General and administrative		1618,~~649~~576			1619,~~320~~585
Gain on disposition of assets		(955	)		(73	)
Loss (gain) on disposition of assets		3,396			(1,213	)
Total operating expenses		~~244~~252,~~095~~797			~~233~~236,~~648~~981
Operating income (loss)		~~863~~21,813			(74,~~575~~960	)
Other income (expense):
Interest income		~~161~~1,774			117
Interest expense, net of amounts capitalized		(1315,~~774~~346	)		(1012,~~364~~040	)
Foreign currency transaction gain		184			237
Foreign currency transaction gain (loss)		231			(1,271	)
Loss on extinguishment of long-term debt		(6,529	)		—
Other, net		(71	)		(152	)
Other, net		(485	)		172
Income (loss) before income tax benefit		8,401			(18,416	)
Loss before income tax (expense) benefit		(19,580	)		(17,519	)
Income tax benefit		3,211			25,645
Income tax (expense) benefit		(125,436	)		23,029
Net income	$	11,612		$	7,229
Net (loss) income	$	(145,016	)	$	5,510
Earnings per share
(Loss) earnings per share
Basic	$	0.11		$	0.07
Basic	$	(1.42	)	$	0.05
Diluted	$	0.11		$	0.07
Diluted	$	(1.42	)	$	0.05
Weighted-average shares outstanding
Basic		102,~~215~~440			~~100~~101,~~875~~331
Diluted		~~102~~104,~~215~~740			~~102~~103,~~273~~936

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~OPERATIONS~~COMPREHENSIVE INCOME

(Unaudited)

(In thousands~~, except per share data~~)

	Nine Months Ended September 30,
	Three Months Ended March 31,
	2023			2022
	2024			2023
Revenues:
Net income	$	11,612		$	7,229
Contract drilling	$	704,302		$	516,992
Other comprehensive loss, net
Revenues related to reimbursable expenses		54,240			101,022
Unrealized loss on marketable securities (net of tax of $1)		(14	)		—
Total revenues		758,542			618,014
Comprehensive income	$	11,598		$	7,229
Operating expenses:
Contract drilling, excluding depreciation		568,390			442,619
Reimbursable expenses		51,454			99,932
Depreciation		83,596			78,714
General and administrative		53,058			52,805
Gain on disposition of assets		(4,102	)		(4,802	)
Total operating expenses		752,396			669,268
Operating income (loss)		6,146			(51,254	)
Other income (expense):
Interest income		173			12
Interest expense, net of amounts capitalized		(38,569	)		(28,792	)
Foreign currency transaction loss		(3,057	)		(285	)
Loss on extinguishment of long-term debt		(6,529	)		—
Other, net		(502	)		1,487
Loss before income tax benefit		(42,338	)		(78,832	)
Income tax benefit		143,334			28,059
Net income (loss)	$	100,996		$	(50,773	)
Earnings (loss) per share
Basic	$	0.99		$	(0.51	)
Diluted	$	0.97		$	(0.51	)
Weighted-average shares outstanding
Basic		101,681			100,356
Diluted		104,256			100,356

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~COMPREHENSIVE~~STOCKHOLDERS’ ~~(LOSS) INCOME~~EQUITY

(Unaudited)

(In thousands)

	Three Months Ended September 30,
	Three Months Ended March 31, 2024
	2023			2022
											Accumulated
Net (loss) income	$	(145,016	)	$	5,510
						Additional					Other								Total
Other comprehensive income, net
	Common Stock					Paid-In		Accumulated			Comprehensive			Treasury Stock					Stockholders’
Unrealized gain on marketable securities (net of tax of $3)		26			—
	Shares			Amount		Capital		Deficit			Income			Shares		Amount			Equity
Comprehensive (loss) income	$	(144,990	)	$	5,510
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

	Nine Months Ended September 30,
	Three Months Ended March 31, 2023
	2023		2022
						Additional										Total
Net income (loss)	$	100,996	$	(50,773	)
	Common Stock					Paid-In		Accumulated			Treasury Stock					Stockholders’
Other comprehensive income, net
	Shares		Amount			Capital		Deficit			Shares		Amount			Equity
Unrealized gain on marketable securities (net of tax of $3)		26		—
January 1, 2023		101,320	$	10		$	964,467	$	(280,555	)		564	$	(4,252	)	$	679,670
Comprehensive income (loss)	$	101,022	$	(50,773	)
Net income		—		—			—		7,229			—		—			7,229
Stock-based compensation, net of tax		38		—			4,072		—			11		(134	)		3,938
March 31, 2023		101,358	$	10		$	968,539	$	(273,326	)		575	$	(4,386	)	$	690,837

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Three Months Ended September 30, 2023
										Accumulated
					Additional					Other							Total
	Common Stock				Paid-In		Accumulated			Comprehensive		Treasury Stock					Stockholders’
	Shares		Amount		Capital		Deficit			Income		Shares		Amount			Equity
July 1, 2023		101,667	$	10	$	972,445	$	(34,543	)	$	—		627	$	(4,986	)	$	932,926
Net loss		—		—		—		(145,016	)		—		—		—			(145,016	)
Stock-based compensation, net of tax		655		—		2,732		—			—		240		(3,507	)		(775	)
Unrealized gain on marketable securities		—		—		—		—			26		—		—			26
September 30, 2023		102,322	$	10	$	975,177	$	(179,559	)	$	26		867	$	(8,493	)	$	787,161

	Nine Months Ended September 30, 2023
										Accumulated
					Additional					Other							Total
	Common Stock				Paid-In		Accumulated			Comprehensive		Treasury Stock					Stockholders’
	Shares		Amount		Capital		Deficit			Income		Shares		Amount			Equity
January 1, 2023		101,320	$	10	$	964,467	$	(280,555	)	$	—		564	$	(4,252	)	$	679,670
Net income		—		—		—		100,996			—		—		—			100,996
Stock-based compensation, net of tax		1,002		—		10,710		—			—		303		(4,241	)		6,469
Unrealized gain on marketable securities		—		—		—		—			26		—		—			26
September 30, 2023		102,322	$	10	$	975,177	$	(179,559	)	$	26		867	$	(8,493	)	$	787,161

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands)

	Three Months Ended September 30, 2022
					Additional										Total
	Common Stock				Paid-In		Accumulated			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Deficit			Shares		Amount			Equity
July 1, 2022		100,131	$	10	$	957,608	$	(233,627	)		18	$	(139	)	$	723,852
Net income		—		—		—		5,510			—		—			5,510
Stock-based compensation, net of tax		1,035		—		3,902		—			446		(3,075	)		827
September 30, 2022		101,166	$	10	$	961,510	$	(228,117	)		464	$	(3,214	)	$	730,189

	Nine Months Ended September 30, 2022
					Additional										Total
	Common Stock				Paid-In		Accumulated			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Deficit			Shares		Amount			Equity
January 1, 2022		100,075	$	10	$	945,039	$	(177,344	)		—	$	—		$	767,705
Net loss		—		—		—		(50,773	)		—		—			(50,773	)
Stock-based compensation, net of tax		1,091		—		16,471		—			464		(3,214	)		13,257
September 30, 2022		101,166	$	10	$	961,510	$	(228,117	)		464	$	(3,214	)	$	730,189

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Nine Months EndedSeptember 30,
	Three Months Ended March 31,
	2023			2022
	2024			2023
Operating activities:
Net income (loss)	$	100,996		$	(50,773	)
Net income	$	11,612		$	7,229
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Adjustments to reconcile net income to net cash
Depreciation		83,596			78,714
provided by (used in) operating activities:
Gain on disposition of assets		(4,102	)		(4,802	)
Depreciation		31,354			27,906
Loss on extinguishment of long-term debt		6,529			—
Loss (gain) on disposition of assets		3,396			(1,213	)
Deferred tax provision		(~~110~~7,~~651~~525	)		(2714,~~162~~457	)
Stock-based compensation expense		103,~~941~~590			164,~~471~~414
Contract liabilities		(7,111	)		(19,725	)
Contract liabilities, net		4,865			297
Contract assets		(4,183	)		1,330
Contract assets, net		10			(270	)
Deferred contract costs, net		(45,~~576~~867	)		(42,~~193~~560	)
Collateral deposits		(16,773	)		17,479
Other assets, noncurrent		860			(400	)
Other assets, noncurrent		3,489			(547	)
Other liabilities, noncurrent		(874	)		1,883
Other liabilities, noncurrent		12,581			(160	)
Other		963			706
Other		2,089			1,275
Changes in operating assets and liabilities:
Changes in operating assets and liabilities:
Accounts receivable		34,400			(15,023	)
Accounts receivable		3,659			(33,575	)
Prepaid expenses and other current assets		(128	)		(4,229	)
Prepaid expenses and other current assets		(29,259	)		(979	)
Accounts payable and accrued liabilities		(29,300	)		(7,796	)
Current income tax assets		(49,664	)		—
Taxes payable		(72	)		(4,664	)
Accounts payable and accrued liabilities		9,902			20,884
Net cash provided by (used in) operating activities		59,018			(8,177	)
Taxes payable		12,742			(16,167	)
Investing activities:
Net cash provided by (used in) operating activities		20,205			(21,930	)
Capital expenditures		(27,935	)		(29,413	)
Investing activities:
Proceeds from disposition of assets, net of disposal costs		3,805			663
Capital expenditures		(99,878	)		(42,653	)
Net cash used in investing activities		(24,130	)		(28,750	)
Proceeds from disposition of assets, net of disposal costs		857			5,861
Financing activities:
Net cash used in investing activities		(99,021	)		(36,792	)
Repayments under revolving credit facility		—			(15,000	)
Financing activities:
Principal payments of finance leases		(4,335	)		(4,079	)
Proceeds from issuance of second lien notes		550,000			—
Net cash used in financing activities		(4,335	)		(19,079	)
Borrowings under exit facilities		40,000			69,000
Net change in cash, cash equivalents and restricted cash		30,553			(56,006	)
Extinguishment of long-term debt		(192,182	)		—
Cash, cash equivalents and restricted cash, beginning of period		138,688			97,334
Repayments of exit facilities		(214,000	)		—
Cash, cash equivalents and restricted cash, end of period	$	169,241		$	41,328
Debt issuance costs and arrangement fees		(15,140	)		—
Principal payment of finance leases		(14,814	)		(11,765	)
Net cash provided by financing activities		153,864			57,235
Net change in cash, cash equivalents and restricted cash		75,048			(1,487	)
Cash, cash equivalents and restricted cash, beginning of period		97,334			62,729
Cash, cash equivalents and restricted cash, end of period	$	172,382		$	61,242

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

DIAMOND OFFSHORE DRILLING, INC. ~~AND SUBSIDIARIES~~

AND SUBSIDIARIES

NOTES TO UNAUDITED 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 Form 10-K for the year ended December 31, ~~2022~~2023.

Interim Financial Information

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (or GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission. Accordingly, pursuant to such rules and regulations, they do not include all disclosures required by GAAP for 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 ~~(loss)~~ 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.

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications did not have a material effect on our unaudited condensed consolidated financial statements.

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

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 ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~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 carrying value of the Ocean Monarch as “Asset held for sale” in our unaudited Condensed Consolidated Balance ~~Sheet~~Sheets at ~~September~~March 3031, ~~2023~~2024. AThe ~~broker~~rig ~~has~~was ~~been~~sold ~~engaged~~in toApril ~~assist~~2024 infor ~~marketing~~aggregate ~~the~~proceeds ~~rig~~of ~~for~~approximately ~~sale~~$7.5 million.

10Accounting Principles Not Yet Adopted

In December 2023, the Financial Accounting Standards Board (or FASB) issued Accounting Standards Update (or ASU) No. 2023-09, Income Tax (Topic 740): Improvements to Income Tax Disclosures (or ASU 2023-09). ASU 2023-09 requires business entities on an annual basis to (i) disclose specific categories in the rate reconciliation and (ii) provide additional information for reconciling items that meet certain quantitative thresholds. The 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, 2024, with early adoption permitted. We are in the process of evaluating the impact of adopting this new guidance on our consolidated financial statement disclosures.

2. Revenue from Contracts with Customers

~~The~~Our ~~activities~~contracts ~~that~~with ~~primarily~~customers ~~drive~~provide ~~the~~for ~~revenue~~an ~~earned~~offshore ~~from~~drilling ~~our~~rig ~~contract~~and drilling services on a dayrate contract basis. The integrated services provided under our contracts primarily include (i) ~~providing~~provision aof an offshore drilling rig, ~~and~~ the work crew and supplies of equipment and services necessary to operate the rig, (ii) ~~mobilizing~~mobilization and ~~demobilizing~~demobilization of the rig to and from the drill site and (iii) ~~performing~~performance of rig preparation activities and/or modifications required for ~~the~~each contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services provided within our drilling contracts as a single performance obligation satisfied over time and comprised of a series of distinct time increments in which we provide drilling services.

~~Consideration~~We account for ~~activities~~the ~~that~~integrated ~~are~~services ~~not~~provided ~~distinct~~ within ~~the context of~~ our drilling contracts ~~and~~as ~~do not correspond to~~ a ~~distinct time increment within the contract term are allocated across the~~ single performance obligation ~~and~~satisfied ~~recognized ratably~~ over ~~the~~time, ~~initial~~comprised ~~term~~ of ~~the~~a ~~contract~~series ~~(which~~of is the period we estimate to be benefited from the corresponding activities and generally ranges from two to 60 months). Such consideration may include mobilization, demobilization, contract preparation and capital modification revenue that is stipulated in our drilling contracts. Consideration for activities that correspond to a distinct time ~~increment~~increments ~~within the contract term is recognized~~ in ~~the~~which ~~period~~we ~~when~~provide ~~the~~drilling services ~~are performed~~. The total transaction price is ~~determined~~recognized for each ~~individual~~drilling contract by estimating both fixed and variable consideration expected to be earned over the ~~term of the~~ contract term.

Revenues Related to Managed Rigs

WeIn ~~are~~2021, ~~participants~~we inentered into an arrangement with an offshore drilling company whereby we would provide management and marketing services (or the ~~MSA~~MMSA) for certain of ~~its~~their rigs. ~~Per~~The ~~the~~MMSA ~~MSA,~~provided for ~~stacked~~(i) ~~rigs we earn~~ a daily ~~service~~fixed fee, ~~and~~based ~~are~~on ~~entitled~~status toof ~~reimbursement~~the ofdrilling ~~direct~~rig, ~~costs~~(ii) ~~incurred~~marketing infees ~~accordance~~based ~~with~~on a percentage of the ~~agreement.~~earned ~~The~~dayrate ~~daily~~of ~~service~~a ~~fee~~drilling ~~revenue~~contract issecured ~~recognized~~by inus ~~line~~on ~~with~~behalf of the ~~contractual~~rig ~~rate~~owner, ~~billed~~(iii) ~~for~~a ~~the~~variable ~~services~~management ~~provided~~fee and is(iv) ~~reported~~reimbursement of direct cost incurred. The fixed and variable fees were recognized in “Contract drilling” revenue” in our unaudited Condensed Consolidated Statements of Operations. WeRevenue ~~record~~related ~~the revenue relating~~ to ~~reimbursed expenses at~~ the ~~gross~~reimbursement ~~amount~~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. In April 2023, we received notice of termination of the marketing arrangement for the managed rigs, which will be effective in the third quarter of 2023. However, termination of the marketing arrangement does not impact the management services that we provide under the MSA.

~~The~~We ~~managed~~may ~~rigs~~enter ~~West~~into ~~Auriga~~certain drilling contracts directly with a customer. We are considered principal or agent of these transactions and ~~West~~recognize ~~Vela~~revenue ~~commenced~~under ~~operations~~the interms of the Ucontract.S. ~~Gulf~~Such ofamounts ~~Mexico~~are ~~(or~~reported ~~GOM)~~as “Contract drilling” revenue in ~~2022.~~our ~~Both~~unaudited ~~rigs~~Condensed ~~are~~Consolidated ~~currently~~Statements ~~under~~of ~~contract;~~Operations. ~~however~~In addition, we ~~expect~~charter ~~each~~the related drilling rig from the rig owner to ~~complete~~satisfy ~~their~~our ~~respective~~performance ~~contracts~~obligation under the contract. We have determined that the arrangement to charter the rig is an operating lease, and the related charter fee has been reported as lease expense within "Contract drilling, excluding depreciation" in ~~2024~~our unaudited Condensed Consolidated Statements of Operations.

~~Upon~~The ~~commencement~~marketing arrangements for each of ~~drilling~~the ~~operations~~managed rigs, the ~~MSA~~West ~~for~~Auriga ~~both~~and ~~rigs~~the ~~was~~West ~~suspended~~Vela, ~~and~~were ~~replaced~~terminated byin a2023. ~~charter~~Additionally, ~~agreement~~the ~~for~~management ~~the~~and ~~duration~~charter ofagreements for the ~~drilling~~West ~~contracts.~~Auriga Wewere ~~entered~~terminated ~~into~~in the ~~drilling~~first ~~contract~~quarter ~~directly~~of ~~with~~2024, and the ~~customer~~rig ~~and~~was ~~recognize~~returned ~~revenue~~to ~~under~~its owner at the ~~terms~~end of ~~the~~February ~~contract~~2024. We ~~report~~also ~~such~~received ~~revenue~~notice asof ~~“Contract~~termination ~~drilling~~of ~~revenue”~~the management agreement for the West Vela in ~~our~~April ~~unaudited~~2024, ~~Condensed~~which ~~Consolidated~~will ~~Statements~~become ofeffective ~~Operations~~after 90 days. InThe ~~addition,~~termination weof the management agreement will have ~~determined~~no ~~that~~effect on the bareboat charter ~~arrangement~~agreement isfor anthe ~~operating~~West ~~lease~~Vela, ~~and~~which ~~the~~provides ~~related~~that ~~charter~~it ~~fee~~will ~~has~~continue ~~been~~in ~~reported~~accordance aswith ~~lease~~its ~~expense~~terms ~~within~~until ~~"Contract~~the ~~drilling,~~completion ~~excluding~~of ~~depreciation"~~the inrig’s ~~our~~existing ~~unaudited~~drilling ~~Condensed~~contract ~~Consolidated~~and ~~Statements~~any ofoption ~~Operations~~periods.

Contract Balances

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

	September 30,			December 31,
	March 31,			December 31,
	2023			2022
	2024			2023
Trade receivables	$	~~170~~206,~~596~~830		$	~~155~~253,~~956~~367
Current contract assets (1)		42,~~324~~565			~~141~~2,575
Current contract liabilities (deferred revenue) (1)		(417,~~888~~833	)		(1112,~~513~~634	)
Noncurrent contract liabilities (deferred revenue) (1)		—(3,613	)		(~~487~~3,947	)

(1)

Contract assets and contract liabilities may reflect balances which have been netted together on a contract 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 contract assets and the contract liabilities balances during the period are as follows (in thousands):

	Contract			Contract
	Assets			Liabilities
Balance as of December 31, 2022	$	141		$	(12,000	)
Balance as of January 1, 2024	$	2,575		$	(16,581	)
Decrease due to amortization of revenue included in the beginning contract liability balance		—			93,~~266~~185
Increase due to cash received, excluding amounts recognized as revenue during the period		—			(28,~~154~~050	)
Increase due to revenue recognized during the period but contingent on future performance		~~6,551~~391			—
Decrease due to transfer to receivables during the period		(~~2,368~~323	)		—
Balance as of September 30, 2023	$	4,324		$	(4,888	)
Adjustments		(78	)		—
Balance as of March 31, 2024	$	2,565		$	(21,446	)

Transaction Price Allocated to Remaining Performance Obligations

The following table reflects ~~the specified types of~~ revenue expected to be recognized in the future related to unsatisfied performance obligations as of ~~September~~March 3031, ~~2023~~2024 (in thousands):

	For the Years Ending December 31,
	For the Year Ending December 31,
	2023 (1)			2024			Total
	2024 (1)			2025			2026			2027			Total
Mobilization and contract preparation revenue	$	(~~633~~4,317	)	$	(~~933~~1,365	)	$	(1,~~566~~337	)	$	(1,271	)	$	(8,290	)
Capital modification revenue		(12,~~673~~954	)		(~~1,649~~142	)		~~(3,322~~—	)		—			(3,096	)
Total	$	(2,306	)	$	(2,582	)	$	(4,888	)
Blended rate/other revenue		(10,060	)		—			—			—			(10,060	)
Total	$	(17,331	)	$	(1,507	)	$	(1,337	)	$	(1,271	)	$	(21,446	)

(1)

Represents the ~~three~~nine-month period beginning ~~October~~April 1, ~~2023~~2024.

The revenue included above consists of expected fixed mobilization and upgrade revenue for both wholly and partially unsatisfied performance obligations, as well as expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. The actual timing of recognition of such amounts may vary due to factors outside of our control. We have applied ~~certain~~the disclosure practical ~~expedients~~expedient ~~and~~in FASB ASU No. 2014-09, ~~accordingly~~Revenue from Contracts with Customers (Topic 606), and its related amendments and have excluded estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue.

1210

3. Supplemental Financial Information

Unaudited Condensed Consolidated Balance Sheets Information

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

	September 30,			December 31,
	March 31,			December 31,
	2023			2022
	2024			2023
Trade receivables	$	~~170~~206,~~596~~830		$	~~155~~253,~~956~~367
Value added tax receivables		5,560			6,075
Insurance claim receivable (1)		11,688			—
Related party receivables		42			73
Value added tax receivables		6,167			5,256
Federal income tax receivables		—			9,450
Related party receivables		75			155
Other		~~925~~894			61,~~121~~346
		177,123			177,675
		225,654			260,124
Allowance for bad debts		(5,698	)		(5,622	)
Allowance for credit losses (2)		(5,731	)		(5,801	)
Total	$	~~171~~219,~~425~~923		$	~~172~~254,~~053~~323

(1)

~~The allowance for credit losses at September 30, 2023 and December 31, 2022 represents our estimate of credit losses associated with our “Trade receivables” and “Current contract assets.”~~ See Note 48 “~~Financial~~Ocean ~~Instruments~~GreatWhite ~~and~~Insurance ~~Fair Value Disclosures~~Claim” for a discussion of ~~our~~an ~~concentrations~~insurance ofclaim ~~credit~~associated ~~risk~~with ~~and~~an ~~allowance~~equipment ~~for~~incident ~~credit~~on ~~losses~~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 (in thousands):

	September 30,		December 31,
	March 31,		December 31,
	2023		2022
	2024		2023
Current income tax asset	$	49,664	$	—
Deferred contract costs	$	15,211	$	20,552
Prepaid taxes		21,918		16,922
Collateral deposit		11,857		11,857
Deferred contract costs		17,525		14,373
Prepaid taxes		7,526		10,868
Collateral deposit		16,773		—
Rig spare parts and supplies		6,981		4,694
Rig spare parts and supplies		10,824		5,091
Current contract assets		2,565		2,575
Prepaid insurance		42,~~457~~117		3,~~022~~437
Current contract assets		4,324		141
Prepaid rig costs		1,978		3,668
Prepaid rig costs		4,185		4,001
Software maintenance agreements and subscriptions		1,650		1,408
Software maintenance agreements and subscriptions		1,560		1,212
Deferred survey costs		1,386		1,418
Deferred survey costs		1,240		838
Other		6,131		2,935
Other		3,741		3,095
Total	$	57,402	$	63,412
Total	$	136,211	$	48,695

Accrued liabilities consist of the following (in thousands):

	September 30,		December 31,
	March 31,		December 31,
	2023		2022
	2024		2023
Contract advances	$	52,414	$	52,743
Rig operating costs	$	47,316	$	42,893
Rig operating costs		36,692		39,288
Contract advances		33,225		63,618
Payroll and benefits		3326,~~211~~260		2935,~~408~~215
Accrued capital project/upgrade costs		13,764		8,419
Interest payable		24,691		13,013
Personal injury and other claims		6,198		3,738
Deferred revenue		17,833		12,634
Shorebase and administrative costs		5,457		4,365
Personal injury and other claims		6,217		7,391
Current operating lease liability		48,~~905~~171		138,~~480~~436
Deferred revenue		4,888		11,513
Accrued capital project/upgrade costs		8,059		10,766
Interest payable		1,334		1,897
Deposit for equipment sale		5,902		1,977
Deposit for equipment sale		1,207		1,670
Shorebase and administrative costs		4,967		5,699
Other		32,~~342~~491		~~264~~1,694
Total	$	~~163~~185,~~412~~132	$	~~166~~203,~~785~~336

1311

Other assets consist of the following (in thousands):

	September 30,		December 31,
	2023		2022
Noncurrent deferred tax assets	$	121,264	$	10,612
Operating lease right of use assets		18,810		30,332
Noncurrent receivables		8,677		13,030
Noncurrent milestone payments		5,804		856
Deferred debt arrangement fees		4,188		6,716
Deferred inspection costs, noncurrent		3,829		2,489
Noncurrent deposits		1,461		1,531
Other		3,420		2,400
Total	$	167,453	$	67,966

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 are as follows (in thousands):

	Nine Months EndedSeptember 30,
	Three Months Ended March 31,
	2023			2022
	2024			2023
Accrued but unpaid capital expenditures at period end	$	138,~~764~~059		$	211,~~226~~697
Common stock withheld for payroll tax obligations (1)		~~4,241~~661			~~3,214~~134
Cash interest payments		~~30,552~~—			177,~~718~~488
Cash income taxes paid, net of (refunds):
Foreign		51,~~603~~851			121,~~187~~258
U.S. Federal		~~(5,019~~130	)		2(8,~~855~~966	)
State		1			—

(1)

Represents the cost of 302,833 and ~~463~~10,~~951~~946 shares of common stock withheld to satisfy payroll tax obligations incurred as a result of the vesting of restricted stock and restricted stock units during the ~~nine~~three-month periods ended ~~September~~March 3031, ~~2023~~2024 and ~~September~~March 3031, ~~2022~~2023, respectively, which is presented as a deduction from stockholders’ equity in “Treasury stock” in our unaudited Condensed Consolidated Balance Sheets.

4. Financial Instruments and Fair Value Disclosures

Concentrations of Credit Risk and Allowance for Credit Losses

Our credit risk ~~corresponds~~arises primarily tofrom trade receivables. The market for our services is the offshore oil and gas industry, and our customer base consists primarily of major and independent oil and gas companies, as well as government-owned oil companies. At ~~September~~March 3031, ~~2023~~2024, we believed that we had potentially significant concentrations of credit risk 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, we perform a credit review on that customer, including a review of its credit ratings and financial statements. Based on our credit review, we may require that the customer have a bank issue a letter of credit on its behalf, prepay for the services in advance or provide other credit enhancements. AtWe ~~September~~currently ~~30,~~have ~~2023,~~one wecustomer ~~had~~for ~~not~~which ~~required~~prepayments ~~any~~are ~~credit~~required ~~enhancements~~and byfull ~~our~~payment ~~customers~~is ordue ~~required~~prior ~~any~~ to ~~pay~~commencement ~~for~~of ~~services in advance. We have historically used~~ the ~~specific~~contract ~~identification method to identify and reserve for uncollectible accounts. The amounts reserved for uncollectible accounts~~ in ~~previous~~the ~~periods~~second ~~have~~half ~~not~~of ~~been significant, individually or in comparison to our total revenues~~2024. At ~~September~~March 3031, ~~2023~~2024, ~~$6.6~~no ~~million~~amounts ~~in trade receivables~~ were ~~considered~~owed ~~past due~~ by 30this ~~days or more, of which $5~~customer.5 million have been fully reserved. The remaining $1.1 million were less than a year past due. We are working with our customers to resolve any billing issues and expect that the outstanding receivables will be collected or resolved.

14Pursuant 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 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 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 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 it would be 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.

~~Pursuant~~At toMarch ~~Financial~~31, ~~Accounting~~2024, ~~Standards Board (or FASB) Accounting Standards Update No~~$8.5 ~~2016-13,~~million ~~Financial~~in ~~Instruments~~trade –receivables ~~Credit~~were ~~Losses~~considered ~~(Topic~~past ~~326):~~due ~~Measurement~~by of30 ~~Credit~~days ~~Losses on Financial Instruments and its related amendments (~~or ~~collectively~~more, ~~CECL),~~of wewhich ~~have~~$5.4 ~~reviewed~~million ~~our~~have ~~historical~~been ~~credit~~fully ~~loss~~reserved. ~~experience~~The ~~over~~remaining a$3.1 ~~look-back~~million ~~period~~were ofless ~~ten~~than ~~years,~~a ~~which~~year wepast ~~deem~~due ~~to be representative of both up-turns~~ and ~~down-cycles~~considered ~~in the offshore drilling industry~~collectible. ~~Based~~For onpurposes ~~this~~of ~~review,~~calculating weour ~~developed~~current aestimate ~~credit loss factor using a weighted-average ratio~~ of ~~our actual~~ credit losses toat ~~revenues~~March ~~during the look-back period. In addition~~31, we2024 ~~also considered current~~ and ~~future~~December ~~anticipated~~31, ~~economic~~2023, ~~conditions~~all intrade ~~determining our credit loss factor~~receivables, ~~including~~except ~~crude~~for ~~oil~~those ~~prices~~fully ~~and liquidity of credit markets. In applying the requirements of CECL~~reserved, wewere ~~segregated~~deemed ~~our~~to ~~trade~~be ~~receivables~~in ~~into~~a ~~three~~single ~~credit loss~~ risk ~~pools~~pool based on ~~customer~~their credit ratings, at each ofrespective ~~which~~period. ~~represents~~Our atotal ~~tier~~allowance offor ~~increasing~~ credit ~~risk.~~losses Wewas ~~calculated~~$5.7 amillion ~~credit loss factor based on historical loss rate information~~ and ~~then~~$5.8 ~~applied~~million aat ~~multiple~~March ~~of our credit loss factor to each of these risk pools~~31, ~~considering~~2024 ~~the impact of current~~ and ~~future~~December ~~economic~~31, ~~information~~2023, ~~and the level of risk associated with these pools~~respectively, toincluding ~~calculate our current estimate of credit losses~~$0.3 ~~Trade~~million ~~receivables that are fully covered by allowances~~ for ~~credit~~each ~~losses~~period ~~are~~related ~~excluded~~to ~~from these risk pools for purposes of calculating~~ our current estimate of credit losses.

For purposes of calculating our current estimate of credit losses at September 30, 2023 and December 31, 2022, all trade receivables were deemed to be in a single risk pool based on their credit ratings at each respective period. Our current estimate of credit losses under CECL was $0.2 million at both September 30, 2023 and December 31, 2022. Our total allowance for credit losses was $5.7 million and $5.6 million at September 30, 2023 and December 31, 2022, respectively. See Note 3 “Supplemental Financial Information.”12

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 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 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.

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.

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

	September 30, 2023
	March 31, 2024
	Fair Value Measurements Using
	Level 1			Level 2		Level 3		Assets (Liabilities) at Fair Value			Total Losses for ~~Nine~~Three Months Ended (2)
Recurring fair value measurements:
Short-term investments (1)	$	~~109~~63,880		$	—	$	—	$	~~109~~63,880		$	—
Liability-classified Director restricted stock units		(1,417	)		—		—		(1,417	)		(413	)
Liability-classified Director restricted stock units (2)	$	(1,326	)	$	—	$	—	$	(1,326	)	$	(62	)

Represents short-term investments in debt securities classified as available-for-sale. As the original maturities of these debt securities are three months or less, we have reported that our $109.9 million investment in these debt securities as Cash and cash equivalents in our unaudited Condensed Consolidated Balance Sheet at September 30, 2023.


	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	)

(1)

Represents anshort-term ~~increase~~investments, inwith ~~stock~~original ~~compensation~~maturities ~~expense~~of ~~due~~three tomonths ~~the~~or ~~“marking-to-market”~~less, ofin ~~liability-classified~~debt ~~restricted~~securities ~~stock~~classified ~~units~~as ~~granted~~available tofor ~~our non-employee directors~~sale.

(2)

	December 31, 2022
	Fair Value Measurements Using
	Level 1			Level 2		Level 3		Liabilities at Fair Value			Total Losses for Year Ended (1)
Recurring fair value measurements:
Liability-classified Director restricted stock units	$	(1,258	)	$	—	$	—	$	(1,258	)	$	(230	)

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

~~Represents an increase in stock compensation expense due to the “marking-to-market” of liability-classified restricted stock units granted to our non-employee directors.~~13

Wecompensation ~~believe~~expense ~~that~~due to the ~~carrying amounts of our other financial assets and liabilities (excluding our Second Lien Notes, Exit Term Loans and First Lien Notes (each as defined below in Note 6~~ “~~Long~~marking-~~Term Debt~~to-market”~~)),~~ ~~which~~of ~~are~~liability-classified ~~not~~restricted ~~measured~~stock atunits ~~fair~~granted ~~value~~to in our ~~unaudited~~non-employee ~~Condensed~~directors ~~Consolidated Balance Sheets, approximate fair value based~~ on ~~the~~a ~~following~~recurring ~~assumptions:~~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.

~~Exit~~Our ~~RCF~~long-term ~~borrowings~~debt –is ~~The~~not ~~carrying~~measured ~~amount~~at offair ~~borrowings~~value on a recurring basis; however, under ~~our~~the ~~Exit~~GAAP ~~RCF~~fair ~~(as~~value ~~defined~~hierarchy, ~~below~~such inindebtedness ~~Note~~would 6be ~~“Long-Term~~considered ~~Debt”)~~Level ~~approximates~~2 liabilities. The fair value ~~since~~of the ~~variable~~instrument ~~interest~~was ~~rates~~derived ~~are~~using ~~tied~~valuation tospecialists ~~current~~at ~~market~~March ~~rates~~31, 2024 and ~~the~~December ~~applicable~~31, ~~margins represent market rates~~2023.

16Fair values and related carrying values of our Second Lien Notes (as defined below in Note 6 “Long-Term Debt”) are shown below (in millions).

Our long-term debt is not measured at fair value on a recurring basis; however, under the GAAP fair value hierarchy, our long-term debt would be considered Level 2 liabilities. The fair value of these instruments was derived using valuation specialists at September 30, 2023 and December 31, 2022.


	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

~~Fair~~We ~~values~~have estimated the fair value amounts by using appropriate valuation methodologies and ~~related~~information ~~carrying~~available to management. 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 ~~our~~the ~~long-term~~amounts ~~debt~~that ~~are~~would ~~shown~~be ~~below~~realized (in ~~millions)~~a free market exchange.

	September 30, 2023				December 31, 2022
	Fair Value		Carrying Value		Fair Value		Carrying Value
Second Lien Notes	$	550.4	$	550.0	$	—	$	—
Exit Term Loans		—		—		91.1		100.0
First Lien Notes		—		—		78.3		85.3

We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange.

5. Drilling and Other Property and Equipment

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

	September 30,			December 31,
	March 31,			December 31,
	2023			2022
	2024			2023
Drilling rigs and equipment	$	1,~~219~~272,~~768~~564		$	1,~~126~~244,~~793~~798
Finance lease right of use asset		174,571			174,571
Land and buildings		10,~~034~~064			10,~~001~~040
Office equipment and other		35,~~492~~317			25,~~515~~180
Cost		1,~~407~~462,~~865~~516			1,~~313~~434,~~880~~589
Less: accumulated depreciation		(~~250~~309,~~528~~476	)		(~~171~~278,~~972~~221	)
Drilling and other property and equipment, net	$	1,~~157~~153,~~337~~040		$	1,~~141~~156,~~908~~368

6. Long-Term Debt

At ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, the carrying value of our long-term debt, net of unamortized discount, premium and debt issuance costs, was comprised as follows (in thousands):

	September 30,		December 31,
	March 31,			December 31,
	2023		2022
	2024			2023
$550 Million Senior Secured Second Lien Notes due 2030	$	~~535~~534,~~194~~009	$	—$	533,514
Exit Debt
Borrowings under Exit RCF		—		177,478
$100.0 Million Exit Term Loan		—		99,190
9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027		—		83,976
Total Exit Debt, net		—		360,644
Total long-term debt, net	$	535,194	$	360,644

Second Lien Notes

On September 21, 2023, Diamond Foreign Asset Company ~~(or DFAC), a wholly owned subsidiary of Diamond Offshore Drilling, Inc. (or DODI),~~ and Diamond Finance, LLC, ~~a wholly owned subsidiary of DFAC~~ (~~or,~~collectively ~~together~~referred ~~with~~to ~~DFAC,~~as the Issuers), issued $550.0 million aggregate principal amount of 8.5% Senior Secured Second Lien Notes due October 2030 (or ~~Second Lien Notes) in a private placement (or Notes Offering) conducted pursuant to Rule 144A and Regulation S under~~ the ~~Securities Act of 1933, as amended. The~~ Second Lien Notes were issued at par for net proceeds of approximately $540 million after deduction of certain estimated offering expenses. The Second Lien Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured basis by DODI and each of its existing restricted subsidiaries (other than the Issuers) ~~and~~with byinterest ~~certain~~payable ofsemi-annually ~~DODI’s future restricted subsidiaries (other than the Issuers) that guarantee any debt of the Issuers or any guarantor under any syndicated credit facility or capital markets debt~~ in anarrears ~~aggregate~~on ~~principal~~April ~~amount~~1 ~~in excess of a certain amount (or, collectively, the Subsidiary Guarantors~~ and, ~~together~~October ~~with~~1 ~~DODI, the Guarantors). The Second Lien Notes and the related guarantees are secured on a second-priority basis, subject to certain permitted liens, by substantially all the assets~~ of, ~~and equity interests in, the Issuers and the Subsidiary Guarantors.~~

The Second Lien Notes are governed by an Indenture, dated as of September 21, 2023 (or Indenture), entered into among the Issuers, DODI and certain of its subsidiaries named therein and HSBC Bank USA, National Association (or HSBC), as trustee (or Trustee) and collateral agent (or Collateral Agent). The Second Lien Notes will mature on October 1, 2030. Interest on the Second Lien Notes is payable semi-annually in arrears on April 1 and October 1 of each year, beginning on April 1, 2024. The Second Lien Notes are fully and unconditionally guaranteed, jointly and severally, by the Guarantors and by each of DODI’s existing restricted subsidiaries (other than the Issuers) that is a borrower under or a guarantor of our revolving credit facility (see “– Amended Revolving Credit Agreement”) and certain future subsidiaries.14

Oneach ~~or after October 1~~year, ~~2026,~~beginning ~~the~~on ~~Issuers~~April ~~may~~1, at2024. ~~their~~The ~~option, redeem all or any portion of the~~ Second Lien Notes ~~from~~are ~~time~~fully toand ~~time~~unconditionally ~~upon not less than 10 days nor more than 60 days prior notice~~guaranteed, atjointly ~~the~~and ~~redemption prices set forth below~~severally, ~~plus~~on ~~accrued~~a ~~and~~senior ~~unpaid~~secured ~~interest,~~basis ifby ~~any,~~Diamond ~~to,~~Offshore ~~but excluding~~Drilling, ~~the redemption date~~Inc. ~~The~~(or ~~following~~DODI) ~~prices~~and ~~are~~each ~~for~~of ~~Second~~its ~~Lien~~existing ~~Notes~~restricted ~~redeemed~~subsidiaries ~~during~~(other than the ~~12-month~~Issuers) ~~period~~and ~~commencing~~by oncertain ~~October 1~~ of ~~the~~DODI’s ~~years~~future ~~set~~restricted ~~forth~~subsidiaries ~~below,~~(other ~~and~~than ~~are~~the ~~expressed~~Issuers). ~~as percentages of principal amount:~~

Redemption Year	Price
2026		104.250	%
2027		102.125	%
2028 and thereafter		100.000	%

The Second Lien Notes obligate DODI and 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 or substantially all of DODI’s assets. These covenants are subject to important exceptions and qualifications.

AtThe ~~any time and from time to time, prior to October 1, 2026, the Issuers may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of the~~ Second Lien Notes ~~issued~~were ~~under~~valued ~~the~~at ~~Indenture~~par ~~(including~~at ~~any~~issuance ~~additional~~and ~~Second~~were ~~Lien~~presented ~~Notes,~~net ifof ~~any)~~unamortized ~~with~~debt anissuance ~~amount~~costs ~~equal to or less than the net cash proceeds~~ of ~~one~~$16.0 ormillion ~~more~~and ~~equity~~$16.5 ~~offerings~~million, at aMarch ~~redemption price equal to 108.500% of the principal amount thereof~~31, ~~plus~~2024 ~~accrued~~ and ~~unpaid~~December ~~interest thereon~~31, ~~if any~~2023, torespectively. ~~but~~At ~~excluding,~~March ~~the redemption date provided~~31, ~~however~~2024, ~~that immediately after giving effect to any such redemption, at least 65% of~~ the ~~original~~effective ~~aggregate~~interest ~~principal~~rate ~~amount of Second Lien Notes issued~~ on the ~~issue date (excluding~~ Second Lien Notes ~~held~~was ~~by DODI or its subsidiaries) remains outstanding~~9. 10%.

InRevolving ~~addition,~~Credit at any time prior to October 1, 2026, the Issuers may redeem up to 10% of the original aggregate principal amount of the Second Lien Notes issued under the Indenture (including additional Second Lien Notes, if any) during any twelve-month period at a redemption price equal to 103.000% of the aggregate principal amount thereof, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.Agreement

AtOur ~~any~~revolving ~~time~~credit ~~prior~~agreement toprovides ~~October~~for 1a $300.0 million senior secured revolving credit facility (or RCF), ~~2026~~which will mature on April 22, 2026. Borrowings under the ~~Issuers~~RCF may ~~redeem~~be ~~some~~used orto ~~all~~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 ~~Second~~RCF ~~Lien~~is ~~Notes~~subject atto athe ~~price~~satisfaction ~~equal~~of certain conditions, including restrictions on borrowings if, after giving effect to ~~100%~~any such borrowings and the application of the ~~principal~~proceeds thereof, (i) the aggregate amount of Available Cash (as defined in the ~~Second~~RCF) ~~Lien~~would ~~Notes~~exceed ~~redeemed~~$125.0 million, ~~plus~~(ii) ~~accrued~~the ~~and~~RCF ~~unpaid~~Collateral ~~interest,~~Coverage ifRatio ~~any,~~(as defined in the RCF) would be less than 2.00 to, ~~but~~1.00 ~~not~~or ~~including,~~(iii) the ~~redemption~~Total ~~date,~~Collateral ~~plus~~Coverage aRatio ~~“make-whole”~~(as ~~premium~~defined in the RCF) would be less than 1.30 to 1.00.

18At 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.

~~The~~There ~~Indenture~~is ~~contains~~no ~~covenants~~capacity ~~that,~~for ~~among other things, restrict DODI’s ability and~~ the ~~ability~~issuance of ~~certain~~new ofletters 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~~credit ~~assets;~~under ~~(v)~~the ~~engage in certain transactions with affiliates; and (vi) merge~~RCF, ~~consolidate,~~but ~~amalgamate or sell, transfer, lease or otherwise dispose of all or substantially all of~~ the ~~DODI’s~~RCF ~~assets.~~permits ~~These~~us ~~covenants~~to ~~are~~obtain ~~subject~~up to ~~important exceptions and qualifications~~$50.0 Inmillion ~~addition,~~in ~~many~~letters of ~~these~~credit ~~covenants~~outside ~~will be suspended with respect to~~ the ~~Second~~RCF. ~~Lien~~We ~~Notes during any time that the Second Lien Notes~~ have ~~investment~~obtained ~~grade~~a ~~ratings~~separate ~~from~~$25.0 atmillion ~~least~~letter ~~two~~of ~~rating~~credit ~~agencies~~facility; ~~and~~however, noletters ~~default~~of ~~with~~credit ~~respect~~thereunder tomust ~~the~~be ~~Second~~cash ~~Lien Notes has occurred and is continuing~~collateralized.

~~Upon~~At ~~the~~March ~~occurrence~~31, of2024, ~~certain~~we ~~Change~~were ~~of Control Triggering Event (as defined~~ in ~~the~~compliance ~~Indenture),~~with ~~the Issuers may be required to make an offer to repurchase~~ all ofcovenants under the Second Lien Notes ~~then outstanding at a price equal to 101% of the principal amount thereof, plus accrued~~ and ~~unpaid interest, if any, to, but excluding,~~ the ~~repurchase date~~RCF.

We used a portion of the net proceeds from the Notes Offering to fully repay outstanding borrowings and terminate our Exit Term Loan Credit Facility (as defined below), redeem in full our 9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027 (or First Lien Notes) and repay all amounts outstanding under the Exit RCF (as defined below). We intend to use the remaining net proceeds for general corporate purposes.

The Second Lien Notes were valued at par and are presented net of debt issuance costs of $14.8 million, which are being amortized as interest expense over the stated maturity of the notes using the effective interest method. At September 30, 2023, the effective interest rate on the Second Lien Notes was 9.02%.

Amended Revolving Credit Agreement

On April 23, 2021, we entered into a senior secured revolving credit agreement (or the Exit Revolving Credit Agreement), which provided for a $400.0 million senior secured revolving credit facility and also provided for certain lenders (or the LC Lenders) to issue up to $100.0 million of letters of credit thereunder (or the Exit RCF). As a result of the resignation of two LC Lenders since entering into the Exit Revolving Credit Agreement, the aggregate amount of the commitments of the LC Lenders to issue letters of credit under the Exit RCF was reduced from $100.0 million to $75.0 million effective September 30, 2022, and further reduced to $50.0 million effective March 23, 2023.

On June 13, 2023, Wells Fargo Bank, National Association (or Wells Fargo) gave notice of its resignation as Collateral Agent, Administrative Agent and Issuing Lender (as such terms are defined in the Exit Revolving Credit Agreement) under the Exit Revolving Credit Agreement. And on August 10, 2023, DODI entered into an Agency Assignment Agreement and Master Assignment of Liens (or Agency Assignment Agreement) pursuant to which HSBC was appointed (i) as successor administrative agent under the Exit Revolving Credit Agreement and our $100,000,000 Term Loan Agreement, dated as of April 23, 2021 (or the Exit Term Loan Agreement), and (ii) as collateral agent under the Company’s Collateral Agency and Intercreditor Agreement, dated as of April 23, 2021 (or Intercreditor Agreement). Other than as modified by the Agency Assignment Agreement, each of the Exit Revolving Credit Agreement, the Exit Term Loan Agreement and the Intercreditor Agreement remained in full force and effect. In connection with this change, Wells Fargo, as resigning administrative agent under the Exit Revolving Credit Agreement and Exit Term Loan Agreement and as resigning collateral agent under the Intercreditor Agreement, assigned to HSBC, and HSBC assumed, all of the rights and obligations of Wells Fargo in such capacities under the Exit Revolving Credit Agreement, the Exit Term Loan Agreement and the Intercreditor Agreement, respectively.

Wells Fargo continues to have all of the rights and obligations of an Issuing Lender under the Exit RCF with respect to letters of credit issued by it prior to its resignation but, after the effective date of its resignation, is not required to issue additional letters of credit or extend, renew or increase the outstanding letters of credit. Wells Fargo had previously committed to issue up to $25.0 million in letters of credit under the Exit RCF. The LC Lenders, including Wells Fargo, have committed to issue letters of credit under the Exit RCF up to $50.0 million in total. As a result of the resignation of Wells Fargo, the aggregate amount of the commitments of the LC Lenders to issue letters of credit under the Exit RCF is $25.0 million. Wells Fargo had previously issued letters of credit under the Exit RCF aggregating $16.9 million and $1.9 million, which would have expired in October 2023 and May 2024, respectively. The $16.9 million letter of credit was subsequently called by the holder upon replacement of Wells Fargo as Collateral Agent, Administrative Agent and Issuing Lender. We have since cash collateralized the performance bond placed by a third party (see Note 7 “Commitments and Contingencies”). Upon expiration of the letter of credit, Wells Fargo will have no further obligation as an Issuing Lender with respect to letters of credit.

On September 12, 2023, DFAC, as borrower, DODI, as parent, certain of the lenders party thereto, and HSBC, as administrative agent and collateral agent, entered into an amendment (or Credit Agreement Amendment) to the Exit Revolving Credit Agreement. The Credit Agreement Amendment amended the Exit RCF (or, as amended, the Amended RCF) to, among other things, (i) reduce the aggregate commitment of the lenders thereunder from $400.0 million to $300.0 million, (ii) permit the Notes Offering and (iii) provide for obligations in respect of letters of credit in an aggregate principal amount not to exceed $50.0 million. The Credit Agreement Amendment became effective concurrently with the consummation of the Notes Offering, which was conditioned on the Credit Agreement Amendment becoming effective.

On October 24, 2023, Barclays Bank PLC (or Barclays), gave notice of its resignation as an LC Lender under the Amended RCF. Barclays’ resignation will become effective on November 23, 2023, at which time our capacity for the issuance of additional letters of credit under the Amended RCF will be reduced to zero.

Borrowings under the Amended RCF may be used to finance capital expenditures, for working capital and other general corporate purposes. Availability of borrowings under the Amended RCF is subject to the satisfaction of certain conditions, including restrictions on borrowings, as provided in the Credit Agreement Amendment.

On September 21, 2023, we repaid the aggregate principal amount of borrowings outstanding under the Amended RCF of approximately $189.0 million plus accrued and unpaid interest thereon through the repayment date in full with a portion of the proceeds of the Notes Offering. In addition, we wrote off a pro rata portion of unamortized deferred debt arrangement fees related to the reduction in borrowing capacity under the Amended RCF. We reported the $1.3 million write-off of fees as “Loss on extinguishment of long-term debt” in our unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2023.

At September 30, 2023 and November 6, 2023, we had no borrowings outstanding under the Amended RCF and had utilized $1.9 million for the issuance of letters of credit. The outstanding letter of credit will expire on maturity in May 2024, unless replaced. At November 6, 2023, we had no borrowings outstanding under the Amended RCF. As of November 6, 2023, approximately $298.1 million was available for borrowings under the Amended RCF subject to its terms and conditions. There was no capacity to issue additional letters of credit under the Amended RCF.

At September 30, 2023, we were in compliance with all covenants under the Second Lien Notes and Amended RCF.

$100.0 Million Exit Term Loan

Our Exit Term Loan Agreement provided for a $100.0 million senior secured term loan credit facility (or the Exit Term Loan Credit Facility) which was to mature on April 22, 2027. A portion of the proceeds of the Notes Offering was used to repay $100.0 million in borrowings (or the Exit Term Loans) under the Exit Term Loan Facility and accrued and unpaid interest thereon through the redemption date. As a result of the repayment of the Exit Term Loans, we wrote off $0.7 million in unamortized deferred arrangement fees as “Loss on extinguishment of long-term debt” in our unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2023.

9.00%/11.00%/13.00% Senior Secured First Lien PIK Toggle Notes due 2027

We repaid our First Lien Notes in the aggregate principal amount of $85.3 million in full, including accrued and unpaid interest thereon through the end of the period at 104% in accordance with the associated indenture with a portion of the proceeds of the Notes Offering. The $3.4 million call premium paid on retirement of the First Lien Notes, in addition to the write-off of $(0.6) million and $1.7 million of unamortized premium and deferred arrangement fees, respectively, have been reported as “Loss on extinguishment of long-term debt” in our unaudited Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2023.

Upon retirement of the First Lien Notes, unfunded delayed draw commitments aggregating $39.7 million under the indenture governing the First Lien Notes also terminated.

Collateral Agency Agreement

On September 21, 2023, DODI, the Issuers and the Subsidiary Guarantors that are also grantors of collateral entered into an amended and restated collateral agency and intercreditor agreement with the Trustee, the Collateral Agent and HSBC, as administrative agent under the Amended RCF (or Collateral Agency Agreement). The Collateral Agency Agreement, among other things, sets forth the terms on which the Collateral Agent will receive, hold, administer, maintain, enforce and distribute the proceeds of all liens upon any property of the Issuers and the Guarantors at any time held by it, for the benefit of the current and future holders of First Lien Obligations and Junior Lien Obligations (each as defined in the Collateral Agency Agreement) as well as establishing the priority of the liens on the collateral as between the First Lien Obligations and Junior Lien Obligations.

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.

Non-Income Tax and Related Claims. We have 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 various taxing jurisdictions. We have determined that we have a probable loss for certain of these taxes and the related penalties and interest and, accordingly, have recorded a $1312.94 million and $12.47 million liability at ~~September~~March 3031, ~~2023~~2024 and December 31, ~~2022~~2023, respectively, in “Other liabilities” in our unaudited Condensed Consolidated Balance Sheets. We intend to defend these matters vigorously; however, the ultimate outcome of these assessments and exposures could result in additional taxes, interest and penalties for which the fully assessed amounts would have a material adverse effect on our financial condition, results of operations and cash flows.

Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business, including a claim by one of our customers in Brazil, Petróleo Brasileiro S.A. (or Petrobras), that it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities for our applicable portion of withholding taxes related to Petrobras’ charter agreements with its contractors. We intend to defend these matters vigorously; however, 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.15

21Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of 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.

Personal Injury Claims. Under our current insurance policies, which renewed effective May 1, 2024, we generally self-insure $1.0 million to $52.05 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. Depending on the nature, severity, and frequency of claims that might arise during the policy year, if the aggregate level of claims exceed certain thresholds, we may self-insure up to $100.0 million for each subsequent 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~~March 3031, ~~2023~~2024, our estimated liability for personal injury claims was $1611.18 million, of which $6.2 million and $95.96 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our unaudited Condensed Consolidated Balance Sheets. At December 31, ~~2022~~2023, our estimated liability for personal injury claims was $1814.36 million, of which $3.7.4 million and $147.62 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 ~~and volume~~ 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 ~~September~~March 3031, ~~2023~~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. ~~Commitments~~Future commitments under the contractual services agreements are estimated to be approximately $2725.06 million annually. Total future commitments are projected to be $88.1 million in ~~2023~~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. As of ~~September~~March 3031, ~~2023~~2024, an aggregate of $1814.80 million in bonds and letters of credit had been issued on our behalf in connection with certain customs, tax assessment and tenant security deposit requirements. Of this amount, approximately $1612.81 million had been cash collateralized as of ~~September~~March 3031, ~~2023~~2024. An additional $1.9 million was collateralized by a letter of credit issued under our ~~Amended~~ RCF, which cannot require additional collateral except in events of default, or until its maturity in May 2024, if not replaced.

~~8. Income Taxes~~16

~~We account for income taxes in interim periods in accordance with FASB Accounting Standards Codification Topic No~~8. ~~740,~~Ocean ~~Income~~GreatWhite ~~Taxes,~~Insurance which requires us to estimate our annual effective tax rate (or AETR) for continuing operations by considering our forecasted pre-tax income or loss for the full year in each of the various jurisdictions in which we operate. The AETR is then applied to our current pre-tax income or loss, as adjusted, when estimating our income tax benefit or expense for the interim period. We exclude discrete tax adjustments from the computation of the AETR and record such adjustments in the quarter in which they occur.Claim

WeOn ~~recorded~~February a1, ~~net~~2024, ~~income~~the ~~tax~~Ocean ~~expense~~GreatWhite ofreported ~~$125.4~~an ~~million~~equipment ~~and~~incident ~~income~~while ~~tax~~located ~~benefit~~in the North Sea west of ~~$143~~the Shetland Islands.3 ~~million~~The ~~for~~rig’s ~~the~~lower ~~three-month~~marine riser package (or LMRP) and ~~nine-month~~deployed ~~periods~~riser ~~ended~~string ~~September~~unintentionally ~~30,~~separated ~~2023,~~from ~~respectively,~~the ~~inclusive~~rig ofat athe ~~net~~slip ~~$14.5~~joint ~~million~~tensioner ~~additional~~ring, ~~tax~~and ~~expense~~the ~~with~~LMRP ~~respect~~and riser dropped to ~~prior~~the ~~years’~~seabed. ~~operations~~Since inthe ~~Egypt~~incident, ~~upon~~we ~~final~~have ~~judgment~~been byworking ~~the~~closely ~~Egyptian~~with ~~tax~~our ~~court.~~customer ~~The~~and ~~effective~~local ~~tax~~authorities ~~rates~~in ~~are~~response ~~the~~and ~~result~~have ofpursued ~~the~~efforts ~~mix~~to ofrecover ~~pre-tax~~the ~~income~~equipment and ~~loss~~replace ~~across~~missing ~~jurisdictions,~~or ~~including~~damaged ~~significant~~equipment. ~~losses~~We inhave ~~jurisdictions~~safely ~~with~~recovered ~~zero~~the ~~percent~~LMRP ~~tax~~from ~~rates~~the ~~resulting~~seabed and are in noa ~~benefit.~~repair ~~The~~facility ~~impact~~in isKishorn ~~compounded~~port, bywhere repairs to the ~~amount~~LMRP ofand ~~our~~any ~~year-to-date~~related ~~pre-tax~~work ~~loss.~~are underway.

22As of the date of this report, $19.1 million of incremental recovery and repair and maintenance costs have been incurred, as well as $2.6 million in capital expenditures. At March 31, 2024, we had retired assets with an aggregate net book value of $3.3 million. We anticipate that the repairs and equipment replacement will be covered by our hull and machinery insurance policy and that all incremental costs, less our $10.0 million deductible, will be reimbursable under that policy. At March 31, 2024, we had recorded an insurance receivable in the amount of $11.7 million for the aggregate expenditures, less the deductible, as of that date. However, we cannot fully predict the extent of such insurance coverage or the timing of such claims. We had not received any proceeds from insurance as of March 31, 2024. In addition, we will be required to pay an additional loss premium of up to 3.5% of net insurance proceeds received, payable after the claim is closed and all proceeds known.

9. ~~(Loss)~~ Earnings Per Share

We compute basic earnings ~~(loss)~~ per share by dividing net ~~(loss)~~ income available to holders of our common stock by the weighted-average number of shares of our common stock outstanding during the period. Diluted earnings ~~(loss)~~ per share reflects the potential dilution that could occur if securities or other contracts to issue our common stock (common stock equivalents) were exercised or converted into common stock. Basic and diluted earnings per share (or EPS) was calculated in accordance with the treasury stock method, and includes all potentially dilutive stock equivalents, including warrants, restricted stock ~~awards, restricted stock~~ unit awards and performance stock unit awards.

A reconciliation of the numerators and denominators of our basic and diluted EPS computations ~~are~~is summarized as follows (in thousands).

	Three Months EndedSeptember 30,
	Three Months Ended March 31,
	2023			2022
	2024			2023
Net (loss) income – basic and diluted numerator	$	(145,016	)	$	5,510
Net income – basic and diluted (numerator)	$	11,612		$	7,229
Weighted average shares – basic (denominator):		102,~~215~~440			~~100~~101,~~875~~331
Dilutive effect of stock-based awards		—2,300			12,~~398~~605
Weighted average shares including conversions – diluted (denominator)		~~102~~104,~~215~~740			~~102~~103,~~273~~936

	Nine Months EndedSeptember 30,
	2023		2022
Net income (loss) – basic and diluted numerator	$	100,996	$	(50,773	)
Weighted average shares – basic (denominator):		101,681		100,356
Dilutive effect of stock-based awards		2,575		—
Weighted average shares including conversions – diluted (denominator)		104,256		100,356

The computation of EPS for the three-month periods ended March 31, 2024 and March 31, 2023 excluded non-vested stock-based awards of 283,981 shares and 349,784 shares, respectively, as the inclusion of such would have been antidilutive for the periods.

NoAs ~~amounts~~of ~~are~~March ~~allocated~~31, 2024, we had 7.5 million stock warrants outstanding (or Warrants) to ~~non-vested~~purchase ~~share~~shares ~~awards~~of our common stock that were exercisable for ~~the~~one ~~periods~~share ~~with~~of acommon ~~net~~stock ~~loss~~per ~~position~~Warrant at an exercise price of $29.22 (subject to adjustment). The Warrants are exercisable until they expire on April 23, as2026. ~~the~~The ~~inclusion~~presumed exercise of ~~such~~these ~~amounts~~Warrants into shares of our common stock would have ~~been~~an antidilutive toeffect ~~earnings~~as the exercise price per ~~share.~~warrant exceeded the average price of our common stock and they have been excluded from the computation of EPS for all periods presented.

The computation of EPS for the nine-month period ended September 30, 2023 and the three-month period ended September 30, 2022 excluded non-vested stock-based awards of 166 shares and 103,939 shares, respectively, as the inclusion of such would have been antidilutive for the periods.17

As of September 30, 2023, we had 7.5 million stock warrants outstanding (or Warrants) to purchase shares of our common stock that were exercisable for one share of common stock per warrant at an exercise price of $29.22. The Warrants are exercisable until they expire on April 23, 2026. The presumed exercise of these Warrants into shares of our common stock would have an antidilutive effect as the exercise price per warrant exceeded the average price of our common stock and they have been excluded from the computation of EPS for all periods presented.

10. Segments and Geographic Area Analysis

We provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic 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 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.

23Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At March 31, 2024, our active drilling rigs were located offshore four countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country where the services were performed during the periods presented, which may not be indicative of where the rigs are currently located.

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, 2023, our active drilling rigs were located offshore four countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country where the services were 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, 2023
	Three Months Ended March 31, 2024
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	~~123~~146,~~140~~475	$	87,~~885~~328	$	~~132~~153,~~025~~803
United Kingdom		3632,~~207~~568		4,~~839~~233		4136,~~046~~801
Senegal		29,365		3,539		32,904
Australia		27,360		2,463		29,823
Brazil		1826,~~982~~570		—		1826,~~982~~570
Australia		17,235		2,766		20,001
Senegal		25,797		1,816		27,613
Total	$	~~224~~258,~~929~~770	$	2015,~~029~~840	$	~~244~~274,~~958~~610

	Nine Months Ended September 30, 2023
	Three Months Ended March 31, 2023
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	~~357~~104,~~650~~581	$	2912,~~974~~557	$	~~387~~117,~~624~~138
United Kingdom		~~113~~17,~~750~~702		101,~~491~~060		~~124~~18,~~241~~762
Senegal		135,360		9,247		144,607
Australia		19,309		840		20,149
Brazil		6020,~~710~~660		—		6020,~~710~~660
Australia		36,832		4,528		41,360
Senegal		52,131		3,181		55,312
Total	$	~~704~~214,~~302~~383	$	5417,~~240~~638	$	~~758~~232,~~542~~021

	Three Months Ended September 30, 2022
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	70,970	$	26,917	$	97,887
United Kingdom		26,111		2,520		28,631
Senegal		46,274		2,603		48,877
Brazil		21,564		—		21,564
Australia		24,616		4,049		28,665
Myanmar		326		123		449
Total	$	189,861	$	36,212	$	226,073

	Nine Months Ended September 30, 2022
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	226,425	$	69,121	$	295,546
United Kingdom		47,506		6,407		53,913
Senegal		100,094		8,451		108,545
Brazil		60,583		—		60,583
Australia		72,475		10,095		82,570
Myanmar		9,909		6,948		16,857
Total	$	516,992	$	101,022	$	618,014

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 Item 1A, “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, ~~2022~~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 1412 floater rigs (four owned drillships, ~~eight~~seven owned semisubmersibles and ~~two~~one managed ~~rigs~~rig). See “– Market Overview.”

Market Overview

~~Energy~~During ~~industry fundamentals continue to support~~ the ~~global~~first ~~growth~~quarter ~~cycle~~of in2024, ~~our~~oil ~~business.~~commodity ~~Commodity~~ prices ~~rose~~remained ~~substantially~~elevated ~~during~~above ~~the~~their ~~third~~5-year ~~quarter of 2023~~average, primarily as ~~the~~a ~~focus~~result onof ~~energy~~continued ~~security and~~ OPEC+ ~~actions~~supply ~~interacted~~restraint, ~~with~~muted ~~strong~~production ~~oil~~growth ~~demand. Brent crude oil prices increased approximately 29% during the quarter, closing~~ in the ~~mid-$90~~United ~~per~~States, ~~barrel~~strong ~~range.~~growth ~~Potential further upside~~ in ~~commodity~~oil ~~prices~~demand ~~remains,~~and asexpanding ~~significant~~manufacturing ~~draws~~trends in ~~both~~the ~~U.S.~~United States and ~~OECD~~China ~~inventories~~signaling ~~have driven~~ global ~~inventories~~economic ofimprovements. ~~petroleum~~Oil and ~~other~~natural ~~liquids~~gas ~~stocks~~benchmark toprices ~~their~~are ~~lowest~~expected ~~levels~~to inremain 20volatile ~~years,~~as ~~according~~geopolitical touncertainty ~~industry~~resulting ~~reports.~~from Anconflicts ~~expansion~~in ofRussia/Ukraine ~~conflict~~and in the Middle East may ~~result~~affect ~~in oil~~ supply ~~disruptions~~ and ~~cause~~demand. ~~further~~Brent ~~volatility~~crude ~~in commodity~~ prices. ~~According~~reached tothe ~~industry~~high ~~data,~~$80- ~~approximately~~to 25low ~~percent~~$90-per ofbarrel ~~oil~~range ~~production~~ in ~~the~~mid-April ~~third~~2024, ~~quarter~~which ofare ~~2023~~the ~~came~~highest ~~from~~levels ~~the~~reached ~~Middle~~since ~~East~~October 2023. ~~Against~~This ~~this~~rebound ~~backdrop~~represents ofan ~~robust~~approximate ~~commodity~~20% ~~prices,~~increase ~~industry~~since ~~experts~~the ~~believe~~beginning ~~that~~of the ~~oil~~year, ~~and~~according ~~gas~~to ~~industry~~pricing isdata ~~staged~~published ~~for~~by athe ~~meaningful~~U.S. ~~increase~~Energy ofInformation ~~approximately~~Administration. ~~30%~~Commodity inprices ~~greenfield~~are ~~capital~~expected ~~commitments~~to inremain ~~2023~~at ~~versus~~levels ~~2022,~~that ~~with~~are ~~current~~supportive ~~projections~~of ~~estimating~~investment ~~approximately $171 billion~~ in ~~2023~~deepwater ~~greenfield~~exploration ~~upstream~~and development projects,. As of ~~which~~mid-April ~~60%~~2024, isdated ~~attributable~~Brent tocrude ~~offshore~~oil ~~projects.~~prices ~~With~~for ~~approximately~~the ~~$90~~remainder ~~billion~~of ~~sanctioned~~2024 ~~thus~~and ~~far,~~2025 ~~95%~~were ofin the ~~remaining~~low-to-middle $980-per-barrel ~~billion~~range according to beindustry ~~sanctioned has a breakeven oil price of less than $40 per barrel~~data.

~~The~~In ~~positive dynamics of increased offshore spending and~~ the ~~push~~first ~~for~~quarter ~~diversity~~ of ~~commodity supply continue to drive improving demand for floating drilling rigs as demonstrated in the increased volume of incoming tenders for floating rigs. According to S&P Global~~2024, ~~incoming~~growth ~~floating rig tenders for the first nine months of 2023 as measured~~ in ~~rig-years~~offshore ofupstream ~~demand~~capital ~~represent~~expenditures ~~the~~continued ~~highest levels since 2012. This increase in recent tendering activity continues~~ to ~~build~~be ~~visibility~~supported ~~for~~by ~~deepwater~~strong ~~rig~~cash ~~demand,~~flows ~~supported~~realized by ~~the~~oil ~~increased duration~~ and ~~lead~~gas ~~times~~companies, ~~from~~continued ~~contract~~expectations ~~award to commencement of service~~ for ~~floater~~growing ~~contracts signed so far in 2023~~demand, asand ~~operators~~breakeven ~~become~~costs ~~more~~well ~~willing~~below tocurrent ~~commit~~oil toprice ~~longer periods for deepwater drilling capacity~~forecasts. According to industry ~~analysts~~reports, ~~lead~~analysts ~~times~~expect ~~and~~offshore ~~duration~~upstream ~~for~~capital ~~drillship~~expenditures ~~contracts signed in 2023 year~~ to ~~date~~increase ~~were~~approximately 03.83% ~~years~~annually, ~~and~~on ~~1.5 years~~average, ~~respectively,~~from ~~which~~2024 ~~represent~~to ~~levels~~2027, ~~not~~rising ~~seen since 2013. Several multi-year multi-rig tenders have come~~ to ~~market~~more ~~for~~than ~~the~~$230 ~~Golden~~billion ~~Triangle~~by ~~(a common reference for the deepwater and ultra-deepwater regions of the Gulf of Mexico~~2027, ~~southeast Brazil and West Africa)~~ with ~~commencement~~exploration ~~dates~~growing into ~~2025~~approximately ~~and~~12% ~~2026,~~of ~~which will further increase~~ the ~~average~~capital ~~lead~~expenditure ~~time and duration of contracts booked once these tenders are concluded~~total.

~~The~~During ~~strong~~the ~~demand~~first ~~for~~quarter ~~deepwater~~of ~~drilling~~2024, ~~rigs~~the ~~continues~~positive todynamics ~~support~~of ~~increasing~~increased ~~rates~~offshore ~~and utilization for ultra-deepwater drilling rigs~~spending, coupled with ~~current~~the ~~dayrates~~growing trend in ~~the~~long-cycle ~~mid $400~~developments,~~000~~ ~~per~~production ~~day~~capacity ~~range,~~expansions and ~~marketed~~exploration ~~utilization approaching 95%. Combined with the longer duration~~ and ~~lead~~appraisal ~~times of recent tenders~~activities, ~~these~~continued ~~factors~~to ~~have~~drive ~~resulted~~growth in ~~compelling~~demand ~~economics~~ for ~~rig~~floating ~~reactivations,~~drilling ~~with idle capacity continuing to enter the market~~rigs. ~~The~~According ~~return of idle capacity~~ to ~~the~~industry ~~market~~reports, ~~may~~on ~~adversely affect utilization and dayrates. While there is~~ a ~~possibility~~trailing ~~for~~three-month ~~additional stranded rigs to enter the market~~basis, the ~~remaining~~volume ~~inventory~~ of ~~idle~~floating rig ~~capacity~~years contracted has ~~decreased~~grown ~~significantly~~month ~~and~~over ~~the~~month ~~owners~~from ofNovember ~~this~~2023 ~~capacity~~through ~~have~~February ~~exhibited~~2024, ~~capital~~reaching ~~discipline~~its ashighest itlevel ~~relates~~since toFebruary ~~reactivations~~2023. ~~The~~According ~~anticipated~~to ~~growth~~data infrom ~~upstream~~S&P ~~capital~~Global, ~~spending~~in ~~continues~~mid-April to2024 ~~drive~~outstanding ~~further~~demand ~~increases~~from infloating rig ~~demand~~tenders ~~and~~was ~~may~~approximately ~~mitigate~~56 ~~the~~rig ~~long-term~~years, ~~impact~~compared ofto ~~future~~42 rig ~~reactivations.~~years ~~Further,~~a ~~supply~~year ~~chain~~earlier, ~~constraints~~representing ~~and~~an ~~inflationary~~increase ~~pressures~~of ~~could~~more ~~limit~~than ~~the~~33%. ~~pace~~Most atof ~~which~~this ~~these~~demand ~~additional~~was ~~rigs~~concentrated ~~return~~in to the ~~market,~~deepwater ~~with~~and ~~some~~ultra-deepwater ~~analysts~~regions ~~estimating~~of the ~~average~~Gulf ~~time for rig reactivations~~ of ~~approximately~~Mexico, 12Brazil ~~to 18 months at costs approaching $100 million~~ and ~~$350~~West ~~million for stacked and stranded assets~~Africa, ~~respectively,~~which asare ofareas ~~the~~where ~~date~~we ofcurrently ~~this report~~operate. ~~Despite~~The ~~policy~~recent ~~tightening~~improvement byin ~~major~~contracting ~~central~~activity ~~banks~~has ~~and~~pushed adayrates ~~moderating~~for ~~pace~~ultra-deepwater ofdrilling ~~world~~rigs ~~economic~~into ~~expansion,~~the ~~inflationary~~high ~~pressures~~$400 ~~remain~~to ~~elevated,~~low ~~which~~$500 ~~may~~thousand ~~result~~per inday ~~continued upward pressure on operating expenses for offshore drillers~~range.

26This 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.

InDespite ~~addition~~policy totightening ~~market~~by ~~factors,~~major ~~customer~~central ~~capital~~banks ~~allocation~~and ~~decisions~~a ~~will~~moderating ~~continue~~pace toof ~~affect~~world ~~demand~~economic ~~for our services. Customer investment mixes over time~~expansion, ~~coupled~~inflationary ~~with~~pressures ~~energy~~have ~~demand~~generally ~~and~~remained ~~regulatory~~elevated ~~measures, could adversely impact demand for offshore drilling services~~ in the ~~long~~industry ~~term. Notwithstanding this possibility~~sector, ~~global~~though ~~energy~~recent ~~demand~~trends ~~continues~~indicate topossible bemoderation ~~strong~~in ~~and~~some ~~energy supply growth remains constrained~~areas. WeContinued ~~expect~~inflation ~~increased~~may ~~investment~~result in ~~both~~upward ~~traditional~~pressure ~~and~~on ~~renewable~~operating ~~sources~~expenses offor ~~energy to be required in the future, much of which we expect to be invested in finding and producing hydrocarbons in the~~ offshore ~~segment~~drillers. ~~Industry experts continue to expect oil and gas to remain the largest sources of global energy in the foreseeable future.~~

~~See~~In “–addition ~~Contract~~to ~~Drilling~~market ~~Backlog”~~factors, ~~for~~during ~~future~~the ~~commitments~~first quarter of 2024, customer capital allocation decisions have continued to affect demand for our ~~rigs~~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 ~~remainder~~first quarter, global energy demand continued to be strong and energy supply growth remained constrained. We expect increased investment in both traditional and renewable sources of ~~2023~~energy ~~through~~to ~~2027~~be required in the future, some of which we expect to be invested in finding and producing hydrocarbons in the offshore segment.

2719

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.

See “– Contract Drilling Backlog” for future commitments of our rigs during the remainder of 2024 through 2028.

Contract Drilling Backlog

We believe that our contract drilling backlog provides a useful indicator of our 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 may be different than the amounts and periods shown in the tables below due to various factors. Our utilization rates, which generally have been in the range of 92-98% during contracted periods, can be adversely impacted due to various operating factors including unscheduled repairs and maintenance, weather conditions, and other factors. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. Revenue is generally not earned during periods of downtime for regulatory 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.

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 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 ~~October~~April 1, ~~2023~~2024 (based on information available at that time), January 1, ~~2023~~2024 (the date reported in our Annual Report on Form 10-K for the year ended December 31, ~~2022~~2023), and ~~October~~April 1, ~~2022~~2023 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended ~~September~~March 3031, ~~2022~~2023) (in millions).

	October 1,2023 (1)		January 1, 2023 (1)		October 1,2022 (1) (2)
	April 1,2024		January 1, 2024		April 1,2023
Contract Drilling Backlog	$	1,406	$	1,788	$	1,596
Contract Drilling Backlog (1)	$	1,877	$	1,424	$	1,596

(1)

Includes contract backlog of $~~156~~50.37 million, $~~307~~117.76 million and $~~300~~256.8 million at ~~October~~April 1, ~~2023~~2024, January 1, ~~2023~~2024 and ~~October~~April 1, ~~2022~~2023, respectively, attributable to customer drilling contracts secured for rigs managed, but not owned, by us. We entered into the drilling contracts directly with the customer and will receive and recognize revenue under the terms of the contract. ~~Pursuant~~The tomarketing ~~the~~arrangements ~~terms~~for each of our managed rigs were terminated in 2023, and the charter agreement ~~with~~for the ~~rig~~West ~~owner~~Auriga was terminated in February 2024. The Company received notice of termination of the management agreement for the West Vela in April 2024, wewhich will ~~realize~~become aeffective ~~gross~~after ~~margin~~90 ~~equivalent~~days. toThe ~~our~~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 ~~marketing~~any ~~fee~~option periods.

Previously reported contract backlog at October 1, 2022 included $73.4 million attributable to the term of a contract for the Ocean Patriot for which the customer executed its right to terminate the drilling contract. 21

28The following table reflects the amount of revenue related to our contract drilling backlog by year as of April 1, 2024 (in millions).

The following table reflects the amount of revenue related to our contract drilling backlog by year as of October 1, 2023 (in millions).


	For the Year Ending December 31,
	Total		2024 (1)		2025		2026		2027		2028
Contract Drilling Backlog (2)	$	1,877	$	662	$	552	$	471	$	190	$	2

(1)

	For the Years Ending December 31,
	Total		2023 (1)		2024		2025		2026		2027
Contract Drilling Backlog (2)	$	1,406	$	270	$	789	$	144	$	106	$	97

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

(2)

~~Represents~~Includes ~~the~~contract ~~three-month~~backlog ~~period~~of ~~beginning~~$50.7 ~~October~~million 1in the remainder of 2024, ~~2023~~attributable to customer drilling contract secured for the managed rig West Vela under an arrangement with an offshore drilling company (or the MMSA) whereby we provide management services for the rig.

~~Includes~~The ~~contract~~following ~~backlog~~table reflects the percentage of ~~$71.7~~rig ~~million~~days ~~and~~per ~~$84~~year committed as of April 1, 2024.6 ~~million~~The inpercentage of rig days committed is calculated as the ~~remainder~~ratio of ~~2023~~total ~~and~~days incommitted ~~2024,~~under ~~respectively~~contracts, ~~attributable~~as towell ~~customer~~as ~~drilling~~scheduled ~~contracts~~shipyard, ~~secured~~survey ~~for~~and ~~two~~mobilization ~~rigs~~days ~~managed~~for ~~under~~all anrigs ~~arrangement~~in ~~with~~our anfleet, ~~offshore~~to ~~drilling~~total ~~company~~available days (ornumber ~~the~~of ~~MSA)~~rigs, ~~whereby~~including wecold-stacked ~~provide~~rigs, ~~management~~multiplied ~~services~~by ~~for~~the ~~certain~~number of ~~its~~days ~~rigs~~in a particular year).

The following table reflects the percentage of rig days per year committed as of October 1, 2023. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs, including cold-stacked rigs, multiplied by the number of days in a particular year).


	For the Year Ending December 31,
	2024 (1)			2025			2026			2027			2028
Percentage of Rig Days Committed (2)		88	%		48	%		41	%		23	%	<1%

(1)

	For the Years Ending December 31,
	2023 (1)			2024			2025			2026			2027
Percentage of Rig Days Committed (2)		77	%		54	%		11	%		8	%		8	%

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

(2)

~~Represents~~As ~~the~~of ~~three-month~~April ~~period~~1, ~~beginning~~2024, ~~October~~includes 1approximately 220 rig days currently known and scheduled for shipyard projects, ~~2023~~including capital upgrades, surveys and contract preparation activities for the remainder of 2024.

As of October 1, 2023, includes approximately 95 rig days currently known and scheduled for shipyard projects, including capital upgrades, surveys and contract preparation activities for the remainder of 2023.

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

Regulatory Surveys and Planned Downtime. We perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs and an intermediate survey, which is performed every two-and-one-half years, for our North Sea rigs. Our operating income is 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 ~~2023~~2024, we expect to incur approximately 95220 days of planned downtime, including approximately 61(i) 100 days for ~~capital~~a ~~modifications~~shipyard project, ~~contract~~as ~~preparation~~well ~~and~~as ~~acceptance~~mobilization ~~testing~~and demobilization activities for the Ocean ~~Courage,~~BlackRhino; ~~approximately~~(ii) 1770 days for ~~contract~~the ~~preparation~~Ocean ~~and~~GreatWhite’s ~~mobilization~~lower ~~activities~~marine riser package (or LMRP) repairs; (iii) 25 days for the Ocean ~~BlackHawk,~~Endeavor’s ~~and~~blowout ~~approximately~~preventer 17(or BOP) recertification; (iv) 20 days for ~~standby,~~the ~~mobilization~~Ocean orBlackHornet’s ~~demobilization~~special ofsurvey ~~rigs~~and ~~between~~(v) ~~well~~five ~~sites~~days for the Ocean Apex’s mobilization activities. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, repairs, contract preparation, rig mobilizations and other shipyard projects. See “ –— Contract Drilling Backlog.”

29Physical 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 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 results of operations, financial condition, and cash flows. Under our current insurance policy, 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 $10.0 million per occurrence. In addition, we currently carry loss-of-hire insurance on certain of our owned rigs to cover 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.

~~Physical~~In ~~Damage~~addition, ~~and~~we ~~Marine~~carry ~~Liability~~marine ~~Insurance.~~liability Weinsurance ~~are~~covering ~~self-insured~~certain ~~for~~legal ~~physical~~liabilities, ~~damage~~including tocoverage ~~rigs~~for ~~and~~certain ~~equipment~~personal ~~caused~~injury byclaims, ~~named~~collisions, ~~windstorms~~and inwreck ~~the U.S. Gulf of Mexico~~removals, asand ~~defined~~generally bycovering ~~the~~liabilities ~~relevant~~arising ~~insurance~~out ~~policy.~~of Ifor arelating ~~named~~to ~~windstorm~~pollution inand/or ~~the~~environmental Urisk.S. ~~Gulf~~We ofbelieve ~~Mexico~~that ~~causes~~the ~~significant~~policy ~~damage~~limit tofor our ~~rigs~~marine orliability ~~equipment,~~insurance itis ~~could~~within ~~have~~the arange ~~material~~that ~~adverse~~is ~~effect~~customary onfor ~~our~~companies ~~results~~ of ~~operations, financial condition, and cash flows. Under~~ our ~~current~~size ~~insurance~~in ~~policy,~~the weoffshore ~~carry~~drilling ~~physical~~industry ~~damage~~and ~~insurance~~is appropriate for ~~certain~~our ~~losses~~business. ~~other~~Under ~~than~~these ~~those~~marine ~~caused~~liability bypolicies, ~~named~~we ~~windstorms~~generally inself-insure ~~the U~~$1.S.0 ~~Gulf~~million ofto ~~Mexico for which our deductible for physical damage is~~ $102.05 million per occurrence~~. In addition~~, wedepending ~~currently carry loss-of-hire insurance~~ on ~~certain~~jurisdiction, ofbut ~~our~~up ~~owned rigs~~ to ~~cover~~$25.0 ~~lost~~million ~~cash~~for ~~flow~~liabilities ~~when~~arising aout ~~rig~~of ~~is damaged (other than when caused by~~ named windstorms in the U.S. Gulf of Mexico).

In addition, 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. Under these marine liability policies, we generally self-insure $1.0 million to $5.0 million per occurrence, depending on jurisdiction, but up to $25.0 million for liabilities arising out of named windstorms in the U.S. Gulf of Mexico. Depending on the nature, severity, and frequency of claims that might arise during the policy year, if the aggregate level of claims exceeds certain thresholds, we may self-insure up to $100.0 million for each subsequent occurrence.22

Depending on the nature, severity, and frequency of claims that might arise during the policy year, if the aggregate level of claims exceeds certain thresholds, we may self-insure up to $100.0 million for each subsequent occurrence.

Critical Accounting Policies

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 Form 10-K for the year ended December 31, ~~2022~~2023.

Results of Operations

We have elected to present a comparison of our results of operations for 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 a comparative measurement of the activity level of our fleet, rig utilization is an indicator of our ability to secure work for and the operational efficiency of our fleet and average daily revenue provides a comparative measure for our revenue-earning performance. We utilize these performance indicators in the review of our business and operating results and believe these are 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 ~~September~~March 3031, ~~2023 and June 30~~2024, ~~2023~~December ~~and the nine-month periods ended September 30~~31, 2023 and ~~September~~March 3031, ~~2022~~2023.

30Results for the Three-Month Periods Ended March 31, 2024, December 31, 2023 and March 31, 2023

Results for the Three-Month Periods Ended September 30, 2023 and June 30, 2023


	Three Months Ended
	March 31,			December 31,			March 31,
	2024			2023			2023
Revenue-Earning Days (1)		849			886			789
Utilization (2)		68	%		69	%		63	%
Average daily revenue (3)	$	305,000		$	315,800		$	271,700

Revenues:
Contract drilling	$	258,770		$	279,681		$	214,383
Revenues related to reimbursable expenses		15,840			17,956			17,638
Total revenues		274,610			297,637			232,021
Operating expenses:
Contract drilling, excluding depreciation		184,205			188,803			173,490
Reimbursable expenses		15,266			17,304			17,213
Depreciation		31,354			27,705			27,906
General and administrative		18,576			19,190			19,585
Loss (gain) on disposition of assets		3,396			(280	)		(1,213	)
Total operating expenses		252,797			252,722			236,981
Operating income (loss)		21,813			44,915			(4,960	)
Other income (expense):
Interest income		1,774			1,464		7
Interest expense		(15,346	)		(14,847	)		(12,040	)
Foreign currency transaction gain (loss)		231			(2,863	)		(1,271	)
Other, net		(71	)		(54	)		(152	)
Income (loss) before income tax benefit		8,401			28,615			(18,416	)
Income tax benefit (expense)		3,211			(174,317	)		25,645
Net income (loss)	$	11,612		$	(145,702	)	$	7,229

	Three Months Ended
	September 30,			June 30,
	2023			2023
REVENUE-EARNING DAYS (1)		732			887
UTILIZATION (2)		57	%		70	%
AVERAGE DAILY REVENUE (3)	$	307,200		$	298,700
CONTRACT DRILLING REVENUE	$	224,929		$	264,990
REVENUE RELATED TO REIMBURSABLE EXPENSES		20,029			16,573
TOTAL REVENUES	$	244,958		$	281,563
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION	$	181,954		$	212,947
REIMBURSABLE EXPENSES	$	18,662		$	15,579
OPERATING INCOME (LOSS)
Contract drilling services, net	$	42,975		$	52,043
Reimbursable expenses, net		1,367			994
Depreciation		(27,785	)		(27,906	)
General and administrative expense		(16,649	)		(16,824	)
Gain on disposition of assets		955			1,933
Total Operating Income	$	863		$	10,240
Other income (expense):
Interest income		161			5
Interest expense, net of amounts capitalized		(13,774	)		(12,755	)
Foreign currency transaction gain (loss)		184			(1,968	)
Loss on extinguishment of long-term debt		(6,529	)		—
Other, net		(485	)		136
Loss before income tax benefit		(19,580	)		(4,342	)
Income tax (expense) benefit		(125,436	)		243,125
NET (LOSS) INCOME	$	(145,016	)	$	238,783

(1)

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

(2)

Utilization is calculated as the ratio of total R-E days divided by the total calendar days in the period for all rigs in our fleet (including managed and cold-stacked rigs).

(3)

Average daily revenue is defined as total contract drilling revenue for all of the rigs in our fleet (including managed rigs) per R-E day.

Three Months Ended March 31, 2024 Compared to Three Months Ended December 31, 2023

~~Three~~Contract ~~Months~~Drilling ~~Ended~~Revenue. ~~September~~Contract 30drilling revenue decreased $20.9 million during the three months ended March 31, ~~2023~~2024 ~~Compared~~compared to ~~Three~~the ~~Months~~three ~~Ended~~months ~~June~~ended 30December 31, 2023 , primarily due to lower average daily revenue earned ($9.2 million), combined with a 37-day decrease in R-E days ($11.7 million).

~~Contract~~The ~~Drilling~~decrease ~~Revenue.~~in ~~Contract~~average ~~drilling~~daily revenue ~~decreased $40.1 million~~ during the ~~three~~first ~~months~~quarter ~~ended~~of ~~September 30~~2024, ~~2023~~ compared to the ~~three~~fourth ~~months~~quarter ~~ended~~of ~~June 30,~~ 2023, was primarily due to athe ~~155-day~~absence ~~decrease~~of inincremental ~~R-E~~revenue ~~days~~recognized ~~($46.3~~in ~~million),~~the ~~partially~~fourth ~~offset~~quarter byof ~~the~~2023 ~~favorable~~related ~~impact~~to offavorable ~~higher~~settlements ~~average~~with ~~daily~~customers ~~revenue~~regarding ~~earned~~equipment ~~($6.2~~issues ~~million).~~and ~~Results~~non-productive ~~for~~time, ~~the~~which ~~third~~had ~~quarter~~occurred ofearlier in 2023, ~~included~~performance ~~$4.3~~bonuses ~~million~~for inthe ~~revenue~~Ocean ~~associated~~BlackHawk ~~with~~and ~~the~~Ocean ~~termination~~BlackRhino ofand aan ~~second~~early ~~well~~termination ~~option~~fee ~~program~~received ~~for~~by the Ocean Apex.

R-E days decreased during the ~~third~~first quarter of ~~2023~~2024, ~~compared~~primarily due to ~~the~~downtime ~~second~~as ~~quarter~~a result of ~~2023,~~the ~~primarily~~Ocean ~~due~~GreatWhite tobeing ~~downtime~~out ~~associated~~of ~~with~~service aand in shipyard ~~project~~ for ~~the~~repairs ~~Ocean~~due ~~BlackHawk prior~~ to the ~~rig’s~~LMRP ~~mobilization~~incident to(60 ~~the~~fewer ~~U.S.~~R-E ~~Gulf~~days), termination of ~~Mexico~~the ~~(or~~managed ~~GOM)~~services ~~for~~agreement aand ~~one-year~~charter ~~contract~~of the West Auriga (8630 fewer days), ~~the~~ warm stacking of the Ocean Patriot between contracts (8829 fewer R-E days) and an aggregate net ~~decrease~~incremental indowntime ~~R-E~~for ~~days~~repairs for other rigs in our fleet (2214 fewer R-E days). The decrease in R-E days was partially offset by ~~incremental~~nearly ~~operating~~full-quarter ~~days~~operations for the Ocean ~~Apex~~Courage and Ocean BlackHawk in 2024 (4196 incremental days), ~~which~~compared ~~was~~to inthe afourth ~~shipyard~~quarter ~~for~~of a2023 ~~special~~when ~~survey~~both ~~and~~rigs ~~regulatory~~completed ~~and~~shipyard ~~other~~projects ~~upgrades~~in ~~during~~advance ~~the~~of ~~second~~their ~~quarter~~current ~~of 2023~~contracts.

~~Revenue~~Contract ~~Related~~Drilling toExpense, ~~Reimbursable~~Excluding ~~Expenses~~Depreciation. ~~During~~Contract drilling expense, excluding depreciation decreased $4.6 million during the ~~third~~first quarter of ~~2023~~2024, wecompared ~~recognized~~to ~~gross~~the ~~reimbursable~~fourth ~~revenue~~quarter ~~and~~of ~~expenses~~2023. ofLower expense in the 2024 period was primarily due to reduced charter costs for the managed rigs ($2013.0 million), ~~including~~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 ($25.13 million) ~~earned~~and ~~under~~the absence of expense associated with an annual efficiency bonus recognized in the ~~MSA~~fourth quarter of 2023 related to a services agreement for certain well control equipment on our drillships ($6.0 ~~Gross~~million). ~~reimbursable~~The ~~revenue~~reduction ~~and~~in costs between periods was partially offset by higher operating expenses for the ~~second~~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 ~~2023~~the ~~were~~fourth quarter of 2023, $167.6 million, in non-recoverable expense (or a portion of ~~which~~the ~~none~~insurance ~~was~~deductible) ~~earned~~associated ~~under~~with repairs for the ~~MSA~~Ocean GreatWhite attributable to the LMRP incident and a net increase in operating expense for the other rigs in our fleet ($1.5 million).

~~Contract~~Loss ~~Drilling~~on ~~Expense,~~disposition ~~Excluding~~of ~~Depreciation~~assets. ~~Contract~~We ~~drilling~~recorded ~~expense,~~a ~~excluding~~net ~~depreciation~~loss ~~decreased~~on ~~$31.0~~disposition ~~million~~of ~~during~~assets ~~the third quarter~~ of ~~2023,~~$3.4 ~~compared~~million tofor the ~~second~~first quarter of ~~2023~~2024, ~~and~~which ~~was~~included ~~primarily~~$2.4 ~~attributable~~million toin ~~the~~non-recoverable ~~absence~~expense of(or ~~mobilization~~a ~~costs~~portion ~~associated with the mobilization~~ of the ~~Ocean~~insurance ~~BlackHawk~~deductible) ~~from Senegal to a shipyard in the Canary Islands in the second quarter, combined with the deferral of contract preparation costs~~ associated with ~~the~~capital ~~rig~~repairs ~~being readied~~ for ~~its new contract in~~ the ~~GOM.~~Ocean GreatWhite.

Loss on Extinguishment of Long-Term Debt. Concurrent with our issuance of $550 million aggregate principal amount of new debt in September 2023, we repaid all our previously outstanding debt and amended our revolving credit facility to reduce the borrowing capacity thereunder. We recognized a $6.5 million loss on extinguishment of debt, primarily related to the retirement of a portion of our then existing debt at a premium ($3.4 million) and the write off of deferred issuance costs related to the retired debt and reduction in borrowing capacity ($3.1 million).

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 ~~expense~~benefit of $~~125~~3.42 million for the three months ended ~~September~~March 3031, ~~2023~~2024. For the three months ended ~~June~~December 3031, 2023, we recorded a net income tax ~~benefit~~expense of $~~243~~174.~~1 million~~3million. The effective tax rate for the quarter ended ~~September~~March 3031, ~~2023~~2024 isresulted afrom ~~result of~~ the mix of pre-tax income and loss across jurisdictions, ~~including~~increased ~~significant~~profitability ~~losses~~ in jurisdictions ~~with~~which ~~zero~~rigs ~~percent~~are ~~tax~~currently ~~rates~~operating, ~~resulting~~and inthe noeffect ~~tax~~of discrete items, specifically a benefit on remeasurement of uncertain tax positions in Egypt.

32Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

~~Results~~Contract ~~for~~Drilling Revenue. Contract drilling revenue increased $44.4 million during the ~~Nine-Month~~three ~~Periods~~months ~~Ended~~ended ~~September~~March 3031, 2024 compared to the three months ended March 31, 2023, ~~and~~primarily ~~September~~due 30to higher average daily revenue earned ($28.2 million), ~~2022~~in addition to a 60-day increase in R-E days ($16.2 million).

	Nine Months Ended			Nine Months Ended
	September 30, 2023			September 30, 2022
REVENUE-EARNING DAYS		2,408			2,253
UTILIZATION		63	%		65	%
AVERAGE DAILY REVENUE	$	292,500		$	229,400
CONTRACT DRILLING REVENUE	$	704,302		$	516,992
REVENUE RELATED TO REIMBURSABLE EXPENSES		54,240			101,022
TOTAL REVENUES	$	758,542		$	618,014
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION	$	568,390		$	442,619
REIMBURSABLE EXPENSES	$	51,454		$	99,932
OPERATING INCOME (LOSS)
Contract drilling services, net	$	135,912		$	74,373
Reimbursable expenses, net		2,786			1,090
Depreciation	$	(83,596	)		(78,714	)
General and administrative expense		(53,058	)		(52,805	)
Gain on disposition of assets		4,102			4,802
Total Operating Income (Loss)	$	6,146		$	(51,254	)
Other income (expense):
Interest income		173			12
Interest expense, net of amounts capitalized		(38,569	)		(28,792	)
Foreign currency transaction loss		(3,057	)		(285	)
Loss on extinguishment of long-term debt		(6,529	)		—
Other, net		(502	)		1,487
Loss before income tax benefit		(42,338	)		(78,832	)
Income tax benefit		143,334			28,059
NET INCOME (LOSS)	$	100,996		$	(50,773	)

~~Nine~~Average ~~Months~~daily ~~Ended~~revenue ~~September~~earned 30during the first quarter of 2024 increased, compared to the first quarter of 2023, ~~Compared~~primarily due to ~~Nine~~higher ~~Months~~dayrates ~~Ended~~earned ~~September~~by 30several rigs in the fleet, ~~2022~~which operated under new contracts or extensions that commenced after the first quarter of 2023.

~~Contract~~R-E ~~Drilling~~days ~~Revenue.~~increased ~~Contract~~during ~~drilling~~the ~~revenue~~first ~~increased~~quarter ~~$187.3~~of ~~million~~2024, ~~during~~compared to the ~~nine~~first ~~months~~quarter ~~ended~~of ~~September 30~~2023, ~~2023~~primarily ~~compared~~due to ~~the~~incremental ~~nine~~operating ~~months~~days ~~ended~~for ~~September~~the 30Ocean Endeavor, ~~2022.~~which ~~Comparing~~completed shipyard repairs in the ~~periods~~first quarter of 2023, and the West Vela, which was warm stacked between contracts during the first quarter of 2023 (105 incremental days). The increase in ~~contract~~R-E ~~drilling~~days ~~revenue~~during the 2024 period was ~~the~~partially ~~result~~offset ofby ~~higher~~a ~~average~~net ~~daily~~increase ~~revenue~~in ~~earned~~downtime for repairs (~~$151.8~~20 ~~million~~fewer R-E days), ~~combined~~the ~~with~~warm-stacking aof ~~155-day~~rigs ~~increase~~between incontracts (26 fewer R-E days) and termination of the MMSA for the West Auriga (~~$35.5~~23 ~~million~~fewer R-E days). Comparing the quarters, the Ocean GreatWhite had achieved 24 incremental R-E days prior to going out of service for repairs as a result of the LMRP incident during the first quarter of 2024.

Contract ~~Average~~Drilling ~~daily~~Expense, ~~revenue~~Excluding ~~for~~Depreciation. ~~the~~Contract ~~nine~~drilling ~~months ended September 30~~expense, ~~2023~~excluding depreciation increased ~~compared~~$10.7 tomillion during the ~~prior~~first ~~year~~quarter ~~period~~of 2024, ~~primarily~~compared ~~due~~ to ~~dayrates~~the ~~earned~~first byquarter ~~the~~of ~~Ocean~~2023 ~~BlackHornet~~ and ~~West~~reflected ~~Auriga,~~higher ~~which~~net ~~operated~~expense ~~under~~for ~~new~~the ~~contracts~~managed orrigs ~~extensions~~($5.8 ~~during~~million), ~~2023~~primarily atdue to higher ~~dayrates~~charter ~~than~~fees ~~those~~for ~~earned~~both inmanaged ~~the~~rigs, ~~same~~partially ~~period~~offset ofby ~~2022.~~lower ~~Contract~~repair ~~drilling~~and ~~revenue~~maintenance costs for the ~~nine~~West ~~months ended September 30~~Vela, ~~2023~~and also included ~~revenue~~$7.6 ~~for~~million ~~the~~in ~~Ocean~~non-recoverable ~~GreatWhite~~expense ~~and~~(or ~~West~~a ~~Vela,~~portion ~~which~~of ~~commenced~~the ~~drilling~~insurance ~~operations~~deductible) ~~after~~associated with repairs for the ~~third~~Ocean ~~quarter~~GreatWhite. ofComparing ~~2022~~the periods, ascontract ~~well~~drilling asexpense ~~$16.5~~was ~~million~~reduced inby ~~revenue~~a ~~related~~net todecrease ~~the~~in ~~early~~other ~~termination~~operating ofcosts ~~drilling~~across ~~contracts~~our ~~for~~owned ~~the~~rig ~~Ocean~~fleet ~~Patriot~~($2.7 ~~and~~million) during the ~~Ocean~~first ~~Apex~~quarter of 2024.

~~The~~Interest ~~increase~~Expense. inInterest ~~R-E~~expense ~~days~~increased ~~for~~$3.3 million during the first ~~nine~~quarter ~~months~~ of ~~2023~~2024, primarily due to higher average debt outstanding compared to the first ~~nine~~quarter ~~months~~ of ~~2022,~~2023. ~~was~~Interest expense for the ~~result~~first quarter of ~~incremental~~2024 ~~R-E~~included ~~days~~$12.2 ~~for~~million ~~the~~in ~~Ocean~~expense ~~GreatWhite~~related ~~(183~~to ~~days),~~our ~~and~~$550.0 ~~our~~million ~~two~~aggregate ~~managed~~principal ~~rigs~~amount of senior secured second lien notes (~~278~~or ~~days).~~the ~~R-E~~Second ~~days~~Lien ~~were~~Notes), ~~partially~~which ~~reduced~~bear byinterest ~~downtime~~at ~~associated~~8.5%, ~~with~~and the ~~completion~~amortization of ~~contracts~~associated ~~and~~debt ~~subsequent~~issuance ~~cold~~costs. ~~stacking~~During the first quarter of ~~the~~2023, ~~Ocean~~we ~~Onyx~~incurred ~~(192~~interest ~~fewer~~expense ~~days)~~of ~~and~~$8.8 ~~the~~million ~~Ocean~~on ~~Monarch~~weighted ~~(82~~average ~~fewer~~debt ~~days),~~outstanding asof ~~well~~approximately as$354.0 million at an ~~aggregate~~average ~~reduction~~interest rate of 9.5%, in ~~R-E~~addition ~~days~~to ~~for~~amortization ~~other~~of ~~rigs~~associated indebt ~~our~~issuance ~~fleet~~costs ~~(32~~and ~~fewer~~debt ~~days)~~premium.

~~Revenue~~Loss ~~Related~~(gain) toon ~~Reimbursable~~disposition ~~Expenses~~of assets. ~~Gross~~We ~~reimbursable~~recorded ~~revenue~~a ~~and~~net ~~expenses~~loss on disposition of assets of $3.4 million for the first ~~nine~~quarter ~~months~~ of ~~2023~~2024, ~~were~~which included $~~54.~~2.4 million, ~~including~~in ~~$8.5~~non-recoverable ~~million~~expense ~~earned~~(or ~~under~~a portion of the ~~MSA.~~insurance Wedeductible) ~~recognized~~associated ~~gross~~with ~~reimbursable~~capital ~~revenue~~repairs for the LMRP and ~~expenses~~related ofequipment ~~$101.1~~on ~~million~~the ~~for~~Ocean GreatWhite. During the first ~~nine~~quarter ~~months~~ of ~~2022~~2023, ~~including~~we recognized a $551.32 million ~~earned~~gain ~~under~~on ~~the~~disposition ~~MSA.~~of surplus equipment.

33Income 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 discrete items, specifically a benefit on remeasurement of uncertain tax positions in Egypt.

Contract Drilling Expense, Excluding Depreciation. Contract drilling expense, excluding depreciation increased $125.8 million during the nine months ended September 30, 2023 compared to the same period in 2022. Higher contract drilling expense for the first nine months of 2023 included incremental costs related to the Ocean GreatWhite, which commenced its first drilling contract post-reactivation at the end of the first quarter, incremental costs associated with the Ocean Apex shipyard project that commenced in March 2023, higher personnel-related and repair costs for our rigs offshore Senegal and contract drilling expense associated with two rigs managed under the MSA. Contract drilling expense for the 2023 period was favorably impacted by reduced expense for the Ocean Onyx and Ocean Monarch, which operated under contract for part of 2022 but are now cold-stacked.

Gain on Disposition of Assets. During the first nine months of 2023, we recognized an aggregate gain on disposition of assets of $4.1 million, primarily related to the sale of surplus equipment. During the first quarter of 2022, we sold the Ocean Valor for aggregate proceeds of approximately $6.6 million and recognized a net gain on the transaction of $4.2 million.

Interest Expense. Interest expense for the nine-month period ended September 30, 2023 increased $9.8 million compared to the nine month period ended September 30, 2022, primarily due to higher market interest rates on outstanding indebtedness, combined with higher average outstanding borrowings compared to the 2022 period. Interest expense for the nine months ended September 30, 2023 also included $1.3 million in accrued interest related to our notes issuance in September 2023.

Loss on Extinguishment of Long-Term Debt. Concurrent with our issuance of $550 million aggregate principal amount of new debt in September 2023, we retired all our previously outstanding debt and amended our revolving credit facility to reduce the borrowing capacity thereunder. We recognized a $6.5 million loss on extinguishment of debt, primarily related to the retirement of a portion of our then existing debt at a premium ($3.4 million) and the write off of deferred issuance costs related to the retired debt and reduction in borrowing capacity ($3.1 million).

Income Tax Benefit. We recorded a net income tax benefit of $143.3 million for the nine months ended September 30, 2023, inclusive of a net $14.5 million additional tax expense with respect to prior years’ operations in Egypt upon final judgment by the Egyptian tax court. For the nine months ended September 30, 2022, we recorded a net income tax benefit of $28.1 million. The effective tax rate for the nine months ended September 30, 2023 is a result of the mix of pre-tax income and loss across jurisdictions, including significant losses in jurisdictions with zero percent tax rates resulting in no tax benefit.

Liquidity and Capital Resources

InWe ~~September~~have ~~2023,~~available wea ~~issued $550.0 million in aggregate principal amount of 8.5%~~ senior secured ~~second~~revolving ~~lien~~credit ~~notes due 2030 (or the Second Lien Notes)~~agreement, which ~~are~~provides ~~scheduled~~for toa ~~mature on October 1, 2030 (or the Notes Offering). Concurrent with the issuance of the Second Lien Notes, we entered into an amendment (or the Credit Agreement Amendment) to our then-existing~~ $~~400~~300.0 million ~~exit~~senior ~~revolving~~secured ~~credit agreement, which amended the~~ revolving credit facility (or the ~~Exit~~ RCF). ~~to,~~The ~~among~~RCF ~~other~~is ~~things,~~scheduled ~~(i)~~to ~~reduce~~mature ~~the~~on ~~aggregate~~April ~~commitment~~22, of2026. ~~the~~See ~~lenders~~Note ~~thereunder~~6 ~~from~~“Long-Term ~~$400.0~~Debt” ~~million~~ to ~~$300.0~~our ~~million,~~unaudited ~~(ii)~~condensed ~~permit~~consolidated ~~the~~financial ~~Notes~~statements ~~Offering~~included ~~(or, as amended, the Amended RCF) and (iii) provide for obligations~~ in ~~respect~~Item of1 ~~letters~~ of ~~credit~~Part inI anof ~~aggregate~~this ~~principal~~report ~~amount~~for ~~not~~a todiscussion ~~exceed $50.0 million . The Credit Agreement Amendment became effective concurrently with the consummation~~ of ~~the~~our ~~Notes Offering, which was conditioned on the Credit Agreement Amendment becoming effective~~RCF.

WeAt ~~used~~May a6, ~~portion~~2024, ofwe ~~the~~had ~~net~~no ~~proceeds~~borrowings ~~from~~outstanding under the ~~Notes~~RCF, ~~Offering to fully repay~~ and ~~terminate~~a ~~our~~ $~~100~~1.09 million ~~senior~~letter ~~secured~~of ~~exit term loan~~ credit ~~facility~~had ~~(or~~been ~~the~~issued ~~Exit~~thereunder. ~~Term~~As ~~Loan~~of ~~Credit~~May ~~Facility)~~6, ~~redeem~~2024, inapproximately ~~full our 9~~$298.~~00%/11.00%/13.00%~~1 ~~Senior~~million ~~Secured~~was ~~First~~available ~~Lien~~for ~~PIK~~borrowings ~~Toggle~~under ~~Notes~~the ~~due~~RCF ~~2027~~subject ~~(or~~to ~~First~~its ~~Lien~~terms ~~Notes)~~ and ~~repay~~conditions; ~~all~~however, ~~amounts~~the ~~outstanding~~availability of borrowings under the ~~Exit~~ RCF. Weis ~~intend~~subject to ~~use~~ the ~~remaining~~satisfaction ~~net~~of ~~proceeds~~certain ~~for~~conditions ~~general~~as ~~corporate~~specified ~~purposes~~in our revolving credit agreement, including restrictions on borrowings.

~~See~~There ~~Note~~is 6no ~~“Long-Term~~capacity ~~Debt”~~for tothe ~~our~~issuance ~~unaudited~~of ~~condensed~~new ~~consolidated~~letters ~~financial~~of ~~statements~~credit ~~included~~under inthe ~~Item~~RCF, 1but ofthe ~~Part~~RCF Ipermits us to obtain up to $50.0 million in letters of ~~this~~credit ~~report~~outside ~~for~~the RCF. We have obtained a ~~discussion~~$25.0 million letter of ~~our~~credit ~~Second~~facility; ~~Lien~~however, ~~Notes~~letters of credit thereunder must be cash collateralized.

~~On October 24~~Historically, ~~2023,~~we ~~Barclays~~have ~~Bank~~relied ~~PLC~~on ~~(or~~our ~~Barclays),~~cash ~~gave~~flows ~~notice~~from ofoperations ~~its~~and ~~resignation~~cash asreserves anto LCmeet ~~Lender~~our ~~under~~liquidity ~~the Amended RCF. Barclays’ resignation will become effective on November 23~~needs, ~~2023, at~~ which ~~time~~primarily ~~our~~include ~~capacity~~funding ~~for the issuance~~ of ~~additional~~our ~~letters~~working ofcapital ~~credit~~requirements ~~under~~and ~~the~~capital ~~Amended RCF will be reduced to zero. However~~expenditures, as ~~allowed~~well ~~under~~as the ~~Amended~~servicing ~~RCF,~~of weour ~~have~~debt ~~capacity~~repayments toand ~~obtain~~interest uppayments. toAs ~~$50~~of ~~million~~May in6, ~~letters~~2024, all of ~~credit~~our ~~outside~~rigs, excluding the ~~credit~~managed ~~facility.~~rig, are

3425

Atowned ~~November~~and 6operated, ~~2023,~~directly weor ~~had~~indirectly, noby ~~borrowings~~Diamond ~~outstanding~~Foreign ~~under~~Asset ~~the~~Company ~~Amended~~(or ~~RCF, and a $1~~DFAC).9 ~~million~~Our ~~letter~~management ofhas ~~credit~~determined ~~had~~that ~~been~~we ~~issued~~will ~~thereunder.~~permanently Asreinvest offoreign ~~November 6~~earnings, ~~2023,~~which ~~approximately~~restricts ~~$298.1~~the ~~million~~ability ~~was~~to ~~available~~utilize ~~for~~cash ~~borrowings~~flows ~~under~~of ~~the~~DFAC ~~Amended~~on ~~RCF~~a ~~subject~~company-wide tobasis. ~~its~~To ~~terms~~the ~~and~~extent ~~conditions; however~~possible, ~~the~~we ~~availability~~expect ofto ~~borrowings~~utilize ~~under~~ the ~~Amended~~operating ~~RCF~~cash isflows ~~subject~~and tocash ~~the~~reserves ~~satisfaction~~ of ~~certain~~DFAC ~~conditions~~and asthe ~~specified~~operating incash ~~our~~flows ~~revolving~~available ~~credit~~to ~~agreement,~~and ~~including~~cash ~~restrictions~~reserves onof ~~borrowings.~~Diamond WeOffshore ~~have~~Drilling, upInc. to ~~$50.0~~meet ~~million~~each inrespective ~~capacity~~entity's toworking ~~issue~~capital ~~letters~~requirements ofand ~~credit~~capital ~~outside the credit facility~~commitments.

Historically, we have relied on our cash flows from operations and cash reserves to meet our liquidity needs, which primarily include funding of our working capital requirements and capital expenditures, as well as the servicing of our debt repayments and interest payments. As of November 6, 2023, all of our rigs, excluding managed rigs, are owned and operated, directly or indirectly, by Diamond Foreign Asset Company (or DFAC). Our management has determined that we will permanently reinvest foreign earnings, which restricts the ability to utilize cash flows of DFAC on a company-wide basis. To the extent possible, we expect to utilize the operating cash flows and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each respective entity's working capital requirements and capital commitments.

From time to time, based on market conditions and other factors, we may seek to repay, refinance or restructure all or a portion of our outstanding indebtedness or otherwise enter into transactions regarding our capital structure to obtain more favorable terms, enhance flexibility in conducting our business, increase liquidity or otherwise. We regularly evaluate capital markets to consider future opportunities for enhancements of our capital structure and may opportunistically pursue financing transactions to optimize our capital 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, and there can be no assurance that we would be able to complete any such offering of securities.

As of ~~October~~April 1, ~~2023~~2024, our contractual backlog was approximately $1.49 billion. At ~~September~~March 3031, ~~2023~~2024, we had cash of $~~172~~169.42 million, including $~~25.~~6.8 million that is subject to restrictions pursuant to the ~~MSA~~MMSA.

Sources and Uses of Cash

Cash Flows and Cash Expenditures

For the ~~nine~~three-month period ended ~~September~~March 3031, ~~2023~~2024, our operating activities generated cash of $2059.20 million. Cash receipts from contract drilling services ($~~766~~315.87 million) were partially offset by cash expenditures for contract drilling, shorebase support, and general and administrative costs ($~~729~~256.86 million) ~~and placement of cash collateral related to certain tax matters ($16~~.8 ~~million).~~

Cash outlays for capital expenditures during the first ~~nine~~three months of ~~2023~~2024 aggregated $9927.9 million, primarily related to long-lead items for the Ocean BlackRhino’s shipyard ~~projects~~project and equipment ~~upgrades~~updates scheduled for ~~several~~the ~~rigs~~second inhalf ~~our~~of ~~fleet~~2024. We also made payments of $4.3 million under finance lease obligations related to well control equipment on our owned drillships.

AsFor ~~discussed~~the ~~above,~~three-month inperiod ~~the~~ended ~~third~~March ~~quarter~~31, of 2023, weour ~~issued~~operating ~~$550.0~~activities ~~million of Second Lien Notes at par and~~ used acash ~~portion~~ of ~~the~~$8.2 ~~proceeds~~million. toCash ~~repay~~expenditures ~~amounts~~for ~~outstanding~~contract ~~under~~drilling, ~~the~~shorebase ~~Exit RCF~~support, ~~repay~~ and ~~terminate~~general ~~our Exit Term Loan Credit Facility~~ and ~~redeem~~administrative incosts ~~full the First Lien Notes~~ ($~~381~~232.29 million)., ~~Costs~~were ~~associated~~partially ~~with~~offset ~~the~~by ~~issuance~~cash ofreceipts ~~the~~from ~~Second~~contract ~~Lien~~drilling ~~Notes~~services ~~and amendment of the Exit RCF were~~ ($15217.10 million.) ~~During~~and ~~the~~a ~~first~~net ~~nine~~refund ~~months~~ of ~~2023,~~cash weincome ~~also~~taxes ~~made payments in connection with finance lease obligations aggregating~~ ($147.87 million), ~~related~~primarily toin ~~well~~the ~~control~~U.S. ~~equipment~~tax onjurisdiction, ~~our~~during ~~owned~~the ~~drillships~~three-month period.

~~For~~Cash ~~the~~outlays ~~nine-month~~for ~~period~~capital ~~ended~~expenditures ~~September~~during ~~30,~~the ~~2022,~~first ~~our~~quarter ~~operating~~of ~~activities~~2023 ~~used~~aggregated ~~cash of~~ $2129.94 million. ~~Cash~~(including ~~expenditures~~capital outlays for ~~contract~~the ~~drilling,~~Ocean ~~shorebase~~Endeavor ~~support,~~ and ~~general~~Ocean ~~and~~GreatWhite ~~administrative~~shipyard ~~costs~~projects ~~($590.4~~completed ~~million~~this year). ~~and~~We ~~cash~~also ~~income~~repaid ~~taxes paid, net of refunds (~~$15.0 million), ~~were~~in ~~partially~~outstanding ~~offset~~draws byunder ~~cash~~the ~~receipts~~RCF ~~from~~and ~~contract~~made ~~drilling~~payments ~~services~~in ~~($566.0~~connection ~~million)~~with ~~during~~finance ~~the~~lease ~~nine-month~~obligations ~~period. In addition, collateral deposits~~ aggregating $174.51 million ~~were~~related ~~exchanged~~to ~~for~~our ~~letters~~owned ~~of credit drawn under the Exit RCF, positively impacting cash flow but with a neutral effect on total liquidity~~drillships.

35Ocean GreatWhite

~~Cash~~On ~~outlays~~February ~~for~~1, ~~capital~~2024, ~~expenditures~~the ~~during~~Ocean ~~the~~GreatWhite, ~~first~~reported ~~nine~~an ~~months~~equipment ofincident ~~2022~~while ~~aggregated~~located ~~$42.7~~in ~~million~~the ~~(including~~North ~~capital~~Sea ~~outlays~~west ~~for~~of the ~~Ocean~~Shetland ~~Endeavor~~Islands. ~~and~~The ~~Ocean~~rig’s ~~Patriot~~lower ~~shipyard~~marine ~~work~~riser package (“LMRP”). Weand ~~also~~deployed ~~paid~~riser ~~$11.8~~string ~~million~~unintentionally inseparated ~~finance~~from ~~lease~~the ~~obligations~~rig ~~related~~at tothe ~~well~~slip ~~control~~joint ~~equipment~~tensioner onring ~~our~~and ~~owned~~the ~~drillships~~LMRP ~~during~~and riser dropped to the ~~period~~seabed. ~~Asset~~We ~~sales,~~have ~~including~~safely recovered the ~~sale~~LMRP offrom the ~~Ocean~~seabed ~~Valor,~~and ~~generated~~are ~~cash~~in ~~proceeds~~a ofrepair ~~$5.9~~facility ~~million,~~in ~~and~~Kishorn weport, ~~borrowed~~where ~~$69.0~~repairs ~~million~~to ~~under~~ the ~~Exit~~LMRP ~~RCF~~and ~~during~~any ~~the~~related ~~first~~work ~~nine~~are ~~months of 2022~~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 flow under certain circumstances. After a 60-day waiting period, our loss-of-hire insurance provides $150,000 per day, for 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 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.

Capital Expenditures and Other Projects

We have historically invested a significant portion of our cash flows in the enhancement of our 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 current and expected industry conditions and our cash flow forecast. As of the date of this report, we expect total capital expenditures for ~~2023~~2024 to be approximately $~~130~~135.0 million to $~~135~~145.0 million.

Contractual Obligations and Other Commercial Commitments

As of September 30, 2023, with the exception of the following, there have been no material changes to our contractual obligations or other commercial commitments as previously disclosed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Contractual Cash Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2022 (in thousands).

			Twelve months ending September 30
Contractual Obligations	Total		2024		2025-2026		2027-2028		Thereafter
$550 Million Second Lien Notes (principal and interest) (1)(2)	$	877,250	$	46,750	$	93,500	$	93,500	$	643,500
Total obligations	$	877,250	$	46,750	$	93,500	$	93,500	$	643,500

We issued $550.0 million aggregate principal amount of 8.5% Senior Secured Second Lien Notes due 2030 on September 21, 2023. Proceeds from the issuance were used to repay and terminate our Exit Term Loan Credit Facility, redeem in full the First Lien Notes and repay all borrowings under our Exit RCF, including accrued and unpaid interest thereon. We have no further obligations with respect to these previously reported items, other than borrowings from time to time and letters of credit issued under the Amended RCF.

Interest on the Second Lien Notes accrues at 8.5% per annum and is payable April 1 and October 1 of each year, commencing April 1, 2024.

Other Obligations

As of ~~September~~March 3031, ~~2023~~2024, the amount of total net unrecognized tax benefits related to uncertain tax positions that could result in a future cash payment was $4440.93 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 $1721.30 million related to prior years’ operations in Egypt.

Other Commercial Commitments - Letters of Credit

See Note 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 certain of our other commercial commitments.

Forward-Looking Statements

We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (or the Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (or the Exchange Act). All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “would,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

•

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

•

offshore exploration activity, future investment in hydrocarbons, future spending trends or growth, customer capital allocation and commitments, drilling contract duration trends, and customer spending programs and future projects;

•

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

environmental social and governance trends, practices and related matters;

business plans or financial condition of our customers, including with respect to or as a result of the COVID-19 pandemic;

expectations regarding our plans and strategies;

contractual obligations and future contract negotiations;

•

future commodity prices and volatility, dayrates or utilization;

•

market outlook;

•

the transition to renewable energy sources and other alternative forms of energy;

•

future energy demand and future demand for offshore drilling services;

•

~~interest~~global ~~rate~~energy demand and ~~foreign~~the ~~exchange~~role ~~risk~~of ~~and~~hydrocarbons ~~the~~in ~~transition~~meeting ~~away~~the ~~from~~world’s ~~LIBOR~~energy needs;

•

inflation;

•

future economic trends, including interest rates and recessionary economic conditions;

•

operations outside the United States;

~~geopolitical events and risks including Russia’s invasion of Ukraine and related sanctions, conflict in the Middle East and related disruptions;~~27

•

geopolitical events and risks, including Russia’s invasion of Ukraine and related sanctions, conflict in the Middle East including the armed conflict between Israel and Hamas, and related disruptions;

•

business strategy;

•

strategic initiatives;

•

growth opportunities;

•

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

•

expected financial position and liquidity;

•

cash flows and contract backlog;

•

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

•

idling drilling rigs or reactivating stacked or stranded rigs;

•

outcomes of litigation and legal proceedings;

•

declaration and payment of dividends;

•

expectations regarding our plans and strategies;

•

financing plans;

•

any repayment, refinancing or restructuring of our outstanding indebtedness or other transaction regarding our capital structure or any offering of securities or other capital markets transaction;

•

market outlook;

inflation;

future economic trends, including interest rates and recessionary economic conditions;

future commodity prices, dayrates or utilization;

tax planning;

cybersecurity;

unionization efforts;

changes in tax laws and policies or adverse outcomes resulting from examination of our tax returns;

debt levels and the impact of changes in the credit markets, including interest rates;

•

budgets for capital and other expenditures;

•

interest rate and foreign exchange risk;

•

business plans or financial condition of our customers;

•

duration and impacts of the COVID-19 pandemic, including new variants of the virus, lockdowns, re-openings and any other related actions taken by businesses and governments on the offshore drilling industry and our business, operations, supply chain and personnel, financial condition, results of operations, cash flows and liquidity;

•

ESG trends, practices and related matters;

•

tax planning and effects of the Inflation Reduction Act;

•

changes in tax laws and policies or adverse outcomes resulting from examination of our tax returns;

•

contractual obligations related to our well control equipment services agreement and potential exercise of the purchase option at the end of the original lease term;

•

the ~~MSA~~MMSA and charters with an offshore drilling company and future management ~~and marketing~~ services thereunder;

•

~~duration~~any ~~and~~response ~~impacts~~to of the ~~COVID-19~~equipment ~~pandemic,~~incident ~~including~~on ~~new variants of~~ the ~~virus,~~Ocean ~~lockdowns~~GreatWhite, ~~re-openings and~~ any ~~other~~ related ~~actions~~damage ~~taken~~or byenvironmental ~~businesses~~impact ~~and~~or ~~governments~~efforts onto ~~the~~recover ~~offshore~~equipment ~~drilling~~or ~~industry~~replace ~~and~~any onmissing ~~our~~or ~~business,~~damaged ~~operations, supply chain and personnel, financial condition, results of operations, cash flows and liquidity~~equipment;

•

the ~~effects~~estimated downtime, duration of ~~our~~repairs, ~~former~~cost ~~bankruptcy~~of ~~proceedings~~repairs onand ~~our~~replacement ~~operations~~capital, ~~including~~and ~~our~~the ~~relationships~~insurance ~~with employees~~claim, ~~regulatory~~coverage ~~authorities,~~and ~~customers,~~estimated ~~suppliers, banks,~~ insurance ~~companies~~recovery and ~~other~~costs ~~third~~as ~~parties,~~a ~~and~~result ~~agreements~~of the equipment incident on the Ocean GreatWhite;

•

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

•

process and timing for acquiring regulatory permits and approvals for our drilling operations;

•

timing and cost of completion of capital projects;

•

delivery dates and drilling contracts related to capital projects;

•

plans and objectives of management;

•

sale or scrapping of retired rigs;

•

asset impairments and impairment evaluations;

•

assets held for sale;

•

our internal controls and internal control over financial reporting;

•

performance of contracts;

•

cybersecurity;

•

unionization efforts;

•

compliance with applicable laws; and

•

availability, limits and adequacy of insurance or indemnification.

These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, those described or referenced in Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, ~~2022~~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 these reports are reliable, we have not independently verified the information included in such reports. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

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

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 ~~September~~March 3031, ~~2023~~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~~March 3031, ~~2023~~2024. See “Quantitative and Qualitative Disclosures About Market Risk” included in Item 7A of our Annual Report on Form 10-K for the year ended December 31, ~~2022~~2023 for further information.

ITEM 4. Controls and Procedures.

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

Our Chief Executive Officer (or CEO) and Chief Financial Officer (or CFO) participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2023. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of September 30, 2023.

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our third fiscal quarter of 2023 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.29

3913a-15(e) and 15d-15(e)) as of 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 March 31, 2024.

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

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings.

Information related to certain legal proceedings is included in Note 7 “Commitments and Contingencies” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report, which is incorporated herein by reference.

ITEM 1A. Risk Factors.

Our Annual Report on Form 10-K for the year ended December 31, ~~2022~~2023 includes a detailed discussion of certain material risk factors facing the Company. The risk factors included under Item 1A of our Annual Report on Form 10-K for the year ended December 31, ~~2022~~2023 are incorporated herein by reference. No material changes have been made to such risk factors as of ~~September~~March 3031, ~~2023~~2024.

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

Items 2(a) and 2(b) are not applicable.

(c) During the three months ended September 30, 2023, in connection with the vesting of restricted stock units held by our officers and certain other employees, which were awarded under an equity incentive compensation plan, we acquired shares of our common stock in satisfaction of tax withholding obligations that were incurred in connection with such vesting. The date of acquisition, number of shares and average effective acquisition price per share were as follows:

Issuer Purchases of Equity Securities

Period	Total Number of Shares Acquired			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1, 2023 through July 31, 2023		240,236	$		14.93	N/A	N/A
August 1, 2023 through August 31, 2023		—			—	N/A	N/A
September 1, 2023 through September 30, 2023		—			—	N/A	N/A
Total		240,236	$	14.93		N/A	N/A

ITEM 5. Other Information.

Items 5(a) and 5(b) are not applicable.

(c) ~~During~~On ~~the~~March ~~quarter~~4, ~~ended~~2024, ~~September~~Bernie 30Wolford, ~~2023~~Jr., noPresident ~~director~~and orChief ~~officer~~Executive ~~adopted~~Officer, orentered ~~terminated~~into ~~any~~a ~~Rule~~pre-arranged stock trading plan (the “Wolford 10b5-1 ~~trading~~Plan”). ~~arrangement~~The orWolford ~~non~~10b5-1 Plan was entered into during an open insider trading window and is intended to satisfy the affirmative defense of Rule 10b5-1(c) ~~trading~~of ~~arrangement,~~the Exchange Act and our policies regarding trading in ~~each~~our ~~case~~securities. asThe ~~such~~Wolford ~~terms~~10b5-1 ~~are~~Plan ~~defined~~provides infor ~~Item~~the potential sale of up to 408,000 shares of ~~Regulation~~the ~~S-K~~Company’s common stock between June 3, 2024 and May 30, 2025, subject to the terms and conditions of the plan.

40 On March 4, 2024, Dominic A. Savarino, Senior Vice President and Chief Financial Officer, entered into a pre-arranged stock trading plan (the “Savarino 10b5-1 Plan”). The Savarino 10b5-1 Plan was entered into during an open insider trading window and is intended to satisfy the affirmative defense of Rule 10b5-1(c) of the Exchange Act and our policies regarding trading in our securities. The Savarino 10b5-1 Plan provides for the potential sale of up to 18,226 shares of the Company’s common stock between June 3, 2024 and December 31, 2024, subject to the terms and conditions of the plan.

On March 4, 2024, David L. Roland, Senior Vice President, General Counsel and Secretary, entered into a pre-arranged stock trading plan (the “Roland 10b5-1 Plan”). The Roland 10b5-1 Plan was entered into during an open insider trading window and is intended to satisfy the affirmative defense of Rule 10b5-1(c) of the Exchange Act and our policies regarding trading in our securities. The Roland 10b5-1 Plan provides for the potential sale of up to 40,000 shares of the Company’s common stock between June 3, 2024 and April 4, 2025, subject to the terms and conditions of the plan.

During the quarter ended March 31, 2024, no other director or officer adopted or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement, in each case as such terms are defined in Item 408 of Regulation S-K.

ITEM 6. Exhibits.

Exhibit No.		Description of Exhibit
3.1		Fourth Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on May 10, 2023).
3.2		Third Amended and Restated Bylaws of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed on February 10, 2023).
4.1		Indenture, dated September 21, 2023, by and among Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, Diamond Finance, LLC, the other Guarantors party thereto, and HSBC Bank USA, National Association, as trustee and as collateral agent, relating to the 8.500% Senior Secured Second Lien Notes due 2030 (incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K filed on September 22, 2023).
10.1		Form of 2024 Time-Vesting Restricted Stock Unit Award Agreement (incorporated by reference toExhibit 10.23 to our Annual Report on Form 10-K filed on February 28, 2024).
10.1		Amended and Restated Collateral Agency and Intercreditor Agreement, dated September 21, 2023, by and among Diamond Foreign Asset Company, Diamond Offshore Drilling, Inc., other grantors from time to time party thereto and HSBC Bank USA, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on September 22, 2023).
10.2		Form of 2024 Executive Performance-Vesting Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.24 to our Annual Report on Form 10-K filed on February 28, 2024).
10.2		Purchase Agreement, dated as of September 12, 2023, between Diamond Foreign Asset Company, Diamond Finance, LLC, certain guarantors named therein and Goldman Sachs & Co. LLC, as representative of the initial purchasers (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on September 13, 2023).
10.3**		Amendment to Credit Agreement, dated September 12, 2023, by and among Diamond Foreign Asset Company, Diamond Offshore Drilling, Inc., HSBC Bank USA, National Association, as administrative agent and as collateral agent, and the lenders and issuing lenders from time to time party thereto (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on September 13, 2023).
10.4		Agency Assignment Agreement and Master Assignment of Liens, dated as of August 10, 2023, by and among HSBC Bank USA, National Association, as successor administrative agent and collateral agent, Wells Fargo Bank, National Association, as resigning administrative agent and collateral agent, Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, the other loan parties named therein, the Revolving Credit Agreement lenders party thereto, and the Term Loan Agreement lenders party thereto (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on August 11, 2023).
31.1*		Rule 13a-14(a) Certification of the Chief Executive Officer.
31.2*		Rule 13a-14(a) Certification of the Chief Financial Officer.
32.1*		Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.
101.INS*		Inline XBRL Instance 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*		Inline XBRL Taxonomy Calculation Linkbase Document.
104*		The cover page of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, formatted in Inline XBRL (included with the Exhibit 101 attachments).
101.LAB*		Inline XBRL Taxonomy Label Linkbase Document.
101.PRE*		Inline XBRL Presentation Linkbase Document.
101.DEF*		Inline XBRL Definition Linkbase Document.
104*		The cover page of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2023, formatted in Inline XBRL (included with the Exhibit 101 attachments).

* Filed or furnished herewith.

** Certain schedules and similar attachments have been omitted. The Company agrees to furnish a supplemental copy of any omitted schedule or attachment to the Securities and Exchange Commission upon request.32

SIGNATURES

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

	DIAMOND OFFSHORE DRILLING, INC.
	(Registrant)
Date November 7, 2023	By:	/s/ Dominic A. Savarino
Date May 8, 2024	By:	/s/ Dominic A. Savarino
		Dominic A. Savarino
		Senior Vice President and Chief Financial Officer

4233

Filing Compare · DIAMOND OFFSHORE DRILLING, INC.