Valaris Ltd - Quarter Report: 2022 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2022


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

For the transition period from __________ to__________

Commission File Number 1-8097

Valaris Limited

(Exact name of registrant as specified in its charter)

Bermuda

98-1589854

(State or other jurisdiction of
incorporation or organization)

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

Clarendon House, 2 Church Street

Hamilton

Bermuda

HM 11

(Address of principal executive offices)

(Zip Code)

Registrant's telephone number, including area code: +44 (0) 20 7659 4660

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

Title of each class

Ticker Symbol(s)

Name of each exchange on which registered

Common Shares, $0.01 par value share

VAL

New York Stock Exchange

Warrants to purchase Common Shares

VAL WS

New York Stock Exchange

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

☒

Accelerated filer

☐

Non-Accelerated filer

☐

Smaller reporting company

☐

Emerging growth company

☐

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

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

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

As of April 28, 2022, there were 75,001,107 common shares of the registrant issued and outstanding.

VALARIS LIMITED

INDEX TO FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2022


PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



Condensed Consolidated Statements of Operations Three Months Ended March 31, 2022 (Successor) and 202 1 (Predecessor)			5



Condensed Consolidated Statements of Comprehensive Loss Three Months Ended March 31, 2022 (Successor) and 2021 (Predecessor)			6



Condensed Consolidated Balance Sheets March 31, 2022 and December 31, 202 1			7

Condensed Consolidated Statements of Cash Flows Three Months Ended March 31, 202 2 (Successor) and 20 21 (Predecess or)			8

Notes to Condensed Consolidated Financial Statements			9

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			29

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			48

ITEM 4. CONTROLS AND PROCEDURES			49

PART II OTHER INFORMATION			50

ITEM 1. LEGAL PROCEEDINGS			50

ITEM 1A. RISK FACTORS			50



ITEM 6. EXHIBITS			51

SIGNATURES			52

FORWARD-LOOKING STATEMENTS

Statements contained in this report that are not historical facts are 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 (the "Exchange Act"). Forward-looking statements include words or phrases such as "anticipate," "believe," "estimate," "expect," "intend," "likely," "plan," "project," "could," "may," "might," "should," "will" and similar words and specifically include statements regarding expected financial performance; expected utilization, day rates, revenues, operating expenses, cash flows, contract status, terms and duration, contract backlog, capital expenditures, insurance, financing and funding; the effect, impact, potential duration and other implications of the ongoing COVID-19 pandemic; impact of our emergence from bankruptcy; the offshore drilling market, including supply and demand, customer drilling programs, stacking of rigs, effects of new rigs on the market and effect of the volatility of commodity prices; expected work commitments, awards, contracts and letters of intent; the availability, delivery, mobilization, contract commencement or relocation or other movement of rigs and the timing thereof; future rig reactivations, enhancement, upgrade or repair and timing and cost thereof; the suitability of rigs for future contracts; performance of our joint venture with Saudi Arabian Oil Company ("Saudi Aramco"); expected divestitures of assets; general market, business and industry conditions, trends and outlook; general political conditions, including political tensions, conflicts and war (such as the ongoing conflict in Ukraine); future operations; the impact of increasing regulatory complexity; the outcome of tax disputes, assessments and settlements; expense management; and the likely outcome of litigation, legal proceedings, investigations or insurance or other claims or contract disputes and the timing thereof.

Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:

•delays in contract commencement dates or cancellation, suspension, renegotiation or termination (with or without cause, including those due to impacts of the COVID-19 pandemic) of drilling contracts or drilling programs as a result of general or industry-specific economic conditions, mechanical difficulties, performance, delays in the delivery of critical drilling equipment, failure of the customer to receive final investment decision (FID) for which the drilling rig was contracted or other reasons;

•changes in worldwide rig supply and demand, competition or technology, including as a result of delivery of newbuild drilling rigs or reactivation of stacked drilling rigs;

•requirements to make significant expenditures in connection with rig reactivations, customer drilling requirements and to comply with governing laws or regulations in the regions we operate;

•loss of a significant customer or customer contract, as well as customer consolidation and changes to customer strategy, including focusing on renewable energy projects;

•our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, rising wages, unionization, or otherwise, or to retain employees;

•governmental policies that could reduce demand for hydrocarbons, including mandating or incentivizing the conversion from internal combustion engine powered vehicles to electric-powered vehicles;

•consumer preferences for alternative fuels and electric-powered vehicles, as part of the global energy transition, may lead to reduced demand for our services;

•increased scrutiny from regulators, market and industry participants, stakeholders and others in regards to our Environmental, Social and Governance ("ESG") practices and reporting responsibilities;

•the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems, including our rig operating systems;

•potential additional asset impairments;

•the adequacy of sources of liquidity for us and our customers;

•the ongoing COVID-19 pandemic, the related public health measures implemented by governments worldwide, the duration and severity of the outbreak and its impact on global oil demand, the volatility in prices for oil and natural gas and the extent of disruptions to our operations;

•downtime or temporary shutdown of operations of our rigs as a result of an outbreak of COVID-19 on one or more of our rigs;

•disruptions to the operations and business, as a result of the spread of COVID-19, of our key customers, suppliers and other counterparties, including impacts affecting our supply chain and logistics;

•risks inherent to drilling rig reactivations, repair, modification or upgrades, unexpected delays in equipment delivery, engineering, design or commissioning issues following delivery, or changes in the commencement, completion or service dates;

•internal control risk due to significant employee reductions and changes in management;

•our ability to generate operational efficiencies from our shared services center and potential risks relating to the processing of transactions and recording of financial information;

•downtime and other risks associated with offshore rig operations, including rig or equipment failure, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to severe storms and hurricanes and the limited availability or high cost of insurance coverage for certain offshore perils, such as hurricanes in the Gulf of Mexico or associated removal of wreckage or debris;

•our customers cancelling or shortening the duration of our drilling contracts, cancelling future drilling programs and seeking pricing and other contract concessions from us;

•decreases in levels of drilling activity and capital expenditures by our customers, whether as a result of the global capital markets and liquidity, prices of oil and natural gas, climate change concerns or otherwise, which may cause us to idle, stack or retire additional rigs;

•governmental action, terrorism, cyber-attacks, piracy, military action and political and economic uncertainties, including civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East, North Africa, West Africa, Southeast Asia, Eastern Europe or other geographic areas, which may result in expropriation, nationalization, confiscation or deprivation or destruction of our assets; suspension and/or termination of contracts based on force majeure events or adverse environmental safety events; or volatility in prices of oil and natural gas;

•disputes over production levels among members of the Organization of Petroleum Exporting Countries and other oil and gas producing nations (“OPEC+”), which could result in increased volatility in prices for oil and natural gas that could affect the markets for our services;

•our ability to enter into, and the terms of, future drilling contracts, including contracts for newbuild rigs and acquired rigs, for rigs currently idled and for rigs whose contracts are expiring;

•any failure to execute definitive contracts following announcements of letters of intent, letters of award or other expected work commitments;

•the outcome of litigation, legal proceedings, investigations or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any renegotiation, nullification, cancellation or breach of contracts with customers or other parties;

•governmental regulatory, legislative and permitting requirements affecting drilling operations, including limitations on drilling locations (such as the Gulf of Mexico during hurricane season), limitations on new oil and gas leasing in U.S. federal lands and waters, and regulatory measures to limit or reduce greenhouse gas emissions;

•potential impacts on our business resulting from climate-change or greenhouse gas legislation or regulations, and the impact on our business from climate-change related physical changes or changes in weather patterns;

•new and future regulatory, legislative or permitting requirements, future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill abatement contingency plan capability requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts, operations or financial results;

•environmental or other liabilities, risks, damages or losses, whether related to storms, hurricanes or other weather-related events (including wreckage or debris removal), collisions, groundings, blowouts, fires, explosions, cyberattacks, terrorism or otherwise, for which insurance coverage and contractual indemnities may be insufficient, unenforceable or otherwise unavailable;

•tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;

•our ability to realize the expected benefits of our joint venture with Saudi Aramco, including our ability to fund any required capital contributions or to enforce any payment obligations of the joint venture pursuant to outstanding shareholder notes receivable;

•the impact of our emergence from bankruptcy on our business and relationships and comparability of our financial results, as well as the potentially dilutive impacts of warrants issued pursuant to the plan of reorganization;

•the costs, disruption and diversion of our management's attention associated with campaigns by activist securityholders;

•economic volatility and political, legal and tax uncertainties following the U.K.'s exit from the European Union; and

•adverse changes in foreign currency exchange rates, including their effect on the fair value measurement of any derivative instruments that we may enter into.

In addition to the numerous risks, uncertainties and assumptions described above, you should also carefully read and consider "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part I and "Item 1A. Risk Factors" in Part II of this report, and "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our annual report on Form 10-K for the year ended December 31, 2021, which is available on the U.S. Securities and Exchange Commission website at www.sec.gov. 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, except as required by law.

PART I - FINANCIAL INFORMATION

Item 1.Financial Statements

VALARIS LIMITED AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per share amounts)

(Unaudited)


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021

OPERATING REVENUES	$	318.4	$	307.1
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	331.3		253.6
Loss on impairment	—		756.5
Depreciation	22.5		122.1
General and administrative	18.8		24.3
Total operating expenses	372.6		1,156.5

EQUITY IN EARNINGS OF ARO	4.3		1.9
OPERATING LOSS	(49.9)		(847.5)
OTHER INCOME (EXPENSE)
Interest income	10.9		2.6
Interest expense, net (Unrecognized contractual interest expense for debt subject to compromise was $100.3 million for the three months ended March 31, 2021)	(11.5)		(1.3)
Reorganization items, net	(1.0)		(52.2)
Other, net	11.0		22.5
	9.4		(28.4)
LOSS BEFORE INCOME TAXES	(40.5)		(875.9)
PROVISION (BENEFIT) FOR INCOME TAXES
Current income tax expense (benefit)	(0.1)		30.8
Deferred income tax expense (benefit)	(0.6)		0.9
	(0.7)		31.7
NET LOSS	(39.8)		(907.6)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	1.2		(2.4)
NET LOSS ATTRIBUTABLE TO VALARIS	$	(38.6)	$	(910.0)
LOSS PER SHARE - BASIC AND DILUTED	$	(0.51)	$	(4.56)
WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic and Diluted	75.0		199.6

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

VALARIS LIMITED AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(In millions)

(Unaudited)


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021

NET LOSS	$	(39.8)	$	(907.6)
OTHER COMPREHENSIVE LOSS, NET

Net reclassification adjustment for amounts recognized in net loss as a component of net periodic benefit	—		0.1
Reclassification of net gains on derivative instruments from other comprehensive loss into net loss	—		(5.6)
Other	(0.3)		0.2
NET OTHER COMPREHENSIVE LOSS	(0.3)		(5.3)
COMPREHENSIVE LOSS	(40.1)		(912.9)
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	1.2		(2.4)
COMPREHENSIVE LOSS ATTRIBUTABLE TO VALARIS	$	(38.9)	$	(915.3)

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

VALARIS LIMITED AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except par value amounts)



	March 31, 2022		December 31, 2021
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	578.2	$	608.7
Restricted cash	30.0		35.9
Accounts receivable, net	439.3		444.2
Other current assets	125.7		117.8
Total current assets	1,173.2		1,206.6
PROPERTY AND EQUIPMENT, AT COST	1,018.8		957.0
Less accumulated depreciation	88.6		66.1
Property and equipment, net	930.2		890.9
LONG-TERM NOTES RECEIVABLE FROM ARO	256.8		249.1
INVESTMENT IN ARO	90.9		86.6
OTHER ASSETS	186.6		176.0
	$	2,637.7	$	2,609.2
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$	311.2	$	225.8
Accrued liabilities and other	212.1		196.2


Total current liabilities	523.3		422.0
LONG-TERM DEBT	545.5		545.3
OTHER LIABILITIES	544.8		581.1
Total liabilities	1,613.6		1,548.4

COMMITMENTS AND CONTINGENCIES
VALARIS SHAREHOLDERS' EQUITY


Common shares, $0.01 par value, 700 shares authorized, 75 shares issued as of March 31, 2022 and December 31, 2021	0.8		0.8
Preference shares, $0.01 par value, 150 shares authorized, no shares issued as of March 31, 2022 and December 31, 2021	—		—
Stock warrants	16.4		16.4
Additional paid-in capital	1,086.4		1,083.0

Retained deficit	(71.6)		(33.0)
Accumulated other comprehensive loss	(9.4)		(9.1)

Total Valaris shareholders' equity	1,022.6		1,058.1
NONCONTROLLING INTERESTS	1.5		2.7
Total equity	1,024.1		1,060.8
	$	2,637.7	$	2,609.2

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

VALARIS LIMITED AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021

OPERATING ACTIVITIES
Net loss	$	(39.8)	$	(907.6)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation expense	22.5		122.1
Accretion of discount on shareholders note	(7.7)		—
Equity in earnings of ARO	(4.3)		(1.9)
Net periodic pension and retiree medical income	(4.0)		(4.0)
Share-based compensation expense	3.4		3.8
Gain on asset disposals	(2.5)		(1.4)
Amortization, net	1.6		(4.6)
Deferred income tax expense (benefit)	(0.6)		0.9
Amortization of debt issuance cost	0.2		—
Loss on impairment	—		756.5




Other	—		5.8
Changes in operating assets and liabilities	32.5		20.9
Contributions to pension plans and other post-retirement benefits	(0.8)		(22.2)
Net cash provided by (used in) operating activities	0.5		(31.7)
INVESTING ACTIVITIES
Additions to property and equipment	(38.5)		(6.0)
Net proceeds from disposition of assets	1.3		3.7




Net cash used in investing activities	(37.2)		(2.3)








FINANCING ACTIVITIES	—		—

Effect of exchange rate changes on cash and cash equivalents and restricted cash	0.3		(0.1)
DECREASE IN CASH AND CASH EQUIVALENTS AND RESTRICTED CASH	(36.4)		(34.1)
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, BEGINNING OF PERIOD	644.6		325.8
CASH AND CASH EQUIVALENTS AND RESTRICTED CASH, END OF PERIOD	$	608.2	$	291.7

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

VALARIS LIMITED AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 -Unaudited Condensed Consolidated Financial Statements

We prepared the accompanying condensed consolidated financial statements of Valaris Limited and its subsidiaries ("Valaris" or "Successor") in accordance with accounting principles generally accepted in the United States of America ("GAAP"), pursuant to the rules and regulations of the Securities and Exchange Commission (the "SEC") included in the instructions to Form 10-Q and Article 10 of Regulation S-X. The financial information included in this report is unaudited but, in our opinion, includes all adjustments (consisting of normal recurring adjustments) that are necessary for a fair presentation of our financial position, results of operations and cash flows for the interim periods presented. The December 31, 2021 Condensed Consolidated Balance Sheet data was derived from our 2021 audited consolidated financial statements but does not include all disclosures required by GAAP. The preparation of our condensed consolidated financial statements requires us to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities, the related revenues and expenses and disclosures of gain and loss contingencies as of the date of the financial statements. Actual results could differ from those estimates.

Results of operations for the three months ended March 31, 2022 are not necessarily indicative of the results of operations that will be realized for the year ending December 31, 2022. We recommend these condensed consolidated financial statements be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2021.

Summary of Significant Accounting Policies

Please refer to "Note 1. Description of the Business and Summary of Significant Accounting Policies" of our Consolidated Financial Statements from our Form 10-K for the year ended December 31, 2021, filed with the SEC on February 22, 2022, for the discussion of our significant accounting policies. Certain previously reported amounts have been reclassified to conform to the current year presentation.

Emergence from Chapter 11 Bankruptcy and Fresh Start Accounting

As described in "Note 1. Description of the Business and Summary of Significant Accounting Policies", "Note. 2 Chapter 11 Proceedings" and "Note 3. Fresh Start Accounting" from our 2021 Form 10-K, we filed voluntary petitions for bankruptcy on August 19, 2020 (the “Petition Date”), and on April 30, 2021 (the "Effective Date") emerged from bankruptcy.

References to the financial position and results of operations of the "Successor" relate to the financial position and results of operations of Valaris Limited, together with its consolidated subsidiaries, after the Effective Date. References to the financial position and results of operations of the "Predecessor" refer to the financial position and results of operations of Valaris plc ("Legacy Valaris"), together with its consolidated subsidiaries, on and prior to the Effective Date. References to the “Company,” “we,” “us” or “our” in this Quarterly Report are to Valaris Limited, together with its consolidated subsidiaries, when referring to periods following the Effective Date, and to Legacy Valaris, together with its consolidated subsidiaries, when referring to periods prior to and including the Effective Date.

On the Effective Date, we qualified for and applied fresh start accounting. The application of fresh start accounting resulted in a new basis of accounting, and we became a new entity for financial reporting purposes. Accordingly, our financial statements and notes after the Effective Date are not comparable to our financial statements and notes on and prior to that date. The condensed consolidated financial statements and notes have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor. Historical financial statements on or before the Effective Date are not a reliable indicator of the Company's financial condition and results of operations for any period after the adoption of fresh start accounting.

New Accounting Pronouncements

Leases - In July 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2021-05, “Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments”, (“Update 2021-05”) which requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or rate as an operating lease if another classification (i.e. sales-type or direct financing) would trigger a day-one loss. Update 2021-05 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. We adopted this update January 1, 2022 using a prospective method, with no material impact to our condensed consolidated financial statements.

Accounting pronouncements to be adopted

Reference Rate Reform - In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting ("Update 2020-04"), which provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other transactions affected by reference rate reform if certain criteria are met. The amendments in Update 2020-04 apply only to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of reference rate reform. The expedients and exceptions provided by the amendments do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, for which an entity has elected certain optional expedients and that are retained through the end of the hedging relationship. The provisions in Update 2020-04 are effective upon issuance and can be applied prospectively through December 31, 2022. Our notes receivable with ARO, from which we generate interest income on a LIBOR-based rate, are impacted by the application of this standard. As the notes bear interest on the LIBOR rate determined at the end of the preceding year, the rate governing our interest income in 2022 has already been determined. We expect to be able to modify the terms of our notes receivable to a comparable interest rate before the applicable LIBOR rate is no longer available and as such, do not expect this standard to have a material impact to our condensed consolidated financial statements.

Business Combinations - In October 2021, the FASB issued ASU No. 2021-08, “Accounting for Contracts Assets and Contract Liabilities from Contracts with Customers” (“Update 2021-08”). ASU No. 2021-08 requires an entity (acquirer) to recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with Topic 606 and provides practical expedients for acquirers when recognizing and measuring acquired contract assets and contract liabilities from revenue contracts in a business combination. The amendments also apply to contract assets and contract liabilities from other contracts to which the provisions of Topic 606 apply, such as contract liabilities for the sale of nonfinancial assets within the scope of Subtopic 610-20, Other Income - Gains and Losses from the Derecognition of Nonfinancial Assets. The FASB issued the update to improve the accounting for acquired revenue contracts with customers in a business combination. Update 2021-08 is effective for fiscal years beginning after December 15, 2022, and interim periods within those fiscal years, with early adoption permitted. We will adopt Update 2021-08 in the period required and will apply it to any business combination completed subsequent to the adoption.

With the exception of the updated standards discussed above, there have been no accounting pronouncements issued and not yet effective that have significance, or potential significance, to our condensed consolidated financial statements.

Note 2 -Revenue from Contracts with Customers

Our drilling contracts with customers provide a drilling rig and drilling services on a day rate contract basis. Under day rate contracts, we provide an integrated service that includes the provision of a drilling rig and rig crews for which we receive a daily rate that may vary between the full rate and zero rate throughout the duration of the contractual term, depending on the operations of the rig.

We also may receive lump-sum fees or similar compensation for the mobilization, demobilization and capital upgrades of our rigs. Our customers bear substantially all of the costs of constructing the well and supporting drilling operations, as well as the economic risk relative to the success of the well.

Our drilling contracts contain a lease component and we have elected to apply the practical expedient provided under Accounting Standards Codification ("ASC") 842 to not separate the lease and non-lease components and apply the revenue recognition guidance in ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)." Our drilling service provided under each drilling contract is a single performance obligation satisfied over time and comprised of a series of distinct time increments, or service periods. Total revenue is determined for each individual drilling contract by estimating both fixed and variable consideration expected to be earned over the contract term. Fixed consideration generally relates to activities such as mobilization, demobilization and capital upgrades of our rigs that are not distinct performance obligations within the context of our contracts and is recognized on a straight-line basis over the contract term. Variable consideration generally relates to distinct service periods during the contract term and is recognized in the period when the services are performed.

The amount estimated for variable consideration is only recognized as revenue to the extent that it is probable that a significant reversal will not occur during the contract term. We have applied the optional exemption afforded in ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)", and have not disclosed the variable consideration related to our estimated future day rate revenues. The remaining duration of our drilling contracts based on those in place as of March 31, 2022 was between approximately 1 month and 3.5 years.

Day Rate Drilling Revenue

Our drilling contracts provide for payment on a day rate basis and include a rate schedule with higher rates for periods when the drilling rig is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The day rate invoiced to the customer is determined based on the varying rates applicable to specific activities performed on an hourly or other time increment basis. Day rate consideration is allocated to the distinct hourly or other time increment to which it relates within the contract term and is generally recognized consistent with the contractual rate invoiced for the services provided during the respective period. Invoices are typically issued to our customers on a monthly basis and payment terms on customer invoices are typically 30 days.

Certain of our contracts contain performance incentives whereby we may earn a bonus based on pre-established performance criteria. Such incentives are generally based on our performance over individual monthly time periods or individual wells. Consideration related to performance bonus is generally recognized in the specific time period to which the performance criteria was attributed.

We may receive termination fees if certain drilling contracts are terminated by the customer prior to the end of the contractual term. Such compensation is recognized as revenue when our performance obligation is satisfied, the termination fee can be reasonably measured and collection is probable.

Mobilization / Demobilization Revenue

In connection with certain contracts, we receive lump-sum fees or similar compensation for the mobilization of equipment and personnel prior to the commencement of drilling services or the demobilization of equipment and personnel upon contract completion. Fees received for the mobilization or demobilization of equipment and personnel are included in Operating revenues. The costs incurred in connection with the mobilization and demobilization of equipment and personnel are included in Contract drilling expense.

Mobilization fees received prior to commencement of drilling operations are recorded as a contract liability and amortized on a straight-line basis over the contract term. Demobilization fees expected to be received upon contract completion are estimated at contract inception and recognized on a straight-line basis over the contract term. In some cases, demobilization fees may be contingent upon the occurrence or non-occurrence of a future event. 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.

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. Fees received for requested capital upgrades and other contract preparation work are recorded as a contract liability and amortized on a straight-line basis over the contract term to Operating revenues. Costs incurred for capital upgrades are capitalized and depreciated over the useful life of the asset.

Contract Assets and Liabilities

Contract assets represent amounts recognized as revenue but for which the right to invoice the customer is dependent upon our future performance. Once the previously recognized revenue is invoiced, the corresponding contract asset, or a portion thereof, is transferred to accounts receivable.

Contract liabilities generally represent fees received for mobilization, capital upgrades or in the case of our 50/50 joint venture with Saudi Aramco, represent the difference between the amounts billed under the bareboat charter arrangements and lease revenues earned up to the respective period end. See “No te 3 – Equity Method Investment in ARO" for additional details regarding our balances with ARO.

Contract assets and liabilities are presented net on our Condensed Consolidated Balance Sheets on a contract-by-contract basis. Current contract assets and liabilities are included in Other current assets and Accrued liabilities and other, respectively, and noncurrent contract assets and liabilities are included in Other assets and Other liabilities, respectively, on our Condensed Consolidated Balance Sheets.

The following table summarizes our contract assets and contract liabilities (in millions):



	March 31, 2022		December 31, 2021
Current contract assets	$	3.6	$	0.3
Noncurrent contract assets	$	0.1	$	—
Current contract liabilities (deferred revenue)	$	56.3	$	45.8
Noncurrent contract liabilities (deferred revenue)	$	9.7	$	10.8

Changes in contract assets and liabilities during the period are as follows (in millions):


	Contract Assets		Contract Liabilities










Balance as of December 31, 2021	$	0.3	$	56.6
Revenue recognized in advance of right to bill customer	3.4		—
Increase due to cash received	—		22.3
Decrease due to amortization of deferred revenue that was included in the beginning contract liability balance	—		(12.1)
Decrease due to amortization of deferred revenue added during the period	—		(0.8)

Balance as of March 31, 2022	$	3.7	$	66.0

Deferred Contract Costs

Costs incurred for upfront rig mobilizations and certain contract preparations are attributable to our future performance obligation under each respective drilling contract. These costs are deferred and amortized on a straight-line basis over the contract term. Demobilization costs are recognized as incurred upon contract completion. Costs associated with the mobilization of equipment and personnel to more promising market areas without contracts are expensed as incurred. Deferred contract costs were included in Other current assets and Other assets on our Condensed Consolidated Balance Sheets and totaled $37.2 million and $31.4 million as of March 31, 2022 and December 31, 2021, respectively. For the Successor, during the three months ended March 31, 2022, amortization of such costs totaled $11.7 million. For the Predecessor, during the three months ended March 31, 2021, amortization of such costs totaled $5.8 million.

Deferred Certification Costs

We must obtain certifications from various regulatory bodies in order to operate our drilling rigs and must maintain such certifications through periodic inspections and surveys. The costs incurred in connection with maintaining such certifications, including inspections, tests, surveys and drydock, as well as remedial structural work and other compliance costs, are deferred and amortized on a straight-line basis over the corresponding certification periods. Deferred regulatory certification and compliance costs were included in Other current assets and Other assets on our Condensed Consolidated Balance Sheets and totaled $7.6 million and $3.3 million as of March 31, 2022 and December 31, 2021, respectively. For the Successor, during the three months ended March 31, 2022, amortization of such costs totaled $0.3 million. For the Predecessor, during the three months ended March 31, 2021, amortization of such costs totaled $2.6 million.

Future Amortization of Contract Liabilities and Deferred Costs

Our contract liabilities and deferred costs are amortized on a straight-line basis over the contract term or corresponding certification period to Operating revenues and Contract drilling expense, respectively, with the exception of the contract liabilities related to our bareboat charter arrangements with ARO which would not be contractually payable until the end of the lease term or termination, if sooner. See "Note 3 - Equity Method Investment in ARO" for additional information on ARO and related arrangements. The expected future amortization of our contract liabilities, or in the case of our contract liabilities related to our bareboat charter arrangements with ARO, the amount is reflected at the end of the lease term, and deferred costs recorded as of March 31, 2022 is set forth in the table below (in millions):


	Remaining 2022		2023		2024		2025 and Thereafter		Total
Amortization of contract liabilities	$	54.6	$	5.4	$	3.8	$	2.2	$	66.0
Amortization of deferred costs	$	26.6	$	15.4	$	2.8	$	—	$	44.8

Note 3 -Equity Method Investment in ARO

Background

ARO is a 50/50 unconsolidated joint venture between the Company and Saudi Aramco that owns and operates offshore drilling rigs in Saudi Arabia. As of March 31, 2022, ARO owns seven jackup rigs, has ordered two newbuild jackup rigs, and leases eight rigs from us through bareboat charter arrangements (the "Lease Agreements") whereby substantially all operating costs are incurred by ARO. At March 31, 2022, all of the leased rigs were operating under three-year drilling contracts, or related extensions, with Saudi Aramco. The seven rigs owned by ARO are currently operating under contracts with Saudi Aramco for an aggregate 15 years provided that the rigs meet the technical and operational requirements of Saudi Aramco.

ARO has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176.0 million. These newbuild rigs are expected to be delivered in the first or second quarter of 2023 and ARO is expected to place orders for two additional newbuild jackups in 2022. In connection with these plans, we have a potential obligation to fund ARO for newbuild jackup rigs. See "Note 1 1 - Contingencies" for additional information.

The joint venture partners agreed in the shareholders' agreement that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. The initial contracts provided by Saudi Aramco for each of the newbuild rigs will be for an eight-year term. The day rate for the initial contracts for each newbuild rig will be determined using a pricing mechanism that targets a six-year payback period for construction costs on an EBITDA basis. The initial eight-year contracts will be followed by a minimum of another eight years of term, re-priced in three-year intervals based on a market pricing mechanism.

Summarized Financial Information

The operating revenues of ARO presented below reflect revenues earned under drilling contracts with Saudi Aramco for the seven ARO-owned jackup rigs as well as the rigs leased from us.

Contract drilling expense is inclusive of the bareboat charter fees for the rigs leased from us. See additional discussion below regarding these related-party transactions.

Summarized financial information for ARO is as follows (in millions):


	Three Months Ended
	March 31, 2022		March 31, 2021
Revenues	$	111.3	$	122.7
Operating expenses
Contract drilling (exclusive of depreciation)	84.2		86.3
Depreciation	16.5		16.1
General and administrative	5.2		3.0
Operating income	5.4		17.3
Other expense, net	3.3		4.5
Provision for income taxes	0.7		4.5
Net income	$	1.4	$	8.3


	March 31, 2022		December 31, 2021
Cash and cash equivalents	$	240.2	$	270.8
Other current assets	179.5		135.0
Non-current assets	775.8		775.8
Total assets	$	1,195.5	$	1,181.6

Current liabilities	$	92.9	$	79.9
Non-current liabilities	957.9		956.7
Total liabilities	$	1,050.8	$	1,036.6

Equity in Earnings of ARO

We account for our interest in ARO using the equity method of accounting and only recognize our portion of ARO's net income, adjusted for basis differences as discussed below, which is included in Equity in earnings (losses) of ARO in our Condensed Consolidated Statements of Operations. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO. Judgments regarding our level of influence over ARO included considering key factors such as each partner's ownership interest, representation on the board of managers of ARO and ability to direct activities that most significantly impact ARO's economic performance, including the ability to influence policy-making decisions. Our investment in ARO would be assessed for impairment if there are changes in facts and circumstances that indicate a loss in value may have occurred. If a loss were deemed to have occurred and this loss was determined to be other than temporary, the carrying value of our investment would be written down to fair value and an impairment recorded.

We have an equity method investment in ARO that was recorded at its estimated fair value at both the Effective Date and the date of our combination with our joint venture partner. We computed the difference between the fair value of ARO's net assets and the carrying value of those net assets in ARO's U.S. GAAP financial statements ("basis differences") on each of these dates. These basis differences primarily related to ARO's long-lived assets and the recognition of intangible assets associated with certain of ARO's drilling contracts that were determined to have favorable terms as of the measurement dates.

Basis differences are amortized over the remaining life of the assets or liabilities to which they relate and are recognized as an adjustment to the Equity in earnings (losses) of ARO in our Condensed Consolidated Statements of Operations. The amortization of those basis differences are combined with our 50% interest in ARO's net income. A reconciliation of those components is presented below (in millions):


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
50% interest in ARO net income	$	0.7	$	4.1
Amortization of basis differences	3.6		(2.2)
Equity in earnings of ARO	$	4.3	$	1.9

Related-Party Transactions

Revenues recognized by us related to the Lease Agreements are as follows (in millions):


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
Lease revenue	$	14.2	$	16.6

(1) Revenues presented above are included in our Other segment in our segment disclosures. See "Note 12 - Segment Information" for additional information.

Amounts receivable from ARO totaled $11.6 million and $12.1 million as of March 31, 2022 and December 31, 2021, respectively, and are included in Accounts receivable, net, on our Condensed Consolidated Balance Sheets.

We had $13.9 million and $37.1 million of Contract liabilities and Accounts payable, respectively, related to the Lease Agreements as of March 31, 2022. As of December 31, 2021, we had $10.8 million and $38.3 million of Contract liabilities and Accounts payable, respectively, related to the Lease Agreements. The per day bareboat charter amount in the Lease Agreements is subject to adjustment based on actual performance of the respective rig and as such Contract liabilities related to the Lease Agreements are subject to adjustment during the lease term. Upon completion of the lease term, such amount becomes a payable to or a receivable from ARO.

During 2017 and 2018, the Company contributed cash to ARO in exchange for ten-year shareholder notes receivable based on a one-year LIBOR rate, set as of the end of the year prior to the year applicable, plus two percent. The notes receivable were adjusted to fair value as of the Effective Date by recording a discount to the principal amount of $442.7 million. The discount is being amortized using the effective interest method to interest income over the remaining terms of the notes. As of March 31, 2022 and December 31, 2021, the carrying amount of the long-term notes receivable from ARO was $256.8 million and $249.1 million, respectively. The agreement entered into by us and Saudi Aramco to create ARO prohibits the sale or transfer of the shareholder note to a third party, except in certain limited circumstances. During the three months ended March 31, 2022 (Successor), interest income totaled $10.5 million of which $7.7 million pertains to non-cash amortization of the discount on the shareholder notes. During the three months ended March 31, 2021 (Predecessor), interest income totaled $2.6 million. As of March 31, 2022, our interest receivable from ARO was $2.9 million, which is included in Accounts receivable, net, on our Condensed Consolidated Balance Sheet. There was no interest receivable from ARO as of December 31, 2021.

Maximum Exposure to Loss

The following table summarizes the total assets and liabilities as reflected in our Condensed Consolidated Balance Sheets as well as our maximum exposure to loss related to ARO (in millions). Our maximum exposure to loss is limited to (1) our equity investment in ARO; (2) the carrying amount of our shareholder notes receivable; and (3) other receivables and contract assets from ARO, partially offset by contract liabilities as well as payables to ARO.



	March 31, 2022		December 31, 2021
Total assets	$	362.9	$	348.1
Less: total liabilities	51.0		49.1
Maximum exposure to loss	$	311.9	$	299.0

Note 4 -Fair Value Measurements

The carrying values and estimated fair values of our long-term debt instrument were as follows (in millions):



	March 31, 2022				December 31, 2021
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
Senior secured first lien notes due 2028	$	545.5	$	569.1	$	545.3	$	575.7

The estimated fair value of the Senior Secured First Lien Notes (the "First Lien Notes") was determined using quoted market prices, which are level 1 inputs.

As of March 31, 2022, the estimated fair value of our notes receivable from ARO was $274.9 million and was estimated by using an income approach to value the forecasted cash flows attributed to the notes receivable using a discount rate based on comparable yield with a country-specific risk premium.

The estimated fair values of our cash and cash equivalents, restricted cash, accounts receivable and trade payables approximated their carrying values as of March 31, 2022 and December 31, 2021.

Note 5 -Property and Equipment

Property and equipment consisted of the following (in millions):



	March 31, 2022		December 31, 2021
Drilling rigs and equipment	$	938.7	$	886.9
Work-in-progress	42.6		35.6
Other	37.5		34.5
	$	1,018.8	$	957.0

Assets held-for-use

On a quarterly basis, we evaluate the carrying value of our property and equipment to identify events or changes in circumstances ("triggering events") that indicate the carrying value may not be recoverable. For rigs whose carrying values are determined not to be recoverable, we record an impairment for the difference between their fair values and carrying values.

Predecessor

During the first quarter of 2021, as a result of challenging market conditions for certain of our floaters, we revised our near-term operating assumptions which resulted in a triggering event for purposes of evaluating impairment. We determined that the estimated undiscounted cash flows were not sufficient to recover the carrying values for certain rigs and concluded they were impaired as of March 31, 2021.

Based on the asset impairment analysis performed as of March 31, 2021, we recorded a pre-tax, non-cash loss on impairment in the first quarter of 2021 for certain floaters totaling $756.5 million, inclusive of $5.6 million of gains reclassified from accumulated other comprehensive income into loss on impairment associated with related cash flow hedges. We measured the fair value of these assets to be $26.0 million at the time of impairment by applying either an income approach, using projected discounted cash flows or estimated sales price. These valuations were based on unobservable inputs that require significant judgments for which there is limited information, including, in the case of an income approach, assumptions regarding future day rates, utilization, operating costs and capital requirements. In instances where we applied an income approach, forecasted day rates and utilization took into account then current market conditions and our anticipated business outlook.

Assets held-for-sale and Assets sold

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations that are not part of our long-term strategic plan or that no longer meet our standards for economic returns. We continue to focus on our fleet management strategy in light of the composition of our rig fleet. While taking into account certain restrictions on the sales of assets under our Indenture dated April 30, 2021 that governs our First Lien Notes (the “Indenture”), as part of our strategy, we may act opportunistically from time to time to monetize assets to enhance stakeholder value and improve our liquidity profile, in addition to reducing holding costs by selling or disposing of lower-specification or non-core rigs. To this end, we continually assess our rig portfolio and actively work with rig brokers to market certain rigs. See “Note 8 – Debt" for additional information on restrictions on the sales of assets.

On a quarterly basis, we assess whether any long-lived assets meets the criteria established for held-for-sale classification on our balance sheet. Assets classified as held-for-sale are recorded at fair value, less costs to sell. We measure the fair value of our assets held-for-sale by applying a market approach based on unobservable third-party estimated prices that would be received in exchange for the assets in an orderly transaction between market participants or a negotiated sales price. We reassess the fair value of our held-for-sale assets on a quarterly basis and adjust the carrying value, as necessary. No assets were considered as held-for-sale on our Condensed Consolidated Balance Sheets as of March 31, 2022, or December 31, 2021.

VALARIS 67 was sold during the three months ended March 31, 2022 (Successor) resulting in a pre-tax gain of $2.0 million, which is included in Other, net on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2022 (Successor).

During the three months ended March 31, 2021 (Predecessor), our Australia office building was sold, resulting in an immaterial pre-tax gain, which is included in Other, net on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2021 (Predecessor).

Subsequent to March 31, 2022, we reached an agreement for the sale of VALARIS 113 and VALARIS 114, resulting in an expected pre-tax gain on sale to be recorded in the second quarter of 2022 of approximately $120 million.

Note 6 -Pension and Other Post-retirement Benefits

We have defined-benefit pension plans and retiree medical plans that provide post-retirement health and life insurance benefits.

The components of net periodic pension and retiree medical cost were as follows (in millions):


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021

Interest cost	5.5		5.0
Expected return on plan assets	(9.5)		(9.1)
Amortization of net loss	—		0.1
Net periodic pension and retiree medical income (1)	$	(4.0)	$	(4.0)

(1)Included in Other, net, in our Condensed Consolidated Statements of Operations.

In March 2021, the American Rescue Plan Act of 2021 ("ARPA-21") was passed. ARPA-21 provides funding relief for U.S. qualified pension plans which should lower pension contribution requirements over the next few years. As a result, we currently expect to contribute or directly pay approximately $4.2 million to our pension and other post-retirement benefits plans for the remainder of 2022. These amounts represent the minimum contributions we are required to make under relevant statutes. We do not expect to make contributions in excess of the minimum required amounts.

Note 7 -Earnings Per Share

Basic income (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted-average number of common shares outstanding during the period. Basic and diluted earnings per share ("EPS") for the Predecessor was calculated in accordance with the two-class method. Predecessor net loss attributable to Legacy Valaris used in our computations of basic and diluted EPS was adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares outstanding used in our computation of diluted EPS is calculated using the treasury stock method and for the Successor includes the effect of all potentially dilutive warrants, restricted stock unit awards and performance stock unit awards and for the Predecessor includes the effect of all potentially dilutive stock options and excludes non-vested shares. For the Successor, during the three months ended March 31, 2022, our potentially dilutive instruments were not included in the computation of diluted EPS as the effect of including these shares in the calculation would have been anti-dilutive. Additionally, for the Predecessor, during the three months ended March 31, 2021, our potentially dilutive instruments were not included in the computation of diluted EPS as the effect of including these shares in the calculation would have been anti-dilutive.

For the Successor, during the three months ended March 31, 2022, loss from continuing operations attributable to our shares was $38.6 million.

For the Predecessor, during the three months ended March 31, 2021, loss from continuing operations attributable to Legacy Valaris and Legacy Valaris shares was $910.0 million. No amounts were allocated to non-vested share awards in this period given that losses are not allocated to non-vested share awards.

Anti-dilutive share awards totaling 1.0 million and 300,000 for the three months ended March 31, 2022 (Successor) and the three months ended March 31, 2021 (Predecessor), respectively, were excluded from the computation of diluted EPS. Due to the net loss position, potentially dilutive share awards are excluded from the computation of diluted EPS.

We have 5,470,972 warrants outstanding (the "Warrants") as of March 31, 2022 to purchase common shares of Valaris Limited which are exercisable for one Common Share per Warrant at an initial exercise price of $131.88 per Warrant, in each case as may be adjusted from time to time pursuant to the applicable warrant agreement. The Warrants are exercisable for a period of seven years and will expire on April 29, 2028. The exercise of these Warrants into Common Shares would have a dilutive effect to the holdings of Valaris Limited's existing shareholders. These warrants are anti-dilutive for the three months ended March 31, 2022.

Note 8 -Debt

First Lien Notes Indenture

On the Effective Date, in accordance with the plan of reorganization and Backstop Commitment Agreement, dated August 18, 2020 (as amended, the "BCA"), the Company consummated the rights offering of the First Lien Notes and associated shares in an aggregate principal amount of $550.0 million.

The First Lien Notes were issued pursuant to the Indenture, among Valaris Limited, certain direct and indirect subsidiaries of Valaris Limited as guarantors, and Wilmington Savings Fund Society, FSB, as collateral agent and trustee (in such capacities, the “Collateral Agent”).

The First Lien Notes are guaranteed, jointly and severally, on a senior basis, by certain of the direct and indirect subsidiaries of the Company. The First Lien Notes and such guarantees are secured by first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by the Company or any guarantor and a first-priority perfected lien on substantially all assets of the Company and each guarantor of the First Lien Notes, in each case subject to certain exceptions and limitations. The following is a brief description of the material provisions of the Indenture and the First Lien Notes.

The First Lien Notes are scheduled to mature on April 30, 2028. Interest on the First Lien Notes accrues, at our option, at a rate of: (i) 8.25% per annum, payable in cash; (ii) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind; or (iii) 12% per annum, with the entirety of such interest to be paid in kind. Interest is due semi-annually in arrears on May 1 and November 1 of each year and shall be computed on the basis of a 360-day year of twelve 30-day months.

At any time prior to April 30, 2023, the Company may redeem up to 35% of the aggregate principal amount of the First Lien Notes at a redemption price of 104% up to the net cash proceeds received by the Company from equity offerings provided that at least 65% of the aggregate principal amount of the First Lien Notes remains outstanding and provided that the redemption occurs within 120 days after such equity offering of the Company. At any time prior to April 30, 2023, the Company may redeem the First Lien Notes at a redemption price of 104% plus a “make-whole” premium. On or after April 30, 2023, the Company may redeem all or part of the First Lien Notes at fixed redemption prices (expressed as percentages of the principal amount), plus accrued and unpaid interest, if any, to, but excluding, the redemption date. The Company may also redeem the First Lien Notes, in whole or in part, at any time and from time to time on or after April 30, 2026 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest, if any, to, but excluding, the applicable redemption date. Notwithstanding the foregoing, if a Change of Control (as defined in the Indenture, with certain exclusions as provided therein) occurs, the Company will be required to make an offer to repurchase all or any part of each note holder’s notes at a purchase price equal to 101% of the aggregate principal amount of First Lien Notes repurchased, plus accrued and unpaid interest to, but excluding, the applicable date.

The Indenture contains covenants that limit, among other things, the Company’s ability and the ability of the guarantors and other restricted subsidiaries, to: (i) incur, assume or guarantee additional indebtedness; (ii) pay dividends or distributions on equity interests or redeem or repurchase equity interests; (iii) make investments; (iv) repay or redeem junior debt; (v) transfer or sell assets; (vi) enter into sale and lease back transactions; (vii) create, incur or assume liens; and (viii) enter into transactions with certain affiliates. These covenants are subject to a number of important limitations and exceptions.

The Indenture also provides for certain customary events of default, including, among other things, nonpayment of principal or interest, breach of covenants, failure to pay final judgments in excess of a specified threshold, failure of a guarantee to remain in effect, failure of a collateral document to create an effective security interest in collateral, with a fair market value in excess of a specified threshold, bankruptcy and insolvency events, cross payment default and cross acceleration, which could permit the principal, premium, if any, interest and other monetary obligations on all the then outstanding First Lien Notes to be declared due and payable immediately.

The Company incurred $5.2 million in issuance costs in association with the First Lien Notes that are being amortized into interest expense over the expected life of the notes using the effective interest method.

Note 9 -Shareholders' Equity

Activity in our various shareholders' equity accounts for the three months ended March 31, 2022 (Successor) and the three months ended March 31, 2021 (Predecessor) were as follows (in millions, except per share amounts):


	Shares	Par Value		Additional Paid-in Capital		Warrants		Retained Earnings (Deficit)		AOCI		Non-controlling Interest
BALANCE, December 31, 2021 (Successor)	75.0	$	0.8	$	1,083.0	$	16.4	$	(33.0)	$	(9.1)	$	2.7
Net loss	—	—		—		—		(38.6)		—		(1.2)

Share-based compensation cost	—	—		3.4		—		—		—		—
Net other comprehensive loss	—	—		—		—		—		(0.3)		—
BALANCE, March 31, 2022 (Successor)	75.0	$	0.8	$	1,086.4	$	16.4	$	(71.6)	$	(9.4)	$	1.5


	Shares	Par Value		Additional Paid-in Capital		Retained Earnings (Deficit)		AOCI		Treasury Shares		Non-controlling Interest
BALANCE, December 31, 2020 (Predecessor)	206.1	$	82.6	$	8,639.9	$	(4,183.8)	$	(87.9)	$	(76.2)	$	(4.3)
Net loss	—	—		—		(910.0)		—		—		2.4
Shares issued under share-based compensation plans, net	—	—		(0.2)		—		—		0.2		—

Net changes in pension and other postretirement benefits	—	—		—		—		0.1		—		—
Share-based compensation cost	—	—		3.8		—		—		—		—
Net other comprehensive loss	—	—		—		—		(5.4)		—		—
BALANCE, March 31, 2021 (Predecessor)	206.1	$	82.6	$	8,643.5	$	(5,093.8)	$	(93.2)	$	(76.0)	$	(1.9)

Note 10 -Income Taxes

Valaris Limited is domiciled and resident in Bermuda. Our subsidiaries conduct operations and earn income in numerous countries and are subject to the laws of taxing jurisdictions within those countries. The income of our non-Bermuda subsidiaries is not subject to Bermuda taxation as there is not an income tax regime in Bermuda. Legacy Valaris was domiciled and resident in the U.K. The income of our non-U.K. subsidiaries was generally not subject to U.K. taxation.

Income tax rates and taxation systems in the jurisdictions in which our subsidiaries conduct operations vary and our subsidiaries are frequently subjected to minimum taxation regimes. In some jurisdictions, tax liabilities are based on gross revenues, statutory deemed profits or other factors, rather than on net income, and our subsidiaries are frequently unable to realize tax benefits when they operate at a loss. Accordingly, during periods of declining profitability, our income tax expense may not decline proportionally with income, which could result in higher effective income tax rates. Furthermore, we will continue to incur income tax expense in periods in which we operate at a loss.

Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. As a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in profitability levels and changes in tax laws, our annual effective income tax rate may vary substantially from one reporting period to another.

Historically, we calculated our provision for income taxes during interim reporting periods by applying the estimated annual effective tax rate for the full fiscal year to pre-tax income or loss, excluding discrete items, for the reporting period. We determined that since small changes in estimated pre-tax income or loss would result in significant changes in the estimated annual effective tax rate, the historical method would not provide a reliable estimate of income taxes for the three months ended March 31, 2022 (Successor) and three months ended March 31, 2021 (Predecessor). We used a discrete effective tax rate method to calculate income taxes for the three months ended March 31, 2022 (Successor) and March 31, 2021 (Predecessor). We will continue to evaluate income tax estimates under the historical method in subsequent quarters and employ a discrete effective tax rate method if warranted.

Discrete income tax benefit for the three months ended March 31, 2022 (Successor) was $14.5 million and was primarily attributable to changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years. Discrete income tax expense for the three months ended March 31, 2021 (Predecessor) was $20.3 million and was primarily attributable to changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years. Excluding the aforementioned discrete tax items, income tax expense for the three months ended March 31, 2022 (Successor) and the three months ended March 31, 2021 (Predecessor) was $13.8 million and $11.4 million, respectively.

Note 11 -Contingencies

Indonesian Well-Control Event

In July 2019, a well being drilled offshore Indonesia by one of our jackup rigs experienced a well-control event requiring the cessation of drilling activities. In February 2020, the rig resumed operations. Indonesian authorities initiated an investigation into the event and have contacted the customer, us and other parties involved in drilling the well for additional information. We cooperated with the Indonesian authorities. We cannot predict the scope or ultimate outcome of this investigation. If the Indonesian authorities determine that we violated local laws in connection with this matter, we could be subject to penalties including environmental or other liabilities, which may have a material adverse impact on us.

ARO Newbuild Funding Obligations

In connection with our 50/50 unconsolidated joint venture, we have a potential obligation to fund ARO for newbuild jackup rigs. ARO has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. The joint venture partners intend for the newbuild jackup rigs to be financed out of available cash from ARO's operations and/or funds available from third-party debt financing. ARO paid a 25% down payment from cash on hand for each of the two newbuilds ordered in January 2020 and is actively exploring financing options for remaining payments due upon delivery. In the event ARO has insufficient cash from operations or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, as delivered, on a proportionate basis.

Letters of Credit

In the ordinary course of business with customers and others, we have entered into letters of credit to guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Letters of credit outstanding as of March 31, 2022 (Successor) totaled $33.6 million and are issued under facilities provided by various banks and other financial institutions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of March 31, 2022 (Successor), we had collateral deposits in the amount of $27.1 million with respect to these agreements.

Other Matters

In addition to the foregoing, we are named defendants or parties in certain other lawsuits, claims or proceedings incidental to our business and are involved from time to time as parties to governmental investigations or proceedings, including matters related to taxation, arising in the ordinary course of business. Although the outcome of such lawsuits or other proceedings cannot be predicted with certainty and the amount of any liability that could arise with respect to such lawsuits or other proceedings cannot be predicted accurately, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows.

Note 12 -Segment Information

Our business consists of four operating segments: (1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups, (3) ARO and (4) Other, which consists of management services on rigs owned by third-parties and the activities associated with our arrangements with ARO under the Lease Agreements. Floaters, Jackups and ARO are also reportable segments.

Upon emergence, we ceased allocation of our onshore support costs included within Contract drilling expenses to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in “Reconciling Items”. We have adjusted the historical period to conform with current period presentation. Further, General and administrative expense and Depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items." We measure segment assets as Property and equipment, net.

The full operating results included below for ARO are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See "Note 3 - Equity Method Investment in ARO" for additional information on ARO and related arrangements.

Segment information for the three months ended March 31, 2022 (Successor) and March 31, 2021 (Predecessor), respectively, are presented below (in millions).

Three Months Ended March 31, 2022 (Successor)


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	99.7	$	180.7	$	111.3	$	38.0	$	(111.3)	$	318.4
Operating expenses
Contract drilling (exclusive of depreciation)	147.6		139.2		84.2		15.5		(55.2)		331.3

Depreciation	12.2		9.1		16.5		0.9		(16.2)		22.5
General and administrative	—		—		5.2		—		13.6		18.8
Equity in earnings of ARO	—		—		—		—		4.3		4.3
Operating income (loss)	$	(60.1)	$	32.4	$	5.4	$	21.6	$	(49.2)	$	(49.9)
Property and equipment, net	$	457.6	$	387.1	$	730.9	$	51.7	$	(697.1)	$	930.2

Three Months Ended March 31, 2021 (Predecessor)


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	97.3	$	172.6	$	122.7	$	37.2	$	(122.7)	$	307.1
Operating expenses
Contract drilling (exclusive of depreciation)	85.1		121.3		86.3		15.3		(54.4)		253.6
Loss on impairment	756.5		—		—		—		—		756.5
Depreciation	56.2		52.4		16.1		11.3		(13.9)		122.1
General and administrative	—		—		3.0		—		21.3		24.3

Equity in earnings of ARO	—		—		—		—		1.9		1.9
Operating income (loss)	$	(800.5)	$	(1.1)	$	17.3	$	10.6	$	(73.8)	$	(847.5)
Property and equipment, net	$	5,685.4	$	3,778.9	$	729.2	$	566.3	$	(675.9)	$	10,083.9

Information about Geographic Areas

As of March 31, 2022, the geographic distribution of our and ARO's drilling rigs was as follows:


	Floaters	Jackups	Other	Total Valaris	ARO
North & South America	6	6	—	12	—
Europe & the Mediterranean	6	12	—	18	—
Middle East & Africa	2	7	8	17	7
Asia & Pacific Rim	2	6	—	8	—


Total	16	31	8	55	7

We provide management services in the U.S. Gulf of Mexico on two rigs owned by a third party not included in the table above.

We are a party to contracts whereby we have the option to take delivery of two recently constructed drillships that are not included in the table above.

ARO has ordered two newbuild jackups which are under construction in the Middle East that are not included in the table above.

Note 13 -Supplemental Financial Information

Condensed Consolidated Balance Sheet Information

Accounts receivable, net, consisted of the following (in millions):



	March 31, 2022		December 31, 2021
Trade	$	288.2	$	296.8
Income tax receivable	150.9		151.1
Other	16.5		12.7
	455.6		460.6
Allowance for doubtful accounts	(16.3)		(16.4)
	$	439.3	$	444.2

Other current assets consisted of the following (in millions):



	March 31, 2022		December 31, 2021
Prepaid taxes	$	42.8	$	44.4
Deferred costs	31.8		26.9
Prepaid expenses	21.4		23.1

Other	29.7		23.4
	$	125.7	$	117.8

Other assets consisted of the following (in millions):



	March 31, 2022		December 31, 2021
Tax receivables	$	65.6	$	64.8
Deferred tax assets	60.8		59.7
Right-of-use assets	22.1		20.5


Other	38.1		31.0
	$	186.6	$	176.0

Accrued liabilities and other consisted of the following (in millions):



	March 31, 2022		December 31, 2021
Personnel costs	$	58.2	$	64.6
Deferred revenue	56.3		45.8
Income and other taxes payable	48.6		45.7

Accrued interest	18.9		7.6
Lease liabilities	9.7		10.0

Other	20.4		22.5
	$	212.1	$	196.2

Other liabilities consisted of the following (in millions):



	March 31, 2022		December 31, 2021
Unrecognized tax benefits (inclusive of interest and penalties)	$	285.2	$	320.2
Pension and other post-retirement benefits	199.2		204.0







Other	60.4		56.9
	$	544.8	$	581.1

Accumulated other comprehensive income (loss) consisted of the following (in millions):



	March 31, 2022		December 31, 2021
Pension and other post-retirement benefits	$	(9.1)	$	(9.1)
Currency translation adjustment	(0.3)		—


	$	(9.4)	$	(9.1)

Condensed Consolidated Statements of Operations Information

Other, net, consisted of the following (in millions):


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
Net foreign currency exchange gains	$	4.7	$	16.6
Net periodic pension income, excluding service cost	4.0		4.0

Net gain on sale of property	2.5		1.4
Other income (expense)	(0.2)		0.5
	$	11.0	$	22.5

Condensed Consolidated Statement of Cash Flows Information

Our restricted cash of $30.0 million and $35.9 million at March 31, 2022 and December 31, 2021, respectively, consists primarily of $27.1 million and $31.1 million of collateral on letters of credit for each respective period. See "Note 11 - Contingencies" for more information regarding our letters of credit.

Concentration of Risk

We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents and, at times, investments. We mitigate our credit risk relating to receivables from customers, which consist primarily of major international, government-owned and independent oil and gas companies, by performing ongoing credit evaluations. We also maintain reserves for potential credit losses, which generally have been within our expectations. We mitigate our credit risk relating to cash and investments by focusing on diversification and quality of instruments.

Consolidated revenues with customers that individually contributed 10% or more of revenue were as follows:


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
BP plc ("BP")(1)	16	%	15	%
Shell plc ("Shell")(2)	11	%	9	%
Eni S.p.A ("Eni")(3)	10	%	7	%
Other	63	%	69	%
	100	%	100	%

(1)During the three months ended March 31, 2022 (Successor), 43% of the revenues provided by BP were attributable to our Floaters segment, 13% of the revenues were attributable to our Jackups segment and the remaining were attributable to our managed rigs.

During the three months ended March 31, 2021 (Predecessor), 43% of the revenues provided by BP were attributable to our Floaters segment, 15% of the revenues were attributable to our Jackups segment and the remaining were attributable to our managed rigs.

(2) During the three months ended March 31, 2022 (Successor), 67% of the revenues provided by Shell were attributable to our Floaters segment and 33% of the revenues were attributable to our Jackups segment.

During the three months ended March 31, 2021 (Predecessor), 62% of the revenues provided by Shell were attributable to our Floaters segment and 38% of the revenues were attributable to our Jackups segment.

(3) During the three months ended March 31, 2022 (Successor), 58% of the revenues provided by Eni were attributable to our Jackups segment and 42% of the revenues were attributable to our Floaters segment.

During the three months ended March 31, 2021 (Predecessor), 69% of the revenues provided by Eni were attributable to our Floaters segment and 31% of the revenues were attributable to our Jackups segment.

For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned. Consolidated revenues for locations that individually had 10% or more of revenue are as follows (in millions):


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
United Kingdom(1)	$	65.6	$	56.1
U.S. Gulf of Mexico(2)	50.6		56.8
Saudi Arabia(3)	38.1		41.6
Norway(1)	24.3		54.0
Mexico(4)	22.1		38.2


Other	117.7		60.4
	$	318.4	$	307.1

(1)During the three months ended March 31, 2022 (Successor) and 2021 (Predecessor), revenues earned in the United Kingdom and Norway were attributable to our Jackups segment.

(2)During the three months ended March 31, 2022 (Successor), 41% and 13% of the revenues earned in U.S. Gulf of Mexico were attributable to our Floaters segment and Jackups segment respectively. The remaining revenues were attributable to our managed rigs.

During the three months ended March 31, 2021 (Predecessor), 65% of the revenues earned in U.S. Gulf of Mexico were attributable to our Floaters segment and the remaining revenues were primarily attributable to our managed rigs.

(3)During the three months ended March 31, 2022 (Successor), 62% of the revenues earned in Saudi Arabia were attributable to our Jackups segment. The remaining revenues were attributable to our Other segment and relates primarily to our rigs leased to ARO.

During the three months ended March 31, 2021 (Predecessor), 57% of the revenues earned in Saudi Arabia were attributable to our Jackups segment. The remaining revenues were attributable to our Other segment and relates primarily to our rigs leased to ARO.

(4)During the three months ended March 31, 2022 (Successor), 93% of the revenues earned in Mexico were attributable to our Jackups segment and the remaining revenues were attributable to our Floaters segment.

During the three months ended March 31, 2021 (Predecessor), 56% of the revenues earned in Mexico were attributable to our Floaters segment and the remaining revenues were attributable to our Jackups segment.

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

Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the accompanying unaudited condensed consolidated financial statements and related notes thereto included in "Item 1. Financial Statements" and with our annual report on Form 10-K for the year ended December 31, 2021. The following discussion and analysis contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth under “Risk Factors” in Item 1A of our annual report and elsewhere in this quarterly report. See “Forward-Looking Statements.”

EXECUTIVE SUMMARY

Our Business

We are a leading provider of offshore contract drilling services to the international oil and gas industry. We currently own an offshore drilling rig fleet of 53 rigs, with drilling operations in almost every major offshore market across six continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 37 jackup rigs and a 50% equity interest in ARO, our 50/50 unconsolidated joint venture with Saudi Aramco, which owns an additional seven rigs. Additionally, we have options to purchase two additional recently constructed drillships on or before December 31, 2023. We own the world's largest fleet, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.

Emergence from Chapter 11 Bankruptcy and Fresh Start Accounting

On August 19, 2020 (the "Petition Date"), Valaris plc (“Legacy Valaris”) and certain of its direct and indirect subsidiaries (collectively, the “Debtors”) filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court for the Southern District of Texas (the "Chapter 11 Cases"). In connection with the Chapter 11 Cases and the plan of reorganization, on and prior to April 30, 2021 ("Effective Date"), Legacy Valaris effectuated certain restructuring transactions, pursuant to which Valaris Limited ("Valaris") was formed and, through a series of transactions, Legacy Valaris transferred to a subsidiary of Valaris substantially all of the subsidiaries, and other assets, of Legacy Valaris.

On the Effective Date, we successfully completed our financial restructuring and together with the Debtors emerged from the Chapter 11 Cases. On the Effective Date, Legacy Valaris Class A ordinary shares were cancelled and the Valaris common shares (the "Common Shares") were issued. Also, former holders of Legacy Valaris' equity were issued warrants (the "Warrants") to purchase Common Shares.

References to the financial position and results of operations of the "Successor" relate to the financial position and results of operations of Valaris, together with its consolidated subsidiaries, after the Effective Date. References to the financial position and results of operations of the "Predecessor" refer to the financial position and results of operations of Legacy Valaris, together with its consolidated subsidiaries, on and prior to the Effective Date. References to the “Company,” “we,” “us” or “our” in this Quarterly Report are to Valaris, together with its consolidated subsidiaries, when referring to periods following the Effective Date, and to Legacy Valaris, together with its consolidated subsidiaries, when referring to periods prior to and including the Effective Date.

Our Industry

Operating results in the offshore contract drilling industry are highly cyclical and are directly related to the demand for and the available supply of drilling rigs. Low demand and excess supply can independently affect day rates and utilization of drilling rigs. Therefore, adverse changes in either of these factors can result in adverse changes in our industry. While the cost of moving a rig may cause the balance of supply and demand to vary somewhat between regions, significant variations between most regions are generally of a short-term nature due to rig mobility.

In 2020, the combined effects of the global COVID-19 pandemic, the significant decline in the demand for oil and the substantial surplus in the supply of oil resulted in significantly reduced demand and day rates for offshore drilling provided by the Company and increased uncertainty regarding long-term market conditions. These events had a significant adverse impact on our expected liquidity position and financial runway and led to the filing of the Chapter 11 Cases.

In 2021, Brent crude oil prices increased from approximately $50 per barrel at the beginning of the year to nearly $80 per barrel by the end of the year. Increased oil prices were due to, among other factors, rebounding demand for hydrocarbons, a measured approach to production increases by OPEC+ members and a focus on cash flow and returns by major exploration and production companies. The constructive oil price environment led to an improvement in contracting and tendering activity in 2021 as compared to 2020.

In 2022, Brent crude oil prices have increased dramatically and become increasingly volatile, in large part due to Russia’s invasion of Ukraine, which led to sanctions being placed on Russia, including its ability to export crude oil and other petroleum products. The anticipated impact on supply drove Brent crude oil prices above $130 per barrel in early March. As of March 31, 2022, the spot Brent crude price had declined to approximately $108 per barrel. However, volatility remains high.

While the spot market for crude oil is indicative of current market conditions, for larger offshore projects, our customers are more focused on medium-term and long-term commodity prices when making investment decisions. These forward prices have also reached levels that are constructive for offshore projects.

The full impact that the pandemic and the volatility of oil prices will have on our results of operations, financial condition, liquidity and cash flows is uncertain due to numerous factors, including the duration and severity of the pandemic, the continued effectiveness of the ongoing vaccine rollout, the general resumption of global economic activity along with the injection of substantial government monetary and fiscal stimulus, inflation and the sustainability of the improvements in oil prices and demand in the face of market volatility. To date, the COVID-19 pandemic has resulted in limited operational downtime. While we have seen improvement in recent months, our rigs have had to shut down operations while crews are tested, and incremental sanitation protocols are implemented and while crew changes have been restricted as replacement crews are quarantined. We continue to incur additional personnel, housing and logistics costs in order to mitigate the potential impacts of COVID-19 to our operations. In limited instances, we have been reimbursed for these costs by our customers. Our operations and business may be subject to further economic disruptions as a result of the spread of COVID-19 among our workforce, the extension or imposition of further public health measures affecting supply chain and logistics, and the impact of the pandemic on key customers, suppliers, and other counterparties. There can be no assurance that these, or other issues caused by the COVID-19 pandemic, will not materially affect our ability to operate our rigs in the future.

More recently, we have begun to feel the impacts of global inflation, both in increased personnel costs as well as in the prices of goods and services required to operate our rigs. While we are currently unable to estimate the ultimate impact of rising prices, we do expect that our costs will continue to rise in the near term and will impact our profitability. While certain of our long-term contracts contain provisions for escalating costs, we cannot predict with certainty our ability to successfully claim recoveries of higher costs from our customers under these contractual stipulations.

The near-term outlook for the offshore drilling industry has improved since the beginning of 2021, as evidenced by improving global utilization and increasing day rates for offshore drilling rigs, most notably for drillships. However, heightened geopolitical tensions have increased volatility, inflation is increasing costs of operations and the global recovery from the COVID-19 pandemic remains uncertain. As a result, there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for, and profitability of, offshore drilling services.

Backlog

Our backlog was $2.5 billion and $2.4 billion as of May 2, 2022 and February 21, 2022, respectively, as recent contract awards and contract extensions were offset by revenues realized. Our backlog excludes ARO's backlog but includes backlog of $140.1 million and $134.3 million, respectively, from our rigs leased to ARO at the contractual rates. Contract rates with ARO are subject to adjustment resulting from the shareholder agreement governing the joint venture. See "Note 3 - Equity Method Investment in ARO" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information.

Approximately $428 million of backlog as of May 2, 2022 is attributable to our contract awarded to VALARIS DS-11 for an eight-well contract for a deepwater project in the U.S. Gulf of Mexico expected to commence in mid-2024. In February 2022, the customer decided not to sanction and therefore withdrew from the project associated with this contract. In March 2022, the contract was novated to another customer, which was a partner on the project. No material changes to the contract resulted from the novation, including with respect to the termination provisions in the event the project does not receive final investment decision (FID).

ARO backlog was $1.5 billion as of both May 2, 2022 and February 21, 2022, inclusive of backlog on both ARO owned rigs and rigs leased from us, as a recent contract award was offset by revenues realized. As a 50/50 unconsolidated joint venture, when ARO realizes revenue from its backlog, 50% of the earnings thereon would be reflected in our results in the equity in earnings of ARO in our Condensed Consolidated Statement of Operations. The earnings from ARO backlog with respect to rigs leased from us will be net of, among other things, payments to us under bareboat charters for those rigs.

BUSINESS ENVIRONMENT

Floaters

Starting in 2021, the more constructive oil price environment has led to an improvement in contracting and tendering activity. Benign floater rig years awarded in 2021 were more than double the amount awarded in 2020. This increase in activity is particularly evident for drillships with several multi-year contracts awarded and a meaningful improvement in day rates for this class of assets. As a result, we are currently in the process of reactivating three drillships and recently completed the reactivation of one semisubmersible, each in preparation for long-term contracts expected to commence in the second quarter of 2022.

While we expect the improved oil price environment to continue to support deepwater investments, heightened geopolitical tensions, including Russia's invasion of Ukraine, have increased volatility, and the global recovery from the COVID-19 pandemic remains uncertain. As a result, there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.

Our backlog for our floater segment was $1.7 billion (including approximately $428 million for the VALARIS DS-11 discussed above) as of both May 2, 2022 and February 21, 2022, as recent contract awards and contract extensions were offset by revenues realized.

Utilization for our floaters was 25% during the first quarter of 2022 compared to 28% in the fourth quarter of 2021 due to special periodic survey work required in the first quarter of 2022. Average day rates were approximately $197,000 during the first quarter of 2022 compared to approximately $189,000 in the fourth quarter of 2021. The increase in average day rate is the result of integrated services provided to certain customers in the first quarter of 2022 as well as lower rates resulting from weather conditions in the fourth quarter of 2021.

Globally, there are 19 newbuild drillships and benign environment semisubmersible rigs reported to be under construction, of which five are scheduled to be delivered before the end of 2022. Most newbuild floaters are uncontracted. Several newbuild deliveries have been delayed into future years, and more uncontracted newbuilds may be delayed or cancelled.

Drilling contractors have retired 136 benign environment floaters since the beginning of 2014. Eight benign environment floaters older than 20 years of age are currently idle, four additional benign environment floaters older than 20 years have contracts that will expire within six months without follow-on work, and there are a further 12 benign environment floaters that have been stacked for more than three years. Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify some of these rigs may prove cost prohibitive. Drilling contractors may elect to scrap or cold stack a portion of these rigs.

A sustained constructive oil price environment and improvement in demand for offshore projects are necessary to maintain the improving floater utilization and day rate trajectory.

Jackups

While the demand for jackups declined during 2020 as a result of the combined impacts of the COVID-19 pandemic as well as the oil supply and demand imbalance, the decline was not as significant as it was for floaters. As such, with recent improvements in oil prices, we are experiencing incremental contracting activity, but at a pace slower than that for floaters. With much of the anticipated demand for jackups coming from infill drilling of existing fields, we expect that this demand will remain more stable in light of changes in oil prices.

Our backlog for our jackup segment was $515.2 million and $643.0 million as of May 2, 2022 and February 21, 2022, respectively. The decrease in our backlog was due to revenues realized partially offset by the addition of backlog from new contract awards and contract extensions.

Utilization for our jackups was 63% during the first quarter of 2022 compared to 55% in the fourth quarter of 2021 as new jackup contracts commenced or had a full quarter of operations in the first quarter of 2022. Average day rates were approximately $89,000 during the first quarter of 2022 compared to approximately $90,000 in the fourth quarter of 2021. While operating days increased across the jackup fleet, certain higher specification jackups rolled off contract resulting in an overall decline in the average day rate.

Globally, there are 28 newbuild jackup rigs reported to be under construction, of which 18 are scheduled to be delivered before the end of 2022. Most newbuild jackups are uncontracted. Over the past year, some jackup orders have been cancelled, and many newbuild jackups have been delayed. We expect that scheduled jackup deliveries will continue to be delayed until more rigs are contracted.

Drilling contractors have retired 162 jackups since the beginning of the downturn. 61 jackups older than 30 years are currently idle, 24 jackups that are 30 years or older have contracts expiring within the next six months without follow-on work, and there are a further 15 jackups that have been stacked for more than three years. Expenditures required to re-certify some of these rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold stack these rigs.

A sustained constructive oil price environment and improvement in demand for offshore projects are necessary to maintain the improving jackup utilization and day rate trajectory, which has been at a slower pace than that of floaters.

Divestitures

Our business strategy has been to focus on ultra-deepwater floater and premium jackup operations and de-emphasize other assets and operations that are not part of our long-term strategic plan or that no longer meet our standards for economic returns. We continue to focus on our fleet management strategy in light of the composition of our rig fleet. While taking into account certain restrictions on the sales of assets under our Indenture dated April 30, 2021 that governs our First Lien Notes (the “Indenture”), as part of our strategy, we may act opportunistically from time to time to monetize assets to enhance stakeholder value and improve our liquidity profile, in addition to reducing holding costs by selling or disposing of lower-specification or non-core rigs. To this end, we continually assess our rig portfolio and actively work with rig brokers to market certain rigs. See “Note 8 – Debt" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information on restrictions on the sales of assets.

RESULTS OF OPERATIONS

Management believes the comparison of the most recently completed quarter to the immediately preceding quarter provides more relevant information needed to understand and analyze the business. As such, as permitted under applicable SEC rules, we have elected to discuss any material changes in our results of operations by including a comparison of our most recently completed fiscal quarter ended March 31, 2022 (the "current quarter") (Successor) to the immediate preceding fiscal quarter ended December 31, 2021 (Successor) (the "preceding quarter"). We also continue to discuss any material changes in our results of operations for the current quarter compared to the corresponding period of the preceding fiscal year (Predecessor) (the "prior year quarter"), as required under the applicable SEC rules.

The following table summarizes our Condensed Consolidated Results of Operations for the three months ended March 31, 2022 (Successor), three months ended December 31, 2021 (Successor) and three months ended March 21, 2021 (Predecessor) (in millions):


	Successor				Predecessor
	Three Months Ended March 31, 2022		Three Months Ended December 31, 2021			Three Months Ended March 31, 2021
Revenues	$	318.4	$	305.5		$	307.1
Operating expenses
Contract drilling (exclusive of depreciation)	331.3		285.5			253.6
Loss on impairment	—		—			756.5
Depreciation	22.5		25.1			122.1
General and administrative	18.8		18.3			24.3
Total operating expenses	372.6		328.9			1,156.5

Equity in earnings (losses) of ARO	4.3		(1.3)			1.9
Operating loss	(49.9)		(24.7)			(847.5)
Other income (expense), net	9.4		21.4			(28.4)
Provision (benefit) for income taxes	(0.7)		(31.0)			31.7
Net income (loss)	(39.8)		27.7			(907.6)
Net (income) loss attributable to noncontrolling interests	1.2		—			(2.4)
Net income (loss) attributable to Valaris	$	(38.6)	$	27.7		$	(910.0)

Overview

Revenue increased $12.9 million, or 4%, for the current quarter as compared to the preceding quarter, primarily due to $8.1 million from higher average day rates from certain rigs and $4.7 million from higher customer reimbursable revenues. This increase was partially offset by $3.7 million from fewer operating days from certain rigs.

Revenues increased $11.3 million, or 4%, for the current quarter as compared to the prior year quarter, primarily due to $18.3 million from increased operating days for certain rigs and $11.8 million from higher customer reimbursable revenue. This increase was partially offset by $13.6 million from lower average day rates and $2.4 million due to lower revenues earned under the Lease Agreements resulting from the retirement of two rigs at the end of 2021 that were leased to ARO for much of the year.

Contract drilling expense increased $45.8 million, or 16%, for the current quarter as compared to the preceding quarter, primarily due to a $24.3 million increase in reactivation costs compared to the preceding quarter, an $8.3 million increase in personnel costs and a $6.5 million increase in reimbursable expenses.

Contract drilling expense increased $77.7 million, or 31%, for the current quarter as compared to the prior year quarter, primarily due to a $50.3 million increase in reactivation costs, a $13.8 million increase in reimbursable expenses, a $12.1 million increase in personnel costs and a $6.8 million increase in mobilization costs. These increases were partially offset by $5.8 million of lower costs on idle rigs.

During the prior year quarter, we recorded non-cash losses on impairment totaling $756.5 million, with respect to certain assets in our fleet. See "Note 5 - Property and Equipment" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information.

Depreciation expense decreased $99.6 million, or 82%, for the current quarter as compared to the prior year quarter, primarily due to the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.

General and administrative expenses decreased by $5.5 million, or 23%, for the current quarter as compared to the prior year quarter, primarily due to a change in incentive compensation structure following the Effective Date.

Other income, net, decreased $12.0 million for the current quarter as compared to the preceding quarter, primarily due to the decrease in gains on the sale of assets of $18.5 million partially offset by a $3.9 million decrease in reorganization costs incurred directly related to the Chapter 11 Cases.

Other income, net, increased $37.8 million for the current quarter as compared to the prior year quarter, primarily due to a $51.2 million reduction in reorganization costs incurred directly related to the Chapter 11 Cases and an $8.3 million increase to interest income primarily due to the amortization of the discount on the note receivable from ARO. This increase is partially offset by an $11.9 million decrease in foreign currency gains as well as an increase in interest expense of $10.2 million. The higher interest expense is related to our First Lien Notes in the first quarter of 2022 whereas in the prior year quarter we had discontinued accruing interest on our outstanding predecessor debt after the Petition Date.

Rig Counts, Utilization and Average Day Rates

The following table summarizes our and ARO's offshore drilling rigs as of March 31, 2022 and December 31, 2021 (Successor) and March 31, 2021 (Predecessor):


	March 31, 2022	December 31, 2021	March 31, 2021
Floaters	16	16	16
Jackups(1)	31	33	36
Other(2)	8	7	9

Total Valaris	55	56	61

ARO(3)	7	7	7

(1)During the second, third and fourth quarters of 2021, we sold VALARIS 101, VALARIS 100 and VALARIS 142, respectively. During the first quarter of 2022, we sold VALARIS 67 and leased VALARIS 140 to ARO.

(2)This represents the jackup rigs leased to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All rigs leased to ARO are under three-year contracts with Saudi Aramco. During the fourth quarter of 2021, we sold VALARIS 22 and VALARIS 37, which were previously leased to ARO. During the first quarter of 2022, VALARIS 140 was leased to ARO.

(3)This represents the seven jackup rigs owned by ARO which are operating under long-term contracts with Saudi Aramco.

We provide management services in the U.S. Gulf of Mexico on two rigs owned by a third-party not included in the table above.

We are a party to contracts whereby we have the option to take delivery of two recently constructed drillships that are not included in the table above.

Additionally, ARO has ordered two jackups which are under construction in the Middle East that are not included in the table above. These newbuild rigs are expected to be delivered in the first or second quarter of 2023.

The following table summarizes our and ARO's rig utilization and average day rates by reportable segment:


	Three Months Ended March 31, 2022			Three Months Ended December 31, 2021			Three Months Ended March 31, 2021
Rig Utilization(1)
Floaters	25		%	28		%	29		%
Jackups	63		%	55		%	50		%
Other (2)	100		%	100		%	100		%
Total Valaris	57		%	54		%	54		%
ARO	91		%	84		%	90		%
Average Day Rates(3)
Floaters	$	197,394		$	188,523		$	198,485
Jackups	88,641			90,053			95,043
Other (2)	39,227			32,538			31,647
Total Valaris	$	89,609		$	89,325		$	88,637
ARO	$	95,867		$	97,251		$	93,199

(1)Rig utilization is derived by dividing the number of days under contract by the number of days in the period. Days under contract equals the total number of days that rigs have earned and recognized day rate revenue, including days associated with early contract terminations, compensated downtime and mobilizations and excluding suspension periods. When revenue is deferred and amortized over a future period, for example, when we receive fees while mobilizing to commence a new contract or while being upgraded in a shipyard, the related days are excluded from days under contract.

For newly-constructed or acquired rigs, the number of days in the period begins upon commencement of drilling operations for rigs with a contract or when the rig becomes available for drilling operations for rigs without a contract.

(2)Includes our two management services contracts and our rigs leased to ARO under bareboat charter contracts.

(3)Average day rates are derived by dividing contract drilling revenues, adjusted to exclude certain types of non-recurring reimbursable revenues, lump-sum revenues, revenues earned during suspension periods and revenues attributable to amortization of drilling contract intangibles, by the aggregate number of contract days, adjusted to exclude contract days associated with certain suspension periods, mobilizations and demobilizations.

Operating Income by Segment

Upon emergence, we ceased allocation of our onshore support costs included within contract drilling expenses to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in "Reconciling Items." We have adjusted the historical period to conform with current period presentation. Further, General and administrative expense and Depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items."

The full operating results included below for ARO are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See "Note 3 - Equity Method Investment in ARO" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information.

Segment information for the current quarter, the preceding quarter and prior year quarter was as follows (in millions):

Three Months Ended March 31, 2022 (Successor)


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	99.7	$	180.7	$	111.3	$	38.0	$	(111.3)	$	318.4
Operating expenses
Contract drilling (exclusive of depreciation)	147.6		139.2		84.2		15.5		(55.2)		331.3

Depreciation	12.2		9.1		16.5		0.9		(16.2)		22.5
General and administrative	—		—		5.2		—		13.6		18.8

Equity in earnings of ARO	—		—		—		—		4.3		4.3
Operating income (loss)	$	(60.1)	$	32.4	$	5.4	$	21.6	$	(49.2)	$	(49.9)

Three Months Ended December 31, 2021 (Successor)


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	100.5	$	172.3	$	105.4	$	32.7	$	(105.4)	$	305.5
Operating expenses
Contract drilling (exclusive of depreciation)	113.8		128.0		88.9		15.4		(60.6)		285.5

Depreciation	11.7		12.1		17.7		1.1		(17.5)		25.1
General and administrative	—		—		5.1		—		13.2		18.3

Equity in losses of ARO	—		—		—		—		(1.3)		(1.3)
Operating income (loss)	$	(25.0)	$	32.2	$	(6.3)	$	16.2	$	(41.8)	$	(24.7)

Three Months Ended March 31, 2021 (Predecessor)


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	97.3	$	172.6	$	122.7	$	37.2	$	(122.7)	$	307.1
Operating expenses
Contract drilling (exclusive of depreciation)	85.1		121.3		86.3		15.3		(54.4)		253.6
Loss on impairment	756.5		—		—		—		—		756.5
Depreciation	56.2		52.4		16.1		11.3		(13.9)		122.1
General and administrative	—		—		3.0		—		21.3		24.3

Equity in earnings of ARO	—		—		—		—		1.9		1.9
Operating income (loss)	$	(800.5)	$	(1.1)	$	17.3	$	10.6	$	(73.8)	$	(847.5)

Floaters

Floater revenue decreased $0.8 million, or 1%, for the current quarter as compared to the preceding quarter, primarily due to $9.3 million from a decline in operating days partially offset by $5.5 million from an increase in customer reimbursable revenue and $2.1 million from higher average day rates.

Floater revenue increased $2.4 million, or 2%, for the current quarter as compared to the prior year quarter, primarily due to $9.1 million from increased customer reimbursable revenue, partially offset by a decrease in certain deferred revenue amortization as well as slightly lower average day rates and fewer operating days.

Floater contract drilling expense increased $33.8 million, or 30%, for the current quarter as compared to the preceding quarter, primarily due to an increase in rig reactivation costs of $26.9 million and higher personnel costs of $5.4 million.

Floater contract drilling expense increased $62.5 million, or 73%, for the current quarter as compared to the prior year quarter, primarily due to an increase of $55.1 million in reactivation costs, a $7.7 million increase in reimbursable costs and a $3.9 million increase in personnel costs, partially offset by $10.5 million of lower costs on idle rigs.

During the prior year quarter, we recorded non-cash losses on impairment totaling $756.5 million, with respect to certain assets in our Floater segment. See "Note 5 - Property and Equipment" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information.

Floater depreciation expense decreased $44.0 million, or 78%, for the current quarter as compared to the prior year quarter, primarily due to the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.

Jackups

Jackup revenues increased $8.4 million, or 5%, for the current quarter as compared to the preceding quarter, primarily due to $5.9 million from an increase in operating days.

Jackup revenues increased $8.1 million, or 5%, for the current quarter as compared to the prior year quarter, primarily due to $19.9 million from increased operating days and $3.6 million from increased customer reimbursable revenue. This increase was partially offset by a decline of $15.4 million due to lower average day rates.

Jackup contract drilling expense increased $11.2 million, or 9%, for the current quarter as compared to the preceding quarter, primarily due to adjustments of certain accruals in the preceding quarter of $4.8 million as well as an increase of $4.0 million in mobilization costs.

Jackup contract drilling expense increased $17.9 million, or 15%, for the current quarter as compared to the prior year quarter, primarily due to a $7.6 million increase in reimbursable expenses, a $5.7 million increase in scheduled repairs and maintenance and a $5.4 million increase in personnel costs.

Jackup depreciation expense decreased $43.3 million, or 83%, for the current quarter as compared to the prior year quarter, primarily due to the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.

ARO

The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for both the ARO-owned jackup rigs and the rigs leased from us. Contract drilling expenses are inclusive of the bareboat charter fees for the rigs leased from us. See "Note 3 - Equity Method Investment in ARO" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information on ARO.

ARO revenue increased $5.9 million, or 6%, for the current quarter as compared to the preceding quarter, primarily due to $6.8 million incremental revenues from more operating days on certain rigs which were undergoing maintenance in the preceding quarter.

ARO revenue decreased $11.4 million, or 9%, for the current quarter as compared to the prior year quarter, primarily due to fewer operating days related to two rigs which operated in the prior year quarter but completed their contracts in 2021.

ARO contract drilling expense decreased $4.7 million, or 5%, for the current quarter as compared to the preceding quarter, due to a $5.2 million reduction in repairs and maintenance costs as certain rigs were undergoing maintenance projects in the preceding quarter.

Other

Other revenues increased $5.3 million, or 16%, for the current quarter as compared to the preceding quarter, primarily due to $2.6 million from higher average day rates on certain rigs and $3.2 million of higher revenues earned under the Lease Agreements with ARO. See "Note 3 - Equity Method Investment in ARO" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information.

Other depreciation expense decreased $10.4 million, or 92%, for the current quarter as compared to the prior year quarter, primarily due to the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.

Other Income (Expense)

The following table summarizes other income (expense) (in millions):


	Successor				Predecessor
	Three Months Ended March 31, 2022		Three Months Ended December 31, 2021			Three Months Ended March 31, 2021
Interest income	$	10.9	$	11.0		$	2.6

Interest expense	(11.5)		(11.7)			(1.3)


Reorganization items, net	(1.0)		(4.9)			(52.2)
Net foreign currency exchange gains	4.7		3.3			16.6
Net gain on sale of property	2.5		21.0			1.4
Other	3.8		2.7			4.5
	$	9.4	$	21.4		$	(28.4)

Interest income increased for the current quarter as compared to the prior year quarter primarily due to amortization of the discount on our note receivable from ARO recorded in fresh start accounting.

Interest expense increased by $10.2 million for the current quarter as compared to the prior year quarter as current quarter interest expense is attributable to our First Lien Notes issued upon the Effective Date and in the prior year quarter we did not accrue interest on our Predecessor outstanding debt subsequent to the Chapter 11 Cases.

Reorganization items, net of $4.9 million recognized during the preceding quarter was related to legal and other professional advisory service fees directly related to the Chapter 11 Cases.

Reorganization items, net of $52.2 million recognized during prior year quarter was related to other net losses and expenses directly related to Chapter 11 Cases, consisting of legal and other professional advisory fees of $47.8 million and contract items related to the rejection of certain operating leases of $4.4 million.

Our functional currency is the U.S. dollar, and a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates.

Net foreign currency exchange gains of $4.7 million for the current quarter primarily included $3.4 million related to euros. Net foreign currency exchange gains of $3.3 million for the preceding quarter primarily included $2.7 million related to euros. Net foreign currency exchange gains of $16.6 million for the prior year quarter primarily included $11.8 million and $4.3 million related to Libyan dinars and euros, respectively.

Net gains on the sale of property decreased by $18.5 million for the current quarter as compared to the preceding quarter primarily due to a decrease in gains from rigs sold.

Provision for Income Taxes

Discrete income tax benefit for the current quarter was $14.5 million and was primarily attributable to changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years. Discrete income tax benefit for the preceding quarter was $29.5 million and was primarily related to a reduction in liabilities for unrecognized tax benefits associated with tax positions taken in prior years and deferred tax benefits associated with Swiss tax reform. Discrete income tax expense for the prior year quarter was $20.3 million and was primarily attributable to changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years. Excluding the aforementioned discrete tax items, income tax expense was $13.8 million for the current quarter, income tax benefit was $1.5 million for the preceding quarter and income tax expense was $11.4 million for the prior year quarter. The $15.3 million increase in income tax expense as compared to the preceding quarter was primarily due to the derecognition of valuation allowance against deferred tax assets in the preceding quarter resulting from a change in estimate of future taxable income and to changes in the relative components of our earnings and losses generated in tax jurisdictions with higher effective tax rates in the current quarter as compared to the preceding quarter.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect to fund our short-term liquidity needs, including contractual obligations and anticipated capital expenditures as well as working capital requirements, from cash and cash equivalents, proceeds from the sale of assets and cash flows from operations. We expect to fund our long-term liquidity needs, including contractual obligations and anticipated capital expenditures from cash and cash equivalents, cash flows from operations, as well as cash to be received from maturity of our long-term notes receivable and from the distribution of earnings from ARO. If necessary, we may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs. However, the Indenture contains covenants that limit our ability to incur additional indebtedness.

Our Cash and cash equivalents as of March 31, 2022 and December 31, 2021 were $578.2 million and $608.7 million and we have no debt principal payments due until 2028. See "Note 8 - Debt" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information on the First Lien Notes.

Cash Flow and Capital Expenditures

Absent periods where we have significant financing or investing transactions or activities, such as debt or equity issuances, debt repayments, business combinations or asset sales, our primary sources and uses of cash are driven by cash generated from or used in operations and capital expenditures. Our net cash provided by or used in operating activities and capital expenditures were as follows (in millions):


	Successor		Predecessor
	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
Net cash provided by (used in) operating activities	$	0.5	$	(31.7)




Capital expenditures	38.5		6.0

During the three months ended March 31, 2022 (Successor), we generated $0.5 million from operating activities and our primary uses of cash were $38.5 million for the enhancement and other improvements of our drilling rigs. During the three months ended March 31, 2021 (Predecessor), our primary uses of cash were $31.7 million used in operating activities and $6.0 million for the enhancement and other improvements of our drilling rigs.

During the three months ended March 31, 2022 (Successor), net cash provided by operating activities was $0.5 million primarily related to higher net collections of customer receivables partially offset by cash outflows from the payment of certain taxes.

During the three months ended March 31, 2021 (Predecessor), net cash used in operating activities was $31.7 million primarily related to contributions to pension and other post-retirement benefit plans and reorganization costs.

We have construction agreements, as amended, with a Shipyard that provide for, among other things, an option construct whereby the Company has the right, but not the obligation, to take delivery of either or both VALARIS DS-13 and VALARIS DS-14 rigs under construction on or before December 31, 2023. Under the amended agreements, the purchase prices for the rigs are estimated to be approximately $119.1 million for VALARIS DS-13 and $218.3 million for VALARIS DS-14, assuming a December 31, 2023 delivery date. Delivery can be requested any time prior to December 31, 2023 with a downward purchase price adjustment based on predetermined terms. If the Company elects not to purchase the rigs, the Company has no further obligations to the shipyard.

We continue to take a disciplined approach to reactivations with our stacked rigs, only returning them to the active fleet when there is visibility into work at attractive economics. In most cases, we expect the initial contract to pay for the reactivation costs and that the rig would have solid prospects for longer-term work. Most of this reactivation cost will be operating expenses, recognized in the income statement, related to de-preservation activities, including reinstalling key pieces of equipment and crewing up the rigs. Capital expenditures during reactivations include rig modifications, equipment overhauls and any customer required capital upgrades. We would generally expect to be compensated for these customer-specific enhancements.

Based on our current projections, we expect capital expenditures during 2022 to approximate $225 to $250 million for rig enhancement, reactivation and upgrade projects. We expect that customers will reimburse us for a significant portion of the 2022 expenditures. Depending on market conditions and future opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.

Approximately $70 million of our expected capital expenditures for 2022 relate to the reactivation and upgrade of the VALARIS DS-11 for an eight-well contract for a deepwater project in the U.S. Gulf of Mexico expected to commence in mid-2024. The contract requires the rig to be upgraded with 20,000 psi well-control equipment. In February 2022, the customer decided not to sanction and therefore withdrew from the project associated with this contract. In March 2022, the contract was novated to another customer, which was a partner on the project. No material changes to the contract resulted from the novation, including with respect to the termination provisions in the event the project does not receive final investment decision (FID). In the event of termination, the early termination fee and contractual reimbursements from the customer will be more than sufficient to cover expenses and commitments incurred by Valaris on the project.

As we reactivate rigs, we expect spending levels to increase beyond the levels we incurred in 2021, with more spending associated with reactivation of our floater fleet relative to our jackup fleet and for rigs that have been preservation stacked for longer periods of time.

We review from time to time possible acquisition opportunities relating to our business, which may include the acquisition of rigs or other businesses. The timing, size or success of any acquisition efforts and the associated potential capital commitments are unpredictable and uncertain. We may seek to fund all or part of any such efforts with cash on hand and proceeds from debt and/or equity issuances and may issue equity directly to the sellers. Our ability to obtain capital for additional projects to implement our growth strategy over the longer term will depend on our future operating performance, financial condition and, more broadly, on the availability of equity and debt financing. Capital availability will be affected by prevailing conditions in our industry, the global economy, the global financial markets and other factors, many of which are beyond our control. In addition, any additional debt service requirements we take on could be based on higher interest rates and shorter maturities and could impose a significant burden on our results of operations and financial condition, and the issuance of additional equity securities could result in significant dilution to shareholders.

Financing and Capital Resources

First Lien Notes

We have $550 million aggregate principal amount of Senior Secured First Lien Notes due 2028 (the "First Lien Notes") which were issued on the Effective Date pursuant to the Indenture. The First Lien Notes are scheduled to mature on April 30, 2028. See "Note 8 - Debt" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information on the First Lien Notes.

Investment in ARO and Notes Receivable from ARO

We consider our investment in ARO to be a significant component of our investment portfolio and an integral part of our long-term capital resources. We expect to receive cash from ARO in the future both from the maturity of our long-term notes receivable and from the distribution of earnings from ARO. The long-term notes receivable, which are governed by the laws of Saudi Arabia, mature in 2027 and 2028. In the event that ARO is unable to repay these notes when they become due, we would require the prior consent of our joint venture partner to enforce ARO’s payment obligations.

The distribution of earnings to the joint-venture partners is at the discretion of the ARO Board of Managers, consisting of 50/50 membership of managers appointed by Saudi Aramco and managers appointed by us, with approval required by both shareholders. The timing and amount of any cash distributions to the joint-venture partners cannot be predicted with certainty and will be influenced by various factors, including the liquidity position and long-term capital requirements of ARO. ARO has not made a cash distribution of earnings to its partners since its formation. See "Note 3 - Equity Method Investment in ARO" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information on our investment in ARO and notes receivable from ARO.

The following table summarizes the maturity schedule of our notes receivable from ARO as of March 31, 2022 (in millions):


Maturity Date	Principal Amount
October 2027	$	265.0
October 2028	177.7

Total	$	442.7

Other Commitments

We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. As of March 31, 2022, we were contingently liable for an aggregate amount of $33.6 million under outstanding letters of credit which guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of March 31, 2022, we had collateral deposits in the amount of $27.1 million with respect to these agreements.

In connection with our 50/50 unconsolidated joint venture, we have a potential obligation to fund ARO for newbuild jackup rigs. ARO has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176.0 million. These newbuild rigs are expected to be delivered in the first or second quarter of 2023 and ARO is expected to place orders for two additional newbuild jackups in 2022. The joint venture partners intend for the newbuild jackup rigs to be financed out of available cash from ARO's operations and/or funds available from third-party debt financing. ARO paid a 25% down payment from cash on hand for each of the newbuilds ordered in January 2020 and is actively exploring financing options for remaining payments due upon delivery. In the event ARO has insufficient cash from operations or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, as delivered, on a proportionate basis. See "Note 3 - Equity Method Investment in ARO" to our condensed consolidated financial statements included in "Item 1. Financial Statements" for additional information on ARO.

Tax Assessments

During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $75.6 million converted at current period-end exchange rates) plus interest related to the examination of certain of our tax returns for the years 2011 through 2016. During the third quarter of 2019, we made a A$42 million payment (approximately $29 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. We have an $18.8 million liability for unrecognized tax benefits relating to these assessments as of March 31, 2022. We believe our tax returns are materially correct as filed, and we are vigorously contesting these assessments. Although the outcome of such assessments and related administrative proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows.

SUPPLEMENTAL FINANCIAL INFORMATION

Guarantees of Registered Securities

The First Lien Notes issued by Valaris Limited have been fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by certain of the direct and indirect subsidiaries (the “Guarantors”) of Valaris Limited under the Indenture governing the First Lien Notes (the “Guarantees”). The First Lien Notes and Guarantees are secured by liens on the collateral, including, among other things, subject to certain agreed security principles, (i) first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by Valaris Limited or any Guarantor and (ii) a first-priority perfected lien on substantially all assets of Valaris Limited and each Guarantor, in each case subject to certain exceptions and limitations (collectively, the “Collateral”). We are providing the following information about the Guarantors and the Collateral in compliance with Rules 13-01 and 13-02 of Regulation S-X.

First Lien Note Guarantees

The Guarantees are joint and several senior secured obligations of each Guarantor and rank equally in right of payment with existing and future senior indebtedness of such Guarantor and effectively senior to such Guarantor’s existing and future indebtedness (i) that is not secured by a lien on the Collateral securing the First Lien Notes, or (ii) that is secured by a lien on the Collateral securing the First Lien Notes ranking junior to the liens securing the First Lien Notes. The Guarantees rank effectively junior to such Guarantor’s existing and future secured indebtedness (i) that is secured by a lien on the Collateral that is senior or prior to the lien securing the First Lien Notes, or (ii) that is secured by liens on assets that are not part of the Collateral, to the extent of the value of such assets. The Guarantees rank equally with such Guarantor’s existing and future indebtedness that is secured by first-priority liens on the Collateral and senior in right of payment to any existing and future subordinated indebtedness of such Guarantor. The Guarantees are structurally subordinated to all existing and future indebtedness and other liabilities of any non-Guarantors, including trade payables (other than indebtedness and liabilities owed to such Guarantor).

Under the Indenture, a Guarantor may be automatically and unconditionally released and relieved of its obligations under its guarantee under certain circumstances, including: (1) in connection with any sale, transfer or other disposition (including by merger, consolidation, distribution, dividend or otherwise) of all or substantially all of the assets of such Guarantor to a person that is not the Company or a restricted subsidiary, if such sale, transfer or other disposition is conducted in accordance with the applicable terms of the Indenture, (2) in connection with any sale, transfer or other disposition (including by merger, consolidation, amalgamation, distribution, dividend or otherwise) of all of the capital stock of any Guarantor, if such sale, transfer or other disposition is conducted in accordance with the applicable terms of the Indenture, (3) upon our exercise of legal defeasance, covenant defeasance or discharge under the Indenture, (4) unless an event of default has occurred and is continuing, upon the dissolution or liquidation of a Guarantor in accordance with the Indenture, and (5) if such Guarantor is properly designated as an unrestricted subsidiary, in each case in accordance with the provisions of the Indenture.

We conduct our operations primarily through our subsidiaries. As a result, our ability to pay principal and interest on the First Lien Notes is dependent on the cash flow generated by our subsidiaries and their ability to make such cash available to us by dividend or otherwise. The Guarantors’ earnings will depend on their financial and operating performance, which will be affected by general economic, industry, financial, competitive, operating, legislative, regulatory and other factors beyond their control. Any payments of dividends, distributions, loans or advances to us by the Guarantors could also be subject to restrictions on dividends under applicable local law in the jurisdictions in which the Guarantors operate. In the event that we do not receive distributions from the Guarantors, or to the extent that the earnings from, or other available assets of, the Guarantors are insufficient, we may be unable to make payments on the First Lien Notes.

Pledged Securities of Affiliates

Pursuant to the terms of the First Lien Notes collateral documents, the Collateral Agent under the Indenture may pursue remedies, or pursue foreclosure proceedings on the Collateral (including the equity of the Guarantors and other direct subsidiaries of Valaris Limited and the Guarantors), following an event of default under the Indenture. The Collateral Agent’s ability to exercise such remedies is limited by the intercreditor agreement for so long as any priority lien debt is outstanding.

The combined value of the affiliates whose securities are pledged as Collateral constitutes substantially all of the Company’s value, including assets, liabilities and results of operations. As such, the assets, liabilities and results of operations of the combined affiliates whose securities are pledged as Collateral are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company. The value of the pledged equity is subject to fluctuations based on factors that include, among other things, general economic conditions and the ability to realize on the Collateral as part of a going concern and in an orderly fashion to available and willing buyers and outside of distressed circumstances. There is no trading market for the pledged equity interests.

Under the terms of the Indenture and the other documents governing the obligations with respect to the First Lien Notes (the “Notes Documents”), Valaris Limited and the Guarantors will be entitled to the release of the Collateral from the liens securing the First Lien Notes under one or more circumstances, including (1) upon full and final payment of any such obligations; (2) to the extent that proceeds continue to constitute Collateral, in the event that Collateral is sold, transferred, disbursed or otherwise disposed of in accordance with the Notes Documents; (3) upon our exercise of legal defeasance, covenant defeasance or discharge under the Indenture; (4) with respect to vessels, certain specified events permitting release of the mortgage with respect to such vessels under the Indenture; (5) with the consent of the requisite holders under the Indenture; (6) with respect to equity interests in restricted subsidiaries that incur permitted indebtedness, if such equity interests shall secure such other indebtedness and the same is permitted under the terms of the Indenture; and (7) as provided in the intercreditor agreement. The collateral agency agreement also provides for release of the Collateral from the liens securing the Notes under the above described circumstances (but including additional requirements for release in relation to all of the documents governing the indebtedness that is secured by first-priority liens on the Collateral, in addition to the Indenture). Upon the release of any subsidiary from its guarantee, if any, in accordance with the terms of the Indenture, the lien on any pledged equity interests issued by such Guarantor and on any assets of such Guarantor will automatically terminate.

Summarized Financial Information

The summarized financial information below reflects the combined accounts of the Guarantors and Valaris Limited (collectively, the “Obligors”), for the dates and periods indicated. The financial information is presented on a combined basis and intercompany balances and transactions between entities in the Obligor group have been eliminated.

Summarized Balance Sheet Information:



(in millions)	March 31, 2022		December 31, 2021
ASSETS
Current assets	$	1,094.7	$	1,140.2
Amounts due from non-guarantor subsidiaries, current	693.8		785.8
Amounts due from related party, current	12.0		13.1
Noncurrent assets	1,008.5		989.8
Amounts due from non-guarantor subsidiaries, noncurrent	1,469.7		1,469.7
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities	374.3		308.0
Amounts due to non-guarantor subsidiaries, current	10.9		55.3
Amounts due to related party, current	37.1		38.3
Long-term debt	545.5		545.3
Noncurrent liabilities	444.3		438.5
Amounts due to non-guarantor subsidiaries, noncurrent	1,922.5		1,921.6
Noncontrolling interest	1.4		2.6

Summarized Statement of Operations Information:


	Successor		Predecessor
(in millions)	Three Months Ended March 31, 2022		Three Months Ended March 31, 2021
Operating revenues	$	299.9	$	314.7
Operating revenues from related party	14.3		17.8
Operating costs and expenses	349.5		1,148.4
Reorganization expense	(1.0)		(51.6)
Loss from continuing operations before income taxes	(65.0)		(849.2)
Net income (loss) attributable to noncontrolling interest	1.2		(2.4)
Net loss	(63.9)		(851.6)

MARKET RISK

Interest Rate Risk

Our outstanding debt at March 31, 2022 consisted of our $550.0 million aggregate principal amount of First Lien Notes. We are subject to interest rate risk on our fixed-interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in market interest rates impacting the fair value of the debt.

Our long-term notes receivable from ARO bear interest based on a one-year LIBOR rate, set as of the end of the year prior to the year applicable, plus two percent. As the notes bear interest on the LIBOR rate determined at the end of the preceding year, the rate governing our interest income in 2022 has already been determined.

A hypothetical 1% decrease to LIBOR would decrease our interest income by approximately $4.4 million based on the principal amount outstanding at March 31, 2022 of $442.7 million.

Foreign Currency Risk

Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; 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. 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 the foreign currency or revenue earned differs from costs incurred in the foreign currency. We do not currently hedge our foreign currency risk as our unsecured foreign currency credit lines were terminated in the second quarter of 2020 and our access to other foreign currency credit lines is limited.

CRITICAL ACCOUNTING POLICIES

The preparation of financial statements and related disclosures in conformity with accounting principles generally accepted in the United States of America requires us to make estimates, judgments and assumptions that affect the amounts reported in our condensed consolidated financial statements and accompanying notes. Our significant accounting policies are included in Note 1 to our audited consolidated financial statements for the year ended December 31, 2021, included in our annual report on Form 10-K filed with the SEC on February 22, 2022. These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our condensed consolidated financial statements.

We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results and that require the most difficult, subjective and/or complex judgments regarding estimates in matters that are inherently uncertain. Our critical accounting policies are those related to property and equipment, impairment of property and equipment for the Predecessor, income taxes and pension and other post-retirement benefits. For a discussion of the critical accounting policies and estimates that we use in the preparation of our condensed consolidated financial statements, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates" in Part II of our annual report on Form 10-K for the year ended December 31, 2021.

New Accounting Pronouncements

See Note 1 - Unaudited Condensed Consolidated Financial Statements to our condensed consolidated financial statements included in "Item 1. Financial Statements" for information on new accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Information required under this Item 3. has been incorporated herein from "Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures – We have established disclosure controls and procedures to ensure that the information required to be disclosed by us in the reports that we file under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and that such information is accumulated and made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors as appropriate to allow timely decisions regarding required disclosure.

Based on their evaluation as of March 31, 2022, our management, with the participation of our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective.

Changes in Internal Controls – There have been no material changes in our internal controls over financial reporting during the fiscal quarter ended March 31, 2022 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

Environmental Matters

We are currently subject to pending notices of assessment relating to spills of drilling fluids, oil, brine, chemicals, grease or fuel from drilling rigs operating offshore Brazil from 2008 to 2020, pursuant to which the governmental authorities have assessed, or are anticipated to assess, fines. We have contested these notices and appealed certain adverse decisions and are awaiting decisions in these cases. Although we do not expect final disposition of these assessments to have a material adverse effect on our financial position, operating results and cash flows, there can be no assurance as to the ultimate outcome of these assessments. A $0.5 million liability related to these matters was included in Accrued liabilities and other on our Condensed Consolidated Balance Sheet as of March 31, 2022 included in "Item 1. Financial Statements."

Other Matters

Item 1A. Risk Factors

There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to the other information presented in this quarterly report, you should carefully read and consider "Item 1A. Risk Factors" in Part I and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II of our annual report on Form 10-K for the year ended December 31, 2021, which contains descriptions of significant risks that may cause our actual results of operations in future periods to differ materially from those currently anticipated or expected.

Item 6. Exhibits


Exhibit Number						Exhibit
4.1						Second Supplemental Indenture, dated as of January 12, 2022, among Valaris Limited, Valaris United LLC, and Wilmington Savings Fund, FSB as collateral agent and trustee (incorporated by reference to Exhibit 4.4 to the Registrant’s Annual Report on Form 10-K filed on February 22, 2022, File No. 001-08097).
*10.1						Valaris Non-Executive Severance Plan (as amended and restated on 30 April 2020)
10.2						Amendment to Cash Retention Letter (Gilles Luca) effective as of January 20, 2022 (incorporated by reference to Exhibit 10.45 to the Registrant’s Annual Report filed on Form 10-K on February 22, 2022, File No. 001-08097).
*22.1						List of Guarantor Subsidiaries and Affiliate Securities Pledged as Collateral

*31.1						Certification of the Chief Executive Officer of Registrant Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2						Certification of the Chief Financial Officer of Registrant Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**32.1						Certification of the Chief Executive Officer of Registrant Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**32.2						Certification of the Chief Financial Officer of Registrant Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101.INS						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 Document
*101.CAL						Inline XBRL Taxonomy Extension Calculation Linkbase Document
*101.DEF						Inline XBRL Taxonomy Extension Definition Linkbase Document
*101.LAB						Inline XBRL Taxonomy Extension Label Linkbase Document
*101.PRE						Inline XBRL Taxonomy Extension Presentation Linkbase Document
*104						The cover page of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2022, formatted in Inline XBRL (included with Exhibit 101 attachments).

* Filed herewith.

** Furnished herewith.

SIGNATURES

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


		Valaris Limited


Date:	May 3, 2022	/s/ DARIN GIBBINS
		Darin Gibbins Interim Chief Financial Officer and Vice President, Investor Relations and Treasurer (principal financial officer)

		/s/ COLLEEN W. GRABLE
		Colleen W. Grable Controller (principal accounting officer)