UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

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

For the quarterly period ended ~~September~~June 30, ~~2017~~2023

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

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

For the transition period from to

Commission File Number: ~~333-212081~~333-159299

VANTAGE DRILLING INTERNATIONAL

(Exact name of Registrant as specified in its charter)

Cayman Islands

98-1372204

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

c/o Vantage Energy Services, Inc.

777 Post Oak Boulevard, Suite ~~800~~440

Houston, TX77056

(Address of principal executive offices and zip code)

Registrant’s telephone number, including area code: ~~(281)~~ (281) 404-4700

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


Title of each class	Trading Symbol	Name of each exchange on which registered
N/A	N/A	N/A

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~~registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). Yes☒ No ☐

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


Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer		Smaller reporting company	☐
~~Non-accelerated filer~~	☒ ~~(Do not check if a smaller reporting company)~~	~~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 Act). Yes ☐ No ☒

The number of Vantage Drilling International ~~ordinary shares~~Ordinary Shares outstanding as of ~~October 20, 2017~~August 1, 2023 is ~~5,000,053~~13,229,280 shares.

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 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 ☐

TABLE OF CONTENTS

SAFE HARBOR STATEMENT

This Quarterly Report on Form 10-Q (this “Quarterly Report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act ~~of 1933, as amended,~~ and Section 21E of the ~~Securities~~ Exchange ~~Act of 1934, as amended.~~Act. These forward-looking statements are included throughout this Quarterly Report, including under ~~“Item~~“Item 2. Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations.~~Operations” When used, statements which are not historical in nature, including those containing words such as “anticipate,” “assume,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “predict,” “project,” “should,” “would,” “will,” “future” and similar expressions are intended to identify forward-looking statements in this Quarterly Report.

These forward-looking statements reflect our current views with respect to future events and are based on assumptions and subject to risks and uncertainties. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in these forward-looking statements.

Among the factors that could cause actual results to differ materially are the risks and uncertainties described under “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with the SEC on March 31, 2023, “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations”~~Operations” of this Quarterly Report, and the following:

•

~~our small number of customers;~~

~~credit risks of our key customers and certain other third parties;~~

reduced expenditures by oil and ~~natural~~ gas exploration and production companies;

•

~~termination or renegotiation of our customer contracts;~~

general economic conditions and conditions in the oil and gas ~~industry;~~

industry, including the worldwide supply and demand for oil and gas, and expectations regarding future prices of oil and gas;

•

~~competition within our industry;~~

excess supply of drilling units worldwide;

•

~~limited mobility~~competition within our industry;

•

growing focus on climate change, including regulatory, social and market efforts to address climate change, and its overall impact on the level of investments being directed to fossil fuel exploration and production companies and the associated products or services;

•

our current level of indebtedness and the ability to incur additional indebtedness in the near- and long-term;

•

epidemics, pandemics, global health crises, or other public health events and concerns, including any future resurgence of COVID-19, and the effectiveness of associated vaccinations and treatments;

•

governmental, tax and environmental regulations and related actions and legal matters, including the actions taken by governments in response to any global health events and crises, as well as the results and effects of legal proceedings and governmental audits, assessments, orders and investigations;

•

volatility in the price of commodities due to actions taken by members of OPEC, OPEC+ and other, oil-exploring countries, with respect to oil production levels and announcements of potential changes in such levels, including the ability of members of OPEC+ to agree on and comply with announced supply limitations;

•

the potential for increased production from U.S. shale producers and non-OPEC countries driven by current oil prices, including the effect of such production rates on the overall global oil and gas supply, demand balance and commodity prices;

•

termination or renegotiation of our ~~drilling units between geographic regions;~~

customer contracts, and the invoking of force majeure clauses;

•

termination or renegotiation of our management and marketing agreements, including any terminations arising directly or indirectly from the consummation of the Aquadrill Merger (as defined below);

•

losses on impairment of long-lived assets;

•

any non-compliance with the U.S. Foreign Corrupt Practices Act, as amended, and any other anti-corruption laws;

•

the sufficiency of our internal controls, including exposure arising from the failure to (i) establish and maintain effective internal control over financial reporting in accordance with applicable regulatory requirements, and (ii) fully remediate any material weaknesses identified with respect to such internal controls;

•

operating hazards in the offshore drilling industry;

•

~~ability to obtain indemnity from customers;~~

~~adequacy of insurance coverage upon the occurrence of a catastrophic event;~~

~~governmental, tax and environmental regulation;~~

~~changes in legislation removing or increasing current applicable limitations of liability;~~

~~effects of new products and new technology on the market;~~

~~our substantial level of indebtedness;~~

~~our ability to incur additional indebtedness;~~

~~compliance with restrictions and covenants in our debt agreements;~~

~~identifying and completing acquisition opportunities;~~

~~levels of operating and maintenance costs;~~

~~our dependence on key personnel;~~

~~availability of workers and the related labor costs;~~

~~increased cost of obtaining supplies;~~

~~the sufficiency of our internal controls;~~

~~changes in tax laws, treaties or regulations;~~

operations in international markets, including geopolitical, ~~risk,~~global, regional or local economic and financial market risks and challenges, applicability of foreign laws, including foreign labor and employment laws, foreign tax and customs regimes, and foreign currency exchange rate risk;

•

political disturbances, geopolitical instability and tensions, or terrorist attacks, and associated changes in global trade policies and economic sanctions, including, but not limited to, Russia’s invasion of Ukraine in February 2022 and the Russo-Ukrainian War;

•

~~any non-compliance with~~adequacy of, or gaps in, insurance coverage upon the ~~U.S. Foreign Corrupt Practices Act and any~~occurrence of a catastrophic or other ~~anti-corruption laws; and~~

material adverse event;

•

effects of new products and new technology on the market;

•

the occurrence (or recurrence) of cybersecurity incidents, attacks, intrusions or other breaches to our information technology systems;

•

our small number of customers, related concentration and/or the loss of any customers;

•

consolidation of our competitors and suppliers;

•

termination or renegotiation of vendor contracts;

•

changes in the status of pending, or the initiation of new litigation, claims or proceedings, including our ability to prevail in the defense of any appeal or counterclaim;

•

changes in legislation removing or increasing current applicable limitations of liability;

•

limited mobility of our drilling units between geographic regions;

•

the small size of our fleet and associated vulnerabilities in the case of prolonged downtime of any of our drilling rigs;

•

levels of operating and maintenance costs;

•

our dependence on key personnel;

•

availability of workers and the related labor costs;

•

increased costs resulting from supply chain constraints, delays and impediments, including, but not limited to, increases in (i) the costs of obtaining supplies, (ii) labor costs, and (iii) freight, transportation and input costs, among others;

•

changes in tax laws, treaties or regulations;

•

credit risks of our key customers and other third parties we engage commercially;

•

compliance with restrictions and covenants in our debt agreements;

•

our recent lack of overall profitability and whether we will generate material revenues or profits in the near- and long-term;

•

adverse macroeconomic conditions, including (i) inflationary pressures and potential recessionary conditions, as well as actions taken by central banks and regulators across the world in an attempt to reduce, curtail and address such pressures and conditions, and (ii) the effects of adverse developments at financial institutions, including bank failures, that impact general sentiment regarding the stability and liquidity of banks, and the resulting impact on the stability of the global financial markets at large;

•

our incorporation under the laws of the Cayman Islands and the limited rights to relief that may be available compared to U.S. ~~laws.~~

law;

•

compliance with the Economic Substance Act 2021 (as amended) and the Economic Substance Act 2018 (as amended), among other legislation enacted in the Cayman Islands and Bermuda; and

•

our ability to identify and complete strategic and/or transformational transactions, including acquisitions, dispositions, joint ventures and mergers, as well as the impact that such transactions may have on our operations and financial condition.

Many of these factors are beyond our ability to control or predict. Any, or a combination of these factors, could materially affect our future financial condition or results of operations and the ultimate accuracy of the forward-looking statements. These forward-looking statements are not guarantees of our future performance, and our actual results and future developments may differ materially from those projected in the forward-looking statements. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels.

In addition, each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements. We may not update these forward-looking statements, even if our situation changes in the future. All forward-looking statements attributable to us are expressly qualified by these cautionary statements. Additional information concerning factors that could cause actual results to differ materially from those in the forward-looking statements is contained from time to time in filings we may make with the ~~Securities and Exchange Commission (the “SEC”),~~SEC, which may be obtained by contacting us or the SEC. These filings

are also available through our website at www.vantagedrilling.com or through the SEC’s Electronic Data Gathering and Analysis Retrieval system ~~(EDGAR)~~(“EDGAR”) at www.sec.gov. The contents of our website are not part of this Quarterly Report.

Unless the context indicates otherwise, all references to the “Company,” “Vantage~~” “VDI,~~ Drilling International,” “we,” “our” or “us” refer to Vantage Drilling International and its consolidated subsidiaries. References to “VDI” refer to Vantage Drilling International, a Cayman Islands exempted company and the group parent company.

GLOSSARY OF TERMS

The following terms used in this Quarterly Report have the following meanings, unless specified elsewhere in this Quarterly Report:


Abbreviation/Acronym		Definition
2016 Amended MIP		The Company's Amended and Restated 2016 Management Incentive Plan
9.25% First Lien Indenture		First Lien Indenture, dated as of November 30, 2018, by and between Vantage Drilling International and U.S. Bank National Association
9.25% First Lien Notes		The Company's 9.25% Senior Secured First Lien Notes due November 15, 2023
9.50% First Lien Indenture		Indenture, dated as of March 1, 2023, by and between VDI, the guarantors party thereto, and U.S. Bank Trust Company, National Association, as trustee and first lien collateral agent
9.50% First Lien Notes		The Company's 9.50% Senior Secured First Lien Notes due February 15, 2028
ADES		ADES International Holding Ltd, an offshore and onshore provider of oil and gas drilling and production services in the Middle East, India and Africa
ADVantage		ADVantage Drilling Services SAE, a joint venture owned 51% by the Company and 49% by ADES
ASC		Accounting Standards Codification
Board of Directors		The Company's board of directors
Comparable Period		The six months ended June 30, 2022
Comparable Quarter		The three months ended June 30, 2022
Convertible Notes		The Company's 1%/12% Step-Up Senior Secured Third Lien Convertible Notes due 2030
COVID-19		Coronavirus disease 2019, a strain of coronavirus caused by SARS-CoV-2
Current Period		The six months ended June 30, 2023
Current Quarter		The three months ended June 30, 2023
DOJ		U.S. Department of Justice
EDC		Emerald Driller Company, which owns the Emerald Driller, Sapphire Driller and Aquamarine Driller
EDC Sale		The sale by VHI of all of the issued and outstanding equity of EDC to ADES Arabia Holding, pursuant to the terms of that certain Share Purchase Agreement, dated as of December 6, 2021, by and between VHI and to sell to ADES Arabia Holding, as amended, which closed on May 27, 2022
Effective Date		February 10, 2016, the date the Company emerged from bankruptcy
EPS		Earnings per share
Exchange Act		Securities Exchange Act of 1934, as amended
IRS		U.S. Internal Revenue Service
OPEC		The Organization of the Petroleum Exporting Countries
OPEC+		The Organization of the Petroleum Exporting Countries plus 10 non-OPEC nations
Ordinary Shares		The Company's ordinary shares, par value $0.001 per share
PBGs		Performance-based restricted stock units
QLE		A qualified liquidity event as defined in the 2016 Amended MIP
ROU		Right-of-use
Russo-Ukrainian War		The ongoing war resulting from Russia's invasion of Ukraine in February 2022
SEC		Securities and Exchange Commission
Securities Act		Securities Act of 1933, as amended
Tax Election		Tax election filed with the IRS on January 22, 2020, to allow VDI to be treated as a partnership, rather than a corporation, for U.S. federal income tax purposes, with an effective date retroactive to December 9, 2019
TBGs		Time-based restricted stock units
TEV		Total enterprise value
U.S.		United States of America
U.S. GAAP		Accounting principles generally accepted in the United States of America
U.S. Holder		A beneficial owner of the Ordinary Shares that is, for U.S. federal income tax purposes, (i) a citizen or individual resident of the United States, (ii) a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) that was organized under the laws of the United States, any state thereof, or the District of Columbia, (iii) an estate, the income of which is subject to U.S. federal income tax regardless of its source or (iv) a trust, if a U.S. court can exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust, or such trust has a valid election in effect under applicable treasury regulations to be treated as a U.S. person for U.S. federal income tax purposes
USD or $		U.S. Dollar
VDC		Vantage Drilling Company, the Company's former parent company
VDI		Vantage Drilling International
VHI		Vantage Holdings International, a subsidiary of VDI
VIE		Variable interest entity

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Vantage Drilling International

Consolidated Balance ~~Sheet~~Sheets

(In thousands, except share and par value information)

(Unaudited)


							June 30, 2023			December 31, 2022
	September 30, 2017			December 31, 2016
ASSETS
Current assets
Cash and cash equivalents	$	198,637		$	231,727		$	79,650		$	74,026
Trade receivables		36,103			20,850
Inventory		43,675			45,206
Restricted cash								455			16,450
Trade receivables, net of allowance for credit losses of $3,850 and $4,962, respectively								83,109			62,776
Materials and supplies								44,759			41,250
Prepaid expenses and other current assets		16,158			12,423			40,166			25,621
Total current assets		294,573			310,206			248,139			220,123
Property and equipment
Property and equipment		904,327			902,241			649,910			647,909
Accumulated depreciation		(123,215	)		(67,713	)		(330,911	)		(309,453	)
Property and equipment, net		781,112			834,528			318,999			338,456
Operating lease ROU assets								812			1,648
Other assets		22,384			15,694			12,659			18,334
Total assets	$	1,098,069		$	1,160,428		$	580,609		$	578,561

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Accounts payable	$	46,182		$	35,283		$	55,570		$	57,775
Accrued liabilities		20,073			18,448
Current maturities of long-term debt		4,430			1,430
Other current liabilities								65,770			66,179
Total current liabilities		70,685			55,161			121,340			123,954
Long–term debt, net of discount and financing costs of $68,564 and $105,568		904,084			867,372
Long–term debt, net of discount and financing costs of $11,080 and $773, respectively								188,920			179,227
Other long-term liabilities		9,899			11,335			9,678			12,881
Commitments and contingencies (Note 8)
Commitments and contingencies (see Note 8)
Shareholders' equity
Ordinary shares, $0.001 par value, 50 million shares authorized; 5,000,053 shares issued and outstanding		5			5
Ordinary shares, $0.001 par value, 50 million shares authorized; 13,229,280 and 13,115,026 shares issued and outstanding, each period								13			13
Additional paid-in capital		373,972			373,972			633,605			633,863
Accumulated deficit		(260,576	)		(147,417	)		(373,971	)		(373,147	)
Total shareholders' equity		113,401			226,560
Total liabilities and shareholders’ equity	$	1,098,069		$	1,160,428
Controlling interest shareholders' equity								259,647			260,729
Noncontrolling interests								1,024			1,770
Total equity								260,671			262,499
Total liabilities and shareholders' equity							$	580,609		$	578,561

The accompanying notes are an integral part of these unaudited consolidated financial statements.

Vantage Drilling International

Consolidated Statement of Operations

(In thousands, except per share amounts)

(Unaudited)

Successor

Predecessor

Three Months Ended September 30,

Nine Months Ended September 30, 2017

Period from February 10, 2016 to September 30, 2016

Period from January 1, 2016 to February 10, 2016

2017

2016

Revenue

Contract drilling services

$
51,831

$
34,755

$
137,672

$
99,715

$
20,891

Management fees

342

993

1,148

3,664

752

Reimbursables

5,523

4,194

14,188

14,860

1,897

Total revenue

57,696

39,942

153,008

118,239

23,540

Operating costs and expenses

Operating costs

49,848

30,983

119,030

93,387

25,213

General and administrative

6,949

10,128

29,929

27,991

2,558

Depreciation

18,538

18,977

55,531

49,434

10,696

Total operating costs and expenses

75,335

60,088

204,490

170,812

38,467

Loss from operations

(17,639
)

(20,146
)

(51,482
)

(52,573
)

(14,927
)

Other income (expense)

Interest income

231

11

587

26

3

Interest expense and other financing charges (contractual interest of $23,219 for the period from January 1, 2016 to February 10, 2016)

(19,258
)

(18,722
)

(57,180
)

(48,144
)

(1,728
)

Other, net

858

669

2,073

987

(69
)

Reorganization items

—

35

—

(606
)

(452,919
)

Bargain purchase gain

—

—

1,910

—

—

Total other expense

(18,169
)

(18,007
)

(52,610
)

(47,737
)

(454,713
)

Loss before income taxes

(35,808
)

(38,153
)

(104,092
)

(100,310
)

(469,640
)

Income tax provision

4,260

3,373

9,067

5,978

2,371

Net loss

(40,068
)

(41,526
)

(113,159
)

(106,288
)

(472,011
)

Net loss attributable to noncontrolling interests

—

—

—

—

(969
)

Net loss attributable to VDI

$
(40,068
)

$
(41,526
)

$
(113,159
)

$
(106,288
)

$
(471,042
)

Net loss per share, basic and diluted

$
(8.01
)

$
(8.31
)

$
(22.63
)

$
(21.26
)

N/A

Weighted average successor ordinary shares outstanding, basic and diluted

5,000

5,000

5,000

5,000

N/A


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Revenue
Contract drilling services	$	67,673		$	42,744		$	115,590		$	87,657
Management fees		5,569			2,840			7,689			3,943
Reimbursables and other		34,598			27,654			61,633			39,969
Total revenue		107,840			73,238			184,912			131,569
Operating costs and expenses
Operating costs		74,383			59,405			140,938			103,338
General and administrative		5,161			6,910			9,992			13,492
Depreciation		11,045			11,087			22,094			22,382
(Gain) loss on EDC Sale		—			(60,781	)		3			(60,781	)
Total operating costs and expenses		90,589			16,621			173,027			78,431
Income from operations		17,251			56,617			11,885			53,138
Other (expense) income
Interest income		141			7			190			11
Interest expense and other financing charges		(5,346	)		(8,503	)		(10,904	)		(17,007	)
Other, net		(457	)		(1,011	)		(135	)		(1,786	)
Total other expense		(5,662	)		(9,507	)		(10,849	)		(18,782	)
Income before income taxes		11,589			47,110			1,036			34,356
Income tax provision (benefit)		10,584			(1,221	)		2,606			217
Net income (loss)		1,005			48,331			(1,570	)		34,139
Net (loss) income attributable to noncontrolling interests		(457	)		232			(746	)		938
Net income (loss) attributable to shareholders	$	1,462		$	48,099		$	(824	)	$	33,201
Earnings (loss) per share
Basic	$	0.11		$	3.67		$	(0.06	)	$	2.53
Diluted	$	0.11		$	3.61		$	(0.06	)	$	2.49

The accompanying notes are an integral part of these unaudited consolidated financial statements.

Vantage Drilling International

Consolidated Statement of ~~Cash Flows~~Shareholders’ Equity

(In thousands)

(Unaudited)

Successor

Predecessor

Nine Months Ended September 30, 2017

Period from February 10, 2016 to September 30, 2016

Period from January 1, 2016 to February 10, 2016

CASH FLOWS FROM OPERATING ACTIVITIES

Net loss

$
(113,159
)

$
(106,288
)

$
(472,011
)

Adjustments to reconcile net loss to net cash provided by (used in) operating activities:

Depreciation expense

55,531

49,434

10,696

Amortization of debt financing costs

351

310

—

Amortization of debt discount

36,653

31,075

—

Amortization of contract value

3,095

—

—

PIK interest on the Convertible Notes

5,692

4,822

—

Reorganization items

—

—

430,210

Share-based compensation expense

2,882

76

—

Gain on bargain purchase

(1,910
)

—

—

Deferred income tax benefit

(3,489
)

(2,660
)

—

Loss on disposal of assets

191

634

—

Changes in operating assets and liabilities, net of businesses acquired:

Restricted cash

—

1,000

(1,000
)

Trade receivables

(15,253
)

53,405

(3,575
)

Inventory

1,531

(1,856
)

223

Prepaid expenses and other current assets

(1,685
)

(47
)

6,893

Other assets

5,947

(1,823
)

941

Accounts payable

10,899

2,136

(14,890
)

Accrued liabilities and other long-term liabilities

(4,688
)

(26,935
)

21,148

Net cash (used in) provided by operating activities

(17,412
)

3,283

(21,365
)

CASH FLOWS FROM INVESTING ACTIVITIES

Additions to property and equipment

(1,606
)

(10,107
)

116

Cash paid for Vantage 260 acquisition

(13,000
)

—

—

Net cash (used in) provided by investing activities

(14,606
)

(10,107
)

116

CASH FLOWS FROM FINANCING ACTIVITIES

Repayment of long-term debt

(1,072
)

(1,072
)

(7,000
)

Proceeds from issuance of 10% Second Lien Notes

—

—

75,000

Debt issuance costs

—

(51
)

(1,125
)

Net cash (used in) provided by financing activities

(1,072
)

(1,123
)

66,875

Net (decrease) increase in cash and cash equivalents

(33,090
)

(7,947
)

45,626

Cash and cash equivalents—beginning of period

231,727

249,046

203,420

Cash and cash equivalents—end of period

$
198,637

$
241,099

$
249,046

SUPPLEMENTAL CASH FLOW INFORMATION

Cash paid for:

Interest

$
12,575

$
10,134

$
1,568

Income taxes (net of refunds)

13,253

15,445

(1,864
)

Non-cash investing and financing transactions:

Payment of interest in kind on the Convertible Notes

$
3,780

$
2,911

$
—

Additional notes issued for backstop premium

—

—

1,125


	Six-Month Period Ended June 30, 2022
	Ordinary Shares
	Shares		Amount		Additional Paid-in Capital			Accumulated Deficit			Non-Controlling Interests			Total Equity
Balance January 1, 2022		13,115	$	13	$	633,847		$	(369,792	)	$	1,783		$	265,851
Share-based compensation		—		—		26			—			—			26
Share-based compensation - dividend equivalents		—		—		(63	)		—			—			(63	)
Net (loss) income		—		—		—			(14,898	)		706			(14,192	)
Balance March 31, 2022		13,115	$	13	$	633,810		$	(384,690	)	$	2,489		$	251,622
Share-based compensation		—		—		18			—			—			18
Net income		—		—		—			48,099			232			48,331
Balance June 30, 2022		13,115	$	13	$	633,828		$	(336,591	)	$	2,721		$	299,971


	Six-Month Period Ended June 30, 2023
	Ordinary Shares
	Shares		Amount		Additional Paid-in Capital			Accumulated Deficit			Non-Controlling Interests			Total Equity
Balance January 1, 2023		13,115	$	13	$	633,863		$	(373,147	)	$	1,770		$	262,499
Share-based compensation issuance of shares		114		—		—			—			—			—
Shares repurchased to settle withholding taxes		—		—		(246	)		—			—			(246	)
Share-based compensation		—		—		11			—			—			11
Share-based compensation - dividend equivalents		—		—		(37	)		—			—			(37	)
Net loss		—		—		—			(2,286	)		(289	)		(2,575	)
Balance March 31, 2023		13,229	$	13	$	633,591		$	(375,433	)	$	1,481		$	259,652
Share-based compensation		—		—		14			—			—			14
Net income (loss)		—		—		—			1,462			(457	)		1,005
Balance June 30, 2023		13,229	$	13	$	633,605		$	(373,971	)	$	1,024		$	260,671

The accompanying notes are an integral part of these unaudited consolidated financial statements.

Vantage Drilling International

Consolidated Statement of Cash Flows

(In thousands)

(Unaudited)


	Six Months Ended June 30,
	2023			2022
CASH FLOWS FROM OPERATING ACTIVITIES
Net (loss) income	$	(1,570	)	$	34,139
Adjustments to reconcile net income (loss) to net cash used in operating activities
Depreciation expense		22,094			22,382
Amortization of debt financing costs		862			820
Share-based compensation expense		25			44
Loss on debt extinguishment		703			—
Deferred income tax expense		733			410
Gain on disposal of assets		—			(1,630	)
Loss (gain) on EDC Sale		3			(60,781	)
Changes in operating assets and liabilities:
Trade receivables, net		(20,333	)		(58,864	)
Materials and supplies		(3,509	)		(1,811	)
Prepaid expenses and other current assets		(5,379	)		3,369
Other assets		5,269			(25,043	)
Accounts payable		(2,205	)		29,564
Other current liabilities and other long-term liabilities		(7,773	)		17,696
Net cash used in operating activities		(11,080	)		(39,705	)
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property and equipment		(2,637	)		(7,736	)
Net proceeds from EDC Sale		—			200,000
Net proceeds from sale of assets		—			3,100
Net cash (used in) provided by investing activities		(2,637	)		195,364
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from 9.50% First Lien Notes		194,000			—
Repayment of long-term debt		(180,000	)		—
Shares repurchased for tax withholdings on settlement of RSUs		(246	)		—
Payments of dividend equivalents		(5,278	)		—
Debt issuance costs		(5,645	)		—
Net cash provided by financing activities		2,831			—
Net (decrease) increase in unrestricted and restricted cash and cash equivalents		(10,886	)		155,659
Unrestricted and restricted cash and cash equivalents—beginning of period		93,257			90,608
Unrestricted and restricted cash and cash equivalents—end of period	$	82,371		$	246,267
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for:
Interest	$	5,179			16,229
Income taxes (net of refunds)		6,657			686
Non-cash investing and financing transactions:
Accrued debt issuance costs		227			—
Accrued additions to property and equipment		—			8,908

The accompanying notes are an integral part of these unaudited consolidated financial statements.

VANTAGE DRILLING INTERNATIONAL

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Recent Events

Vantage Drilling International, ~~(the “Company” or “VDI”),~~ a Cayman Islands exempted company, together with its consolidated subsidiaries (collectively the “Company”), is an international offshore drilling company focused on operating a fleet of modern, high specification drilling units. Our principal business is to contract drilling units, related equipment and work crews, primarily on a dayrate basis to drill oil and ~~natural~~ gas wells for our customers. Through our fleet of drilling units, we are a provider of offshore contract drilling services to major, national and independent oil and ~~natural~~ gas companies, focused ~~primarily~~ on international markets. Additionally, for third party owned drilling units, ~~owned by others,~~ we provide operations and marketing services for operating and stacked rigs, construction supervision services ~~while~~for rigs that are under construction, and preservation management services ~~when~~for rigs that are stacked.

On February 3, 2023, the Company issued a notice of full conditional redemption to the then existing recordholders (the “Notice of Full Conditional Redemption”) of the remaining ~~$11.7~~portion of the 9.25% First Lien Notes then outstanding after the partial redemption consummated in December 2022. The balance of the 9.25% First Lien Notes was redeemed in full on March 6, 2023 with proceeds derived from the issuance of the 9.50% First Lien Notes (as discussed immediately below). See “Note 5. Debt” of these “Notes to Unaudited Consolidated Financial Statements” for further information regarding the Notice of Full Conditional Redemption.

9.50% First Lien Notes Offering

On February 14, 2023, the Company priced an offering of $200.0 million ~~was paid at closing. The rig has been renamed~~in aggregate principal amount of the ~~Vantage 260. In August 2017 we substituted the~~ ~~Sapphire Driller, a Baker Marine Pacific Class 375 jack-up rig to fulfill the drilling contract. On October 19, 2017, we~~9.50% First Lien Notes and entered into a purchase ~~and sale~~ agreement with several investors pursuant to which the Company agreed to sell the ~~Vantage 260~~9.50% First Lien Notes (the “9.50% First Lien Notes Offering”) to the purchasers in reliance on an exemption from registration provided by Section 4(a)(2), Rule 144A and/or Regulation S of the Securities Act. On March 1, 2023, the Company closed on the sale of the 9.50% First Lien Notes. See “Note 5. Debt” of these “Notes to Unaudited Consolidated Financial Statements” for ~~$5.1 million.~~ further information regarding the 9.50% First Lien Notes Offering.

The ~~transaction, which is subject to customary closing conditions, is expected to close in~~Aquadrill Merger and the ~~fourth quarter~~Termination of ~~2017.~~ Certain Agreements

~~Restructuring Agreement and Emergence from Voluntary Reorganization under Chapter 11 Proceeding~~

~~On December 1, 2015, we and Vantage Drilling Company (“VDC”), our former parent company,~~VHI previously entered into a ~~restructuring support~~framework agreement with Aquadrill LLC (“Aquadrill”) on February 9, 2021 (the ~~“Restructuring~~“Framework Agreement”), and, certain subsidiaries of VHI (the “VHI Entities”) subsequently entered into a series of related management and marketing agreements (collectively, the “Marketing and Management Agreements” and together with the Framework Agreement, the “Framework, Management and Marketing Agreements”) with ~~a majority~~certain subsidiaries of ~~our secured creditors.~~ Aquadrill (collectively, the “Aquadrill Entities”). Pursuant to the Framework, Management and Marketing agreements, the VHI Entities agreed to provide certain marketing and operational management services with respect to the Capella, Polaris and Aquarius floaters. As of August 8, 2023, the Capella and the Polaris were performing drilling services for clients under their respective drilling contracts, while the Aquarius is currently in Norway and is no longer under the Company’s management.

Pursuant to the terms of the ~~Restructuring Agreement,~~Framework, Management and Marketing Agreements, the Company ~~agreed~~is eligible to ~~pursue a pre-packaged plan of reorganization (the “Reorganization Plan”) under Chapter 11 of Title 11~~receive the following fees associated with the management and marketing of the ~~United States Bankruptcy Code~~Aquadrill rigs: (i) first, the Company is to be paid a fixed management fee of $2,000, $4,000, $6,000 and ~~VDC agreed~~$10,000 per day to ~~commence official liquidation proceedings~~manage a cold stacked rig, warm stacked rig, reactivating rig or operating rig, respectively (provided, that, certain discounts are to be provided on the management fee associated with cold stacked rigs to the extent there are more than one such rigs managed by the Company for Aquadrill); (ii) second, there are certain bonus/malus amounts that are applied to the fixed management fee that are contingent on whether the actual expenditures for a particular rig that is stacked, mobilizing, being reactivated or preparing for a contract exceed or come in under budget; (iii) third, the ~~laws~~Company is eligible to receive a marketing fee of 1.5% of the ~~Cayman Islands. On December 2, 2015, pursuant to~~effective day rate of a drilling contract secured for the ~~Restructuring Agreement,~~benefit of Aquadrill; (iv) fourth, the Company ~~acquired two subsidiaries responsible for the management~~is eligible to earn a variable fee equal to 13% of the ~~Company from VDC in exchange~~gross margin associated with managing an operating rig for a $61.5 million promissory note (the “VDC Note”). As this transaction involved a reorganization of entities under common control, it was reflected in the consolidated financial statements, at carryover basis, on a retrospective basis. Effective with the Company’s emergence from bankruptcy on February 10, 2016 (the “Effective Date”), VDC’s former equity interest inAquadrill; and (v) lastly, all costs incurred by the Company was cancelled. Immediately following that event, the VDC Note was converted into 655,094 new ordinary shares of the reorganized Company (the “New Shares”) in accordance with the terms thereof, in satisfaction of the obligation thereunder, which, including accrued interest, totaled approximately $62.6 million as of such date.

On December 3, 2015 (the “Petition Date”), the Company, certain of its subsidiaries and certain VDC subsidiaries who were guarantors of the Company’s pre-bankruptcy secured debt, filed the Reorganization Plan in the United States Bankruptcy Court for the District of Delaware (~~In re Vantage Drilling International (F/K/A Offshore Group Investment Limited), et al., Case No. 15-12422)~~are reimbursed by Aquadrill (other than incremental overhead costs incurred by Vantage). ~~On January 15, 2016, the District Court of Delaware confirmed the Company’s pre-packaged Reorganization Plan and the Company emerged from bankruptcy on the Effective Date.~~

Pursuant to the terms of the Reorganization Plan, the pre-bankruptcy term loans and senior notes were retired on the Effective Date by issuing to the debtholders 4,344,959 units in the reorganized Company (the “Units”). Each Unit of securities originally consisted of one New Share and $172.61 of principal of the Company’s 1%/12% Step-Up Senior Secured Third Lien Convertible Notes due 2030 (the “Convertible Notes”), subject to adjustment upon the payment of interest in kind (“PIK interest”) and certain cases of redemption or conversion of the Convertible Notes, as well as share splits, share dividends, consolidation or reclassification of the New Shares~~. The New Shares and the Convertible Notes are subject to the terms of an agreement that prohibits the New Shares and Convertible Notes from being traded separately.~~

~~The Convertible Notes are convertible into New Shares in certain circumstances, at a conversion price (subject to adjustment in~~In accordance with the terms of the ~~Indenture for the Convertible Notes) which was $95.60 as of the issue date. The Indenture for the Convertible Notes includes customary covenants~~Framework, Marketing and Management Agreements, Aquadrill may also terminate such agreements upon 90 days’ notice (the “Notice Termination Period”), subject to certain conditions set forth in such agreements.

On December 23, 2022, Seadrill Ltd. announced that restrict, among other things, the granting of liens and customary events of default, including among other things, failure to issue securities upon conversion of the Convertible Notes. As of September 30, 2017, taking into account the payment of PIK interest on the Convertible Notes to such date, each such Unit consisted of one New Share and $175.02 of principal of Convertible Notes.

~~Other significant elements of the Reorganization Plan included:~~

~~Second Amended and Restated Credit Agreement~~. The Company’s pre-petition credit agreement was amended to (i) replace the $32.0 million revolving letter of credit commitment under its pre-petition facility with a new $32.0 million revolving letter of credit facility and (ii) repay the $150 million of outstanding borrowings with (a) $7.0 million of cash and (b) the issuance of $143.0 million initial term loans (the “2016 Term Loan Facility”).

~~10% Senior Secured Second Lien Notes~~. Holders of the Company’s pre-petition term loans and senior notes claims were eligible to participate in a rights offering conducted by the Company for $75.0 million of the Company’s new 10% Senior Secured Second Lien Notes due 2020 (the “10% Second Lien Notes”). In connection with this rights offering, certain creditors entered into a

“backstop” agreement to purchase 10% Second Lien Notes if the offer was not fully subscribed. The premium paid to such creditors under the backstop agreement was approximately $2.2 million, which was paid $1.1 million in cash and $1.1 million in additional 10% Second Lien Notes, resulting in a total issued amount of $76.1 million of 10% Second Lien Notes and net cash proceeds to the Company of $73.9 million, after deducting the cash portion of the backstop premium.

The Reorganization Plan allowed the Company to continue business operations during the court proceedings and maintain all operating assets and agreements. The Company had adequate liquidity prior to the filing and did not have to seek any debtor-in-possession financing. All trade payables, credits, wages and other related obligations were unimpaired by the Reorganization Plan.

~~Other Events:~~ ~~In July 2015, we became aware that Hamylton Padilha, the Brazilian agent VDC used in the contracting of the~~ ~~Titanium Explorer~~ ~~drillship to Petroleo Brasileiro S.A. (“Petrobras”),~~it had entered into a ~~plea arrangement~~merger agreement with Aquadrill, pursuant to which Aquadrill would become a wholly owned subsidiary of Seadrill Ltd. (the “Aquadrill Merger”), and on April 3, 2023, Seadrill Ltd. announced that it had closed the Aquadrill Merger. Subsequent to the Aquadrill Merger, Aquadrill was renamed to Seadrill LLC (”Seadrill”). On April 10, 2023, we received a notice of termination (the “Termination Notice”) of the management agreement (the “Aquarius Management Agreement”) and marketing agreement with respect to the Aquarius (the “Aquarius Marketing Agreement,” and together with the ~~Brazilian authorities in connection~~Aquarius Management Agreement, the “Aquarius Agreements”), and the marketing agreements with ~~his role in facilitating the payment of bribes to former Petrobras executives. Among other things, Mr. Padilha provided information~~respect to the ~~Brazilian authorities of an alleged bribery scheme between former Petrobras executives~~ Capella and ~~Mr. Hsin-Chi Su, who was, at~~ Polaris (the ~~time~~“Capella and Polaris Marketing Agreements”), in each case as a result of the ~~alleged bribery scheme, a member~~Aquadrill Merger. Given that the Notice Termination Period has now lapsed, we are therefore no longer managing or marketing the Aquarius nor eligible to earn management fees under the Aquarius Management Agreement as of July 9, 2023. Notwithstanding the termination of the ~~Board of Directors and a significant shareholder of our former parent company, VDC. When we learned of Mr. Padilha’s plea agreement~~Aquarius

Agreements and the ~~allegations,~~Capella and Polaris Marketing Agreements, certain provisions survived such termination and, therefore, to the extent that a drilling contract(s) is secured and executed in respect of outstanding bids or tenders for the Aquarius, Polaris and/or Capella, we ~~voluntarily contacted~~will still be eligible to earn the ~~U.S. Department~~marketing fee in respect of ~~Justice (“DOJ”)~~such secured and ~~the~~ ~~Securities and Exchange Commission (the “SEC”)~~ ~~to advise them of these developments,~~executed contracts, as well as in respect of existing drilling contracts. Moreover, as the ~~fact that we had engaged outside counsel~~management agreements with respect to ~~conduct an internal investigation~~the Capella and Polaris remain in effect as of the ~~allegations. Since disclosing this matter~~date hereof, we continue to manage and operate those rigs for Seadrill Ltd. (and for the ~~DOJ~~oil and ~~SEC, we have cooperated fully~~gas clients under their respective drilling contracts) and therefore, remain eligible to receive the management and variable fees described immediately above. Nevertheless, there is no guarantee that such arrangements will remain in their investigation of these allegations. In connection with such cooperation, we advised both agencies that in early 2010, we engaged outside counsel to investigate a report of alleged improper payments to customs and immigration officials in Asia. That investigation was concluded in 2011, and we determined at that time that no disclosure was warranted; however, in an abundance of caution, we provided the results of this investigation to the DOJ and SEC in light of the allegationsplace in the ~~Petrobras matter. In August 2017, we received a letter from the DOJ acknowledging our full cooperation in the DOJ’s investigation into the Company concerning the possible violations~~near- and long-term and any further terminations of ~~the U.S. Foreign Corrupt Practices Act (“FCPA”) in the Petrobras matter and indicating that the DOJ has closed~~ such investigation without any action. Although the DOJ’s investigation into this matter has closed, we cannot predict the outcome of the SEC’s investigation, which remains open, and if the SEC determines that violations of the FCPA have occurred, the Company could be subject to civil and criminal sanctions, including monetary penalties, as well as additional requirements or changes to our business practices and compliance programs, any or all of whicharrangements could have a material ~~adverse effect~~impact on our ~~business~~financial condition and ~~financial condition. Additionally, if we become subject to any judgment, decree, order, governmental penalty or fine, this may constitute an event~~future results of default under the terms of our secured debt agreements and, following notice from the requisite lenders and/or noteholders, as applicable, result in our outstanding debt under the 2016 Term Loan Facility and 10% Second Lien Notes becoming immediately due and payable at par, and our outstanding debt under Convertible Notes becoming immediately due and payable at the make-whole amount specified in the indenture governing the Convertible Notes.operations.

2. Basis of Presentation and Significant Accounting Policies

Basis of Consolidation: The accompanying interim consolidated financial information as of ~~September~~June 30, ~~2017,~~2023, and for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, for the three months ended September 30, 2016, for the period from February 10, 2016 to September 30, 2016~~2023 and ~~for the period from January 1, 2016 to February 10, 2016~~2022, has been prepared without audit, pursuant to the rules and regulations ofpromulgated by the SEC, and includes our accounts and those of our majority owned subsidiaries and ~~variable interest entities (“VIEs”)~~VIEs (as discussed ~~below.~~below). All significant intercompany transactions and accounts have been eliminated. They reflect all adjustments which are, in the opinion of management, necessary for a fair ~~presentation~~statement of the financial position and results of operations for the interim periods, on a basis consistent with the annual audited financial statements. Certain information and footnote disclosures normally included in financial statements prepared in accordance with ~~generally accepted accounting principles in the United States of America (“~~U.S. ~~GAAP”)~~GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC, although we believe that the disclosures made are adequate to provide for fair ~~presentation. The consolidated balance sheet~~statement. Our Consolidated Balance Sheet at December 31, ~~2016~~2022 is derived from our audited consolidated financial statements for the year ended December 31, ~~2016 audited financial statements.~~2022. These interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022, which was filed with the SEC on March 31, 2023. The results of operations for the interim periods are not necessarily indicative of the operating results for the full fiscal year or any future periods. Certain previously reported amounts have been reclassified to conform to the current period presentation.

~~In connection with our bankruptcy filing, we were subject to the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 852~~ ~~Reorganizations~~ (“ASC 852”). All expenses, realized gains and losses and provisions for losses directly associated with the bankruptcy proceedings were classified as “reorganization items” in the consolidated statements of operations. Certain pre-petition liabilities subject to Chapter 11 proceedings were considered as Liabilities Subject To Compromise (“LSTC”) on the Petition Date and just prior to our emergence from bankruptcy on the Effective Date. The LSTC classification distinguished such liabilities from the liabilities that were not expected to be compromised and liabilities incurred post-petition.

ASC 852 requires that subsequent to the Petition Date, expenses, realized gains and losses and provisions for losses that can be directly associated with the reorganization of the business be reported separately as reorganization items in the consolidated statements of operations. We were required to distinguish pre-petition liabilities subject to compromise from those that were not and

post-petition liabilities in our balance sheet. Liabilities that were subject to compromise were reported at the amounts expected to be allowed by the Bankruptcy Court, even if they were settled for lesser amounts as a result of the Reorganization Plan.

Upon emergence from bankruptcy on the Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical consolidated balance sheets. The effects of the Reorganization Plan and the application of fresh-start accounting were reflected in our consolidated financial statements as of February 10, 2016 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items for the period January 1, 2016 to February 10, 2016.

As a result, our consolidated balance sheets and consolidated statement of operations subsequent to the Effective Date will not be comparable to our consolidated balance sheets and statements of operations prior to the Effective Date. Our consolidated financial statements and related notes are presented with a black line division which delineates the lack of comparability between amounts presented on or after February 10, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

References to “Successor” relate to the Company on and subsequent to the Effective Date. References to “Predecessor” refer to the Company prior to the Effective Date. The consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.

In addition to the consolidation of our majority owned subsidiaries, we also consolidate VIEs when we are determined to be the primary beneficiary of a VIE. Determination of the primary beneficiary of a VIE is based on whether an entity has (1) the power to direct activities that most significantly impact the economic performance of the VIE and (2) the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. Our determination of the primary beneficiary of a VIE considers all relationships between us and the VIE. ~~Certain subsidiaries~~

ADVantage is a joint venture company formed to operate deepwater drilling rigs in Egypt. We determined that ADVantage met the criteria of ~~VDC, who were guarantors of our pre-petition debt~~a VIE for accounting purposes because its equity at risk was insufficient to permit it to carry on its activities without additional subordinated financial support from us. We also determined that we are the primary beneficiary for accounting purposes since we are entitled to use ADVantage for deepwater drilling contract opportunities rejected by ADES, and ~~part~~have the (a) power to direct the operating activities associated with the deepwater drilling rigs, which are the activities that most significantly impact the entity’s economic performance, and (b) obligation to absorb losses or the right to receive a majority of the ~~Reorganization Plan, became our subsidiaries upon emergence from bankruptcy on~~benefits that could be potentially significant to the ~~Effective Date. We consolidated these entities~~VIE. As a result, we consolidate ADVantage in our ~~Predecessor~~ consolidated financial statements, ~~because~~ we ~~determined~~eliminate intercompany transactions and we present the interests that ~~they were VIEs~~are not owned by us as “Noncontrolling interests” in our Consolidated Balance Sheets. The carrying amount associated with ADVantage was as follows:


	June 30, 2023		December 31, 2022
(unaudited, in thousands)
Current assets	$	4,380	$	11,383
Non-current assets		736		1,590
Current liabilities		983		4,749
Non-current liabilities		2,068		4,637
Net carrying amount	$	2,065	$	3,587

As ADVantage is a majority owned subsidiary of the Company, it serves as a guarantor under the 9.50% First Lien Indenture. The 9.50% First Lien Notes are secured by a first priority lien on all of the assets of ADVantage, subject to certain exceptions. Creditors’ recourse against ADVantage for liabilities of ADVantage is limited to the assets of ADVantage.

See “Note 9. Supplemental Financial Information” of these “Notes to Unaudited Consolidated Financial Statements” for additional information regarding related party transactions associated with this joint venture.

Use of Estimates: The preparation of financial statements in accordance with U.S. GAAP requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we ~~were the primary beneficiary. The following table summarizes the net effect of consolidating~~evaluate our estimates, including those related to property and equipment, income taxes, insurance, employee benefits and contingent liabilities. Actual results could differ from these ~~entities on our Predecessor consolidated statement of operations.~~ estimates.

Predecessor

Period from January 1, 2016 to February 10, 2016

(unaudited, in thousands)

Revenue

$
1,219

Operating costs and expenses

1,240

Income before taxes

22

Income tax provision

991

Net income (loss) attributable to noncontrolling interests

(969
)

Cash and Cash Equivalents: Includes deposits with financial institutions ~~as well as short-term money market~~and compliant financial instruments with maturities of three months or less when purchased.

~~Inventory:~~Materials and Supplies: Consists of materials, ~~consumables,~~ spare parts, consumables and related supplies for our drilling ~~rigs~~rigs. We record these materials and ~~is carried~~supplies at ~~the lower of~~their average ~~cost or market.~~cost.

Property and Equipment: Consists ~~of the costs~~ of our drilling rigs, furniture and fixtures, computer equipment and capitalized costs for computer software. Drilling rigs are depreciated on a component basis over estimated useful lives ranging from five to ~~thirty-five~~35 years on a straight-line basis as of the date placed in service. Other assets are depreciated upon placement in service over estimated useful lives ranging from three to seven years on a straight-line basis. When assets are sold, retired or otherwise disposed of, the cost and related accumulated depreciation are removed from our Consolidated Balance Sheets and the ~~accounts and a~~resulting gain or loss is ~~recognized.~~included in “Operating costs” or “General and administrative” expenses on the Consolidated Statement of Operations, depending on the nature of the asset. For the three and six months ended June 30, 2022, we recognized a net loss of approximately $0.3 million and net gain of approximately $1.6 million, respectively, related to the sale or retirement of assets. The gain/loss related to the sale or retirement of assets for the three and six months ended June 30, 2023 was immaterial.

We evaluate the realization of property and equipment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss on our property and equipment exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. Any impairment loss recognized would ~~represent~~be computed as the excess of the asset’s carrying value over the estimated fair value. ~~In connection~~Estimates of future cash flows require us to make long-term forecasts of our future revenues and operating costs with regard to the assets subject to review. Our business, including the utilization rates and dayrates we receive for our ~~adoption~~drilling rigs, depends on the level of ~~fresh-start accounting upon~~ our ~~emergence from bankruptcy on February 10, 2016, an adjustment~~customers’ expenditures for oil and gas exploration, development and production expenditures. Oil and gas prices and customers’ expectations of ~~$2.0 billion was recorded~~potential changes in these prices, the general outlook for worldwide economic growth, political and social stability in the major oil and gas producing basins of the world, availability of credit and changes in governmental laws and regulations, among many other factors, significantly affect our customers’ levels of expenditures. Sustained declines in or persistent depressed levels of oil and gas prices, worldwide rig counts and utilization, reduced access to ~~decrease~~credit markets, reduced or depressed sale prices of comparably equipped jackups and drillships and any other significant adverse economic news could require us to evaluate the ~~net book value~~realization of our drilling ~~rigs to estimated fair value.~~rigs. As of ~~September~~June 30, ~~2017,~~2023, no triggering event has occurred to indicate that the ~~current~~ carrying value of our drilling rigs may not be recoverable.

Interest costs and the amortization of debt financing costs related to the financings of our drilling rigs are capitalized as part of the cost while they are under construction and prior to the commencement of each vessel’s first contract. We did ~~not~~not capitalize any interest for the reported periods.

~~Intangible assets:~~ ~~In connection with our acquisition of the~~ ~~Vantage 260~~ and related multi-year drilling contract, the Company recorded an identifiable intangible asset of $12.6 million for the fair value of the acquired favorable drilling contract. The resulting intangible asset is being amortized on a straight-line basis over the term of the drilling contract. We recognized approximately $1.5 million and $3.1 million of amortization expense for intangible assets for the three and nine months ended September 30, 2017, respectively.

~~Expected future intangible asset amortization as of September 30, 2017 is as follows:~~

(in thousands)

Fiscal year:

Remaining 2017
$
1,591

2018

6,311

2019

1,643

Thereafter

-

Total
$
9,545

Debt Financing Costs: Costs incurred with financing debt ~~financings~~ are deferred and amortized over the term of the related financing facility on a straight-line basis, which approximates the effective interest method. Debt issuance costs ~~related to a recognized debt liability~~ are presented in the ~~consolidated balance sheet~~Consolidated Balance Sheets as a direct deduction from the carrying amount of that debt liability.

~~Revenue:~~ ~~Revenue is recognized as services are performed based on contracted dayrates and the number of operating days during the period.~~

In connection with a customer contract, we may receive lump-sum fees for the mobilization of equipment and personnel or the demobilization of equipment and personnel upon completion. Mobilization fees received and costs incurred to mobilize a rig from one geographic market to another are deferred and recognized on a straight-line basis over the term of such contract, excluding any option periods. Costs incurred to mobilize a rig without a contract are expensed as incurred. Fees or lump-sum payments received for capital improvements to rigs are deferred and amortized to income over the term of the related drilling contract. The costs of such capital improvements are capitalized and depreciated over the useful lives of the assets. Upon completion of drilling contracts, any demobilization fees received are recorded as revenue. We record reimbursements from customers for rebillable costs and expenses as revenue and the related direct costs as operating expenses.

Rig and Equipment Certifications: We are required to obtain regulatory certifications to operate our drilling rigs and certain specified equipment, and must maintain such certifications through periodic inspections and surveys. These certifications are typically valid for approximately 2.5 to 5 years. The costs associated with these certifications, including drydock costs, are deferred and amortized over the corresponding certification periods.

Revenue Recognition: See “Note 3. Revenue from Contracts with Customers” of these “Notes to Unaudited Consolidated Financial Statements” for further information.

Income Taxes: Income taxes are provided for based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. Deferred income tax assets and liabilities are computed for differences between the financial statement basis and tax basis of assets and liabilities that will result in future taxable or ~~deductible~~tax-deductible amounts and are based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. We do not establish deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely reinvest to finance foreign activities. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized. We recognize interest and penalties related to income taxes as a component of income tax expense.

Concentrations of Credit Risk: Financial instruments that potentially subject us to a significant concentration of credit risk consist primarily of cash and cash equivalents, restricted cash and accounts receivable. We maintain deposits in federally insured financial institutions in excess of federally insured limits. We monitor the credit ratings and our concentration of risk with these financial institutions on a continuing basis to safeguard our cash deposits. We have a limited number of key customers, who are primarily large international oil and gas operators, national oil companies and other international oil and gas companies. Our contracts provide for monthly billings as services are performed and we monitor compliance with contract payment terms on an ongoing basis. Payment terms on customer invoices typically range from 30 to 45 days. Outstanding receivables beyond payment terms are promptly investigated and discussed with the specific customer. ~~We do not have an~~

Four customers accounted for approximately 30%, 22%, 15% and 15% of our consolidated trade receivables, net as of June 30, 2023, and three customers accounted for approximately 34%, 26% and 12% of our consolidated trade receivables, net as of June 30, 2022.

Credit Losses – Accounts Receivable: The allowance for ~~doubtful accounts~~credit losses is based on the Company’s assessment of the collectability of customer accounts. Current estimates of expected credit losses consider factors such as the historical experience and credit quality of our customers. The Company considers historical loss information as the most reasonable basis on which to determine expected credit losses unless current or forecasted future conditions for customers (or customer groups) indicate that risk characteristics have changed. We also considered the impact of oil price and market share volatility, as well as other applicable macroeconomic considerations, on our ~~trade receivables~~allowance for credit losses.

The following is a summary of the allowance for credit losses:


	June 30, 2023			December 31, 2022
(unaudited, in thousands)
Beginning balance	$	4,962		$	4,962
Additions charged to expenses		942			—
Write-offs		(2,054	)		—
Ending balance	$	3,850		$	4,962

The allowance for credit loss includes an amount that represents a customer’s decisions not to pay us for days impacted by what we believe were force majeure and other similar events for which we would still be entitled to receive payment under the applicable contracts. We disagree with the customer's decision and are currently evaluating our remedies, if any, under the applicable contracts. The write-offs in the period represent items where the Company has used reasonable collection efforts and are deemed as ~~of September 30, 2017 or December 31, 2016.~~uncollectible receivables.

~~Use of Estimates:~~ ~~The preparation of financial statements~~Earnings (loss) per Share: We compute basic and diluted EPS in accordance with ~~U.S. GAAP requires management~~the two-class method. We include restricted stock units granted to ~~make estimates~~employees and ~~assumptions~~directors that ~~affect~~contain non-forfeitable rights to dividends as such grants are considered participating securities. Basic earnings (loss) per share are based on the ~~reported amounts~~weighted average number of ~~assets~~Ordinary Shares outstanding during the applicable period. Diluted EPS are computed based on the weighted average number of Ordinary Shares and ~~liabilities and~~ordinary share equivalents outstanding in the ~~disclosure of contingent assets and liabilities at~~applicable period, as if all potentially dilutive securities were converted into Ordinary Shares (using the ~~date~~treasury stock method).

The following is a reconciliation of the ~~financial statements~~number of shares used for the basic and diluted EPS computations:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(unaudited, in thousands)
Weighted average Ordinary Shares outstanding for basic EPS		13,229		13,115		13,204		13,115
Restricted share equity awards		91		217		—		215
Adjusted weighted average Ordinary Shares outstanding for diluted EPS		13,320		13,332		13,204		13,330

The following sets forth the ~~reported amounts~~number of shares excluded from diluted EPS computations due to their antidilutive effect:


	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(unaudited, in thousands)
Restricted share equity awards		—		—		103		—
Future potentially dilutive Ordinary Shares excluded from diluted EPS		—		—		103		—

Functional Currency: We consider USD to be the functional currency for all of our operations since the majority of our revenues and ~~expenses during~~expenditures are denominated in USD, which limits our exposure to currency exchange rate fluctuations. We recognize currency exchange rate gains and losses in “Other, net” in our Consolidated Statement of Operations. For the ~~reporting period. On an ongoing basis,~~three and six months ended June 30, 2023, we ~~evaluate our estimates, including those~~recognized a net loss of approximately $0.5 million and $0.1 million, respectively, related to ~~property~~currency exchange rates. For the three and ~~equipment, income taxes, insurance, employee benefits~~six months ended June 30, 2022, we recognized a net loss of approximately $1.0 million and ~~contingent liabilities. Actual results could differ from these estimates.~~$1.8 million, respectively, related to currency exchange rates.

Fair Value of Financial Instruments: The financial instruments of the Company consist primarily of cash and cash equivalents, accounts receivable and accounts payable. These items are considered Level 1 due to their short-term nature and their market interest rates and are, therefore, considered a reasonable estimate of fair value. The Company classifies short-term investments within Level 1 in the fair value hierarchy because quoted prices for identical assets in active markets are used to determine fair value. As of our short-term financial assets and liabilities approximates the carrying amounts represented in the consolidated balance sheet principally due to the short-term nature or floating rate nature of these

~~instruments. At September~~June 30, ~~2017,~~2023, the fair value of the ~~2016 Term Loan Facility, the 10% Second~~9.50% First Lien ~~Notes and the Convertible~~ Notes was approximately ~~$142.3~~$196.6 million ~~$73.1 million and $808.2 million, respectively,~~ based on quoted market prices in a less active

market, a Level 2 measurement. See “Note 5. Debt” of these “Notes to Unaudited Consolidated Financial Statements” for additional information on the 9.50% First Lien Notes.

Share-based Compensation:TBGs granted under the 2016 Amended MIP vest annually, ratably over four years; however, accelerated vesting is provided for in the event of a QLE. Otherwise, the settlement of any vested TBGs occurs upon the seventh anniversary of the effective date set forth in each individual award letter.PBGs granted under the 2016 Amended MIP contain vesting eligibility provisions tied to the earlier of a QLE or seven years from the Effective Date. Upon the occurrence of a vesting eligibility event, the number of PBGs that vest will be dependent on the achievement of pre-determined TEV targets specified in the grants.

~~Recent~~Both the TBGs and PBGs are classified as equity awards. Under the provisions of ASC 718 Compensation – Stock Compensation share-based compensation expense is recognized over the requisite service period from the grant date to the fourth-year vest date for TBGs. For PBGs, expense will be recognized when it is probable that the TEV targets will be met. Once it is probable the performance condition will be met, compensation expense based on the fair value of the PBGs at the conversion date of the Convertible Notes will be recognized for the service period completed to the seventh anniversary of the Effective Date for PBGs.

Noncontrolling Interest:

Noncontrolling interests represent the equity investments of the minority owner in ADVantage, a joint venture with ADES that we consolidate in our financial statements.

Recently Adopted Accounting Standards:~~In May 2014,~~

No new accounting standards were adopted during the ~~FASB~~ ~~issued~~ ~~ASU~~ ~~No. 2014-09,~~ three-month period ended June 30, 2023.

Recently Issued Accounting Standards:

There have been no new accounting pronouncements not yet effective that have significance with respect to our consolidated financial statements.

3. Revenue from Contracts with Customers~~. ASU No. 2014-09 supersedes most of~~

The activities that primarily drive the ~~existing~~ revenue ~~recognition requirements~~earned in ~~U.S. GAAP, including industry-specific guidance.~~ The ASU is based on the principle that revenue is recognized when an entity transfers promised goods and services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new standard also requires significant additional disclosures regarding the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those years, using either a full or a modified retrospective application approach. We plan to adopt ASU 2014-09 effective January 1, 2018 using the modified retrospective approach whereby we will record the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018 as an adjustment to opening retained earnings.

~~When applying the new standard, we currently plan to account for the integrated services provided within~~ our drilling contracts aswith customers include (i) providing our drilling rig, work crews, related equipment and services necessary to operate the rig, (ii) delivering the drilling rig by mobilizing to, and demobilizing from, the drill site, and (iii) performing pre-operating activities, including rig preparation activities and/or equipment modifications required for the contract.

The integrated drilling services that we perform under each drilling contract represent a single performance obligation ~~composed~~satisfied over time and comprised of a series of distinct time increments, ~~which will be satisfied over time.~~or service periods. We ~~will determine~~have elected to exclude from the ~~total~~ transaction price measurement all taxes assessed by a governmental authority.

Dayrate Drilling Revenue. Our drilling contracts generally provide for ~~each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. Consideration that does not relate to~~payment on a distinct good or service, such as mobilization and demobilization revenue, will be allocated across the single performance obligation and recognized ratably each period over the term of the contract. All other components of consideration within a contract, including the dayrate ~~revenue, will continue to be recognized in the period~~basis, with higher rates for periods when the ~~services~~drilling unit is operating and lower rates or zero rates for periods when drilling operations are ~~performed. We expect our revenue recognition under ASU 2014-09~~interrupted or restricted. The dayrate billed to ~~differ from our current revenue recognition pattern only as~~the customer is determined based on varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to ~~demobilization revenue. Demobilization revenue, which is currently~~within the contract term and therefore, recognized ~~upon completion~~as we perform the daily drilling services.

For rigs owned by a third party that we manage or support, the contracts generally provide for a fixed fee based on various factors, including the status of the rig or a specific duration. In addition, we may earn a marketing fee based on a percentage of the effective dayrate of a drilling contract ~~will~~secured on behalf of the third party and a variable management fee of the gross margin associated with managing an operating rig. We are considered the principal or agent with respect to certain contractual arrangements and therefore, we record the associated revenue at the gross or net amounts billed to the customers, respectively.

Amortizable Revenue. In connection with certain contracts, we receive lump-sum fees or similar compensation for (i) the mobilization of equipment and personnel prior to the commencement of drilling services, (ii) the demobilization of equipment and personnel upon contract completion or (iii) postponement fees in consideration for the postponement of a contract until a later date. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall single performance obligation.

Mobilization fees received prior to the commencement of drilling operations are recorded as a contract liability and amortized on a straight‑line basis over the initial contract period. Demobilization fees expected to be received upon contract completion are estimated at contract ~~commencement~~inception and recognized on a straight-line basis over the initial contract term, with an offset to an accretive contract asset. In many contracts, demobilization fees are contingent upon the occurrence or non-occurrence of a future event and the estimate for such revenue may therefore be constrained. In such cases, this may result in cumulative-effect adjustments to demobilization revenues upon changes in our estimates of future events during the contract term. Postponement fees received that are contingent upon the occurrence or non-occurrence of a future event are recognized on a straight-line basis over the contract term.Fees received for the mobilization or demobilization of equipment and personnel are included in “Contract drilling services” in our Consolidated Statement of Operations.

Capital Upgrade/Contract Preparation Revenue. In connection with certain contracts, we receive lump-sum fees or similar compensation for requested capital upgrades to our drilling rigs or for other contract preparation work. These activities are not considered to be distinct within the context of the contract and therefore, fees received are recorded as a contract liability and amortized to contract drilling revenues on a straight-line basis over the initial contract term.

Charter Lease Revenue. In relation to certain bareboat charter agreements where we lease our owned rigs to unaffiliated third parties, we receive a fixed fee based on the number of days the rig is drilling. Furthermore, under certain other bareboat charter agreements, we receive a variable fee based on a percentage of gross margin generated on a monthly basis.

Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. We may be considered a principal or an agent in such transactions and therefore, we recognize reimbursable revenues and the corresponding costs either on a gross or net basis, as applicable, as we provide the requested goods and services.

Disaggregation of Revenue

The following tables present our revenue disaggregated by revenue source for the periods indicated:


	Three Months Ended June 30, 2023								Three Months Ended June 30, 2022
	Jackups		Deepwater		Managed		Consolidated		Jackups		Deepwater		Managed		Consolidated
(unaudited, in thousands)
Dayrate revenue	$	4,975	$	35,177	$	25,526	$	65,678	$	15,963	$	24,304	$	2,840	$	43,107
Amortized revenue		123		6,103		1,338		7,564		1,439		1,038		—		2,477
Charter lease revenue		3,152		—		—		3,152		—		—		—		—
Reimbursable revenue		3,237		1,445		26,764		31,446		1,944		3,175		22,535		27,654
Total revenue	$	11,487	$	42,725	$	53,628	$	107,840	$	19,346	$	28,517	$	25,375	$	73,238


	Six Months Ended June 30, 2023								Six Months Ended June 30, 2022
	Jackups		Deepwater		Managed		Consolidated		Jackups		Deepwater		Managed		Consolidated
(unaudited, in thousands)
Dayrate revenue	$	10,098	$	54,752	$	47,251	$	112,101	$	31,294	$	50,300	$	3,943	$	85,537
Amortized revenue		236		8,280		2,662		11,178		1,659		4,404		—		6,063
Charter lease revenue		5,302		—		—		5,302		—		—		—		—
Reimbursable revenue		6,455		2,499		47,377		56,331		4,151		6,151		29,667		39,969
Total revenue	$	22,091	$	65,531	$	97,290	$	184,912	$	37,104	$	60,855	$	33,610	$	131,569

Dayrate revenue and amortized revenue for “Jackups” and “Deepwater” are included within “Contract drilling services” in our Consolidated Statement of Operations. Dayrate revenue for “Managed” is included within “Contract drilling services” and “Management fees” within our Consolidated Statement of Operations. All other revenue is included within “Reimbursables and other” in our Consolidated Statement of Operations.

Accounts Receivable, Contract Liabilities and Contract Costs

Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on customer invoices typically range from 30 to 45 days.

We recognize contract liabilities, recorded in other “Other current liabilities” and “Other long-term liabilities” within our Consolidated Balance Sheets, for prepayments received from customers and for deferred revenue received for mobilization, contract preparation and capital upgrades.

Certain direct and incremental costs incurred for contract preparation, initial mobilization and modifications of contracted rigs represent contract fulfillment costs as they relate directly to a contract, enhance resources that will be used to satisfy our performance obligations in the future and are expected to be recovered. These costs are deferred as a current or noncurrent asset depending on the length of the initial contract term and are amortized on a straight-line basis to operating costs as services are rendered over the initial term of the ~~contract under~~related drilling contract. Costs incurred for capital upgrades are capitalized and depreciated over the new guidance. Additionally, we currently expect that the cumulative effect adjustment to opening retained earnings required by the modified retrospective adoption approach will not be significant as it will primarily consistuseful life of the ~~impact of the timing difference related to recognition of demobilization revenue for affected contracts. Not all drilling contracts include a demobilization provision. Our adoption of ASU No, 2014-09,~~ ~~and the ultimate effect on our consolidated financial statements,~~ ~~is subject to potential change as we continue to evaluate application of the accounting standard.~~asset.

~~In February 2016, the FASB issued ASU No. 2016-02,~~ ~~Leases (Topic 842): Amendments to the FASB Accounting Standards Codification~~, to increase transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU No. 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, and early adoption is permitted. A modified retrospective approach is required. We expect to adopt ASU 2016-02 on January 1, 2019. Under the updated accounting standards, we have concluded that our drilling contracts contain a lease component, and our adoption, therefore, will require that we separately recognize revenues associated with the lease of our drilling rigs and the provision of contract drilling services. Our adoption of ASU No. 2016-02, and the ultimate effect on our consolidated financial statements, will be based on an evaluation of the contract-specific facts and circumstances, and such effect could result in differences in the timing of our revenue recognition relative to current accounting standards. With respect to leases whereby we are the lessee we expect to recognize lease liabilities and corresponding “right of use” assets. We are continuing to evaluate the requirements with regard to arrangements under which we are either the lessor or lessee, to determine the effect such requirements may have on our consolidated statements of financial position, operations and cash flows and on the disclosures contained in our notes to consolidated financial statements.

~~In August 2016, the FASB issued ASU No. 2016-15,~~ ~~Classification of Certain Cash Receipts and Cash Payments,~~ ~~which addresses the classification and presentation of eight specific cash flow issues that currently result in diverse practice.~~ ASU No. 2016-15 is effective for fiscal years beginning after December 15, 2017 utilizing a retrospective transition approach. Early adoption is permitted, provided that all amendments are adopted in the same period. We are currently evaluating the provisions of ASU 2016-15 but do not expect the standard update to have a significant impact on the presentation of cash receipts and cash payments within our consolidated statements of cash flows.

~~In October 2016, the FASB issued ASU No. 2016-16,~~ ~~Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory~~, which requires entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transaction occurs as opposed to deferring tax consequences and amortizing them into future periods. This update is effective for annual and interim periods beginning after December 15, 2017, with early adoption permitted. A modified retrospective approach with a cumulative-effect adjustment directly to retained earnings at the beginning of the period of adoption is required. We have not completed an evaluation of ASU No. 2016-16 and have not yet determined the impact, if any, on our financial statements and related disclosures.

~~In January 2017, the FASB issued ASU No. 2017-01,~~ ~~Business Combinations (Topic 805): Clarifying the Definition of a Business~~, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU No. 2017-01 is effective for financial

~~statements issued for fiscal years beginning after December 15, 2017 utilizing a prospective basis on or after the effective date. Early adoption is permitted. We~~ ~~are currently evaluating the provisions~~ ~~of ASU~~ ~~No.~~ ~~2017-01 but do not expect the standard update to have a significant impact, if any, on our financial statements and related disclosures.~~

~~3. Acquisitions~~

On April 5, 2017, pursuant to a purchase and sale agreement with a third party, we completed the purchase of a class 154-44C jackup rig and related multi-year drilling contract for $13.0 million. A down payment of $1.3 million was made in February 2017 upon execution of the agreement and the remaining $11.7 million was paid at closing. The rig has been renamed the ~~Vantage 260. In August 2017 we substituted the~~ ~~Sapphire Driller, a Baker Marine Pacific Class 375 jack-up rig to fulfill the contract. The~~ ~~Vantage 260~~ ~~is currently classified as held for sale. We accounted~~Costs incurred for the ~~acquisition~~demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred to mobilize a business combination in accordance with accounting guidance which requires, among other things, that we allocate the purchase price to the assets acquired and liabilities assumed based on their fair valuesrig without a contract are expensed as ~~of the acquisition date.~~ incurred.

The following table provides information about contract cost assets and contract revenue liabilities from contracts with customers:


		June 30, 2023		December 31, 2022
(unaudited, in thousands)	Classification in the Consolidated Balance Sheets
Current contract cost assets	Prepaid expenses and other current assets	$	7,141	$	7,324
Current contract revenue liabilities	Other current liabilities		35,506		35,085

Significant changes in contract cost assets and contract revenue liabilities during the six months ended June 30, 2023 are as follows:


	Contract Cost Assets			Contract Revenues
(unaudited, in thousands)
Balance as of December 31, 2022	$	7,324		$	35,085
Increase due to contractual changes		9,412			64,458
Decrease due to recognition of revenue		(9,595	)		(64,037	)
Balance as of June 30, 2023 (1)	$	7,141		$	35,506

(1)

We expect to recognize contract revenues of approximately $35.5 million during the remaining six months of 2023 related to unsatisfied performance obligations existing as of June 30, 2023, which includes $26.1 million related to customer prefunding of reimbursables.

We have elected to utilize an optional exemption that permits us to exclude disclosure of the estimated ~~fair values~~transaction price related to the variable portion of unsatisfied performance obligations at the end of the reporting period, as our transaction price is based on a single performance obligation consisting of a series of distinct hourly increments, the variability of which will be resolved at the time the future services are rendered.

4. Leases

We have operating leases expiring at various dates, principally for office space, onshore storage yards and certain operating equipment. Additionally, we sublease certain office space to third parties. We determine if an arrangement is a lease at inception. Operating leases with an initial term greater than 12 months are included in “Operating lease ROU assets”, “Other current liabilities”, and “Other long-term liabilities” on our Consolidated Balance Sheets. Operating lease ROU assets ~~acquired~~ and operating lease liabilities ~~assumed.~~

(in thousands)

Total cash consideration
$
13,000

Purchase price allocation:

Drilling contract value

12,640

Rig equipment to be sold (net of disposal costs)

2,050

Drillpipe assets

700

Severance liabilities assumed

(480
)

Net assets acquired

14,910

Bargain purchase gain
$
1,910

~~Under accounting guidance, a bargain purchase gain results from an acquisition if~~are recognized based on the ~~fair~~present value of the ~~purchase consideration paid~~future lease payments over the lease term at commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in ~~connection with such acquisition is less than~~determining the ~~net fair~~present value of future payments. The operating lease ROU asset also includes any lease payments made prior to or at the ~~assets acquired~~commencement date and ~~liabilities assumed.~~is reduced by lease incentives received and initial direct costs incurred. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Lease expense is recognized on a straight-line basis over the lease term. We ~~recorded a bargain purchase gain~~have lease agreements with lease and non-lease components, which are generally not accounted for separately. Certain of ~~approximately $1.9 million related to the acquisition~~our leases include provisions for variable payments. These variable payments are not included in the ~~nine months ending September 30, 2017. We believe that we were able to negotiate a bargain purchase price as a result~~calculation of ~~our operational presence in West Africa~~lease liability and ~~the seller’s liquidation.~~ ROU assets.

~~Pro forma results~~The components of ~~operations related to the acquisition have not been presented because they are not material to our consolidated statement of operations.~~

~~4. Reorganization Items~~

~~Reorganization items represent amounts incurred subsequent to the Petition Date as a direct result of the filing of the Reorganization Plan and are comprised of the following:~~

Successor

Predecessor

Three Months Ended September 30,

Nine Months Ended September 30, 2017

Period from February 10, 2016 to September 30, 2016

Period from January 1, 2016 to February 10, 2016

2017

2016

(unaudited, in thousands)

Professional fees

$
—

$
(35
)

$
—

$
606

$
22,712

Net gain on settlement of LSTC

—

—

—

—

(1,630,025
)
Fresh-start adjustments

—

—

—

—

2,060,232

$
—

$
(35
)

$
—

$
606

$
452,919

~~For the nine months ended September 30, 2017, and~~lease expense for the periods ~~from February 10, 2016 to September 30, 2016 and from January 1, 2016 to February 10, 2016, cash payments for reorganization items totaled $208,000, $15.9~~indicated were as follows:


		Three Months Ended June 30,						Six Months Ended June 30,
(unaudited, in thousands)	Classification in the Consolidated Statement of Operations	2023			2022			2023			2022
Operating lease cost(1)	Operating costs	$	197		$	313		$	414		$	568
Operating lease cost(1)	General and administrative		284			193			568			477
Sublease income	General and administrative		(208	)		(224	)		(423	)		(407	)
Total operating lease cost		$	273		$	282		$	559		$	638

(1) Short-term lease costs were approximately $9.6 million and ~~$7.3~~$19.3 million during each of the three and six months ended June 30, 2023, respectively, which includes bareboat charter expense for a third party owned rig operated by the Company. For the three and six months ended June 30, 2022, short-term lease costs were approximately $0.2 million and $0.3 million, respectively. Operating cash flows used for operating leases approximates lease expense.


(unaudited, in thousands)	Classification in the Consolidated Balance Sheets	June 30, 2023		December 31, 2022
Assets:
Operating lease assets	Operating lease ROU assets	$	812	$	1,648
Total leased assets		$	812	$	1,648
Liabilities:
Current operating	Other current liabilities	$	679	$	1,520
Noncurrent operating	Other long-term liabilities		164		222
Total lease liabilities		$	843	$	1,742

As of June 30, 2023, maturities of lease liabilities were as follows:


(unaudited, in thousands)	Operating Leases
Remaining six months of 2023	$	637
2024		139
2025		104
Total future lease payments	$	880
Less imputed interest		(37	)
Present value of lease obligations	$	843

The weighted average discount rate was 9.25% as of each of June 30, 2023 and December 31, 2022. The weighted average remaining lease term for operating leases was 0.99 years and 1.19 years as of June 30, 2023 and December 31, 2022, respectively.

5. Debt

Our debt was composed of the ~~following:~~

September 30, 2017

December 31, 2016

(unaudited, in thousands)

2016 Term Loan Facility

$
140,497

$
141,570

10% Second Lien Notes, net of financing costs of $1,522 and $1,873

74,604

74,252

Convertible Notes, net of discount of $67,042 and $103,695

693,413

652,980

908,514

868,802

Less current maturities of long-term debt

4,430

1,430

Long-term debt, net

$
904,084

$
867,372

~~Second Amended and Restated Credit Agreement.~~ The Company entered into the 2016 Term Loan Facility providing for (i) a $32.0 million revolving letter of credit facility to replace the Company’s existing $32.0 million revolving letter of credit commitment under its pre-petition credit facility and (ii) $143.0 million of term loans into which the claimsfollowing as of the ~~lenders under~~dates indicated:


	June 30, 2023		December 31, 2022
(unaudited, in thousands)
9.25% First Lien Notes, net of financing costs of $0 and $773, respectively	$	—	$	179,227
9.50% First Lien Notes, net of financing costs of $11,080 and $0, respectively		188,920		—
		188,920		179,227
Less current maturities of long-term debt		—		—
Long-term debt, net	$	188,920	$	179,227

9.25% First Lien Notes. On November 30, 2018, the Company’s pre-petition credit facility were converted. The lenders under the Company’s pre-petition credit facility also received $7.0 million of cash under the Reorganization Plan. The obligations under the 2016 Term Loan Facility are guaranteed by substantially all of the Company’s subsidiaries, subject to limited exceptions, and secured on a first priority basis by substantially all of the Company’s and the guarantors’ assets, including ship mortgages on all vessels, assignments of related earnings and insurance and pledges of the capital stock of all guarantors, in each case, subject to certain exceptions. We haveCompany issued ~~$19.3~~$350.0 million in ~~letters of credit as of September 30, 2017.~~

~~The maturity date of the term loans and commitments established under the 2016 Term Loan Facility is December 31, 2019. Interest is payable on the unpaid~~aggregate principal amount of each term loan under the 2016 Term Loan Facility at LIBOR plus 6.5%, with a LIBOR floor of 0.5%. The term loans are currently bearing interest at 7.7%. The 2016 Term Loan Facility has quarterly scheduled debt maturities of $357,500 which commenced in March 2016.

~~Fees are payable on the outstanding face amount of letters of credit at a rate per annum equal to 5.5% pursuant to the terms of the 2016 Term Loan Facility.~~

The 2016 Term Loan Facility includes customary representations and warranties, mandatory prepayments, affirmative and negative covenants and events of default, including covenants that, among other things, restrict the granting of liens, the incurrence of indebtedness, the making of investments and capital expenditures, the sale or other conveyance of assets, including vessels, transactions with affiliates, prepayments of certain debt and the operation of vessels. The 2016 Term Loan Facility also requires that the Company maintain $75.0 million of available cash (defined to include unrestricted cash and cash equivalents plus undrawn commitments).

~~10% Senior Secured Second~~9.25% First Lien ~~Notes.~~ ~~The Company engaged~~Notes in a rights offering for $75.0 million of new 10% Second Lien Notes for certain holders of its secured debt claims. In connection with this rights offering, certain creditors entered into a “backstop” agreement to purchase 10% Second Lien Notes if the offer was not fully subscribed.private placement. The premium paid to such creditors under the backstop agreement was approximately $2.2 million, which was paid $1.1 million in cash and $1.1 million in additional 10% Second Lien Notes, resulting in a total issued amount of $76.1 million of 10% Second Lien Notes, and in net cash proceeds of approximately $73.9 million after deducting the cash portion of the backstop premium.

~~The 10% Second~~9.25% First Lien Notes were issued at par and are fully ~~and unconditionally~~ guaranteed ~~(except for customary release provisions),~~ on a senior secured basis by the Company’s direct and indirect subsidiaries, and were secured by a first priority lien on substantially all of the ~~subsidiaries~~assets of the ~~Company.~~Company and its subsidiaries, in each case subject to certain exceptions. The ~~10% Second~~9.25% First Lien Notes were subject to first payment priority in favor of holders of up to $50.0 million of future super-priority debt and were subject to both mandatory and optional redemption provisions.

The 9.25% First Lien Notes were scheduled to mature on ~~December 31, 2020,~~November 15, 2023 and ~~bear~~bore interest from the date of their issuance at the rate of ~~10%~~9.25% per year. Interest on outstanding 10% Second Lien Notes is payable semi-annually in arrears, which commenced on June 30, 2016. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months. The 10% Second Lien Notes rank behind the 2016 Term Loan Facility as to collateral.

The Indenture for the 10% Second Lien Notes includes customary covenants and events of default, including covenants that, among other things, restrict the granting of liens, restrict the making of investments, restrict the incurrence of indebtedness and the conveyance of vessels, limit transactions with affiliates, and require that the Company provide periodic financial reports.

~~1%/12% Step-Up Senior Secured Third Lien Convertible Notes.~~ The Company issued 4,344,959 New Shares and $750.0 million of the Convertible Notes to certain creditors holding approximately $2.5 billion of pre-petition secured debt claims. The New Shares issued to the creditors and the Convertible Notes may only be traded together and not separately. The Convertible Notes mature on December 31, 2030 and are convertible into New Shares, in certain circumstances, at a conversion price (subject to adjustment in accordance with the terms of the Indenture for the Convertible Notes) which was $95.60 as of the issue date. The Indenture for the Convertible Notes includes customary covenants that restrict, among other things, the granting of liens and customary events of default, including among other things, failure to issue securities upon conversion of the Convertible Notes. As of September 30, 2017, taking into account the payment of PIK interest on the Convertible Notes to such date, each such unit of securities was comprised of one New Share and $175.02 of principal of Convertible Notes. As of September 30, 2017, we would be required to issue approximately 8.0 million New Shares if the Convertible Notes were converted.

In connection with the adoption of fresh-start accounting, the Convertible Notes were recorded at an estimated fair value of approximately $603.1 million. The difference between face value and the fair value at date of issuance of the Convertible Notes was recorded as a debt discount and is being amortized to interest expense over the expected life of the Convertible Notes using the effective interest rate method.

Interest on the Convertible Notes is payable semi-annually in arrears commencing June 30, 2016 as a payment in kind, either through an increase in the outstanding principal amount of the Convertible Notes or, if the Company is unable to increase such principal amount, by the issuance of additional Convertible Notes. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months and was payable semi-annually in arrears, commencing on May 15, 2019.

On November 22, 2022, the Company issued a notice of partial redemption (the “Notice of Partial Redemption”) of the 9.25% First Lien Notes. Pursuant to the Notice of Partial Redemption, the Company gave the existing recordholders of the 9.25% First Lien Notes notice that it intended to redeem $170.0 million of the outstanding 9.25% First Lien Notes on December 22, 2022 (the “Redemption Date”), at a redemption price equal to 100.0% of the aggregate principal amount of the 9.25% First Lien Notes to be redeemed, plus accrued and unpaid interest and Additional Amounts (as defined in the 9.25% First Lien Indenture), if any, but not including, the date fixed for the redemption of the 9.25% First Lien Notes. On the Redemption Date, the Company made a payment of approximately $171.6 million, an amount which included principal and interest.

On February 3, 2023, the Company issued a notice of full conditional redemption (the “Notice of Full Conditional Redemption”) pursuant to the 9.25% First Lien Indenture. Pursuant to the Notice of Full Conditional Redemption, the Company gave existing recordholders of the 9.25% First Lien Notes notice that, upon the satisfaction of the Condition Precedent (as defined below), it intended to redeem all $180.0 million of its outstanding 9.25% First Lien Notes at a redemption price equal to 100.0% of the aggregate principal amount of the 9.25% First Lien Notes to be redeemed, plus accrued and unpaid interest and Additional Amounts (as defined in the 9.25% First Lien Indenture), if any, to, but not including, the date of redemption. The redemption of the 9.25% First Lien Notes was conditioned upon the receipt by the Company of proceeds from a completed debt financing in an amount sufficient, in the Company’s opinion, to fund the Redemption Price on the date of redemption pursuant to the terms of the Indenture (the “Condition Precedent”). The 9.25% First Lien Notes were redeemed in full on March 6, 2023 for approximately $185.1 million including principal and interest, using proceeds derived from the issuance of the 9.50% First Lien Notes (as discussed immediately below). Due to the Company’s intention and ability to replace the 9.25% First Lien Notes with the 9.50% First Lien Notes, which mature in February 2028, the 9.25% First Lien Notes have been presented as long-term liabilities on our Consolidated Balance Sheets as of December 31, 2022.

9.50% First Lien Notes. On February 14, 2023, the Company priced an offering of $200.0 million in aggregate principal amount of 9.50% First Lien Notes at an issue price of 97% and entered into a purchase agreement with several investors pursuant to which the Company agreed to sell the 9.50% First Lien Notes (the “9.50% First Lien Notes Offering”) to the purchasers in reliance on an exemption from registration provided by Section 4(a)(2), Rule 144A and/or Regulation S of the Securities Act. On March 1, 2023, the Company closed the sale of the 9.50% First Lien Notes. The proceeds derived from the 9.50% First Lien Notes Offering were used (i) to redeem all outstanding 9.25% First Lien Notes for approximately $185.1 million, including principal and interest (as discussed immediately above), (ii) to pay fees and expenses related to the 9.50% First Lien Notes Offering and (iii) for general corporate purposes.

The 9.50% First Lien Notes will mature on February 15, 2028. The Company will pay interest on the 9.50% First Lien Notes on February 15 and August 15 of each year, commencing on August 15, 2023. Interest on the 9.50% First Lien Notes will accrue from March 1, 2023, at a rate of 1%9.50% per annum, ~~for the first four years~~ and ~~then increasing to 12% per annum until maturity.~~

be payable in cash. The ~~Company’s obligations under the Convertible~~9.50% First Lien Notes ~~are fully and unconditionally~~will be guaranteed ~~(except for customary release provisions),~~ on a ~~senior~~joint and several basis by the Company’s current and future direct and indirect subsidiaries, subject to certain exceptions (including Vantage Financial Management Co.) and will be secured ~~basis,~~ by a first priority lien on substantially all of the ~~subsidiaries~~assets of the Company and such subsidiaries, in each case subject to certain exceptions. In connection with the ~~obligations~~issuance of the 9.50% First Lien Notes, we are permitted to maintain up to $25.0 million in letters of credit outstanding to support our operations.

The 9.50% First Lien Notes are subject to mandatory redemptions upon the occurrence of certain events, including (i) an annual excess cash flow sweep of 50% of excess cash flow and (ii) upon the receipt of net proceeds from specified asset sales, in each case as further described in the 9.50% First Lien Indenture.

The 9.50% First Lien Notes are subject to redemption at the option of the Company, including upon certain change of control events occurring on or after February 15, 2025, and ~~guarantors are secured by liens on substantially all~~in certain cases upon the occurrence of ~~their respective assets.~~certain events, as further described in the 9.50% First Lien Indenture. The ~~guarantees by~~9.50% First Lien Indenture contains customary covenants that will limit the Company’s ability and, in certain instances, the ability of the Company’s subsidiaries, to borrow money, create liens on assets, make distributions and pay dividends on or redeem or repurchase stock, make certain types of investments, enter into agreements that restrict dividends or other payments from subsidiaries, enter into transactions with affiliates, issue guarantees of debt, and sell assets or merge with other companies. These limitations are subject to a number of important exceptions and qualifications which are described in greater detail in the 9.50% First Lien Indenture.

Events of default under the 9.50% First Lien Indenture include, among other events, the following with respect to the 9.50% First Lien Notes: default for 30 days in the payment when due of interest on the 9.50% First Lien Notes; default in payment when due of the ~~Convertible Notes are joint and several. The Company has no independent assets~~principal of, or ~~operations apart~~premium, if any, on the 9.50% First Lien Notes; failure to comply with certain covenants in the 9.50% First Lien Indenture for 30 days (or 60 days in respect of the reporting covenant contained therein) after the receipt of notice from the ~~assets and operations of its wholly-owned subsidiaries. In addition, there are no significant restrictions on the Company’s~~trustee or any subsidiary guarantor’s ability to obtain funds from its subsidiaries by dividend or loan. The Indenture for the Convertible Notes includes customary covenants that restrict the granting of liens and customary events of default, including, among other things, failure to issue securities upon conversion of the Convertible Notes. In addition, the Indenture, and the applicable Collateral Agreements, provide that any capital stock and other securities of any of the guarantors will be excluded from the collateral to the extent the pledge of such capital stock or other securities to secure the Convertible Notes would cause such guarantor to be required to file separate financial statements with the SEC pursuant to Rule 3-16 of Regulation S-X (as in effect from time to time).

~~The Convertible Notes will convert only (a) prior to the third anniversary of the issue date (February 10, 2016), (i) upon the instruction of~~ holders of ~~a majority~~25.0% in aggregate principal amount of the ~~Convertible Notes~~9.50% First Lien Notes; acceleration or ~~(ii) upon the full and final resolution~~payment default of ~~all potential Investigation Claims (as defined below), as determined in good faith by the board of directors~~debt of the Company ~~(the “Board”) (which determination shall require the affirmative vote~~or a restricted subsidiary in excess of $30.0 million (subject to a ~~supermajority~~cure right within 60 days); certain judgments in excess of ~~the non-management directors),~~$50.0 million subject to certain exceptions; and ~~(b) from and after February 10, 2019 through their maturity date~~certain events of December 31, 2030, upon the approval of the Board (which approval shall require the affirmative vote of a supermajority of the non-management directors). For these purposes, (i) “supermajority of the non-management directors” means five affirmative votes of non-management directors assuming six non-management directors eligible to vote and, in all other circumstances, the affirmative vote of at least 75% of the non-management directors eligible to vote and (ii) “Investigation Claim” means any claim held by a United Statesbankruptcy or Brazilian governmental unit and arising from or related to the procurement of that certain Agreement for the Provision of Drilling Services, dated as of February 4, 2009, by and between Petrobras Venezuela Investments & Services B.V. and Vantage Deepwater Company, as amended, modified, supplemented, or novated from time to time.

insolvency. In the event of a change in control, the holders of our Convertible Notes have the right to require us to repurchase all or any part of the Convertible Notes at a price equal to 101% of their principal amount. We assessed the prepayment requirements and concluded that this feature met the criteria to be considered an embedded derivative and must be bifurcated and separately valued at fair value due to the discount on the Convertible Notes at issuance. We considered the probabilities of a change of control occurring and determined that the derivative had a de minimis value at February 10, 2016 and December 31, 2016, respectively.

Upon the occurrence of specified change of control events or certain losses of our vessels in the agreements governing our 10% Second Lien Notes, Convertible Notes or 2016 Term Loan Facility, we will be required to offer to repurchase or repay all (or in the case of events of losses of vessels, an amount up to the amount of proceeds received from such event of loss) of such outstanding debt under such debt agreements at the prices and upon the terms set forth in the applicable agreements. In addition, in connection with certain asset sales, we will be required to offer to repurchase or repay such outstanding debt as set forth in the applicable debt agreements. In addition, in connection with their investigation, if the SEC determines that violations of the FCPA have occurred, the Company could be subject to civil and criminal sanctions, including monetary penalties, and if we become subject to any judgment, decree, order, governmental penalty or fine, this may constitute an event of default ~~under the terms~~arising from certain events of ~~our secured debt agreements and, following notice from the requisite lenders and/~~bankruptcy or ~~noteholders, as applicable, result in our outstanding debt under the 2016 Term Loan Facility and 10% Second~~insolvency, all 9.50% First Lien Notes ~~becoming immediately~~then outstanding will become due and payable ~~at par, and our outstanding debt under Convertible~~immediately without further action or notice. If any other event of default occurs with respect to the 9.50% First Lien Notes, ~~becoming immediately~~the trustee or holders of 25.0% in aggregate principal amount of the 9.50% First Lien Notes may declare all the 9.50% First Lien Notes to be due and payable ~~at the make-whole amount specified~~immediately.

Letters of credit to support our bank guarantee and similar needs are provided to us on demand by JPMorgan Chase Bank N.A. As of June 30, 2023, we maintained letters of credit outstanding in the ~~indenture governing the Convertible Notes.~~ aggregate amount of $7.4 million.

6. Shareholders’ Equity

~~We have~~ Stock Issuance

VDI has 50,000,000 authorized ~~ordinary shares, par value $0.001 per share. Upon emergence from bankruptcy, we issued 5,000,053 ordinary shares in connection with the settlement of LSTC and the VDC Note.~~Ordinary Shares. As of ~~September~~June 30, ~~2017, 5,000,053 ordinary shares~~2023, 13,229,280 Ordinary Shares were issued and outstanding.

Share-based Compensation

On August 9, 2016, the Company adopted the 2016 Amended ~~and Restated 2016 Management Incentive Plan (the “2016 Amended MIP”)~~MIP to align the interests of participants with those of the Company’s shareholders by providing incentive compensation opportunities tied to the performance of the Company’s equity securities. Pursuant to the 2016 Amended MIP, the Compensation Committee may grant to employees, directors and consultants stock options, restricted stock, restricted stock units or other awards.

During the ~~nine~~six months ended ~~September~~June 30, ~~2017, we~~2023, 14,286 TBGs were granted to certain directors of the Company. No awards were granted to employees ~~29,008 time-based restricted stock units (“TBGs”)~~or directors during the six months ended June 30, 2022. During the six months ended June 30, 2023, 919 of previously granted TBGs vested and 67,685 performance-based restricted stock units (“PBGs”) under our 2016 Amended MIP. In March 2017, four directors were granted 415 TBGs each, or a total of 1,660 TBGs. The TBGs vest annually, ratably over four years; however, accelerated vesting is provided for in the event of a qualified liquidity event as defined in the 2016 Amended MIP (a “QLE”). Otherwise, the settlement of any131,844 previously vested TBGs ~~occurs upon the seventh anniversary~~were issued to current or former employees or directors of the ~~Effective Date. The PBGs contain vesting eligibility provisions tied~~Company, of which 17,590 Ordinary Shares were repurchased to settle withholding taxes. During the earlier of a QLE or seven years from the Effective Date. Upon the occurrence of a vesting eligibility event, the number of PBGs that actually vest will be dependent on the achievement of pre-determined Total Enterprise Value (“TEV”) targets specified in the grants. six months ended June 30, 2022, 1,564 previously-granted TBGs vested and none were issued.

Both the TBGs and PBGs are classified as ~~liabilities consistent with~~equity awards. For the ~~classification of the underlying securities and under the provisions of ASC 718~~ ~~Compensation – Stock Compensation~~ are remeasured at each reporting period until settled. Share based compensation expense is recognized over the requisite service period until settled. We recognized approximately $1.2 million and $76,000 ofsix months ended June 30, 2023, share-based compensation expense ~~for~~related to the ~~three months ended September~~TBGs was immaterial. As of June 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017 and for the period from February 10, 2016 to September 30, 2016, we recognized $2.9 million and $76,000, respectively of share-based compensation expense. In the nine months ended September 30, 2017, 11,237 of previously granted TBGs vested.

Share based compensation expense for PBGs will be recognized when it is probable that the TEV targets will be met. Once it is probable the performance condition will be met, compensation expense based on the fair value of the PBGs at the balance sheet date will be recognized for the service period completed. For the quarter ended September 30, 2017,2023, we concluded that it was not probable that the TEV performance condition would be met and therefore, no ~~share based~~share-based compensation expense was recognized for PBGs. Pursuant to the terms of the award agreements, all the PBGs granted were forfeited and cancelled for no consideration as they had not met the TEV performance condition as of the seventh anniversary of the Effective Date.

Pursuant to the 2016 Amended MIP and the terms of the applicable unit awards, participants holding restricted stock units are contractually entitled to receive all dividends or other distributions that are paid to VDI’s stockholders, provided that any such dividends will be subject to the same vesting requirements of the underlying units. Dividend payments accrue to outstanding awards (both vested and unvested) in the form of “Dividend Equivalents” equal to the dividend per share underlying the applicable award under the 2016

Amended MIP. As a result of a special cash distribution paid to shareholders of record on December 17, 2019, $3.3 million has been recorded in “Other current liabilities” and $0.3 million has been recorded in “Other long-term liabilities” in our Consolidated Balance Sheets at June 30, 2023 to be paid upon settlement of the TBGs. During the six months ended June 30, 2023, $5.3 million was paid to current or former employees or directors as a result of the settlement of the TBGs (as discussed immediately above).

7. Income Taxes

~~We are~~VDI is a Cayman Islands ~~entity.~~company operating in multiple countries through its subsidiaries. The Cayman Islands ~~does~~do not impose corporate income taxes. Consequently, we have calculated income taxes based on the laws and tax rates in effect in the countries in which operations are conducted, or in which we and our subsidiaries are considered resident for income tax purposes. We operate in multiple countries under different legal forms. As a result, we are subject to the jurisdiction of numerous domestic and foreign tax authorities, as well as to tax agreements and treaties among these governments. Tax rates vary between jurisdictions, as does the tax base to which the rates are applied. Taxes may be levied based on net profit before taxes or gross revenues. Determination of taxable income in any jurisdiction requires the interpretation of the related tax laws and regulations and the use of estimates and assumptions regarding significant future events, such as the amount, timing and character of deductions, permissible revenue recognition methods under the tax law and the sources and character of income and tax credits. Our income tax expense may vary substantially from one period to another as a result of changes in tax laws, regulations, agreements and treaties, foreign currency exchange restrictions, rig movements or our level of operations or profitability in each tax jurisdiction. Furthermore, our income taxes are generally dependent upon the results of our operations and when we generate significant revenues in jurisdictions where the income tax liability is based on gross revenues or asset values, there is no correlation ~~between our~~to the net operating results and the income tax expense. Furthermore, in some jurisdictions we do not pay taxes, pay taxes at lower rates or receive benefits for certain income and expense items, including interest expense, loss on extinguishment of debt, gains or losses on disposal or transfer of assets, reorganization expenses and write-off of development costs.

On January 22, 2020, VDI filed the Tax Election with the IRS to be treated as a partnership, rather than a corporation, for U.S. federal income tax purposes, with an effective date retroactive to December 9, 2019. As a result, U.S. Holders are required to take into account their allocable share of items of income, gain, loss deduction and credit of VDI for each taxable year of VDI ending with or within the U.S. Holder’s taxable year, regardless of whether any distribution has been or will be received from VDI. Each item generally will have the same character and source (either U.S. or foreign) as though the U.S. Holder had realized the item directly.

Deferred income tax assets and liabilities are recorded for the expected future tax consequences of events that have been recognized in our financial statements or tax returns. We provide for deferred taxes on temporary differences between the financial statements and tax bases of assets and liabilities using the enacted tax rates which are expected to apply to taxable income when the temporary differences are expected to reverse. Deferred tax assets are also provided for certain tax losses and tax credit carryforwards. A valuation allowance is established to reduce deferred tax assets when it is more likely than not that some portion or all of the deferred tax asset will not be realized. We do not establish deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely reinvest to finance foreign activities.

In certain jurisdictions we are taxed under preferential tax regimes, which may require our compliance with specified requirements to sustain the tax benefits. We believe we are in compliance with the specified requirements and will continue to make

all reasonable efforts to comply; however, our ability to meet the requirements of the preferential tax regimes may be affected by changes in laws or administrative practices, our business operations and other factors affecting ~~our company~~the Company and industry, many of which are beyond our control.

Our periodic tax returns are subject to examination by taxing authorities in the jurisdictions in which we operate in accordance with the normal statute of limitations in the applicable jurisdiction. These examinations may result in assessments of additional taxes that are resolved with the authorities or through the courts. Resolution of these matters involves uncertainties and there are no assurances as to the outcome. Our tax years ~~2010 and forward~~from 2013 onward remain open to examination in many of our jurisdictions and we are currently involved in several tax examinations in jurisdictions where we are operating or have previously operated. As information becomes available during the course of these examinations, we may increase or decrease our estimates of tax assessments and accruals.

8. Commitments and Contingencies

We are subject to litigation, claims and disputes in the ordinary course of business, some of which may not be covered by insurance. There is an inherent risk in any litigation or dispute and no assurance can be given as to the outcome of any claims.

~~In July 2015, we became aware~~Brazil Improbity Action

On April 27, 2018, the Company was added as an additional defendant in a legal proceeding (the “Improbity Action”), initiated by the Brazilian Federal Prosecutor against certain individuals, including an executive of ~~media reports that~~Petrobras and two political lobbyists, in connection with the contracting of the Titanium Explorer drillship to Petrobras under the Government Agreement for the Provision of Drilling Services for the Titanium Explorer, dated February 4, 2009, by and between Petrobras Venezuela Investments & Services, BV and Vantage Deepwater Company (and subsequently novated to Petrobras America, Inc. and Vantage Deepwater Drilling, Inc.), with the Brazilian government and Petrobras as plaintiffs. Vantage is alleged to have been involved in and benefited from the purported bribery scheme at Petrobras through Hamylton Padilha, the Brazilian agent our former parent company, VDC, used in the contracting of the Titanium Explorer drillship to Petrobras, ~~had entered into~~and Mr. Hsin-Chi Su, a ~~plea arrangement with the Brazilian authorities in connection with his role in facilitating the payment of bribes to~~ former Petrobras executives. Among other things, Mr. Padilha provided information to the Brazilian authorities of an alleged bribery scheme between former Petrobras executives and Nobu Su, who was, at the time of the alleged bribery scheme, a member of ~~the Board~~VDC’s board of ~~Directors~~directors and a significant shareholder of VDC. We first became aware of the legal proceeding on July 19, 2018 as it was previously under seal. On March 22, 2019, we were formally served in the United States and on April 12, 2019, we subsequently filed our ~~former parent company, VDC. When~~preliminary statement of defense with the 11th Federal court of the Judicial Branch of Curitiba, State of Parana, Brazil (the “Brazilian Federal Court”). On August 20, 2020, the Brazilian Federal Court dismissed our preliminary statement of defense. On October 5, 2020, we subsequently filed a motion to clarify with the Brazilian Federal Court requesting the reconsideration of certain aspects of the decision dismissing our preliminary statement of defense. Our motion to clarify was denied on December 14, 2020, and on February 10, 2021 we filed an interlocutory

appeal with the 4th Circuit of the Federal Court of Appeals in Porto Alegre, State of Rio Grande do Sul, Brazil (the “Brazilian Appellate Court”), the appellate court hearing appeals in the “Car Wash” cases, seeking to reverse the Brazilian Federal Court’s denial of our preliminary defense. On April 15, 2021, the Brazilian authorities served us indirectly through the U.S. Department of Justice agreeing to formally send us documents related to the Improbity Action. On May 13, 2021, the Brazilian Appellate Court’s reporting judge for our matter granted our request for preliminary relief and ordered an immediate stay of the Improbity Action (as it applies to the Company). A proceeding with regard to the interlocutory appeal commenced on August 30, 2022 (the “August 2022 Proceeding”) and on December 6, 2022, the Brazilian Appellate Court ruled in our favor, revoking the asset freeze order, which had already been stayed pending a decision from the court, and immediately dismissed the Improbity Action as to the Company (the “Improbity Decision”). The Improbity Decision is still subject to clarification and appeal by the Brazilian government and Petrobras, and on January 30, 2023 and February 1, 2023, Petrobras and the Brazilian federal government filed respective motions to clarify the Improbity Decision. On March 31, 2023, the Company filed its response to the motions to clarify the Improbity Decision. The Company will be notified as to the timing of the hearing of the motions to clarify the Improbity Decision.

The Company understands that the Improbity Action is a civil action and is part of the Brazilian Federal Prosecutor’s larger “Car Wash” investigation into money laundering and corruption allegations in Brazil. Separately, Federal Law no. 14,230/2021 (the “New Administrative Improbity Law”) was enacted on October 26, 2021, which substantially amended the existing Brazilian improbity legal framework. While the Company believes that the developments arising from the enactment of the New Administrative Improbity Law render the case against it moot, the Company cannot predict the ultimate outcome of the August 2022 Proceeding and the Company will be obligated to file a statement of defense in the matter if the Improbity Decision is later reversed.

The damages claimed in the proceeding are in the amount of BRL 102.8 million (approximately $21.8 million, changes in the USD amounts result from foreign exchange rate fluctuations), together with a civil fine equal to three times that amount. The Company understands that the Brazilian Federal Court previously issued an order authorizing the seizure and freezing of the assets of the Company and the other three defendants in the legal proceeding, as a precautionary measure, in the amount of approximately $87.3 million. The Company and the other three defendants are jointly and severally liable for this amount. The seizure order has not had an effect on the Company’s assets or operations, as the Company does not own any assets in Brazil and does not currently intend to relocate any assets to Brazil. On February 13, 2019, we learned that the Brazilian Federal Prosecutor had previously requested mutual legal assistance from the DOJ pursuant to the United Nations Convention against Corruption of ~~Mr. Padilha’s plea agreement~~2003 to obtain a freezing order against the Company’s U.S. assets in the amount of approximately $87.3 million.

On April 12, 2019, the Company filed an interlocutory appeal with the Brazilian Appellate Court to stay the seizure and freezing order of the Brazilian Federal Court.

On May 20, 2019, the Company announced that the Brazilian Appellate Court's reporting judge ruled in favor of the Company’s appeal to stay the seizure and freezing order of the Brazilian Federal Court. As noted above, the Brazilian Appellate Court ruled in favor of the Company in the Improbity Decision, which, among other things, revoked the asset freeze order. The Improbity Decision is still subject to clarification and appeal by the Brazilian government and Petrobras, and on January 30, 2023 and February 1, 2023, Petrobras and the ~~allegations, we voluntarily contacted~~Brazilian federal government filed respective motions to clarify the ~~DOJ and~~Improbity Decision. On March 31, 2023, the ~~SEC~~Company filed its responses to ~~advise them of these developments,~~the motions to clarify the Improbity Decision. The Company will be notified by the Brazilian Appellate Court as ~~well as~~to the ~~fact that we had engaged outside counsel to conduct an internal investigation~~timing of the ~~allegations. Since disclosing this matter~~hearing of the Brazilian Appellate Court to adjudicate the motions to clarify the Improbity Decision.

The Company previously communicated the Brazilian Appellate Court’s ruling to the DOJ and ~~SEC, we have cooperated fully in their investigation of these allegations. In connection with such cooperation, we advised both agencies that in early 2010, we engaged outside counsel~~has asked the Brazilian Federal Court to investigate a report of alleged improper payments to customs and immigration officials in Asia. That investigation was concluded in 2011, and we determined at that time that no disclosure was warranted; however, in an abundance of caution, we provideddo the ~~results of this investigation to the DOJ and SEC in light of the allegations in the Petrobras matter.~~ ~~In August 2017, we received a letter from the DOJ acknowledging our full cooperation in the DOJ’s investigation into~~same. On July 18, 2019, the Company ~~concerning~~announced that the ~~possible violations of~~Brazilian Government made a filing with the ~~U.S. Foreign Corrupt Practices Act (“FCPA”) in the Petrobras matter and indicating~~Brazilian Federal Court reporting that the DOJ has ~~closed such investigation without any action. Although~~advised the Brazilian Ministry of Justice that it would not be possible for the DOJ to comply with the mutual assistance request in respect of the asset freeze order. The Company also announced that it learned from the Brazilian Ministry of Justice that the DOJ’s ~~investigation into this~~response to the request for mutual assistance stated that no legal grounds existed for implementing the requested asset freeze, and that the DOJ was returning the request without taking action and considers the matter concluded.

The Company has ~~closed, we cannot predict~~defended, and intends to continue to vigorously defend, against the ~~outcome of the SEC’s investigation, which remains open, and if the SEC determines that violations of the FCPA~~ have occurred, the Company could be subject to civil and criminal sanctions, including monetary penalties, as well as additional requirements or changes to our business practices and compliance programs, any or all of which could have a material adverse effect on our business and financial condition. Additionally, if we become subject to any judgment, decree, order, governmental penalty or fine, this may constitute an event of default under the terms of our secured debt agreements and, following notice from the requisite lenders and/or noteholders, as applicable, result in our outstanding debt under the 2016 Term Loan Facility and 10% Second Lien Notes becoming immediately due and payable at par, and our outstanding debt under Convertible Notes becoming immediately due and payable at the make-whole amount specifiedallegations made in the ~~indenture governing~~Improbity Action and oppose and defend against any attempts to reverse the ~~Convertible Notes.~~

~~In connection with our bankruptcy cases, two appeals were filed relating to~~Improbity Decision and/or seize the confirmation of the Reorganization Plan. Specifically, on January 29, 2016, Hsin Chi Su and F3 Capital filed two appeals before the United States District Court for the District of Delaware seeking a reversal of (i) the Court’s determination that Hsin Chi Su and F3 Capital did not have standing to appear and be heard in the bankruptcy cases, which was made on the record at a hearing held on January 14, 2016, and (ii) the Court’s Findings of Fact, Conclusions of Law, and Order (I) Approving the Debtors’ (A) Disclosure Statement Pursuant to Sections 1125 and 1126(b) of the Bankruptcy Code, (B) Solicitation of Votes and Voting Procedures, and (C) Forms of Ballots, and (II) Confirming the Amended Joint Prepackaged Chapter 11 Plan of Offshore Group Investment Limited and its Affiliated Debtors [Docket No. 188], which was entered on January 15, 2016. The appeals were consolidated on June 14, 2016. We cannot predict with certainty the ultimate outcome of any such appeals. An adverse outcome could negatively affect our business, results of operations and financial condition.

On August 31, 2015, VDC received notice from Petrobras America, Inc. (“PAI”) and Petrobras Venezuela Investments & Services B.V. (“PVIS”) stating that PAI and PVIS were terminating the Agreement for the Provision of Drilling Services dated February 4, 2009 (the “Drilling Contract”). The Drilling Contract was initially entered into between PVIS and Vantage Deepwater Company, one of our wholly-owned indirect subsidiaries, and was later novated by PVIS to PAI and by Vantage Deepwater Company to Vantage Deepwater Drilling, Inc., another of our wholly-owned indirect subsidiaries. The notice stated that PAI and PVIS were terminating the Drilling Contract because Vantage had allegedly breached its obligations under the agreement. Under the terms of the Drilling ContractCompany's assets. However, we initiated arbitration proceedings before the American Arbitration Association on August 31, 2015, challenging PVIS and PAI’s wrongful attempt to terminate the Drilling Contract. Vantage has maintained that it complied with all of its obligations under the Drilling Contract and that PVIS and PAI’s attempt to terminate the agreement is both improper and a breach of the Drilling Contract.

In the ongoing arbitration proceeding, the hearing on the merits has concluded and the parties have exchanged post-hearing briefs. Vantage has asserted claims against PAI and PVIS for declaratory relief and monetary damages based on breach of contract. Vantage has also asserted a claim against Petroleo Brasileiro S.A. (“PBP”) to enforce a guaranty provided by PBP. The Petrobras entities (PVIS, PAI and PBP) have asserted that the Drilling Contract is void as illegally procured, that PVIS and PBP are not proper parties to the arbitration, and that PAI and PVIS properly terminated the contract. PAI has further counterclaimed for attorneys’ fees and costs alleging that Vantage failed to negotiate in good faith before commencing arbitration proceedings and is seeking disgorgement damages of approximately $102 million. We are vigorously pursuing our claims in the arbitration and deny that any of the claims or defenses asserted by the Petrobras entities have merit.

Pursuant to the terms of the Restructuring Agreement, the Company agreed to the Reorganization Plan and VDC agreed to commence official liquidation proceedings under the laws of the Cayman Islands. On December 2, 2015, pursuant to the Restructuring Agreement, the Company acquired two subsidiaries responsible for the management of the Company from VDC in exchange for the VDC Note. In connection with our separation from our former parent company, we and the Joint Official Liquidators, appointed to oversee the liquidation of VDC, are in discussions regarding the settlement of certain intercompany receivables and payables as between the Company and its subsidiaries, on the one hand, and VDC and its subsidiaries on the other. While we continue to believe that our position regarding the settlement of such amounts is correct, we cannotcan neither predict the ultimate outcome of this matter ~~should legal proceedings between~~nor that there will not be further developments in the ~~parties transpire.~~“Car Wash” investigation or in any other ongoing investigation or related proceeding that could adversely affect us. We are not able to determine the likelihood of loss, if any, arising from this matter as of the date of this Quarterly Report.

Cyber Matters

In 2022, we experienced additional e-mail related cybersecurity intrusions (the “2022 Cyber Matters”). We became aware of the 2022 Cyber Matters in the fourth quarter of 2022 that resulted in (i) two unauthorized transfers of cash from a Company-controlled bank account to an outside bank account, (ii) one attempted transfer that was stopped and reversed by a financial institution and (iii) one attempted transfer that was stopped by the Company’s internal controls. We have since taken, and continue to take, measures designed to detect, remediate and prevent similar cybersecurity intrusions and threats from recurring. Because the 2022 Cyber Matters are still under investigation, we can neither predict the ultimate outcome of this matter nor whether there will be further developments in the 2022 Cyber Matters investigation that could adversely affect us. Our investigation to date has not revealed any information that suggests

the 2022 Cyber Matters will result in a material loss to the Company. However, we are not able to determine the likelihood of loss, if any, arising from the 2022 Cyber Matters as of the date of this Quarterly Report. Furthermore, we cannot provide assurance that we will not in the future experience any other actual or attempted breaches of our cybersecurity, or that our security efforts and remedial measures will prevent future security threats from materializing, if at all.

9. Supplemental Financial Information

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the ~~following:~~ following as of the dates indicated:


	September 30, 2017		December 31, 2016		June 30, 2023		December 31, 2022
(unaudited, in thousands)
Prepaid insurance	$	209	$	782
Sales tax receivable		7,269		7,129	$	7,096	$	5,407
Down payments to vendors						7,555		6,269
Prepaid fuel						2,216		3,200
Income tax receivable		1,267		1,025		10,186		1,373
Other receivables		135		74
Assets held for sale		2,050		—
Current deferred contract costs						7,141		7,324
Current deposits						3,548		139
Other		5,228		3,413		2,424		1,909
	$	16,158	$	12,423	$	40,166	$	25,621

Property and Equipment, ~~net~~Net

Property and equipment, net, consisted of the ~~following:~~ following as of the dates indicated:


	September 30, 2017			December 31, 2016			June 30, 2023			December 31, 2022
(unaudited, in thousands)
Drilling equipment	$	882,897		$	880,267		$	625,986		$	624,739
Assets under construction		1,487			2,138			4,829			4,075
Office and technology equipment		18,778			18,764			18,405			18,405
Leasehold improvements		1,165			1,072			690			690
		904,327			902,241			649,910			647,909
Accumulated depreciation		(123,215	)		(67,713	)		(330,911	)		(309,453	)
Property and equipment, net	$	781,112		$	834,528		$	318,999		$	338,456

Other Assets

Other assets consisted of the ~~following:~~ following as of the dates indicated:


	June 30, 2023		December 31, 2022
(unaudited, in thousands)
Noncurrent restricted cash	$	2,266	$	2,781
Deferred certification costs		3,259		3,308
Deferred income taxes		1,169		1,897
Noncurrent tax receivable		1,681		4,766
Other noncurrent assets		4,284		5,582
	$	12,659	$	18,334

Other Current Liabilities

September 30, 2017

December 31, 2016

(unaudited, in thousands)

Contract value, net

$
9,545

$
—

Performance bond collateral

—

3,197

Deferred certification costs

4,004

4,885

Deferred mobilization costs

2,387

4,194

Deferred income taxes

5,329

2,237

Deposits

1,119

1,181

$
22,384

$
15,694

~~Accrued Liabilities~~

~~Accrued~~Other current liabilities consisted of the ~~following:~~ following as of the dates indicated:


	June 30, 2023		December 31, 2022
(unaudited, in thousands)
Interest	$	6,332	$	2,126
Compensation		6,381		8,786
2016 MIP - Dividend equivalent (1)		3,272		5,278
Income taxes payable		6,630		2,662
Current deferred revenue		35,506		35,085
Current portion of operating lease liabilities		679		1,520
Current customer prefunding		6,285		10,049
Other		685		673
	$	65,770	$	66,179

(1) “Dividend equivalents” on vested TBGs are payable upon settlement of the applicable award.

Other Long-term Liabilities

September 30, 2017

December 31, 2016

(unaudited, in thousands)

Interest

$
3,925

$
104

Compensation

9,718

11,289

Income taxes payable

4,521

5,008

Other

1,909

2,047

$
20,073

$
18,448

Other Long-term liabilities consisted of the following as of the dates indicated:


	June 30, 2023		December 31, 2022
(unaudited, in thousands)
Deferred income taxes	$	734	$	730
2016 MIP - Dividend equivalent (1)		285		3,520
Noncurrent operating lease liabilities		164		222
Noncurrent customer prefunding		4,093		3,950
Indirect tax contingencies		4,323		4,339
Other non-current liabilities		79		120
	$	9,678	$	12,881

(1) “Dividend equivalents” on vested TBGs are payable upon settlement of the applicable award.

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets that sum to the total of the same amounts shown in the Consolidated Statement of Cash Flows as of the dates indicated:


	June 30, 2023		December 31, 2022
(unaudited, in thousands)
Cash and cash equivalents	$	79,650	$	74,026
Restricted cash		455		16,450
Restricted cash included within Other Assets		2,266		2,781
Total cash, cash equivalents and restricted cash shown in the Consolidated Statements of Cash Flows	$	82,371	$	93,257

Restricted cash represents cash held by banks as collateralizing letters of credit.

Other Transactions

ADES

In conjunction with ~~Former Parent~~the establishment of ADVantage, the Company entered into a series of agreements with ADES, including: (i) a Secondment Agreement; (ii) a Manpower Agreement; and (iii) a Supply Services Agreement. Pursuant to these agreements, the Company, largely through its seconded employees, has agreed to provide various services to ADES and ADES has agreed in turn to provide various services to ADVantage.

On December 6, 2021, we entered into the EDC Purchase Agreement to sell to ADES Arabia all of the issued and outstanding equity of EDC, which owns the Emerald Driller, Sapphire Driller and Aquamarine Driller. The ~~Company's~~transactions contemplated by the EDC Purchase Agreement closed on the EDC Closing Date. Simultaneously with the EDC Sale, certain subsidiaries of the Company and ADES entered into the EDC Support Services Agreements, pursuant to which a subsidiary of the Company agreed to provide, in exchange for customary fees and reimbursements, support services to EDC with respect to the Emerald Driller, Sapphire Driller and Aquamarine Driller for a three-year term. Fees earned as a result of these agreements are included in “Management fees” and

“Reimbursable and other” in our Consolidated Statement of Operations ~~included~~within the ~~following transactions with VDC for the periods indicated:~~

~~The following table summarizes the balances payable to VDC included~~Managed Services segment as reported in ~~the Company's Consolidated Balance Sheet as of the periods indicated:~~

September 30, 2017

December 31, 2016

(unaudited, in thousands)

Accounts payable to related parties, net

$
17,278

$
17,278

$
17,278

$
17,278

“Note 10. Business Segment and Significant Customer Information.”

~~We aggregate~~On September 22, 2022, three wholly owned subsidiaries of VHI entered into several related agreements with Advanced Energy Services, S.A.E., a subsidiary of ADES (“ADES SAE” and together with ADES Arabia, the “ADES Group”), including a: (i) secondment agreement; (ii) services agreement; and (iii) bareboat charter agreement, in each case to support a drilling campaign that will utilize the Topaz Driller jackup (collectively, the “ADES Ancillary Agreements”). These contracts generally provide for: (a) reimbursement of loaned employee personnel costs plus a service fee; (b) a fixed fee based on days the rig is drilling; (c) a variable fee based on a percentage of gross margin generated on a monthly basis; and (d) reimbursement for purchases of supplies, equipment and personnel services, and other services provided at the request of ADES SAE. Fees earned as a result of these agreements are included in “Reimbursable and other” in our ~~contract~~Consolidated Statement of Operations within the Drilling Services segment as reported in “Note 10. Business Segment and Significant Customer Information.”

For the three and six months ended June 30, 2023, we recognized revenue of $6.7 million and $12.3 million, respectively, from the ADES Group in connection with the ADES Ancillary Agreements.

The Company and ADES also entered into an agreement on December 6, 2021 (the “Collaboration Agreement”) to pursue a global strategic alliance in order to leverage both the EDC Support Services Agreements and ADVantage, the parties’ existing joint venture in Egypt. Pursuant to the Collaboration Agreement, the parties agreed to collaborate on exploring future commercial and operational opportunities.

Aquadrill Merger; Framework, Management and Marketing Agreements

VHI previously entered into the Framework, Management and Marketing Agreements, pursuant to which certain subsidiaries of VHI agreed to provide operating, management and marketing services to the Aquadrill Entities. Fees earned in connection with these agreements are included in “Management fees” and “Reimbursable and other” in our Consolidated Statement of Operations within the Managed Services segment as reported below in “Note 10. Business Segment and Significant Customer Information.” For the three and six months ended June 30, 2023, we recognized revenue of $21.8 million and $43.6 million, respectively, and, for the three and six months ended June 30, 2022, we recognized revenue of $22.2 million and $30.4 million, respectively.

On December 23, 2022, Seadrill Ltd. announced that it had agreed to consummate the Aquadrill Merger and on April 3, 2023, the Aquadrill Merger closed. On April 10, 2023, we received the Termination Notice from Aquadrill and, given that the Notice Termination Period has lapsed, we are therefore no longer (i) managing or marketing the Aquarius nor (ii) marketing the Capella and Polaris. However, as the management agreements are still in effect with respect to the Capella and Polaris, we continue to manage and operate those rigs for Seadrill Ltd. (and for the oil and gas clients under their respective drilling ~~operations into one reportable segment even though we provide contract drilling services~~contracts). See “Note 1. Organization and Recent Events” of these Notes to Unaudited Financial Statements for further information with ~~different types~~respect to the termination of ~~rigs, including jackup rigs~~the Aquarius Agreements and ~~drillships,~~ the Capella and ~~in different geographic regions.~~ Polaris Marketing Agreements.

10. Business Segment and Significant Customer Information

Our operations are dependent on the global oil and gas industry, and our rigs are relocated based on demand for our services and customer requirements. Our customers consist primarily of large international oil and gas companies, national or government-controlled oil and gas companies, and other international exploration and production companies.

~~Additionally,~~As the result of an increase in activity related to operating, management and marketing services for ~~drilling units~~rigs owned by ~~others,~~third parties, the Company has two reportable segments: (1) “Drilling Services,” which includes activities related to owned jackup rigs and drillships; and (2) “Managed Services,” which consists of activities related to rigs owned by third parties that we ~~provide construction supervision services while under construction and preservation management services when stacked. In September 2013, we signed an agreement to supervise and~~ manage or support. The chief operating decision maker evaluates the construction of two ultra-deepwater drillships for a third party. In January 2017, we signed an agreement to manage the preservation of two ultra-deepwater drillships for a third party. Our management business represented approximately 0.6%, 0.8%, 2.5%, 3.1% , 3.2%,performance of our ~~total revenue~~reportable segments using adjusted operating income (loss), which is a segment performance measure, because this financial measure reflects our ongoing profitability and performance. Adjusted operating income (loss) is defined as segment income (loss) from operations plus depreciation. General and administrative expenses, other (expense) income, and income taxes are not allocated to the operating segments for purposes of measuring segment income (loss) from operations and are included in “Unallocated” in the table below. There are no intersegment revenues. Our segment results for the ~~three and nine months ended September 30, 2017, for the three months ended September 30, 2016,~~periods indicated were as follows:


	Three Months Ended June 30, 2023
	Drilling Services		Managed Services		Unallocated			Consolidated
(unaudited, in thousands)
Revenue
Contract drilling services	$	46,378	$	21,295	$	—		$	67,673
Management fees		—		5,569		—			5,569
Reimbursables and other		7,834		26,764		—			34,598
Total revenue		54,212		53,628		—			107,840
Operating costs and expenses
Operating costs		33,163		41,220		—			74,383
General and administrative		—		—		5,161			5,161
Depreciation		10,601		—		444			11,045
Gain on EDC Sale		—		—		—			—
Total operating costs and expenses		43,764		41,220		5,605			90,589
(Loss) income from operations		10,448		12,408		(5,605	)		17,251
Other (expense) income
Interest income		—		—		141			141
Interest expense and financing charges		—		—		(5,346	)		(5,346	)
Other, net		—		—		(457	)		(457	)
Total other expense		—		—		(5,662	)		(5,662	)
Income before income taxes	$	10,448	$	12,408	$	(11,267	)	$	11,589

Reconciliation of income from operations to segment adjusted operating income:	Drilling Services		Managed Services
Income from operations	$	10,448	$	12,408
Depreciation		10,601		—
Segment adjusted operating income	$	21,049	$	12,408


	Three Months Ended June 30, 2022
(unaudited, in thousands)	Drilling Services		Managed Services		Unallocated			Consolidated
Revenue
Contract drilling services	$	42,744	$	—	$	—		$	42,744
Management fees		—		2,840		—			2,840
Reimbursables and other		5,119		22,535		—			27,654
Total revenue		47,863		25,375		—			73,238
Operating costs and expenses
Operating costs		36,164		23,241		—			59,405
General and administrative		—		—		6,910			6,910
Depreciation		10,695		—		392			11,087
Gain on EDC Sale		—		—		(60,781	)		(60,781	)
Total operating costs and expenses		46,859		23,241		(53,479	)		16,621
Income from operations		1,004		2,134		53,479			56,617
Other (expense) income
Interest income		—		—		7			7
Interest expense and financing charges		—		—		(8,503	)		(8,503	)
Other, net		—		—		(1,011	)		(1,011	)
Total other expense		—		—		(9,507	)		(9,507	)
Income before income taxes	$	1,004	$	2,134	$	43,972		$	47,110

Reconciliation of income from operations to segment adjusted operating income:	Drilling Services		Managed Services
Income from operations	$	1,004	$	2,134
Depreciation		10,695		—
Segment adjusted operating income	$	11,699	$	2,134


	Six Months Ended June 30, 2023
	Drilling Services		Managed Services		Unallocated			Consolidated
(unaudited, in thousands)
Revenue
Contract drilling services	$	73,366	$	42,224	$	—		$	115,590
Management fees		—		7,689		—			7,689
Reimbursables and other		14,256		47,377		—			61,633
Total revenue		87,622		97,290		—			184,912
Operating costs and expenses
Operating costs		60,885		80,053		—			140,938
General and administrative		—		—		9,992			9,992
Depreciation		21,240		—		854			22,094
Loss on EDC Sale		—		—		3			3
Total operating costs and expenses		82,125		80,053		10,849			173,027
(Loss) income from operations		5,497		17,237		(10,849	)		11,885
Other (expense) income
Interest income		—		—		190			190
Interest expense and financing charges		—		—		(10,904	)		(10,904	)
Other, net		—		—		(135	)		(135	)
Total other expense		—		—		(10,849	)		(10,849	)
(Loss) income before income taxes	$	5,497	$	17,237	$	(21,698	)	$	1,036

Reconciliation of income from operations to segment adjusted operating income:	Drilling Services		Managed Services
Income from operations	$	5,497	$	17,237
Depreciation		21,240		—
Segment adjusted operating income	$	26,737	$	17,237


	Six Months Ended June 30, 2022
	Drilling Services		Managed Services		Unallocated			Consolidated
(unaudited, in thousands)
Revenue
Contract drilling services	$	87,657	$	—	$	—		$	87,657
Management fees		—		3,943		—			3,943
Reimbursables and other		10,302		29,667		—			39,969
Total revenue		97,959		33,610		—			131,569
Operating costs and expenses
Operating costs		72,602		30,736		—			103,338
General and administrative		—		—		13,492			13,492
Depreciation		21,551		—		831			22,382
Gain on EDC Sale		—		—		(60,781	)		(60,781	)
Total operating costs and expenses		94,153		30,736		(46,458	)		78,431
Income from operations		3,806		2,874		46,458			53,138
Other (expense) income
Interest income		—		—		11			11
Interest expense and financing charges		—		—		(17,007	)		(17,007	)
Other, net		—		—		(1,786	)		(1,786	)
Total other expense		—		—		(18,782	)		(18,782	)
Income before income taxes	$	3,806	$	2,874	$	27,676		$	34,356

Reconciliation of income from operations to segment adjusted operating income:	Drilling Services		Managed Services
Income from operations	$	3,806	$	2,874
Depreciation		21,551		—
Segment adjusted operating income	$	25,357	$	2,874

~~for the period from February 10, 2016 to September 30, 2016 and for the period from January 1, 2016 to February 10, 2016, respectively.~~

For the three and ~~nine~~six months ended ~~September~~June 30, ~~2017~~2023 and ~~2016, all~~2022, a substantial amount of our revenue was derived from countries outside of the United States. Consequently, we are exposed to the risk of changes in economic, political and social conditions inherent in foreign operations. Four customers accounted for approximately 47%, 22%, 11% and 10% of consolidated revenue for the three months ended September 30, 2017. For the nine months ended September 30, 2017, four customers accounted for approximately 53%, 14%, 14% and 11% of consolidated revenue. For the three months ended September 30, 2016, two customers accounted for approximately 66% and 19% of consolidated revenue. Three customers accounted for approximately 56%, 19% and 15% of consolidated revenue for the period from February 10, 2016 to September 30, 2016. Three customers accounted for approximately 58%, 18% and 14% of consolidated revenue for the period from January 1, 2016 to February 10, 2016.

Our revenue by country and segment was as ~~follows:~~ follows for the periods indicated (revenue of less than 10% is included in “Other countries”):

	Successor								Predecessor
	Three Months Ended September 30,				Nine Months Ended September 30, 2017		Period from February 10, 2016 to September 30, 2016		Period from January 1, 2016 to February 10, 2016			Three months ended June 30,				Six months ended June 30,
	2017		2016		Nine Months Ended September 30, 2017		Period from February 10, 2016 to September 30, 2016		Period from January 1, 2016 to February 10, 2016
Country											Segment	2023		2022		2023		2022
(unaudited, in thousands)
Congo	$	39,830	$	26,385	$	102,517	$	65,664	$	13,769
Malaysia		6,460		7,783		20,965		22,743		3,319
India											Drilling Services and Managed Services	$	34,683	$	13,230	$	68,822	$	26,518
UAE											Drilling Services and Managed Services		20,267		19,778		42,911		27,966
Indonesia		—		—		—		18,062		4,214	Drilling Services and Managed Services		12,832		5,827		22,378		8,805
Namibia											Drilling Services		29,385		—		38,378		—
Egypt											Drilling Services		—		9,738		—		26,859
Qatar		5,882		—		17,574		—		—	Drilling Services		—		6,934		—		14,319
Other countries (a)		5,524		5,774		11,952		11,770		2,238
Other countries (1)											Drilling Services and Managed Services		10,673		17,731		12,423		27,102
Total revenues	$	57,696	$	39,942	$	153,008	$	118,239	$	23,540		$	107,840	$	73,238	$	184,912	$	131,569

(1) “Other countries” represent countries in which we operate that individually had operating revenues representing less than 10% of total revenues earned.

~~(a)~~

~~Other countries represent countries in which we operate that individually had operating revenues representing less than 10% of total revenues earned.~~

~~Our property and equipment, net by country was~~Revenue with customers that contributed 10% or more of revenue for the periods indicated were as follows:

September 30, 2017

December 31, 2016

(unaudited, in thousands)

Congo

$
261,672

$
277,305

Malaysia

264,647

280,689

South Africa

183,634

196,473

Other countries (a)

71,159

80,061

Total property and equipment

$
781,112

$
834,528

~~(a)~~

~~Other countries represent countries in which we individually had property and equipment, net, representing less than 10% of total property and equipment, net.~~


		Three months ended June 30,						Six months ended June 30,
(unaudited)	Segment	2023			2022			2023			2022
Customer 1	Drilling Services and Managed Services		32	%		18	%		37	%		20	%
Customer 2	Managed Services		20	%		30	%		24	%		23	%
Customer 3	Drilling Services		27	%		0	%		21	%		0	%
Customer 4	Drilling Services		0	%		13	%		0	%		20	%
Customer 5	Drilling Services		0	%		0	%		0	%		10	%

AInformation related to the Company’s “Total Assets” as reported on the Consolidated Balance Sheets is not available by reportable segment; however, a substantial portion of our assets are mobile drilling ~~units.~~units included in the Drilling Services segment. Asset locations at the end of the period are not necessarily indicative of the geographic distribution of the revenues generated by such assets during the periods.Our property and equipment, net by country, was as follows as of the dates indicated (property and equipment of less than 10% are included in “Other countries”):


	June 30, 2023		December 31, 2022
(unaudited, in thousands)
Namibia	$	151,060	$	—
India		74,614		81,309
Indonesia		56,165		58,663
International Waters		—		158,785
Other countries (1)		37,160		39,699
Total property and equipment	$	318,999	$	338,456

(1) “Other countries” represent countries in which we individually had property and equipment, net, representing less than 10% of total property and equipment, net.

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

The following discussion is intended to assist you in understanding our financial position ~~at September~~as of June 30, ~~2017~~2023, and our results of operations for the three and ~~nine~~six months ended ~~September~~June 30, ~~2017, for the three months ended September 30, 2016~~2023 and for the periods from February 10, 2016 to September 30, 2016 (the “Successor Period”) and from January 1, 2016 to February 10, 2016 (the “Predecessor Period”). The Successor Period and the Predecessor Period referred to in the results of operations are two distinct reporting periods as a result of our emergence from bankruptcy on February 10, 2016.2022. The discussion should be read in conjunction with the financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2022, which was filed with the SEC on March 31, 2023. The results of operations for the interim periods are not necessarily indicative of the operating results for the full fiscal year or any future periods. ~~Certain previously reported amounts have been reclassified to conform to the current year presentation.~~

Overview

We are an international offshore drilling company focused on operating a fleet of modern, high specification drilling units. Our principal business is to contract drilling units, related equipment and work crews, primarily on a dayrate basis, to drill oil and ~~natural~~ gas wells for our customers. Through our fleet of drilling units, we ~~are a provider of~~provide offshore contract drilling services to major, national and independent oil and ~~natural~~ gas companies, focused ~~primarily~~ on international markets. Additionally, for third party owned drilling units, ~~owned by others,~~ we provide ~~construction supervision services while under construction, preservation management services when stacked and~~ operations and marketing services for operating ~~rigs.~~and stacked rigs, construction supervision services for rigs that are under construction and preservation management services for rigs that are stacked.

The following table sets forth certain current information concerning our offshore drilling fleet as of ~~October 20, 2017.~~ August 1, 2023:


Name	Year Built	Water Depth Rating (feet)		Drilling Depth Capacity (feet)		Location	Status
Owned Rigs:
Jackups
Topaz Driller	2009		375		30,000	High Seas	Mobilizing
Soehanah	2007		375		30,000	Indonesia	Operating
Drillships (1)
Platinum Explorer	2010		12,000		40,000	India	Operating
Tungsten Explorer	2013		12,000		40,000	Namibia	Operating
Third Party Owned Rigs:
Drillships
Polaris	2008		10,000		37,500	India	Operating
Capella	2008		10,000		37,500	Indonesia	Operating
Jackups
Emerald Driller	2008		375		30,000	Qatar	Operating
Sapphire Driller	2009		375		30,000	Qatar	Operating
Aquamarine Driller	2009		375		30,000	Qatar	Operating

Name

Year Built

Water Depth
Rating (feet)

Drilling Depth
Capacity
(feet)

Status
Jackups

Emerald Driller

2008

375

30,000

Operating
Sapphire Driller

2009

375

30,000

Operating
Aquamarine Driller

2009

375

30,000

Operating
Topaz Driller

2009

375

30,000

Operating
Vantage 260 (1)

1979

250

20,000

Held for sale
Drillships (2)

Platinum Explorer

2010

12,000

40,000

Mobilizing
Titanium Explorer

2012

12,000

40,000

Warm Stacked
Tungsten Explorer

2013

12,000

40,000

Operating

(1) ~~The~~ ~~Vantage 260~~ ~~is designed for 250 feet water depths but is currently outfitted for 150 feet water depth.~~

~~(2)~~

The drillships are designed to drill in up to 12,000 feet of ~~water and are~~water. The Platinum Explorer is currently equipped to drill in 10,000 feet of water and the Tungsten Explorer is currently equipped to drill in 11,000 feet of water.

Recent Developments

~~Reorganization~~Redemption of the 9.25% First Lien Notes

On February 3, 2023, the ~~Petition Date, we filed~~Company issued a ~~reorganization plan~~notice of full conditional redemption to the then existing recordholders (the “Notice of Full Conditional Redemption”) of the remaining portion of the 9.25% First Lien Notes then outstanding after the partial redemption consummated in December 2022. The balance of the 9.25% First Lien Notes was redeemed in full on March 6, 2023 with proceeds derived from the issuance of the 9.50% First Lien Notes (as discussed below). See “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report for further information regarding the Notice of Full Conditional Redemption. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2 of this Quarterly Report.

9.50% First Lien Notes Offering

On February 14, 2023, the Company priced an offering of $200.0 million in aggregate principal amount of the 9.50% First Lien Notes and entered into a purchase agreement with several investors pursuant to which the Company agreed to sell the 9.50% First Lien Notes (the “9.50% First Lien Notes Offering”) to the purchasers in reliance on an exemption from registration provided by Section 4(a)(2), Rule 144A and/or Regulation S of the Securities Act. On March 1, 2023, the Company closed the sale of the 9.50% First Lien Notes. See “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report for further information regarding the 9.50% First Lien Notes Offering. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2 of this Quarterly Report.

Geopolitical and Market Instability Caused by the Ongoing Russo-Ukrainian War, Inflationary Pressures and Other Macroeconomic Conditions

Over the past 18 months, global oil prices have experienced a robust recovery resulting in the ~~United States Bankruptcy Court~~strongest annual performance (on a price-per-barrel basis) since 2012. During the calendar year 2022, specifically, Brent crude reached a high of approximately $125.00 per barrel in March 2022, although Brent crude ultimately settled at approximately $85.00 per barrel on the last day of trading in December 2022. However, Brent crude prices have continued to fluctuate through the first six months of 2023, specifically, (i) during the first quarter of 2023, Brent crude reached a high of approximately $88.00 per barrel and settled at approximately $80.00 per barrel on the last date of trading in March 2023, and (ii) during the second quarter of 2023, Brent crude reached a high of approximately $87.00 per barrel and settled at approximately $75.00 per barrel on the last date of trading in June 2023. While our management anticipates that oil and gas prices will remain elevated in the near-term as compared to prices exhibited during the last five years, price volatility is still expected to continue as a result of, among other factors, (i) adverse macroeconomic conditions, including inflationary pressures, potential recessionary conditions, and supply chain impediments and constraints, (ii) changes in oil and gas inventories, (iii) global market demand, (iv) geopolitical instability, armed conflict and social unrest, including the Russo-Ukrainian War, the associated response undertaken by western nations, such as the implementation, expansion and renewal of broad sanctions, the potential for retaliatory actions on the part of Russia and the overall impact on OPEC+ countries' ability to achieve production targets in the near- and long-term, (v) potential future disagreements among OPEC+ countries regarding the supply of oil, (vi) the potential for increased production and activity from U.S. shale producers and non-OPEC countries driven by the current oil prices, and (vii) any resurgence of COVID-19, and therefore, the Company cannot predict how long oil and gas prices will remain stable or further increase, if at all, or whether they could reverse course and decline.

The Russo-Ukrainian War, in particular, has led to, and will likely continue to lead to, geopolitical instability, disruption and volatility in the markets in which we operate. It is not possible at this time to predict or determine the ultimate consequences of the Russo-Ukrainian War, which could include, among other things, additional sanctions, greater regional instability, embargoes, geopolitical shifts and other material and adverse effects on macroeconomic conditions. However, such macroeconomic conditions, including inflationary pressures and potential recessionary conditions (and actions taken or being contemplated by central banks and regulators in an attempt to reduce, curtail and address such pressures and conditions), changes in energy policy, supply chain constraints and limitations, unpredictable financial markets and currency exchange rates, and hydrocarbon price volatility, are likely to continue for the ~~District~~foreseeable future. To the extent the Russo-Ukrainian War and other adverse macroeconomic conditions, including those set forth above, continue (or exacerbate), it could have a lasting impact in the near- and long-term on the (i) operations and financial condition of ~~Delaware (In re Vantage Drilling International (F/K/A Offshore Group Investment Limited), et al., Case No. 15-12422). On January 15, 2016,~~our business and the ~~District Court~~businesses of ~~Delaware confirmed~~our critical counterparties and (ii) global economy.

While our management is actively monitoring the foregoing events and its associated financial impact on our business, it is uncertain at this time as to the full magnitude that volatile and uncertain oil and gas prices will have on our financial condition and future results of operations. Likewise, in May 2023 the World Health Organization declared that COVID-19 was no longer a global health emergency; however, the Company continues to monitor for lingering impacts of COVID-19 on the Company’s ~~pre-packaged reorganization plan~~personnel, business operations and ~~we emerged from bankruptcy effective~~industry at large, and any resurgence of COVID-19 could pose significant risks and challenges worldwide.

The Aquadrill Merger and the Termination of Certain Agreements

VHI previously entered into a framework agreement with Aquadrill LLC (“Aquadrill”) on February 9, 2021 (the “Framework Agreement”), and, certain subsidiaries of VHI (the “VHI Entities”) subsequently entered into a series of related management and marketing agreements (collectively, the ~~Effective Date.~~“Marketing and Management Agreements” and together with the Framework Agreement, the “Framework, Management and Marketing Agreements”) with certain subsidiaries of Aquadrill (collectively, the “Aquadrill Entities”). Pursuant to the Framework, Management and Marketing agreements, the VHI Entities agreed to provide certain marketing and operational management services with respect to the Capella, Polaris and Aquarius floaters. As of August 8, 2023, the Capella and the Polaris were performing drilling services for clients under their respective drilling contracts, while the Aquarius is currently in Norway and is no longer under the Company’s management.

Pursuant to the terms of the ~~Reorganization Plan,~~Framework, Management and Marketing Agreements, the ~~pre-bankruptcy term loans~~Company is eligible to receive the following fees associated with the management and ~~senior notes were retired~~marketing of the Aquadrill rigs: (i) first, the Company is to be paid a fixed management fee of $2,000, $4,000, $6,000 and $10,000 per day to manage a cold stacked rig, warm stacked rig, reactivating rig or operating rig, respectively (provided, that, certain discounts are to be provided on the ~~Effective Date by issuing~~management fee associated with cold stacked rigs to the ~~debtholders 4,344,959 Units~~extent there are more than one such rigs managed by the Company for Aquadrill); (ii) second, there are certain bonus/malus amounts that are applied to the fixed management fee that are contingent on whether the actual expenditures for a particular rig that is stacked, mobilizing, being reactivated or preparing for a contract exceed or come in under budget; (iii) third, the ~~reorganized Company. Each Unit~~Company is eligible to receive a marketing fee of ~~securities originally consisted of one New Share and $172.61 of principal~~1.5% of the ~~Convertible Notes, subject~~effective day rate of a drilling contract secured for the benefit of Aquadrill; (iv) fourth, the Company is eligible to ~~adjustment upon the payment of PIK interest and certain cases of redemption or conversion~~earn a variable fee equal to 13% of the ~~Convertible Notes, as well as share splits, share dividends, consolidation or reclassification of~~gross margin associated with managing an operating rig for Aquadrill; and (v) lastly, all costs incurred by the ~~New Shares~~Company are reimbursed by Aquadrill (other than incremental overhead costs incurred by Vantage). ~~The New Shares and the Convertible Notes are subject to the terms of an agreement that prohibits the New Shares and Convertible Notes from being traded separately.~~

~~The Convertible Notes are convertible into New Shares in certain circumstances, at a conversion price (subject to adjustment in~~In accordance with the terms of the ~~Indenture~~Framework, Marketing and Management Agreements, Aquadrill may also terminate such agreements upon 90 days’ notice (the “Notice Termination Period”), subject to certain conditions set forth in such agreements.

On December 23, 2022, Seadrill Ltd. announced that it had entered into a merger agreement with Aquadrill, pursuant to which Aquadrill would become a wholly owned subsidiary of Seadrill Ltd. (the “Aquadrill Merger”), and on April 3, 2023, Seadrill Ltd. announced that it had closed the Aquadrill Merger. Subsequent to the Aquadrill Merger, Aquadrill was renamed to Seadrill LLC (”Seadrill”). On April 10, 2023, we received a notice of termination (the “Termination Notice”) of the management agreement (the “Aquarius Management Agreement”) and marketing agreement with respect to the Aquarius (the “Aquarius Marketing Agreement,” and together with the Aquarius Management Agreement, the “Aquarius Agreements”), and the marketing agreements with respect to the Capella and Polaris (the “Capella and Polaris Marketing Agreements”), in each case as a result of the Aquadrill Merger. Given that the Notice Termination Period has now lapsed, we are therefore no longer managing or marketing the Aquarius nor eligible to earn management fees under the Aquarius Management Agreement as of July 9, 2023. Notwithstanding the termination of the Aquarius Agreements and the Capella and Polaris Marketing Agreements, certain provisions survived such termination and, therefore, to the extent that a drilling contract(s) is secured and executed in respect of outstanding bids or tenders for the ~~Convertible Notes) which was $95.60~~Aquarius, Polaris and/or Capella, we will still be eligible to earn the marketing fee in respect of such secured and executed contracts, as well as in respect of existing drilling contracts. Moreover, as the management agreements with respect to the Capella and Polaris remain in effect as of the ~~issue date. The Indenture~~date hereof, we continue to manage and operate those rigs for Seadrill Ltd. (and for the ~~Convertible Notes includes customary covenants that restrict, among other things, the granting of liens~~oil and customary events of default, including among other things, failure to issue securities upon conversion of the Convertible Notes. As of September 30, 2017, taking into account the payment of PIK interest on the Convertible Notes to such date, each such Unit consisted of one New Sharegas clients under their respective drilling contracts) and ~~$175.02 of principal of Convertible Notes.~~

~~Other significant elements of the Reorganization Plan included:~~

~~facility and (ii) repay the $150 million of outstanding borrowings under its pre-petition facility with (a) $7.0 million of cash and (b) the issuance of $143.0 million initial term loans.~~

~~10% Senior Secured Second Lien Notes.~~ ~~Holders of the Company’s pre-petition secured debt claims were~~therefore, remain eligible to ~~participate~~receive the management and variable fees described immediately above. Nevertheless, there is no guarantee that such arrangements will remain in a rights offering conducted by the Company for $75.0 million of the Company’s 10% Second Lien Notes. In connection with this rights offering, certain creditors entered into a “backstop” agreement to purchase 10% Second Lien Notes if the offer was not fully subscribed. The premium paid to such creditors under the backstop agreement was approximately $2.2 million, paid $1.1 million in cash and $1.1 million in additional 10% Second Lien Notes, resulting in a total issued amount of $76.1 million of 10% Second Lien Notes, and in net cash proceeds of $73.9 million, after deducting the cash portion of the backstop premium.

~~VDC Note.~~ ~~Effective with the Company’s emergence from bankruptcy, VDC’s former equity interest~~place in the Company was cancelled. Immediately following that event, the VDC Note was converted into 655,094 New Shares in accordance with the terms thereof, in satisfaction of the obligation thereunder, which, including accrued interest, totaled approximately $62.6 million asnear- and long-term and any further terminations of such ~~date.~~arrangements could have a material impact on our financial condition and future results of operations.

The Reorganization Plan allowed the Company to maintain all operating assets and agreements. All trade payables, credits, wages and other related obligations were unimpaired by the Reorganization Plan.

Upon emergence from bankruptcy on the Effective Date, we adopted fresh-start accounting in accordance with ASC 852, which resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical consolidated balance sheets. The effects of the Reorganization Plan and the application of fresh-start accounting are reflected in our consolidated balance sheet as of December 31, 2016 and the related adjustments thereto were recorded in our consolidated statements of operations as reorganization items.

Business Outlook

Expectations about future oil and ~~natural~~ gas prices have historically been a key driver of demand for our services. Global oil prices have experienced a robust recovery since the COVID-19 pandemic resulting in prices that are supportive of investment in shallow-water and deepwater exploration and development projects.

While industry sentiment is positive, the industry is a highly cyclical and competitive business. Market volatility and uncertainty in regards to Brent oil prices largely remain as prices fell to a low of approximately $72.00 barrel in June 2023 (as compared to a high of approximately $125.00 per barrel in March 2022). In addition, the oil and gas industry continues to be materially impacted and shaped by external factors which have influenced its overall development and recovery, including global macroeconomic challenges resulting from inflationary pressures and potential recessionary conditions, as well as geopolitical and market instability caused by the Russo-Ukrainian War. Further, OPEC+ has actively sought to manage production during this time to reduce supply and stabilize crude price. Additionally, geopolitical developments could occur, including a possible agreement relating to Iran’s nuclear deal and the subsequent suspension of U.S. sanctions in Iran (which could result in, among other things, the influx of Iranian crude oil into the global markets), any of which could significantly impact our business and operations. With higher crude oil prices there is the potential for increased production from U.S. shale producers and non-OPEC countries, which could lead to significant increases in the overall global oil and gas supply, and result in reduced commodity prices.

The ~~International Energy Agency (the “Agency”)~~opening of economies, supply chain constraints and limitations occurring throughout the world and across various industries, and the injection of significant levels of governmental monetary and fiscal stimulus to avoid a recession during the peak of the COVID-19 pandemic, collectively contributed to the highest level of inflation in decades across the U.S., the United Kingdom, Europe and the global community at large. As a result, central banks and regulators across the world have raised, and could continue to raise, interest rates in an attempt to gain further control over and reduce inflation in their October 2017 Oil Market Report, estimates that average demand will increase by approximately 1.6 million barrels per day or 1.6% in 2017 from 96.6 million barrels per day to 98.2 million barrels per day. The Agency forecasts a slightly lower growth in demand of 1.4 million barrels per day for 2018, when global demand is estimated to reach 99.6 million barrels per day.respective jurisdictions. While this represents favorable growth in demand, it has not been enough to fully offset surplus production and high inventories remain, which continue to depress oil prices. Continuing uncertainty around the viability and length ofwe anticipate gradual rate reductions in ~~production agreed~~the future, our operations may face significant adverse effects from industry-specific inflation. This industry-specific inflation could be attributed to the growing rig supply, leading to heightened demand for qualified labor and equipment, which might become scarce at certain times. As a consequence, we may experience higher personnel costs and increased prices for goods and services essential for rig operations. Given that we predominantly enter into fixed dayrate contracts that have contractual terms with minimal adjustments to account for rising inflation, the majority (if not all) of these costs would be borne by us.

While we are currently unable to estimate the ~~Organization~~ultimate impact of ~~Petroleum Exporting Countries (“OPEC”)~~inflation, including the associated impact on the prices of goods and services, our costs could rise in the ~~incremental production capacity~~near-term and materially impact our profitability and overall financial condition. In addition, the efforts being undertaken by central banks and regulators to rein in ~~non-OPEC countries, including growing production from~~inflation could tip the ~~U.S. shale activity, continue to contribute to an uncertain~~global economy into a recession, which could materially and adversely impact demand for oil ~~price environment.~~

and gas and, in the process, demand for our services. As a result of ~~the persistence of reduced oil prices since 2014, exploration~~such volatility, disruption, instability and ~~development companies~~uncertainty, operators have ~~significantly reduced capital expenditures during this period~~faced, and ~~historically low levels of spending are expected for 2017 and 2018. Recent analyst surveys of exploration and production spending indicate that oil and gas companies~~may continue to ~~reduce~~face, challenges when attempting to definitively plan their capital ~~expenditures~~budget programs for the near- and we expect that the offshore drilling programs of operators will remain curtailed until higher, sustainable crude oil prices are achieved. Accordingly, we anticipate that our industry will experience depressed market conditions through 2017 and 2018.long- term.

In addition to the reduction in demand for drilling rigs, the additional supply of newbuild rigs is further depressing the market. There are currently 97 jackups and 31 deepwater floaters on order at shipyards per Bassoe Offshore A.S. with scheduled deliveries extending out to April 2021. While 25 jackups and 12 deepwater floaters are scheduled for delivery through December 31, 2017, it is unclear when these drilling rigs will actually be delivered as many rig deliveries have already been deferred to later dates and some rig orders have been canceled. In response to the oversupply of drilling rigs, a number of competitors are removing older, less efficient rigs from their fleets by either cold stacking the drilling rigs or taking them permanently out of service.30

Since June 2014, 101 rigs, with an average age of approximately 36 years, have been announced for recycling according to Bassoe Offshore AS. Of these 101 rigs, 69 are semisubmersibles, 15 are drillships and 17 are jackups. We expect drilling rig cold stacking, scrapping and conversion to non-drilling use to continue during 2017 and 2018. While we believe this is an important element in bringing the supply of drilling rigs back into balance with demand, we do not anticipate that it will be sufficient to materially improve market conditions in 2017 or in 2018.Backlog

The following table ~~reflects a summary of~~summarizes our contract ~~drilling~~ backlog coverage of days contracted and related revenue as of ~~September~~June 30, ~~2017 forward (based~~2023 based on information available ~~at that time).~~ as of such date:


	Percentage of Days Contracted			Revenues Contracted (in thousands)
	2023	2024	Beyond	2023		2024		Beyond
Backlog
Jackups	77%	56%	41%	$	52,240	$	49,383	$	36,210
Drillships	89%	4%	0%	$	84,191	$	6,580	$	—
Third party owned rigs (1)	75%	60%	24%	$	35,203	$	5,206	$	219

Percentage of Days Contracted

Revenues Contracted
(in thousands)

2017

2018

2017

2018

Beyond

Jackups

100%

40%

$
22,944

$
40,146

$
7,727

Drillships

55%

61%

$
38,825

$
124,186

$
67,727

(1)

~~In June 2017, our ultra-deepwater drillship,~~These amounts include: (i) a fixed management fee paid to us pursuant to the ~~Platinum Explorer, received~~applicable management agreement; (ii) a ~~letter~~marketing fee paid to us pursuant to the applicable marketing agreement; (iii) a fixed management fee paid to us pursuant to the applicable EDC Support Services Agreements; and (iv) contract backlog attributable to rigs owned by third parties for which we enter into contracts directly with customers and lease the rigs through bareboat charters from the rig owners. However, these amounts exclude any variable fee payable to us pursuant to the applicable management agreement. The terms of ~~award for a three year contract from Oil and Natural Gas Company. The~~ ~~Platinum Explorer~~ ~~is currently mobilizing to India for planned commencement of operations~~the bareboat charters are consistent with the management agreements, resulting in the ~~fourth quarter of 2017.~~same financial impact to us had the rigs remained under the management agreements.

Results of Operations

Operating results for our contract drilling services are dependent on three primary metrics: available ~~days,~~days; rig ~~utilization~~utilization; and dayrates. The following table sets forth this selected operational information for the periods ~~indicated.~~ indicated:


	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
Jackups
Rigs available		2			2			2			2
Available days (1)		91			182			181			362
Utilization (2)		94.4	%		98.8	%		97.2	%		79.6	%
Average daily revenues (3)	$	59,355		$	60,694		$	58,755		$	65,807
Deepwater
Rigs available		2			2			2			2
Available days (1)		182			182			362			362
Utilization (2)		95.2	%		99.7	%		79.1	%		99.2	%
Average daily revenues (3)	$	238,234		$	139,628		$	220,182		$	152,261
Sold Rigs/Held for Sale (4)
Rigs available		—			3			—			3
Available days (1)		—			168			—			654
Utilization (2)	N/A				47.0	%	N/A				62.3	%
Average daily revenues (3)	N/A			$	82,127		N/A			$	34,339

Successor

Predecessor

Three Months Ended September 30,

Nine Months Ended September 30, 2017

Period from February 10, 2016 to September 30, 2016

Period from January 1, 2016 to February 10, 2016

2017

2016

Jackups

Rigs available (at end of period)

4

4

4

4

4

Available days (1)

439

368

1,250

936

160

Utilization (2)

93.8
%

25.6
%

76.4
%

43.4
%

53.6
%

Average daily revenues (3)

$
63,263

$
112,205

$
64,269

$
94,794

$
88,347

Deepwater

Rigs available

3

3

3

3

3

Available days (1)

276

276

819

702

120

Utilization (2)

33.3
%

33.1
%

33.2
%

33.2
%

33.3
%

Average daily revenues (3)

$
280,191

$
265,000

$
281,040

$
262,271

$
332,715

(1)

Available days are the total number of rig calendar days in the period, excluding rigs under bareboat charter contracts to third parties.

(2)

Utilization is calculated as a percentage of the actual number of revenue earning days divided by the available days in the period. A revenue earning day is defined as a day for which a rig earns dayrate after commencement of operations.

(3)

Average daily revenues are based on contract drilling revenues divided by revenue earning days. Average daily revenue will differ from average contract dayrate due to billing adjustments for any non-productive time, mobilization fees and demobilization fees.

(4)

Each of these rigs were classified as held for sale on our Consolidated Balance Sheet at December 31, 2022, up to the date of the EDC Sale.

~~(1)~~

~~Available days are the total number of rig calendar days in the period. Rigs are removed upon classification as held for sale and no longer eligible to earn revenue.~~

~~(2)~~

~~(3)~~

For the Three Months Ended ~~September~~June 30, ~~2017~~2023 and ~~2016~~2022

Net ~~loss~~income attributable to shareholders for the ~~three months ended September 30, 2017 (the “Current Quarter”)~~Current Quarter was ~~$40.1~~$1.5 million, or ~~$8.01~~$0.11 per basic ~~and diluted~~ share, on operating revenues of ~~$57.7~~$107.8 million, compared to net ~~loss~~income attributable to shareholders for the ~~three months ended September 30, 2016 (the “Comparable Quarter”)~~Comparable Quarter of ~~$41.5~~$48.1 million, or ~~$8.31~~$3.67 per basic ~~and diluted~~ share, on operating revenues of ~~$39.9~~$73.2 million.

The following table ~~is an analysis of~~sets forth our operating results for the three months ended ~~September~~June 30, ~~2017~~2023 and ~~2016.~~2022:

Three Months Ended September 30,

Change

2017

2016

$

%
(unaudited, in thousands)

Revenues

Contract drilling services

$
51,831

$
34,755

$
17,076

49
%

Management fees

342

993

(651
)

-66
%

Reimbursables

5,523

4,194

1,329

32
%

Total revenues

57,696

39,942

17,754

44
%

Operating costs and expenses

Operating costs

49,848

30,983

18,865

61
%

General and administrative

6,949

10,128

(3,179
)

-31
%

Depreciation

18,538

18,977

(439
)

-2
%

Total operating costs and expenses

75,335

60,088

15,247

25
%

Loss from operations

(17,639
)

(20,146
)

2,507

-12
%

Other income (expense)

Interest income

231

11

220

**

Interest expense and financing charges

(19,258
)

(18,722
)

(536
)

3
%

Other, net

858

669

189

28
%

Reorganization items

-

35

(35
)

-100
%

Total other expense

(18,169
)

(18,007
)

(162
)

1
%

Loss before income taxes

(35,808
)

(38,153
)

2,345

-6
%

Income tax provision

4,260

3,373

887

26
%

Net loss

$
(40,068
)

$
(41,526
)

$
1,458

-4
%

** Not a meaningful percentage.


	Three Months Ended June 30,						Change
	2023			2022			$			%
(unaudited, in thousands)
Consolidated:
Revenues
Contract drilling services	$	67,673		$	42,744		$	24,929			58	%
Management fees		5,569			2,840			2,729			96	%
Reimbursables and other		34,598			27,654			6,944			25	%
Total revenues		107,840			73,238			34,602			47	%
Operating costs and expenses:
Operating costs		74,383			59,405			14,978			25	%
General and administrative		5,161			6,910			(1,749	)		-25	%
Depreciation		11,045			11,087			(42	)		0	%
Gain on EDC Sale		—			(60,781	)		60,781			-100	%
Total operating costs and expenses		90,589			16,621			73,968			445	%
Income from operations		17,251			56,617			(39,366	)		-70	%
Other (expense) income
Interest income		141			7			134		n/m
Interest expense and financing charges		(5,346	)		(8,503	)		3,157			-37	%
Other, net		(457	)		(1,011	)		554			-55	%
Total other expense		(5,662	)		(9,507	)		3,845			-40	%
Income before income taxes		11,589			47,110			(35,521	)		-75	%
Income tax provision (benefit)		10,584			(1,221	)		11,805			-967	%
Net income		1,005			48,331			(47,326	)		-98	%
Net (loss) income attributable to noncontrolling interests		(457	)		232			(689	)		-297	%
Net income attributable to shareholders	$	1,462		$	48,099		$	(46,637	)		-97	%

Drilling Services:
Revenue
Contract drilling services	$	46,378		$	42,744		$	3,634			9	%
Management fees		—			—			—		n/m
Reimbursables and other		7,834			5,119			2,715			53	%
Total revenue		54,212			47,863			6,349			13	%
Operating costs and expenses:
Operating costs		33,163			36,164			(3,001	)		-8	%
General and administrative		—			—			—		n/m
Depreciation		10,601			10,695			(94	)		-1	%
Gain on EDC sale		—			—			—		n/m
Total operating costs and expenses		43,764			46,859			(3,095	)		-7	%
Income from operations		10,448			1,004			9,444			941	%

Managed Services:
Revenue
Contract drilling services	$	21,295		$	—		$	21,295		n/m
Management fees		5,569			2,840			2,729			96	%
Reimbursables and other		26,764			22,535			4,229			19	%
Total revenue		53,628			25,375			28,253			111	%
Operating costs and expenses:
Operating costs		41,220			23,241			17,979			77	%
General and administrative		—			—			—		n/m
Depreciation		—			—			—		n/m
Gain on EDC sale		—			—			—		n/m
Total operating costs and expenses		41,220			23,241			17,979			77	%
Income from operations		12,408			2,134			10,274			481	%
n/m = not meaningful

Consolidated Revenue:Total revenue increased ~~44% and contract~~$34.6 million due primarily to an increase in operating activities in the Current Quarter, as discussed below.

Drilling Services Revenue: Contract drilling revenue increased ~~49%~~$3.6 million for the Current Quarter as compared to the Comparable Quarter. The increase in our contract drilling revenue was primarily the result of the (i) Tungsten Explorer on contract at a higher dayrate in the Current Quarter ~~was primarily due to improved utilization on our jackup fleet, with an aggregate of 317 incremental revenue-earning days, including 71 additional days attributable to the addition of the~~ ~~Vantage 260, contributing $5.5 million in increased revenue. Increased average dayrates and revenue efficiencies on the~~ ~~Tungsten Explorer~~ ~~contributed an incremental $1.6 million contract drilling revenue in the Current Quarter.~~

Management fees and reimbursable revenue for the Current Quarter were $0.3 million and $5.5 million, respectively, as compared to $1.0 million and $4.2 million, respectively, in the Comparable Quarter. The decrease in management fees was primarily due to the completion of the construction of a managed drillship in 2016. The increase in reimbursable revenue was primarily a result of the increases in jackup utilization.

~~Operating costs:~~ ~~Operating costs for the Current Quarter increased 61%~~ as compared to the Comparable Quarter, which was offset by lower contract drilling revenue as we operated three less jackup rigs (each of which were included in the EDC Sale), and (ii) Topaz Driller as the rig is operating under a bareboat charter in the Current Quarter as compared to operating under a drilling contact in the Comparable Quarter. ~~Jackup utilization changes resulted~~Reimbursables and other revenue increased 53% in ~~an incremental $11.6 million, including $1.6 million for non-cash amortization~~the Current Quarter as compared to the Comparable Quarter primarily as a result of the ~~contract value acquired with~~changes in drilling contracts (as discussed immediately above).

Managed Services Revenue: Contract drilling revenue increased $21.3 million in the ~~Vantage 260. Deepwater~~Current Quarter due to the Polaris, which is currently operated by the Company. Management fees increased 96% in the Current Quarter as compared to the Comparable Quarter primarily due to the management of the rigs included in the EDC Sale as well as deepwater floaters owned by Seadrill. Reimbursables and other revenue increased $4.2 million in the Current Quarter as compared to the Comparable Quarter is primarily as a result of the management of the deepwater floaters owned by Seadrill and the rigs included in the EDC Sale.

Consolidated Operating Costs: Total operating costs increased ~~$7.3 million~~25% due primarily to ~~incremental~~an increase in operating activities in the Current Quarter as discussed below.

Drilling Services Operating Costs: Drilling Services operating costs ~~for~~decreased 8% in the ~~reactivation~~Current Quarter as compared to the Comparable Quarter primarily as a result of the ~~Platinum Explorer~~ ~~for an upcoming~~Topaz Driller as the rig is operating under a bareboat charter in the Current Quarter as compared to operating under a drilling contract in ~~India.~~the Comparable Quarter (as discussed in “Drilling Services Revenue” above).

Managed Services Operating Costs: The increase in Managed Services operating costs in the Current Quarter as compared to the Comparable Quarter is the result of the management of certain deepwater floaters (as discussed in “Managed Services Revenue” above).

General and ~~administrative expenses:~~Administrative Expenses: Decreasesin general and administrative expenses for the Current Quarter as compared to the Comparable Quarter were primarily due to lower compensation expense as a ~~$1.4 million decrease~~result of bonuses paid in ~~legal expenses associated with~~the comparable quarter that did not recur in the current quarter and professional fees. Non-cash share-based compensation expense included in “General and administrative expenses” was immaterial for each of the Current Quarter and Comparable Quarter.

Depreciation Expense: Depreciation expense is primarily related to rigs owned by us which are included in our ~~internal FCPA investigation and the Petrobras arbitration. Additionally, the Comparable Quarter included accrued severance costs in connection with the resignations of former executives.~~

~~Depreciation expense:~~ Drilling Services segment. The Managed Services segment does not currently own any depreciable assets.Depreciation expense for the Current Quarter ~~was~~is generally consistent with the Comparable Quarter.

Interest ~~expense and other financing charges:~~ ~~Interest expense~~Income: Increases in interest income for the Current Quarter ~~was consistent with~~as compared to the Comparable Quarter were due primarily to higher cash balances during the Current Quarter.

Interest Expense and Financing Charges: Decreases in interest expense ~~includes non-cash discount accretion, payment-in-kind interest~~ and ~~deferred~~ financing ~~costs totaling approximately $14.3 million and $14.1 million~~charges for the Current Quarter ~~and for~~as compared to the Comparable Quarter were primarily due to lower outstanding debt as a result of the pay down of the 9.25% Notes in Q4 2022 offset by higher interest rates due to the refinancing of the remaining balance with the 9.50% Notes during Q1 2023. Non-cash deferred financing costs included in “Interest expense and financing charges” was approximately $0.6 million and $0.4 million for each of the Current Quarter and Comparable Quarter, respectively.

Other, ~~net:~~ Net:Our functional currency is ~~the U.S. dollar;~~USD; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than ~~the U.S. dollar.~~USD. These transactions are ~~remeasured~~re-measured in ~~U.S. dollars~~

USD based on a combination of both current and historical exchange rates. Net foreign currency exchange ~~gains~~loss of ~~$0.9~~approximately $0.5 million and ~~$0.7~~$1.0 million ~~were~~was included in ~~other,~~“other, net,” for the Current Quarter and ~~the~~ Comparable Quarter, respectively.

Income ~~tax expense:~~ ~~Income tax expense increased in the Current Quarter as compared to the Comparable Quarter due to an increase in revenue in the Current Quarter and the impact of the annualized effective tax rate.~~

~~For the Nine months ended September 30, 2017 and the Successor and Predecessor Periods~~

Net loss for the nine months ended September 30, 2017 (the “Current Period”) was $113.2 million, or $22.63 per basic and diluted share, on operating revenues of $153.0 million and net loss for the Successor Period was $106.3 million, or $21.26 per basic and diluted share, on operating revenues of $118.2 million. Net loss attributable to VDI for the Predecessor Period was $471.0 million, on operating revenues of $23.5 million.

~~The following table is an analysis of our operating results for the Current Period, the Successor Period and the Predecessor Period.~~

Successor

Predecessor

Nine Months Ended September 30, 2017

Period from February 10, 2016 to September 30, 2016

Period from January 1, 2016 to February 10, 2016

(unaudited, in thousands)

Revenues

Contract drilling services

$
137,672

$
99,715

$
20,891

Management fees

1,148

3,664

752

Reimbursables

14,188

14,860

1,897

Total revenues

153,008

118,239

23,540

Operating costs and expenses

Operating costs

119,030

93,387

25,213

General and administrative

29,929

27,991

2,558

Depreciation

55,531

49,434

10,696

Total operating costs and expenses

204,490

170,812

38,467

Loss from operations

(51,482
)

(52,573
)

(14,927
)

Other income (expense)

Interest income

587

26

3

Interest expense and financing charges

(57,180
)

(48,144
)

(1,728
)

Other, net

2,073

987

(69
)

Reorganization items

-

(606
)

(452,919
)

Bargain purchase gain

1,910

-

-

Total other expense

(52,610
)

(47,737
)

(454,713
)

Loss before income taxes

(104,092
)

(100,310
)

(469,640
)

Income tax provision

9,067

5,978

2,371

Net loss

(113,159
)

(106,288
)

(472,011
)

Net loss attributable to noncontrolling interests

-

-

(969
)

Net loss attributable to VDI

$
(113,159
)

$
(106,288
)

$
(471,042
)

~~Revenue:~~ ~~During the Current Period jackup utilization averaged 76% with both the~~ ~~Emerald Driller~~ ~~and the~~ ~~Aquamarine Driller~~ working throughout and the remaining three jackups working a combined additional 410 days generating a combined average daily revenue of $64,268 across the jackup fleet. During the Successor Period, only the ~~Aquamarine Driller~~ worked the entire period with the remaining three jackups working a combined additional 175 days at a combined average daily revenue of $94,794. In the Predecessor period of January 1, 2016 to February 10, 2016, our jackups had an aggregate 86 revenue earning days at average daily revenue of approximately $88,347.

~~Deepwater utilization for the Current Period, for the Successor Period and for the Predecessor Period averaged 33% as only the~~ ~~Tungsten Explorer~~ ~~worked throughout all periods. Neither of our other two ultra-deepwater drillships worked during the reported periods as the~~ ~~Platinum Explorer~~ ~~completed its initial 5-year contract during the fourth quarter of 2015 and the~~ ~~Titanium Explorer~~ ~~drilling contract was cancelled by the operator in August 2015.~~

Management fees for the Current Period, the Successor Period and the Predecessor Period averaged approximately $4,206 per day, $15,658 per day and $18,810 per day, respectively. Reimbursable revenue for the Current Period and the Successor Period was $14.2 million and $14.9 million, respectively, with six rigs working part of the Current Period and four working for part of the Successor Period.~~Reimbursable revenue for the Predecessor Period was $1.9 million when three rigs worked for the entire period.~~

~~Operating costs:~~ Operating costs for the Current Period were approximately $119.0 million, including $8.2 million of reimbursable costs. Operating costs for the Successor Period were approximately $93.4 million, including $11.9 million of reimbursable costs. ~~For the Predecessor Period, operating costs were $25.2 million, including $1.4 million of reimbursable costs. Operating costs in the respective periods were dependent on the operational status of the~~ ~~rigs.~~

~~General and administrative expenses:~~ General and administrative expenses for the Current Period and the Successor Period were $29.9 million and $28.0 million, respectively, including $10.9 million and $6.8 million, respectively, in legal expenses associated with our internal FCPA investigation and the Petrobras arbitration. Similar charges incurred in the Predecessor Period totaled $531,000.

~~Depreciation expense:~~ For the Predecessor Period, depreciation expense was based on the historical cost basis of our property and equipment. Upon our emergence from bankruptcy, we applied the provisions of fresh-start accounting and revalued our property and equipment to fair value which resulted in a significant decrease in those values. Depreciation expense for the Current Period and the Successor Period is based on the reduced asset values of property and equipment as a result of the adoption of fresh-start accounting.

~~Interest expense and other financing charges:~~ Interest expense for the Current Period and for the Successor Period is calculated on the debt that was issued in connection with our emergence from bankruptcy on February 10, 2016. Interest expense for the Predecessor Period was calculated on the old credit agreement as provided for in the Reorganization Plan and on the VDC Note issued in connection with the Reorganization Plan. Interest expense for the Current Period and for the Successor Period includes approximately $42.7 million and $36.2 million of non-cash payment in kind interest and deferred financing costs, respectively.

~~Reorganization items:~~ In the Predecessor Period, we incurred $22.7 million of post-petition professional fees associated with the bankruptcy cases. Additionally, we incurred non-cash charges of $2.06 billion in fresh-start accounting adjustments, offset by a $1.63 billion non-cash gain on settlement of LSTC. During the Successor Period we incurred $606,000 in professional fee expenses in connection with our bankruptcy cases.

~~Bargain purchase gain:~~ We recorded a bargain purchase gain of $1.9 million during the Current Period related to our Vantage 260 acquisition. The gain on bargain purchase resulted from the excess of the net fair value of the assets acquired and liabilities assumed in the acquisition over the purchase price. We believe that we were able to negotiate a bargain purchase price as a result of our operational presence in West Africa and the seller’s liquidation.

~~Other, net:~~ Net foreign currency exchange gains included in other, net for the Current Period and the Successor Period were $2.3 million and $1.0 million, respectively. Foreign currency exchange gains or losses included in other, net in the Predecessor Period were insignificant.

~~Income tax expense:~~ Tax Provision: Our ~~estimated~~ annualized effective tax rate for the Current ~~Period~~Quarter is 163.61% based on estimated annualized ordinary profit before income taxes excluding income tax discrete items. Our annualized effective tax rate for the Comparable Quarter was negative ~~8.8%~~15.40%, based on estimated annualized loss before income taxes excluding income tax discrete items. Our estimated annualized effective tax rates for the Successor Period and the Predecessor Period were negative 9.4% based on estimated annualized loss or profit before income taxes in the respective periods, excluding income tax discrete items. For all periods, we had a loss before income taxes resulting in negative tax rates.

Our income taxes are generally dependent upon the results of our operations and the local income taxes in the jurisdictions in which we operate. In some jurisdictions, we do not pay taxes or receive benefits for certain income and expense items, including interest expense and disposal gains or losses. In other jurisdictions, we recognize income taxes on a net income basis or a deemed profit basis.

For the Six Months Ended June 30, 2023 and 2022

Net loss attributable to shareholders for the Current Period was $0.8 million, or $0.06 per basic share, on ~~extinguishment~~operating revenues of $184.9 million, compared to net income attributable to shareholders for the Comparable Period of $33.2 million, or $2.53 per basic share, on operating revenues of $131.6 million.

The following table sets forth our operating results for the six months ended June 30, 2023 and 2022:


	Six Months Ended June 30,						Change
	2023			2022			$			%
(unaudited, in thousands)
Consolidated:
Revenues
Contract drilling services	$	115,590		$	87,657		$	27,933			32	%
Management fees		7,689			3,943			3,746			95	%
Reimbursables and other		61,633			39,969			21,664			54	%
Total revenues		184,912			131,569			53,343			41	%
Operating costs and expenses:
Operating costs		140,938			103,338			37,600			36	%
General and administrative		9,992			13,492			(3,500	)		-26	%
Depreciation		22,094			22,382			(288	)		-1	%
Loss on EDC Sale		3			(60,781	)		60,784			-100	%
Total operating costs and expenses		173,027			78,431			94,596			121	%
Income from operations		11,885			53,138			(41,253	)		-78	%
Other (expense) income
Interest income		190			11			179		n/m
Interest expense and financing charges		(10,904	)		(17,007	)		6,103			-36	%
Other, net		(135	)		(1,786	)		1,651			-92	%
Total other expense		(10,849	)		(18,782	)		7,933			-42	%
Income before income taxes		1,036			34,356			(33,320	)		-97	%
Income tax provision		2,606			217			2,389		n/m
Net (loss) income		(1,570	)		34,139			(35,709	)		-105	%
Net (loss) income attributable to noncontrolling interests		(746	)		938			(1,684	)		-180	%
Net (loss) income attributable to shareholders	$	(824	)	$	33,201		$	(34,025	)		-102	%

Drilling Services:
Revenue
Contract drilling services	$	73,366		$	87,657		$	(14,291	)		-16	%
Management fees		—			—			—		n/m
Reimbursables and other		14,256			10,302			3,954			38	%
Total revenue		87,622			97,959			(10,337	)		-11	%
Operating costs and expenses:
Operating costs		60,885			72,602			(11,717	)		-16	%
General and administrative		—			—			—		n/m
Depreciation		21,240			21,551			(311	)		-1	%
Total operating costs and expenses		82,125			94,153			(12,028	)		-13	%
Income from operations		5,497			3,806			1,691			44	%

Managed Services:
Revenue
Contract drilling services	$	42,224		$	—		$	42,224		n/m
Management fees		7,689			3,943			3,746			95	%
Reimbursables and other		47,377			29,667			17,710			60	%
Total revenue		97,290			33,610			63,680			189	%
Operating costs and expenses:
Operating costs		80,053			30,736			49,317			160	%
General and administrative		—			—			—		n/m
Depreciation		—			—			—		n/m
Total operating costs and expenses		80,053			30,736			49,317			160	%
Income from operations		17,237			2,874			14,363			500	%
n/m = not meaningful

Consolidated Revenue: Total revenue increased $53.3 million due primarily to an increase in operating activities in the Current Period, as discussed below.

Drilling Services Revenue: Contract drilling revenue decreased $14.3 million for the Current Period as compared to the Comparable Period. The decrease in our contract drilling revenue was primarily the result of lower contract drilling revenue as we operated three less jackup rigs (each of which were included in the EDC Sale), and the Topaz Driller as the rig is operating under a bareboat charter in the Current Period as compared to operating under a drilling contact in the Comparable Period. Reimbursables and other revenue increased 38% in the Current Period as compared to the Comparable Period primarily as a result of bareboat charter fees earned on the Topaz Driller,offset by lower reimbursable revenue as a result of the changes in drilling contracts (as discussed immediately above).

Managed Services Revenue: Contract drilling revenue increased $42.2 million in the Current Period due to the Polaris, which is currently operated by the Company. Management fees increased $3.7 million in the Current Period as compared to the Comparable Period primarily due to the management of the rigs included in the EDC Sale as well as deepwater floaters owned by Seadrill. Reimbursables and other revenue increased $17.7 million in the Current Period as compared to the Comparable Period, primarily as a result of the management of the deepwater floaters owned by Seadrill and the rigs included in the EDC Sale.

Consolidated Operating Costs: Total operating costs increased 36% due primarily to an increase in operating activities in the Current Period as discussed below.

Drilling Services Operating Costs: Drilling Services operating costs decreased 16% in the Current Period as compared to the Comparable Period primarily as a result of the Company operating three less jackup rigs (each of which were included in the EDC Sale) and the Topaz Driller operating under a bareboat charter in the Current Period as compared to operating under a drilling contract in the Comparable Period (as discussed in “Drilling Services Revenue” above). The Comparable Period includes a net gain of approximately $1.9 million related to the sale of various assets.

Managed Services Operating Costs: The increase in Managed Services operating costs in the Current Period as compared to the Comparable Period is the result of the management of certain deepwater floaters (as discussed in “Managed Services Revenue” above).

General and Administrative Expenses: Decreases in general and administrative expenses for the Current Period as compared to the Comparable Period were primarily due to lower compensation expense as a result of bonuses paid in the comparable period that did not recur in the current period. Non-cash share-based compensation expense included in “General and administrative expenses” was immaterial for each of the Current Period and Comparable Period.

Depreciation Expense: Depreciation expense is primarily related to rigs owned by us which are included in our Drilling Services segment. The Managed Services segment does not currently own any depreciable assets.Depreciation expense for the Current Period is generally consistent with the Comparable Period.

Interest Income: Increases in interest income for the Current Period as compared to the Comparable Period were due primarily to higher cash balances during the Current Period.

Interest Expense and Financing Charges: Decreases in interest expense and financing charges in the Current Period as compared to the Comparable Period were primarily due to lower outstanding debt as a result of the pay down of the 9.25% Notes in Q4 2022 offset by higher interest rates due to the refinancing of the remaining balance with the 9.50% Notes during Q1 2023. Non-cash deferred financing costs included in “Interest expense and ~~reorganization expenses.~~financing charges” was approximately $0.9 million and $0.8 million for each of the Current Period and Comparable Period, respectively.

Other, Net: Our functional currency is USD; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than USD. These transactions are re-measured in USD based on a combination of both current and historical exchange rates. Net foreign currency exchange loss of approximately $0.1 million and $1.8 million was included in “other, net,” for the Current Period and Comparable Period, respectively.

Income Tax Provision: Our annualized effective tax rate for the Current Period is 163.61% based on estimated annualized ordinary profit before income taxes excluding income tax discrete items. Our annualized effective tax rate for the Comparable Period was negative 15.40%, based on estimated annualized loss before income taxes excluding income tax discrete items.

Liquidity and Capital Resources

Sources and Uses of Liquidity

Our anticipated cash flow needs, both in the short- and long-term, may include, among others: (i) normal recurring operating expenses; (ii) planned and discretionary capital expenditures; (iii) repayments of interest; and (iv) certain contractual cash obligations and commitments. We may, from time to time, redeem, repurchase or otherwise acquire our outstanding 9.50% First Lien Notes through open market purchases, tender offers or pursuant to the terms of such securities.

We currently expect to fund our cash flow needs with cash generated by our operations, cash on hand or proceeds from sales of assets. As of ~~September~~June 30, ~~2017,~~2023, we believe we maintain adequate cash reserves and are continuously managing our actual cash flow and cash forecasts. Accordingly, management believes that we have adequate liquidity to fund our operations for the twelve months following the date our Consolidated Financial Statements are issued and therefore, have been prepared under the going concern assumption.

As of June 30, 2023, we had working capital of approximately ~~$233.9~~$126.8 million, including approximately ~~$198.6~~ $79.7million of cash available for general corporate purposes. Scheduled ~~principal~~ debt ~~maturities and~~service consists of interest payments through ~~December 31, 2018 are~~June 30, 2024 of approximately ~~$31.1~~$18.3 million. We anticipate capital expenditures through ~~December 31, 2018 for sustaining capital expenditures on our rig fleet, capital spares, information technology and other general corporate projects~~June 30, 2024 to be between approximately ~~$3.1~~$13.7 million ~~to $3.8~~and $16.8 million. As our rigs obtain new contracts, we could incur reactivation and mobilization costs for these rigs, as well as additional customer requested equipment ~~upgrades. These costs~~upgrades, some (or all) of which could be significant and may not be fully recoverable from the customer. ~~Additionally, we anticipate expenditures for maintenance and repairs and equipment certifications~~Based on our ~~rigs in preparation for future contracts. Through December 31, 2018, we anticipate~~anticipated levels of activity, incremental expenditures through June 30, 2024 for ~~fleet reactivation,~~ special periodic surveys, ~~and~~ major repair and maintenance expenditures and equipment re-certifications are anticipated to be between approximately ~~$15.8~~$19.2 million ~~to $19.4~~and $23.4 million. As of ~~September~~June 30, ~~2017~~2023, we ~~had $12.7 million available for the issuance of~~maintained letters of credit ~~under our revolving letter~~outstanding in the aggregate amount of ~~credit facility.~~

~~In February 2017, we executed a purchase and sale agreement with a third party to acquire the~~ ~~Vantage 260~~ ~~jackup rig and related multi-year drilling contract for $13.0~~$7.4 million. ~~A down payment of $1.3 million was made upon execution of the agreement and the remaining $11.7 million was paid upon closing on April 5, 2017.~~

The following table ~~below includes a summary of~~summarizes our cash flow information for the periods ~~indicated.~~indicated:


		Successor						Predecessor				Six Months Ended June 30,
(unaudited, in thousands)	(unaudited, in thousands)	Nine Months Ended September 30, 2017			Period from February 10, 2016 to September 30, 2016			Period from January 1, 2016 to February 10, 2016			(unaudited, in thousands)	2023			2022
Cash flows provided by (used in):
Cash flows (used in) provided by:											Cash flows (used in) provided by:
	Operating activities	$	(17,412	)	$	3,283		$	(21,365	)	Operating activities	$	(11,080	)	$	(39,705	)
	Investing activities		(14,606	)		(10,107	)		116		Investing activities		(2,637	)		195,364
	Financing activities		(1,072	)		(1,123	)		66,875		Financing activities		2,831			—

Changes in cash flows from operating activities are driven by changes in net ~~income~~loss during the relevant periods (see the discussion of changes in net ~~income~~loss above in “Results of Operations” ~~above) during the periods. Changes in cash~~of this Part I, Item 2).

Cash flows ~~used in~~from investing activities ~~are dependent upon our level of capital expenditures, which varies based on the timing of projects. Cash used for the acquisition of the~~ ~~Vantage 260~~ ~~totaled $13.0 million~~ in the ~~nine months ended September 30, 2017. In the Predecessor~~Comparable Period ~~from January 1, 2016 to February 10, 2016, we received~~include (i) net proceeds of ~~$73.9~~$200.0 million derived from the EDC Sale and (ii) $3.1 million derived from the sale of various assets.

Cash flows from financing activities in the Current Period include (i) net proceeds of ~~debt issuance costs of $2.3~~$188.4 million derived from the issuance of the ~~10% Second~~9.50% First Lien ~~Notes. Additionally, we made a $7.0~~Notes, as described in “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report, (ii) the redemption of the principal balance of the 9.25% First Lien Notes for $180.0 million as described in “Note 5. Debt” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report, and (iii) the $5.3 million payment ~~on our pre-petition credit agreement.~~of dividend equivalents as described in “Note 6. Shareholders’ Equity” in the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report.

The significant elements of ~~our post-petition debt~~the 9.50% First Lien Notes are described in “Note 5. Debt” of the “Notes to ~~our consolidated financial statements included elsewhere~~Unaudited Consolidated Financial Statements” in Part I, Item 1 of this ~~report.~~Quarterly Report. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2.

We enter into operating leases in the normal course of business for office space, housing, vehicles and specified operating equipment. Some of these leases contain options that would cause our future cash payments to change if we exercised those options.

Commitments and Contingencies

We are subject to litigation, claims and disputes in the ordinary course of business, some of which may not be covered by insurance. Information regarding our legal proceedings is set forth in “Note 8. Commitments and ~~Contingencies”~~Contingencies” of the “Notes to ~~our consolidated financial statements included elsewhere~~Unaudited Consolidated Financial Statements” in Part I, Item 1 of this ~~report.~~ Quarterly Report. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2.

There is an inherent risk in any litigation, claim or dispute and therefore no assurance can be given as to the outcome of any ~~claims.~~such litigation, claim or dispute. We do not believe the ultimate resolution of any existing litigation, claims or disputes will have a material adverse effect on our financial position, results of operations or cash flows.

Critical Accounting Policies and Accounting Estimates

The preparation of unaudited financial statements and related disclosures in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Our significant accounting policies are included in “Note 2. Basis of Presentation and Significant Accounting Policies” of the “Notes to Unaudited Consolidated Financial Statements” in Part I, Item 1 of this Quarterly Report. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our consolidated financial statements. While management believes current estimates are appropriate and reasonable, actual results could materially differ from those estimates. We

have ~~identified~~discussed the development, selection and disclosure of such policies ~~below as critical to our business operations~~ and ~~the understanding of our financial operations.~~

~~Fresh-start Accounting:~~ ~~Effective with our bankruptcy filing on December 3, 2015, we were subject to the requirements of ASC 852. All expenses, realized gains and losses and provisions for losses directly associated~~estimates with the ~~bankruptcy proceedings were classified as “reorganization items” in the consolidated statements of operations.~~ Certain pre-petition liabilities subject to Chapter 11 proceedings were considered LSTC on the Petition Date and just prior to our emergence from bankruptcy on the Effective Date. The LSTC classification distinguished such liabilities from the liabilities that were not expected to be compromised and liabilities incurred post-petition.

Upon emergence from bankruptcy, we adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values asaudit committee of the ~~Effective Date. The Effective Date fair values~~Board of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical consolidated balance sheets. The effects of the Reorganization Plan and the application of fresh-startDirectors.

Our critical accounting policies are ~~reflected in our consolidated balance sheet as of December 31, 2016 and the~~those related ~~adjustments thereto were recorded in our consolidated statement of operations as reorganization items for the period January 1, 2016~~ to ~~February 10, 2016.~~

~~Property and Equipment:~~ Our long-lived assets, primarily consisting of the values of our drilling rigs, are the most significant amount of our total assets. We make judgments with regard to the carrying value of these assets, including amounts capitalized, componentization, depreciation and amortization methods, salvage values and estimated useful lives. Drilling rigs are depreciated on a component basis over estimated useful lives on a straight-line basis as of the date placed in service. Other assets are depreciated upon placement in service over estimated useful lives on a straight-line basis.

~~We evaluate the realization of~~ property and equipment, ~~whenever events or changes in circumstances indicate that the carrying amount~~impairment of ~~an asset may not be recoverable. An impairment loss on our property~~long-lived assets and ~~equipment exists when estimated undiscounted cash flows expected to result from the use~~income taxes. For a discussion of the ~~asset~~critical accounting policies and ~~its eventual disposition are less than its carrying amount. Any impairment loss recognized would be computed as~~estimates that we use in the ~~excess of the asset’s carrying value over the estimated fair value. Estimates of future cash flows require us to make long-term forecasts~~preparation of our ~~future revenues~~consolidated financial statements, see “Item 7. Management's Discussion and ~~operating costs~~Analysis of Financial Condition and Results of Operations - Critical Accounting Estimates” in Part II of our Annual Report on Form 10-K for the year ended December 31, 2022, which was filed with ~~regard~~the SEC on March 31, 2023. During the Current Quarter, there were no material changes to the ~~assets subject to review. Our business, including the utilization rates and dayrates we receive for~~judgments, assumptions or policies upon which our drilling rigs, depends on the level of our customers’ expenditures for oil and natural gas exploration, development and production expenditures. Oil and natural gas prices and customers’ expectations of potential changes in these prices, the general outlook for worldwide economic growth, political and social stability in the major oil and natural gas producing basins of the world, availability of credit and changes in governmental laws and regulations, among many other factors, significantly affect our customers’ levels of expenditures. Sustained declines in or persistent depressed levels of oil and natural gas prices, worldwide rig counts and utilization, reduced access to credit markets, reduced or depressed sale prices of comparably equipped jackups and drillships and any other significant adverse economic news could require us to evaluate the realization of our drilling rigs. In connection with our adoption of fresh-startcritical accounting upon our emergence from bankruptcy on February 10, 2016, an adjustment of $2.0 billion was recorded to decrease the net book value of our drilling rigs to estimated fair value. As of September 30, 2017, no triggering event has occurred to indicate that the current carrying value of our drilling rigs may not be recoverable.estimates are based.

~~Revenue:~~ ~~Revenue is recognized as services are performed based on contracted dayrates and the number of operating days during the period.~~

In connection with a customer contract, we may receive lump-sum fees for the mobilization of equipment and personnel. Mobilization fees and costs incurred to mobilize a rig from one geographic market to another are deferred and recognized on a straight-line basis over the term of such contract, excluding any option periods. Costs incurred to mobilize a rig without a contract are expensed as incurred. Fees or lump-sum payments received for capital improvements to rigs are deferred and amortized to income over the term of the related drilling contract. The costs of such capital improvements are capitalized and depreciated over the useful lives of the assets. We had no deferred revenues under drilling contracts at September 30, 2017 or December 31, 2016.

~~Rig and Equipment Certifications:~~ We are required to obtain regulatory certifications to operate our drilling rigs and certain specified equipment and must maintain such certifications through periodic inspections and surveys. The costs associated with these certifications, including drydock costs, are deferred and amortized over the corresponding certification periods.

~~Income Taxes:~~ Income taxes have been provided based upon the tax laws and rates in effect in the countries in which operations are conducted and income is earned. Deferred income tax assets and liabilities are computed for differences between the financial statement basis and tax basis of assets and liabilities that will result in future taxable or deductible amounts and are based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce deferred income tax assets to the amount expected to be realized. We recognize interest and penalties related to income taxes as a component of income tax expense.

Recent Accounting ~~Standards:~~ Pronouncements: See “Note 2. Basis of Presentation and Significant Accounting ~~Policies”~~Policies” of the “Notes to ~~our consolidated financial statements included elsewhere~~Unaudited Consolidated Financial Statements” in Part I, Item 1 of this ~~report.~~Quarterly Report for further information. The information discussed therein is incorporated by reference in its entirety into this Part I, Item 2.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Our rigs operate in various international locations and thus are sometimes subject to foreign exchange risk. We may from time to time also be exposed to certain commodity price risk, equity price risk and risks related to other market driven rates or prices. We do not enter into derivatives or other financial instruments for trading or speculative purposes. The significant decline in worldwide exploration and production spending as a result of reduced oil prices ~~has~~since 2014, the continual spread and exacerbation of the COVID-19 pandemic, including as a result of its highly transmittable variants and sub-lineages, geopolitical instability caused by the Russo-Ukrainian War, the ongoing oil price and market share volatility, and rising inflationary pressures and potential recessionary conditions have each negatively impacted the offshore contract drilling business asat large (as discussed in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations.~~Operations”of this Quarterly Report).

Interest Rate Risk: As of ~~September~~June 30, ~~2017,~~2023, we had ~~approximately $140.5 million face amount of~~no variable rate debt outstanding under the 2016 Term Loan Facility. Under the 2016 Term Loan Facility, interest is payable on the unpaid principal amount of each term loan at LIBOR plus 6.5%, with a LIBOR floor of 0.5%. As of September 30, 2017, the 1-month LIBOR rate was 1.24% and the current interest rate on the 2016 Term Loan Facility is 7.74%. Increases in the LIBOR rate would impact the amount of interest that we are required to pay on these borrowings. For every 1% increase in LIBOR (above the LIBOR floor) we would be subject to an increase in interest expense of $1.4 million per annum based on September 30, 2017 outstanding principal amounts. We have not entered into any interest rate hedges or swaps with regard to the 2016 Term Loan Facility.outstanding.

Foreign Currency Exchange Rate ~~Risk.~~Risk: Our functional currency is the ~~U.S. Dollar,~~USD, which is consistent with the oil and gas industry. However, outside the ~~United States,~~U.S., a portion of our expenses are incurred in local currencies. Therefore, when the ~~U.S. Dollar~~USD weakens (strengthens) in relation to the currencies of the countries in which we operate, our expenses reported in ~~U.S. Dollars~~USD will increase (decrease). A substantial majority of our revenues are received in ~~U.S. dollars,~~USD, our functional currency; however, in certain countries in which we operate, local laws or contracts may require us to receive some portion (or the entirety) of the payment in the local currency. We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs

from our obligations in that foreign currency. In order to mitigate the effect of exchange rate risk, we attempt to limit foreign currency holdings to the extent they are needed to pay liabilities in the local currency. To further manage our exposure to fluctuations in currency exchange rates, foreign exchange derivative instruments, specifically foreign exchange forward contracts, or spot purchases, may be used. A foreign exchange forward contract obligates us to exchange predetermined amounts of specified foreign currencies at specified exchange rates on specified dates or to make an equivalent ~~U.S. dollar~~USD payment equal to the value of such exchange. We do not enter into derivative transactions for speculative purposes. As of ~~September~~June 30, ~~2017,~~2023, we did not have any open foreign exchange derivative contracts or material foreign currency exposure risk.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we voluntarily file or submit to the SEC is recorded, processed, summarized, and reported within the time periods required by our debt agreements.

WeDisclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit to the SEC is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, the Company has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of June 30, 2023. Based upon this evaluation, and due to the material weakness in the Company’s internal controls over financial reporting (as described below in Management’s Report on Internal Control over Financial Reporting), the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures were not effective.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed to

provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Moreover, projections of any evaluation of effectiveness to future periods are subject to the inherent risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management carried out an evaluation based on the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our ~~disclosure controls and procedures~~internal control over financial reporting as of the end of the period covered by this ~~report.~~Quarterly Report. Based on that evaluation, such officers have concluded that the design and operation of these ~~disclosure controls and procedures~~internal control over financial reporting were not effective as of ~~September~~June 30, ~~2017~~2023 (as described below).

As previously reported in our Annual Report on Form 10-K for the year ended December 31, 2022, management identified a material weakness in internal control over financial reporting related to ~~provide reasonable~~the prevention of unauthorized cash disbursements, which continues to exist as of June 30, 2023. Management has implemented new controls and continues its remediation efforts through designing and implementing additional effective controls and training of employees; however, there can be no assurance that information required to be disclosed on our reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) was (1) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure and (2) recorded, summarized and reported within the time periods specifiedadditional material weaknesses will not arise in the ~~SEC’s rules~~future and ~~forms.~~any failure to remediate the material weakness, or the development of new material weaknesses in our internal control over financial reporting, could result in material misstatements in our financial statements and cause us to fail to meet our reporting and financial obligations in the future.

~~There~~Changes in Internal Control over Financial Reporting

Except for the foregoing, there were no changes in our internal control over financial reporting ~~(as defined in Rule 13a-15(f) and 15d-15(f) of the Exchange Act)~~ during the ~~most recent fiscal~~ quarter ended June 30, 2023 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 regarding the Company’s legal proceedings is set forth in “Note 8. Commitments and Contingencies” ~~located in~~of the ~~Notes~~“Notes to Unaudited Consolidated Financial ~~Statements included~~Statements” in Part I, Item 1 of this Quarterly ~~Report on Form 10-Q and~~Report. The information discussed therein is incorporated ~~herein~~ by ~~reference.~~reference into this Part II, Item 1.

Item 5. Other Information

During the three-month period covered by this Quarterly Report, none of the Company’s directors or executive officers adopted or terminated any contract, instruction or written plan for the purchase or sale of Company securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any “non-Rule 10b5-1 trading arrangement” (as such term is defined in Item 408(a) of Regulation S-K).

Item 6. Exhibits

Incorporated by Reference
Exhibit
Number

Exhibit Description

Filed
Herewith

Form

File Number

Exhibit

Filing
Date
2.1

Joint Prepackaged Chapter 11 Plan of Offshore Group Investment Limited and its Affiliated Debtors, dated December 1, 2015, which is Exhibit A to the Disclosure Statement

T-3

022-29012

99.T3E.1

12/02/15
3.1A

Certificate of Incorporation of the Company

S-4

333-170841

3.3

11/24/10
3.1B

Third Amended and Restated Memorandum and Articles of Association of the Company

8-K

333-159299-15

3.01

08/05/16
4.1

Second Amended and Restated Credit Agreement by and between Offshore Group Investment Limited, certain subsidiaries thereof as Guarantors, the lenders from time to time party thereto as Lenders and Royal Bank of Canada as Administrative Agent and Collateral Agent, dated as of February 17, 2016

8-K

333-159299-15

4.1

02/17/16
4.2

Second Lien Indenture by and between Offshore Group Investment Limited, the guarantors from time to time party thereto (including certain of the Assignors, as defined therein) and U.S. Bank National Association, as trustee and noteholder collateral agent, dated as of February 10, 2016

8-K

333-159299-15

4.2

02/17/16
4.3

Third Lien Indenture by and between Offshore Group Investment Limited, the guarantors from time to time party thereto (including certain of the Assignors, as defined therein) and U.S. Bank National Association, as trustee and noteholder collateral agent, dated as of February 10, 2016

8-K

333-159299-15

4.3

02/17/16
4.4

Supplemental Indenture, dated as of June 8, 2016, among Vantage Drilling International (f/k/a Offshore Group Investment Limited), the guarantors party thereto, and U.S. Bank National Association, as trustee and noteholder collateral agent, to the Third Lien Indenture dated as of February 10, 2016

S-1

333-212081

4.4

06/16/16
4.5

Shareholders Agreement by and among Offshore Group Investment Limited and the Shareholders (as defined therein) dated as of February 10, 2016

8-K

333-159299-15

10.1

02/17/16
4.6

Registration Rights Agreement by and among Offshore Group Investment Limited and each of the Holders (as defined therein) party thereto dated as of February 10, 2016

8-K

333-159299-15

10.2

02/17/16
4.7

Amendment No. 1 to the Registration Rights Agreement dated as of May 9, 2016, by and among Vantage Drilling International (f/k/a Offshore Group Investment Limited) and each of the Holders party thereto

10-Q

333-159299-15

10.3

5/13/16

Incorporated by Reference

Exhibit

Number

Exhibit Description

Filed

Herewith

Form

File Number

Exhibit

Filing

Date

2.1

Joint Prepackaged Chapter 11 Plan of Offshore Group Investment Limited and its Affiliated Debtors, dated December 1, 2015, which is Exhibit A to the Disclosure Statement

T-3

022-29012

99.T3E.1

12/02/15

2.2

Share Purchase Agreement, dated December 6, 2021, by and between Vantage Holdings International and ADES Arabia Holding

10-K

333-159299-15

2.2

03/30/22

3.1A

Certificate of Incorporation of the Company

S-4

333-170841

3.3

11/24/10

3.1B

Fourth Amended and Restated Memorandum and Articles of Incorporation of the Company

8-K

333-159299-15

3.1

03/08/19

4.1

First Lien Indenture, dated as of November 30, 2018, by and between Vantage Drilling International, the subsidiary guarantors party thereto and U.S. Bank National Association, as trustee and first lien collateral agent

8-K

333-159299-15

4.1

12/04/18

4.8

Registration Rights Agreement among Vantage Drilling International, Vantage Drilling Company and the joint official liquidators of Vantage Drilling Company, dated as of April 26, 2017

10-K/A

333-212081

10.1

05/01/17
12.1

Statement re Computation of Earnings to Fixed Charges

X

31.1

Certification of Principal Executive Officer Pursuant to Section 302

X

31.2

Certification of Principal Financial and Accounting Officer Pursuant to Section 302

X

32.1**

Certification of Principal Executive Officer Pursuant to Section 906

32.2**

Certification of Principal Financial and Accounting Officer Pursuant to Section 906

101.INS

— XBRL Instance Document

X

101.SCH

— XBRL Schema Document

X

101.CAL

— XBRL Calculation Document

X

101.DEF

— XBRL Definition Linkbase Document

X

101.LAB

— XBRL Label Linkbase Document

X

101.PRE

— XBRL Presentation Linkbase Document

X

** These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.


4.2	First Supplemental Indenture by and between Vantage Drilling International, the subsidiary guarantors party thereto and U.S. Bank National Association, as trustee and first lien collateral agent, dated January 24, 2019	10-K	333-159299-15	4.4	03/10/20
4.3	Second Supplemental Indenture by and between Vantage Drilling International, the subsidiary guarantors party thereto and U.S. Bank National Association, as trustee and first lien collateral agent, dated February 13, 2019	10-K	333-159299-15	4.5	03/10/20
4.4	Shareholders Agreement dated as of February 10, 2016, by and among Offshore Group Investment Limited and the Shareholders (as defined therein)	8-K	333-159299-15	10.1	02/17/16
4.5	Amendment No. 1 to the Shareholders Agreement, dated as of February 10, 2016, by and among Offshore Group Investment Limited and the Shareholders (as defined therein)	8-K	333-159299-15	10.1	03/08/19
4.6	Registration Rights Agreement, dated as of February 10, 2016, by and among Offshore Group Investment Limited and each of the Holders (as defined therein) party thereto	8-K	333-159299-15	10.2	02/17/16
4.7	Amendment No. 1 to the Registration Rights Agreement, dated as of May 9, 2016, by and among Vantage Drilling International (f/k/a Offshore Group Investment Limited) and each of the Holders party thereto	10-Q	333-159299-15	10.3	5/13/16
4.8	Registration Rights Agreement among Vantage Drilling International, Vantage Drilling Company and the joint official liquidators of Vantage Drilling Company, dated as of April 26, 2017	10-K/A	333-212081	10.1	05/01/17
4.9	Indenture, dated as of March 1, 2023, among Vantage Drilling International, the guarantors party thereto, and U.S. Bank Trust Company, National Association, as trustee and first lien collateral agent	8-K	333-159299-15	4.1	03/07/23
10.1	Agreement, dated June 20, 2019, among Vantage Deepwater Company, Vantage Deepwater Drilling, Inc., Petroleo Brasileiro S.A., Petrobras America, Inc. and Petrobras Venezuela Investments & Services, BV.	8-K	333-159299-15	10.1	06/24/19
10.2	Second Amended and Restated Employment and Non-Competition Agreement between Offshore Group Investment Limited and Linda J. Ibrahim, dated February 10, 2016	10-Q	333-159299-15	10.2	08/12/21
10.3	Form of Third Amendment to Employment Agreement between Vantage Drilling International and each Executive (as defined therein)	10-Q	333-159299-15	10.3	08/12/22
10.4	Form of Support Service Agreement, dated May 27, 2022 by and between Vantage Driller III Co, Vantage Drilling International and Emerald Driller Company	10-Q	333-159299-15	10.4	08/12/22
10.5	Employment Agreement between Vantage Drilling International and Derek Massie, dated January 1, 2018	10-K/A	333-159299-15	10.16	04/28/23

~~SIGNATURES~~39

10.6

Fourth Amendment to Employment Agreement between Vantage Drilling International and Ihab Toma, dated March 1, 2023

10-Q

333-159299-15

10.6

05/12/2023

10.7

Fourth Amendment to Employment Agreement between Vantage Drilling International and Derek Massie, dated March 1, 2023

10-Q

333-159299-15

10.7

05/12/2023

31.1

Certification of Principal Executive Officer Pursuant to Section 302

31.2

Certification of Principal Financial and Accounting Officer Pursuant to Section 302

32.1**

Certification of Principal Executive Officer Pursuant to Section 906

32.2**

Certification of Principal Financial and Accounting Officer Pursuant to Section 906

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

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase

101.DEF

Inline XBRL Taxonomy Extension Definition Inline Linkbase

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase

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Cover Page Interactive Data File (the cover page XBRL tags are embedded in the Inline XBRL document)

** These exhibits are furnished herewith and shall not be deemed “filed” for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act.

SIGNATURES

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


	VANTAGE DRILLING INTERNATIONAL

Date: ~~November 7, 2017~~August 10, 2023	By:	/s/ ~~THOMAS J. CIMINO~~ RAFAEL BLATTNER
		~~Thomas J. Cimino~~Rafael Blattner
		Chief Financial Officer
		(Principal Financial ~~and Accounting~~ Officer)


		Page
SAFE HARBOR STATEMENT		3
PART I—FINANCIAL INFORMATION
Item 1	Financial Statements (unaudited)		~~Financial~~ ~~Statements~~	57
	Consolidated Balance ~~Sheet~~Sheets	57
	Consolidated Statement of Operations	68
	Consolidated Statement of Shareholders’ Equity	9
	Consolidated Statement of Cash Flows	710
	Notes to Unaudited Consolidated Financial Statements	811
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2128
Item 3	Quantitative and Qualitative Disclosures About Market Risk	2837
Item 4	Controls and Procedures	37
PART II—OTHER INFORMATION
Item 1	Legal Proceedings	38
Item 6	Exhibits	38
~~Item 4~~SIGNATURES			~~Controls and Procedures~~	29
~~PART II—OTHER INFORMATION~~
~~Item 1~~	~~Legal Proceedings~~	29
~~Item 6~~	~~Exhibits~~	30
~~SIGNATURES~~		3241

(in thousands)
Fiscal year:
Remaining 2017	$	1,591
2018		6,311
2019		1,643
Thereafter		-
Total	$	9,545

(in thousands)
Total cash consideration	$	13,000

Purchase price allocation:
Drilling contract value		12,640
Rig equipment to be sold (net of disposal costs)		2,050
Drillpipe assets		700
Severance liabilities assumed		(480	)
Net assets acquired		14,910

Bargain purchase gain	$	1,910