Valaris Ltd - Annual Report: 2020 (Form 10-K)


UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2020


OR


☐			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 plc
(Exact name of registrant as specified in its charter)

England and Wales

98-0635229

(State or other jurisdiction of
incorporation or organization)

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

Cannon Place, 78 Cannon Street

London,

England

EC4N 6AF

(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: None


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

Title of each class

Ticker Symbol(s)

Name of each exchange on which registered

Class A ordinary shares, U.S. $0.40 par value

VALPQ

OTC Pink Open Market

Indicate by check mark if the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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 (S232.405 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 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 has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C 7262(b)) by the registered public accounting firm that prepared or issued its audit report.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes ☐ No ☒

The aggregate market value of the Class A ordinary shares (based upon the closing price on the New York Stock Exchange on June 30, 2020 of $0.65 of Valaris plc held by non-affiliates of Valaris plc at that date) was approximately $104,731,000.

As of February 22, 2021, there were 199,613,642 Class A ordinary shares of Valaris plc issued and outstanding.



TABLE OF CONTENTS


PART I	ITEM 1.	BUSINESS	6
	ITEM 1A.	RISK FACTORS	18
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	50
	ITEM 2.	PROPERTIES	51
	ITEM 3.	LEGAL PROCEEDINGS	54
	ITEM 4.	MINE SAFETY DISCLOSURES	55


PART II	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	56
	ITEM 6.	SELECTED FINANCIAL DATA	61
	ITEM 7	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	61
	ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	100
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	101
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	180
	ITEM 9A.	CONTROLS AND PROCEDURES	180
	ITEM 9B.	OTHER INFORMATION	180


PART III	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	181
	ITEM 11.	EXECUTIVE COMPENSATION	186
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS	197
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	199
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	200


PART IV	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	201
	ITEM 16.	FORM 10-K SUMMARY	210
		SIGNATURES	211

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 (the "Securities Act"), 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; the outcome and effects of the Chapter 11 Cases (as defined below); expected utilization, day rates, revenues, operating expenses, cash flows, contract terms, contract backlog, capital expenditures, insurance, financing and funding; the effect, impact, potential duration and other implications of the COVID-19 pandemic; the offshore drilling market, including supply and demand, customer drilling programs, stacking of rigs, effects of new rigs on the market and effects of declines in commodity prices; expected work commitments, awards and contracts; the timing of availability, delivery, mobilization, contract commencement or relocation or other movement of rigs and the timing thereof; future rig construction (including work in progress and completion thereof), 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; future operations; the impact of increasing regulatory complexity; the outcome of tax disputes, assessments and settlements; synergies and expected additional cost savings; dividends; 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, particularly in light of difficult market conditions, our projected negative cash flows in 2021 and highly leveraged balance sheet, including:

•potential adverse effects of the Chapter 11 Cases on our liquidity and results of operations;

•objections to the confirmation of our plan of reorganization or other pleadings we file that could protract the Chapter 11 Cases;

•our ability to comply with the restrictions and other covenants imposed by our DIP Credit Agreement (as defined herein) and other financial arrangements;

•the Bankruptcy Court’s rulings in the Chapter 11 Cases, and the outcome of the Chapter 11 Cases generally;

•the length of time that we will operate under chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;

•the COVID-19 pandemic, the related public health measures implemented by governments worldwide and the effects of the decline in oil prices during 2020, including the duration and severity of the outbreak, the duration of the price and demand decline and the extent of disruptions to our operations;

•downtime or temporary shut down 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;

•disputes over production levels among members of the Organization of Petroleum Exporting Countries and other oil and gas producing nations (“OPEC+”);

•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 or otherwise, which may cause us to idle or stack additional rigs;

•delays in contract commencement dates or cancellation, suspension, renegotiation or termination (with or without cause, including due to impacts of the COVID-19 pandemic) of drilling contracts or drilling programs as a result of general and industry-specific economic conditions, mechanical difficulties, performance or other reasons;

•potential additional asset impairments;

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

•the reaction of our customers, prospective customers, suppliers and service providers to the Chapter 11 Cases and the related increased performance and credit risks associated with our constrained liquidity position and capital structure;

•our customers, in response to reduced oil price expectations, cancelling or shortening the duration of our drilling contracts, cancelling future drilling programs and seeking pricing and other contract concessions from us;

•the impact of the delisting of our Class A ordinary shares from the New York Stock Exchange ("NYSE") in September 2020;

•our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to labor regulations, unionization, or otherwise, or to retain employees as a result of the imposition of further public health measures due to the COVID-19 pandemic, our financial condition generally or as a result of the Chapter 11 Cases;

•internal control risk due to significant employee reductions;

•our ability to successfully integrate the business, operations and employees of Rowan Companies Limited (formerly Rowan Companies plc) ("Rowan") and the Company to realize synergies and cost savings in connection with the Company's 2019 combination with Rowan (the "Rowan Transaction");

•changes in worldwide rig supply and demand, competition or technology, including as a result of delivery of newbuild drilling rigs and governmental policies that could reduce demand for hydrocarbons, including mandating or incentivizing the conversion from internal combustion engine powered vehicles to electric-powered vehicles;

•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;

•governmental action, terrorism, 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 or other geographic areas, which may result in expropriation, nationalization, confiscation or deprivation or

destruction of our assets; or suspension and/or termination of contracts based on force majeure events or adverse environmental safety events;

•risks inherent to shipyard rig construction, 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;

•our ability to enter into, and the terms of, future drilling contracts, including contracts for our 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, 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) and regulatory measures to limit or reduce greenhouse gases (such as the current moratorium on oil and gas leasing and permitting in federal lands and waters);

•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, other accidents, 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;

•activism by our security holders;

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

•the occurrence of cybersecurity incidents, attacks or other breaches to our information technology systems, including our rig operating systems; 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 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 this Form 10-K. 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

Item 1. Business

General

Valaris plc is a global offshore contract drilling company. Unless the context requires otherwise, the terms "Valaris," "Company," "we," "us" and "our" refer to Valaris plc together with all its subsidiaries and predecessors.

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 61 rigs, with drilling operations in almost every major offshore market across five continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 45 jackup rigs and a 50% equity interest in Saudi Aramco Rowan Offshore Drilling Company ("ARO"), our 50/50 joint venture with Saudi Aramco, which owns an additional seven rigs. We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.

Our customers include many of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations spanning nine countries on five continents. The markets in which we operate include the Gulf of Mexico, the North Sea, the Middle East, West Africa, Australia and Southeast Asia.

We provide 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.

Following several years of market volatility beginning with oil price declines in 2014, as we entered 2020, we expected that volatility to continue over the near-term with the expectation that long-term oil prices would remain at levels sufficient to support a continued gradual recovery in the demand for offshore drilling services. We were focused on opportunities to put our rigs to work, manage liquidity, extend our financial runway, and reduce debt as we sought to navigate the extended market downturn and improve our balance sheet. Recognizing our ability to maintain a sufficient level of liquidity to meet our financial obligations depended upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control, we had significant financial flexibility within our capital structure to support our liability management efforts. However, starting in early 2020, the COVID-19 pandemic and the response thereto negatively impacted the macro-economic environment and global economy. Global oil demand fell sharply at the same time global oil supply increased as a result of certain oil producers competing for market share, leading to a supply glut. As a consequence, the price of Brent crude oil fell from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020. In response to dramatically reduced oil price expectations for the near term, our customers reviewed, and in most cases lowered significantly, their capital expenditure plans in light of revised pricing expectations. This caused our customers to cancel or shorten the duration of many of our 2020 drilling contracts, cancel future drilling programs and seek pricing and other contract concessions which led to material operating losses and liquidity constraints for us. While there has been some recent improvement to Brent crude oil prices, to approximately $65 per barrel in February 2021, there is still a significant amount of uncertainty around the sustainability of the improvement in oil prices to support a recovery in demand for offshore drilling services.

demand decline, and the extent of disruptions to our operations. To date, the COVID-19 pandemic has resulted in only limited operational downtime. 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.

We expect that these challenges will continue for drilling contractors as customers wait to gain additional clarity on commodity pricing and seek to reduce costs in the near-term by attempting to renegotiate existing contract terms. We believe the current market and macro-economic conditions will create a challenging contracting environment through 2021 and into 2022 and potentially beyond.

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 have resulted in significantly reduced demand and day rates for offshore drilling provided by the Company and increased uncertainty regarding long-term market conditions. These recent events have had a significant adverse impact on our current and expected liquidity position and financial runway and led to the filing of the Chapter 11 Cases (as defined herein).

While we have and are continuing to pursue a variety of cost-cutting measures such as further reductions in corporate overhead and discretionary expenditures, reductions in capital expenditures and an increased focus on operational efficiencies, we determined that based on our significant level of indebtedness and the circumstances described above that a comprehensive restructuring of our indebtedness was needed to improve our financial position. As more fully described in “Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data", the Company will undergo a financial restructuring that is intended to reduce debt levels substantially, support continued operations during the current lower demand environment and provide a robust financial platform to take advantage of market recovery over the long-term.

Chapter 11 Proceedings and Ability to Continue as a Going Concern

On August 19, 2020 (the “Petition Date”), Valaris plc and certain of its direct and indirect subsidiaries (collectively, “the Debtors") filed voluntary petitions for reorganization under chapter 11 of the United States Bankruptcy Code (“Bankruptcy Code”) in the Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). As part of the chapter 11 cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI) (the “Chapter 11 Cases”), the Debtors were granted “first-day” relief which enabled the Company to continue operating without interruption or disruption to its relationships with its customers and vendors or its high-quality service delivery. In particular, employee pay and benefits are expected to continue without interruption.

On August 18, 2020, the Debtors entered into the Restructuring Support Agreement (the "Original RSA") with certain senior note holders (collectively, the "Consenting Noteholders"). On February 5, 2021, the Debtors entered into the Amended Restructuring Support Agreement (the “Amended RSA”) with the Consenting Noteholders and certain revolving credit facility lenders (the “Consenting Lenders” and, together with the Consenting Noteholders, the “Consenting Creditors”), which contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA. Holders of approximately 100% of the total commitments outstanding under our revolving credit facility and holders of approximately 72% of the aggregate amount of our Senior Notes outstanding are party to the Amended RSA.

See “Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional details regarding the Chapter 11 Cases and related items, the Amended RSA and our ability to continue as a going concern.

Contract Drilling Operations

Our business consists of four operating segments: (1) Floaters, which included 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 Rig Lease Agreements, the Secondment Agreement and the Transition Services Agreement. Floaters, Jackups and ARO are also reportable segments.

We own and operate 61 rigs, 27 are located in the Middle East, Africa and Asia Pacific, 11 are located in North and South America and 23 are located in Europe as of December 31, 2020.

Our drilling rigs drill and complete oil and natural gas wells. From time to time, our drilling rigs may be utilized as accommodation units or for non-drilling services, such as workovers and interventions, plug and abandonment and decommissioning work. Demand for our drilling services is based upon many factors beyond our control. See “Item 1A. Risk Factors - The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.”

Our drilling contracts are the result of negotiations with our customers, and most contracts are awarded upon competitive bidding. The terms of our drilling contracts can vary significantly, but generally contain the following commercial terms:

•contract duration or term for a specific period of time or a period necessary to drill one or more wells,

•term extension options, exercisable by our customers, upon advance notice to us, at mutually agreed, indexed, fixed rates or current rate at the date of extension,

•provisions permitting early termination of the contract (1) if the rig is lost or destroyed, (2) if operations are suspended for a specified period of time due to various events, including damage or breakdown of major rig equipment, unsatisfactory performance, or "force majeure" events or (3) at the convenience (without cause) of the customer (in certain cases obligating the customer to pay us an early termination fee providing some level of compensation to us for the remaining term),

•payment of compensation to us is (generally in U.S. dollars although some contracts require a portion of the compensation to be paid in local currency) on a day rate basis such that we receive a fixed amount for each day that the drilling rig is under contract (lower day rates generally apply for limited periods when operations are suspended due to various events, including during delays that are beyond our reasonable control, during repair of equipment damage or breakdown and during periods of re-drilling damaged portions of the well, and no day rate, or zero rate, generally applies when these limited periods are exceeded until the event is remediated, and during periods to remediate unsatisfactory performance or other specified conditions),

•payment by us of the operating expenses of the drilling rig, including crew labor and incidental rig supply and maintenance costs,

•mobilization and demobilization requirements of us to move the drilling rig to and from the planned drilling site, and may include reimbursement of a portion of these moving costs by the customer in the form of an up-front payment, additional day rate over the contract term or direct reimbursement, and

•provisions allowing us to recover certain labor and other operating cost increases, including certain cost increases due to changes in applicable law, from our customers through day rate adjustment or direct reimbursement.

In general, following the downturn in offshore drilling demand commencing in 2014, contract awards have been subject to an extremely competitive bidding process. The intense pressure on operating day rates has resulted in lower margin contracts that also contain less favorable contractual and commercial terms, including reduced or no mobilization and/or demobilization fees; reduced day rates or zero day rates during downtime due to damage or failure of our equipment; reduced standby, redrill and moving rates and reduced periods in which such rates are payable; reduced caps on reimbursements for lost or damaged downhole tools; reduced periods to remediate downtime due to equipment breakdowns or failure to perform in accordance with the contractual standards of performance before the operator may terminate the contract; certain limitations on our ability to be indemnified from operator and third party damages caused by our fault, resulting in increases in the nature and amounts of liability allocated to us; and reduced or no early termination fees and/or termination notice periods.

Backlog Information

Our contract drilling backlog reflects commitments, represented by signed drilling contracts, and is calculated by multiplying the contracted day rate by the contract period. The contracted day rate excludes certain types of lump sum fees for rig mobilization, demobilization, contract preparation, as well as customer reimbursables and bonus opportunities. Contract backlog is adjusted for drilling contracts signed or terminated after each respective balance sheet date but prior to filing each of our annual reports on Form 10-K on March 2, 2021 and February 21, 2020, respectively. Our backlog excludes ARO's backlog, but includes backlog from our rigs leased to ARO at the contractual rates, which are subject to adjustment by the shareholder agreement. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

The following table summarizes our contract backlog of business as of December 31, 2020 and 2019 (in millions):


	2020		2019
Floaters	$	205.7	$	847.3
Jackups	859.5		1,281.2
Other(1)	140.1		324.3
Total	$	1,205.3	$	2,452.8

(1)Other includes the bareboat charter backlog for the nine jackup rigs leased to ARO to fulfill contracts between ARO and Saudi Aramco, in addition to backlog for our managed rig services. Substantially all the operating costs for jackups leased to ARO through the bareboat charter agreements will be borne by ARO.

As of December 31, 2020, our backlog was $1.2 billion as compared to $2.5 billion as of December 31, 2019. Our floater backlog declined $641.6 million and our jackup backlog declined $421.7 million. Changes resulted from revenues realized during the period, contract terminations and contract suspensions, partially offset by new contract awards and contract extensions. Our other segment backlog declined $184.2 million due to contract concessions and revenues realized during the period.

The following table summarizes our contract backlog of business as of December 31, 2020 and the periods in which such revenues are expected to be realized (in millions):


	2021		2022		2023		2024 and Beyond		Total
Floaters	$	205.7	$	—	$	—	$	—	$	205.7
Jackups	548.7		235.8		75.0		—		859.5
Other(1)	130.2		9.9		—		—		140.1
Total	$	884.6	$	245.7	$	75.0	$	—	$	1,205.3

(1)Includes the bareboat charter backlog for the nine jackup rigs leased to ARO to fulfill contracts between ARO and Saudi Aramco, in addition to backlog for our managed rig services. Substantially all the operating costs for jackups leased to ARO through the bareboat charter agreements will be borne by ARO.

Our drilling contracts generally contain provisions permitting early termination of the contract if the rig is lost or destroyed or by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions. In addition, our drilling contracts generally permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in some cases without making an early termination payment to us. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.

The amount of actual revenues earned and the actual periods during which revenues are earned will be different from amounts disclosed in our backlog calculations due to a lack of predictability of various factors, including unscheduled repairs, maintenance requirements, weather delays, contract terminations or renegotiations and other factors.

See "Item 1A. Risk Factors - Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future, which may have a material adverse effect on our financial position, results of operations and cash flows” and “Item 1A. Risk Factors - We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.”

Drilling Contracts and Insurance Program

Our drilling contracts provide for varying levels of allocation of responsibility for liability between our customer and us for loss or damage to each party's property and third-party property, personal injuries and other claims arising out of our drilling operations. We also maintain insurance for personal injuries, damage to or loss of property and certain business risks.

Our insurance policies typically consist of 12-month policy periods, and the next renewal date for a substantial portion of our insurance program is scheduled for May 31, 2021. Our insurance program provides coverage, subject to the policies' terms and conditions and to the extent not otherwise assumed by the customer under the indemnification provisions of the drilling contract, for third-party claims arising from our operations, including third-party claims arising from well-control events, named windstorms, sudden and accidental pollution originating from our rigs, wrongful death and personal injury. Third-party pollution claims could also arise from damage to adjacent pipelines and from spills of fluids maintained on the drilling rig. Generally, our program provides liability coverage up to $750.0 million, with a per occurrence deductible of $10.0 million or less. We retain the risk for liability not indemnified by the customer in excess of our insurance coverage.

Well-control events generally include an unintended release from a well that cannot be contained by using equipment on site (e.g., a blowout preventer), by increasing the weight of drilling fluid or by diverting the fluids safely into production facilities. In addition to the third-party coverage described above, for claims relating to a

well-control event, we also have $150.0 million of coverage available to pay costs of controlling and re-drilling of the well and third-party pollution claims.

Our insurance program also provides coverage to us for physical damage (including total loss) to our rigs, excluding damage arising from a named windstorm in the U.S. Gulf of Mexico. This coverage is based on an agreed amount for each rig and has a per occurrence deductible for losses ranging from $15.0 million to $25.0 million. Due to the significant premium, high deductible and limited coverage, we do not purchase windstorm insurance for our rigs in the U.S. Gulf of Mexico. Accordingly, we retain the risk for windstorm damage to our jackup and floater rigs in the U.S. Gulf of Mexico.

Our drilling contracts customarily provide that each party is responsible for injuries or death to their respective personnel and loss or damage to their respective property (including the personnel and property of each parties’ contractors and subcontractors) regardless of the cause of the loss or damage. However, in certain drilling contracts our customer’s responsibility for damage to its property and the property of its other contractors contains an exception to the extent the loss or damage is due to our negligence, which exception is usually subject to negotiated caps on a per occurrence basis, although in some cases we assume responsibility for all damages due to our negligence. In addition, our drilling contracts typically provide for our customers to indemnify us, generally based on replacement cost minus some level of depreciation, for loss or damage to our down-hole equipment, and in some cases for a limited amount of the replacement cost of our subsea equipment, unless the damage is caused by our negligence, normal wear and tear or defects in our equipment.

Subject to the exceptions noted below, our customers typically assume most of the responsibility for and indemnify us from any loss, damage or other liability resulting from pollution or contamination arising from operations, including as a result of blowouts, cratering and seepage, when the source of the pollution originates from the well or reservoir, including costs for clean-up and removal of pollution and third-party damages. In most drilling contracts, we assume liability for third-party damages resulting from such pollution and contamination caused by our negligence, usually subject to negotiated caps on a per occurrence or per event basis. In addition, in substantially all of our contracts, the customer assumes responsibility and indemnifies us for loss or damage to the reservoir, for loss of hydrocarbons escaping from the reservoir and for the costs of bringing the well under control. Further, subject to the exceptions noted below, most of our contracts provide that the customer assumes responsibility and indemnifies us for loss or damage to the well, except when the loss or damage to the well is due to our negligence, in which case most of our contracts provide that the customer's sole remedy is to require us to redrill the lost or damaged portion of the well at a substantially reduced rate and, in some cases, pay for some of the costs to repair the well.

Most of our drilling contracts incorporate a broad exclusion that limits the operator's indemnity for damages and losses resulting from our gross negligence and willful misconduct and for fines and penalties and punitive damages levied or assessed directly against us. This exclusion overrides other provisions in the contract that would otherwise limit our liability for ordinary negligence. In most of these cases, we are still able to negotiate a liability cap (although these caps are significantly higher than the caps we are able to negotiate for ordinary negligence) on our exposure for losses or damages resulting from our gross negligence. In certain cases, the broad exclusion only applies to losses or damages resulting from the gross negligence of our senior supervisory personnel. However, in some cases we have contractually assumed significantly increased exposure or unlimited exposure for losses and damages due to the gross negligence of some or all our personnel, and in most cases, we are not able to contractually limit our exposure for our willful misconduct.

Notwithstanding our negotiation of express limitations in our drilling contracts for losses or damages resulting from our ordinary negligence and any express limitations (albeit usually much higher) for losses or damages in the event of our gross negligence, under the applicable laws that govern certain of our drilling contracts, the courts will not enforce any indemnity for losses and damages that result from our gross negligence or willful misconduct. As a result, under the laws of such jurisdictions, the indemnification provisions of our drilling contracts that would otherwise limit our liability in the event of our gross negligence or willful misconduct are deemed to be unenforceable as being contrary to public policy, and we are exposed to unlimited liability for losses

and damages that result from our gross negligence or willful misconduct, regardless of any express limitation of our liability in the relevant drilling contracts. Under the laws of certain jurisdictions, an indemnity from an operator for losses or damages of third parties resulting from our gross negligence is enforceable, but an indemnity for losses or damages of the operator is not enforceable. In such cases, the contractual indemnity obligation of the operator to us would be enforceable with respect to third-party claims for losses of damages, such as may arise in pollution claims, but the contractual indemnity obligation of the operator to us with respect to injury or death to the operator's personnel and the operator’s damages to the well, to the reservoir and for the costs of well control would not be enforceable. Furthermore, although there is a lack of precedential authority for these types of claims in countries where the civil law is applied, in those situations where a fault based codified civil law system is applicable to our drilling contracts, as opposed to the common law system, the courts generally will not enforce a contractual indemnity clause that totally indemnifies us from losses or damages due to our gross negligence but may enforce the contractual indemnity over and above a cap on our liability for gross negligence, assuming the cap requires us to accept a significant amount of liability.

Similar to gross negligence, regardless of any express limitations in a drilling contract regarding our liability for fines and penalties and punitive damages, the laws of most jurisdictions will not enforce an indemnity that indemnifies a party for a fine or penalty that is levied or punitive damages that are assessed directly against such party on the ground that it is against public policy to indemnify a party from a fine and penalty or punitive damages, especially where the purpose of such levy or assessment is to deter the behavior that resulted in the fine or penalty or punish such party for the behavior that warranted the assessment of punitive damages.

The above description of our insurance program and the indemnification provisions of our drilling contracts is only a summary as of the date hereof and is general in nature. In addition, our drilling contracts are individually negotiated, and the degree of indemnification we receive from operators against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated and the interpretation and enforcement of applicable law when the claim is adjudicated. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor a contractual indemnity obligation that is enforceable under applicable law. Our insurance program and the terms of our drilling contracts may change in the future.

In certain cases, vendors who provide equipment or services to us limit their pollution liability to a specific monetary cap, and we assume the liability above that cap. Typically, in the case of original equipment manufacturers, the cap is a negotiated amount based on mutual agreement of the parties considering the risk profiles and thresholds of each party. However, for smaller vendors, the liability is usually limited to the value, or double the value, of the contract.

We generally indemnify the customer for legal and financial consequences of spills of waste oil, fuels, lubricants, motor oils, pipe dope, paint, solvents, ballast, bilge, garbage, debris, sewage, hazardous waste and other liquids, the discharge of which originates from our rigs or equipment above the surface of the water and in some cases from our subsea equipment. Our contracts generally provide that, in the event of any such spill from our rigs, we are responsible for fines and penalties.

Major Customers

We provide our contract drilling services to major international, government-owned and independent oil and gas companies. During 2020, our five largest customers accounted for 41% of consolidated revenues. BP, our only customer who accounts for 10% or more of consolidated revenues, accounted for 11% of consolidated revenues.

Competition

The offshore contract drilling industry is highly competitive. Drilling contracts are, for the most part, awarded on a competitive bid basis. Price is often the primary factor in determining which contractor is awarded a

contract, although quality of service, operational and safety performance, equipment suitability and availability, location of equipment, reputation and technical expertise also are factors. There are numerous competitors with significant resources in the offshore contract drilling industry.

Governmental Regulation and Environmental Matters

Our operations are affected by political initiatives and by laws and regulations that relate to the oil and gas industry, including laws and regulations that have or may impose increased financial responsibility and oil spill abatement contingency plan capability requirements. Accordingly, we will be directly affected by the approval and adoption of laws and regulations curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety or other policy reasons. It is also possible that these laws and regulations and political initiatives could adversely affect our operations in the future by significantly increasing our operating costs or restricting areas open for drilling activity. See "Item 1A. Risk Factors- Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations."

•require the acquisition of various permits before drilling commences;

•require notice to stakeholders of proposed and ongoing operations;

•require the installation of expensive pollution control equipment;

•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling; and

•restrict the production rate of natural resources below the rate that would otherwise be possible.

Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations, which may not be covered by contractual indemnification or insurance or for which indemnity is prohibited by applicable law and could have a material adverse effect on our financial position, operating results and cash flows. To date, such laws and regulations have not had a material adverse effect on our operating results. However, the legislative, judicial and regulatory response to any well-control incidents could substantially increase our customers' liabilities in respect of oil spills and also could increase our liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.

Additionally, environmental laws and regulations are revised frequently, and any changes, including changes in implementation or interpretation, that result in more stringent and costly waste handling, disposal and cleanup requirements for our industry could have a significant impact on our operating costs.

The International Convention on Oil Pollution Preparedness, Response and Cooperation, the International Convention on Civil Liability for Oil Pollution Damage 1992, the U.K. Merchant Shipping Act 1995, Marpol 73/78 (the International Convention for the Prevention of Pollution from Ships), the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998, as amended, and other related legislation and regulations and the Oil Pollution Act of 1990 ("OPA 90"), as amended, the Clean Water Act and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention, reporting and control and have significantly expanded potential liability, fine and penalty exposure across many segments of the oil and gas industry. Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited

exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Similar environmental laws apply in our other areas of operation. Failure to comply with these statutes and regulations may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance, or for which indemnity is prohibited under applicable law, and could have a material adverse effect on our financial position, operating results and cash flows.

High-profile and catastrophic events such as the 2010 Macondo well incident have heightened governmental and environmental concerns about the oil and gas industry. From time to time, legislative proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas. We are adversely affected by restrictions on drilling in certain areas of the U.S. Gulf of Mexico and elsewhere, including the adoption of additional safety requirements and policies regarding the approval of drilling permits and restrictions on development and production activities in the U.S. Gulf of Mexico that have and may further impact our operations.

As a result of the 2010 Macondo well incident, the United States Bureau of Safety and Environmental Enforcement ("BSEE") issued a drilling safety rule in 2012 that included requirements for the cementing of wells, well-control barriers, blowout preventers, well-control fluids, well completions, workovers and decommissioning operations. BSEE also issued regulations requiring operators to have safety and environmental management systems ("SEMS") prior to conducting operations and requiring operators and contractors to agree on how the contractors will assist the operators in complying with the SEMS. In addition, in August 2012, BSEE issued an Interim Policy Document ("IPD") stating that it would begin issuing Incidents of Non-Compliance to contractors as well as operators for serious violations of BSEE regulations. Following federal court decisions successfully challenging the scope of BSEE’s jurisdiction over offshore contractors, this IPD has been removed from the list of IPDs on the BSEE website. If this judicial precedent stands, it may reduce regulatory and civil litigation liability exposures.

In late 2014, the United States Coast Guard ("USCG") proposed new regulations that would impose GPS equipment and positioning requirements for drilling rigs operating in the U.S. Gulf of Mexico and issued notices regarding the development of guidelines for cybersecurity measures used in the marine and offshore energy sectors for all vessels and facilities that are subject to the Maritime Transportation Security Act of 2002 ("MTSA"), including our rigs. The regulations imposing GPS equipment and positioning requirements have not yet been issued. In March 2020, the USCG issued its “Guidelines for Addressing Cyber Risks at MTSA Regulated Facilities” in order to assist facility owners and operators in complying with the requirements to assess, document, and address computer system or network vulnerabilities. The MTSA regulations provide general requirements for regulated facility cybersecurity while allowing facility owners and operators the discretion to determine the details of how they will comply. Facility owners and operators are responsible for assessing and documenting cybersecurity vulnerabilities and ensuring cybersecurity of their facilities under the Coast Guard’s oversight and guidance. The Company is currently evaluating the new USCG guidelines and the extent to which the BSEE or other regulators will review our ability to address cybersecurity risks at MTSA-regulated facilities. As the USCG provides further detail on how these guidelines will be implemented, we will address our cybersecurity program to comply with any regulations that are ultimately promulgated.

On July 28, 2016, BSEE adopted a new well-control rule that will be implemented in phases over the next several years (the "2016 Well Control Rule"). This new rule includes more stringent design requirements for well-control equipment used in offshore drilling operations. Subsequently, on May 2, 2019, BSEE issued the 2019 Well Control Rule, the revised well control and blowout preventer rule governing the Outer Continental Shelf (OCS) activities. The new rule revised existing regulations impacting offshore oil and gas drilling, completions, workovers and decommissioning activities. Specifically, the 2019 Well Control Rule addresses six areas of offshore operations: well design, well control, casing, cementing, real-time monitoring and subsea containment. The revisions were targeted to ensure safety and environmental protection while correcting errors in the 2016 rule and reducing unnecessary regulatory burden. We have not incurred significant costs to comply with the 2016 Well Control Rule or 2019 Well Control Rule.

The continuing and evolving threat of cyber attacks will likely require increased expenditures to strengthen cyber risk management systems for drilling rigs and onshore facilities. For example, on May 11, 2017, an executive

order was issued entitled Strengthening the Cybersecurity of Federal Networks and Critical Infrastructure, which is intended to improve the nation's ability to defend against increasing and evolving cyber attacks, and in July 2017 the USCG issued proposed cybersecurity guidelines for port facilities and offshore facilities, including drilling rigs, that could be impacted by cyber attacks. We cannot currently estimate the future expenditures associated with increased regulatory requirements, which may be material, and we continue to monitor regulatory changes as they occur.

Additionally, climate change is receiving increasing attention from scientists and legislators, and significant focus is being put on companies that are active producers of hydrocarbon resources. Globally, there are a number of legislative and regulatory proposals at various levels of government to address the greenhouse gas emissions that contribute to climate change, such as laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy and programs to mandate or incentivize the conversion from internal combustion engine powered vehicles to electric-powered vehicles. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could require us or our customers to incur increased operating costs. Any such legislation or regulatory programs could also increase the cost of consuming oil, and thereby reduce demand for oil, which could reduce our customers’ demand for our services. Consequently, legislation and regulatory programs to reduce greenhouse gas emissions could have an adverse effect on our financial position, operating results and cash flows.

Although the United States had withdrawn from the Paris Agreement in November 2020, the current Presidential Administration officially reentered the United States into the agreement in February 2021. It is likely that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, restricting, or delaying oil and gas development activities in certain areas, will be proposed and/or promulgated. For example, the current Presidential administration has issued multiple executive orders pertaining to environmental regulations and climate change, including the (1) Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad. The latter executive order announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, established climate change as a primary foreign policy and national security consideration and affirmed that achieving net-zero greenhouse gas emissions by or before mid-century is a critical priority.

If new laws are enacted or other government actions are taken that restrict or prohibit offshore drilling in our principal areas of operation, impose additional regulatory (including environmental protection) requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development or production of oil and natural gas, or promote other sources of clean energy, our financial position, operating results and cash flows could be materially adversely affected. See "Item 1A. Risk Factors - Compliance with or breach of environmental laws can be costly and could limit our operations."

Non-U.S. Operations

Revenues from non-U.S. operations were 83%, 85% and 87% of our total consolidated revenues during 2020, 2019 and 2018, respectively. Our non-U.S. operations and shipyard rig construction and enhancement projects are subject to political, economic and other uncertainties, including:

•terrorist acts, war and civil disturbances,

•expropriation, nationalization, deprivation or confiscation of our equipment or our customer's property,

•repudiation or nationalization of contracts,

•assaults on property or personnel,

•piracy, kidnapping and extortion demands,

•significant governmental influence over many aspects of local economies and customers,

•unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,

•work stoppages, often due to strikes over which we have little or no control,

•complications associated with repairing and replacing equipment in remote locations,

•limitations on insurance coverage, such as war risk coverage, in certain areas,

•imposition of trade barriers,

•wage and price controls,

•import-export quotas,

•exchange restrictions,

•currency fluctuations,

•changes in monetary policies,

•uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate,

•changes in the manner or rate of taxation,

•limitations on our ability to recover amounts due,

•increased risk of government and vendor/supplier corruption,

•increased local content requirements,

•the occurrence or threat of epidemic or pandemic diseases and any government response to such occurrence or threat,

•changes in political conditions, and

•other forms of government regulation and economic conditions that are beyond our control.

See "Item 1A. Risk Factors - Our non-U.S. operations involve additional risks not associated with U.S. operations."

Executive Officers

Officers generally serve for a one-year term or until successors are elected and qualified to serve. The table below sets forth certain information regarding our executive officers as of February 22, 2021:

Name

Age

Position

Thomas Burke

President and Chief Executive Officer

Jonathan Baksht

Executive Vice President and Chief Financial Officer

Gilles Luca

Senior Vice President - Chief Operating Officer

Alan Quintero

Senior Vice President - Business Development

Michael T. McGuinty

Senior Vice President - General Counsel and Secretary

Set forth below is certain additional information on our executive officers, including the business experience of each executive officer for at least the last five years:

Thomas Burke became the President and Chief Executive Officer of Valaris and a member of the Board of Directors in April 2019 in connection with the Rowan Transaction. Previously, he served as Rowan’s President and Chief Executive Officer as well as a director since April 2014. He served as Rowan’s Chief Operating Officer beginning in July 2011 and was appointed President in March 2013. Mr. Burke first joined Rowan in December 2009, serving as Chief Executive Officer and President of LeTourneau Technologies until the sale of LeTourneau in June 2011. From 2006 to 2009, Mr. Burke was a Division President at Complete Production Services, an oilfield services company, and from 2004 to 2006, served as its Vice President for Corporate Development. Mr. Burke received his PhD in Engineering from Trinity College at the University of Oxford, a Bachelor of Science in Engineering with Honors from Heriot-Watt University in Scotland, and an MBA from Harvard Business School, where he was awarded a Baker Scholarship.

Jonathan Baksht became Executive Vice President and Chief Financial Officer of Valaris in June 2019. Previously, he served as the Company's Senior Vice President - Chief Financial Officer since November 2015, and as Vice President - Finance and Vice President - Treasurer before his appointment as Chief Financial Officer. Prior to joining Valaris in August 2013, Mr. Baksht served as a Senior Vice President at Goldman Sachs & Co. within the Investment Banking Division where he served as a financial advisor to energy clients, oilfield services lead and a member of the Merger & Acquisitions Group. Prior to joining Goldman Sachs in 2006, he consulted on strategic initiatives for energy clients at Andersen Consulting. Mr. Baksht holds a Master of Business Administration from the Kellogg School of Management at Northwestern University and a Bachelor of Science with High Honors in Electrical Engineering from the University of Texas at Austin.

Gilles Luca joined Valaris in 1997 and was appointed to his current position of Senior Vice President - Chief Operating Officer in November 2019. Prior to his current position, Mr. Luca served as Senior Vice President - Western Hemisphere, Vice President - Business Development and Strategic Planning, Vice President - Brazil Business Unit and General Manager - Europe and Africa. He holds a Master's Degree in Petroleum Engineering from the French Petroleum Institute and a Bachelor in Civil Engineering from ESTP, Paris.

Alan Quintero became Senior Vice President - Business Development of Valaris in April 2019 in connection with the Rowan Transaction. Previously, he served as Rowan’s Senior Vice President, Business Development since 2018, after joining Rowan as Senior Vice President, Chief Technology Officer in 2017. Prior to joining Rowan, Mr. Quintero was a Partner at Trenegy Incorporated, a management consulting firm, from January 2016 to June 2017, and spent more than 20 years in various operational and managerial roles for international offshore drilling companies including serving as Senior Vice President, Operations at Transocean. Mr. Quintero received a Bachelor of Science in Mechanical Engineering from Texas A&M University. He also received education at Heriot-Watt University, Columbia University, Harvard University and the Wharton School of Business.

Michael T. McGuinty joined Valaris in February 2016 as Senior Vice President - General Counsel and Secretary. Prior to joining Valaris, Mr. McGuinty served as General Counsel and Company Secretary of Abu Dhabi

National Energy Company from January 2014 to December 2015. Previously, Mr. McGuinty spent 18 years with Schlumberger where he held various senior legal management positions in the United States, Europe and the Middle East including Director of Compliance, Deputy General Counsel - Corporate and M&A and Director of Legal Operations. Prior to Schlumberger, Mr. McGuinty practiced corporate and commercial law in Canada and France. Mr. McGuinty holds a Bachelor of Laws and Bachelor of Civil Law from McGill University and a Bachelor of Social Sciences from the University of Ottawa.

Employees

We employed approximately 4,500 personnel worldwide including contract employees, and approximately 3,400 personnel excluding contract employees, as of December 31, 2020. The majority of our personnel work on rig crews and are compensated on an hourly basis.

Available Information

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to these reports that we file or furnish to the Securities and Exchange Commission ("SEC") in accordance with the Exchange Act are available on our website at www.valaris.com/investors. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. These reports also are available in print without charge by contacting our Investor Relations Department as soon as reasonably practicable after we electronically file the information with, or furnish it to, the SEC. The information contained on our website is not included as part of, or incorporated by reference into, this report.

RISK FACTORS SUMMARY

An investment in our securities involves a high degree of risk. You should consider carefully all of the risks described below, together with the other information contained in this Form 10-K, before making a decision to invest in our securities. If any of the following events occur, our business, financial condition and operating results may be materially adversely affected. In that event, the trading price of our securities could decline, and you could lose all or part of your investment.

Risks Related to Chapter 11 Proceedings

•Operating under the Bankruptcy Court protection for a long period of time may harm our business.

•We may not be able to obtain confirmation of a plan of reorganization.

•We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation.

•As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.

•We may be subject to claims that will not be discharged in the Chapter 11 Cases.

•Our actual financial results may vary significantly from the projections filed with the Bankruptcy Court.

•The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, and we may face increased levels of employee attrition.

•Trading in our securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks.

•In certain instances, a chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code.

•Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

•We may not be able to achieve our stated goals and continue as a going concern under a plan of reorganization.

•Our ability to use our net operating loss carryforwards ("NOLs") may be limited by changes in ownership due to the Chapter 11 Cases.

Risks Related to Our Business, Operations and Market Conditions

•The COVID-19 pandemic and recent developments in the oil and gas industry could adversely impact our financial condition and results of operations.

•The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.

•The offshore contract drilling industry historically has been highly competitive and cyclical, with periods of low demand and excess rig availability that could result in adverse effects on our business.

•Our business will be adversely affected if we are unable to secure contracts on economically favorable terms or if option periods in existing contracts are not exercised as expected.

•We have a significant amount of debt. Our debt levels and debt agreement restrictions may limit our liquidity, our ability to obtain additional financing and our pursuit of other business opportunities.

•Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities.

•We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.

•We may incur impairments as a result of future declines in demand for offshore drilling rigs.

•The loss of a significant customer or customer contract could adversely affect us.

•Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future.

•We may not realize the expected benefits of the ARO joint venture, which depends on a single customer for its income and accounts receivable, and our inability to realize such benefits may introduce additional risks to our business.

•We have taken, and continue to take, cost-reduction actions, which may not be successful.

•We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage may not protect us against all of the risks and hazards we face, including those specific to offshore operations.

•The potential for U.S. Gulf of Mexico hurricane related windstorm damage or liabilities could result in uninsured losses and may cause us to alter our operating procedures during hurricane season.

•Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.

•Geopolitical events and violence could affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.

•Rig construction, upgrade, enhancement and reactivation projects are subject to risks, including delays and cost overruns, which could have a material adverse effect on our financial position, operating results or cash flows.

•Failure to recruit and retain skilled personnel could adversely affect our business.

•We have historically made significant capital expenditures to maintain our fleet to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to expand our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness.

•Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.

•Significant part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.

•Our long-term contracts are subject to the risk of cost increases, which could adversely affect our profitability.

•Our information technology systems, including rig operating systems, are subject to cybersecurity risks and threats.

Risks Related to Our Indebtedness and Ordinary Shares

•Our Class A ordinary shares have been delisted from the NYSE.

•The accounting method for our 2024 Convertible Notes could have a material effect on our reported financial results.

•Transfers of our Class A ordinary shares may be subject to stamp duty or stamp duty reserve tax ("SDRT") in the U.K., which would increase the cost of dealing in our Class A ordinary shares.

•If our Class A ordinary shares are not eligible for continued deposit and clearing within the facilities of DTC, then transactions in our securities may be disrupted.

•We have less flexibility as a U.K. public limited company with respect to certain aspects of capital management than U.S. corporations due to increased shareholder approval requirements.

•Our articles of association contain anti-takeover provisions; however, the Company is not subject to the U.K.'s City Code on Takeovers and Mergers.

•English law requires that we meet certain additional financial requirements before declaring dividends and returning funds to shareholders.

Legal, Regulatory and Tax Risks

•Failure to comply with anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act, could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

•Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations and reduce demand.

•Compliance with or breach of environmental laws can be costly and could limit our operations.

•Regulation of greenhouse gases and climate change could have a negative impact on our business.

•The IRS may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes.

•U.S. tax laws and IRS guidance could affect our ability to engage in certain acquisition strategies and certain internal restructurings.

•Governments may pass laws that subject us to additional taxation or may challenge our tax positions.

•Our consolidated effective income tax rate may vary substantially over time.

•Investor enforcement of civil judgments against us may be more difficult.

•Our business could be affected as a result of activist investors.

Risks Related to Our International Operations:

•Our non-U.S. operations involve additional risks not typically associated with U.S. operations.

•The U.K.'s withdrawal from the E.U. may have a negative effect on economic conditions, financial markets and our business.

Item 1A. Risk Factors

Risks Related to Chapter 11 Proceedings

We are subject to the risks and uncertainties associated with the Chapter 11 Cases.

On August 19, 2020, the Debtors filed the Chapter 11 Cases in the United States Bankruptcy Court for the Southern District of Texas. For the duration of the Chapter 11 Cases, our operations and our ability to develop and execute the business plan, as well as our continuation as a going concern, are subject to risks and uncertainties associated with bankruptcy. These risks include the following:

•our ability to execute, confirm and consummate a plan of reorganization as contemplated by the Amended RSA with respect to the Chapter 11 Cases;

•the high costs of bankruptcy proceedings and related fees;

•our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

•our ability to maintain our relationships with our suppliers, service providers, customers, employees and other third parties;

•our ability to maintain contracts that are critical to our operations;

•our ability to execute our business plan in the current depressed commodity price environment;

•our ability to attract, motivate and retain key employees;

•the ability of third parties to seek and obtain court approval to terminate contracts and other agreements with us;

•the ability of third parties to seek and obtain court approval to convert the Chapter 11 Cases to a chapter 7 proceeding; and

•the actions and decisions of our creditors and other third parties who have interests in the Chapter 11 Cases that may be inconsistent with our plans.

Delays in the Chapter 11 Cases increase the risks of us being unable to reorganize our business and emerge from bankruptcy, and also increase our costs associated with the bankruptcy process.

These risks and uncertainties could affect our business and operations in various ways. For example, negative events or publicity associated with the Chapter 11 Cases could adversely affect our relationships with customers, suppliers, service providers, employees and other third parties, which in turn could adversely affect our operations and financial condition. Also, pursuant to the Bankruptcy Code, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond in a timely fashion to certain events or take advantage of certain opportunities. We also need Bankruptcy Court confirmation of a plan of reorganization as contemplated by the Amended RSA. Because of the risks and uncertainties associated with the Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact that events that occur during or as a result of the Chapter 11 Cases will have on our business, financial condition, results of operations and cash flows.

Even if a plan of reorganization is consummated, we will continue to face a number of risks, including those associated with our ability to reduce expenses, implement any strategic initiatives and generally maintain favorable relationships with and secure the confidence of our customers, suppliers, service providers, employees and other third parties. Accordingly, we cannot guarantee that the proposed financial restructuring will achieve our stated goals nor can we give any assurance of our ability to continue as a going concern.

Operating under the Bankruptcy Court protection for a long period of time may harm our business.

A long period of operations under the protection of the Bankruptcy Court could have a material adverse effect on our business, financial condition, results of operations and liquidity. A prolonged period of operating under Bankruptcy Court protection may also make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships. So long as the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 Cases.

Furthermore, we cannot predict the ultimate terms of settlement of the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from chapter 11 bankruptcy.

We may not be able to obtain confirmation of a plan of reorganization.

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a chapter 11 plan of reorganization, solicit and

obtain the requisite acceptances of such a reorganization plan and fulfill other statutory conditions for confirmation of such a plan. However, even if a plan of reorganization as contemplated by the Amended RSA meets other requirements under the Bankruptcy Code, certain interested parties may file objections to the plan in an effort to persuade the Bankruptcy Court that we have not satisfied the confirmation requirements under section 1129 of the Bankruptcy Code. Even if no objections are filed and the requisite acceptances of our plan are received from creditors entitled to vote on the plan, the Bankruptcy Court, which can exercise substantial discretion, may not confirm the plan of reorganization. The precise requirements and evidentiary requirements for having a plan confirmed, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims).

If a plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

We have substantial liquidity needs and may not be able to obtain sufficient liquidity for the duration of the Chapter 11 Cases or to confirm a plan of reorganization or liquidation.

Although we have lowered our capital budget and reduced the scale of our operations significantly, our business remains capital intensive. In addition to the cash requirements necessary to fund ongoing operations, we have incurred, and expect to continue to incur, significant professional fees and other costs in connection with the Chapter 11 Cases. As of December 31, 2020, our total available liquidity was $825.8 million, which included $325.8 million of cash on hand and $500.0 million available under our DIP Facility. We expect to continue using cash on hand that will further reduce this liquidity. With the Bankruptcy Court’s authorization to use cash collateral under the DIP Credit Agreement, we believe that we will have sufficient liquidity, including cash on hand, to fund anticipated cash requirements through the Chapter 11 Cases. As such, we expect to pay vendor obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders, if any, approving such payments. However, there can be no assurance that our current liquidity will be sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases or to pursue confirmation of a plan of reorganization. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, that such funds will be offered to us on acceptable terms.

As a result of the Chapter 11 Cases, our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections and claims assessments significantly impact our financial results. As a result, our historical financial performance is likely not indicative of financial performance after the date of the bankruptcy filing. In addition, if we emerge from chapter 11, the amounts reported in subsequent periods may materially change relative to historical results, including due to revisions to our operating plans pursuant to a plan of reorganization. We anticipate that we will adopt fresh start accounting upon our emergence from chapter 11, becoming a new entity for financial reporting purposes. As a result, upon emergence, the Company’s assets and liabilities will generally be reported at fair value and will reconcile to the enterprise value confirmed by the Bankruptcy Court. These fair values are expected to differ materially from the amounts reflected on our historical balance sheet.

We may be subject to claims that will not be discharged in the Chapter 11 Cases.

The Bankruptcy Code provides that the confirmation of a plan of reorganization may discharge a debtor from substantially all debts arising prior to the Petition Date. Although the Company intends to pay pre-petition trade claims in full, with few exceptions, all claims that arose before the Petition Date (1) are subject to compromise and/or treatment under a plan of reorganization and/or (2) could be discharged in accordance with the terms of a plan of reorganization. The Bankruptcy Code excepts certain pre-petition claims from discharge for corporate debtors, including certain debts owed to governmental entities obtained by, among other things, false

representations or actual fraud. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on their financial condition and results of operations on a post-reorganization basis.

Our actual financial results may vary significantly from the projections filed with the Bankruptcy Court.

In connection with the plan of reorganization process, we were required to prepare projected financial information to demonstrate to the Bankruptcy Court the feasibility of the restructuring plan and our ability to continue operations upon emergence from bankruptcy. At the time they were last filed with the Bankruptcy Court on December 30, 2020, the projections reflected numerous assumptions concerning anticipated future performance and prevailing and anticipated market and economic conditions that were and continue to be beyond our control and that may not materialize. Further, to the extent we issue new guidance, such projections will supersede any prior guidance. Projections, in any event, are inherently subject to uncertainties and to a wide variety of significant business, economic and competitive risks. Our actual results will vary from those contemplated by our projections and the variations may be material.

The pursuit of the Chapter 11 Cases has consumed and will continue to consume a substantial portion of the time and attention of our management, which may have an adverse effect on our business and results of operations, and we may face increased levels of employee attrition.

While the Chapter 11 Cases continue, our management will be required to spend a significant amount of time and effort focusing on the Chapter 11 Cases instead of focusing exclusively on our business operations. This diversion of attention may have a material adverse effect on the conduct of our business, and, as a result, our financial condition and results of operations, particularly if the Chapter 11 Cases are protracted.

During the duration of the Chapter 11 Cases, our employees will face considerable distraction and uncertainty and we may experience increased levels of employee attrition. A loss of key personnel or material erosion of employee morale could have a material adverse effect on our ability to meet customer expectations, thereby adversely affecting our business and results of operations. The failure to retain or attract members of our management team and other key personnel could impair our ability to execute our strategy and implement operational initiatives, thereby having a material adverse effect on our financial condition and results of operations.

Trading in our securities during the pendency of the Chapter 11 Cases is highly speculative and poses substantial risks. It is possible that our Class A ordinary shares will be cancelled pursuant to the plan of reorganization and holders of any such ordinary shares will receive only such distributions as set forth in the plan of reorganization, which may result in such holders being unable to recover their investments.

A significant amount of our indebtedness is senior to the Class A ordinary shares in our capital structure. It is unclear at this stage of the Chapter 11 Cases if any plan of reorganization would allow for distributions with respect to our Class A ordinary shares and other outstanding equity interests without the consent of the senior debt holders. It is possible that these equity interests may be cancelled and extinguished upon the approval of the Bankruptcy Court and the holders thereof would not be entitled to receive, and would not receive or retain, any property or interest in property on account of such equity interests. In the event of a cancellation of these equity interests, amounts invested by such holders in our outstanding equity securities will not be recoverable. Under the current plan of reorganization, holders of our Class A ordinary shares may be entitled to receive their pro rata share of 7-year warrants to purchase up to 7% of New Equity (subject to dilution). However, if our plan of reorganization is not approved, our currently outstanding Class A ordinary shares may have no value. Trading prices for our Class A ordinary shares are very volatile and may bear little or no relationship to the actual recovery, if any, by the holders of such securities in the Chapter 11 Cases. Accordingly, we urge that extreme caution be exercised with respect to existing and future investments in our equity securities and any of our other securities.

In certain instances, a chapter 11 case may be converted to a case under chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert the Chapter 11 Cases to cases under chapter 7

of the Bankruptcy Code. In such event, a chapter 7 trustee would be appointed or elected to liquidate our assets and the assets of our subsidiaries for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a plan of reorganization because of (1) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (2) additional administrative expenses involved in the appointment of a chapter 7 trustee, and (3) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

Any plan of reorganization that we may implement will be based in large part upon assumptions and analyses developed by us. If these assumptions and analyses prove to be incorrect, our plan may be unsuccessful in its execution.

Any plan of reorganization that we may implement could affect both our capital structure and the ownership, structure and operation of our businesses and will reflect assumptions and analyses based on our experience and perception of historical trends, current conditions and expected future developments, as well as other factors that we consider appropriate under the circumstances. In addition, any plan of reorganization will rely upon financial projections, including with respect to revenues, capital expenditures, debt service and cash flow. Financial forecasts are necessarily speculative, and it is likely that one or more of the assumptions and estimates that are the basis of these financial forecasts will not be accurate. Whether actual future results and developments will be consistent with our expectations and assumptions depends on a number of factors, including but not limited to (1) our ability to substantially change our capital structure, (2) our ability to obtain adequate liquidity and financing sources, (3) our ability to maintain customers’ confidence in our viability as a continuing entity and to attract and retain sufficient business from them, (4) our ability to retain key employees and (5) the overall strength and stability of general economic conditions of the financial and oil and gas industries, both in the U.S. and in global markets. The failure of any of these factors could materially adversely affect the successful reorganization of our businesses. Consequently, there can be no assurance that the results or developments contemplated by any plan of reorganization we may implement will occur or, even if they do occur, that they will have the anticipated effects on us and our subsidiaries or our businesses or operations. The failure of any such results or developments to materialize as anticipated could materially adversely affect the successful execution of any plan of reorganization.

We may not be able to achieve our stated goals and continue as a going concern under a plan of reorganization.

Even if a plan of reorganization is consummated, we will continue to face a number of risks. For example, improvements in demand for offshore drilling services and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized. Accordingly, we cannot guarantee that a plan of reorganization will achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through such plan, we may need to raise additional funds through public or private debt or equity financing or other means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

Our ability to continue as a going concern is dependent upon our ability to raise additional capital. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a chapter 11 plan of reorganization is confirmed.

Our ability to use our NOL carryforwards may be limited by changes in ownership due to the Chapter 11 Cases.

As of December 31, 2020, we had deferred tax assets of $2.3 billion relating to $9.7 billion of NOL carryforwards, $171.2 million for U.S. foreign tax credits (“FTCs”) and $221.2 million for U.S. and U.K. interest limitation carryforwards, which can be used to reduce our income taxes payable in future years. NOL

carryforwards, which were generated in various jurisdictions worldwide, include $9.5 billion that do not expire and $223.0 million that will expire, if not utilized, between 2021 and 2040. Deferred tax assets for NOL carryforwards at December 31, 2020 include $1.4 billion and $687.3 million pertaining to NOL carryforwards in Luxembourg and the United States, respectively. The U.S. FTCs expire between 2021 and 2028. The interest limitation carryforwards do not expire. Due to the uncertainty of realization, we have a $2.7 billion valuation allowance on deferred taxes relating to NOL carryforwards, U.S. FTCs and interest limitation carryforwards.

Under Section 382 of the Internal Revenue Code (“IRC”), changes in our ownership, in certain circumstances, will limit the amount of U.S. NOL carryforwards, FTCs and interest limitation carryforwards that can be utilized annually in the future to offset U.S. taxable income. Calculations pursuant to Section 382 of the IRC can be very complicated and no assurance can be given relative to our ability to utilize our U.S. NOL carryforwards, FTCs and interest limitation carryforwards in the future. If we are limited in our ability to use our U.S. NOL carryforwards, FTCs and interest limitation carryforwards in future years in which we have taxable income, we will pay more taxes than if we were able to utilize them fully. We may experience ownership changes in the future as a result of subsequent shifts in our stock ownership that we cannot predict or control that could result in further limitations being placed on our ability to utilize our U.S. NOL carryforwards, FTCs and interest limitation carryforwards.

Risks Related to Our Business, Operations and Market Conditions

The COVID-19 pandemic and recent developments in the oil and gas industry has, and could continue to, adversely impact our financial condition and results of operations.

The COVID-19 pandemic and related public health measures implemented by governments worldwide have negatively impacted the global macroeconomic environment and resulted in a sharp decline in global oil demand and prices. As of February 2021, crude oil prices have recovered from the historic lows seen in the first half of 2020 and have returned to 2019 prices. However, our customers have generally lowered their capital expenditure plans, in many cases significantly, in light of revised pricing expectations. To date, there have been various impacts from the pandemic and the resultant drop in oil prices, including contract cancellations and the cancellation of drilling programs by operators, contract concessions, stacking rigs, inability to change crews due to travel restrictions, and workforce reductions. Our operations and business may be subject to further disruptions as a result of the spread of coronavirus among our workforce, the extension or imposition of further public health measures affecting our supply chain and logistics, and the impact of the pandemic on key customers, suppliers, and other counterparties. Oil prices are expected to continue to be volatile as a result of the near-term production instability, ongoing COVID-19 outbreaks, the implementation of vaccination programs and the related impact on overall economic activity, changes in oil inventories, industry demand and global and national economic performance.

The success of our business largely depends on the level of activity in the oil and gas industry, which can be significantly affected by volatile oil and natural gas prices.

The success of our business largely depends on the level of activity in offshore oil and natural gas exploration, development and production. Oil and natural gas prices, and market expectations of potential changes in these prices, significantly affect the level of drilling activity. Historically, when drilling activity and operator capital spending decline, utilization and day rates also decline and drilling may be reduced or discontinued, resulting in an oversupply of drilling rigs. The oversupply of drilling rigs will be exacerbated by the entry of newbuild rigs into the market. Oil and natural gas prices have historically been volatile, and have declined significantly from prices in excess of $100 since mid-2014, causing operators to reduce capital spending and cancel or defer existing programs, substantially reducing the opportunities for new drilling contracts. Brent crude averaged nearly $42 per barrel in 2020 with a year-end price of $51. Commodity prices in 2021 have not improved to a level that supports increased rig demand sufficient to absorb existing rig supply and generate meaningful increases in day rates. We expect these trends to continue as long as commodity prices and rig supply remain at current levels. The lack of a meaningful recovery of oil and natural gas prices or further price reductions or volatility in prices may cause our customers to maintain historically low capital spending levels or further reduce their overall level of activity, in

which case demand for our services may further decline and revenues may continue to be adversely affected through lower rig utilization and/or lower day rates. Numerous factors may affect oil and natural gas prices and the level of demand for our services, including:

•regional and global economic conditions and changes therein,

•COVID-19 and related public health measures implemented by governments worldwide and the occurrence or threat of other epidemic or pandemic diseases and any government response to such occurrence or threat,

•oil and natural gas supply and demand,

•expectations regarding future energy prices,

•the ability of the Organization of Petroleum Exporting Countries ("OPEC") to reach further agreements to set and maintain production levels and pricing and to implement existing and future agreements,

•capital allocation decisions by our customers, including the relative economics of offshore development versus onshore prospects,

•the level of production by non-OPEC countries,

•U.S. and non-U.S. tax policy,

•advances in exploration and development technology,

•costs associated with exploring for, developing, producing and delivering oil and natural gas,

•the rate of discovery of new oil and gas reserves and the rate of decline of existing oil and gas reserves,

•laws and government regulations that limit, restrict or prohibit exploration and development of oil and natural gas in various jurisdictions, or materially increase the cost of such exploration and development (such as the current moratorium on oil and gas leasing and permitting in federal lands and waters),

•the development and exploitation of alternative fuels or energy sources and increased demand for electric-powered vehicles,

•disruption to exploration and development activities due to hurricanes and other severe weather conditions and the risk thereof,

•natural disasters or incidents resulting from operating hazards inherent in offshore drilling, such as oil spills, and

•the worldwide military or political environment, including the global macroeconomic effects of trade disputes and increased tariffs and sanctions and uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas of the Middle East or geographic areas in which we operate, or acts of terrorism.

Despite significant declines in capital spending and cancelled or deferred drilling programs by many operators since 2014, oil and gas production has not yet been reduced by amounts sufficient to result in a rebound in pricing to levels seen in 2014, and we may not see sufficient supply reductions or a resulting rebound in pricing for an extended period of time. Further, the agreements of OPEC and certain non-OPEC countries to freeze and/or cut production may not be fully realized. The lack of actual production cuts or freezes, or the perceived risk that OPEC

countries may not comply with such agreements, may result in depressed commodity prices for an extended period of time.

Higher commodity prices may not necessarily translate into increased activity, and even during periods of high commodity prices, customers may cancel or curtail their drilling programs, or reduce their levels of capital expenditure for exploration and production for a variety of reasons, including their expectations for future oil prices and their lack of success in exploration efforts. Advances in onshore exploration and development technologies, particularly with respect to onshore shale, could also result in our customers allocating more of their capital expenditure budgets to onshore exploration and production activities and less to offshore activities. These factors could cause our revenues and profits to decline further, as a result of declines in utilization and day rates, and limit our future growth prospects. Any significant decline in day rates or utilization of our rigs could materially reduce our revenues and profitability. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and obtain insurance coverage that we consider adequate or are otherwise required by our contracts.

The offshore contract drilling industry historically has been highly competitive and cyclical, with periods of low demand and excess rig availability that could result in adverse effects on our business.

Our industry is highly competitive, and our contracts are traditionally awarded on a competitive bid basis. Pricing, safety records and competency are key factors in determining which qualified contractor is awarded a job. Rig availability, location and technical capabilities also can be significant factors in the determination. If we are not able to compete successfully, our revenues and profitability may be reduced.

The offshore contract drilling industry historically has been very cyclical and is primarily related to the demand for drilling rigs and the available supply of drilling rigs. Demand for rigs is directly related to the regional and worldwide levels of offshore exploration and development spending by oil and gas companies, which is beyond our control. Offshore exploration and development spending may fluctuate substantially from year-to-year and from region-to-region.

The significant decline in oil and gas prices and resulting reduction in spending by our customers, together with the increase in supply of offshore drilling rigs in recent years, has resulted in an oversupply of offshore drilling rigs and a decline in utilization and day rates, a situation which may persist for many years.

Such a prolonged period of reduced demand and/or excess rig supply has required us, and may in the future require us, to idle or scrap rigs and enter into low day rate contracts or contracts with unfavorable terms. There can be no assurance that the current demand for drilling rigs will increase in the future. Any further decline in demand for drilling rigs or a continued oversupply of drilling rigs could adversely affect our financial position, operating results or cash flows.

Our business will be adversely affected if we are unable to secure contracts on economically favorable terms or if option periods in existing contracts are not exercised as expected.

Our ability to renew expiring contracts or obtain new contracts and the terms of any such contracts will depend on market conditions. Our customers’ decisions to exercise option periods resulting in additional work for the rig under contract also depend on market conditions. We may be unable to renew our expiring contracts, including contracts expiring for failure by the customer to exercise option periods, or obtain new contracts for the rigs under contracts that have expired or have been terminated, and the day rates under any new contracts or any renegotiated contracts may be substantially below the existing day rates, which could adversely affect our revenues and profitability. In addition, if customers do not exercise option periods under contracts that we currently expect to be exercised, we may face longer downtime associated with the related rig, as we would have difficulty tendering that rig for additional work to cover the option period.

On December 30, 2020, we reached an agreement in principle to amend and assume pursuant to section 365 of the Bankruptcy Code two agreements for the construction of two new rigs, which was subsequently modified through further negotiations. On February 26, 2021, we entered into amended agreements that extend the delivery date for both new rigs to December 31, 2023. The two rigs under construction are currently uncontracted. There is no assurance that we will secure drilling contracts for these rigs, or future rigs we construct or acquire, or that the drilling contracts we may be able to secure will be based upon rates and terms that will provide a reasonable rate of return on these investments. Our failure to secure contracts for these rigs at day rates and terms that result in a reasonable return upon completion of construction may result in a material adverse effect on our financial position, operating results or cash flows.

We have a significant amount of debt. Our debt levels and debt agreement restrictions may limit our liquidity, our ability to obtain additional financing our pursuit of other business opportunities.

As of December 31, 2020, we had $7.1 billion in total debt outstanding, representing approximately 61.9% of our total capitalization. Our current indebtedness may have several important effects on our future operations, including:

•a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest, and

•our ability to access capital markets, refinance our existing indebtedness, raise capital on favorable terms, or obtain additional financing to fund working capital requirements, capital expenditures, acquisitions, debt service requirements, execution of our business strategy and general corporate or other cash requirements may be limited.

Our ability to maintain a sufficient level of liquidity to meet our financial obligations will be dependent upon our future performance, which will be subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control. For 2020 and 2019, our cash flows from operating activities of continuing operations were negative $251.7 million and $276.9 million, respectively, and we further incurred capital expenditures on continuing operations of $93.8 million and $227.0 million, respectively. Our operating activities and capital expenditures are expected to continue to result in negative annual cash flow in 2021. Meaningful recovery in drilling demand and day rates are required for annual cash flow to turn positive.

To the extent we are unable to repay our debt and other obligations as they become due with cash on hand or from other sources, we will need to restructure or refinance all or part of our debt, sell assets, reduce capital expenditures, borrow more cash or raise equity. Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing debt and other obligations, or if available, such additional debt or equity financing may not be available in a sufficient amount, on a timely basis, or on terms acceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell additional assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale.

Our revolving credit facility places restrictions on us and certain of our subsidiaries with respect to incurring additional indebtedness and liens, paying dividends and other payments to shareholders, repurchasing our ordinary shares, repurchasing or redeeming certain other indebtedness which matures after the revolving credit facility, entering into mergers and other matters. Our revolving credit facility also requires compliance with covenants to maintain specified financial and guarantee coverage ratios, including a total debt to total capitalization ratio that is less than or equal to 60%. As of December 31, 2020, our total debt to total capitalization ratio was 61.9%.

As of August 19, 2020, we have been in default under certain of our debt instruments. Our filing of the Chapter 11 Cases accelerated our obligations under the Senior Notes (as defined below). Additionally, events of

default under the indentures governing our Senior Notes have occurred and are continuing, including as a result of cross-defaults between such indentures.

Our customers may be unable or unwilling to fulfill their contractual commitments to us, including their obligations to pay for losses, damages or other liabilities.

Certain of our customers are subject to liquidity risk and such risk could lead them to seek to repudiate, cancel or renegotiate our drilling contracts or fail to fulfill their commitments to us under those contracts. These risks are heightened in periods of depressed market conditions. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well-control, reservoir liability and pollution. Our drilling contracts also provide for varying levels of indemnification and allocation of liabilities between our customers and us with respect to loss or damage to property and injury or death to persons arising from the drilling operations we perform. Under our drilling contracts, liability with respect to personnel and property customarily is allocated so that we and our customers each assume liability for our respective personnel and property. Our customers have historically assumed most of the responsibility for and indemnified us from any loss, damage or other liability resulting from pollution or contamination, including clean-up and removal and third-party damages arising from operations under the contract when the source of the pollution originates from the well or reservoir, including those resulting from blow-outs or cratering of the well. However, we regularly are required to assume a limited amount of liability for pollution damage caused by our negligence, which liability generally has caps for ordinary negligence, with much higher caps or unlimited liability where the damage is caused by our gross negligence or willful misconduct. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to assume their responsibility and honor their indemnity to us for such losses. In addition, under the laws of certain jurisdictions, such indemnities under certain circumstances are not enforceable if the cause of the damage was our gross negligence or willful misconduct. This could result in us having to assume liabilities in excess of those agreed in our contracts due to customer balance sheet or liquidity issues or applicable law.

We may suffer losses if our customers terminate or seek to renegotiate our contracts, if operations are suspended or interrupted or if a rig becomes a total loss.

In market downturns similar to the current environment, our customers may not be able to honor the terms of existing contracts, may terminate contracts even where there may be onerous termination fees, may seek to void or otherwise repudiate our contracts including by claiming we have breached the contract, or may seek to renegotiate contract day rates and terms in light of depressed market conditions. Since early 2015, we have renegotiated a number of contracts and received termination notices with respect to several of our rigs. Often, our drilling contracts are subject to termination without cause or termination for convenience upon notice by the customer. In certain cases, our contracts require the customer to pay an early termination fee in the event of a termination for convenience (without cause). Such payment would provide some level of compensation to us for the lost revenue from the contract but in many cases would not fully compensate us for all of the lost revenue. Certain of our contracts permit termination by the customer without an early termination fee. Furthermore, financially distressed customers may seek to negotiate reduced termination fees as part of a restructuring package. During 2020, the offshore drilling market suffered serious negative effects in relation to the COVID-19 pandemic and a significant drop in oil and gas commodity prices. Global economic shutdowns driven by COVID-19 served to exacerbate the reduction in world demand for oil and gas which then prompted operators to slash budgets and defer, cancel and/or renegotiate rates for existing contracts.

Drilling contracts customarily specify automatic termination or termination at the option of the customer in the event of a total loss of the drilling rig and often include provisions addressing termination rights or reduction or cessation of day rates if operations are suspended or interrupted for extended periods due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.

If a customer cancels a contract or if we terminate a contract due to the customer’s breach and, in either case, we are unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is disputed or suspended for an extended period of time or renegotiated, it could materially and adversely affect our financial position, operating results or cash flows.

We may incur impairments as a result of future declines in demand for offshore drilling rigs.

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. The offshore drilling industry historically has been highly cyclical, and it is not unusual for rigs to be idle or underutilized for significant periods of time and subsequently resume full or near full utilization when business cycles change. Likewise, during periods in which rig supply exceeds rig demand, competition may force us to contract our rigs at or near cash break-even rates for extended periods of time.

Since 2014 we have recorded pre-tax, non-cash losses on impairment of long-lived assets totaling $9.0 billion, including $3.6 billion aggregate pre-tax, non-cash impairments with respect to certain floaters, jackups and spare equipment, which we recorded during the first and second quarters of 2020. Further asset impairments may be necessary if market conditions remain depressed for longer than we expect. See "N ote 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

The loss of a significant customer or customer contract could adversely affect us.

We provide our services to major international, government-owned and independent oil and gas companies. During 2020, our five largest customers accounted for 41% of our consolidated revenues in the aggregate, with our largest customer representing 11% of our consolidated revenues and a significant percentage of our operating cash flows. Our ability to retain existing significant customers may be adversely affected by the ongoing Chapter 11 Cases and certain of our largest customers have discussed with us our financial viability to perform for the duration of the potential terms of new contracts. Our financial position, operating results or cash flows may be materially adversely affected if any of our higher day rate contracts were terminated or renegotiated on less favorable terms or if a major customer terminates its contracts with us, fails to renew its existing contracts with us, requires renegotiation of our contracts or declines to award new contracts to us.

Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future.

As of December 31, 2020, our contract backlog was approximately $1.2 billion, which represents a decline of $1.2 billion to the reported backlog of $2.5 billion as of December 31, 2019. This amount reflects the remaining contractual terms multiplied by the applicable contractual day rate. The contractual revenue may be higher than the actual revenue we ultimately receive because of a number of factors, including rig downtime or suspension of operations. Several factors could cause rig downtime or a suspension of operations, many of which are beyond our control, including:

•the early termination, repudiation or renegotiation of contracts,

•breakdowns of equipment,

•work stoppages, including labor strikes,

•shortages of material or skilled labor,

•surveys by government and maritime authorities,

•periodic classification surveys,

•severe weather, strong ocean currents or harsh operating conditions,

•the occurrence or threat of epidemic or pandemic diseases and any government response to such occurrence or threat, and

•force majeure events.

Our customers may seek to terminate, repudiate or renegotiate our drilling contracts for various reasons. Generally, our drilling contracts permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in certain cases without making an early termination payment to us. There can be no assurances that our customers will be able to or willing to fulfill their contractual commitments to us.

The decline in oil prices and the resulting downward pressure on utilization has caused and may continue to cause some customers to consider early termination of select contracts despite having to pay onerous early termination fees in certain cases. Customers may continue to request to renegotiate the terms of existing contracts, or they may request early termination or seek to repudiate contracts in some circumstances. Furthermore, as our existing contracts expire, we may be unable to secure new contracts for our rigs. Therefore, revenues recorded in future periods could differ materially from our current backlog. Our inability to realize the full amount of our contract backlog may have a material adverse effect on our financial position, operating results or cash flows.

We may not realize the expected benefits of the ARO joint venture, which depends on a single customer for its income and accounts receivable, and our inability to realize such benefits may introduce additional risks to our business.

In November 2016, Rowan and Saudi Aramco announced plans to form a 50/50 joint venture with Rowan and Saudi Aramco each selling existing drilling rigs and contributing capital as the foundation of the new company. The new entity, Saudi Aramco Rowan Offshore Drilling Company (ARO) commenced operations on October 17, 2017, and is expected to add up to 20 newbuild jackup rigs to its fleet over an approximate 10 year period. In January 2020, ARO ordered the first two newbuild jackups for delivery scheduled in 2022. There can be no assurance that the new jackup rigs will begin operations as anticipated or we will realize the expected return on our investment. We may also experience difficulty jointly managing the venture. Further, in the event ARO has insufficient cash from operations or is unable to obtain third party financing, we may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion. Any required capital contributions we make will negatively impact our liquidity position and financial condition. In 2017 and 2018, Rowan issued 10-year shareholder notes receivables to ARO, which are governed by the laws of Saudi Arabia, earn interest at LIBOR plus two percent and mature during 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 notes receivable may be reduced by future Company obligations to the joint venture. In the event of a dispute with ARO over the repayment of the long-term notes receivable, our ability to enforce the payment obligations of ARO or to exercise other remedies are subject to several significant limitations, including that our ability to accelerate outstanding amounts under the long-term notes receivable is subject to the consent of Saudi Aramco and that the long-term notes receivable are governed by the laws of Saudi Arabia and we are limited to the remedies available under Saudi law.

As a result of these risks, it may take longer than expected for us to realize the expected returns from ARO or such returns may ultimately be less than anticipated. Additionally, if we are unable to make any required contributions, our ownership in ARO could be diluted which could hinder our ability to effectively manage ARO and adversely impact our operating results or financial condition.

ARO’s income and accounts receivable are concentrated with one customer. The loss of this customer, or a substantial decrease in demand by this customer for ARO’s services, would have a material adverse effect on ARO’s business, results of operations and financial condition, which could adversely impact our operating results or financial condition.

ARO, as a provider of offshore drilling services, faces many of the same risks as we face. Operating through ARO, in which we have a shared interest, may result in our having less control over many decisions made with respect to projects, operations, safety, utilization, internal controls and other operating and financial matters. ARO may not apply the same controls and policies that we follow to manage our risks, and ARO’s controls and policies may not be as effective. As a result, operational, financial and control issues may arise, which could have a material adverse effect on our financial condition and results of operations. Additionally, in order to establish or preserve our relationship with our joint venture partner we may agree to risks and contributions of resources that are proportionately greater than the returns we could receive, which could reduce our income and return on our investment in ARO compared to what we may traditionally require in other areas of our business.

We have taken, and continue to take, cost-reduction actions, which may not be successful.

After announcing significant synergy targets and cost savings in connection with the Rowan Transaction, we are implementing these and additional cost savings opportunities. As we implement these synergy and cost-saving initiatives, we may not realize anticipated savings or other benefits from one or more of the initiatives in the amounts or within the time periods we expect. The cost-reduction actions could negatively impact or disrupt our operations. The impact of these cost-reduction actions on our operations may be influenced by many factors, including declines in employee morale and the potential inability to meet operational targets due to our inability to retain or recruit key employees. Additionally, the cost-reduction actions could lead to the deterioration or failure of our operational and financial controls due to an inability to properly control and manage change, employee attrition, financial and operating system conversion and other factors that could adversely impact our business during the implementation or respective cost-reduction initiatives. If we experience any of these circumstances or otherwise fail to realize the anticipated savings or benefits from our synergy and cost-saving initiatives, our financial condition, results of operations and cash flows could be materially and adversely affected.

We may have difficulty obtaining or maintaining insurance in the future on terms we find acceptable and our insurance coverage may not protect us against all of the risks and hazards we face, including those specific to offshore operations.

Our operations are subject to hazards inherent in the offshore drilling industry, such as blow-outs, reservoir damage, loss of production, loss of well-control, uncontrolled formation pressures, lost or stuck drill strings, equipment failures and mechanical breakdowns, punchthroughs, craterings, industrial accidents, fires, explosions, oil spills and pollution. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, which could lead to claims by third parties or customers, suspension of operations and contract terminations. Our fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as punch-throughs, capsizing, sinking, grounding, collision, damage from severe weather and marine life infestations. Additionally, a cyber-attack or other security breach of our information systems or other technological failure could lead to a material disruption of our operations, information systems and/or loss of business information, which could result in an adverse impact to our business. Our drilling contracts provide for varying levels of indemnification from our customers, including with respect to well-control and subsurface risks. For example, most of our drilling contracts incorporate a broad exclusion that limits the customer's indemnity rights for damages and losses resulting from our gross negligence and willful misconduct and for fines and penalties and punitive damages levied or assessed directly against us. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurance coverage for various business risks.

We generally identify the operational hazards for which we will procure insurance coverage based on the likelihood of loss, the potential magnitude of loss, the cost of coverage, the requirements of our customer contracts and applicable legal requirements. Although we maintain what we believe to be an appropriate level of insurance covering hazards and risks we currently encounter during our operations, no assurance can be given that we will be able to obtain insurance against all potential risks and hazards, or that we will be able to maintain the same levels and types of coverage that we have maintained in the past. Our financial leverage and negative cash flow could cause insurance companies to increase our premiums and deductibles or limit our coverage amounts.

As a result of climate change activism or increased costs to insurance companies due to regulatory, geopolitical or other developments, insurance companies that have historically participated in underwriting energy-related risks may discontinue that practice, may reduce the insurance capacity they are willing to offer or demand significantly higher premiums or deductibles to cover these risks. Additionally, a significant number of energy-related insurance claims may increase insurance premiums to energy companies.

Furthermore, our insurance carriers may interpret our insurance policies such that they do not cover losses for all of our claims. Our insurance policies may also have exclusions of coverage for some losses. Uninsured exposures may include radiation hazards, certain loss or damage to property onboard our rigs and losses relating to terrorist acts or strikes.

If we are unable to obtain or maintain adequate insurance at rates and with deductibles or retention amounts that we consider commercially reasonable, we may choose to forgo insurance coverage and retain the associated risk of loss or damage.

If a significant accident or other event occurs and is not fully covered by insurance or contractual indemnity (or if our contractual indemnity is not enforceable under applicable law or our clients are unable to meet their indemnification obligation), it could adversely affect our financial position, operating results or cash flows.

The potential for U.S. Gulf of Mexico hurricane related windstorm damage or liabilities could result in uninsured losses and may cause us to alter our operating procedures during hurricane season.

Certain areas of the world such as the U.S. Gulf of Mexico experience hurricanes or similar extreme weather conditions on a relatively frequent basis. Some of our drilling rigs in the U.S. Gulf of Mexico are located in areas that could cause them to be susceptible to damage and/or total loss by these storms, and we have a larger concentration of jack-up rigs in the U.S. Gulf of Mexico than most of our competitors. We had four jackup rigs and four floaters in the U.S. Gulf of Mexico as of December 31, 2020. Damage caused by high winds and turbulent seas could result in rig loss or damage, termination of drilling contracts for lost or severely damaged rigs or curtailment of operations on damaged drilling rigs with reduced or suspended day rates for significant periods of time until the damage can be repaired. Moreover, even if our drilling rigs are not directly damaged by such storms, we may experience disruptions in our operations due to damage to our customers' platforms and other related facilities in the area. Our drilling operations in the U.S. Gulf of Mexico have been impacted by hurricanes in the past, including the total loss of drilling rigs, with associated losses of contract revenues and potential liabilities.

Insurance companies incurred substantial losses in the offshore drilling, exploration and production industries as a consequence of hurricanes that occurred in the U.S. Gulf of Mexico during 2004, 2005 and 2008. Accordingly, insurance companies have substantially reduced the nature and amount of insurance coverage available for losses arising from named tropical storm or hurricane damage in the U.S. Gulf of Mexico and have dramatically increased the cost of available windstorm coverage. The tight insurance market not only applies to coverage related to U.S. Gulf of Mexico windstorm damage or loss of our drilling rigs, but also impacts coverage for any potential liabilities to third parties associated with property damage, personal injury or death and environmental liabilities, as well as coverage for removal of wreckage and debris associated with hurricane losses. It is likely that the tight insurance market for windstorm damage, liabilities and removal of wreckage and debris will continue into the foreseeable future.

We have not purchased windstorm insurance for hull and machinery losses to our floaters arising from windstorm damage in the U.S. Gulf of Mexico due to the significant premium, high deductible and limited coverage for windstorm damage. We believe it is no longer customary for drilling contractors with similar size and fleet composition to purchase windstorm insurance for rigs in the U.S. Gulf of Mexico for the aforementioned reasons. Accordingly, we have retained the risk of loss or damage for our jackups and floaters arising from windstorm damage in the U.S. Gulf of Mexico.

We have established operational procedures designed to mitigate risk to our jackups in the U.S. Gulf of Mexico during hurricane season, and these procedures may, on occasion, result in a decision to decline to operate on a customer-designated location during hurricane season notwithstanding that the location, water depth and other standard operating conditions are within a rig's normal operating range. Our procedures and the associated regulatory requirements addressing drilling rig operations in the U.S. Gulf of Mexico during hurricane season, coupled with our decision to retain (self-insure) certain windstorm-related risks, may result in a significant reduction in the utilization of our jackups in the U.S. Gulf of Mexico.

Our annual insurance policies are up for renewal effective May 31, 2021, and any retained exposures for property loss or damage and wreckage and debris removal or other liabilities associated with U.S. Gulf of Mexico tropical storms or hurricanes may have a material adverse effect on our financial position, operating results or cash flows if we sustain significant uninsured or underinsured losses or liabilities as a result of these storms or hurricanes.

Our drilling contracts with national oil companies may expose us to greater risks than we normally assume in drilling contracts with non-governmental customers.

We currently own and operate ten rigs that are contracted with national oil companies. The terms of these contracts are often non-negotiable and may expose us to greater commercial, political and operational risks than we assume in other contracts, such as exposure to materially greater environmental liability, personal injury and other claims for damages (including consequential damages), or the risk that the contract may be terminated by our customer without cause on short-term notice, contractually or by governmental action, under certain conditions that may not provide us with an early termination payment. We can provide no assurance that the increased risk exposure will not have an adverse impact on our future operations or that we will not increase the number of rigs contracted to national oil companies with commensurate additional contractual risks.

Geopolitical events and violence could affect the markets for our services and have a material adverse effect on our business and cost and availability of insurance.

Geopolitical events have resulted in military actions, terrorist, pirate and other armed attacks, civil unrest, political demonstrations, mass strikes and government responses. Military action by the United States or other nations could escalate, and acts of terrorism, piracy, kidnapping, extortion, acts of war, violence, civil war or general disorder may initiate or continue. Such acts could be directed against companies such as ours. Such developments have caused instability in the world’s financial and insurance markets in the past. In addition, these developments could lead to increased volatility in prices for oil and natural gas and could affect the markets for our services, particularly to the extent that such events take place in regions with significant oil and natural gas reserves, refining facilities or transportation infrastructure, such as the Persian Gulf area. Insurance premiums could increase and coverage for these kinds of events may be unavailable in the future. Any or all of these effects could have a material adverse effect on our financial position, operating results or cash flows.

Rig construction, upgrade, enhancement and reactivation projects are subject to risks, including delays and cost overruns, which could have a material adverse effect on our financial position, operating results or cash flows.

We currently have two ultra-deepwater drillships under construction. In the future, we may construct additional rigs and continue to upgrade the capability and extend the service lives of our existing rigs. As a result of current market conditions, we may seek to delay delivery of our rigs under construction. During the third quarter of 2019, we entered into amendments to our construction agreements with the shipyard for the VALARIS DS-13 and VALARIS DS-14 rigs to provide for two-year extensions of the delivery date of each rig into 2021 and 2022, respectively. On December 30, 2020, we reached an agreement in principle to amend and assume pursuant to section 365 of the Bankruptcy Code the two construction agreements, which was subsequently modified through further negotiations. On February 26, 2021, we entered into amended agreements that extend the delivery date for both new rigs to December 31, 2023. During periods of heightened rig construction projects, shipyards and third-party equipment vendors may be under significant resource constraints to meet delivery obligations. Such

constraints may lead to substantial delivery and commissioning delays, equipment failures and/or quality deficiencies. Furthermore, new drilling rigs may face start-up or other operational complications following completion of construction, upgrades or maintenance. Other unexpected difficulties, including equipment failures, design or engineering problems, could result in significant downtime at reduced or zero day rates or the cancellation or termination of drilling contracts.

Rig construction, upgrade, life extension and repair projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:

•failure of third-party equipment to meet quality and/or performance standards,

•delays in equipment deliveries or shipyard construction,

•shortages of materials or skilled labor,

•damage to shipyard facilities or construction work-in-progress, including damage resulting from fire, explosion, flooding, severe weather, terrorism, war or other armed hostilities,

•unforeseen design or engineering problems, including those relating to the commissioning of newly designed equipment,

•unanticipated actual or purported change orders,

•strikes, labor disputes or work stoppages,

•financial or operating difficulties of equipment vendors or the shipyard while constructing, enhancing, upgrading, improving or repairing a rig or rigs,

•unanticipated cost increases,

•foreign currency exchange rate fluctuations impacting overall cost,

•inability to obtain the requisite permits or approvals,

•client acceptance delays,

•disputes with shipyards and suppliers,

•latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates and assumptions,

•claims of force majeure events, and

•additional risks inherent to shipyard projects in a non-U.S. location.

With respect to VALARIS DS-13 and VALARIS DS-14, if we were to secure contracts for these rigs, we would be subject to the risk of delays and other hazards impacting the viability of such contracts, which could have a material adverse effect on our financial position, operating results or cash flows.

In addition, we believe the costs required to reactivate a stacked rig and return the rig to drilling service are significant. Depending on the length of time that a rig has been stacked, we may incur significant costs to restore the rig to drilling capability, which may also include capital expenditures due to the possible technological obsolescence of the rig. In the future, market conditions may not justify these expenditures or enable us to operate our older rigs profitably during the remainder of their economic lives. We can provide no assurance that we will have access to adequate or economical sources of capital to fund the return of stacked rigs to drilling service.

Failure to recruit and retain skilled personnel could adversely affect our business.

We require skilled personnel to operate our drilling rigs and to provide technical services and support for

our business. Historically, competition for the labor required for drilling operations and construction projects was intense as the number of rigs activated, added to worldwide fleets or under construction increased, leading to shortages of qualified personnel in the industry. During such periods of intensified competition, it is more difficult and costly to recruit and retain qualified employees, especially in foreign countries that require a certain percentage of national employees. The recent prolonged industry downturn and reductions in offshore personnel wages may further reduce the number of qualified personnel available. If competition for labor were to intensify in the future, we could experience an increase in operating expenses, with a resulting reduction in net income, and our ability to fully staff and operate our rigs could be negatively affected.

We may be required to maintain or increase existing levels of compensation to retain our skilled workforce, especially if our competitors raise their wage rates. We also are subject to potential legislative or regulatory action that may impact working conditions, paid time off or other conditions of employment. These conditions could further increase our costs or limit our ability to fully staff and operate our rigs.

We have historically made substantial capital expenditures to maintain our fleet to comply with laws and the applicable regulations and standards of governmental authorities and organizations, or to expand our fleet, and we may be required to make significant capital expenditures to maintain our competitiveness.

We have historically made substantial capital expenditures to maintain our fleet. These expenditures could increase as a result of changes in:

•offshore drilling technology,

•the cost of labor and materials,

•customer requirements,

•fleet size,

•the cost of replacement parts for existing drilling rigs,

•the geographic location of the drilling rigs,

•length of drilling contracts,

•governmental regulations and maritime self-regulatory organization and technical standards relating to safety, security or the environment, and

•industry standards.

Changes in offshore drilling technology, customer requirements for new or upgraded equipment and competition within our industry may require us to make significant capital expenditures in order to maintain our competitiveness. In addition, changes in governmental regulations relating to safety or equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. As a result, we may be required to take our rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. In the future, market conditions may not justify these expenditures or enable us to operate our older rigs profitably during the remainder of their economic useful lives.

Additionally, in order to expand our fleet, we may require additional capital in the future. If we are unable to fund capital with cash flows from operations or proceeds from sales of non-core assets, we may be required to either incur additional borrowings or raise capital through the sale of debt or equity securities. Our ability to access the capital markets may be limited by our financial condition at the time, by changes in laws and regulations (or

interpretation thereof) and by adverse market conditions resulting from, among others, general economic conditions, contingencies and uncertainties that are beyond our control. Similarly, when lenders and institutional investors reduce, and in some cases cease to provide, funding to industry borrowers, the liquidity and financial condition of us and our customers can be adversely impacted. If we raise funds by issuing equity securities, existing shareholders may experience dilution. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business and on our financial position, operating results or cash flows.

Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.

Outside of the U.S., we are often subject to collective bargaining agreements that require periodic salary negotiations, which usually result in higher personnel expenses and other benefits. Efforts have been made from time to time to unionize other portions of our workforce. In addition, we have been subjected to strikes or work stoppages and other labor disruptions in certain countries. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.

Certain legal obligations require us to contribute certain amounts to retirement funds or other benefit plans and restrict our ability to dismiss employees. Future regulations or court interpretations established in the countries in which we conduct our operations could increase our costs and materially adversely affect our business, financial position, operating results or cash flows.

Significant part or equipment shortages, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.

Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our operations exposes us to potential volatility in the quality, prices and availability of such items. Certain high-specification parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers, or in some cases must be sourced through a single supplier, manufacturer or service provider. Recent deterioration in the business environment has reduced the number of available suppliers, and the imposition of further public health measures affecting supply chain and logistics due to the COVID-19 pandemic may negatively impact our suppliers. Additionally, the longer that our Chapter 11 Cases continue, the more likely it is that our suppliers will lose confidence in our ability to reorganize our business successfully and will seek to establish alternative commercial relationships. A disruption in the deliveries from such third-party suppliers, manufacturers or service providers, capacity constraints, production disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment could adversely affect our ability to meet our commitments to customers, thus adversely impacting our operations and revenues and/or our operating costs.

Our long-term contracts are subject to the risk of cost increases, which could adversely impact our profitability.

In general, our costs increase as the demand for contract drilling services and skilled labor increases. While some of our contracts include cost escalation provisions that allow changes to our day rate based on stipulated cost increases or decreases, the timing and amount earned from these day rate adjustments may differ from our actual increase in costs and many contracts do not allow for such day rate adjustments. During times of reduced demand, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking, after which time the crew members are assigned to active rigs or dismissed. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. In general, labor costs increase primarily due to higher salary levels and inflation. Equipment maintenance expenses fluctuate depending upon the type of activity a drilling rig is performing and the age and condition of the equipment. Contract preparation expenses vary based on the scope and length of contract preparation required.

Our information technology systems, including rig operating systems, are subject to cybersecurity risks and threats.

We depend on technologies, systems and networks to conduct our offshore and onshore operations, to collect payments from customers and to pay vendors and employees. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. The risks associated with cyber incidents and attacks on our information technology systems could include disruptions of certain systems on our rigs; other impairments of our ability to conduct our operations; loss of intellectual property, proprietary information or customer and vendor data; disruption of our or our customers' operations; and increased costs to prevent, respond to or mitigate cybersecurity events. Any such breach or attack could result in injury to people, loss of control of, or damage to, our (or our customer's) assets, or harm to the environment. Any such breach or attack could also compromise our networks or our customers' and vendors' networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in significant fines, civil and/or criminal claims or proceedings, including under data privacy laws and regulations such as the European Union General Data Protection Regulation and, with effect from January 1, 2021, such regulation as amended and forming part of the law of the United Kingdom, disruption to our operations and damage our reputation, which could adversely affect our financial position, operating results or cash flows. In the past, we have experienced data security breaches resulting from unauthorized access to our systems, which to date have not had a material impact on our operations; however, there can be no assurance that such impacts will not be material in the future.

Risk Related to Our Indebtedness and Ordinary Shares

Our Class A ordinary shares have been delisted from the NYSE.

Effective September 14, 2020, our Class A ordinary shares were delisted from the NYSE. Since August 19, 2020, our shares have been traded on the OTC Pink Open Market under the symbol “VALPQ.” We can provide no assurance that our ordinary shares will continue to trade on this market, whether broker-dealers will continue to provide public quotes of our ordinary shares on this market, whether the trading volume of our ordinary shares will be sufficient to provide for an efficient trading market or whether quotes for our ordinary shares will continue on this market in the future, which could result in significantly lower trading volumes and reduced liquidity for investors seeking to buy or sell our ordinary shares.

The accounting method for our 2024 Convertible Notes could have a material effect on our reported financial results.

Based on our current plan of reorganization, we expect our 3.00% exchangeable senior notes due 2024 (the “2024 Convertible Notes”) to be cancelled with holders receiving the treatment as set forth in the plan of reorganization. However, to the extent the 2024 Convertible Notes (as defined below) are not cancelled, under U.S. GAAP, we must separately account for the liability and equity components of convertible debt instruments, such as our 2024 Convertible Notes in a manner that reflects the issuer’s economic interest cost. The equity component representing the conversion feature is recorded in additional paid-in capital within the shareholders’ equity section of our consolidated balance sheet. The equity component is not remeasured if we continue to meet certain conditions for equity classification under U.S. GAAP, including maintaining the ability to settle the 2024 Convertible Notes entirely in shares. During periods in which we are unable to meet the conditions for equity classification, the equity component or a portion thereof would be remeasured through earnings, which could adversely affect our operating results.

If the 2024 Convertible are not cancelled pursuant to our plan reorganization, upon conversion of the 2024 Convertible Notes, holders will receive cash, our Class A ordinary shares or a combination thereof, at our election. Our intent is to settle the principal amount of the 2024 Convertible Notes in cash upon conversion. If the conversion value exceeds the principal amount (i.e., our share price exceeds the exchange price on the date of conversion), we expect to deliver shares equal to our conversion obligation in excess of the principal amount. During each respective reporting period that our average share price exceeds the exchange price, an assumed number of shares required to

settle the conversion obligation in excess of the principal amount will be included in the denominator for our computation of diluted earnings per share using the treasury stock method. If we are unable to demonstrate our intent to settle the principal amount in cash, or are otherwise unable to utilize the treasury stock method, our diluted earnings per share would be adversely affected. See "Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes.

Transfers of our Class A ordinary shares may be subject to stamp duty or stamp duty reserve tax (“SDRT”) in the U.K., which would increase the cost of dealing in our Class A ordinary shares.

Stamp duty and/or SDRT are imposed in the U.K. on certain transfers of chargeable securities (which include shares in companies incorporated in the U.K.) at a rate of 0.5% of the consideration paid for the transfer. Certain transfers of shares to depositary receipt facilities or clearance systems providers are charged at a higher rate of 1.5%.

Pursuant to arrangements that we entered into with the Depository Trust Company (“DTC”), our Class A ordinary shares are eligible to be held in book entry form through the facilities of DTC. Transfers of shares held in book entry form through DTC will not attract a charge to stamp duty or SDRT in the U.K. A transfer of the shares from within the DTC system out of DTC and any subsequent transfers that occur entirely outside the DTC system will attract a charge to stamp duty at a rate of 0.5% of any consideration, which is payable by the transferee of the shares. Any such duty must be paid (and the relevant transfer document stamped by Her Majesty's Revenue & Customs (“HMRC”)) before the transfer can be registered in the share register of Valaris plc. If a shareholder decides to redeposit shares into DTC, the redeposit will attract SDRT at a rate of 1.5% of the value of the shares.

We have put in place arrangements with our transfer agent to require that shares held in certificated form cannot be transferred into the DTC system until the transferor of the shares has first delivered the shares to a depository specified by us so that SDRT may be collected in connection with the initial delivery to the depository. Any such shares will be evidenced by a receipt issued by the depository. Before the transfer can be registered in our share register, the transferor will also be required to provide the transfer agent sufficient funds to settle the resultant liability for SDRT, which will be charged at a rate of 1.5% of the value of the shares.

Following decisions of the European Court of Justice and the U.K. First-tier Tax Tribunal, HMRC announced that it would not seek to apply a charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into a depositary receipt facility or clearance system provider, such as DTC. Further, in its 2017 Autumn Budget the U.K. government announced that it would not reintroduce the Stamp Duty and Stamp Duty Reserve Tax 1.5% charge on the issue of shares (and transfers integral to capital raising) into overseas clearance services and depositary receipt systems following the U.K.’s exit from the European Union. However, it is possible that the U.K. government may change or enact laws applicable to stamp duty or SDRT, which could have a material effect on the cost of trading in our shares.

If our Class A ordinary shares are not eligible for continued deposit and clearing within the facilities of DTC, then transactions in our securities may be disrupted.

The facilities of DTC are widely-used for rapid electronic transfers of securities between participants within the DTC system, which include numerous major international financial institutions and brokerage firms. Currently, all trades of our Class A ordinary shares on the OTC Pink Open Market are cleared and settled on the facilities of DTC. Our Class A ordinary shares are, at present, eligible for deposit and clearing within the DTC system, pursuant to arrangements with DTC whereby DTC accepted our Class A ordinary shares for deposit, clearing and settlement services, and we agreed to indemnify DTC for any stamp duty and/or SDRT that may be assessed upon it as a result of its service as a clearance system provider for our Class A ordinary shares. However, DTC retains sole discretion to cease to act as a clearance system provider for our Class A ordinary shares at any time.

If DTC determines at any time that our shares are no longer eligible for deposit, clearing and settlement services within its facilities, trading in such shares would be disrupted. In this event, DTC has agreed it will provide us advance notice and assist us, to the extent possible, with efforts to mitigate adverse consequences. While we would pursue alternative arrangements to preserve our listing and maintain trading, any such disruption could have a material adverse effect on the trading price of our Class A ordinary shares.

We have less flexibility as a U.K. public limited company with respect to certain aspects of capital management than U.S. corporations due to increased shareholder approval requirements.

Directors of Delaware and other U.S. corporations may issue, without further shareholder approval, shares of common stock authorized in their certificates of incorporation that were not already issued or reserved. The business corporation laws of Delaware and other U.S. states also provide substantial flexibility in establishing the terms of preferred stock. However, English law provides that a board of directors of a U.K. public limited company may only allot shares with the prior authorization of an ordinary resolution of the company’s shareholders, which authorization must state the maximum amount of shares that may be allotted under it and specify the date on which it will expire, which must not be more than five years from the date on which the shareholder resolution is passed. An ordinary resolution was passed by shareholders at our last annual general meeting on June 15, 2020 to authorize the allotment of up to a prescribed amount of additional shares until the conclusion of the next annual general meeting or the close of business on August 19, 2021 (whichever is earlier).

English law also generally provides shareholders pre-emption rights over new shares that are issued for cash. However, it is possible, where the board of directors is generally authorized to allot shares, to exclude pre-emption rights by a special resolution of the shareholders or by a provision in the articles of association. Such exclusion of pre-emption rights will commonly cease to have effect at the same time as the general allotment authority to which it relates is revoked or expires. If the general allotment authority is renewed, the authority excluding pre-emption rights may also be renewed by a special resolution of the shareholders. Two special resolutions were passed, in conjunction with an allotment authority at our last annual general meeting on June 15, 2020, to disapply pre-emption rights in respect of new shares up to a prescribed amount, both generally and in connection with an acquisition or specified capital investment, until the conclusion of the next annual general meeting or the close of business on August 19, 2021 (whichever is earlier).

Our shares are not traded on a “recognized investment exchange” for the purposes of English law and we are therefore only able to conduct “off-market” purchases of our shares. English law generally prohibits a company from repurchasing its own shares by way of "off-market" purchases without approval by ordinary resolution of the shareholders of the terms of the contract by which the purchase(s) is affected. Such approval may only last for a maximum period of five years after the date on which the resolution is passed. An ordinary resolution was passed at our annual shareholder meeting on May 21, 2018 authorizing us to make "off-market" purchases of our own shares pursuant to certain purchase agreements for a five-year term.

We can provide no assurances that future shareholder approvals required for the matters described above will be forthcoming. If all or any of such approvals are not granted, our flexibility with respect to certain capital management matters could be reduced which could, in turn, deprive our shareholders of substantial benefits.

Our articles of association contain anti-takeover provisions; however, the Company is not subject to the U.K.'s City Code on Takeovers and Mergers.

Certain provisions of our articles of association have anti-takeover effects, such as the ability to issue shares under the Rights Plan (as defined therein). These provisions are intended to ensure that any takeover or change of control of the Company is conducted in an orderly manner, all shareholders of the Company are treated equally and fairly and receive an optimum price for their shares and the long-term success of the Company is safeguarded. Under English law, it may not be possible to implement these provisions in all circumstances.

The Code only applies to an offer for a public company that is registered in the U.K. (or the Channel Islands or the Isle of Man) and the securities of which are not admitted to trading on a regulated market in the U.K. (or the Channel Islands or the Isle of Man) if the company is considered by the takeover panel (the "Takeover Panel") to have its place of central management and control in the U.K. (or the Channel Islands or the Isle of Man). This is known as the "residency test." The test for central management and control under the Code is different from that used by the U.K. tax authorities. Under the Code, the Takeover Panel will look to where the majority of the directors of the company are residents for the purposes of determining where the company has its place of central management and control. Accordingly, the Takeover Panel has previously indicated that the Code does not apply to the Company and the Company's shareholders therefore do not have the benefit of the protections the Code affords, including, but not limited to, the requirement that a person who acquires an interest in shares carrying 30% or more of the voting rights in the Company must make a cash offer to all other shareholders at the highest price paid in the 12 months before the offer was announced.

English law requires that we meet certain additional financial requirements before declaring dividends and returning funds to shareholders.

Under English law, we are only able to declare dividends and return funds to our shareholders out of the accumulated distributable reserves on our statutory balance sheet. Distributable reserves are a company’s accumulated, realized profits, so far as not previously utilized by distribution or capitalization, less its accumulated, realized losses, so far as not previously written off in a reduction or reorganization of capital duly made. Realized profits are created through the remittance of profits of certain subsidiaries to our parent company in the form of dividends.

English law also provides that a public company can only make a distribution if, among other things (a) the amount of its net assets (that is, the total excess of assets over liabilities) is not less than the total of its called up share capital and non-distributable reserves and (b) if, and to the extent that, the distribution does not reduce the amount of its net assets to less than that total.

We may be unable to remit the profits of our subsidiaries in a timely or tax efficient manner. If at any time we do not have sufficient distributable reserves to declare and pay quarterly dividends, we may undertake a reduction in the capital of the Company, in addition to the reduction of capital undertaken in 2014, to reduce the amount of our share capital and non-distributable reserves and to create a corresponding increase in our distributable reserves out of which future distributions to shareholders can be made. To comply with English law, a reduction of capital would, in addition to the restrictions described above, be subject to (a) approval of shareholders at a general meeting by special resolution; (b) confirmation by an order of the English Courts and (c) the Court order being delivered to and registered by the Registrar of Companies in England. If we were to pursue a reduction of capital of the Company as a course of action, and failed to obtain the necessary approvals from shareholders and the English Courts, we may undertake other efforts to allow the Company to declare dividends and return funds to shareholders.

Legal, Regulatory and Tax Risks

Failure to comply with anti-bribery statutes, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act, could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

We operate in a number of countries throughout the world, including countries known to have a reputation for corruption and are subject to the U.S. Foreign Corrupt Practices Act of 1977 (“FCPA”), the U.S. Treasury Department's Office of Foreign Assets Control ("OFAC") regulations, the U.K. Bribery Act ("UKBA"), other U.S. laws and regulations governing our international operations and similar laws in other countries.

In August 2017, one of our Brazilian subsidiaries was contacted by the Office of the Attorney General for the Brazilian state of Paraná in connection with a criminal investigation procedure initiated against agents of both Samsung Heavy Industries, a shipyard in South Korea (“SHI”), and Pride International LLC ("Pride") in relation to

the drilling services agreement with Petrobras for the DS-5 (the "DSA"). The Brazilian authorities requested information regarding our compliance program and the findings of our internal investigations relating to the DSA. We cooperated with the Office of the Attorney General and provided documents in response to its request. We cannot predict the scope or ultimate outcome of this procedure or whether any Brazilian governmental authority will open an investigation into Pride’s involvement in this matter, or if a proceeding were opened, the scope or ultimate outcome of any such investigation.

Any violation of the FCPA, OFAC regulations, the UKBA or other applicable anti-corruption laws by us, our affiliated entities or their respective officers, directors, employees and agents could in some cases provide a customer with termination rights and other remedies under the terms of their contracts(s) with us and also result in substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions and could adversely affect our financial condition, operating results, cash flows or the availability of funds under our revolving credit facility. Further, we may incur significant costs and consume significant internal resources in our efforts to detect, investigate and resolve actual or alleged violations.

Increasing regulatory complexity could adversely impact the costs associated with our offshore drilling operations and reduce demand.

The offshore contract drilling industry is dependent on demand for services from the oil and gas industry. Accordingly, we will be directly affected by the approval and adoption of laws and regulations limiting or curtailing exploration and development drilling for oil and natural gas for economic, environmental, safety and other policy reasons. Furthermore, we may be required to make significant capital expenditures or incur substantial additional costs to comply with new governmental laws and regulations. It is also possible that legislative and regulatory activity could adversely affect our operations by limiting drilling opportunities or significantly increasing our operating costs. Increases in regulatory requirements, particularly in the U.S. Gulf of Mexico, could significantly increase our costs. In recent years, we have seen several significant regulatory changes that have affected the way we operate in the U.S. Gulf of Mexico.

As a result of jackup rig fitness requirements during hurricane seasons issued by BSEE and its predecessor agency, jackup rigs in the U.S. Gulf of Mexico are required to operate with a higher air gap (the space between the water level and the bottom of the rig's hull) during hurricane season, effectively reducing the water depth in which they can operate. The guidelines also provide for enhanced information and data requirements from oil and gas companies operating in the U.S. Gulf of Mexico. Current or future Notice to Lessees from the U.S. Department of the Interior or other rules, directives and regulations may further impact our customers' ability to obtain permits and commence or continue deep or shallow water operations in the U.S. Gulf of Mexico.

Proposed revisions to the 2016 Well Control Rule, which imposed new requirements for well-control and blowout prevention equipment that could increase our costs and cause delays in our operations due to unavailability of associated equipment, would revise requirements for well design, well control, casing, cementing, real-time monitoring and subsea containment. The revisions are targeted to ensure safety and environmental protection while correcting errors in the 2016 rule and reducing certain unnecessary regulatory burdens imposed under the existing regulations. The proposed revisions have not yet been finalized.

Although only operators are currently required to have a SEMS, BSEE has in the past stated that future rulemaking may require offshore drilling contractors to implement their own SEMS programs. The current SEMS regulations, which require written agreements between operators and contractors regarding the contractors’ support of the operators' safety and environmental policies at the worksite (including requirements for personnel training and written safe work practices), and the possibility of additional SEMS rules for contractors could expose us to increased costs.

Finally, since 2014, the United States Coast Guard has proposed new regulations that would impose GPS equipment and positioning requirements for drilling rigs operating in the U.S. Gulf of Mexico and issued notices

regarding the development of guidelines for cybersecurity measures used in the marine and offshore energy sectors for all vessels and facilities that are subject to the MTSA, including our rigs.

Any new or additional regulatory, legislative, permitting or certification requirements in the U.S., including laws and regulations that have or may impose increased financial responsibility, oil spill abatement contingency plan capability requirements, or additional operational requirements and certifications, could materially adversely affect our financial position, operating results or cash flows.

We anticipate that government regulation in other countries where we operate may follow the U.S. in regard to enhanced safety and environmental regulation, which could also result in governments imposing sanctions on contractors when operators fail to comply with regulations that impact drilling operations. Even if not a requirement in these countries, most international operating companies, and many others, are voluntarily complying with some or all of the U.S. inspections and safety and environmental guidelines when operating outside the U.S. Such additional governmental regulation and voluntary compliance by operators could increase the cost of our operations and expose us to greater liability.

Compliance with or breach of environmental laws can be costly and could limit our operations.

Our operations are subject to laws and regulations controlling the discharge of materials into the environment, pollution, contamination and hazardous waste disposal or otherwise relating to the protection of the environment. Environmental laws and regulations specifically applicable to our business activities could impose significant liability on us for damages, clean-up costs, fines and penalties in the event of oil spills or similar discharges of pollutants or contaminants into the environment or improper disposal of hazardous waste generated in the course of our operations. To date, such laws and regulations have not had a material adverse effect on our operating results, and we have not experienced an accident that has exposed us to material liability arising out of or relating to discharges of pollutants into the environment. However, the legislative, judicial and regulatory response to a well incident could substantially increase our and our customers' liabilities. In addition to potential increased liabilities, such legislative, judicial or regulatory action could impose increased financial, insurance or other requirements that may adversely impact the entire offshore drilling industry.

The International Convention on Oil Pollution Preparedness, Response and Cooperation, the International Convention on Civil Liability for Oil Pollution Damage 1992, the U.K. Merchant Shipping Act 1995, Marpol 73/78 (the International Convention for the Prevention of Pollution from Ships), the U.K. Merchant Shipping (Oil Pollution Preparedness, Response and Co-operation Convention) Regulations 1998, as amended, and other related legislation and regulations and the OPA 90, as amended, the Clean Water Act, and other U.S. federal statutes applicable to us and our operations, as well as similar statutes in Texas, Louisiana, other coastal states and other non-U.S. jurisdictions, address oil spill prevention, reporting and control and have significantly expanded potential liability, fine and penalty exposure across many segments of the oil and gas industry.

Such statutes and related regulations impose a variety of obligations on us related to the prevention of oil spills, disposal of waste and liability for resulting damages. For instance, OPA 90 imposes strict and, with limited exceptions, joint and several liability upon each responsible party for oil removal costs as well as a variety of fines, penalties and damages. Although OPA 90 provides for certain limits of liability, such limits are not applicable where there is any safety violation or where gross negligence is involved. Failure to comply with these statutes and regulations, including OPA 90, may subject us to civil or criminal enforcement action, which may not be covered by contractual indemnification or insurance and could have a material adverse effect on our financial position, operating results or cash flows. Further, remedies under the Clean Water Act and related legislation and OPA 90 do not preclude claims under state regulations or civil claims for damages to third parties under state laws.

High profile and catastrophic events, including the 2010 Macondo well incident, have heightened governmental and environmental concerns about the risks associated with offshore oil and gas drilling. We are adversely affected by restrictions on drilling in certain areas in which we operate, including policies and guidelines regarding the approval of drilling permits, restrictions on development and production activities, and directives and

regulations that have and may further impact our operations. From time to time, legislative and regulatory proposals have been introduced that would materially limit or prohibit offshore drilling in certain areas, or that would increase the liabilities or costs associated with offshore drilling. If new laws are enacted, or if government actions are taken that restrict or prohibit offshore drilling in our principal areas of operation or that impose environmental or other requirements that materially increase the liabilities, financial requirements or operating or equipment costs associated with offshore drilling, exploration, development, or production of oil and natural gas, our financial position, operating results or cash flows could be materially adversely affected.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

Governments around the world are increasingly focused on enacting laws and regulations regarding climate change and regulation of greenhouse gases. Lawmakers and regulators in the jurisdictions where we operate have proposed or enacted regulations requiring reporting of greenhouse gas emissions and the restriction thereof, including increased fuel efficiency standards, carbon taxes or cap and trade systems, restrictive permitting, and incentives for renewable energy. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels, including plans developed in connection with the Paris climate conference in December 2015 and the Katowice climate conference in December 2018. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Additionally, numerous large cities globally and several countries have adopted programs to mandate or incentivize the conversion from internal combustion engine powered vehicles to electric-powered vehicles and placed restrictions on non-public transportation. Such policies or other laws, regulations, treaties and international agreements related to greenhouse gases and climate change may negatively impact the price of oil relative to other energy sources, reduce demand for hydrocarbons, limit drilling in the offshore oil and gas industry, or otherwise unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs and additional operating restrictions, all of which would have a material adverse impact on our business. In addition, in recent years the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, has promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental initiatives aimed at limiting climate change and reducing air pollution could ultimately interfere with our business activities and operations and our access to capital.

In addition to potential impacts on our business resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customers’ operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of greenhouse gas emissions-related agreements, legislation and measures on our company’s financial performance is highly uncertain because we are unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes.

The IRS may not agree with the conclusion that we should be treated as a foreign corporation for U.S. federal tax purposes.

Although Valaris plc is incorporated in the United Kingdom (and thus would generally be considered a “foreign” corporation (or non-U.S. tax resident)), the U.S. Internal Revenue Service (“IRS”) may assert that we should be treated as a U.S. corporation (and U.S. tax resident) pursuant to the rules under Section 7874 of the Internal Revenue Code (including as a result of the Atwood acquisition completed in 2017). While we do not believe we are a U.S. corporation pursuant to these rules, the rules are complex and the determination is subject to

factual uncertainties. If the IRS successfully challenged our status as a foreign corporation, significant adverse tax consequences would result for us and for certain of our shareholders.

U.S. tax laws and IRS guidance could affect our ability to engage in certain acquisition strategies and certain internal restructurings.

Even if we are currently treated as a foreign corporation for U.S. federal income tax purposes, Section 7874 of the Internal Revenue Code and U.S. Treasury Regulations promulgated thereunder, including temporary Treasury Regulations, may adversely affect our ability to engage in certain future acquisitions of U.S. businesses in exchange for our equity, which may affect the tax efficiencies that otherwise might be achieved in such potential future transactions.

Governments may pass laws that subject us to additional taxation or may challenge our tax positions.

There is increasing uncertainty with respect to tax laws, regulations and treaties, and the interpretation and enforcement thereof that may affect our business. The Organization for Economic Cooperation and Development (“OECD”) has issued its final reports on base erosion and profit shifting, which generally focus on situations where profits are earned in low-tax jurisdictions, or payments are made between affiliates from jurisdictions with high tax rates to jurisdictions with lower tax rates. Certain countries within which we operate have recently enacted changes to their tax laws in response to the OECD recommendations or otherwise and these and other countries may enact changes to their tax laws or practices in the future (prospectively or retroactively), which may have a material adverse effect on our financial position, operating results or cash flows. U.S. federal income tax reform legislation enacted in late 2017 introduced significant changes to U.S. income tax law, including a reduction in the statutory income tax rate from 35% to 21%, a one-time transition tax on deemed repatriation of deferred foreign income, a base erosion anti-abuse tax that effectively imposes a minimum tax on certain payments to non-U.S. affiliates, new and revised rules relating to the current taxation of certain income of foreign subsidiaries and revised rules associated with limitations on the deduction of interest.

In addition, our tax positions are subject to audit by U.K., U.S. and other foreign tax authorities. Such tax authorities may disagree with our interpretations or assessments of the effects of tax laws, treaties or regulations or their applicability to our corporate structure or certain transactions we have undertaken. Even if we are successful in maintaining our tax positions, we may incur significant expenses in defending our positions and contesting claims asserted by tax authorities. If we are unsuccessful in defending our tax positions, the resulting assessments or rulings could significantly impact our consolidated income taxes in past or future periods.

As a result of these uncertainties, as well as changes in the administrative practices and precedents of tax authorities or other matters (such as changes in applicable accounting rules) that increase the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements, we cannot provide any assurances as to what our consolidated effective income tax rate will be in future periods. If we are unable to mitigate the negative consequences of any change in law, audit or other matters, this could cause our consolidated income taxes to increase and cause a material adverse effect on our financial position, operating results or cash flows.

Our consolidated effective income tax rate may vary substantially over time.

We cannot provide any assurances as to what our future consolidated effective income tax rate will be because of, among other matters, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.K., U.S. and other foreign tax laws, regulations or treaties or the interpretation or enforcement thereof, changes in the

administrative practices and precedents of tax authorities or other matters (such as changes in applicable accounting rules) that increase the amounts we have provided for income taxes or deferred tax assets and liabilities in our consolidated financial statements. In addition, as a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in the overall level of our income and changes in tax laws, our consolidated effective income tax rate may vary substantially from one reporting period to another. In periods of declining profitability, our income tax expense may not decline proportionately with income. Further, we may continue to incur income tax expense in periods in which we operate at a loss. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. If we are unable to mitigate the negative consequences of any change in law, audit, business activity or other matters, this could cause our consolidated effective income tax rate to increase and cause a material adverse effect on our financial position, operating results or cash flows.

Investor enforcement of civil judgments against us may be more difficult.

Because we are a public limited company incorporated under the Laws of England and Wales, investors could experience difficulty enforcing judgments obtained against us in U.S. courts. In addition, it may be more difficult (or impossible) to bring some types of claims against us in courts in England than it would be to bring similar claims against a U.S. company in a U.S. court.

Our business could be affected as a result of activist investors.

Publicly traded companies have increasingly become subject to campaigns by activist investors advocating corporate actions such as actions related to environment, social and governance (“ESG”) matters, financial restructuring, increased borrowing, dividends, share repurchases or even sales of assets or the entire company. Responding to proxy contests and other actions by such activist investors or others in the future could be costly and time-consuming, disrupt our operations and divert the attention of our Board of Directors and senior management from the pursuit of our business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of investor activism or changes to the composition of the Board of Directors may lead to the perception of a change in the direction of our business, instability or lack of continuity which may be exploited by our competitors, cause concern to our current or potential customers, and make it more difficult to attract and retain qualified personnel. If customers choose to delay, defer or reduce transactions with us or transact with our competitors instead of us because of any such issues, then our revenue, earnings and operating cash flows could be adversely affected. In addition, the trading price of our shares could experience periods of increased volatility as a result of investor activism.

Risks Related to Our International Operations:

Our non-U.S. operations involve additional risks not typically associated with U.S. operations.

•terrorist acts, war and civil disturbances,

•expropriation, nationalization, deprivation or confiscation of our equipment or our customer's property,

•repudiation or nationalization of contracts,

•assaults on property or personnel,

•piracy, kidnapping and extortion demands,

•significant governmental influence over many aspects of local economies and customers,

•unexpected changes in law and regulatory requirements, including changes in interpretation or enforcement of existing laws,

•work stoppages, often due to strikes over which we have little or no control,

•complications associated with repairing and replacing equipment in remote locations,

•limitations on insurance coverage, such as war risk coverage, in certain areas,

•imposition of trade barriers,

•wage and price controls,

•import-export quotas,

•exchange restrictions,

•currency fluctuations,

•changes in monetary policies,

•uncertainty or instability resulting from hostilities or other crises in the Middle East, West Africa, Latin America or other geographic areas in which we operate,

•changes in the manner or rate of taxation,

•limitations on our ability to recover amounts due,

•increased risk of government and vendor/supplier corruption,

•increased local content requirements,

•the occurrence or threat of epidemic or pandemic diseases (including the COVID-19 pandemic) and any government response to such occurrence or threat,

•changes in political conditions, and

•other forms of government regulation and economic conditions that are beyond our control.

We historically have maintained insurance coverage and obtained contractual indemnities that protect us from some, but not all, of the risks associated with our non-U.S. operations such as nationalization, deprivation, expropriation, confiscation, political and war risks. However, there can be no assurance that any particular type of contractual or insurance protection will be available in the future or that we will be able to purchase our desired level of insurance coverage at commercially feasible rates. Moreover, we may initiate a self-insurance program through one or more captive insurance subsidiaries. In circumstances where we have insurance protection for some or all of the risks sometimes associated with non-U.S. operations, such insurance may be subject to cancellation on short notice, and it is unlikely that we would be able to remove our rig or rigs from the affected area within the notice period. Accordingly, a significant event for which we are uninsured, underinsured or self-insured, or for

which we have not received an enforceable contractual indemnity from a customer, could cause a material adverse effect on our financial position, operating results or cash flows.

We are subject to various tax laws and regulations in substantially all countries in which we operate or have a legal presence. Actions by tax authorities that impact our business structures and operating strategies, such as changes to tax treaties, laws and regulations, or the interpretation or repeal of any of the foregoing or changes in the administrative practices and precedents of tax authorities, adverse rulings in connection with audits or otherwise, or other challenges may have a material impact on our tax expense.

As required by law, we file periodic tax returns that are subject to review and examination by various revenue agencies within the jurisdictions in which we operate. We are currently subject to tax assessments in various jurisdictions, which we are contesting. Although the outcome of such assessments cannot be predicted with certainty, unfavorable outcomes could have a material adverse effect on our liquidity.

Our non-U.S. operations also face the risk of fluctuating currency values, which may impact our revenues, operating costs and capital expenditures. We currently conduct contract drilling operations in certain countries that have experienced substantial fluctuations in the value of their currency compared to the U.S. dollar. In addition, some of the countries in which we operate have occasionally enacted exchange controls. Generally, we have contractually mitigated these risks by invoicing and receiving payment in U.S. dollars (our functional currency) or freely convertible currency and, to the extent possible, by limiting our acceptance of foreign currency to amounts which approximate our expenditure requirements in such currencies. However, not all of our contracts contain these terms and there is no assurance that our contracts will contain such terms in the future.

A portion of the costs and expenditures incurred by our non-U.S. operations, including certain capital expenditures, are settled in local currencies, exposing us to risks associated with fluctuation in the value of these currencies relative to the U.S. dollar. We use foreign currency forward contracts to reduce this exposure in certain cases. However, a relative weakening in the value of the U.S. dollar in relation to the local currencies in these countries may increase our costs and expenditures.

Our non-U.S. operations are also subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the operation of drilling rigs and the requirements for equipment. We may be required to make significant capital expenditures to operate in such countries, which may not be reimbursed by our customers. Governments in some countries have become increasingly active in regulating and controlling the ownership of oil, natural gas and mineral concessions and companies holding concessions, the exploration of oil and natural gas and other aspects of the oil and gas industry in their countries. In some areas of the world, government activity has adversely affected the amount of exploration and development work performed by major international oil companies and may continue to do so. Moreover, certain countries accord preferential treatment to local contractors or joint ventures or impose specific quotas for local goods and services, which can increase our operational costs and place us at a competitive disadvantage. There can be no assurance that such laws and regulations or activities will not have a material adverse effect on our future operations.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Our import activities are governed by specific customs laws and regulations in each of the countries where we operate. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose express or de facto economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled

operational downtime, reduced day rates during such downtime and contract cancellations. Any failure to comply with applicable legal and regulatory trading obligations also could result in criminal and civil penalties and sanctions, such as fines, imprisonment, exclusion from government contracts, seizure of shipments and loss of import and export privileges.

Our employees, contractors and agents may take actions in violation of our policies and procedures designed to promote compliance with the laws of the jurisdictions in which we operate. Any such violation could have a material adverse effect on our financial position, operating results or cash flows.

The U.K.'s withdrawal from the E.U. may have a negative effect on economic conditions, financial markets and our business.

In June 2016, a referendum was held in the U.K. which resulted in a majority voting in favor of the U.K. withdrawing from the E.U. (commonly referred to as “Brexit”). Pursuant to legislation approved by the U.K. Parliament and the E.U. Parliament in January 2020, the U.K. withdrew from the E.U. with effect from 11 p.m. (GMT) on January 31, 2020 on the terms of a withdrawal agreement agreed between the U.K. and the E.U. in October 2019 (the “Withdrawal Agreement”). The Withdrawal Agreement provided for the U.K.’s withdrawal to be followed by a “transition period”, during which, in summary, the U.K. was not a member of the E.U. but most E.U. rules and regulations continued to apply to the U.K. During the transition period, the U.K. and the E.U. sought to negotiate the terms of a long-term trading relationship between the U.K. and the E.U. based on a “Political Declaration” agreed between the U.K. and the E.U. in October 2019. The transition period expired on December 31, 2020.

On December 24, 2020, the European Commission and the United Kingdom reached agreement on the terms of the U.K.’s future relationship with the E.U. (the “Trade and Cooperation Agreement”). As negotiations concerning the terms of the Trade and Cooperation Agreement could only be finalized shortly before the expiry of the transition period, the European Commission has determined to apply the Trade and Cooperation Agreement provisionally with effect from January 1, 2021, until it can be formally ratified by the European Union. This will require the European Parliament to give its consent to the Trade and Cooperation Agreement and the Council of the European Union to adopt a formal decision on its conclusion. It is currently expected that such processes will be completed during the first quarter of 2021.

Many of the practical effects of the Trade and Cooperation Agreement will only become clear with the passage of time and at present it is not possible for us to estimate with certainty whether its implementation will have a material adverse effect on our financial position, operating results or cash flows. While the Trade and Cooperation Agreement provides for zero tariffs and quotas on the movement of goods between the U.K. and the E.U. (provided they comply with the parties’ agreed rules of origin) and also seeks to minimize trade disruption arising from technical and administrative barriers to trade, there can be no guarantee that the implementation of the Trade and Cooperation Agreement will not lead to significant increased costs and supply chain disruption for our business and the businesses of our U.K. customers and suppliers. Any incremental costs incurred by our U.K. suppliers may be passed on to us and any supply chain disruption experienced by our U.K. customers or suppliers may in turn disrupt our own operations.

The U.K.’s withdrawal from the E.U. has also given rise to calls for the governments of other E.U. member states to consider withdrawal, while the U.K.’s withdrawal negotiation process has increased the risk of the possibility of a further referendum concerning Scotland’s independence from the rest of the U.K. These developments, or the perception that any of them could occur, have had and may continue to have a material adverse effect on global, regional and/or national economic conditions and the stability of global financial markets, and may significantly reduce global market liquidity.

The implementation of the Trade and Cooperation Agreement and/or any subsequent divergence of the law applicable in the U.K. and the E.U. could depress economic activity, result in changes to currency exchange rates, taxes, import/export regulations, laws and other regulatory matters, and/or restrict our access to capital and the free movement of our employees, which could have a material adverse effect on our financial position, operating results

or cash flows. Approximately 15% of our total revenues were generated in the U.K. for the year ended December 31, 2020.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Contract Drilling Fleet

The following table provides certain information about the rigs in our drilling fleet as of February 22, 2021:

Rig Name

Rig Type

Year Built/
Rebuilt

Design

Maximum
Water Depth/
Drilling Depth

Location

Status

Floaters

VALARIS DS-4

Drillship

2010

Dynamically Positioned

12,000'/40,000'

United Kingdom

Preservation stacked(1)

VALARIS DS-7

Drillship

2013

Dynamically Positioned

10,000'/40,000'

Spain

Preservation stacked(1)

VALARIS DS-8

Drillship

2015

Dynamically Positioned

12,000'/40,000'

United Kingdom

Preservation stacked(1)

VALARIS DS-9

Drillship

2015

Dynamically Positioned

12,000'/40,000'

Spain

Preservation stacked(1)

VALARIS DS-10

Drillship

2015

Dynamically Positioned

12,000'/40,000'

Nigeria

Under contract

VALARIS DS-11

Drillship

2013

Dynamically Positioned

12,000'/40,000'

Spain

Preservation stacked(1)

VALARIS DS-12

Drillship

2013

Dynamically Positioned

12,000'/40,000'

Angola

Under contract

VALARIS DS-13

Drillship

Under construction

Dynamically Positioned

12,000'/40,000'

South Korea

Option(2)

VALARIS DS-14

Drillship

Under construction

Dynamically Positioned

12,000'/40,000'

South Korea

Option(2)

VALARIS DS-15

Drillship

2014

Dynamically Positioned

12,000'/40,000'

Mexico

Under contract

VALARIS DS-16

Drillship

2014

Dynamically Positioned

12,000'/40,000'

Spain

Preservation stacked(1)

VALARIS DS-17

Drillship

2014

Dynamically Positioned

12,000'/40,000'

Spain

Preservation stacked(1)

VALARIS DS-18

Drillship

2015

Dynamically Positioned

12,000'/40,000'

Gulf of Mexico

Under contract

VALARIS 8503

Semisubmersible

2010

Dynamically Positioned

8,500'/37,500'

Gulf of Mexico

Preservation stacked(1)

VALARIS 8505

Semisubmersible

2012

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Under contract

VALARIS 8506

Semisubmersible

2012

Dynamically Positioned

8,500'/35,000'

Gulf of Mexico

Preservation stacked(1)

VALARIS DPS-1

Semisubmersible

2012

F&G ExD Millennium

10,000'/35,000'

Malaysia

Available

VALARIS MS-1

Semisubmersible

2011

F&G ExD Millennium

8,200'/40,000

Australia

Under contract

Jackups

VALARIS JU-22

Jackup

1980/2011

MLT 116-C

313'/25,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-36

Jackup

1981/2011

MLT 116-C

300'/25,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-37

Jackup

1981/2011

MLT 116-C

300'/25,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-54

Jackup

1982/2004

F&G L-780 MOD II-C

300'/25,000'

Saudi Arabia

Under contract

VALARIS JU-67

Jackup

1976/2005

MLT 84-CE

350'/30,000'

Indonesia

Under contract

VALARIS JU-72

Jackup

1981/2011

Hitachi K1025N

225'/25,000'

United Kingdom

Under contract

VALARIS JU-75

Jackup

1999

MLT Super 116-C

400'/30,000'

Gulf of Mexico

Preservation stacked(1)

VALARIS JU-76

Jackup

2000

MLT Super 116-C

350'/30,000'

Saudi Arabia

Under contract

VALARIS JU-92

Jackup

1982/2003

MLT 116-C

210'/25,000'

United Kingdom

Under contract

VALARIS JU-100

Jackup

1987/2009

MLT 150-88-C

328'/25,000'

Denmark

Preservation stacked(1)

VALARIS JU-101

Jackup

2000/2010

KFELS MOD V-A

400'/30,000'

United Kingdom

Preservation stacked(1)

VALARIS JU-102

Jackup

2002

KFELS MOD V-A

400'/30,000'

Gulf of Mexico

Under contract

VALARIS JU-104

Jackup

2002/2011

KFELS MOD V-B

400'/30,000'

UAE

Preservation stacked(1)

VALARIS JU-106

Jackup

2005

KFELS MOD V-B

400'/30,000'

Indonesia

Under contract

VALARIS JU-107

Jackup

2006

KFELS MOD V-B

400'/30,000'

Australia

Under contract

VALARIS JU-108

Jackup

2007/2009

KFELS MOD V-B

400'/30,000'

Saudi Arabia

Under contract

VALARIS JU-109

Jackup

2008

KFELS MOD V-Super B

350'/35,000'

Namibia

Preservation stacked(1)

Rig Name

Rig Type

Year Built/
Rebuilt

Design

Maximum
Water Depth/
Drilling Depth

Location

Status

Jackups

VALARIS JU-110

Jackup

2015

KFELS MOD V-B

400'/35,000'

Qatar

Under contract

VALARIS JU-111

Jackup

2003

KFELS MOD V Enhanced B-Class

400'/36,000'

Malta

Preservation stacked(1)

VALARIS JU-113

Jackup

2012

Baker Marine Pacific Class 400

400'/30,000'

Philippines

Preservation stacked(1)

VALARIS JU-114

Jackup

2012

Baker Marine Pacific Class 400

400'/30,000'

Philippines

Preservation stacked(1)

VALARIS JU-115

Jackup

2013

Baker Marine Pacific Class 400

400'/30,000'

Thailand

Under contract

VALARIS JU-116

Jackup

2008/2018

LT 240- C

375'/35,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-117

Jackup

2009

LT 240- C

350'/35,000'

Gulf of Mexico

Available

VALARIS JU-118

Jackup

2012

LT 240- C

350'/35,000

Mexico

Under contract

VALARIS JU-120

Jackup

2013

KFELS Super A

400'/40,000'

United Kingdom

Under contract

VALARIS JU-121

Jackup

2013

KFELS Super A

400'/40,000'

United Kingdom

Under contract

VALARIS JU-122

Jackup

2013

KFELS Super A

400'/40,000'

United Kingdom

Under contract

VALARIS JU-123

Jackup

2016

KFELS Super A

400'/40,000'

United Kingdom

Under contract

VALARIS JU-140

Jackup

2016

LT Super 116E

340'/30,000'

Saudi Arabia

Under contract

VALARIS JU-141

Jackup

2016

LT Super 116E

340'/30,000'

Saudi Arabia

Under contract

VALARIS JU-142

Jackup

2008

LT Super 116-E

350'/36,000'

Malta

Preservation stacked(1)

VALARIS JU-143

Jackup

2010/2018

LT EXL Super 116-E

350'/35,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-144

Jackup

2010

LT Super 116-E

350'/35,000'

Mexico

Under contract

VALARIS JU-145

Jackup

2010

LT Super 116-E

350'/35,000'

Gulf of Mexico

Preservation stacked(1)

VALARIS JU-146

Jackup

2011/2018

LT EXL Super 116-E

320'/35,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-147

Jackup

2012/2019

LT Super 116-E

350'/30,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-148

Jackup

2013/2019

LT Super 116-E

350'/30,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-247

Jackup

1998

LT Super Gorilla

400'/35,000'

United Kingdom

Available

VALARIS JU-248

Jackup

2001/2014

LT Super Gorilla

400'/35,000'

United Kingdom

Under contract

VALARIS JU-249

Jackup

2001

LT Super Gorilla

400'/35,000'

United Kingdom

Preservation stacked(1)

VALARIS JU-250

Jackup

2003

LT Super Gorilla XL

550'/35,000'

Saudi Arabia

Leased to ARO drilling

VALARIS JU-290

Jackup

2011

KEFLS N Class

435'/35,000'

Norway

Under contract

VALARIS JU-291

Jackup

2011

KEFLS N Class

400'/35,000'

Norway

Under contract

VALARIS JU-292

Jackup

2011

KEFLS N Class

400'/35,000'

Norway

Under contract

(1)Prior to stacking, upfront steps are taken to preserve the rig. This may include a quayside power source to dehumidify key equipment and/or provide electric current to the hull to prevent corrosion. Also, certain equipment may be removed from the rig for storage in a temperature-controlled environment. While stacked, large equipment that remains on the rig is periodically inspected and maintained by Valaris personnel. These steps are designed to reduce time and lower cost to reactivate the rig when market conditions improve.

(2)The Amended RSA provides that on or before the effective date of the reorganization, the construction contracts for these rigs shall be rejected under Section 365 of the Bankruptcy Code, unless otherwise agreed between the shipyard and the Company with the consent of required Consenting Noteholders. If rejected, it is contemplated that we would have to pay an amount equal to the liquidation recovery, which is the amount the contract counterparty would be entitled to receive or retain if the applicable Company entity was liquidated under chapter 7 of the Bankruptcy Code. Prior to December 31, 2020, a Stipulation was filed with the Bankruptcy Court which included an Assumption Term Sheet stating amended terms of these construction agreements.

Following further negotiations, we entered into amended agreements with the shipyard on February 26, 2021 that become effective upon our emergence from bankruptcy. The amendments 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 rigs on or before December 31, 2023. Under the amended agreements, the purchase price for the rigs are estimated to be approximately $119.1 million for the VALARIS DS-13 and $218.3 million for the 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. The amended agreements remove any Company guarantee.

The equipment on our drilling rigs includes engines, draw works, derricks, pumps to circulate drilling fluid, well control systems, drill string and related equipment. The engines power a top-drive mechanism that turns the drill string and drill bit so that the hole is drilled by grinding subsurface materials, which are then returned to the rig by the drilling fluid. The intended water depth, well depth and geological conditions are the principal factors that determine the size and type of rig most suitable for a particular drilling project.

Floater rigs consist of drillships and semisubmersibles. Drillships are purpose-built maritime vessels outfitted with drilling apparatus. Drillships are self-propelled and can be positioned over a drill site through the use of a computer-controlled propeller or "thruster" dynamic positioning systems. Our drillships are capable of drilling in water depths of up to 12,000 feet and are suitable for deepwater drilling in remote locations because of their superior mobility and large load-carrying capacity. Although drillships are most often used for deepwater drilling and exploratory well drilling, drillships can also be used as a platform to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations.

Semisubmersibles are drilling rigs with pontoons and columns that are partially submerged at the drilling location to provide added stability during drilling operations. Semisubmersibles are held in a fixed location over the ocean floor either by being anchored to the sea bottom with mooring chains or dynamically positioned by computer-controlled propellers or "thrusters" similar to that used by our drillships. Moored semisubmersibles are most commonly used for drilling in water depths of 4,499 feet or less. However, VALARIS MS-1, which is a moored semisubmersible, is capable of deepwater drilling in water depths greater than 5,000 feet. Dynamically positioned semisubmersibles generally are outfitted for drilling in deeper water depths and are well-suited for deepwater development and exploratory well drilling. Further, we have two hybrid semisubmersibles, VALARIS 8503 and VALARIS 8505, which leverage both moored and dynamically positioned configurations. This hybrid design provides multi-faceted drilling solutions to customers with both shallow water and deepwater requirements.

Jackup rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected leg supports. Jackups are generally preferred over other rig types in shallow water depths of 400 feet or less, primarily because jackups provide a more stable drilling platform with above water well-control equipment. Our jackups are of the independent leg design where each leg can be fixed into the ocean floor at varying depths and equipped with a cantilever that allows the drilling equipment to extend outward from the hull over fixed platforms enabling safer drilling of both exploratory and development wells. The jackup hull supports the drilling equipment, jacking system, crew quarters, storage and loading facilities, helicopter landing pad and related equipment and supplies.

Over the life of a typical rig, many of the major systems are replaced due to normal wear and tear or technological advancements in drilling equipment. We believe all our rigs are in good condition. As of February 22, 2021, we owned all rigs in our fleet. We also manage the drilling operations for two platform rigs owned by a third-party.

We lease our executive offices in London, England in addition to office space in Houston, Aberdeen, Indonesia, Malaysia, Mexico, Brazil, Trinidad, Nigeria, The Netherlands, Saudi Arabia, Thailand, and Norway. We own offices and other facilities in Louisiana, Angola, Australia, Aberdeen and Brazil.

Item 3. Legal Proceedings

UMB Bank Lawsuit

On March 19, 2020, UMB Bank, National Association (“UMB”), the purported indenture trustee for four series of Valaris notes, filed a lawsuit in Harris County District Court in Houston, Texas. The lawsuit was filed against Valaris plc, two legacy Rowan entities, two legacy Ensco entities and the individual directors of the two legacy Rowan entities. The complaint alleges, among other things, breach of fiduciary duty, aiding and abetting breach of fiduciary duty and fraudulent transfer in connection with certain intercompany transactions occurring after completion of the Rowan merger and the Rowan entities’ guarantee of Valaris’ revolving credit facility. In addition to an unspecified amount of damages, the lawsuit seeks to void and undo all historical transfers of cash or other assets from legacy Rowan entities to Valaris and its other subsidiaries and the internal reorganization transaction. On August 18, 2020, Valaris and certain of its affiliates entered into the Original RSA, including the noteholders that directed UMB to file the lawsuit. Under the Original RSA and the Amended RSA, the lawsuit is stayed by agreement throughout the pendency of the bankruptcy proceeding unless the Original RSA terminates at which point each party reserves its rights to argue whether the case should proceed while in bankruptcy. If the Bankruptcy Court confirms a plan based on the transactions set forth in the Original RSA or the Amended RSA, the lawsuit will be dismissed with prejudice. On August 24, 2020, the parties filed a joint notice staying the case. If the Original RSA terminates and the case in fact proceeds, we are unable to predict the outcome of this matter or estimate the extent to which we may be exposed to any resulting liability. Although we do not expect final disposition of this matter 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 the proceedings.

Shareholder Class Action

On August 20, 2019, plaintiff Xiaoyuan Zhang, a purported Valaris shareholder, filed a class action lawsuit on behalf of Valaris shareholders against Valaris plc and certain of our executive officers, alleging violations of federal securities laws. The complaint cites general statements in press releases and SEC filings and alleges that the defendants made false or misleading statements or failed to disclose material information regarding the performance of our ultra-deepwater segment, among other things.

The complaint asserts claims on behalf of a class of investors who purchased Valaris plc shares between April 11, 2019 and July 31, 2019. The court appointed a lead plaintiff and lead counsel. The case has now been stayed in light of the Valaris plc bankruptcy filing, with the exception that lead plaintiff may continue efforts to serve certain defendants and may file an amended complaint. At this time, we are unable to predict the outcome of these matters or the extent of any resulting liability.

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 2017, 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 $482,000 liability related to these matters was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2020.

Other Matters

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 or cash flows.

Item 4. Mine Safety Disclosures

Not applicable.

PART II


Item 5.			Market for Registrant's Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities

Market Information

As a result of the Chapter 11 Cases and in accordance with Section 802.01D of the NYSE Listed Company Manual, on August 19, 2020, we were notified by NYSE of its determination to indefinitely suspend trading of the Company’s Class A ordinary shares and to commence proceedings to delist the Company’s Class A ordinary shares from the NYSE. Our Class A ordinary shares were delisted from the NYSE effective September 14, 2020. Since that time, the shares have been quoted on the OTC Pink Open Market under the symbol “VALPQ.” We can provide no assurance that our ordinary shares will continue to trade on this market, whether broker-dealers will continue to provide public quotes of our ordinary shares on this market, whether the trading volume of our ordinary shares will be sufficient to provide for an efficient trading market or whether quotes for our ordinary shares will continue on this market in the future. These recent developments could result in significantly lower trading volumes and reduced liquidity for investors seeking to buy or sell shares of our ordinary shares.

Many of our shareholders hold shares electronically, all of which are owned by a nominee of DTC. We had 204 shareholders of record on February 1, 2021.

Dividends

The declaration and amount of dividends is at the discretion of our Board of Directors. No dividends have been declared since the first quarter of 2019.

Exchange Controls

There are no U.K. government laws, decrees or regulations that restrict or affect the export or import of capital, including but not limited to, foreign exchange controls on remittance of dividends on our ordinary shares or on the conduct of our operations.

U.K. Taxation

The following paragraphs are intended to be a general guide to current U.K. tax law and what is understood to be HMRC practice applying as of the date of this report (both of which are subject to change at any time, possibly with retrospective effect) in respect of the taxation of capital gains, the taxation of dividends paid by us and stamp duty and SDRT on the transfer of our shares. In addition, the following paragraphs relate only to persons who for U.K. tax purposes are beneficial owners of the shares.

These paragraphs may not relate to certain classes of holders or beneficial owners of shares, such as our employees or directors, persons who are connected with us, persons who could be treated for U.K. tax purposes as holding their shares as carried interest, insurance companies, charities, collective investment schemes, pension schemes, trustees or persons who hold shares other than as an investment, or U.K. resident individuals who are not domiciled in the U.K. or who are subject to split-year treatment.

These paragraphs do not describe all of the circumstances in which shareholders may benefit from an exemption or relief from taxation. It is recommended that all shareholders obtain their own taxation advice. In particular, any shareholders who are non-U.K. resident or domiciled are advised to consider the potential impact of any relevant double tax treaties, including the Convention between the United States of America and the United Kingdom for the Avoidance of Double Taxation with respect to Taxes on Income, to the extent applicable.

U.K. Taxation of Dividends

U.K. Withholding Tax - Dividends paid by us will not be subject to any withholding or deduction for, or on account of, U.K. tax, irrespective of the residence or the individual circumstances of the shareholders.

U.K. Income Tax - An individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us. An individual shareholder who is not resident in the U.K. will not be subject to U.K. income tax on dividends received from us, unless that shareholder carries on (whether alone or in partnership) any trade, profession or vocation through a branch or agency in the U.K. and shares are used by, or held by or for, that branch or agency. In these circumstances, the non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to U.K. income tax on dividends received from us.

The tax treatment of dividends paid by the Company to individual shareholders is as follows:

•dividends paid by the Company will not carry a tax credit,

•all dividends received by an individual shareholder from the Company (or from other sources) will, except to the extent that they are earned through an Individual Savings Account, self-invested personal pension plan or other regime which exempts the dividends from income tax, form part of the shareholder's total income for income tax purposes,

•a nil rate of income tax will apply to the first £2,000 of taxable dividend income received by an individual shareholder in the tax year 2020/2021 (the "Nil Rate Amount"), regardless of what tax rate would otherwise apply to that dividend income,

•any taxable dividend income received by an individual shareholder in a tax year in excess of the Nil Rate Amount will be taxed at a special rate, as set out below, and

•that tax will be applied to the amount of the dividend income actually received by the individual shareholder (rather than to a grossed-up amount).

Where a shareholder’s taxable dividend income for a tax year exceeds the Nil Rate Amount, the excess amount will, subject to the availability of any income tax personal allowance, be subject to income tax at the following rates for the tax year 2020/2021:

•at the rate of 7.5%, to the extent that the excess amount falls below the threshold for the higher rate of income tax,

•at the rate of 32.5%, to the extent that the excess amount falls above the threshold for the higher rate of income tax but below the threshold for the additional rate of income tax, or

•at the rate of 38.1%, to the extent that the excess amount falls above the threshold for the additional rate of income tax.

In determining whether and, if so, to what extent the relevant dividend income falls above or below the threshold for the higher rate of income tax or, as the case may be, the additional rate of income tax, the shareholder’s total dividend income for the tax year in question (including the part within the Nil Rate Amount) will be treated as the highest part of the shareholder’s total income for income tax purposes.

U.K. Corporation Tax - Unless an exemption is available, as discussed below, a corporate shareholder that is resident in the U.K. will be subject to U.K. corporation tax on dividends received from us. A corporate shareholder that is not resident in the U.K. will not be subject to U.K. corporation tax on dividends received from

us, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares are used by, for or held by or for, the permanent establishment. In these circumstances, the non-U.K. resident corporate shareholder may, depending on its individual circumstances (and if no exemption is available), be subject to U.K. corporation tax on dividends received from us.

The main rate of corporation tax payable with respect to dividends received from us in the financial year 2020 is 19%. If dividends paid by us fall within any of the exemptions from U.K. corporation tax set out in Part 9A of the U.K. Corporation Tax Act 2009, the receipt of the dividend by a corporate shareholder generally will be exempt from U.K. corporation tax. Generally, the conditions for one or more of those exemptions from U.K. corporation tax on dividends paid by us should be satisfied, although the conditions that must be satisfied in any particular case will depend on the individual circumstances of the relevant corporate shareholder.

Shareholders that are regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us, unless the dividends are received as part of a tax advantage scheme. Shareholders that are not regarded as small companies should generally be exempt from U.K. corporation tax on dividends received from us on the basis that the shares should be regarded as non-redeemable ordinary shares. Alternatively, shareholders that are not small companies should also generally be exempt from U.K. corporation tax on dividends received from us if they hold shares representing less than 10% of our issued share capital, would be entitled to less than 10% of the profits available for distribution to our equity-holders and would be entitled on a winding up to less than 10% of our assets available for distribution to such equity-holders. In certain limited circumstances, the exemption from U.K. corporation tax will not apply to such shareholders if a dividend is made as part of a scheme that has a main purpose of falling within the exemption from U.K. corporation tax.

U.K. Taxation of Capital Gains

U.K. Withholding Tax - Capital gains accruing to non-U.K. resident shareholders on the disposal of shares will not be subject to any withholding or deduction for or on account of U.K. tax, irrespective of the residence or the individual circumstances of the relevant shareholder.

U.K. Capital Gains Tax - A disposal of shares by an individual shareholder who is resident in the U.K. may, depending on his or her individual circumstances, give rise to a taxable capital gain or an allowable loss for the purposes of U.K. capital gains tax (“CGT”). An individual shareholder who temporarily ceases to be resident in the U.K. for a period of five years or less and who disposes of his or her shares during that period of temporary non-residence may be liable for CGT on a taxable capital gain accruing on the disposal on his or her return to the U.K. under certain anti-avoidance rules.

An individual shareholder who is not resident in the U.K. will not be subject to CGT on capital gains arising on the disposal of their shares, unless that shareholder carries on a trade, profession or vocation in the U.K. through a branch or agency in the U.K. and the shares were acquired, used in or for the purposes of the branch or agency or used in or for the purposes of the trade, profession or vocation carried on by the shareholder through the branch or agency. In these circumstances, the relevant non-U.K. resident shareholder may, depending on his or her individual circumstances, be subject to CGT on chargeable gains arising from a disposal of his or her shares. The rate of CGT in the tax year 2020/2021 is:

•10%, to the extent that the shareholder's total taxable gains and taxable income in a given year, including any chargeable gains arising from a disposal of his or her shares ("Total Taxable Gains and Income"), are less than or equal to the upper limit of the income tax basic rate band applicable to that shareholder in respect of that tax year (the "Band Limit"), and

•20%, to the extent that the shareholder's Total Taxable Gains and Income are more than the Band Limit.

U.K. Corporation Tax - A disposal of shares by a corporate shareholder resident in the U.K. may give rise to a chargeable gain or an allowable capital loss for the purposes of U.K. corporation tax. A corporate shareholder not resident in the U.K. will not be liable for U.K. corporation tax on chargeable gains accruing on the disposal of its shares, unless that shareholder carries on a trade in the U.K. through a permanent establishment in the U.K. and the shares were acquired, used in or for the purposes of the permanent establishment or used in or for the purposes of the trade carried on by the shareholder through the permanent establishment. In these circumstances, the relevant non-U.K. resident shareholder may, depending on its individual circumstances, be subject to U.K. corporation tax on chargeable gains arising from a disposal of its shares.

The financial year for U.K. corporation tax purposes runs from April 1 to March 31. The main rate of U.K. corporation tax on chargeable gains is 19% in the financial year 2020. Corporate shareholders may be entitled to an indexation allowance in computing the amount of a chargeable gain accruing on a disposal of the shares, which provides relief for the effects of inflation by reference to movements in the U.K. retail price index. Such indexation allowance is calculated only up to and including December 2017. From January 1, 2018, indexation allowance is frozen. Indexation allowance will be calculated for assets acquired before January 1, 2018, irrespective of the date of disposal of the asset.

If the conditions of the substantial shareholding exemption are satisfied in relation to a chargeable gain accruing to a corporate shareholder on a disposal of its shares, the chargeable gain will be exempt from U.K. corporation tax. The conditions of the substantial shareholding exemption that must be satisfied will depend on the individual circumstances of the relevant corporate shareholder. One of the conditions of the substantial shareholding exemption that must be satisfied is that the corporate shareholder must have held a substantial shareholding in the Company throughout a 12-month period beginning not more than six years before the day on which the disposal takes place. Ordinarily, a corporate shareholder will not be regarded as holding a substantial shareholding in us unless it (whether alone, or together with other group companies) holds more than 10% of our ordinary share capital.

U.K. Stamp Duty and SDRT

The discussion below relates to shareholders wherever resident but not to holders such as market makers, brokers, dealers and intermediaries, to whom special rules apply. Special rules also apply in relation to certain stock lending and repurchase transactions.

Transfer of Shares held in book entry form via DTC - A transfer of shares held in book entry (i.e., electronic) form within the facilities of the DTC system will not be subject to U.K. stamp duty or SDRT.

Transfers of Shares out of, or outside of, DTC - Subject to an exemption for certain low value transactions, a transfer of shares from within the DTC system out of that system or any transfer of shares that occurs entirely outside the DTC system generally will be subject to a charge to ad valorem U.K. stamp duty (normally payable by the transferee) at 0.5% of the purchase price of the shares (rounded up to the nearest multiple of £5). SDRT generally will be payable on an unconditional agreement to transfer such shares at 0.5% of the amount or value of the consideration for the transfer. However, such liability for SDRT generally will be cancelled and any SDRT paid will be refunded if the agreement is completed by a duly-stamped transfer within six years of either the date of the agreement or, if the agreement was conditional, the date when the agreement became unconditional.

We have put in place arrangements to require that shares held outside the facilities of DTC cannot be transferred into such facilities (including where shares are re-deposited into DTC by an existing shareholder) until the transferor of the shares has first delivered the shares to a depository we specify, so that stamp duty and/or SDRT may be collected in connection with the initial delivery to the depository. Before such transfer can be registered in our books, the transferor will be required to put in the depository funds to settle the resultant liability for stamp duty and/or SDRT, which will be 1.5% of the value of the shares, and to pay the transfer agent such processing fees as may be established from time to time.

Following decisions of the European Court of Justice and the U.K. First-tier Tax Tribunal, HMRC announced that it would not seek to apply a charge to stamp duty or SDRT on the issuance of shares (or, where it is integral to the raising of new capital, the transfer of new shares) into a depositary receipt facility or clearance system provider, such as DTC. Further, in its 2017 Autumn Budget, the U.K. government announced that it would not reintroduce the Stamp Duty and Stamp Duty Reserve Tax 1.5% charge on the issue of shares (and transfers integral to capital raising) into overseas clearance services and depositary receipt systems following the U.K.’s exit from the E.U., and HMRC has since confirmed that this charge will remain disapplied under the terms of the European Union (Withdrawal) Act 2018 following the end of the transition period on 31 December 2020. However, it is possible that the U.K. government may change or enact laws applicable to stamp duty or SDRT, which could have a material effect on the cost of trading in our shares.

The above statements are intended only as a general guide to the current U.K. stamp duty and SDRT position. Transfers to certain categories of persons are not liable to U.K. stamp duty or SDRT and transfers to others may be liable at a higher rate than discussed above.

Equity Compensation Plans

For information on shares issued or to be issued in connection with our equity compensation plans, see "Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters."

Issuer Repurchases of Equity Securities

The following table provides a summary of our repurchases of our equity securities during the quarter ended December 31, 2020.


Issuer Repurchases of Equity Securities
Period	Total Number of Securities Repurchased(1)	Average Price Paid per Security		Total Number of Securities Repurchased as Part of Publicly Announced Plans or Programs (2)	Approximate Dollar Value of Securities that May Yet Be Repurchased Under Plans or Programs
October 1 - October 31	17,313	$	0.11	—	$	500,000,000
November 1 - November 30	14,685	$	0.08	—	$	500,000,000
December 1 - December 31	5,549	$	0.06	—	$	500,000,000
Total	37,547	$	0.09	—

(1)During the quarter ended December 31, 2020, equity securities were repurchased from employees and non-employee directors by an affiliated employee benefit trust in connection with the settlement of income tax withholding obligations arising from the vesting of share awards. Such securities remain available for re-issuance in connection with employee share awards.

(2)Our shareholders approved a repurchase program at our annual shareholder meeting held in May 2018. Subject to certain provisions under English law, including the requirement for Valaris plc to have sufficient distributable reserves and for the Board to conclude that a repurchase is in the best interests of Valaris plc taking into account the interests of relevant stakeholders, we may repurchase up to a maximum of $500.0 million in the aggregate from one or more financial intermediaries under the program, but in no case more than 16.3 million shares. The program terminates in May 2023. As of December 31, 2020, there had been no share repurchases under the repurchase program. Our DIP Facility only permits the repurchase of shares of our common stock in certain circumstances and the repurchase of shares would likely require approval of

the bankruptcy court. We do not currently expect to make repurchases under the program while Valaris plc remains subject to chapter 11 bankruptcy proceedings..

Item 6. Selected Financial Data

Not applicable.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

INTRODUCTION

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 61 rigs, with drilling operations in almost every major offshore market across five continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 45 jackup rigs and a 50% equity interest in ARO, our 50/50 joint venture with Saudi Aramco, which owns an additional seven rigs. We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.

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 regions are generally of a short-term nature due to rig mobility.

from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020. In response to dramatically reduced oil price expectations for the near term, our customers reviewed, and in most cases lowered significantly, their capital expenditure plans in light of revised pricing expectations. This caused our customers to cancel or shorten the duration of many of our 2020 drilling contracts, cancel future drilling programs and seek pricing and other contract concessions, which led to material operating losses and liquidity constraints for us. While there has been some recent improvement to Brent crude oil prices, to approximately $65 per barrel in February 2021, there is still a significant amount of uncertainty around the sustainability of the improvement in oil prices to support a recovery in demand for offshore drilling services.

Additionally, the full impact that the pandemic and the decline in 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 outbreak, the effectiveness of the ongoing vaccine rollout, the duration of the oil price and demand decline, and the extent of disruptions to our operations. To date, the COVID-19 pandemic has resulted in only limited operational downtime. 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.

Chapter 11 Proceedings and Ability to Continue as a Going Concern

On August 19, 2020 (the “Petition Date”), the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. As part of the chapter 11 cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI) (the “Chapter 11 Cases”), the Debtors were granted “first-day” relief which enabled the Company to continue operating without interruption or disruption to its relationships with its customers and vendors or its high-quality service delivery. In particular, employee pay and benefits are expected to continue without interruption.

On August 18, 2020, the Debtors entered into the Original RSA with the Consenting Noteholders. On February 5, 2021, the Debtors entered into the Amended RSA with the Consenting Lenders and Consenting Noteholders, which contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA. Holders of approximately 100% of the total commitments outstanding under our revolving credit facility and holders of approximately 72% of the aggregate amount of our Senior Notes outstanding are party to the Amended RSA.

Pursuant to the Amended RSA the holders of the Company's Senior Notes (as defined below) will receive their pro rata share of (1) approximately 39% of new common stock issued after consummation of the restructuring (the “New Equity”) and (2) approximately 97.6% of the subscription rights to participate in the rights offering (the "Rights Offering") through which the Company will offer $550 million of new first lien secured notes (the "New Secured Notes"), which includes the Backstop Premium (as defined below). Additionally, holders of the Senior Notes who participate in the Rights Offering will receive their pro rata share of approximately 29.3% of the New Equity pursuant to the Rights Offering, together with the RCF Lenders (as defined below) who will receive their pro rata share of approximately 0.7% of the New Equity, and senior noteholders who agreed to backstop the Rights Offering will receive their pro rata share of approximately 2.63% of the New Equity, together with 0.07% of the New Equity reserved for RCF Lenders and approximately $48.8 million in New Secured Notes reserved for the holders of the Senior Notes and approximately $1.2 million in New Secured Notes reserved for the RCF Lenders (the "Backstop Premium"). Senior noteholders with respect to certain notes would receive an aggregate cash payment of $26 million in connection with settlement of certain alleged claims against the Company.

A reorganization pursuant to the terms of the Amended RSA provided lenders under the revolving credit facility (“RCF Lenders”) with an option to select between two alternative treatments: (1) the ability to participate on a pro rata basis in up to 14% of the Rights Offering plus a recovery of up to 30.8% of the New Equity and up to $45 million in cash, or (2) a pro rata recovery of up to 27.8% of the New Equity and up to $116.2 million in cash. Following the results of that election, the two RCF Lenders who chose to participate in the Rights Offering will receive their pro rata share of (1) approximately 5.3% of the New Equity, (2) approximately 2.4% of the New Secured Notes (and associated New Equity), (3) approximately $7.8 million in cash, and (4) their pro rata share of the Backstop Premium. The RCF Lenders who entered into the Amended RSA and elected not to participate in the Rights Offering will receive their pro rata share of (1) approximately 23.0% of the New Equity, and (2) approximately $96.1 million in cash.

The Amended RSA provides that holders of general unsecured claims will receive payment in full or reinstatement pursuant to the Bankruptcy Code (excluding claims against the entities party to, or guaranteeing, the new build contracts to be rejected by the Company, which shall receive their liquidation value unless otherwise agreed). Moreover, if holders of equity interests vote as a class in support of the restructuring, they will each receive their pro rata share of 7-year warrants to purchase up to 7% of New Equity (subject to dilution), with a strike price set at a price per share equal to the value at which the senior noteholders would receive a 100% recovery on their claims including accrued interest up to the Petition Date, as applicable. Lastly, to the extent amounts are borrowed, lenders under the DIP Facility (as defined below) will receive payment in full in cash, unless otherwise agreed and certain other fees owed to the DIP Lenders.

The Amended RSA contains certain covenants on the part of Valaris and the Consenting Creditors, including commitments by the Consenting Creditors to vote in favor of a plan of reorganization and commitments of Valaris and the Consenting Creditors to negotiate in good faith to finalize the documents and agreements governing the restructuring. The Amended RSA also provides for certain conditions to the obligations of the parties and for termination upon the occurrence of certain events, including without limitation, the failure to achieve certain milestones and certain breaches by the parties under the Amended RSA.

Subject to certain exceptions, under the Bankruptcy Code, the filing of the Chapter 11 Cases automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the date of the Chapter 11 Cases. Notwithstanding the general applicability of the automatic stay described above, governmental authorities may determine to continue actions brought under their regulatory powers.

Although Valaris intends to pursue the restructuring in accordance with the terms set forth in the Amended RSA, there can be no assurance that Valaris will be successful in completing a restructuring or any other similar transaction on the terms set forth in the Amended RSA, on different terms or at all. Among other things, the Amended RSA includes an outside date milestone requiring the Company’s emergence from chapter 11 by no later than June 15, 2021 (subject to a potential 60-day extension pursuant to the terms of the Amended RSA).

Other Chapter 11 Financial Disclosures

Pre-petition Charges

On August 18, 2020, the Company entered into the Backstop Commitment Agreement with certain backstop parties. In connection with this agreement, the Debtors paid a commitment fee of $20.0 million, in cash prior to the Petition Date. We have reported the backstop commitment fee and legal and other professional advisor fees incurred in relation to the Chapter 11 Cases, but prior to the Petition Date, as General and administrative expenses in our Consolidated Statement of Operations for the year ended December 31, 2020 in the amount of $64.7 million.

Reorganization Items

Expenditures, gains and losses that are realized or incurred by the Debtors as of or subsequent to the Petition Date and as a direct result of the Chapter 11 Cases are reported as Reorganization items, net in our Consolidated Statement of Operations for the year ended December 31, 2020. These costs include legal and other professional advisory service fees pertaining to the Chapter 11 Cases, all adjustments made to the carrying amount of certain pre-petition liabilities reflecting claims expected to be allowed by the Bankruptcy Court, contract items related to rejecting and amending certain operating leases ("Contract items") and DIP Facility fees.

The following table provides information about reorganization items incurred during the year ended December 31, 2020, as of or subsequent to the Petition Date (in millions):


	Year Ended December 31, 2020
Write-off of unamortized debt discounts, premiums and issuance costs	$	447.9
Contract items	(11.5)
Reorganization items (non-cash)	436.4


DIP Facility fees	20.0
Professional fees	66.8
Contract items	4.4
Reorganization items (fees)	91.2
Total reorganization items, net	$	527.6

Reorganization items (fees) unpaid	$	61.2
Reorganization items (fees) paid	$	30.0

Liabilities Subject to Compromise

The Debtors' pre-petition unsecured senior notes and related unpaid accrued interest as of the Petition Date have been classified as Liabilities Subject to Compromise on our Consolidated Balance Sheets. The liabilities are reported at the amounts expected to be allowed as claims by the Bankruptcy Court. Liabilities subject to compromise at December 31, 2020 consist of the following (in millions):


	December 31, 2020
6.875% Senior notes due 2020	$	122.9
4.70% Senior notes due 2021	100.7
4.875% Senior notes due 2022	620.8
3.00% Exchangeable senior notes due 2024	849.5
4.50% Senior notes due 2024	303.4
4.75% Senior notes due 2024	318.6
8.00% Senior notes due 2024	292.3
5.20% Senior notes due 2025	333.7
7.375% Senior notes due 2025	360.8
7.75% Senior notes due 2026	1,000.0
7.20% Debentures due 2027	112.1
7.875% Senior notes due 2040	300.0
5.40% Senior notes due 2042	400.0
5.75% Senior notes due 2044	1,000.5
5.85% Senior notes due 2044	400.0
Amounts drawn under Revolving Credit Facility	581.0
Accrued Interest on Senior Notes, Exchangeable Senior Notes, Debentures and Revolving Credit Facility	203.5
Rig holding costs(1)	13.9
Total liabilities subject to compromise	$	7,313.7

(1) Represents the holding costs incurred to maintain VALARIS DS-13 and VALARIS DS-14 in the shipyard until the delivery date.

Liquidity and Debt Maturities

As discussed in "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data", we have filed the Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness.

The commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under our Senior Notes and revolving credit facility. Any efforts to enforce payment obligations under the Senior Notes, including any rights to require the repurchase by the Company of the 2024 Convertible Notes upon the NYSE delisting of the Class A ordinary shares, and revolving credit facility are automatically stayed as a result of the filing of the Chapter 11 Cases. The $6.5 billion aggregate principal amount of Senior Notes outstanding as well as $581.0 million outstanding borrowings under our revolving credit facility as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020.

On September 25, 2020, following approval by the Bankruptcy Court, we entered into a senior secured superpriority debtor-in-possession term loan credit agreement (the “DIP Credit Agreement”), by and among the Company and certain wholly owned subsidiaries of the Company, as borrowers, the lenders party thereto and Wilmington Savings Fund Society, FSB, as administrative agent and security trustee, in an aggregate amount not to exceed $500.0 million (the “DIP Facility”) to provide liquidity during the pendency of the Chapter 11 Cases. On

February 5, 2021, we entered into an amendment to the Backstop Commitment Agreement, which we expect to provide exit financing in the form of a fully backstopped rights offering to senior noteholders and the RCF Lenders for $550 million of New Secured Notes. We expect the DIP Facility will provide sufficient liquidity for us during the pendency of the Chapter 11 Cases. Additionally, we expect the exit financing will provide the necessary liquidity to support ongoing operations and working capital needs.

As of December 31, 2020, we had $325.8 million in cash and there were no borrowings outstanding under the DIP Credit Agreement.

For the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. There can be no assurance that we will confirm and consummate a plan of reorganization as contemplated by the Amended RSA or complete another plan of reorganization with respect to the Chapter 11 Cases and as such, there is substantial doubt about our ability to continue as a going concern. Further, we have concluded that management’s plans do not alleviate the substantial doubt about our ability to continue as a going concern brought about by the significant risks and uncertainties related to our liquidity and Chapter 11 Cases for a period of one year after the date that the financial statements are issued.

See "Liquidity and Capital Resources" below and "Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Backlog

As of December 31, 2020, our backlog was $1.2 billion as compared to $2.5 billion as of December 31, 2019. Our floater backlog declined $641.6 million and our jackup backlog declined $421.7 million. The decrease in our backlog was due to customer contract cancellations, customer concessions and revenues realized, partially offset by the addition of backlog from new contract awards and contract extensions. Our other segment backlog declined $184.2 million due to contract concessions and revenues realized. Our backlog excludes ARO's backlog, but includes backlog from our rigs leased to ARO at the contractual rates. Contract rates with ARO are subject to adjustment resulting from the shareholder agreement. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

As revenues are realized and if we experience further customer contract cancellations, we may continue to experience declines in backlog, which would result in a decline in revenues and operating cash flows over the near-term. Contract backlog was adjusted for drilling contracts signed, terminated or concessions granted after each respective balance sheet date but prior to filing each annual report on March 2, 2021 and February 21, 2020, respectively.

BUSINESS ENVIRONMENT

Floaters

The floater contracting environment remains challenging due to limited demand and excess supply. Floater demand has declined significantly following the decline in commodity prices in 2014 which caused our customers to reduce capital expenditures, particularly for capital-intensive, long-lead deepwater projects, resulting in the cancellation and delay of drilling programs. Floater demand declined materially in March and April 2020, as our customers reduced capital expenditures particularly for capital-intensive, long-lead deepwater projects in the wake of oil price declines from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020. The decline in demand has resulted in the cancellation and delay of drilling programs and the termination of drilling contracts.

During 2020, we received notices of termination, requests for concessions, cancellation and/or deferral of drilling programs by operators and we may receive additional requests for concessions, termination and/or deferral notices during the pendency of the current market environment.

During the first quarter of 2020, VALARIS DS-12 was awarded a one-well contract that commenced in February 2020. VALARIS MS-1 was awarded a three-well contract that is expected to commence in the second quarter of 2021 and has an estimated duration of 155 days. VALARIS 8505 was awarded a one-well contract that was expected to commence in mid-November 2020, but is now expected to commence in June 2021 with an estimated duration of 80 days.

In March 2020, VALARIS DS-8 experienced a non-drilling incident while operating offshore Angola, resulting in the blowout preventer (BOP) stack being disconnected from the riser while the rig was moving between well locations. The BOP stack, which we later recovered, dropped to the seabed floor, clear of any subsea structures. No injuries, environmental pollution or third-party damage resulted from the BOP stack being disconnected. As a result of the incident, the operator terminated the contract. The termination resulted in a decline in our contracted revenue backlog of approximately $150 million. We carried loss of hire insurance covering $602,500 per day, after a 45-day deductible waiting period, through the end of the contract in November 2020. The waiting period expired on April 22, 2020. We received loss of hire insurance recoveries of $118.1 million, which represents the total amount owed to us under the applicable insurance policy. The recovery was recognized and recorded in Other operating income on our Consolidated Statements of Operations.

During the second quarter of 2020, the VALARIS DS-7 contract for operations offshore Ghana was terminated. Additionally, contracts awarded in the first quarter of 2020 for VALARIS DS-7 operations offshore Senegal/Mauritania, VALARIS DS-9 operations offshore Brazil and VALARIS MS-1 contract operations offshore Australia were terminated. Further, the VALARIS DPS-1 contract was terminated in June, earlier than the previously scheduled end date of September 2021, and the VALARIS DS-10, VALARIS DS-15 and VALARIS 8505 operated on reduced day rates for various periods during 2020. The VALARIS 5004 operated on a reduced day rate from mid-March to mid-April of 2020, at which point the contract was terminated.

During the third quarter of 2020, floater contracting remained challenging and no significant new contracts were executed.

In the fourth quarter of 2020, we extended the VALARIS DS-10 and VALARIS DS-18 contracts for an estimated 90 days and 60 days, respectively. In January 2021, we extended the VALARIS DS-12 contract for an estimated 100 days.

Our backlog for our floater segment was $205.7 million and $847.3 million as of December 31, 2020 and December 31, 2019, respectively. The decrease in our backlog was due to customer contract cancellations, customer concessions and revenues realized, partially offset by the addition of backlog from new contract awards and contract extensions.

The VALARIS 6002 was sold in January 2020 resulting in an insignificant pre-tax gain. Additionally, the VALARIS 5004 was sold in April 2020 resulting in an insignificant pre-tax loss. During the second quarter of 2020, we began marketing VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6 and classified these rigs as held-for-sale, resulting in an impairment of approximately $14.6 million as the net book value exceeded the fair value less costs to sell. During the third quarter of 2020, we sold VALARIS 8500, VALARIS 8501 and VALARIS 8502 for a total pre-tax gain of $7.7 million, we sold the VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6 for an insignificant pre-tax loss and we classified VALARIS 8504 as held-for-sale. The net book value of VALARIS 8504 did not exceed the fair value less costs to sell; therefore, we did not recognize an impairment upon classifying this rig as held-for-sale. The rig was subsequently sold in October 2020.

There are approximately 25 newbuild drillships and semisubmersible rigs reported to be under construction, of which approximately 10 are scheduled to be delivered before the end of 2021. Most newbuild floaters are uncontracted. Several newbuild deliveries have been delayed into future years, and we expect that more uncontracted newbuilds will be delayed or cancelled.

Drilling contractors have retired approximately 160 floaters since the beginning of 2014. Approximately 15 floaters older than 30 years of age are currently idle, approximately ten additional floaters older than 30 years of age have contracts that will expire by the end of 2021 without follow-on work. Additional rigs are expected to become idle as a result of market conditions. Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify these aging rigs may prove cost prohibitive. Drilling contractors will likely elect to scrap or cold-stack some or all of these rigs. Improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized.

Jackups

During 2020, demand for jackups has declined in light of increased market uncertainty. We have received notices of termination, requests for concessions, cancellation and/or deferral of drilling programs by operators, and we may receive additional requests for concessions, termination and/or deferral notices during the pendency of the current market environment.

During the first quarter of 2020, we executed a three-well contract for VALARIS JU-118 that commenced in mid-March 2020 with an estimated duration of 425 days. Additionally, we executed a two-well contract for VALARIS JU-144 that commenced in May 2020 with an estimated duration of 300 days. The previously disclosed contract for the VALARIS JU-144 that was expected to commence in September 2020 was transferred to the VALARIS JU-102 and was subsequently delayed to September 2021, with VALARIS JU-102 being put on a standby rate until the new commencement date. VALARIS JU-87 was awarded a one-well contract that commenced in March 2020 with an estimated duration of 30 days and an extension to May 2020 for another well with an estimated duration of 30 days. During the first quarter of 2020, the VALARIS JU-109 contract was terminated.

During the second quarter of 2020, the VALARIS JU-84 contract was terminated and we negotiated a day rate reduction for VALARIS JU-290 to be suspended at a reduced rate from September 2020 to February 2021. In April 2020, there were various negotiated customer contract concessions, including day rate reductions. VALARIS JU-120 was suspended at a reduced day rate from late-April 2020 to September 2020 and VALARIS JU-72 was suspended at a reduced day rate from April 2020 to August 2020. VALARIS JU-92 was previously expected to be suspended at a reduced day rate from mid-May 2020 to late-September 2020, but has continued to operate at full day rate. VALARIS JU-249 ended its contract in April 2020 and VALARIS JU-100 ended its contract in late-April 2020, in both cases, earlier than expected.

During the second quarter of 2020, we executed short-term contracts for VALARIS JU-102 and VALARIS JU-87 that commenced in June 2020 and May 2020, respectively. We were also awarded a two-well extension for VALARIS JU-291 with an expected duration of approximately 230 days from January 2021 to August 2021. We executed a four-year contract for VALARIS JU-104 expected to commence in September 2020, which was subsequently terminated during the third quarter of 2020. Additionally, we extended the VALARIS JU-67 contract 210 days from May 2020 to December 2020.

During the third quarter of 2020, VALARIS JU-54 and VALARIS JU-76 were put on a reduced standby rate until late 2020. Following the reduced standby rate period, VALARIS JU-54 will be operating at an agreed upon reduced day rate until the end of 2021 and VALARIS JU-76 will be suspended until it resumes operation in March 2021 at an agreed upon reduced day rate until the end of 2021. During the third quarter, we also negotiated reduced rates for VALARIS 108, VALARIS 140 and VALARIS 141. The reduced rates are effective beginning the second quarter of 2020 through the end of their contract terms in November 2021, June 2021 and August 2021, respectively. Additionally, we executed a one year contract extension for VALARIS 110 that commenced in October 2020 and executed a short-term contract for VALARIS 115 that commenced in February 2021.

During the fourth quarter of 2020, we executed an eight-well contract extension for VALARIS JU-292 Additionally, we extended the VALARIS JU-67 contract for approximately 190 days from December 2020 to June 2021. In January and February 2021, we executed a two-year contract for VALARIS JU-121, an approximate one-year contract for VALARIS JU-247, and the VALARIS JU-122 contract was extended for approximately 95 days from April 2021 to July 2021.

Our backlog for our jackup segment was $859.5 million and $1,281.2 million as of December 31, 2020 and December 31, 2019, respectively. The decrease in our backlog was due to customer contract cancellations, customer concessions and revenues realized, partially offset by the addition of backlog from new contract awards and contract extensions.

The VALARIS JU-68 was sold in January 2020, resulting in an insignificant pre-tax gain. Additionally, VALARIS JU-70 and VALARIS JU-71 were sold in June 2020 resulting in insignificant pre-tax losses. During the second quarter of 2020, we classified VALARIS JU-105 as held-for-sale, resulting in an insignificant impairment as the net book value exceeded the fair value less cost to sell. During the third quarter of 2020, we sold VALARIS JU-87 and VALARIS JU-105 for an insignificant pre-tax gain and we classified VALARIS JU-84 and VALARIS JU-88 as held-for-sale. The net book values of VALARIS JU-84 and VALARIS JU-88 did not exceed the fair values less costs to sell, therefore, we did not recognize an impairment upon classifying these rigs as held-for-sale. These rigs were subsequently sold in October 2020.

There are approximately 40 newbuild jackup rigs reported to be under construction, of which 20 are scheduled to be delivered before the end of 2021. 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 approximately 120 jackups since the beginning of 2014. Approximately 90 jackups older than 30 years of age are currently idle and 40 jackups that are 30 years of age or older have contracts expiring by the end of 2021 without follow-on work. Expenditures required to re-certify these aging rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold-stack these rigs. Improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized.

RESULTS OF OPERATIONS

The following table summarizes our consolidated results of operations for each of the years in the three-year period ended December 31, 2020 (in millions):


	2020		2019		2018
Revenues	$	1,427.2	$	2,053.2	$	1,705.4
Operating expenses
Contract drilling (exclusive of depreciation)	1,458.6		1,806.0		1,319.4
Loss on impairment	3,646.2		104.0		40.3
Depreciation	540.8		609.7		478.9
General and administrative	214.6		188.9		102.7
Total operating expenses	5,860.2		2,708.6		1,941.3
Other operating income	118.1		—		—
Equity in losses of ARO	(7.8)		(12.6)		—
Operating loss	(4,322.7)		(668.0)		(235.9)
Other income (expense), net	(794.3)		604.2		(303.0)
Provision (benefit) for income taxes	(259.4)		128.4		89.6
Loss from continuing operations	(4,857.6)		(192.2)		(628.5)
Loss from discontinued operations, net	—		—		(8.1)
Net loss	(4,857.6)		(192.2)		(636.6)
Net (income) loss attributable to noncontrolling interests	2.1		(5.8)		(3.1)
Net loss attributable to Valaris	$	(4,855.5)	$	(198.0)	$	(639.7)

Overview

Year Ended December 31, 2020

Revenues declined by $626.0 million, or 30%, as compared to the prior year. This decline is primarily attributable to a $287.4 million decline in revenue resulting from the sale of VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88, and VALARIS JU-96, which operated in the prior year comparative period, a $286.7 million decline in revenue as a result of fewer days under contract across our fleet, a $150.0 million decline in revenue due to the termination of the VALARIS DS-8 contract and a $28.3 million and $16.0 million, decline in revenues earned under the Secondment Agreement and Transition Services Agreement with ARO, respectively. Further, the additional revenues earned under Lease Agreements with ARO due to the inclusion of a full year of results in 2020 as compared to the period from April 11, 2019 to December 31, 2019 from the comparable period was offset by a reduction of our rental revenues to reflect an amendment to the Shareholder Agreement that impacted the bareboat charter rate in the lease agreements. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information. The decline in revenue was partially offset by $113.6 million of revenue earned by rigs added from the Rowan Transaction, and $46.3 million of contract termination fees received for certain rigs.

Contract drilling expense declined by $347.4 million, or 19%, as compared to the prior year primarily due to a $184.4 million decline as a result of lower costs on idle rigs, $134.5 million lower costs on VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5, VALARIS DS-6, VALARIS JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88 and VALARIS JU-96, as these rigs were sold, and reduced costs resulting primarily from spend control efforts. Additionally, there was a decline in expenses due to a decrease in services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO

during the second quarter of 2020. This decrease was partially offset by $140.1 million of contract drilling expenses incurred on rigs added from the Rowan Transaction.

During the first and second quarters of 2020, we recorded non-cash losses on impairment totaling $3.6 billion, with respect to assets in our fleet, primarily due to the adverse change in the current and anticipated market for these assets. See "Note 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Depreciation expense declined by $68.9 million, or 11%, as compared to the prior year period primarily due to lower depreciation expense on certain assets which were impaired during the first and second quarters of 2020, some of which were subsequently sold in the third and fourth quarters of 2020. This decrease was partially offset by depreciation expense recorded for rigs added in the Rowan Transaction as well as for the VALARIS JU-123 which commenced operations in August 2019.

General and administrative expenses increased by $25.7 million, or 14%, as compared to the prior year period primarily due to the backstop commitment fee and legal and other professional advisor fees incurred in relation to the Chapter 11 Cases, but prior to the Petition Date. This increase was partially offset by merger related costs incurred in the prior year comparative period.

Other operating income of $118.1 million recognized during 2020 was due to loss of hire insurance recoveries collected for the VALARIS DS-8 non-drilling incident.

Other expense, net, increased by $1.4 billion as compared to the prior year period, primarily due to the prior period $637.0 million gain on bargain purchase recognized in connection with the Rowan Transaction, pre-tax gain related to the settlement award from the SHI matter of $200.0 million and $194.1 million of pre-tax gain on debt extinguishment related to the repurchase of senior notes in connection with July 2019 tender offers. Additionally, the current year period includes $527.6 million of reorganization items directly related to the Chapter 11 Cases. Partially offsetting these increases, our Interest Expense, net decreased $137.7 million primarily due to $140.7 million as we discontinued accruing interest on our outstanding debt subsequent to the chapter 11 filing.

Year Ended December 31, 2019

Revenues increased by $347.8 million, or 20%, as compared to the prior year primarily due to $322.2 million of revenue earned by the Rowan rigs, $125.5 million due to revenues earned from our rigs leased to ARO and revenues earned from the Secondment Agreement and Transition Services Agreement, and $84.1 million due to the commencement of VALARIS DS-9, VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141 drilling operations. This increase was partially offset by the sale of ENSCO 6001, VALARIS 5006 and ENSCO 97, which operated in the prior-year period, and lower average day rates across the remaining fleet.

Contract drilling expense increased by $486.6 million, or 37%, as compared to the prior year primarily due to $351.2 million of contract drilling expense incurred by the Rowan rigs, $57.0 million due to expenses incurred under the Secondment Agreement and by our rigs leased to ARO, $38.2 million due to the commencement of VALARIS DS-9, and $31.3 million due to the commencement of drilling operations for VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141. This increase was partially offset by the sale of ENSCO 6001, VALARIS 5006 and ENSCO 97, which operated in the prior-year period.

General and administrative expenses increased by $86.2 million, or 84%, as compared to the prior year, primarily due to transaction and integration costs associated with the Rowan Transaction.

Rig Counts, Utilization and Average Day Rates

The following table summarizes our offshore drilling rigs by reportable segment, rigs under construction, rigs held-for-sale and ARO's offshore drilling rigs as of December 31, 2020, 2019 and 2018. Legacy Rowan and ARO rigs are included from the date the Rowan Transaction closed in April 2019:


	2020	2019	2018
Floaters(1)	16	24	22
Jackups(2)	36	41	34
Other(3)	9	9	—
Held-for-sale(4)	—	3	—
Total Valaris	61	77	56
Valaris - Under construction(5)	2	2	3
ARO(6)	7	7	—
ARO - Under construction (7)	2	—	—

(1)During 2020, we sold VALARIS 5004, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6.

During 2019, we added VALARIS DS-15, VALARIS DS-16, VALARIS DS-17 and VALARIS DS-18 from the Rowan Transaction, sold VALARIS 5006 and classified VALARIS 6002 as held-for-sale

(2)During 2020, we sold VALARIS JU-71, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88 and VALARIS JU-105.

During 2019, we added 10 jackups from the Rowan Transaction, exclusive of rigs leased to ARO that are included in Other, accepted delivery of VALARIS JU-123, classified VALARIS JU-68 and VALARIS JU-70 as held-for-sale and sold VALARIS JU-96 and ENSCO 97.

(3)During 2019, we added nine jackups from the Rowan Transaction that are leased to ARO.

(4)During 2019, we classified VALARIS JU-68, VALARIS JU-70 and VALARIS 6002 as held-for-sale, all of which were subsequently sold in 2020.

(5)During 2019, we accepted the delivery of VALARIS JU-123.

(6)This represents the seven rigs owned by ARO.

(7)During 2020, ARO ordered two newbuild jackup rigs scheduled for delivery in 2022.

The following table summarizes our and ARO's rig utilization and average day rates from continuing operations by reportable segment for each of the years in the three-year period ended December 31, 2020. Rig utilization and average day rates include results of rigs added in the Rowan Transaction or ARO from the date the Rowan Transaction closed in April 2019:


	2020		2019		2018
Rig Utilization(1)
Floaters	29%		47%		46%
Jackups	54%		66%		63%
Other(2)	98%		100%		100%
Total Valaris	54%		63%		56%
ARO	94%		93%		—%
Average Day Rates(3)
Floaters	$	178,372	$	218,837	$	248,395
Jackups	83,618		78,133		77,086
Other(2)	31,207		49,236		81,751
Total Valaris	$	83,845	$	108,313	$	128,365
ARO	$	100,921	$	71,170	$	—

(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. 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 nine 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 and revenues attributable to amortization of drilling contract intangibles, by the aggregate number of contract days, adjusted to exclude contract days associated with certain mobilizations, demobilizations and shipyard contracts.

Detailed explanations of our operating results, including discussions of revenues, contract drilling expense and depreciation expense by segment, are provided below.

Operating Income by Segment

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 Rig Lease Agreements, the Secondment Agreement and the Transition Services Agreement. Floaters, Jackups and ARO are also reportable segments.

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". Substantially all of the expenses incurred associated with our Transition Services Agreement are included in general and administrative under "Reconciling Items" in the table set forth below.

The full operating results included below for ARO (representing only results of ARO from the closing date of the Rowan Transaction) are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO and related arrangements.

Upon establishment of ARO, Rowan entered into (1) an agreement to provide certain back-office services for a period of time until ARO develops its own infrastructure (the "Transition Services Agreement"), and (2) an agreement to provide certain Rowan employees through secondment arrangements to assist with various onshore and offshore services for the benefit of ARO (the "Secondment Agreement"). These agreements remained in place subsequent to the Rowan Transaction. Pursuant to these agreements, we or our seconded employees provide various services to ARO, and in return, ARO provides remuneration for those services. During the quarter ended June 30, 2020, almost all remaining employees seconded to ARO became employees of ARO. Additionally, our services to ARO under the Transition Services Agreement were completed as of December 31, 2020. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO and related arrangements.

Segment information for each of the years in the three-year period ended December 31, 2020 is presented below (in millions).

Year Ended December 31, 2020


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	505.8	$	765.3	$	549.4	$	156.1	$	(549.4)	$	1,427.2
Operating expenses
Contract drilling (exclusive of depreciation)	633.9		733.3		388.2		91.4		(388.2)		1,458.6
Loss on impairment	3,386.2		254.3		—		5.7		—		3,646.2
Depreciation	262.8		217.2		54.8		44.8		(38.8)		540.8
General and administrative	—		—		24.2		—		190.4		214.6
Other operating income	118.1		—		—		—		—		118.1
Equity in losses of ARO	—		—				—		(7.8)		(7.8)
Operating income (loss)	$	(3,659.0)	$	(439.5)	$	82.2	$	14.2	$	(320.6)	$	(4,322.7)

Year Ended December 31, 2019


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	1,014.4	$	834.6	$	410.5	$	204.2	$	(410.5)	$	2,053.2
Operating expenses
Contract drilling (exclusive of depreciation)	898.6		788.9		280.2		118.5		(280.2)		1,806.0
Loss on impairment	88.2		10.2		—		—		5.6		104.0
Depreciation	362.3		203.3		40.3		25.5		(21.7)		609.7
General and administrative	—		—		27.1		—		161.8		188.9
Equity in losses of ARO	—		—		—		—		(12.6)		(12.6)
Operating income (loss)	$	(334.7)	$	(167.8)	$	62.9	$	60.2	$	(288.6)	$	(668.0)

Year Ended December 31, 2018


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	1,013.5	$	630.9	$	—	$	61.0	$	—	$	1,705.4
Operating expenses
Contract drilling (exclusive of depreciation)	737.4		526.5		—		55.5		—		1,319.4
Loss on impairment	—		40.3		—		—		—		40.3
Depreciation	311.8		153.3		—		—		13.8		478.9
General and administrative	—		—		—		—		102.7		102.7
Operating income (loss)	$	(35.7)	$	(89.2)	$	—	$	5.5	$	(116.5)	$	(235.9)

Floaters

2020 compared to 2019

During 2020, revenues declined by $508.6 million, or 50%, as compared to the prior year due to $241.0 million from the sale of VALARIS 5004, VALARIS 5006, and VALARIS 6002, which operated in the prior year comparative period, $189.4 million as a result of fewer days under contract across the floater fleet and $150.0 million due to the termination of the VALARIS DS-8 contract. This decline was partially offset by $46.3 million of contract termination fees received for certain rigs and $40.1 million earned by rigs added in the Rowan Transaction.

Contract drilling expense declined by $264.7 million, or 29%, as compared to the prior year primarily due to $131.1 million lower cost on idle rigs, $92.3 million lower costs on VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6, as such rigs were sold, and reduced costs resulting primarily from spend control efforts. This decrease was partially offset by $53.8 million of contract drilling expense incurred by rigs added in the Rowan Transaction.

During 2020, we recorded a non-cash loss on impairment of $3.4 billion, with respect to assets in our Floater segment due to the adverse change in the current and anticipated market for these assets. See "Note 7 -Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Depreciation expense declined by $99.5 million, or 27%, compared to the prior year primarily due to lower depreciation on certain non-core assets which were impaired during the first and second quarters of 2020 and subsequently sold in the third and fourth quarters of 2020 with the exception of one floater.

Other operating income of $118.1 million recognized during 2020 was due to loss of hire insurance recoveries collected for the VALARIS DS-8 non-drilling incident.

2019 compared to 2018

During 2019, revenues were consistent with the prior year. The $109.3 million of revenue earned by the Rowan rigs and $41.0 million due to the commencement of VALARIS DS-9 drilling operations were offset by the sale of VALARIS 5006 and ENSCO 6001, fewer days under contract and lower average day rates across the remaining floater fleet.

Contract drilling expense increased by $161.2 million, or 22%, as compared to the prior year primarily due to $142.4 million of contract drilling expense incurred by the Rowan rigs and $38.2 million due to the commencement of VALARIS DS-9 drilling operations. The increase was partially offset by the sale of VALARIS 5006 and ENSCO 6001 and lower costs on idle rigs.

Depreciation expense increased by $50.5 million, or 16%, compared to the prior year primarily due to the addition of the Rowan rigs to the fleet and commencement of VALARIS DS-9 drilling operations.

Jackups

2020 compared to 2019

During 2020, revenues declined by $69.3 million, or 8%, as compared to the prior year primarily due to $97.3 million as a result of fewer days under contract across the jackup fleet and $46.4 million due to the sale of VALARIS JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88, and VALARIS JU-96, which operated in the prior year period. This decrease was partially offset by $73.5 million of revenue earned by rigs added in the Rowan Transaction.

Contract drilling expense declined by $55.6 million, or 7%, as compared to the prior year primarily due to $53.3 million lower cost on idle rigs, $42.2 million from the sale of VALARIS JU-68, VALARIS JU-84, VALARIS JU-87, VALARIS JU-88 and VALARIS JU-96 which operated in the prior year period, and reduced costs resulting from spend control efforts. This decrease was partially offset by $86.3 million of contract drilling expense incurred by rigs added in the Rowan Transaction.

During 2020, we recorded a non-cash loss on impairment of $254.3 million with respect to assets in our Jackup segment primarily due to the adverse change in the current and anticipated market for these assets. See "Note 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Depreciation expense increased by $13.9 million, or 7%, as compared to the prior year primarily due to the addition of rigs in the Rowan Transaction as well as the commencement of the VALARIS JU-123 in August 2019. This increase was partially offset by lower depreciation on certain non-core assets which were impaired during 2020 of which three of these jackups were sold in 2020.

2019 compared to 2018

During 2019, revenues increased by $203.7 million, or 32%, as compared to the prior year primarily due to $212.9 million of revenue earned by the Rowan rigs and $43.1 million due to the commencement of VALARIS

JU-123, VALARIS JU-140 and VALARIS JU-141 drilling operations. This increase was partially offset by the sale of ENSCO 97 and ENSCO 80, which operated in the prior-year period.

Contract drilling expense increased by $262.4 million, or 50%, as compared to the prior year primarily due to $208.8 million of contract drilling expense incurred by the Rowan rigs and $31.3 million due to the commencement of drilling operations for VALARIS JU-123, VALARIS JU-140 and VALARIS JU-141. This increase was partially offset by the sale of ENSCO 97 and ENSCO 80.

Depreciation expense increased by $50.0 million, or 33%, as compared to the prior year primarily due to the addition of rigs in the Rowan Transaction and the commencement of VALARIS JU-123 in August 2019.

ARO

ARO currently owns a fleet of seven jackup rigs, leases another nine jackup rigs from us and has plans to purchase 20 newbuild jackup rigs over an approximate 10 year period. In January 2020, ARO ordered the first two newbuild jackups with delivery scheduled 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. 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. The Company's capital contributions to ARO pursuant to this requirement may require approval of the Bankruptcy Court during the Chapter 11 Cases. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis. The joint venture partners agreed that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. 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. We lease rigs to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All nine jackup rigs leased to ARO are under three-year contracts with Saudi Aramco. All seven ARO-owned jackup rigs are under long-term contracts with Saudi Aramco.

The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for the seven ARO-own jackup rigs that operated during the period from the date of the Rowan Transaction in April 2019 through December 31, 2020.

The contract drilling, depreciation and general and administrative expenses are also for the period from the date of the Rowan Transaction in April 2019 through December 31, 2020. Contract drilling expenses are inclusive of the bareboat charter fees for the rigs leased from us. Costs incurred under the Secondment Agreement are included in contract drilling expense and general and administrative, depending on the function to which the seconded employees' services related. General and administrative expenses include costs incurred under the Transition Services Agreement and other administrative costs.

2020 compared to 2019

During 2020, revenues increased by $138.9 million, or 34%, as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a full year of ARO results in 2020 compared to a partial year in 2019.

Contract drilling expense increased by $108.0 million, or 39%, in 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a full year of ARO results in 2020 compared to a partial year in 2019.

Depreciation expense increased by $14.5 million, or 36%, in 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a full year of ARO results in 2020 compared to a partial year in 2019.

General and administrative expenses decreased by $2.9 million, or 11%, in 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 primarily due to a decrease in services received under the Transition Services Agreement.

See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO.

Other

2020 compared to 2019

Other revenues declined $48.1 million, or 24%, for the year ended December 31, 2020, as compared to the prior year period, primarily due to due to lower revenues earned under the Secondment Agreement and Transition Services Agreement with ARO of $28.3 million and $16.0 million, respectively. Further, the additional revenues earned under Lease Agreements due to the inclusion of a full year of results in 2020 as compared to the period from April 11, 2019 to December 31, 2019 from the comparable period was offset by a reduction of our rental revenues to reflect an amendment to the Shareholder Agreement that impacted the bareboat charter rate in the lease agreements. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Other contract drilling expenses declined $27.1 million, or 23%, for the year ended December 31, 2020, as compared to the prior year period, primarily due to a decrease in services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO during the second quarter of 2020.

During 2020, we recorded a non-cash loss on impairment of $5.7 million, with respect to a certain contract intangible due to current market conditions. See "Note 4 - Rowan Transaction" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Depreciation expense increased $19.3 million, or 76%, as compared to the prior year primarily due to the impact of full year results for 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 as well as additional depreciation due to capital expenditures and the commencement of the Bess Brants and Ernest Dees which were in the shipyard most of the comparative period.

2019 compared to 2018

Other revenues increased $143.2 million, or 235%, for the year ended December 31, 2019, as compared to the prior year period, primarily due to revenues earned from our rigs leased to ARO, revenues earned under the Secondment Agreement and Transition Services Agreement of $58.2 million, $49.9 million and $17.3 million, respectively.

Other contract drilling expenses increased $63.0 million, or 114%, for the year ended December 31, 2019, respectively, as compared to the prior year period, primarily due to costs incurred for services provided to ARO under the Secondment Agreement and other costs for ARO rigs.

Impairment of Long-Lived Assets

See "Note 4 - Rowan Transaction", "Note 7 - Property and Equipment" and "Note 15 - Leases" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on impairment of long-lived assets.

Other Income (Expense), Net

The following table summarizes other income (expense), net, for each of the years in the three-year period ended December 31, 2020 (in millions):


	2020		2019		2018
Interest income	$	19.7	$	28.1	$	14.5
Interest expense, net:
Interest expense	(291.9)		(449.2)		(345.3)
Capitalized interest	1.3		20.9		62.6
	(290.6)		(428.3)		(282.7)
Reorganization items, net	(527.6)		—		—
Other, net	4.2		1,004.4		(34.8)
	$	(794.3)	$	604.2	$	(303.0)

Interest income decreased during 2020 as compared to the respective prior-year period primarily due to fewer investments in the current year as compared to the prior year comparable period. Interest income increased during 2019 as compared to the respective prior-year period primarily due to interest income of $16.8 million earned on the shareholder note from ARO (see "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on ARO) acquired in the Rowan Transaction.

Interest expense decreased during 2020 by $157.3 million, or 35%, as compared to the prior year as we did not accrue interest on our outstanding debt or amortize discounts, premiums and debt issuance costs subsequent to the chapter 11 filing totaling $140.7 million and $29.8 million, respectively. Further, debt repurchases resulted in interest savings of $19.2 million. These declines were partially offset by increased interest on debt acquired from Rowan totaling $35.7 million. Interest expense increased during 2019 by $103.9 million, or 30%, as compared to the prior year due to interest expense incurred on senior notes acquired in the Rowan Transaction.

Interest expense capitalized declined during 2020 and 2019 by $19.6 million, or 94%, and $41.7 million, or 67%, as compared to the prior year periods, due to a decline in the amount of capital invested in newbuild construction resulting from newbuild rigs being placed into service.

Reorganization items, net of $527.6 million recognized during 2020 was related to other net losses and expenses directly related to Chapter 11 Cases, consisting of the write off of unamortized debt discounts, premiums and issuance costs of $447.9 million, professional fees of $66.8 million and financing costs of $20.0 million, partially offset by $7.1 million of contract items relating to rejection and amendment of certain operating leases.

Other, net, during 2020 included $14.6 million of net periodic income, excluding service cost, for our pension and retiree medical plans as well as a $3.1 million pre-tax gain on extinguishment of debt. We also incurred a $6.3 million reduction to gain on bargain purchase as a result of measurement adjustments made in the first quarter 2020 related to the Rowan Transaction.

Other, net, during 2019 included a gain on bargain purchase recognized in connection with the Rowan Transaction of $630.7 million, a pre-tax gain related to the award related to settlement with Samsung Heavy

Industries of $200.0 million and a pre-tax gain from debt extinguishment of $194.1 million related to the senior notes repurchased in connection with our July 2019 tender offers. This increase was partially offset by settlement of a Middle East dispute discussed in "Note 14- Commitments and Contingencies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" as well as foreign currency losses as discussed below.

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 losses, inclusive of offsetting fair value derivatives, were $11.0 million, $7.4 million and $17.2 million, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018, respectively. Net foreign currency exchange losses incurred during 2020 included $7.3 million and $1.4 million related to euros and Angolan kwanza, respectively. Net foreign currency exchange losses incurred during 2019 included $3.3 million and $2.8 million, related to euros and Angolan kwanza, respectively. During 2018, the net foreign currency exchange losses incurred included $5.8 million, $3.6 million and $2.0 million, related to Angolan kwanza, euros and Brazilian reals, respectively.

Net unrealized gains of $3.2 million and $5.0 million and unrealized losses of $0.7 million from marketable securities held in our supplemental executive retirement plans ("the SERP") were included in other, net, in our consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018, respectively. Information on the fair value measurement of our marketable securities held in the SERP is presented in "Note 6 - Fair Value Measurements" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."

Provision for Income Taxes

Valaris plc, our parent company, is domiciled and resident in the U.K. 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-U.K. subsidiaries is generally not subject to U.K. taxation. Income tax rates imposed in the tax jurisdictions in which our subsidiaries conduct operations vary, as does the tax base to which the rates are applied. In some cases, tax rates may be applicable to gross revenues, statutory or negotiated deemed profits or other bases utilized under local tax laws, rather than to net income.

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. In periods of declining profitability, our income tax expense may not decline proportionally with income, which could result in higher effective income tax rates. Further, we may continue to incur income tax expense in periods in which we operate at a loss.

U.S. Tax Reform and CARES Act

The U.S. Tax Cuts and Jobs Act (“U.S. tax reform”) was enacted on December 22, 2017 and introduced significant changes to U.S. income tax law, effective January 1, 2018. Due to the timing of the enactment of U.S. tax reform and the complexity involved in applying its provisions, the U.S. Treasury Department continued finalizing rules associated with U.S. tax reform during 2018 and 2019. During 2019, we recognized a tax expense of $13.8 million associated with final rules issued related to U.S. tax reform. During 2018, we recognized a tax benefit of $11.7 million associated with the one-time transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries.

The U.S. Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act") was enacted on March 27, 2020 and introduced various corporate tax relief measures into law. Among other things, the CARES Act allows net operating losses ("NOLs") generated in 2018, 2019 and 2020 to be carried back to each of the five preceding years. During 2020, we recognized a tax benefit of $122.1 million associated with the carryback of NOLs to recover taxes paid in prior years.

Effective Tax Rate

During the year ended December 31, 2020, we recorded an income tax benefit of $259.4 million and during the years ended December 31, 2019 and 2018 we recorded income tax expense of $128.4 million and $89.6 million, respectively. Our consolidated effective income tax rates during the same periods were 5.1%, (201.3)% and (16.6)%, respectively.

Our 2020 consolidated effective income tax rate includes a $322.4 million tax benefit associated with the impact of various discrete tax items, including restructuring transactions, impairments of rigs and other assets, implementation of the U.S. CARES Act, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years, rig sales, reorganization items and the resolution of other prior period tax matters.

Our 2019 consolidated effective income tax rate included $2.3 million associated with the impact of various discrete tax items, including $28.3 million of tax expense associated with final rules relating to U.S. tax reform, gains on repurchase of debt and settlement proceeds, partially offset by $26.0 million of tax benefit related to restructuring transactions, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years and other resolutions of prior year tax matters and rig sales.

Our 2018 consolidated effective income tax rate includes the impact of various discrete tax items, including $46.0 million of tax benefit associated with the utilization of foreign tax credits subject to a valuation allowance, the transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries, and a restructuring transaction, partially offset by $21.0 million of tax expense related to recovery of certain costs associated with an ongoing legal matter, repurchase and redemption of senior notes, unrecognized tax benefits associated with tax positions taken in prior years and rig sales.

Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years ended December 31, 2020, 2019 and 2018 were (7.6)%, (14.6)% and (24.8)%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-year period result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and differences in tax rates in such taxing jurisdictions.

Divestitures

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 DIP Credit Agreement, 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 older, lower-specification or non-core rigs.

We sold the following rigs during the three-year period ended December 31, 2020 (in millions):


Rig	Date of Sale	Classification(1)	Segment(1)	Net Proceeds		Net Book Value(2)		Pre-tax Gain/(Loss)
VALARIS 8504	October 2020	Continuing	Floater	$	4.7	$	4.0	$	.7
VALARIS JU-88	October 2020	Continuing	Jackups	1.4		.3		1.1
VALARIS JU-84	October 2020	Continuing	Jackups	1.2		.3		.9
VALARIS JU-105	September 2020	Continuing	Jackups	2.1		.8		1.3
VALARIS DS-6	August 2020	Continuing	Floaters	5.7		6.1		(.4)
VALARIS JU-87	August 2020	Continuing	Jackups	.3		.2		.1
VALARIS 8500	July 2020	Continuing	Floaters	4.0		.7		3.3
VALARIS 8501	July 2020	Continuing	Floaters	4.0		.7		3.3
VALARIS 8502	July 2020	Continuing	Floaters	1.8		.7		1.1
VALARIS DS-3	July 2020	Continuing	Floaters	6.1		6.1		—
VALARIS DS-5	July 2020	Continuing	Floaters	6.1		6.1		—
VALARIS JU-71	June 2020	Continuing	Jackups	.2		.8		(.6)
VALARIS JU-70	June 2020	Continuing	Jackups	.6		1.0		(.4)
VALARIS 5004	April 2020	Continuing	Floaters	1.9		2.0		(.1)
VALARIS JU-68	January 2020	Continuing	Jackups	.3		.3		—
VALARIS 6002	January 2020	Continuing	Floaters	2.1		.9		1.2
VALARIS JU-96	December 2019	Continuing	Jackups	1.9		.3		1.6
VALARIS 5006	November 2019	Continuing	Floaters	7.0		6.0		1.0
VALARIS JU-42	October 2019	Continuing	Jackups	2.9		2.5		.4
Gorilla IV	May 2019	Continuing	Jackups	2.5		2.5		—
ENSCO 97	April 2019	Continuing	Jackups	1.7		1.0		.7
ENSCO 80	August 2018	Continuing	Jackups	1.0		.5		.5
ENSCO 5005	August 2018	Continuing	Floaters	4.0		2.0		2.0
ENSCO 6001	July 2018	Continuing	Floaters	2.0		.9		1.1
ENSCO 7500	April 2018	Discontinued	Floaters	2.6		1.5		1.1
ENSCO 81	April 2018	Continuing	Jackups	1.0		.3		.7
ENSCO 82	April 2018	Continuing	Jackups	1.0		.3		.7
				$	70.1	$	48.8	$	21.3

(1) Classification denotes the location of the operating results and gain (loss) on sale for each rig in our consolidated statements of operations. For rigs' operating results that were reclassified to discontinued operations in our consolidated statements of operations, these results were previously included within the specified operating segment.

(2) Includes the rig's net book value as well as materials and supplies and other assets on the date of the sale.

LIQUIDITY AND CAPITAL RESOURCES

Chapter 11 Cases and Effect of Automatic Stay

On August 19, 2020, the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court and subsequently obtained joint administration of the Chapter 11 Cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI). Any efforts to enforce payment obligations

related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.

On August 18, 2020, the Debtors entered into the Original RSA with the Consenting Noteholders. On February 5, 2021, the Debtors entered into the Amended RSA with the Consenting Noteholders and the Consenting Lenders. The Amended RSA contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA. The Amended RSA also provides for certain conditions to the obligations of the parties and for termination upon the occurrence of certain events, including without limitation, the failure to achieve certain milestones and certain breaches by the parties under the Amended RSA.

The Debtors continue to operate their businesses and manage their properties as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As part of the Chapter 11 Cases, the Debtors were granted “first-day” relief which enabled the Company to continue operating without interruption or disruption to its relationships with its customers and vendors or its high-quality service delivery. In particular, employee pay and benefits are expected to continue without interruption.

In addition, we have obtained a DIP Facility to fund operations during the bankruptcy proceedings. However, for the duration of the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 Cases. The outcome of the Chapter 11 Cases is dependent upon factors that are outside of our control, including actions of the Bankruptcy Court and our creditors. There can be no assurance that we will confirm and consummate a plan of reorganization as contemplated by the Amended RSA or complete another plan of reorganization with respect to the Chapter 11 Cases and as such, there is substantial doubt about our ability to continue as a going concern. Further, we have concluded that management’s plans do not alleviate the substantial doubt about our ability to continue as a going concern brought about by the significant risks and uncertainties related to our liquidity and Chapter 11 Cases for a period of one year after the date that the financial statements are issued.

Liquidity

Our liquidity position as of December 31, 2020, 2019 and 2018 is summarized below (in millions, except ratios):


	2020		2019		2018
Cash and cash equivalents	$	325.8	$	97.2	$	275.1
Short-term investments	—		—		329.0
Available DIP Facility capacity	500.0		—		—
Available credit facility borrowing capacity	—		1,622.2		2,000.0
Total liquidity	$	825.8	$	1,719.4	$	2,604.1
Working capital	$	746.1	$	233.7	$	781.2
Current ratio(1)	2.7		1.3		2.5

(1)As a result of our chapter 11 filing, we reclassified $7.3 billion representing the principal balance on our unsecured Senior Notes (as defined below), the amount of outstanding borrowings on our revolving credit facility, the accrued interest on our senior notes and revolving credit facility, and rig holding costs for DS-13 and DS-14 to “Liabilities Subject to Compromise” as of December 31, 2020. The current ratio calculated above does not reflect our debt and related interest that would otherwise be current but is stayed under our Chapter 11 Cases, nor does it include rig holding costs for VALARIS DS-13 and VALARIS DS-14.

Cash and Debt

As discussed in "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on Chapter 11 Cases and above, we have filed the Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness.

On September 25, 2020, we entered into the $500.0 million DIP Facility to provide liquidity during the pendency of the Chapter 11 Cases and expect exit financing in the form of a fully backstopped rights offering to noteholders for $550 million of New Secured Notes. We expect the DIP Facility will provide sufficient liquidity for us during the pendency of the Chapter 11 Cases. Additionally, we expect the exit financing to include the backstopped New Secured Notes and that these notes will provide the necessary liquidity to support ongoing operations and working capital needs.

The maturity date of the DIP Credit Agreement is the earliest of (1) August 17, 2021, (2) acceleration of the loans under the DIP Facility and termination of the lenders' commitments under the DIP Facility, (3) the substantial consummation of any plan filed in the Chapter 11 Cases that is confirmed pursuant to an order entered by the Bankruptcy Court and (4) the consummation of a sale of all or substantially all of the assets of the Company and the other Debtors under section 363 of the Bankruptcy Code. Loans under the DIP Credit Agreement accrue interest at a rate of 8.00% per annum, if paid in kind, and at a rate of 7.00% per annum, if paid in cash.

The DIP Credit Agreement contains a requirement that the Company and any other borrowers provide every four weeks, a rolling 13 week budget to be approved by the required lenders (the “Approved Budget”). The Company and any other borrower that becomes party to the DIP Credit Agreement may not vary from the Approved Budget by more than 15% of the forecasted amounts in any forecast period. The Approved Budget is, subject to certain exceptions and is tested at certain times in accordance with the DIP Credit Agreement in order to measure variances between the actual total cash disbursements (excluding professional fees and certain other items consistent with the initial Approved Budget) and the disbursements budgeted for the applicable period.

As of December 31, 2020, there were no borrowings outstanding under the DIP Credit Agreement. The DIP Credit Agreement does not provide for the issuance of letters of credit but permits occurrence of letters of credit in certain circumstances. Any proceeds of the loans under the DIP Credit Agreement may be used (1) to provide working capital to the borrowers and their subsidiaries and for other general corporate purposes in accordance with the rolling 13 week budget to be approved by the required lenders every four weeks (subject to the Permitted Variance), (2) to pay interest, fees, costs and expenses related to the DIP Facility, (3) to pay fees, costs and expenses of the estate professionals retained for the Chapter 11 Cases as approved by the Bankruptcy Court and as provided for in the Approved Budget (subject to the Permitted Variance), (4) make all permitted payments of costs of administration of the Chapter 11 Cases, (5) pay pre-petition expenses as are consistent with the Approved Budget (subject to the Permitted Variance) and approved by the Bankruptcy Court, (6) to fund the reasonable activities, costs and fees in respect of any insolvency proceedings in the United Kingdom and (7) make other payments permitted by the applicable Approved Budget.

The DIP Credit Agreement contains events of default customary to debtor-in-possession financings, including events related to the Chapter 11 Cases, the occurrence of which could result in the acceleration of the Debtors’ obligation to repay the outstanding indebtedness under the DIP Credit Agreement. The Debtors’ obligations under the DIP Credit Agreement are secured by a security interest in, and lien on, substantially all present and after acquired property (subject to certain exceptions) of the Debtors and are guaranteed by certain of the Company’s subsidiaries, including other Debtors.

The DIP Credit Agreement also contains customary covenants that limit the ability of the Company and its subsidiaries to, among other things, (1) incur additional indebtedness and permit liens to exist on their assets, (2) pay dividends or make certain other restricted payments, (3) sell assets and (4) make certain investments. These covenants are subject to exceptions and qualifications as set forth in the DIP Credit Agreement.

During the three-year period ended December 31, 2020, our primary sources of cash were $1.0 billion in proceeds from issuance of senior notes, Rowan cash acquired of $931.9 million, $581.0 million in net borrowings under our revolving credit facility and $440.0 million from short-term investments, net. While the revolving credit facility has not been terminated, no further borrowings are permitted. Our primary uses of cash for the same period were $1.7 billion for the repurchase and redemption of outstanding debt, $747.5 million for the construction, enhancement and other improvements of our drilling rigs and $584.3 million used in operating activities.

Cash Flows and Capital Expenditures

Our cash flows from operating activities of continuing operations and capital expenditures on continuing operations for each of the years in the three-year period ended December 31, 2020 were as follows (in millions):


	2020		2019		2018
Net cash used in operating activities of continuing operations	$	(251.7)	$	(276.9)	$	(55.7)




Capital expenditures	$	93.8	$	227.0	$	426.7

During 2020, cash flows used in operating activities decreased by $25.2 million as compared to the prior year due to lower interest costs, partially offset by declining margins.

During 2019, cash flows from continuing operations declined by $221.2 million as compared to the prior year due primarily to costs incurred related to the Rowan Transaction, interest on the debt assumed in the Rowan Transaction and declining margins.

Based on our current projections, we expect capital expenditures during 2021 to approximate $42.5 million for rig enhancement projects and minor upgrades and improvements. Depending on market conditions and opportunities, we may reduce our planned expenditures or make additional capital expenditures to upgrade rigs for customer requirements.

Financing and Capital Resources

Debt to Capital

Our total debt, total capital and total debt to total capital ratio as of December 31, 2019 were $6.5 billion, $15.8 billion and 41.2%, respectively. Our total debt, total capital and total debt to total capital ratio as of December 31, 2018 were $5.2 billion, $13.3 billion and 38.9%, respectively. Total debt consisted of the principal amount outstanding and total capital consisted of total debt and Valaris shareholders' equity.

During 2020, our total debt principal increased by $568.2 million primarily as a result of borrowings on our revolving credit facility and total capital declined by $4.4 billion primarily due to operating losses, inclusive of impairment of long-lived assets.

During 2019, our total debt principal increased by $1.4 billion and total capital increased by $2.6 billion as a result of the debt acquired and equity issued in connection with the Rowan Transactions. See "No te 4 - Rowan Transaction" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data".

During 2020, we paid $23.8 million of fees related to the establishment of the DIP Credit Agreement, with $20.0 million of these fees included in Reorganization items, net on the Consolidated Statement of Operations for the year ended December 31, 2020.

As of December 31, 2020, we were in compliance with our covenants under the DIP Credit Agreement.

The commencement of the Chapter 11 Cases resulted in an event of default under each series of our Senior Notes and all obligations thereunder were accelerated. However, any efforts to enforce payment obligations related to the acceleration of our debt have been automatically stayed as a result of the filing of the Chapter 11 Cases. Pursuant to the plan of reorganization contemplated by the Amended RSA, each series of our Senior Notes will be cancelled and the holders thereunder will receive the treatment as set forth in the plan of reorganization. Accordingly, the $6.5 billion in aggregate principal amount under the Senior Notes are Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020.

Senior Notes

As a result of the Rowan Transaction, we acquired the following senior notes issued by Rowan Companies, LLC (formerly Rowan Companies, Inc.) ("RCI") and guaranteed by Rowan: (1) $201.4 million in aggregate principal amount of 7.875% unsecured senior notes due 2019, which have been repaid in full, (2) $620.8 million in aggregate principal amount of 4.875% 2022 Notes (the "4.875% 2022 Notes"), (3) $398.1 million in aggregate principal amount of 4.75% 2024 Notes (the "4.75% 2024 Notes"), (4) $500.0 million in aggregate principal amount of 7.375% 2025 Notes (the "7.375% 2025 Notes"), (5) $400.0 million in aggregate principal amount of 2042 Notes (the "2042 Notes") and (6) $400.0 million in aggregate principal amount of 5.85% 2044 Notes (the "5.85% 2044 Notes"). On February 3, 2020, Rowan and RCI transferred substantially all their assets on a consolidated basis to Valaris plc, Valaris plc became the obligor on the notes and Rowan and RCI were relieved of their obligations under the notes and the related indenture.

On January 26, 2018, we issued $1.0 billion aggregate principal amount of unsecured 7.75% senior notes due 2026 (the "2026 Notes") at par, net of $16.5 million in debt issuance costs. Interest on the 2026 Notes is payable semiannually on February 1 and August 1 of each year.

During 2017, we exchanged $332.0 million aggregate principal amount of unsecured 8.00% senior notes due 2024 (the “8% 2024 Notes”) for certain amounts of our outstanding senior notes due 2019, 2020 and 2021. Interest on the 8% 2024 Notes is payable semiannually on January 31 and July 31 of each year.

During 2015, we issued $700.0 million aggregate principal amount of unsecured 5.20% senior notes due 2025 (the “2025 Notes”) at a discount of $2.6 million and $400.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the “New 2044 Notes”) at a discount of $18.7 million in a public offering. Interest on the 2025 Notes is payable semiannually on March 15 and September 15 of each year. Interest on the New 2044 Notes is payable semiannually on April 1 and October 1 of each year.

During 2014, we issued $625.0 million aggregate principal amount of unsecured 4.50% senior notes due 2024 (the "2024 Notes") at a discount of $0.9 million and $625.0 million aggregate principal amount of unsecured 5.75% senior notes due 2044 (the "Existing 2044 Notes") at a discount of $2.8 million. Interest on the 2024 Notes and the Existing 2044 Notes is payable semiannually on April 1 and October 1 of each year. The Existing 2044 Notes together with the New 2044 Notes, the "2044 Notes", are treated as a single series of debt securities under the indenture governing the notes.

During 2011, we issued $1.5 billion aggregate principal amount of unsecured 4.70% senior notes due 2021 (the “2021 Notes”) at a discount of $29.6 million in a public offering. Interest on the 2021 Notes is payable semiannually on March 15 and September 15 of each year.

Upon consummation of our acquisition of Pride International LLC ("Pride") during 2011, we assumed outstanding debt comprised of $900.0 million aggregate principal amount of unsecured 6.875% senior notes due 2020, $300.0 million aggregate principal amount of unsecured 7.875% senior notes due 2040 (collectively, the "Pride Notes"), and $500.0 million aggregate principal amount of unsecured 8.5% senior notes due 2019 (collectively, with the Pride Notes, the "Acquired Notes"). Valaris plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes.

Certain of these senior notes allow us to redeem these senior notes, either in whole in part, subject to the payment of certain “make whole” premiums. However, due to the commencement of the Chapter 11 Cases, we do not expect to make any such redemptions.

The indentures governing these senior notes contain customary events of default, including failure to pay principal or interest on such notes when due, among others. The indenture also contains certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.

Debentures Due 2027

During 1997, Ensco International Incorporated issued $150.0 million of unsecured 7.20% Debentures due 2027 (the "Debentures"). Interest on the Debentures is payable semiannually on May 15 and November 15 of each year. We may redeem the Debentures, in whole or in part, at any time prior to maturity, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium. During 2009, Valaris plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures.

indenture also contains certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.

2024 Convertible Notes

Interest on the 2024 Convertible Notes is payable semiannually on January 31 and July 31 of each year. The 2024 Convertible Notes will mature on January 31, 2024, unless exchanged, redeemed or repurchased in accordance with their terms prior to such date. Holders may exchange their 2024 Convertible Notes at their option any time prior to July 31, 2023 only under certain circumstances set forth in the indenture governing the 2024 Convertible Notes. On or after July 31, 2023, holders may exchange their 2024 Convertible Notes at any time. The exchange rate is 17.8336 shares per $1,000 principal amount of notes, representing an exchange price of $56.08 per share, and is subject to adjustment upon certain events. The 2024 Convertible Notes may not be redeemed by us except in the event of certain tax law changes.

The indenture governing the 2024 Convertible Notes contains customary events of default, including failure to pay principal or interest on such notes when due, among others. The indenture also contains certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions. See "Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes.

The 2021 Notes, 4.875% 2022 Notes, 4.75% 2024 Notes, 8% 2024 Notes, 2024 Notes, 2025 Notes, 7.375% 2025 Notes, 2026 Notes, 2042 Notes, 5.85% 2044 Notes, Existing 2044 Notes, the Pride Notes, the Debentures and 2024 Convertible Notes" together are the "Senior Notes". The commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under our Senior Notes. See "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information related to our Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness.

Tender Offers and Open Market Repurchases

In early March 2020, we repurchased $12.8 million of our outstanding 4.70% senior notes due 2021 on the open market for an aggregate purchase price of $9.7 million, excluding accrued interest, with cash on hand. As a result of the transaction, we recognized a pre-tax gain of $3.1 million net of discounts in other, net, in the consolidated statements of operations.

On June 25, 2019, we commenced cash tender offers for certain series of senior notes issued by us and Ensco International Incorporated and RCI, our wholly-owned subsidiaries. The tender offers expired on July 23, 2019, and we repurchased $951.8 million of our outstanding senior notes for an aggregate purchase price of $724.1 million. As a result of the transaction, we recognized a pre-tax gain from debt extinguishment of $194.1 million, net of discounts, premiums and debt issuance costs.

Concurrent with the issuance of the 2026 Notes in January 2018, we launched cash tender offers for up to $985.0 million aggregate principal amount of certain series of senior notes issued by us and Pride, our wholly-owned subsidiary, and as a result we repurchased $595.4 million of our senior notes. Subsequently, we issued a redemption notice for the remaining principal amount of the $55.0 million principal amount of the 8.50% senior notes due 2019 and repurchased $71.4 million principal amount of our senior notes due 2020. As a result of these transactions, we recognized a pre-tax loss from debt extinguishment of $19.0 million, net of discounts, premiums, debt issuance costs and commissions.

Our tender offers and open market repurchases during the three-year period ended December 31, 2020 are summarized in the following table (in millions):


	Aggregate Principal Amount Repurchased		Aggregate Repurchase Price(1)
Year Ended December 31, 2020
4.70% Senior notes due 2021	$	12.8	$	9.7

Year Ended December 31, 2019
4.50% Senior notes due 2024	$	320.0	$	240.0
4.75% Senior notes due 2024	79.5		61.2
8.00% Senior notes due 2024	39.7		33.8
5.20% Senior notes due 2025	335.5		250.0
7.375% Senior notes due 2025	139.2		109.2
7.20% Senior notes due 2027	37.9		29.9
	$	951.8	$	724.1
Year Ended December 31, 2018
8.50% Senior notes due 2019	$	237.6	$	256.8
6.875% Senior notes due 2020	328.0		354.7
4.70% Senior notes due 2021	156.2		159.7
	$	721.8	$	771.2

(1) Excludes accrued interest paid to holders of the repurchased senior notes.

Revolving Credit Facility and DIP Facility

Effective upon closing of the Rowan Transaction, our revolving credit facility was $1.6 billion.

As previously disclosed, prior to the commencement of the Chapter 11 Cases, we entered into a series of waiver agreements (the “Waivers”) between the dates of June 1, 2020 and August 3, 2020 in respect of the revolving credit facility.

The Waivers did not address any event of default resulting under the revolving credit facility attributed to the filing of Chapter 11 Cases. Consequently, the principal and interest under our revolving credit facility became immediately due and payable upon filing of such Chapter 11 Cases, which constituted an event of default under the revolving credit facility. However, the ability of the lenders under the revolving credit facility to exercise remedies in respect of the revolving credit facility was stayed upon commencement of the Chapter 11 Cases. While the revolving credit facility has not been terminated, notwithstanding the $1.6 billion borrowing capacity under the revolving credit facility, no further borrowings under the revolving credit facility are permitted.

As of December 31, 2020, we had $581.0 million of borrowings outstanding under our revolving credit facility and $27.0 million of undrawn letters of credit. The outstanding borrowings as well as accrued interest as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. See "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information related to our Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness.

We expect cash on hand and the DIP Facility will provide sufficient liquidity for us during the pendency of the Chapter 11 Cases based on current projections of cash flows. Should we experience material variations from our projected cash flows, this could result in us having insufficient liquidity from the DIP Facility and in turn could have a material adverse impact on our financial position, operating results or cash flows.

Maturities

The original principal amounts issued under our senior notes have subsequently changed as a result of our tenders, repurchases, exchanges, redemptions and new debt issuances such that the balance outstanding at December 31, 2020 were as follows (in millions):


													Subject to Compromise(2)
Senior Notes(2)	Original Principal		2016 Tenders, Repurchases and Equity Exchange		2017 Exchange Offers and Repurchases		2018 Tender Offers, Redemption and Debt Issuance		2019 Tender Offers and Acquired Debt		2020 Open Market Repurchase		Remaining Principal
6.875% Senior notes due 2020	$	900.0	$	(219.2)	$	(229.9)	$	(328.0)	$	—	$	—	$	122.9
4.70% Senior notes due 2021	1,500.0		(817.0)		(413.3)		(156.2)		—		(12.8)		100.7
4.875% Senior notes due 2022 (1)	—		—		—		—		620.8		—		620.8
3.00% Exchangeable senior notes due 2024	849.5		—		—		—		—		—		849.5
4.50% Senior notes due 2024	625.0		(1.6)		—		—		(320.0)		—		303.4
4.75% Senior notes due 2024 (1)	—		—		—		—		318.6		—		318.6
8.00% Senior notes due 2024	—		—		332.0		—		(39.7)		—		292.3
5.20% Senior notes due 2025	700.0		(30.8)		—		—		(335.5)		—		333.7
7.375% Senior notes due 2025 (1)	—		—		—		—		360.8		—		360.8
7.75% Senior notes due 2026	—		—		—		1,000.0		—		—		1,000.0
7.20% Debentures due 2027	150.0		—		—		—		(37.9)		—		112.1
7.875% Senior notes due 2040	300.0		—		—		—				—		300.0
5.40% Senior notes due 2042 (1)	—		—		—		—		400.0		—		400.0
5.75% Senior notes due 2044	1,025.0		(24.5)		—		—		—		—		1,000.5
5.85% Senior notes due 2044 (1)	—		—		—		—		400.0		—		400.0
Total	$	6,049.5	$	(1,093.1)	$	(311.2)	$	515.8	$	1,367.1	$	(12.8)	$	6,515.3

(1)These senior notes were acquired in the Rowan Transaction.

(2)The $6.5 billion aggregate principal amount of Senior Notes outstanding as well as associated $201.9 million in accrued interest as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. The maturity dates represent the maturity dates per the debt agreements; however, we are in default on these senior notes and are currently in chapter 11 proceedings. See "Senior Notes" above and “Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” included in "Item 8. Financial Statements and Supplementary Data" for additional information for additional details regarding Chapter 11 Cases.

Other Financing Arrangements

During 2018, our shareholders approved our current share repurchase program. Subject to certain provisions under English law, including the requirement of the Company to have sufficient distributable reserves and the Board to conclude that a repurchase is in the best interests of Valaris plc taking into account the interests of relevant stakeholders, we may repurchase shares up to a maximum of $500 million in the aggregate from one or more financial intermediaries under the program, but in no case more than 16.3 million shares. The program terminates in May 2023. As of December 31, 2020, there had been no share repurchases under this program. Our DIP Credit Agreement only permits the repurchase of our shares in certain limited circumstances and the repurchase of shares would likely require approval of the bankruptcy court. We do not currently expect to make repurchases under the program whilst Valaris plc remains subject to Chapter 11 bankruptcy proceedings.

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, earn interest at LIBOR plus two percent and mature during 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 notes receivable may be reduced by future Company obligations to the joint venture.

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 5 - Equity Method Investment in ARO" included in "Item 8. Financial Statements and Supplementary Data" 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 December 31, 2020 (in millions):


Maturity Date	Principal amount
October 2027	$	265.0
October 2028	177.7
Total	$	442.7

Contractual Obligations

We have various contractual commitments related to our rig construction agreements, long-term debt and operating leases. In light of our ongoing Chapter 11 Cases, our expectations with regards to settling these obligations may change. Generally, we expect to fund our commitments from existing cash and funds borrowed under our DIP Facility or other future financing arrangements unless otherwise stipulated in the Amended RSA. The following table summarizes our significant contractual obligations as of December 31, 2020 and the periods in which such obligations are due (in millions):


	Payments due by period
	2021		2022 and 2023		2024 and 2025		Thereafter		Total
Principal payments on long-term debt(1)	$	—	$	—	$	—	$	—	$	—

New rig construction agreements(2)(3)	83.9		165.0		—		—		248.9
Operating leases	17.8		15.0		4.2		9.0		46.0
Total contractual obligations(4)	$	101.7	$	180.0	$	4.2	$	9.0	$	294.9

(1)As a result of our chapter 11 filing, we reclassified $7.1 billion representing the principal balance on our unsecured senior notes and the amount of outstanding borrowings on our revolving credit facility to Liabilities Subject to Compromise on our Consolidated Balance Sheet as of December 31, 2020.

(2)As of December 31, 2020, the contractual delivery dates for the VALARIS DS-13 and VALARIS DS-14 were September 30, 2021 and June 30, 2022, respectively. The remaining milestone payments for VALARIS DS-13 and VALARIS DS-14 are included in the table above in the period in which they were contractually owed.

The Amended RSA provides that on or before the effective date of the reorganization, the construction contracts for these rigs shall be rejected under Section 365 of the Bankruptcy Code, unless otherwise agreed between the shipyard and the Company with the consent of required consenting noteholders. If rejected, it is contemplated that we would have to pay an amount equal to the liquidation recovery, which is the amount the contract counterparty would be entitled to receive or retain if the applicable Company entity was liquidated under chapter 7 of the Bankruptcy Code. Prior to December 31, 2020, a Stipulation was filed with the Bankruptcy Court which included an Assumption Term Sheet stating amended terms of these construction agreements.

(3)Total commitments are based on fixed-price shipyard construction contracts, exclusive of our internal costs associated with project management, commissioning and systems integration testing. Total commitments also exclude holding costs and interest.

(4)Contractual obligations do not include $286.1 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as of December 31, 2020. We are unable to specify with certainty the future periods in which we may be obligated to settle such amounts. In addition, we have a potential obligation to fund ARO for newbuild jackup rigs. 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. The Company's capital contributions to ARO pursuant to this requirement may require approval of the Bankruptcy Court during the Chapter 11 Cases. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis. "See Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." for additional information on our joint venture with ARO.

Other Commitments

We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. These commitments include 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. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2020, we had insignificant collateral deposits with respect to these agreements. The following table summarizes our other commitments as of December 31, 2020 (in millions):


	Commitment expiration by period
	2021		2022 and 2023		2024 and 2025		Thereafter		Total
Letters of credit	$	88.5	$	15.9	$	7.2	$	3.5	$	115.1

Recent Tax Assessments

During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $77.7 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 a $17.9 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2020. 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. See "Note 13 - Income Taxes" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on recent tax assessments.

Effects of Climate Change and Climate Change Regulation

Greenhouse gas (“GHG”) emissions have increasingly become the subject of international, national, regional, state and local attention. At the December 2015 Conference of the Parties to the United Nations Framework Convention on Climate Change held in Paris, an agreement was reached that requires countries to review and “represent a progression” in their intended nationally determined contributions to the reduction of GHG emissions, setting GHG emission reduction goals every five years beginning in 2020. This agreement, known as the Paris Agreement, entered into force on November 4, 2016 and, as of February 2019, had been ratified by 187 of the 197 parties to the United Nations Framework Convention on Climate Change, including the United Kingdom, the United States and the majority of the other countries in which we operate. The United Nations Climate Change Conference held in Katowice, Poland in December 2018 adopted further rules regarding the implementation of the Paris Agreement and, in connection with this conference, numerous countries issued commitments to increase their GHG emission reduction targets. Although the United States had withdrawn from the Paris Agreement in November 2020, the current Presidential Administration officially reentered the United States into the agreement in February 2021. It is expected that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, restricting, or delaying oil and gas development activities in certain areas, will be proposed and/or promulgated. For example, the acting Secretary of the Department of the Interior recently issued

an order preventing staff from producing any new federal fossil fuel leases or permits without sign-off from a top political appointee. In addition, the current Presidential Administration has issued multiple executive orders pertaining to environmental regulations and climate change, including the (1) Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad. The latter executive order announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of Federal oil and gas permitting and leasing practices, established climate change as a primary foreign policy and national security consideration and affirmed that achieving net-zero greenhouse gas emissions by or before mid-century is a critical priority.

In an effort to reduce GHG emissions, governments have implemented or considered legislative and regulatory mechanisms to institute carbon pricing mechanisms, such as the European Union’s Emission Trading System, and to impose technical requirements to reduce carbon emissions. The Companies Act 2006 (Strategic and Directors' Reports) Regulations 2013 now requires all quoted U.K. companies, including Valaris plc, to report their annual GHG emissions in the Company's directors' report.

During 2009, the United States Environmental Protection Agency (the “EPA”) officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allowed the agency to proceed with the adoption and implementation of regulations to restrict GHG emissions under existing provisions of the Clean Air Act that establish permitting requirements, including emissions control technology requirements, for certain large stationary sources that are potential major sources of GHG emissions. These requirements for stationary sources took effect on January 2, 2011; however, in June 2014 the U.S. Supreme Court reversed a D.C. Circuit Court of Appeals decision upholding these rules and struck down the EPA’s greenhouse gas permitting rules to the extent they impose a requirement to obtain a federal air permit based solely on emissions of greenhouse gases. Large sources of other air pollutants, such as VOC or nitrogen oxides, could still be required to implement process or technology controls and obtain permits regarding emissions of greenhouse gases. The EPA has also adopted rules requiring annual monitoring and reporting of GHG emissions from specified sources in the U.S., including, among others, certain onshore and offshore oil and natural gas production facilities. Although a number of bills related to climate change have been introduced in the U.S. Congress in the past, comprehensive federal climate legislation has not yet been passed by Congress. If such legislation were to be adopted in the U.S., such legislation could adversely impact many industries. In the absence of federal legislation, almost half of the states have begun to address GHG emissions, primarily through the development or planned development of emission inventories or regional GHG cap and trade programs and commitments to contribute to meeting the goals of the Paris Agreement.

Future regulation of GHG emissions could occur pursuant to future treaty obligations, statutory or regulatory changes or new climate change legislation in the jurisdictions in which we operate. Depending on the particular program, we, or our customers, could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. It is uncertain whether any of these initiatives will be implemented. If such initiatives are implemented, we do not believe that such initiatives would have a direct, material adverse effect on our financial condition, operating results and cash flows in a manner different than our competitors.

Restrictions on GHG emissions or other related legislative or regulatory enactments could have an indirect effect in those industries that use significant amounts of petroleum products, which could potentially result in a reduction in demand for petroleum products and, consequently, our offshore contract drilling services. We are currently unable to predict the manner or extent of any such effect. Furthermore, one of the long-term physical effects of climate change may be an increase in the severity and frequency of adverse weather conditions, such as hurricanes, which may increase our insurance costs or risk retention, limit insurance availability or reduce the areas in which, or the number of days during which, our customers would contract for our drilling rigs in general and in the Gulf of Mexico in particular. We are currently unable to predict the manner or extent of any such effect.

In addition, in recent years the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, has promoted divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental initiatives aimed at limiting climate change and reducing air pollution could ultimately interfere with our business activities and operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their greenhouse gas emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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 consolidated financial statements and accompanying notes. Our significant accounting policies are included in "Note 1 - Description of Business and Summary of Significant Accounting Policies to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data". These policies, along with our underlying judgments and assumptions made in their application, have a significant impact on our 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 long-lived assets, income taxes and pensions.

Property and Equipment

As of December 31, 2020, the carrying value of our property and equipment totaled $11.0 billion, which represented 85% of total assets. This carrying value reflects the application of our property and equipment accounting policies, which incorporate our estimates, judgments and assumptions relative to the capitalized costs, useful lives and salvage values of our rigs.

We develop and apply property and equipment accounting policies that are designed to appropriately and consistently capitalize those costs incurred to enhance, improve and extend the useful lives of our assets and expense those costs incurred to repair or maintain the existing condition or useful lives of our assets. The development and application of such policies requires estimates, judgments and assumptions relative to the nature of, and benefits from, expenditures on our assets. We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives. The judgments and assumptions used in determining the useful lives of our property and equipment reflect both historical experience and expectations regarding future operations, utilization and performance of our assets. The use of different estimates, judgments and assumptions in the establishment of our property and equipment accounting policies, especially those involving the useful lives of our rigs, would likely result in materially different asset carrying values and operating results.

The useful lives of our drilling rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry. We evaluate the remaining useful lives of our rigs on a periodic basis, considering operating condition, functional capability and market and economic factors.

Property and equipment held-for-sale is recorded at the lower of net book value or fair value less cost to sell.

During 2020, we recorded an aggregate pre-tax, non-cash impairment of $3.6 billion with respect to certain floaters, jackups and spare equipment. We estimate the portion of the aforementioned impairment related to

impaired rigs that remain in our fleet as of December 31, 2020 will cause a decline in depreciation expense of approximately $35.4 million for the year ended December 31, 2021.

Our fleet of 16 floater rigs, excluding two rigs under construction, represented 54% of the gross cost and 55% of the net carrying amount of our depreciable property and equipment as of December 31, 2020. Our fleet of 36 jackup rigs, represented 37% of the gross cost and 36% of the net carrying amount of our depreciable property and equipment as of December 31, 2020. Our floater rigs and jackup rigs are depreciated over 35 and 30 years, respectively, for newly constructed assets and over their estimated remaining useful lives for rigs obtained in a business combination.

The following table provides an analysis of estimated increases and decreases in depreciation expense from continuing operations that would have been recognized for the year ended December 31, 2020 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2020:


Increase (decrease) in useful lives of our drilling rigs						Estimated (decrease) increase in depreciation expense that would have been recognized (in millions)
10%						$(41.5)
20%						(76.1)
(10%)						50.4
(20%)						101.5

Impairment of Property and Equipment

We recorded pre-tax, non-cash losses on impairment of long-lived assets of $3.6 billion, $98.4 million and $40.3 million during 2020, 2019 and 2018, respectively. See "Note 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our impairments of property and equipment.

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, on a quarterly basis to identify events or changes in circumstances ("triggering events") that indicate that the carrying value of such rigs may not be recoverable. Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.

For property and equipment used in our operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the carrying value of the asset and its estimated fair value. The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including utilization levels, day rates, expense levels and capital requirements, as well as cash flows generated upon disposition, for each of our drilling rigs. Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our recoverability test.

Our judgments and assumptions about future cash flows to be generated by our drilling rigs are highly subjective and based on consideration of the following:

•global macroeconomic and political environment,

•historical utilization, day rate and operating expense trends by asset class,

•regulatory requirements such as surveys, inspections and recertification of our rigs,

•remaining useful lives of our rigs,

•expectations on the use and eventual disposition of our rigs,

•weighted-average cost of capital,

•oil price projections,

•sanctioned and unsanctioned offshore project data,

•offshore economic project break-even data,

•global rig supply and construction orders,

•global rig fleet capabilities and relative rankings, and

•expectations of global rig fleet attrition.

We collect and analyze the above information to develop a range of estimated utilization levels, day rates, expense levels and capital requirements, as well as estimated cash flows generated upon disposition. The drivers of these assumptions that impact our impairment analyses include projections of future oil prices and timing of global rig fleet attrition, which, in large part, impact our estimates on timing and magnitude of recovery from the current industry downturn. However, there are numerous judgments and assumptions unique to the projected future cash flows of each rig that individually, and in the aggregate, can significantly impact the recoverability of its carrying value.

The highly cyclical nature of our industry cannot be reasonably predicted with a high level of accuracy and, therefore, differences between our historical judgments and assumptions and actual results will occur. We reassess our judgments and assumptions in the period in which significant differences are observed and may conclude that a triggering event has occurred and perform a recoverability test. We recognized impairment charges in recent periods upon observation of significant unexpected changes in our business climate and estimated useful lives of certain assets.

There are numerous factors underlying the highly cyclical nature of our industry that are reasonably likely to impact our judgments and assumptions including, but not limited to, the following:

•changes in global economic conditions and demand,

•production levels of the Organization of Petroleum Exporting Countries (“OPEC”),

•production levels of non-OPEC countries,

•advances in exploration and development technology,

•offshore and onshore project break-even economics,

•development and exploitation of alternative fuels,

•natural disasters or other operational hazards,

•changes in relevant law and governmental regulations,

•political instability and/or escalation of military actions in the areas we operate,

•changes in the timing and rate of global newbuild rig construction, and

•changes in the timing and rate of global rig fleet attrition.

There is a wide range of interrelated changes in our judgments and assumptions that could reasonably occur as a result of unexpected developments in the aforementioned factors, which could result in materially different carrying values for an individual rig, group of rigs or our entire rig fleet, materially impacting our operating results.

Income Taxes

We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions. As of December 31, 2020, our consolidated balance sheet included an $8.2 million net deferred income tax asset, a $33.9 million liability for income taxes currently payable and a $286.1 million liability for unrecognized tax benefits, inclusive of interest and penalties.

The carrying values of deferred income tax assets and liabilities reflect the application of our income tax accounting policies and are based on estimates, judgments and assumptions regarding future operating results and levels of taxable income. Carryforwards and tax credits are assessed for realization as a reduction of future taxable income by using a more-likely-than-not determination. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.

We do not provide deferred taxes on the undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we may be subject to additional income taxes.

The carrying values of liabilities for income taxes currently payable and unrecognized tax benefits are based on our interpretation of applicable tax laws and incorporate estimates, judgments and assumptions regarding the use of tax planning strategies in various taxing jurisdictions. The use of different estimates, judgments and assumptions in connection with accounting for income taxes, especially those involving the deployment of tax planning strategies, may result in materially different carrying values of income tax assets and liabilities and operating results.

We operate in several jurisdictions where tax laws relating to the offshore drilling industry are not well developed. In jurisdictions where available statutory law and regulations are incomplete or underdeveloped, we obtain professional guidance and consider existing industry practices before utilizing tax planning strategies and meeting our tax obligations.

Tax returns are routinely subject to audit in most jurisdictions and tax liabilities occasionally are finalized through a negotiation process. In some jurisdictions, income tax payments may be required before a final income tax obligation is determined in order to avoid significant penalties and/or interest. While we historically have not experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:

•During recent years, the number of tax jurisdictions in which we conduct operations has increased.

•In order to utilize tax planning strategies and conduct operations efficiently, our subsidiaries frequently enter into transactions with affiliates that are generally subject to complex tax regulations and are frequently reviewed and challenged by tax authorities.

•We may conduct future operations in certain tax jurisdictions where tax laws are not well developed, and it may be difficult to secure adequate professional guidance.

•Tax laws, regulations, agreements, treaties and the administrative practices and precedents of tax authorities change frequently, requiring us to modify existing tax strategies to conform to such changes.

Pension and Other Postretirement Benefits

Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, annual compensation increases, mortality rates and other factors. Key assumptions at December 31, 2020, included (1) a weighted average discount rate of 2.30% to determine pension benefit obligations, (2) a weighted average discount rate of 3.16% to determine net periodic pension cost and (3), an expected long-term rate of return on pension plan assets of 6.48% to determine net periodic pension cost. The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds, and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $125.6 million, while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease) annual net benefits cost by approximately $5.6 million. To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which decreased to 6.03% at December 31, 2020 from 6.48% at December 31, 2019. See "Note 12 - Pension and Other Post Retirement Benefits" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on our pension and other postretirement benefit plans.

NEW ACCOUNTING PRONOUNCEMENTS

See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on new accounting pronouncements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) or 15d-15(f). Our internal control over financial reporting system is designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, we have concluded that our internal control over financial reporting is effective as of December 31, 2020 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

KPMG LLP, the independent registered public accounting firm who audited our consolidated financial statements, has issued an audit report on our internal control over financial reporting. KPMG LLP's audit report on our internal control over financial reporting is included herein.

March 2, 2021

101

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Valaris plc:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Valaris plc and subsidiaries (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive loss, and cash flows for each of the years in the three‑year period ended December 31, 2020 and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 2, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Going Concern

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company's operations and its ability to develop and execute its business plan are subject to a high degree of risk and uncertainty associated with the Chapter 11 voluntary petition, that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

102

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Impairment of property and equipment

As discussed in Notes 1 and 7 to the consolidated financial statements, the Company recorded impairment with respect to certain floaters, jackups and spare equipment of $3.6 billion for the year ended December 31, 2020. On a quarterly basis, the Company evaluates the carrying value of property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such rigs may not be recoverable. For property and equipment used in operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the carrying value of the asset and its estimated fair value. To estimate the fair value of property and equipment, the Company utilized an income approach or estimated scrap value.

We identified the evaluation of the impairment assessment for certain floaters and jackups as a critical audit matter. A high degree of subjective auditor judgment was required to evaluate certain inputs and assumptions used in the Company's recoverability assessment and determination of fair value using the income approach, specifically assumptions regarding future day rates, forecasted utilization and the discount rate. The assumptions related to future day rates and forecasted utilization were based on unobservable and subjective inputs for which there is limited information. Evaluation of the discount rate involved specialized skills and knowledge.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company's property and equipment impairment assessment process. This included controls over the determination of certain inputs and assumptions used in the recoverability assessment and the fair value estimates of floaters and jackups, including future day rates, forecasted utilization, and the discount rate. We evaluated the Company's estimated future day rates and forecasted utilization by comparing them to historical information, considering contract modifications and industry reports on floaters and jackups. We involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the Company's discount rate by comparing the Company's discount rate against discount rate ranges that we independently developed using publicly-available market data for comparable entities.

Income tax positions pertaining to certain tax transactions

As discussed in Notes 1 and 13 to the consolidated financial statements, the Company evaluates the income tax effect of certain transactions which often requires local country tax expertise and judgment. This requires the Company to interpret complex tax laws in multiple jurisdictions to assess whether its tax positions have a more than 50 percent likelihood of being sustained with the taxing authorities.

We identified the assessment of income tax positions pertaining to certain tax transactions as a critical audit matter. Complex auditor judgment was required to evaluate the Company's assessment that certain tax positions have a more than 50 percent likelihood of being sustained with the taxing authorities. In addition, specialized skills and knowledge were required to evaluate the Company's interpretation of tax laws in the applicable jurisdictions.

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process. This included controls related to the interpretation of tax laws applicable to certain transactions and the assessment that tax positions pertaining to those transactions have a more than 50 percent likelihood of being sustained with taxing authorities. We involved tax professionals with specialized skills and knowledge, who assisted in evaluating the Company's interpretation of local tax laws and assessment of whether certain tax positions had a greater than 50 percent likelihood of being sustained with taxing authorities.

/s/ KPMG LLP

We have served as the Company’s auditor since 2002.

Houston, Texas

March 2, 2021

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Valaris plc:

Opinion on Internal Control Over Financial Reporting

We have audited Valaris plc and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2020 and 2019, the related consolidated statements of operations, comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2020, and the related notes (collectively, the consolidated financial statements), and our report dated March 2, 2021 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may

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become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Houston, Texas

March 2, 2021

106

VALARIS PLC AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)


	Year Ended December 31,
	2020		2019		2018
OPERATING REVENUES	$	1,427.2	$	2,053.2	$	1,705.4
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	1,458.6		1,806.0		1,319.4
Loss on impairment	3,646.2		104.0		40.3
Depreciation	540.8		609.7		478.9
General and administrative	214.6		188.9		102.7
Total operating expenses	5,860.2		2,708.6		1,941.3
Other Operating Income	118.1		—		—
EQUITY IN LOSSES OF ARO	(7.8)		(12.6)		—
OPERATING LOSS	(4,322.7)		(668.0)		(235.9)
OTHER INCOME (EXPENSE)
Interest income	19.7		28.1		14.5
Interest expense, net (Unrecognized contractual interest expense for debt subject to compromise was $140.7 million for the year ended December 31, 2020)	(290.6)		(428.3)		(282.7)
Reorganization items, net	(527.6)		—		—
Other, net	4.2		1,004.4		(34.8)
	(794.3)		604.2		(303.0)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(5,117.0)		(63.8)		(538.9)
PROVISION (BENEFIT) FOR INCOME TAXES
Current income tax expense (benefit)	(153.7)		104.5		33.0
Deferred income tax expense (benefit)	(105.7)		23.9		56.6
	(259.4)		128.4		89.6
LOSS FROM CONTINUING OPERATIONS	(4,857.6)		(192.2)		(628.5)
LOSS FROM DISCONTINUED OPERATIONS, NET	—		—		(8.1)
NET LOSS	(4,857.6)		(192.2)		(636.6)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	2.1		(5.8)		(3.1)
NET LOSS ATTRIBUTABLE TO VALARIS	$	(4,855.5)	$	(198.0)	$	(639.7)
LOSS PER SHARE - BASIC AND DILUTED
Continuing operations	$	(24.42)	$	(1.14)	$	(5.82)
Discontinued operations	—		—		(0.08)
	$	(24.42)	$	(1.14)	$	(5.90)

WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic and Diluted	198.9		173.4		108.5

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

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VALARIS PLC AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in millions)


	Year Ended December 31,
	2020		2019		2018
NET LOSS	$	(4,857.6)	$	(192.2)	$	(636.6)
OTHER COMPREHENSIVE LOSS, NET
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive loss, net of income tax benefit of $5.9 million for the year ended December 31, 2019	(76.3)		(21.7)		—
Net change in fair value of derivatives	(5.4)		1.6		(9.7)
Amortization of settlement gain, net of income tax expense of $(0.1) million for the year ended December 31, 2020	(.2)		—		—
Reclassification of net (gains) losses on derivative instruments from other comprehensive loss into net loss	(11.6)		8.3		(1.0)
Other	(.6)		(.2)		(.5)
NET OTHER COMPREHENSIVE LOSS	(94.1)		(12.0)		(11.2)

COMPREHENSIVE LOSS	(4,951.7)		(204.2)		(647.8)
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	2.1		(5.8)		(3.1)
COMPREHENSIVE LOSS ATTRIBUTABLE TO VALARIS	$	(4,949.6)	$	(210.0)	$	(650.9)

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

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VALARIS PLC AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED BALANCE SHEETS

(in millions, except share and par value amounts)


	December 31,
ASSETS	2020		2019
CURRENT ASSETS
Cash and cash equivalents	$	325.8	$	97.2

Accounts receivable, net	449.2		520.7
Other	397.9		446.5
Total current assets	1,172.9		1,064.4
PROPERTY AND EQUIPMENT, AT COST	13,209.3		18,393.8
Less accumulated depreciation	2,248.8		3,296.9
Property and equipment, net	10,960.5		15,096.9
LONG-TERM NOTES RECEIVABLE FROM ARO	442.7		452.9
INVESTMENT IN ARO	120.9		128.7
OTHER ASSETS	176.2		188.3
	$	12,873.2	$	16,931.2
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$	176.4	$	288.2
Accrued liabilities and other	250.4		417.7
Current maturities of long-term debt	—		124.8
Total current liabilities	426.8		830.7
LONG-TERM DEBT	—		5,923.5
OTHER LIABILITIES	762.4		867.4
Total liabilities not subject to compromise	1,189.2		7,621.6
LIABILITIES SUBJECT TO COMPROMISE	7,313.7		—
COMMITMENTS AND CONTINGENCIES
VALARIS SHAREHOLDERS' EQUITY
Class A ordinary shares, U.S. $0.40 par value, 206.1 and 205.9 million shares issued as of December 31, 2020 and 2019	82.5		82.4
Class B ordinary shares, £1 par value, 50,000 shares issued as of December 31, 2020 and 2019	.1		.1
Additional paid-in capital	8,639.9		8,627.8
Retained (deficit) earnings	(4,183.8)		671.7
Accumulated other comprehensive (loss) income	(87.9)		6.2
Treasury shares, at cost, 6.6 million and 7.9 million shares as of December 31, 2020 and 2019	(76.2)		(77.3)
Total Valaris shareholders' equity	4,374.6		9,310.9
NONCONTROLLING INTERESTS	(4.3)		(1.3)
Total equity	4,370.3		9,309.6
	$	12,873.2	$	16,931.2

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

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VALARIS PLC AND SUBSIDIARIES (DEBTOR-IN-POSSESSION)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	Year Ended December 31,
	2020		2019		2018
OPERATING ACTIVITIES
Net loss	$	(4,857.6)	$	(192.2)	$	(636.6)
Adjustments to reconcile net loss to net cash used in operating activities of continuing operations:
Loss on impairment	3,646.2		104.0		40.3
Depreciation expense	540.8		609.7		478.9
Non-cash reorganization items, net	436.4		—		—
Deferred income tax expense (benefit)	(105.7)		23.9		56.6
Debtor in Possession financing fees and payments on Backstop Agreement	40.0		—		—
Debt discounts and other	36.8		31.5		(7.2)
Share-based compensation expense	21.4		37.3		29.9
Equity in losses of ARO	7.8		12.6		—
(Gain on) adjustment to bargain purchase	6.3		(637.0)		(1.8)
Amortization, net	6.2		(16.8)		(40.2)
(Gain) loss on debt extinguishment	(3.1)		(194.1)		19.0
Other	6.9		9.9		26.2
Changes in operating assets and liabilities, net of acquisition	(22.0)		(52.5)		(20.8)
Contributions to pension plans and other post-retirement benefits	(12.1)		(13.2)		—
Net cash used in operating activities	(251.7)		(276.9)		(55.7)
INVESTING ACTIVITIES
Additions to property and equipment	(93.8)		(227.0)		(426.7)
Net proceeds from disposition of assets	51.8		17.7		11.0
Acquisition of Rowan, net of cash acquired	—		931.9		—
Maturities of short-term investments	—		474.0		1,030.0
Purchases of short-term investments	—		(145.0)		(919.0)
Net cash provided by (used in) investing activities	(42.0)		1,051.6		(304.7)
FINANCING ACTIVITIES
Borrowings on credit facility	596.0		215.0		—
Debtor in Possession financing fees and payments on Backstop Agreement	(40.0)		—		—
Repayments of credit facility borrowings	(15.0)		(215.0)		—
Reduction of long-term borrowings	(9.7)		(928.1)		(771.2)
Purchase of noncontrolling interests	(7.2)		—		—
Debt solicitation fees	—		(9.5)		—
Cash dividends paid	—		(4.5)		(17.9)
Proceeds from issuance of senior notes	—		—		1,000.0
Debt issuance costs	—		—		(17.0)
Other	(1.9)		(10.2)		(5.7)
Net cash provided by (used in) financing activities	522.2		(952.3)		188.2
Net cash provided by discontinued operations	—		—		2.5
Effect of exchange rate changes on cash and cash equivalents	.1		(.3)		(.6)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	228.6		(177.9)		(170.3)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	97.2		275.1		445.4
CASH AND CASH EQUIVALENTS, END OF YEAR	$	325.8	$	97.2	$	275.1

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

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VALARIS PLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 61 rigs, with drilling operations in almost every major offshore market across five continents. Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig and 45 jackup rigs and a 50% equity interest in Saudi Aramco Rowan Offshore Drilling Company ("ARO"), our 50/50 joint venture with Saudi Aramco, which owns an additional seven rigs, We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.

Our customers include many of the leading national and international oil companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies, with current operations spanning nine countries on five continents. The markets in which we operate include the Gulf of Mexico, North Sea, the Middle East, West Africa, Australia and Southeast Asia.

Chapter 11 Cases and Restructuring Support Agreement

On August 19, 2020 (the "Petition Date"), Valaris plc and certain of its direct and indirect subsidiaries (collectively, the "Debtors"), filed voluntary petitions for reorganization under chapter 11 of the United States Bankruptcy Code ("Bankruptcy Code") in the Bankruptcy Court for the Southern District of Texas (the "Bankruptcy Court"). The Debtors obtained joint administration of their chapter 11 cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI) (the "Chapter 11 Cases"). On August 18, 2020, the Debtors entered into the Restructuring Support Agreement (the "Original RSA") with certain senior note holders (collectively, the "Consenting Noteholders"). On February 5, 2021, the Debtors entered into the Amended Restructuring Support Agreement (the “Amended RSA”) with the Consenting Noteholders and holders of approximately 100% of the total commitments under our revolving credit facility (the “Consenting Lenders” and, together with the Consenting Noteholders, the “Consenting Creditors”), which contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA.

See “Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” for additional details regarding the Chapter 11 Cases and Amended RSA.

Basis of Presentation—U.K. Companies Act 2006 Section 435 Statement

The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP, which the Board of Directors consider to be the most meaningful presentation of our results of operations and financial position. The accompanying consolidated financial statements do not constitute U.K. statutory accounts for the year ended December 31, 2020 and 2019 as required to be prepared under the U.K. Companies Act 2006. The U.K. statutory accounts are prepared in accordance with Financial Reporting Standard 102, the financial reporting standard applicable in the U.K. and Republic of Ireland (“FRS 102”). The auditor has reported on the U.K.

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statutory accounts for the year ended December 31, 2019; their report was (1) unqualified, (2) for the year ended December 31, 2019 included reference to a matter to which the auditor drew attention by way of emphasis without qualifying their report in respect of a material uncertainty in respect of going concern and (3) did not contain a statement under section 498 (2) or (3) of the U.K. Companies Act 2006. The U.K. statutory accounts for the year ended December 31, 2020 have yet to be finalized and, if required, will be delivered to the U.K. registrar of companies during 2021.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Valaris plc, those of our wholly-owned subsidiaries and entities in which we hold a controlling financial interest. All intercompany accounts and transactions have been eliminated. Investments in operating entities in which we have the ability to exercise significant influence, but where we do not control operating and financial policies are accounted for using the equity method. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. We account for our interest in ARO using the equity method of accounting and only recognize our portion of equity in earnings in our consolidated financial statements. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO. Certain previously reported amounts have been reclassified to conform to the current year presentation.

Pervasiveness of Estimates

The preparation of financial statements in conformity with U.S. GAAP 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.

Foreign Currency Remeasurement and Translation

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. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. Most transaction gains and losses, including certain gains and losses on our derivative instruments, are included in other, net, in our consolidated statement of operations. Certain gains and losses from the translation of foreign currency balances of our non-U.S. dollar functional currency subsidiaries are included in accumulated other comprehensive income on our consolidated balance sheet. Net foreign currency exchange losses, inclusive of offsetting fair value derivatives, were $11.0 million, $7.4 million and $17.2 million, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018, respectively.

Cash Equivalents and Short-Term Investments

Highly liquid investments with maturities of three months or less at the date of purchase are considered cash equivalents. Highly liquid investments with maturities of greater than three months but less than one year at the date of purchase are classified as short-term investments.

There were no short-term investments as of December 31, 2020 and 2019. Cash flows from purchases and maturities of short-term investments were classified as investing activities in our consolidated statements of cash flows for the years ended December 31, 2019 and 2018. To mitigate our credit risk, our investments in time deposits have historically been diversified across multiple, high-quality financial institutions.

Property and Equipment

All costs incurred in connection with the acquisition, construction, major enhancement and improvement of

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assets are capitalized, including allocations of interest incurred during periods that our drilling rigs are under construction or undergoing major enhancements and improvements. Costs incurred to place an asset into service are capitalized, including costs related to the initial mobilization of a newbuild drilling rig. Repair and maintenance costs are charged to contract drilling expense in the period in which they are incurred. Upon the sale or retirement of assets, the related cost and accumulated depreciation are removed from the balance sheet, and the resulting gain or loss is included in contract drilling expense.

Our property and equipment is depreciated on a straight-line basis, after allowing for salvage values, over the estimated useful lives of our assets. Drilling rigs and related equipment are depreciated over estimated useful lives ranging from four to 35 years. Buildings and improvements are depreciated over estimated useful lives ranging from seven to 30 years. Other equipment, including computer and communications hardware and software costs, is depreciated over estimated useful lives ranging from three to 6 years.

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, on a quarterly basis to identify events or changes in circumstances ("triggering events") that indicate that the carrying value of such rigs may not be recoverable. For property and equipment used in our operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset. If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the carrying value of the asset and its estimated fair value. Property and equipment held-for-sale is recorded at the lower of net book value or fair value less cost to sell.

We recorded pre-tax, non-cash impairment losses related to long-lived assets of $3.6 billion, $104.0 million and $40.3 million during 2020, 2019 and 2018, respectively. See "Note 6 - Property and Equipment" for additional information on our impairment charges.

Operating Revenues and Expenses

See "Note 3 - Revenue from Contracts with Customers" for information on our accounting policies for revenue recognition and certain operating costs that are deferred and amortized over future periods.

Derivative Instruments

We did not have any open derivative instruments as of December 31, 2020. However, we have historically used derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 9 - Derivative Instruments" for additional information on how and why we used derivatives and the impact of the Chapter 11 Cases.

Derivatives are recorded on our consolidated balance sheet at fair value. Derivatives subject to legally enforceable master netting agreements are not offset on our consolidated balance sheet. Accounting for the gains and losses resulting from changes in the fair value of derivatives depends on the use of the derivative and whether it qualifies for hedge accounting. Derivatives qualify for hedge accounting when they are formally designated as hedges and are effective in reducing the risk exposure that they are designated to hedge.

Changes in the fair value of derivatives that are designated as hedges of the variability in expected future cash flows associated with existing recognized assets or liabilities or forecasted transactions ("cash flow hedges") are recorded in accumulated other comprehensive income ("AOCI"). Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transactions.

Gains and losses on a cash flow hedge, or a portion of a cash flow hedge, that no longer qualifies as effective due to an unanticipated change in the forecasted transaction are recognized currently in earnings and included in other, net, in our consolidated statement of operations based on the change in the fair value of the derivative. When a forecasted transaction becomes probable of not occurring, gains and losses on the derivative

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previously recorded in AOCI are reclassified currently into earnings and included in other, net, in our consolidated statement of operations.

Historically, we occasionally would enter into derivatives that hedge the fair value of recognized assets or liabilities but do not designate such derivatives as hedges or the derivatives otherwise do not qualify for hedge accounting. In these situations, a natural hedging relationship generally exists where changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. Changes in the fair value of these derivatives are recognized currently in earnings in other, net, in our consolidated statement of operations.

Derivatives with asset fair values are reported in other current assets or other assets, net, on our consolidated balance sheet depending on maturity date. Derivatives with liability fair values are reported in accrued liabilities and other, or other liabilities on our consolidated balance sheet depending on maturity date.

Income Taxes

We conduct operations and earn income in numerous countries. Current income taxes are recognized for the amount of taxes payable or refundable based on the laws and income tax rates in the taxing jurisdictions in which operations are conducted and income is earned.

Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the enacted tax rates in effect at year-end. A valuation allowance for deferred tax assets is recorded when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. We do not offset deferred tax assets and deferred tax liabilities attributable to different tax paying jurisdictions.

We operate in certain jurisdictions where tax laws relating to the offshore drilling industry are not well developed and change frequently. Furthermore, we may enter into transactions with affiliates or employ other tax planning strategies that generally are subject to complex tax regulations. As a result of the foregoing, the tax liabilities and assets we recognize in our financial statements may differ from the tax positions taken, or expected to be taken, in our tax returns. Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. Interest and penalties relating to income taxes are included in current income tax expense in our consolidated statement of operations.

Our drilling rigs frequently move from one taxing jurisdiction to another based on where they are contracted to perform drilling services. The movement of drilling rigs among taxing jurisdictions may involve a transfer of drilling rig ownership among our subsidiaries through an intercompany rig sale. The pre-tax profit resulting from an intercompany rig sale is eliminated from our consolidated financial statements, and the carrying value of a rig sold in an intercompany transaction remains at historical net depreciated cost prior to the transaction. Our consolidated financial statements do not reflect the asset disposition transaction of the selling subsidiary or the asset acquisition transaction of the acquiring subsidiary. The income tax effects resulting from intercompany rig sales are recognized in earnings in the period in which the sale occurs.

In some instances, we may determine that certain temporary differences will not result in a taxable or deductible amount in future years, as it is more-likely-than-not we will commence operations and depart from a given taxing jurisdiction without such temporary differences being recovered or settled. Under these circumstances, no future tax consequences are expected and no deferred taxes are recognized in connection with such operations. We evaluate these determinations on a periodic basis and, in the event our expectations relative to future tax consequences change, the applicable deferred taxes are recognized or derecognized.

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Share-Based Compensation

We sponsor share-based compensation plans that provide equity compensation to our key employees, officers and non-employee directors. Subject to applicable bankruptcy law, our Long-Term Incentive Plan (the “2018 LTIP”) allows our Board of Directors to authorize share grants to be settled in cash or shares. Compensation expense for share awards to be settled in shares is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). Compensation expense for share awards to be settled in cash is remeasured each quarter with a cumulative adjustment to compensation cost during the period based on changes in our share price. Any adjustments to the compensation cost recognized in our consolidated statement of operations for awards that are forfeited are recognized in the period in which the forfeitures occur. See "Note 11 - Share Based Compensation" for additional information on our share-based compensation.

Pension and Other Post-retirement benefit plans

We measure our actuarially determined obligations and related costs for our defined benefit pension and other post-retirement plans, retiree life and medical supplemental plan benefits, by applying assumptions, the most significant of which include long-term rate of return on plan assets, discount rates and mortality rates. For the long-term rate of return, we develop our assumptions regarding the expected rate of return on plan assets based on historical experience and projected long-term investment returns, and we weight the assumptions based on each plan's asset allocation. For the discount rate, we base our assumptions on a yield curve approach. Actual results may differ from the assumptions included in these calculations. If gains or losses exceed 10% of the greater of the plan assets or plan liabilities, we amortize such gains or losses into income over either the period of expected future service of active participants, or over the expected average remaining lifetime of all participants. We recognize gains or losses related to plan curtailments at the date the plan amendment or termination is adopted which may precede the effective date.

Fair Value Measurements

We measure certain of our assets and liabilities based on a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy assigns the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities ("Level 1") and the lowest priority to unobservable inputs ("Level 3"). Level 2 measurements represent inputs that are observable for similar assets or liabilities, either directly or indirectly, other than quoted prices included within Level 1. See "Note 6 - Fair Value Measurements" for additional information on the fair value measurement of certain of our assets and liabilities.

Noncontrolling Interests

Third parties hold a noncontrolling ownership interest in certain of our non-U.S. subsidiaries. Noncontrolling interests are classified as equity on our consolidated balance sheet, and net income attributable to noncontrolling interests is presented separately in our consolidated statement of operations. For each of the years in the three-year period ended December 31, 2020, all income attributable to noncontrolling interest was from continuing operations.

Earnings Per Share

We compute basic and diluted earnings per share ("EPS") in accordance with the two-class method. Net loss attributable to Valaris used in our computations of basic and diluted EPS is adjusted to exclude net income allocated to non-vested shares granted to our employees and non-employee directors. Weighted-average shares

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outstanding used in our computation of diluted EPS is calculated using the treasury stock method and includes the effect of all potentially dilutive stock options and excludes non-vested shares. In each of the years in the three-year period ended December 31, 2020, 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.

The following table is a reconciliation of loss from continuing operations attributable to Valaris shares used in our basic and diluted EPS computations for each of the years in the three-year period ended December 31, 2020 (in millions):


	2020		2019		2018
Loss from continuing operations attributable to Valaris	$	(4,855.5)	$	(198.0)	$	(631.6)
Income from continuing operations allocated to non-vested share awards (1)	—		(.1)		(.5)
Loss from continuing operations attributable to Valaris shares	$	(4,855.5)	$	(198.1)	$	(632.1)

(1) Losses are not allocated to non-vested share awards. Due to the net loss position, potentially dilutive share awards are excluded from the computation of diluted EPS.

Anti-dilutive share awards totaling 400,000, 300,000 and 1.5 million for the years ended December 31, 2020, 2019 and 2018, respectively, were excluded from the computation of diluted EPS.

Under the terms of our debt agreement, we have the option to settle our 3.00% exchangeable senior notes due 2024 (the "2024 Convertible Notes") in cash, shares or a combination thereof for the aggregate amount due upon conversion. However, the commencement of the Chapter 11 Cases on August 19, 2020 constituted an event of default under the 2024 Convertible Notes. Any efforts to enforce payment obligations under the 2024 Convertible Notes, including any rights to require the repurchase by the Company of the 2024 Convertible Notes upon the NYSE delisting of the Class A ordinary shares, are automatically stayed as a result of the filing of the Chapter 11 Cases. During each respective reporting period that our average share price exceeds the exchange price, an assumed number of shares required to settle the conversion obligation in excess of the principal amount will be included in our denominator for the computation of diluted EPS using the treasury stock method. Our average share price did not exceed the exchange price during the years ended December 31, 2020, 2019 and 2018.

Pursuant to the terms contemplated in the Amended RSA, upon emergence from bankruptcy, our existing Class A ordinary shares will be cancelled. Depending on certain implementation mechanisms in the restructuring related to our Class A ordinary shares and satisfaction of the applicable support requirements set forth in the Amended RSA, the existing Class A ordinary shares may be exchanged for 7-year warrants to purchase up to 7% of the New Equity (subject to dilution on account of the management incentive plan contemplated by the Amended RSA). The strike price of such warrants, if granted, will be set at a price per share equal to the value at which the senior noteholders would receive a 100% recovery on their claims, including accrued interest up to the Petition Date. See “Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern” for additional information related to our Amended RSA.”

Bankruptcy Accounting

The consolidated financial statements included herein have been prepared as if we were a going concern. See “Note 2 – Chapter 11 Proceedings and Ability to Continue as a Going Concern” for additional details regarding the bankruptcy and circumstances raising substantial doubt over our ability to continue as a going concern. As a result, we have segregated liabilities and obligations whose treatment and satisfaction are dependent on the outcome of the Chapter 11 Cases and have classified these items as "Liabilities Subject to Compromise” on our Consolidated Balance Sheets. In addition, we have classified all income, expenses, gains or losses that were incurred or realized as a result of the Chapter 11 Cases subsequent to the Petition Date as “Reorganization Items” in our Consolidated Statements of Operations.

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We anticipate that we will adopt fresh start accounting upon our emergence from chapter 11, becoming a new entity for financial reporting purposes. As a result, upon emergence, the Company’s assets and liabilities will generally be reported at fair value and will reconcile to the enterprise value confirmed by the Bankruptcy Court. These fair values are expected to differ materially from the amounts reflected on our historical balance sheet.

New Accounting Pronouncements

Recently adopted accounting pronouncements

Credit Losses - In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ("Update 2016-13"), which requires companies to measure credit losses of financial instruments, including customer accounts receivable, utilizing a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. Subsequent to the issuance of Update 2016-13, the FASB issued several additional Accounting Standard Updates to clarify implementation guidance, provide narrow-scope improvements and provide additional disclosure guidance. We adopted Update 2016-13 effective January 1, 2020 with no material impact to our financial statements upon adoption as our previously estimated reserves were in line with expected credit losses calculated under Update 2016-13.

Defined Benefit Plans - In August 2018, the FASB issued ASU 2018-14, Compensation – Retirement Benefits – Defined Benefit Plans – General (Subtopic 715-20): Disclosure Framework – Changes to the Disclosure Requirements for Defined Benefit Plans ("Update 2018-14"), which modifies the disclosure requirements for employers that sponsor defined benefit pension or other post-retirement plans. We are required to adopt the amended guidance in annual and interim reports beginning after December 15, 2020, but early adoption is permitted. Adoption is required to be applied on a retrospective basis to all periods presented. We adopted Update 2018-14 effective January 1, 2020 with no material impact on our consolidated financial statements.

Financial Disclosures about Guarantors - In March 2020, the U.S. Securities and Exchange Commission issued final rule 33-10762, “Financial Disclosures About Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities.” In October 2020, the FASB issued ASU 2020-09, Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762 ("Update 2020-09"), which amends ASC 470, Debt, for this rule. The Rule suspends the requirement to disclose condensed financial information within the financial statements for entities whose debt securities are not listed on a national exchange, and meet the reporting obligation under Section 15(d)(1) of the Exchange Act if, on the first day of any fiscal year other than the fiscal year in which the Securities Act registration statement related to the debt securities becomes effective, there are fewer than 300 record holders of the class of debt securities. The Final Rule is effective on January 4, 2021 with early adoption permitted. We early adopted the Rule effective December 31, 2020 and as we meet the requirements for suspension, we no longer provide condensed consolidated financial information that resulted from the debt obligations of our 100% owned subsidiaries, Pride International LLC and Ensco International Incorporated.

Accounting pronouncements to be adopted

Income Taxes - In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes ("Update 2019-12"), which removes certain exceptions for investments, intraperiod allocations and interim tax calculations and adds guidance to reduce complexity in accounting for income taxes. We are required to adopt the amended guidance in annual and interim periods beginning after December 15, 2020. The various amendments in Update 2019-12 are applied on a retrospective basis, modified retrospective basis and prospective basis, depending on the amendment. We are in the process of evaluating the impact this amendment will have on our consolidated financial statements.

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Reference Rate Reform - In March 2020, the FASB issued ASU 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. We are in the process of evaluating the impact this amendment will have on our consolidated financial statements.

Convertible Instruments - In August 2020, the FASB issued ASU 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815 – 40)” ("Update 2020-06”). ASU 2020-06 simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. The ASU is part of the FASB’s simplification initiative, which aims to reduce unnecessary complexity in U.S. GAAP. The ASU’s amendments are effective for fiscal years beginning after December 15, 2021, and interim periods within those fiscal years, with early adoption permitted no earlier than fiscal years beginning after December 15, 2020. We are in the process of evaluating the impact this amendment may have on our consolidated financial statements.

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 consolidated financial statements.

2. CHAPTER 11 PROCEEDINGS AND ABILITY TO CONTINUE AS A GOING CONCERN

Chapter 11 Cases

On August 19, 2020, the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court. The Debtors obtained joint administration of the Chapter 11 Cases under the caption In re Valaris plc, et al., Case No. 20-34114 (MI).

The Debtors continue to operate their businesses and manage their properties as "debtors-in-possession" under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As part of the Chapter 11 Cases, the Debtors filed with the Bankruptcy Court motions seeking a variety of "first-day" relief, all of which were granted and enabled the Company to continue operating without interruption or disruption to its relationships with its customers and vendors or its high-quality service delivery. In particular, employee pay and benefits are expected to continue without interruption.

Restructuring Support Agreement

On August 18, 2020, the Debtors entered into the Original RSA with the Consenting Noteholders. On February 5, 2021, the Debtors entered into the Amended RSA with the Consenting Noteholders and the Consenting Lenders. The Amended RSA contemplates that the Company will implement the restructuring through the Chapter 11 Cases pursuant to a plan of reorganization and the various related transactions set forth in or contemplated by the Amended RSA. Below is a summary of the treatment that the stakeholders of the Company would receive under a plan of reorganization pursuant to the terms of the Amended RSA:

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•Holders of the Company's outstanding senior notes ("Senior Notes") will receive their pro rata share of (i) approximately 39% of new common stock issued after consummation of the restructuring (the “New Equity”) and (ii) approximately 97.6% of the subscription rights to participate in the rights offering (the "Rights Offering") through which the Company will offer $550 million of new first lien secured notes (the "New Secured Notes"), which includes the Backstop Premium (as defined below);

•Holders of the Senior Notes who participate in the Rights Offering will receive their pro rata share of approximately 29.3% of the New Equity pursuant to the Rights Offering, together with the RCF Lenders (as defined below) who will receive their pro rata share of approximately 0.7% of the New Equity, and senior noteholders who agreed to backstop the Rights Offering will receive their pro rata share of approximately 2.63% of the New Equity, together with 0.07% of the New Equity reserved for RCF Lenders and approximately $48.8 million in New Secured Notes reserved for the holders of the Senior Notes and approximately $1.2 million in New Secured Notes reserved for the RCF Lenders (the "Backstop Premium");

•Senior noteholders, solely with respect to Pride International LLC's ("Pride") 6.875% senior notes due 2020 and 7.875% senior notes due 2040, Ensco International 7.20% Debentures due 2027, and the Company's 4.875% senior notes due 2022, 4.75% senior notes due 2024, 7.375% senior notes due 2025, 5.4% senior notes due 2042 and 5.85% senior notes due 2044, will receive an aggregate cash payment of $26 million in connection with settlement of certain alleged claims against the Company;

•Lenders under the revolving credit facility (“RCF Lenders”) were provided an option to select between two alternative treatments: (1) the ability to participate on a pro rata basis in up to 14% of the Rights Offering plus a recovery of up to 30.8% of the New Equity and up to $45 million in cash, or (2) a pro rata recovery of up to 27.8% of the New Equity and up to $116.2 million in cash. Following the results of that election, the two RCF Lenders who chose to participate in the Rights Offering will receive their pro rata share of (1) approximately 5.3% of the New Equity, (2) approximately 2.4% of the New Secured Notes (and associated New Equity), (3) approximately $7.8 million in cash, and (iv) their pro rata share of the Backstop Premium. The RCF Lenders who entered into the Amended RSA and elected not to participate in the Rights Offering will receive their pro rata share of (1) approximately 23.0% of the New Equity, and (2) approximately $96.1 million in cash;

•Holders of general unsecured claims will receive payment in full or reinstatement pursuant to the Bankruptcy Code (excluding claims against the entities party to, or guaranteeing, the new build contracts to be rejected by the Company, which shall receive their liquidation value unless otherwise agreed);

•If holders of equity interests vote as a class in support of the restructuring, they will each receive their pro rata share of 7-year warrants to purchase up to 7% of New Equity (subject to dilution), with a strike price set at a price per share equal to the value at which the senior noteholders would receive a 100% recovery on their claims including accrued interest up to the Petition Date, as applicable; and

•To the extent amounts are borrowed under the DIP Facility (as described below), lenders under the DIP Facility will receive payment in full in cash, unless otherwise agreed, and certain other fees owed to the DIP Facility lenders.

The Original RSA provided that for a period of 15 business days after the commencement of the Chapter 11 Cases (the “Joinder Period”), qualified holders of Senior Notes claims, including the Consenting Noteholders, were eligible to become backstop parties (the “Noteholder Backstop Parties”). All Noteholder Backstop Parties were required to join the Original RSA. The expiration of the Joinder Period was extended on September 10, 2020, to September 14, 2020 upon which date we had support for the Original RSA from holders of approximately 72% of the aggregate amount of our Senior Notes outstanding.

119

The Amended RSA contemplates that holders of claims under the Company’s revolving credit facility also are eligible to become backstop parties (the “Lender Backstop Parties”). The Lender Backstop Parties are required to join the Amended RSA. As of the execution of the Amended RSA, we had support for the transactions contemplated by the Amended RSA from holders of approximately 100% of the total commitments under our revolving credit facility in addition to the holders of approximately 72% of the aggregate amount of our outstanding Senior Notes who supported the Original RSA.

Debtor in Possession Facility

On August 11, 2020, prior to the commencement of the Chapter 11 Cases, certain of the Company’s existing noteholders (or their affiliates or designees) provided the Company with a commitment for a senior secured superpriority debtor-in-possession term loan credit facility in an aggregate principal amount of up to $500.0 million (the “DIP Facility”). On September 25, 2020, following approval by the Bankruptcy Court, the Debtors entered into a senior secured superpriority debtor-in-possession term loan credit agreement (the “DIP Credit Agreement”), by and among the Company and certain wholly owned subsidiaries of the Company, as borrowers, the lenders party thereto and Wilmington Savings Fund Society, FSB, as administrative agent and security trustee, in an aggregate amount not to exceed $500.0 million. Borrowings on the DIP Facility will be used to finance, among other things, the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases and to pay certain fees, costs and expenses associated with the Debtors’ Chapter 11 Cases.

120

As of December 31, 2020, we were in compliance with our covenants under the DIP Credit Agreement. Additionally, as of December 31, 2020, we had no borrowings outstanding against our DIP Facility.

Backstop Commitment Agreement

On August 18, 2020, the Company entered into a Backstop Commitment Agreement (the “Initial BCA”) with the Backstop Parties. Pursuant to the Initial BCA, each of the Backstop Parties will purchase its pro-rata portion (based on an adjusted claims value) of (1) $187.5 million of the New Secured Notes held back for purchase by the Backstop Parties (the "Holdback Notes"), (2) all of the New Secured Notes offered to Backstop Parties as part of the $312.5 million New Secured Notes offered to all claim holders (the “General Rights Offering”) and (3) New Secured Notes not purchased by non-Backstop Parties in the General Rights Offering. The Initial BCA was amended on September 10, 2020, January 22, 2021 and February 5, 2021 (as so amended, the “Amended BCA”). Pursuant to the Amended BCA, certain holders of claims related to the revolving credit facility will be entitled to, among other things 2.427% of the Holdback Notes and the New Secured Notes (together with certain stapled participation equity) offered in the General Rights Offering, as well as a portion of the equity premium payable to all Backstop Parties consisting of 2.7% of New Valaris Equity and backstop premium payable in $50.0 million in New Secured Notes.

In each instance, 30% of the new shares issued and outstanding immediately after the effective date of the plan of reorganization (subject to dilution by the new warrants and the management incentive plan) will be allocated proportionally to purchasers of the New Secured Notes for no additional consideration. Additionally, in exchange for providing the Backstop Commitments, the Company has agreed to pay the Backstop Parties a backstop premium in an aggregate amount equal to $50.0 million payable in New Secured Notes on the effective date of a plan of reorganization, in addition to 2.7% of New Valaris Equity. Further, the Debtors paid a commitment fee of $20.0 million, in cash prior to the Petition Date, which shall be loaned back to the reorganized company upon emergence. Therefore, upon emergence the Debtors will receive $520 million in cash in exchange for a $550 million note, which includes the backstop premium.

The Amended BCA will be terminable by the Company and/or the requisite Backstop Parties upon certain customary events specified therein, including, among others, (i) the termination of the Amended RSA, (ii) the mutual written consent of the Company and the requisite Backstop Parties by written notice to the other such Party(ies) or (iii) either the Company or the requisite Backstop Parties if the effective date of the plan of reorganization has not occurred on or prior to the date that is ten months after the execution date of the Initial BCA (subject to certain extensions as set forth in the Initial BCA).

NYSE Delisting of our Common Stock

121

Effective August 19, 2020, the Company’s Class A ordinary shares commenced trading on the OTC Pink Open Market under the symbol “VALPQ.”

Going Concern

The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business.

The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty. These adjustments could be material.

Pre-petition Charges

We have reported the backstop commitment fee and legal and other professional advisor fees incurred in relation to the Chapter 11 Cases, but prior to the Petition Date, as General and administrative expenses in our Consolidated Statement of Operations for the year ended December 31, 2020 in the amount of $64.7 million.

Reorganization Items

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The following table provides information about reorganization items incurred during the year ended December 31, 2020, as of or subsequent to the Petition Date (in millions):


	Year Ended December 31, 2020
Write-off of unamortized debt discounts, premiums and issuance costs	$	447.9
Contract items	(11.5)
Reorganization items (non-cash)	436.4


DIP Facility fees	20.0
Professional fees	66.8
Contract items	4.4
Reorganization items (fees)	91.2
Total reorganization items, net	$	527.6

Reorganization items (fees) unpaid	$	61.2
Reorganization items (fees) paid	$	30.0

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Liabilities Subject to Compromise

Liabilities subject to compromise at December 31, 2020 consist of the following (in millions):


	December 31, 2020
6.875% Senior notes due 2020	$	122.9
4.70% Senior notes due 2021	100.7
4.875% Senior notes due 2022	620.8
3.00% Exchangeable senior notes due 2024	849.5
4.50% Senior notes due 2024	303.4
4.75% Senior notes due 2024	318.6
8.00% Senior notes due 2024	292.3
5.20% Senior notes due 2025	333.7
7.375% Senior notes due 2025	360.8
7.75% Senior notes due 2026	1,000.0
7.20% Debentures due 2027	112.1
7.875% Senior notes due 2040	300.0
5.40% Senior notes due 2042	400.0
5.75% Senior notes due 2044	1,000.5
5.85% Senior notes due 2044	400.0
Amounts drawn under revolving credit facility	581.0
Accrued Interest on Senior Notes, Exchangeable Senior Notes, Debentures and Revolving Credit Facility	203.5
Rig holding costs(1)	13.9
Total liabilities subject to compromise	$	7,313.7

(1) Represents the holding costs incurred to maintain VALARIS DS-13 and VALARIS DS-14 in the shipyard until the delivery date.

The principal balance on our unsecured senior notes and the amount of outstanding borrowings on our revolving credit facility have been reclassified from Debt to Liabilities Subject to Compromise on our Consolidated Balance Sheet as of December 31, 2020. Accrued interest on our unsecured senior notes and revolving credit facility was also reclassified from Other Current Liabilities to Liabilities Subject to Compromise on our Consolidated Balance Sheet as of December 31, 2020.

The contractual interest expense on our unsecured senior notes and revolving credit facility is in excess of recorded interest expense by $140.7 million for the year ended December 31, 2020. This excess contractual interest is not included as interest expense on the Consolidated Statements of Operations for the year ended December 31, 2020, as the Company has discontinued accruing interest on the unsecured senior notes and revolving credit facility subsequent to the Petition Date. We discontinued making interest payments on our unsecured senior notes beginning in June 2020. See "Note 8 – Debt” for additional information on interest payments.

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Debtor Financial Statements

Consolidated financial statements of the Debtors are set forth below. These financial statements exclude the financial statements of the non-debtor subsidiaries. Transactions and balances of receivables and payables between the Debtors have been eliminated in consolidation. Amounts payable to or receivable from the non-Debtor subsidiaries are reported in the unaudited condensed consolidated balance sheet of the Debtors.

VALARIS PLC AND CERTAIN SUBSIDIARIES PARTY TO THE BANKRUPTCY CASES

(DEBTOR-IN-POSSESSION)

CONDENSED COMBINED STATEMENTS OF OPERATIONS

(In millions)


	Year Ended December 31, 2020
OPERATING REVENUES
Operating revenues	$	1,185.1
Operating revenues from non-debtor subsidiaries	169.8
Total operating revenues	1,354.9
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	1,203.0
Loss on impairment	3,643.9
Depreciation	507.5
General and administrative	213.6
Operating expenses for non-debtor subsidiaries	169.1
Total operating expenses	5,737.1
OTHER OPERATING INCOME	118.1
EQUITY IN LOSSES OF ARO	(7.8)
OPERATING LOSS	(4,271.9)
OTHER INCOME (EXPENSE)
Interest income	19.7
Interest income for non-debtor subsidiaries	285.7
Interest expense, net	(290.8)
Interest Expense for non-debtor subsidiaries	(310.9)
Reorganization items, net	(527.6)

Other, net	(6.7)
	(830.6)
LOSS BEFORE INCOME TAXES	(5,102.5)
EQUITY IN EARNINGS OF SUBSIDIARIES	11.4



PROVISION (BENEFIT) FOR INCOME TAXES	(277.5)
NET LOSS	$	(4,813.6)

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VALARIS PLC AND CERTAIN SUBSIDIARIES PARTY TO THE BANKRUPTCY CASES

(DEBTOR-IN-POSSESSION)

CONDENSED COMBINED BALANCE SHEET

(In millions)


	December 31, 2020
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	228.9
Accounts receivable, net	382.5
Accounts receivable from non-debtor subsidiaries	2,812.0
Other current assets	377.4
Total current assets	3,800.8
PROPERTY AND EQUIPMENT, AT COST	12,256.1
Less accumulated depreciation	1,973.8
Property and equipment, net	10,282.3
LONG-TERM NOTES RECEIVABLE FROM ARO	442.7
LONG-TERM NOTES RECEIVABLE FROM NON-DEBTOR SUBSIDIARIES	2,205.3
INVESTMENT IN ARO	120.9
INVESTMENTS IN NON-DEBTOR SUBSIDIARIES	585.9
OTHER ASSETS	158.2
	$	17,596.1
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$	149.4
Accrued liabilities and other	196.2



Total current liabilities	345.6

LONG-TERM NOTES PAYABLE TO NON-DEBTOR SUBSIDIARIES	2,548.6
OTHER LIABILITIES	602.3
Total liabilities not subject to compromise	3,496.5
Liabilities subject to compromise	7,313.7
Total debtors' equity	6,785.9
Total liabilities and debtors' equity	$	17,596.1

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VALARIS PLC AND CERTAIN SUBSIDIARIES PARTY TO THE BANKRUPTCY CASES

(DEBTOR-IN-POSSESSION)

CONDENSED COMBINED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31, 2020
OPERATING ACTIVITIES
Net loss	$	(4,813.6)
Adjustments to reconcile net loss to net cash used in operating activities:
Loss on impairment	3,643.9
Depreciation expense	507.5
Non cash reorganization items, net	436.4
Deferred income tax benefit	(107.5)
Debtor in Possession financing fees and payments on Backstop Agreement	40.0
Debt discounts and other	36.8
Share-based compensation expense	21.4
Equity in earnings of non-debtor subsidiaries	(11.4)
Equity in losses of ARO	7.8
(Gain on) adjustment to bargain purchase	6.3
Amortization, net	6.2
Gain on extinguishment of debt	(3.1)
Other	17.5
Changes in operating assets and liabilities	(44.5)

Changes in advances (to)/from non-debtor subsidiaries	(74.0)
Net cash used in operating activities	(330.3)
INVESTING ACTIVITIES
Additions to property and equipment	(93.8)
Net proceeds from disposition of assets	51.8




Net cash used in investing activities	(42.0)
FINANCING ACTIVITIES
Borrowings on credit facility	596.0
Debtor in Possession financing fees and payments on Backstop Agreement	(40.0)
Repayments of credit facility borrowings	(15.0)
Reduction of long-term borrowings	(9.7)

Other	(1.8)
Net cash provided by financing activities	529.5
Effect of exchange rate changes on cash and cash equivalents	—
INCREASE IN CASH AND CASH EQUIVALENTS	157.2
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	71.7
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	228.9

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3. 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 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 December 31, 2020 was between approximately one month and two 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 basis 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 typically range from 30 to 45 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.

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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 or capital upgrades.

Contract assets and liabilities are presented net on our consolidated balance sheet 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 consolidated balance sheets.

As of December 31, 2020, we have an ARO contract liability representing the difference between the amount billed under the Lease Agreements and lease revenues earned to date. See “Note 5 – Equity Method Investment in ARO" for additional details regarding our balances with ARO.

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


	December 31, 2020		December 31, 2019
Current contract assets	$	1.4	$	3.5
Noncurrent contract assets	$	.4	$	—
Current contract liabilities (deferred revenue)	$	57.6	$	30.0
Noncurrent contract liabilities (deferred revenue)	$	14.3	$	9.7

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


	Contract Assets		Contract Liabilities
Balance as of January 1, 2020	$	3.5	$	39.7
Revenue recognized in advance of right to bill customer	3.1		—
Increase due to cash received	—		81.5
Decrease due to amortization of deferred revenue that was included in the beginning contract liability balance	—		(24.6)
Decrease due to amortization of deferred revenue that was added during the period	—		(24.7)
Decrease due to transfer to receivables during the period	(4.8)		—
Balance as of December 31, 2020	$	1.8	$	71.9

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 consolidated balance sheets and totaled $13.8 million and $19.7 million as of December 31, 2020 and 2019, respectively. Amortization of these costs totaled $42.1 million, $42.1 million and $34.0 million for the years ended December 31, 2020, 2019 and 2018, respectively.

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 consolidated balance sheets and totaled $8.4 million and $10.8 million as of December 31, 2020 and 2019, respectively. Amortization of these costs totaled $8.9 million, $10.3 million and $12.4 million for the years ended December 31, 2020, 2019 and 2018, respectively.

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 Lease Agreements with ARO which would not be contractually payable until the end of the lease term or termination, if sooner. Expected future amortization of our contract liabilities and deferred costs recorded as of December 31, 2020 is set forth in the table below (in millions):


	2021		2022		2023		2024 & Thereafter		Total
Amortization of contract liabilities	$	57.6	$	14.3	$	—	$	—	$	71.9
Amortization of deferred costs	$	17.4	$	4.3	$	.5	$	—	$	22.2

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4. ROWAN TRANSACTION

On April 11, 2019 (the "Transaction Date"), we completed our combination with Rowan pursuant to the Transaction Agreement (the "Rowan Transaction"). Assets acquired and liabilities assumed in the Rowan Transaction were recorded at their estimated fair values as of the Transaction Date under the acquisition method of accounting. When the fair value of the net assets acquired exceeds the consideration transferred in an acquisition, the difference is recorded as a bargain purchase gain in the period in which the transaction occurs. As of March 31, 2020, we completed our fair value assessments of assets acquired and liabilities assumed.

Consideration

As a result of the Rowan Transaction, Rowan shareholders received 2.75 Valaris Class A Ordinary shares for each share of Rowan Class A ordinary share, representing a value of $43.67 per Rowan share based on a closing price of $15.88 per Valaris share on April 10, 2019, the last trading day before the Transaction Date. Total consideration delivered in the Rowan Transaction consisted of 88.3 million Valaris shares with an aggregate value of $1.4 billion, inclusive of $2.6 million for the estimated fair value of replacement employee equity awards. Upon closing of the Rowan Transaction, we effected a consolidation (being a reverse stock split under English law) where every four existing Class A ordinary shares, each with a nominal value of $0.10, were consolidated into one Class A ordinary share, each with a nominal value of $0.40 (the "Reverse Stock Split"). All share and per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split.

Assets and Liabilities Acquired

Valaris is considered to be the acquirer for accounting purposes. As a result, Rowan's assets and liabilities acquired in the Rowan Transaction were recorded at their estimated fair values as of the Transaction Date under the acquisition method of accounting. When the fair value of the net assets acquired exceeds the consideration transferred in an acquisition, the difference is recorded as a bargain purchase gain in the period in which the transaction occurs.

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The provisional amounts recorded for assets and liabilities acquired were based on preliminary estimates of their fair values as of the Transaction Date and Measurement Period Adjustments were recorded throughout the measurement period as provisional amounts were finalized and are as follows (in millions):


	Amounts Recognized as of Transaction Date		Measurement Period Adjustments (1)		Estimated Fair Value
Assets:
Cash and cash equivalents	$	931.9	$	—	$	931.9
Accounts receivable(2)	207.1		(6.9)		200.2
Other current assets	101.6		(2.6)		99.0
Long-term notes receivable from ARO	454.5		—		454.5
Investment in ARO	138.8		2.5		141.3
Property and equipment	2,989.8		(26.0)		2,963.8
Other assets	41.7		1.1		42.8
Liabilities:
Accounts payable and accrued liabilities	259.4		15.7		275.1
Current portion of long-term debt	203.2		—		203.2
Long-term debt	1,910.9		—		1,910.9
Other liabilities	376.3		34.5		410.8
Net assets acquired	2,115.6		(82.1)		2,033.5
Less: Merger consideration	(1,402.8)		—		(1,402.8)
Bargain purchase gain	$	712.8	$	(82.1)	$	630.7

(1) The measurement period adjustments reflect changes in the estimated fair values of certain assets and liabilities, primarily related to long-lived assets, deferred income taxes and uncertain tax positions. The measurement period adjustments were recorded to reflect new information obtained about facts and circumstances existing as of the Transaction Date and did not result from subsequent intervening events. The adjustments recorded resulted in a $6.3 million and $75.8 million decline to bargain purchase gain during the first quarter of 2020 and for the year ended December 31, 2019. The bargain purchase gain adjustments are included in other, net, in our consolidated statements of operations for the year ended December 31, 2020 and 2019, respectively.

(2) Gross contractual amounts receivable totaled $208.3 million as of the Transaction Date.

Bargain Purchase Gain

The estimated fair values assigned to assets acquired net of liabilities assumed exceeded the consideration transferred, resulting in a bargain purchase gain primarily driven by the decline in our share price from $33.92 to $15.88 between the last trading day prior to the announcement of the Rowan Transaction and the Transaction Date.

Materials and Supplies

We recorded materials and supplies at an estimated fair value of $83.0 million. Materials and supplies consist of consumable parts and supplies maintained on drilling rigs and in shore-based warehouse locations for use in operations and are generally comprised of items of low per unit cost and high reorder frequency. We estimated the fair value of Rowan's materials and supplies primarily using a market approach.

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Equity Method Investment in ARO

The equity method investment in ARO was recorded at its estimated fair value as of the Transaction Date. See "Note 5 - Equity Method Investment in ARO" for additional information on ARO. We estimated the fair value of the equity investment primarily by applying an income approach, using projected discounted cash flows of the underlying assets, a risk-adjusted discount rate and an estimated effective income tax rate.

Property and Equipment

Property and equipment acquired in connection with the Rowan Transaction consisted primarily of drilling rigs and related equipment, including four drillships and 19 jackup rigs (exclusive of two jackups marked for retirement). We recorded property and equipment acquired at its estimated fair value of $3.0 billion. We estimated the fair value of the rigs and equipment by applying an income approach, using projected discounted cash flows, a risk-adjusted discount rate and an estimated effective income tax rate. The estimated remaining useful lives for Rowan's drilling rigs, which ranged from 16 to 35 years based on original estimated useful lives of 30 to 35 years.

Intangible Assets and Liabilities

We recorded intangible assets and liabilities of $16.2 million and $2.1 million, respectively, representing the estimated fair value of Rowan's firm contracts in place at the Transaction Date with favorable or unfavorable contract terms compared to then-market day rates for comparable drilling rigs.

As a result of a price concession negotiated following the onset of the COVID-19 pandemic, on one of our bare boat charter agreements for a rig leased to our 50/50 joint venture with Saudi Aramco ("ARO"), we recognized a $5.7 million impairment to the related contract intangible during the second quarter of 2020. The impairment is included in loss on impairment in our consolidated statements of operations for the year ended December 31, 2020.

Amortization of the intangible assets and liabilities resulted in a net reduction in operating revenues of $2.8 million and $3.6 million for the years ended December 31, 2020 and 2019, respectively. The remaining balances of intangible assets and liabilities of $2.4 million and $0.4 million, respectively, are included in other assets and other liabilities, respectively, on our consolidated balance sheet of December 31, 2020. These balances will be amortized to operating revenues over the respective remaining contract terms on a straight-line basis. As of December 31, 2020, the remaining terms of the underlying contracts is approximately 1.0 year. Amortization of these intangibles is expected to result in a reduction to revenue of $2.0 million in 2021.

Pension and Other Post-retirement benefit plans

We remeasured the fair value of plan assets and benefit obligations for the pension and other-post retirement benefit plans assumed as of April 11, 2019. We used a measurement date of April 11, 2019 for determining net periodic benefit costs.

Long-term Debt

We recorded Rowan's long-term debt at its estimated fair value as of the Transaction Date, which was based on quoted market prices as of April 10, 2019.

Deferred Taxes

The Rowan Transaction was executed through the acquisition of Rowan's outstanding ordinary shares and, therefore, the historical tax bases of the acquired assets and liabilities, net operating losses and other tax attributes of Rowan, were acquired as of the Transaction Date. However, adjustments were recorded to recognize deferred tax assets and liabilities for the tax effects of differences between acquisition date fair values and tax bases of assets acquired and liabilities assumed. Additionally, the interaction of our and Rowan's tax attributes that impacted the

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deferred taxes of the combined entity were also recognized as part of acquisition accounting. As of the Transaction Date, a decrease of $99.0 million to Rowan's historical net deferred tax assets was recognized.

Deferred tax assets and liabilities recognized in connection with the Rowan Transaction were measured at rates enacted as of the Transaction Date. Tax rate changes, or any deferred tax adjustments for new tax legislation, following the Transaction Date will be reflected in our operating results in the period in which the change in tax laws or rate is enacted.

Uncertain Tax Positions

Uncertain tax positions assumed in a business combination are measured at the largest amount of the tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information. As of the Transaction Date, Rowan had previously recognized net liabilities for uncertain tax positions totaling $50.4 million.

The Luxembourg tax authorities issued aggregate tax assessments totaling approximately €142.0 million (approximately $173.5 million converted using the current period-end exchange rate) related to tax years 2014, 2015 and 2016 for several of Rowan's Luxembourg subsidiaries. As a result of our review and analysis of facts and circumstances that existed at the Transaction Date, we recognized liabilities related to the Luxembourg tax assessments totaling €93.0 million (approximately $113.6 million converted using the current period-end exchange rates). See "Note 13 - Income Taxes" for further information on this matter.

Transaction-related costs

Transaction-related costs were expensed as incurred and consisted of various advisory, legal, accounting, valuation and other professional or consulting fees totaling $18.0 million for the year ended December 31, 2019. These costs were included in general and administrative expense in our consolidated statement of operations.

Revenues and Losses of Rowan

The amount of revenues and net losses of Rowan that are included from the Transaction Date to December 31, 2019 in the Company's Consolidated Statement of Operations for the Year ended December 31, 2019 were $448.0 million and $122.7 million, respectively.

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Unaudited Pro Forma Impact of the Rowan Transaction

The following unaudited supplemental pro forma results present consolidated information as if the Rowan Transaction was completed on January 1, 2019. The pro forma results include, among others, (1) the amortization associated with acquired intangible assets and liabilities, (2) a reduction in depreciation expense for adjustments to property and equipment, (3) the amortization of premiums and discounts recorded on Rowan's debt, (iv) removal of the historical amortization of unrealized gains and losses related to Rowan's pension plans and (v) the amortization of basis differences in assets and liabilities of ARO. The pro forma results do not include any potential synergies or non-recurring charges that may result directly from the Rowan Transaction.


(unaudited) (in millions, except per share amounts)	Twelve Months Ended December 31, 2019(1)
Revenues	$	2,240.5
Net loss	$	(997.8)
Earnings per share - basic and diluted	$	(3.82)

(1) Pro forma net loss and loss per share were adjusted to exclude an aggregate $108.1 million of transaction related and integration costs during the year ended December 31, 2019. Additionally, pro forma net loss and loss per share exclude the measurement period adjustments and estimated gain on bargain purchase of $637.0 million recognized during the year ended December 31, 2019.

5. EQUITY METHOD INVESTMENT IN ARO

Background

ARO, a company that owns and operates offshore drilling rigs in Saudi Arabia, was formed and commenced operations in 2017 pursuant to the terms of an agreement entered into by Rowan and Saudi Aramco to create a 50/50 joint venture ("Shareholder Agreement"). Pursuant to the Rowan Transaction, Valaris acquired Rowan's interest in ARO making Valaris a 50% partner. ARO owns seven jackup rigs, has ordered two newbuild jackup rigs and leases nine rigs from us through bareboat charter arrangements (the "Lease Agreements") whereby substantially all operating costs are incurred by ARO. As of December 31, 2020, all nine of the leased rigs were operating under three-year drilling contracts with Saudi Aramco. The seven rigs owned by ARO, previously purchased from Rowan and Saudi Aramco, 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.

The Lease Agreements with ARO originally provided for a fixed per day bareboat charter amount over the term of the lease, calculated based on a split of projected earnings over the lease term. However, in December 2020, the Shareholder Agreement was amended ("December Amendment") such that the per day bareboat charter amount in the associated lease agreements is subject to adjustment based on actual performance of the respective rig and that a cash payment based on actual results will be due at the end of the lease term or, if sooner, termination. The Company, as lessor, accounts for these arrangements as operating leases. The December Amendment resulted in a modification of the leases and as a result we began accounting for lease revenue using the variable rate as opposed to a fixed rental amount. Our results of operations for the year ended December 31, 2020 reflect the impact of the lease modification on our rental revenues to reflect results through that period.

Valaris and Saudi Aramco have agreed to take all steps necessary to ensure that ARO purchases 20 newbuild jackup rigs ratably over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176 million, for delivery scheduled 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. 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

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ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. The Company's capital contributions to ARO pursuant to this requirement may require approval of the Bankruptcy Court during the Chapter 11 Cases. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis. The joint venture partners agreed 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.

Upon establishment of ARO, Rowan entered into (1) an agreement to provide certain back-office services for a period of time until ARO develops its own infrastructure (the "Transition Services Agreement"), and (2) an agreement to provide certain Rowan employees through secondment arrangements to assist with various onshore and offshore services for the benefit of ARO (the "Secondment Agreement"). These agreements remained in place subsequent to the Rowan Transaction. Pursuant to these agreements, we or our seconded employees provide various services to ARO, and in return, ARO provides remuneration for those services. From time to time, we may also sell equipment or supplies to ARO. During the quarter ended June 30, 2020, almost all remaining employees seconded to ARO became employees of ARO. Additionally, our services to ARO under the Transition Services Agreement were completed as of December 31, 2020.

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. Cost incurred under the Secondment Agreement are included in contract drilling expense and general and administrative, depending on the function to which the seconded employee's service related. Substantially all costs incurred under the Transition Services Agreement are included in general and administrative. See additional discussion below regarding these related-party transactions.

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


	Year Ended December 31, 2020		April 11, 2019 - December 31, 2019
Revenues	$	549.4	$	410.5
Operating expenses
Contract drilling (exclusive of depreciation)	388.2		280.2
Depreciation	54.8		40.3
General and administrative	24.2		27.1
Operating income	82.2		62.9
Other expense, net	26.7		28.6
Provision for income taxes	14.2		9.7
Net income	$	41.3	$	24.6

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	December 31, 2020		December 31, 2019
Current assets	$	358.6	$	407.2
Non-current assets	804.0		874.8
Total assets	$	1,162.6	$	1,282.0

Current liabilities	$	70.8	$	183.2
Non-current liabilities	950.8		1,015.5
Total liabilities	$	1,021.6	$	1,198.7

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 of ARO in our 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.

As a result of the Rowan Transaction, we recorded our equity method investment in ARO at its estimated fair value on the Transaction Date. Additionally, 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"). The basis differences primarily relate 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 Transaction Date. The 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 of ARO in our 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):


	Year Ended December 31, 2020		April 11, 2019 - December 31, 2019
50% interest in ARO net income	$	20.7	$	12.3
Amortization of basis differences	(28.5)		(24.9)
Equity in earnings (losses) of ARO	$	(7.8)	$	(12.6)

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Related-Party Transactions

Revenues recognized by us related to the Lease Agreements, Transition Services Agreement and Secondment Agreement are as follows (in millions):


	Year Ended December 31, 2020		April 11, 2019 - December 31, 2019
Lease revenue	$	52.2	$	58.2
Secondment revenue	21.6		49.9
Transition Services revenue	1.3		17.3
Total revenue from ARO (1)	$	75.1	$	125.4

(1) All of the revenues presented above are included in our Other segment in our segment disclosures. See "Note 16- Segment Information" for additional information.

Amounts receivable from ARO related to the items above totaled $21.6 million and $21.8 million as of December 31, 2020 and 2019, respectively, and are included in accounts receivable, net, on our consolidated balance sheets. Additionally, as of December 31, 2019, we had a receivable from ARO of $14.2 million related to an agreement between us and ARO, pursuant to which ARO would reimburse us for certain capital expenditures related to the shipyard upgrade projects for the VALARIS JU-147 and VALARIS JU-148. This amount was collected in the first quarter of 2020.

Accounts payable to ARO totaled $0.7 million as of December 31, 2019. There were no Accounts payable to ARO as of December 31, 2020. We had $30.9 million in Contract Liabilities related to our lease agreements with ARO as of December 31, 2020.

During 2017 and 2018, Rowan contributed cash to ARO in exchange for 10-year shareholder notes receivable at a stated interest rate of LIBOR plus two percent. As of December 31, 2020 and 2019, the carrying amount of the long-term notes receivable from ARO was $442.7 million and $452.9 million, respectively. The Shareholders’ Agreement prohibits the sale or transfer of the shareholder note to a third party, except in certain limited circumstances. The notes receivable may be reduced by future Company obligations to the joint venture. During the year ended December 31, 2020, we recorded $10.2 million of employee benefit obligations against our long-term notes receivable from ARO. Interest is recognized as interest income in our consolidated statement of operations and totaled $18.3 million for the year ended December 31, 2020 and $16.8 million for the period from April 11, 2019 through December 31, 2019. Interest amounts due were collected prior to the end of the year and we had no interest receivable from ARO as of December 31, 2020 or 2019.

Maximum Exposure to Loss

The following summarizes the total assets and liabilities as reflected in our 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 outstanding balance on our shareholder notes receivable; and (3) other receivables and contract assets related to services provided to ARO, partially offset by contract liabilities as well as payables for services received. Contract liabilities related to our Lease Agreements are subject to adjustment during the lease term. The per day bareboat charter amount in the lease agreements is subject to adjustment pursuant to the December Amendment based on actual performance of the respective rig.


	December 31, 2020		December 31, 2019
Total assets	$	585.2	$	623.5
Less: total liabilities	30.9		.7
Maximum exposure to loss	$	554.3	$	622.8

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6. FAIR VALUE MEASUREMENTS

The following fair value hierarchy table categorizes information regarding our financial assets and liabilities measured at fair value on a recurring basis (in millions):


	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
As of December 31, 2020
Supplemental executive retirement plan assets	$	22.6	$	—	$	—	$	22.6

Total financial assets	$	22.6	$	—	$	—	$	22.6
As of December 31, 2019
Supplemental executive retirement plan assets	$	26.0	$	—	$	—	$	26.0
Derivatives, net	—		5.4		—		5.4
Total financial assets	$	26.0	$	5.4	$	—	$	31.4

Supplemental Executive Retirement Plan Assets

Our Valaris supplemental executive retirement plans (the "SERPs") are non-qualified plans that provide eligible employees an opportunity to defer a portion of their compensation for use after retirement. The SERPs were frozen to the entry of new participants in November 2019 and to future compensation deferrals as of January 1, 2020. Assets held in a rabbi trust maintained for the SERP are marketable securities measured at fair value on a recurring basis using Level 1 inputs and were included in other assets, net, on our consolidated balance sheets as of December 31, 2020 and 2019. The fair value measurements of assets held in the SERP were based on quoted market prices. Net unrealized gains of $3.2 million and $5.0 million and losses of $700,000 from marketable securities held in our SERP were included in other, net, in our consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018, respectively.

Derivatives

As of December 31, 2020, we had no derivative contracts outstanding See "Note 9 - Derivative Instruments" for additional information on the impact of the Chapter 11 Cases to our derivatives. Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2019. See "Note 9 - Derivative Instruments" for additional information on our derivatives, including a description of our foreign currency hedging activities and related methodologies used to manage foreign currency exchange rate risk. The fair value measurements of our derivatives were based on market prices that are generally observable for similar assets or liabilities at commonly quoted intervals.

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Other Financial Instruments

The carrying values and estimated fair values of our debt instruments were as follows (in millions):


	Subject to Compromise (1)
	December 31, 2020				December 31, 2019
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
6.875% Senior notes due 2020	$	122.9	$	8.6	$	124.8	$	117.3
4.70% Senior notes due 2021	100.7		4.5		113.2		95.5
4.875% Senior notes due 2022	620.8		32.9		599.2		460.5
3.00% Exchangeable senior notes due 2024 (2)	849.5		76.5		699.0		607.4
4.50% Senior notes due 2024	303.4		13.7		302.0		167.2
4.75% Senior notes due 2024	318.6		18.8		276.5		201.4
8.00% Senior notes due 2024	292.3		12.9		295.7		181.7
5.20% Senior notes due 2025	333.7		12.7		331.7		186.7
7.375% Senior notes due 2025	360.8		20.9		329.2		218.6
7.75% Senior notes due 2026	1,000.0		44.0		987.1		575.1
7.20% Debentures due 2027	112.1		5.7		111.7		70.0
7.875% Senior notes due 2040	300.0		21.0		373.3		153.5
5.40% Senior notes due 2042	400.0		23.6		262.8		194.4
5.75% Senior notes due 2044	1,000.5		38.0		973.3		450.0
5.85% Senior notes due 2044	400.0		26.0		268.8		194.8
Amounts borrowed under revolving credit facility (3)	581.0		581.0		—		—
Total debt	$	7,096.3	$	940.8	$	6,048.3	$	3,874.1
Less : Liabilities Subject to Compromise	7,096.3		940.8		—		—
Less: current maturities	—		—		124.8		—
Total long-term debt	$	—	$	—	$	5,923.5	$	3,874.1

(1) The commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under our Senior Notes and revolving credit facility. Any efforts to enforce payment obligations under the Senior Notes and revolving credit facility, including any rights to require the repurchase by the Company of the 2024 Convertible Notes (as defined below) upon the NYSE delisting of the Class A ordinary shares, are automatically stayed as a result of the filing of the Chapter 11 Cases. The carrying amounts above represent the aggregate principal amount of Senior Notes outstanding as well as outstanding borrowings under our revolving credit facility as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. We discontinued accruing interest on our indebtedness following the Petition Date and all accrued interest as of the Petition Date is classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. Additionally, we incurred a net non-cash charge of $447.9 million to write off any unamortized debt discounts, premiums and issuance costs, including the amounts related to the 2024 Convertible Notes discussed below, which is included in Reorganization Items, net on our Consolidated Statement of Operations for the year ended December 31, 2020. See "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" for additional information.

(2) Our 2024 Convertible Notes are exchangeable into cash, our Class A ordinary shares or a combination thereof. The 2024 Convertible Notes were separated, at issuance, into their liability and equity components on our Consolidated Balance Sheet. The equity component was initially recorded to additional paid-in capital and as a debt discount and the discount was being amortized to interest expense over the life of the instrument. As discussed above, the carrying amount at December 31, 2020 represents the aggregate

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principal amount of these notes as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. We discontinued accruing interest on these notes as of the Petition Date. Additionally, we incurred a net non-cash charge of $128.8 million to write off $119.5 million of unamortized debt discount and $9.3 million of unamortized debt issuance costs related to these notes, which is included in Reorganization Items, net on our Consolidated Statement of Operations for the year ended December 31, 2020. The equity component is $220.0 million at December 31, 2020 and remains in Additional Paid-Capital.

(3) In addition to the amount borrowed above, we had $27.0 million in undrawn letters of credit issued under the revolving credit facility.

While the revolving credit facility has not been terminated, no further borrowings are permitted. As discussed above, the carrying amount at December 31, 2020 represents the outstanding borrowings as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. We discontinued accruing interest on the revolving credit facility as of the Petition Date and wrote off any unamortized debt issuance costs.

The estimated fair values of our senior notes and debentures were determined using quoted market prices, which are level 1 inputs. The estimated fair values of our cash and cash equivalents, accounts receivable, notes receivable, trade payables and other liabilities approximated their carrying values as of December 31, 2020 and 2019.

7. PROPERTY AND EQUIPMENT

Property and equipment as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020		2019
Drilling rigs and equipment	$	12,584.4	$	17,714.0
Work-in-progress	446.1		473.6
Other	178.8		206.2
	$	13,209.3	$	18,393.8

Drilling rigs and equipment as of December 31, 2020 decreased by $5.1 billion, or 29%, as compared to the prior period primarily due to impairments and sales of certain assets in our fleet.

Work-in-progress as of December 31, 2020 and 2019 primarily consisted of approximately $418 million related to the construction of ultra-deepwater drillships VALARIS DS-13 and VALARIS DS-14.

Impairment of Long-Lived Assets

During the year ended December 31, 2020, 2019 and 2018, we recorded an aggregate pre-tax, non-cash impairment with respect to certain floaters, jackups and spare equipment of $3.6 billion, $98.4 million and $40.3 million which is included in loss on impairment in our Consolidated Statements of Operations.

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 were determined not to be recoverable, we recorded an impairment for the difference between their fair values and carrying values.

During the first quarter of 2020, the COVID-19 global pandemic and the response thereto negatively impacted the macro-economic environment and global economy. Global oil demand fell sharply at the same time

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global oil supply increased as a result of certain oil producers competing for market share which lead to a supply glut. As a consequence, Brent crude oil fell from around $60 per barrel at year-end 2019 to around $20 per barrel as of mid-April 2020. These adverse changes and impacts to our customer's capital expenditure plans in the first quarter resulted in further deterioration in our forecasted day rates and utilization for the remainder of 2020 and beyond. As a result, we concluded that a triggering event had occurred and we performed a fleet-wide recoverability test. We determined that our estimated undiscounted cash flows were not sufficient to recover the carrying values of certain rigs and concluded such were impaired as of March 31, 2020.

Based on the asset impairment analysis performed as of March 31, 2020, we recorded a pre-tax, non-cash loss on impairment in the first quarter with respect to certain floaters, jackups and spare equipment totaling $2.8 billion. We measured the fair value of these assets to be $72.3 million at the time of impairment by applying either an income approach, using projected discounted cash flows or estimated scrap value. 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 at that time, both of which had been impacted by the adverse changes in the business environment observed during the first quarter.

During the second quarter of 2020, given the anticipated sustained market impacts arising from the decline in oil price and demand late in the first quarter, we revised our long-term operating assumptions which resulted in a triggering event for purposes of evaluating impairment and we performed a fleet-wide recoverability test. As a result, we recorded a pre-tax, non-cash impairment with respect to two floaters and spare equipment totaling $817.3 million. We measured the fair value of these assets to be $69.0 million at the time of impairment by applying an income approach or estimated scrap value. These valuations were based on unobservable inputs that require significant judgments for which there is limited information including, in the case of the income approach, assumptions regarding future day rates, utilization, operating costs and capital requirements.

During 2019, together with the Rowan Transaction, and as a result of the evaluation of the strategy of the combined fleet, we determined that a triggering event occurred resulting in the performance of a fleet-wide recoverability test. We determined that estimated undiscounted cash flows were sufficient to cover the rigs carrying values and concluded that no impairments were necessary.

During 2018, we recognized a pre-tax, non-cash loss on impairment of $40.3 million related to one older non-core jack up rig. We concluded that a triggering event occurred due to the expiration of a legacy higher day rate contract resulting in the performance of a recoverability test. We determined that the estimated undiscounted cash flows over the remaining useful life of the rig were not sufficient to recover the rigs carrying value and concluded the rig was impaired as of December 31, 2018. We estimated the fair values of these rigs by applying an income approach, using projected discounted cash flows. These valuations were based on unobservable inputs that required significant judgments for which there was limited information, including assumptions regarding future day rates, utilization, operating costs and capital requirements. Forecasted day rates and utilization took into account market conditions and our anticipated business outlook.

Assets held-for-sale

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 DIP Credit Agreement, 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 older, lower-specification or non-core rigs. To this end, we continually assess our rig portfolio and actively work with our rig broker to market certain rigs.

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On a quarterly basis, we assess whether any rig meets the criteria established for held-for-sale classification on our balance sheet. All rigs 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.

During the second quarter of 2020, we classified the following rigs as held-for-sale: VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS DS-3, VALARIS DS-5, VALARIS DS-6 and VALARIS JU-105. The carrying value of these rigs was reduced to fair value, less costs to sell, based on their estimated sales price, and we recorded a pre-tax, non-cash loss on impairment totaling $15.0 million. These rigs were subsequently sold during the third quarter of 2020. During the third quarter of 2020, we classified VALARIS 8504, VALARIS JU-84 and VALARIS JU-88 as held-for-sale. The fair value, less costs to sell, based on each rig's estimated sales price, was in excess of the respective carrying value. As a result, we concluded that there was no impairment of these rigs. These rigs were sold during the fourth quarter of 2020. During the fourth quarter of 2020, we classified our Australia office building as held-for-sale. The fair value, less cost to sale, of this asset was determined to be in excess of the carrying value and we concluded that there was no impairment for the asset.

Our Australia office building had a remaining aggregate carrying value of $2.3 million and is included in other assets, net, on our Consolidated Balance Sheet as of December 31, 2020.

During the third quarter of 2019, we decided to retire VALARIS 5006 and classified the rig as held-for-sale. We recognized a pre-tax, non-cash loss on impairment of $88.2 million, which represented the difference between the carrying value of the rig and related assets and their estimated fair value, less costs to sell. We subsequently sold the rig during the fourth quarter of 2019. During the fourth quarter of 2019, we classified VALARIS 6002, VALARIS JU-68 and VALARIS JU-70 as held-for-sale. We recognized a pre-tax impairment charge of $10.2 million for the VALARIS JU-70. VALARIS 6002 and VALARIS JU-68 were subsequently sold in the first quarter of 2020 and VALARIS JU-70 was sold in the second quarter of 2020.

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8. DEBT

The carrying value of our debt as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020(1)		2019
6.875% Senior notes due 2020	$	122.9	$	124.8
4.70% Senior notes due 2021	100.7		113.2
4.875% Senior notes due 2022(2)	620.8		599.2
3.00% Exchangeable senior notes due 2024	849.5		699.0
4.50% Senior notes due 2024	303.4		302.0
4.75% Senior notes due 2024(2)	318.6		276.5
8.00% Senior notes due 2024	292.3		295.7
5.20% Senior notes due 2025	333.7		331.7
7.375% Senior notes due 2025(2)	360.8		329.2
7.75% Senior notes due 2026	1,000.0		987.1
7.20% Debentures due 2027	112.1		111.7
7.875% Senior notes due 2040	300.0		373.3
5.40% Senior notes due 2042(2)	400.0		262.8
5.75% Senior notes due 2044	1,000.5		973.3
5.85% Senior notes due 2044(2)	400.0		268.8
Amounts drawn under the revolving credit facility (3)	581.0		—
Total debt	$	7,096.3	$	6,048.3
Less: Liabilities Subject to Compromise	7,096.3		—
Less: current maturities	—		124.8
Total long-term debt	$	—	$	5,923.5

(1) The carrying amounts above represent the aggregate principal amount of Senior Notes outstanding as well as outstanding borrowings under our revolving credit facility as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. We discontinued accruing interest on our indebtedness following the Petition Date and all accrued interest as of the Petition Date is classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. Additionally, we incurred a net non-cash charge of $447.9 million to write off any unamortized debt discounts, premiums and issuance costs, including the amounts related to the 2024 Convertible Notes discussed below, which is included in Reorganization Items, net on our Consolidated Statement of Operations for the year ended December 31, 2020. See below and "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" for additional information.

(2) These senior notes were acquired in the Rowan Transaction.

(3) In addition to the amount borrowed above, we had $27.0 million in undrawn letters of credit issued under the revolving credit facility.

The commencement of the Chapter 11 Cases constituted an event of default under our pre-petition indebtedness. Any efforts to enforce payment obligations under our Debt Instruments and other obligations of the Debtors are automatically stayed as a result of the filing of the Chapter 11 Cases and the holders' rights of enforcement in respect of the Debt Instruments are subject to the applicable provisions of the Bankruptcy Code. See “Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern” for additional details regarding the Chapter 11 Cases.

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On September 25, 2020, following approval by the Bankruptcy Court, the Debtors entered into the DIP Credit Agreement, by and among the Company and certain wholly owned subsidiaries of the Company, as borrowers, the lenders party thereto and Wilmington Savings Fund Society, FSB, as administrative agent and security trustee, in an aggregate amount not to exceed $500.0 million that will be used to finance, among other things, the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases and to pay certain fees, costs and expenses associated with the Chapter 11 Cases. For additional information related to the terms, covenants and restrictions under the DIP Credit Agreement, please See “Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern”.

As of December 31, 2020, we had no borrowings outstanding against our DIP Facility.

Senior Notes

As a result of the Rowan Transaction, we acquired the following senior notes issued by Rowan Companies, LLC (formerly Rowan Companies, Inc.) ("RCI") and guaranteed by Rowan: (1) $201.4 million in aggregate principal amount of 7.875% unsecured senior notes due 2019, which have been repaid in full, (2) $620.8 million in aggregate principal amount of 4.875% 2022 Notes (the "4.875% 2022 Notes"), (3) $398.1 million in aggregate principal amount of 4.75% 2024 Notes (the "4.75% 2024 Notes"), (4) $500.0 million in aggregate principal amount of 7.375% 2025 Notes (the "7.375% 2025 Notes"), (5) $400.0 million in aggregate principal amount of 2042 Notes (the "2042 Notes"), and (6) $400.0 million in aggregate principal amount of 5.85% 2044 Notes (the "5.85% 2044 Notes"). On February 3, 2020, Rowan and RCI transferred substantially all their assets on a consolidated basis to Valaris plc, Valaris plc became the obligor on the notes and Rowan and RCI were relieved of their obligations under the notes and the related indenture.

During 2017, we exchanged $332.0 million aggregate principal amount of unsecured 8.00% senior notes due 2024 (the “8 % 2024 Notes”) for certain amounts of our outstanding senior notes due 2019, 2020 and 2021. Interest on the 8% 2024 Notes is payable semiannually on January 31 and July 31 of each year.

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Debentures Due 2027

The Debentures and the indenture pursuant to which the Debentures were issued also contain customary events of default, including failure to pay principal or interest on the Debentures when due, among others. The indenture also contains certain restrictions, including, among others, restrictions on our ability and the ability of our subsidiaries to create or incur secured indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.

2024 Convertible Notes

In December 2016, Ensco Jersey Finance Limited, a wholly-owned subsidiary of Valaris plc, issued $849.5 million aggregate principal amount of 3.00% convertible senior notes due 2024 (the "2024 Convertible Notes") in a private offering. The 2024 Convertible Notes are fully and unconditionally guaranteed, on a senior, unsecured basis, by Valaris plc. Under the terms of our debt agreement, we have the option to settle our 2024 Convertible Notes in cash, shares or a combination thereof for the aggregate amount due upon conversion. However, the commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under the 2024 Convertible Notes. Any efforts to enforce payment obligations under the 2024 Convertible Notes, including any rights to require the repurchase by the Company of the 2024 Convertible Notes upon the NYSE delisting of the Class A ordinary shares, are automatically stayed as a result of the filing of the Chapter 11 Cases. During each respective reporting period that our average share price exceeds the exchange price, an assumed number of shares required to settle the conversion obligation in excess of the principal amount will be included in our denominator for the computation of diluted EPS using the treasury stock method. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for additional information regarding the impact to our EPS.

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The 2024 Convertible Notes were separated, at issuance, into their liability and equity components on our consolidated balance sheet. The equity component was initially recorded to additional paid-in capital and as a debt discount and the discount was being amortized to interest expense over the life of the instrument. The carrying amount of the liability component was initially calculated by measuring the estimated fair value of a similar liability that did not include an associated conversion feature. The carrying amount of the equity component representing the conversion feature was initially determined by deducting the fair value of the liability component from the principal amount of the 2024 Convertible Notes. The difference between the carrying amount of the liability and the principal amount has been amortized to interest expense over the term of the 2024 Convertible Notes, together with the coupon interest, resulting in an effective interest rate of approximately 8.00% per annum. As discussed above, the carrying amount of the 2024 Convertible Notes at December 31, 2020 represents the aggregate principal amount of these notes as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. The equity component is $220.0 million at December 31, 2020 and remains in Additional Paid-Capital. The equity component is not remeasured if we continue to meet certain conditions for equity classification.

The costs related to the issuance of the 2024 Convertible Notes were initially allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component were amortized to interest expense over the term of the notes and the issuance costs attributable to the equity component were recorded to additional paid-in capital on our consolidated balance sheet.

During the year ended December 31, 2020, 2019 and 2018, we recognized $16.1 million, $25.5 million, and $25.5 million, respectively, associated with coupon interest. Amortization of debt discount and issuance costs were $21.4 million, $32.5 million and $31.0 million for the years ended December 31, 2020, 2019 and 2018, respectively. We discontinued accruing interest on these notes as of the Petition Date. Additionally, we incurred a net non-cash charge of $128.8 million to write off $119.5 million of unamortized debt discount and $9.3 million of unamortized debt issuance costs related to these notes, which is included in Reorganization Items, net on our Consolidated Statement of Operations the year ended December 31, 2020.

As of December 31, 2020 and 2019, the 2024 Convertible Notes consist of the following (in millions):


Liability component:	2020		2019
Principal	$	849.5	$	849.5
Less: Unamortized debt discount and issuance costs	—		(150.5)
Net carrying amount (1)	$	849.5	$	699.0
Equity component, net	$	220.0	$	220.0

(1) The carrying amount at December 31, 2020 represents the aggregate principal amount of these notes as of the Petition Date and are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020.

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indebtedness, enter into certain sale/leaseback transactions and enter into certain merger or consolidation transactions.

The 2021 Notes, 4.875% 2022 Notes, 4.75% 2024 Notes, 8.00% 2024 Notes, 2024 Notes, 2025 Notes, 7.375% 2025 Notes, 2026 Notes, 2042 Notes, 5.85% 2044 Notes, Existing 2044 Notes, the Pride Notes, the Debentures and 2024 Convertible Notes" together are the "Senior Notes". The commencement of the Chapter 11 Cases on August 19, 2020, constituted an event of default under our Senior Notes.

Tender Offers and Open Market Repurchases

In early March 2020, we repurchased $12.8 million of our outstanding 4.70% senior notes due 2021 on the open market for an aggregate purchase price of $9.7 million, excluding accrued interest, with cash on hand. As a result of the transaction, we recognized a pre-tax gain of $3.1 million, net of discounts in other, net, in the consolidated statements of operations.

Concurrent with the issuance of the 2026 Notes in January 2018, we launched cash tender offers for up to $985.0 million aggregate principal amount of certain series of senior notes issued by us and Pride, our wholly-owned subsidiary, and as a result we repurchased $595.4 million of our senior notes. Subsequently, we issued a redemption notice for the remaining principal amount of the $55.0 million principal amount of the 8.5% senior notes due 2019 and repurchased $71.4 million principal amount of our senior notes due 2020. As a result of these transactions, we recognized a pre-tax loss from debt extinguishment of $19.0 million, net of discounts, premiums, debt issuance costs and commissions in other, net, in the consolidated statement of operations.

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Our tender offers and open market repurchases during the three-year period ended December 31, 2020 are summarized in the following table (in millions):


	Aggregate Principal Amount Repurchased		Aggregate Repurchase Price(1)
Year Ended December 31, 2020
4.70% Senior notes due 2021	$	12.8	$	9.7

Year Ended December 31, 2019
4.50% Senior notes due 2024	$	320.0	$	240.0
4.75% Senior notes due 2024	79.5		61.2
8.00% Senior notes due 2024	39.7		33.8
5.20% Senior notes due 2025	335.5		250.0
7.375% Senior notes due 2025	139.2		109.2
7.20% Senior notes due 2027	37.9		29.9
	$	951.8	$	724.1
Year Ended December 31, 2018
8.50% Senior notes due 2019	$	237.6	$	256.8
6.875% Senior notes due 2020	328.0		354.7
4.70% Senior notes due 2021	156.2		159.7
	$	721.8	$	771.2

(1) Excludes accrued interest paid to holders of the repurchased senior notes.

Revolving Credit Facility and DIP Facility

Effective upon closing of the Rowan Transaction, our revolving credit facility was $1.6 billion.

As of December 31, 2020, we had $581.0 million of borrowings outstanding under our revolving credit facility and $27.0 million of undrawn letters of credit. The outstanding borrowings as well as accrued interest as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. See "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern" for more information related to our Chapter 11 Cases to effect a comprehensive restructuring of our indebtedness.

On September 25, 2020, following approval by the Bankruptcy Court, the Debtors entered into the DIP Credit Agreement in an aggregate amount not to exceed $500.0 million. Borrowings on the DIP Facility will be used to finance, among other things, the ongoing general corporate needs of the Debtors during the course of the Chapter 11 Cases and to pay certain fees, costs and expenses associated with the Debtors’ Chapter 11 Cases.

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Maturities


													Subject to Compromise(2)
Senior Notes(2)	Original Principal		2016 Tenders, Repurchases and Equity Exchange		2017 Exchange Offers and Repurchases		2018 Tender Offers, Redemption and Debt Issuance		2019 Tender Offers and Acquired Debt		2020 Open Market Repurchase		Remaining Principal
6.875% Senior Notes due 2020	$	900.0	$	(219.2)	$	(229.9)	$	(328.0)	$	—	$	—	$	122.9
4.70% Senior Notes due 2021	1,500.0		(817.0)		(413.3)		(156.2)		—		(12.8)		100.7
4.875% Senior notes due 2022(1)	—		—		—		—		620.8		—		620.8
3.00% Exchangeable senior notes due 2024	849.5		—		—		—		—		—		849.5
4.50% Senior notes due 2024	625.0		(1.6)		—		—		(320.0)		—		303.4
4.75% Senior notes due 2024(1)	—		—		—		—		318.6		—		318.6
8.00% Senior Notes due 2024	—		—		332.0		—		(39.7)		—		292.3
5.20% Senior Notes due 2025	700.0		(30.8)		—		—		(335.5)		—		333.7
7.375% Senior Notes due 2025(1)	—		—		—		—		360.8		—		360.8
7.75% Senior Notes due 2026	—		—		—		1,000.0		—		—		1,000.0
7.20% Debentures due 2027	150.0		—		—		—		(37.9)		—		112.1
7.875% Senior notes due 2040	300.0		—		—		—		—		—		300.0
5.40% Senior notes due 2042 (1)	—		—		—		—		400.0		—		400.0
5.75% Senior notes due 2044	1,025.0		(24.5)		—		—		—		—		1,000.5
5.85% Senior notes due 2044 (1)	—		—		—		—		400.0		—		400.0
Total	$	6,049.5	$	(1,093.1)	$	(311.2)	$	515.8	$	1,367.1	$	(12.8)	$	6,515.3

(1)These senior notes were acquired in the Rowan Transaction.

(2)The $6.5 billion aggregate principal amount of Senior Notes outstanding as well as associated $201.9 million in accrued interest as of the Petition Date are classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020. The maturity dates represent the maturity dates per the debt agreements; however, we are in default on these senior notes and are currently in chapter 11 proceedings. See "Senior Notes" above and "Note 2– Chapter 11 Proceedings and Ability to Continue as a Going Concern” for additional information for additional details regarding Chapter 11 Cases.

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Interest Expense

Interest expense totaled $290.6 million, $428.3 million and $282.7 million for the years ended December 31, 2020, 2019 and 2018, respectively, which was net of capitalized interest of $1.3 million, $20.9 million and $62.6 million associated with newbuild rig construction and other capital projects. The contractual interest expense on our unsecured senior notes and revolving credit facility is in excess of recorded interest expense by $140.7 million for the year ended December 31, 2020. This excess contractual interest is not included as interest expense on the Consolidated Statements of Operations for the year ended December 31, 2020, as the Company has discontinued accruing interest on the unsecured senior notes and revolving credit facility subsequent to the Petition Date. We discontinued making interest payments on our unsecured senior notes beginning in June 2020.

9. DERIVATIVE INSTRUMENTS

Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues 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. These transactions are remeasured in U.S. dollars based on a combination of both current and historical exchange rates. We previously used derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk.

The commencement of the Chapter 11 Cases constituted a termination event with respect to the Company’s derivative instruments, which permits the counterparties of our derivative instruments to terminate their outstanding contracts. The exercise of these termination rights are not stayed under the Bankruptcy Code. During September 2020, the counterparties to the Company’s derivative instruments elected to terminate their outstanding derivatives with us for an aggregate settlement of $3.6 million which was recorded as a gain in contract drilling expense in our Consolidated Statement of Operations for the year ended December 31, 2020 related to this termination.

All derivatives were recorded on our consolidated balance sheets at fair value. Derivatives subject to legally enforceable master netting agreements were not offset on our consolidated balance sheets. Accounting for the gains and losses resulting from changes in the fair value of derivatives depended on the use of the derivative and whether it qualified for hedge accounting. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" for additional information on our accounting policy for derivatives. As of December 31, 2019, our consolidated balance sheets included net foreign currency derivative assets of $5.4 million. See "Note 6 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

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Derivatives recorded at fair value on our consolidated balance sheet as of December 31, 2019, consisted of the following (in millions):


	Derivative Assets		Derivative Liabilities
	2019		2019
Derivatives Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	$	4.2	$	.7
Foreign currency forward contracts - non-current(2)	.8		—
	5.0		.7
Derivatives not Designated as Hedging Instruments
Foreign currency forward contracts - current(1)	1.3		.2
Total	$	6.3	$	.9

(1)Derivative assets and liabilities that have maturity dates equal to or less than 12 months from the respective balance sheet date were included in other current assets and accrued liabilities and other, respectively, on our consolidated balance sheet.

(2)Derivative assets and liabilities that have maturity dates greater than 12 months from the respective balance sheet date were included in other assets and other liabilities, respectively, on our consolidated balance sheet.

We have historically utilized cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk associated with contract drilling expenses and capital expenditures denominated in various currencies.

Gains and losses, net of tax, on derivatives designated as cash flow hedges included in our consolidated statements of operations and comprehensive loss for each of the years in the three-year period ended December 31, 2020 were as follows (in millions):


	Gain (Loss) Recognized in Other Comprehensive Income ("OCI") on Derivatives (Effective Portion)						(Gain) Loss Reclassified from AOCI into Income (Effective Portion)(1)						Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion and Amount Excluded from Effectiveness Testing)(2)
	2020		2019		2018		2020		2019		2018		2020		2019		2018
Interest rate lock contracts(3)	$	—	$	—	$	—	$	—	$	1.9	$	.2	$	—	$	—	$	—
Foreign currency forward contracts(4)	(5.4)		1.6		(9.7)		(11.6)		6.4		(1.2)		—		—		(1.9)
Total	$	(5.4)	$	1.6	$	(9.7)	$	(11.6)	$	8.3	$	(1.0)	$	—	$	—	$	(1.9)

(1)Changes in the fair value of cash flow hedges are recorded in AOCI. Amounts recorded in AOCI associated with cash flow hedges are subsequently reclassified into contract drilling, depreciation or interest expense as earnings are affected by the underlying hedged forecasted transaction.

(2)Gains and losses recognized in income for amounts excluded from effectiveness testing were included in other, net, in our consolidated statements of operations. As a result of our adoption of Update 2017-12 on January 1, 2019, ineffectiveness is no longer separately measured and recognized.

(3)Losses on interest rate lock derivatives reclassified from AOCI into income were included in interest expense, net, in our consolidated statements of operations.

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(4)During the year ended December 31, 2020, $2.0 million of losses were reclassified from AOCI into contract drilling expense and $13.6 million of gains were reclassified from AOCI into depreciation expense in our consolidated statement of operations. During the year ended December 31, 2019, $7.3 million of losses were reclassified from AOCI into contract drilling expense and $0.9 million of gains were reclassified from AOCI into depreciation expense in our consolidated statement of operations. During the year ended December 31, 2018, $400,000 of gains were reclassified from AOCI into contract drilling expense and $800,000 of gains were reclassified from AOCI into depreciation expense in our consolidated statement of operations.

We have net assets and liabilities denominated in numerous foreign currencies and use various methods to manage our exposure to foreign currency exchange rate risk. We predominantly structure our drilling contracts in U.S. dollars, which significantly reduces the portion of our cash flows and assets denominated in foreign currencies. Historically, we have occasionally entered into derivatives that hedged the fair value of recognized foreign currency denominated assets or liabilities but did not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally existed whereby changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. As of December 31, 2020, we did not have open derivative contracts to hedge against this risk.

Net losses of $0.2 million, $6.4 million and $11.8 million associated with our derivatives not designated as hedging instruments were included in other, net, in our consolidated statements of operations for the years ended December 31, 2020, 2019 and 2018, respectively.

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10. SHAREHOLDERS' EQUITY

Activity in our various shareholders' equity accounts for each of the years in the three-year period ended December 31, 2020 was as follows (in millions, except per share amounts):


	Shares	Par Value		Additional Paid-in Capital		Retained Earnings		AOCI		Treasury Shares		Non-controlling Interest
BALANCE, December 31, 2017	111.8	$	44.8	$	7,195.0	$	1,532.7	$	28.6	$	(69.0)	$	(2.1)
Net loss	—	—		—		(639.7)		—		—		3.1
Dividends paid ($0.16 per share)	—	—		—		(18.0)		—		—		—
Cumulative-effect reduction from adoption of ASU 2018-02	—	—		—		(.8)		.8		—		—
Distributions to noncontrolling interests	—	—		—		—		—		—		(3.6)
Shares issued under share-based compensation plans, net	3.4	1.4		(.6)		—		—		(1.3)		—
Repurchase of shares	—	—		—		—		—		(1.9)		—
Share-based compensation cost	—	—		30.6		—		—		—		—
Net other comprehensive loss	—	—		—		—		(11.2)		—		—
BALANCE, December 31, 2018	115.2	46.2		7,225.0		874.2		18.2		(72.2)		(2.6)
Net loss	—	—		—		(198.0)		—		—		5.8
Dividends paid ($0.04 per share)	—	—		—		(4.5)		—		—		—
Equity issuance in connection with the Rowan Transaction	88.0	35.2		1,367.5		—		—		.1		—
Shares issued under share-based compensation plans, net	2.7	1.1		(1.3)		—		—		(.7)		—
Distributions to noncontrolling interests	—	—		—		—		—		—		(4.5)
Repurchase of shares	—	—		—		—		—		(4.5)		—
Equity issuance cost	—	—		(.6)		—		—		—		—
Share-based compensation cost	—	—		37.2		—		—		—		—
Net changes in pension and other postretirement benefits	—	—		—		—		(21.7)		—		—
Net other comprehensive income	—	—		—		—		9.7		—		—
BALANCE, December 31, 2019	205.9	82.5		8,627.8		671.7		6.2		(77.3)		(1.3)
Net loss	—	—		—		(4,855.5)		—		—		(2.1)
Shares issued under share-based compensation plans, net	.2	.1		(1.9)		—		—		2.0		—
Repurchase of shares	—	—		—		—		—		(.9)		—
Share-based compensation cost	—	—		21.2		—		—		—		—
Net changes in pension and other postretirement benefits	—	—		—		—		(76.5)		—		—
Purchase of noncontrolling interests	—	—		(7.2)		—		—		—		—
Distributions to noncontrolling interests	—	—		—		—		—		—		(.9)
Net other comprehensive loss	—	—		—		—		(17.6)		—		—
BALANCE, December 31, 2020	206.1	$	82.6	$	8,639.9	$	(4,183.8)	$	(87.9)	$	(76.2)	$	(4.3)

In connection with the Rowan Transaction on April 11, 2019, we issued 88.3 million Class A ordinary shares with an aggregate value of $1.4 billion. See "Note 4 - Rowan Transaction" for additional information.

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As a U.K. public limited company subject to the U.K. Companies Act 2006, we cannot issue new shares (other than in limited circumstances) without being authorized by our shareholders. At our 2020 annual general meeting held on June 15, 2020, our shareholders authorized the allotment of shares up to an aggregate nominal amount of $26,431,699 (or up to an aggregate nominal amount equal to $52,863,399 in connection with an offer by way of a rights issue or other similar pre-emptive issue), representing approximately 33.3% and 66.6% respectively of the issued share capital (excluding treasury shares) of Valaris plc as of 20 April 2020.

Under English law, we are only able to declare dividends and return funds to our shareholders out of the accumulated distributable reserves on our statutory balance sheet. The declaration and amount of future dividends is at the discretion of our Board of Directors and will depend on our profitability, liquidity, financial condition, market outlook, reinvestment opportunities, capital requirements and other factors and restrictions our Board of Directors deems relevant. There can be no assurance that we will pay a dividend in the future.

Our shareholders approved a repurchase program at our annual shareholder meeting held in May 2018. Subject to certain provisions under English law, including the requirement for Valaris plc to have sufficient distributable reserves and for the Board to conclude that a repurchase is in the best interest of Valaris plc taking into account the interests of relevant stakeholders, we may repurchase shares up to a maximum of $500.0 million in the aggregate from one or more financial intermediaries under the program, but in no case more than 16.3 million shares. The program terminates in May 2023. As of December 31, 2020, there had been no share repurchases under the repurchase program. Our DIP Facility only permits the repurchase of shares of our common stock in certain circumstances and the repurchase of shares would likely require approval of the bankruptcy court. We do not currently expect to make repurchases under the program whilst Valaris plc remains subject to chapter 11 bankruptcy proceedings.

11. SHARE BASED COMPENSATION

In May 2018, our shareholders approved the 2018 Long-Term Incentive Plan (the "2018 LTIP") effective January 1, 2018, to provide for the issuance of non-vested share awards, share option awards and performance awards (collectively "awards"). The 2018 LTIP is similar to and replaces the Company's previously adopted 2012 Long-Term Incentive Plan (the “2012 LTIP”). No further awards will be granted under the 2012 LTIP. Under the 2018 LTIP, 10.5 million shares were reserved for issuance as awards to officers, non-employee directors and key employees who are in a position to contribute materially to our growth, development and long-term success. In April 2020, the 2018 LTIP was amended to increase the number of shares authorized for issuance by 8.2 million. As of December 31, 2020, there were 12.2 million shares available for issuance as awards under the 2018 LTIP. Awards may be satisfied by newly issued shares, including shares held by a subsidiary or affiliated entity, or by delivery of shares held in an affiliated employee benefit trust at the Company's discretion. Grants under the 2018 LTIP are subject to applicable bankruptcy law and settlement of vested share awards and cash-settled awards (each as defined below) held by insiders has been delayed until the Company’s emergence from chapter 11, at which point, such awards are expected to be cancelled unless the insider elects to have their award treated in accordance with the terms of the chapter 11 plan.

In connection with the Rowan Transaction, we assumed the Amended and Restated 2013 Rowan Companies plc Incentive Plan (the "Rowan LTIP") and the non-vested share unit awards, options and share appreciation rights outstanding thereunder. As of December 31, 2020, there were 2.6 million shares remaining available for future issuance as awards under the Rowan LTIP which may be granted to employees and other service providers who were not employed or engaged with Valaris prior to the Rowan Transaction.

In connection with the Atwood Merger, we assumed Atwood’s Amended and Restated 2007 Long-Term Incentive Plan (the “Atwood LTIP”, and together with the 2018 LTIP and the Rowan LTIP, the "LTIP Plans") and the options outstanding thereunder. As of December 31, 2020, there were approximately 200,000 shares remaining available for future issuance as awards under the Atwood LTIP, which may be granted to employees and other service providers who were not employed or engaged with Valaris prior to the Atwood Merger.

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Non-Vested Share Awards, Cash-Settled Awards and Non-employee Director Deferred Awards

Grants of share awards and share units (collectively "share awards") and share units to be settled in cash ("cash-settled awards"), generally vest at rates of 20% or 33% per year, as determined by a committee of the Board of Directors at the time of grant. Additionally, non-employee directors may annually elect to receive deferred share awards. Deferred share awards vest at the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant but are not settled until the director terminates service from the Board. Deferred share awards are settled in cash, shares or a combination thereof at the discretion of the Compensation Committee.

During 2020, 66,000 cash-settled awards were granted while 1.1 million share unit awards were granted to our employees and non-employee directors pursuant to the LTIP Plans. The 2020 share awards issued to certain executive officers were subsequently forfeited in conjunction with the chapter 11 proceedings. Our non-vested share awards have voting and dividend rights effective on the date of grant, and our non-vested share units have dividend rights effective on the date of grant. Compensation expense for share awards is measured at fair value on the date of grant and recognized on a straight-line basis over the requisite service period (usually the vesting period). Compensation expense for cash-settled awards is remeasured each quarter with a cumulative adjustment to compensation cost during the period based on changes in our share price. Our compensation cost is reduced for forfeited awards in the period in which the forfeitures occur.

The following table summarizes share award and cash-settled award compensation expense recognized during each of the years in the three-year period ended December 31, 2020 (in millions):


	2020		2019		2018
Contract drilling	$	10.7	$	22.1	$	18.9
General and administrative	9.2		17.4		14.5
	19.9		39.5		33.4
Tax benefit	(1.8)		(2.5)		(2.8)
Total	$	18.1	$	37.0	$	30.6

The following table summarizes the value of share awards and cash-settled awards granted and vested during each of the years in the three-year period ended December 31, 2020:


	Share Awards						Cash-Settled Awards
	2020		2019		2018		2020		2019		2018
Weighted-average grant-date fair value of share awards granted (per share)	$	3.07	$	11.50	$	24.62	$	0.75	$	—	$	21.35
Total fair value of share awards vested during the period (in millions)	$	3.26	$	17.70	$	7.50	$	0.22	$	3.50	$	9.90

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The following table summarizes share awards and cash-settled awards activity for the year ended December 31, 2020 (shares in thousands):


	Share Awards			Cash-settled Awards
	Awards	Weighted-Average Grant-Date Fair Value		Awards	Weighted-Average Grant-Date Fair Value
Share awards and cash-settled awards as of December 31, 2019	6,433	$	19.89	697	$	46.28
Granted	1,118	3.07		66	0.75
Vested	(2,473)	16.55		(342)	29.59
Forfeited	(2,096)	8.15		(110)	28.01
Share awards and cash-settled awards as of December 31, 2020	2,982	$	16.40	311	$	22.74

As of December 31, 2020, there was $30.4 million of total unrecognized compensation cost related to share awards, which has a weighted-average remaining vesting period of 1.4 years.

Share Appreciation Rights

Share Appreciation Rights ("SARs") granted to employees generally become exercisable in 33% increments over a three-year period and, to the extent not exercised, expire on the tenth anniversary of the date of grant. The exercise price of SARs granted under the Rowan LTIP equals the excess of the market value of the underlying shares on the date of exercise over the market value of the shares on date of grant multiplied by the number of shares covered by the SAR. The Company has accounted for SARs as equity awards. As of December 31, 2020, SARs granted to purchase 426,049 shares with a weighted-average exercise price of $53.23 were outstanding under the Rowan LTIP. No SARs have been granted since 2013 under the Rowan LTIP, and there was no unrecognized compensation cost related to SARs as of December 31, 2020.

Share Option Awards

Share option awards ("options") granted to employees generally become exercisable in 25% increments over a four-year period or 33% increments over a three-year period or 100% after a four-year period and, to the extent not exercised, expire on either the seventh or tenth anniversary of the date of grant. The exercise price of options granted under the 2018 LTIP equals the market value of the underlying shares on the date of grant. As of December 31, 2020, options granted to purchase 318,377 shares with a weighted-average exercise price of $44.94 were outstanding under the Company LTIPs. Excluding options assumed under the Atwood LTIP and Rowan LTIP, no options have been granted since 2011, and there was no unrecognized compensation cost related to options as of December 31, 2020.

Performance Awards

Under the Company LTIPs, performance awards may be issued to our senior executive officers. The 2019 performance awards are subject to achievement of specified performance goals based on both relative and absolute total shareholder return ("TSR"), while the 2018 performance awards are subject to achievement of specified performance goals based on relative TSR and relative return on capital employed ("ROCE") as compared to a specified peer group. The 2020 performance awards were forfeited in exchange for cash-based retention awards.

The performance goals are determined by a committee of the Board of Directors. Awards are payable in cash upon attainment of relative performance goals.

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Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. Our performance awards granted during 2018 and 2019 are classified as liability awards, all with compensation expense recognized over the requisite service period. The estimated probable outcome of attainment of the specified performance goals is based primarily on relative performance over the requisite performance period. Any subsequent changes in this estimate are recognized as a cumulative adjustment to compensation cost in the period in which the change in estimate occurs.

The aggregate grant-date fair value of performance awards granted during 2019 and 2018 was $6.7 million. The 2020 performance awards were subsequently forfeited in conjunction with the Chapter 11 Cases. The aggregate fair value of performance awards vested during 2020, 2019 and 2018 totaled $5.2 million, $2.2 million and $0.7 million, respectively.

During the years ended December 31, 2020, 2019 and 2018, we recognized $1.0 million, $3.2 million and $8.2 million of compensation expense for performance awards, respectively, which was included in general and administrative expense in our consolidated statements of operations.

Savings Plans

We have savings plans, (the Ensco Savings Plan, the Ensco Multinational Savings Plan, the Ensco Limited Retirement Plan and the frozen RDIS International Savings Plan), which cover eligible employees as defined within each plan. During 2020, the plan assets of the legacy Rowan savings plans (the Rowan Companies, Inc. Savings & Investment Plan and the Rowan Drilling UK Pension Scheme) were transferred to the Ensco Savings Plan and the Ensco Limited Retirement Plan, respectively. The Ensco Savings Plan includes a 401(k) savings plan feature, which allows eligible employees to make tax-deferred contributions to the plans. The Ensco Limited Retirement Plan allows eligible employees to make tax-deferred contributions to the plan. Contributions made to the Ensco Multinational Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements.

Historically, we made matching cash contributions to the plans. The legacy Ensco plans previously matched 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary, where the legacy Rowan plans also provided up to a 5% match of eligible salary; however, depending on the plan and the tier, the match percentage could vary. Matching contributions totaled $8.8 million, $18.7 million and $14.4 million for the years ended December 31, 2020, 2019 and 2018, respectively. Effective August 1, 2020, in light of the current economic environment, we suspended employer matching contributions for the Ensco Savings Plan and the Ensco Multinational Savings Plan. In addition, effective December 1, 2020, the matching contributions in the Ensco Limited Retirement Plan were reduced. Employer contributions may be reinstated in future periods at the discretion of the Board of Directors.

As of January 1, 2019, the plans were modified such that all previous, current and future employer contributions become 100% vested.

12. PENSION AND OTHER POST- RETIREMENT BENEFITS

Prior to the Rowan Transaction, Rowan established various defined-benefit pension plans and a post-retirement health and life insurance plan that provide benefits upon retirement for certain full-time employees. The defined-benefit pension plans include: (1) the Rowan Pension Plan; (2) Restoration Plan of Rowan Companies, Inc. (the “Rowan SERP”); (3) the Norway Onshore Plan; and (4) the Norway Offshore Plan. The Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc. (the “Retiree Medical Plan”) provides post-retirement health and life insurance benefits. On November 27, 2017, Rowan purchased annuities to cover post-65 retiree medical benefits for current retirees as of the purchase date. The annuity purchase settled post-65 medical benefits (i.e., Health Reimbursement Account, or “HRA”, amounts) for affected participants, with the insurer taking responsibility for all benefit payments on and after January 1, 2019.

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As a result of the Rowan Transaction, we assumed these plans and obligations, which were remeasured as of the Transaction Date. Each of the plans has a benefit obligation that exceeds the fair value of plan assets. As of the Transaction Date, the net projected benefit obligations totaled $239.3 million, of which $19.2 million was classified as current. The current and non-current portions of the net benefit obligations are included in accrued liabilities and other liabilities in our consolidated balance sheet, respectively. The most significant of the assumed plans is the Rowan Pension Plan, which had a net projected benefit obligation of $202.1 million. Prior to the Transaction Date, Rowan amended the Rowan Pension Plan to freeze the plan as to any future benefit accruals. As a result, eligible employees no longer receive pay credits in the pension plan and newly hired employees are not eligible to participate in the pension plan.

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The following table presents the changes in benefit obligations and plan assets for the year ended December 31, 2020 and 2019 and the funded status and weighted-average assumptions used to determine the benefit obligation at year end (dollars in millions):


	2020								2019
	Pension Benefits			Other Benefits			Total		Pension Benefits			Other Benefits			Total
Projected benefit obligation:
Balance, January 1 and April 11	$	832.4		$	16.1		$	848.5	$	800.1		$	15.9		$	816.0
Interest cost	24.9			0.5			25.4		21.3			0.4			21.7
Service cost	0.1			—			0.1		1.5			—			1.5
Actuarial loss (gain)	97.8			(0.1)			97.7		43.8			0.2			44.0
Plan settlements	(6.6)			—			(6.6)		—			—			—
Plan curtailments	(3.3)			—			(3.3)		—			—			—
Benefits paid	(58.6)			(0.6)			(59.2)		(34.1)			(0.4)			(34.5)
Foreign currency adjustments	—			—			—		(0.2)			—			(0.2)
Balance, December 31	$	886.7		$	15.9		$	902.6	$	832.4		$	16.1		$	848.5

Plan assets
Fair value, January 1 and April 11	$	598.9		$	—		$	598.9	$	576.8		$	—		$	576.8
Actual return	57.9			—			57.9		43.6			—			43.6
Employer contributions	11.5			—			11.5		12.8			—			12.8
Plan settlements	(6.6)			—			(6.6)		—			—			—
Benefits paid	(58.6)			—			(58.6)		(34.1)			—			(34.1)
Foreign currency adjustments	—			—			—		(0.2)			—			(0.2)
Fair value, December 31	$	603.1		$	—		$	603.1	$	598.9		—			$	598.9
Net benefit liabilities	$	283.6		$	15.9		$	299.5	$	233.5		$	16.1		$	249.6

Amounts recognized in consolidated balance sheet:
Accrued liabilities	$	(1.5)		$	(1.4)		$	(2.9)	$	(1.4)		$	(1.5)		$	(2.9)
Other liabilities (long-term)	(282.1)			(14.5)			(296.6)		(232.1)			(14.6)			(246.7)
Net benefit liabilities	$	(283.6)		$	(15.9)		$	(299.5)	$	(233.5)		$	(16.1)		$	(249.6)

Accumulated contributions in excess of (less than) net periodic benefit cost	$	(179.6)		$	(15.8)		$	(195.4)	$	(206.2)		$	(15.9)		$	(222.1)

Amounts not yet reflected in net periodic benefit cost:
Actuarial loss	$	(104.0)		$	(0.1)		$	(104.1)	$	(27.3)		$	(0.2)		$	(27.5)
Total accumulated other comprehensive loss	(104.0)			(0.1)			(104.1)		(27.3)			(0.2)			(27.5)
Net benefit liabilities	$	(283.6)		$	(15.9)		$	(299.5)	$	(233.5)		$	(16.1)		$	(249.6)

Weighted-average assumptions:
Discount rate	2.30		%	2.19		%			3.16		%	3.06		%
Cash balance interest credit rate	2.94		%	N/A					3.29		%	N/A
Rate of compensation increase	N/A			N/A					N/A			N/A

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The unfunded obligation increased by $49.9 million. In addition to the expected year-to-year changes, the increase was primarily attributable to a decline in the discount rate and the impact of updated census data. This was partially offset by higher than expected return on plan assets and employer contributions of $11.5 million.

The projected benefit obligations for pension benefits in the preceding table reflect the actuarial present value of benefits accrued based on services rendered to date and include the estimated effect of future salary increases.

The accumulated benefit obligations, which are presented below for all plans in the aggregate at December 31, 2020 and 2019, are based on services rendered to date, but exclude the effect of future salary increases (in millions):


	2020		2019
Accumulated benefit obligation	$	902.6	$	844.3

The components of net periodic pension, retiree medical cost and the weighted-average assumptions used to determine net periodic pension and retiree medical cost were as follows (dollars in millions):


	Year Ended December 31, 2020			April 11, 2019 - December 31, 2019
Service cost (1)	$	.1		$	1.5
Interest cost (2)	25.4			21.3
Expected return on plan assets (2)	(36.5)			(27.1)
Curtailment gain recognized (2)	(3.3)			—
Settlement gain recognized (2)	(.3)			—
Net periodic pension and retiree medical cost (income)	$	(14.6)		$	(4.3)
Discount rate	3.16		%	3.82		%
Expected return on assets	6.48		%	6.70		%
Cash balance interest credit rate	3.29		%	3.29		%

(1) Included in contract drilling and general and administrative expense in our consolidated statements of operations.

(2) Included in other, net, in our consolidated statements of operations.

The pension plans' investment objectives for fund assets are: to achieve over the life of the plans a return equal to the plans' expected investment return or the inflation rate plus 3%, whichever is greater, to invest assets in a manner such that contributions are minimized and future assets are available to fund liabilities, to maintain liquidity sufficient to pay benefits when due, and to diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk. The plans employ several active managers with proven long-term records in their specific investment discipline.

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Target allocations among asset categories and the fair value of each category of plan assets as of December 31, 2020 and 2019, classified by level within the fair value hierarchy are presented below. The plans will reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses (dollars in millions):


	Target range	Total		Quoted prices in active markets for identical assets (Level 1)		Significant observable inputs (Level 2)		Significant unobservable inputs (Level 3)
December 31, 2020
Equities:	53% to 69%
U.S. large cap	22% to 28%	$	151.9	$	—	$	151.9	$	—
U.S. small cap	4% to 10%	48.1		—		48.1		—
International all cap	21% to 29%	158.5		—		158.5		—
International small cap	2% to 8%	37.0		—		37.0		—
Real estate equities	0% to 13%	53.5		—		53.5		—
Fixed income:	25% to 35%
Aggregate	9% to 19%	74.3		—		74.3		—
Core plus	9% to 19%	75.8		75.8		—		—
Cash and equivalents	0% to 10%	4.0		4.0		—		—
Group annuity contracts		—		—		—		—
Total		$	603.1	$	79.8	$	523.3	$	—

December 31, 2019
Equities:	53% to 69%
U.S. large cap	22% to 28%	$	148.9	$	—	$	148.9	$	—
U.S. small cap	4% to 10%	41.1		—		41.1		—
International all cap	21% to 29%	152.4		—		152.4		—
International small cap	2% to 8%	34.7		—		34.7		—
Real estate equities	0% to 13%	54.9		—		54.9		—
Fixed income:	25% to 35%
Aggregate	9% to 19%	76.7		—		76.7		—
Core plus	9% to 19%	77.6		77.6		—		—
Cash and equivalents	0% to 10%	6.5		6.5		—		—
Group annuity contracts		6.1		—		6.1		—
Total		$	598.9	$	84.1	$	514.8	$	—

Assets in the U.S. equities category include investments in common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) and may be held through separate accounts, commingled funds or an institutional mutual fund. Assets in the international equities category include investments in a broad range of international equity securities, including both developed and emerging markets, and may be held through a commingled or institutional mutual fund. The real estate category includes investments in pooled and commingled funds whose objectives are diversified equity investments in income-producing properties. Each real estate fund is intended to provide broad exposure to the real estate market by property type, geographic location and size and may invest internationally. Securities in both the aggregate and core plus fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds, and both categories target an average credit rating of “A” or better at all times. Individual securities in the aggregate fixed income category must be investment grade or above at the time of purchase, whereas securities in the core plus category may have a rating

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of “B” or above. Additionally, the core plus category may invest in non-U.S. securities. Assets in the aggregate and core plus fixed income categories are held primarily through a commingled fund and an institutional mutual fund, respectively. Group annuity contracts are invested in a combination of equity, real estate, bond and other investments in connection with a pension plan in Norway.

The following is a description of the valuation methodologies used for the pension plan assets as of December 31, 2020:

•Fair values of all U.S. equity securities, the international all cap equity securities and aggregate fixed income securities categorized as Level 2 were held in commingled funds which were valued daily based on a net asset value.

•Fair value of international small cap equity securities categorized as Level 2 were held in a limited partnership fund which was valued monthly based on a net asset value.

•The real estate equities categorized as Level 2 were held in two accounts (a commingled fund and a limited partnership). The assets in the commingled fund were valued monthly based on a net asset value and the assets in the limited partnership were valued quarterly based on a net asset value.

•Cash and equivalents categorized as Level 1 were valued at cost, which approximates fair value.

•Fair value of mutual fund investments in core plus fixed income securities categorized as Level 1 were based on quoted market prices which represent the net asset value of shares held.

To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plans, which was 6.03% at December 31, 2020 and 6.48% at December 31, 2019.

We currently expect to contribute approximately $39.8 million to our pension plans in 2021 and to directly pay other post-retirement benefits of approximately $1.4 million.

Estimated future annual benefit payments from plan assets are presented below. Such amounts are based on existing benefit formulas and include the effect of future service (in millions):


	Pension Benefits		Other Post-Retirement Benefits
Year ended December 31,
2021	$	44.5	$	1.4
2022	44.2		1.3
2023	43.8		1.3
2024	43.4		1.2
2025	43.0		1.2
2026 through 2030	208.0		4.6

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13. INCOME TAXES

We generated losses of $51.0 million, profits of $39.0 million and losses of $115.1 million from continuing operations before income taxes in the U.S. and losses of $5.1 billion, $102.8 million and $423.8 million from continuing operations before income taxes in non-U.S. jurisdictions for the years ended December 31, 2020, 2019 and 2018, respectively.

The following table summarizes components of our provision for income taxes from continuing operations for each of the years in the three-year period ended December 31, 2020 (in millions):


	2020		2019		2018
Current income tax expense (benefit):
U.S.	$	(135.3)	$	31.3	$	(19.9)
Non-U.S.	(18.4)		73.2		52.9
	(153.7)		104.5		33.0
Deferred income tax expense (benefit):
U.S.	(92.9)		19.7		52.9
Non-U.S.	(12.8)		4.2		3.7
	(105.7)		23.9		56.6
Total income tax expense (benefit)	$	(259.4)	$	128.4	$	89.6

U.S. Tax Reform and CARES Act

The U.S. Tax Cuts and Jobs Act ("U.S. tax reform") was enacted on December 22, 2017 and introduced significant changes to U.S. income tax law, effective January 1, 2018. Due to the timing of the enactment of U.S. tax reform and the complexity involved in applying its provisions, the U.S. Treasury Department continued finalizing rules associated with U.S. tax reform during 2018 and 2019. During 2019, we recognized a tax expense of $13.8 million associated with final rules issued related to U.S. tax reform. During 2018, we recognized a tax benefit of $11.7 million associated with the one-time transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries.

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Deferred Taxes

The following table summarizes significant components of deferred income tax assets and liabilities as of December 31, 2020 and 2019 (in millions):


	2020		2019
Deferred tax assets:
Net operating loss carryforwards	$	2,272.2	$	1,546.7
Interest limitation carryforwards	221.2		41.5
Foreign tax credits	171.2		142.9
Premiums on long-term debt	115.7		—
Employee benefits, including share-based compensation	81.6		73.9
Deferred revenue	1.3		.1
Net capital loss carryforwards	—		998.0
Other	5.5		11.6
Total deferred tax assets	2,868.7		2,814.7
Valuation allowance	(2,787.7)		(2,588.7)
Net deferred tax assets	81.0		226.0
Deferred tax liabilities:
Property and equipment	(40.9)		(156.0)
Net discounts on long-term debt	—		(49.5)
Deferred U.S. tax on foreign income	—		(36.7)
Other	(11.2)		(23.7)
Total deferred tax liabilities	(52.1)		(265.9)
Net deferred tax asset (liability)	$	28.9	$	(39.9)

The realization of substantially all of our deferred tax assets is dependent upon generating sufficient taxable income during future periods in various jurisdictions in which we operate. Realization of certain of our deferred tax assets is not assured. We recognize a valuation allowance for deferred tax assets when it is more-likely-than-not that the benefit from the deferred tax asset will not be realized. The amount of deferred tax assets considered realizable could increase or decrease in the near-term if our estimates of future taxable income change.

As of December 31, 2020, we had deferred tax assets of $2.3 billion relating to $9.7 billion of NOL carryforwards, $171.2 million for U.S. foreign tax credits (“FTCs”), and $221.2 million for U.S. and U.K. interest limitation carryforwards, which can be used to reduce our income taxes payable in future years. NOL carryforwards, which were generated in various jurisdictions worldwide, include $9.5 billion that do not expire and $223.0 million that will expire, if not utilized, between 2021 and 2040. Deferred tax assets for NOL carryforwards at December 31, 2020 includes $1.4 billion and $687.3 million pertaining to NOL carryforwards in Luxembourg and the United States, respectively. The U.S. FTCs expire between 2021 and 2028. Interest limitation carryforwards do not expire. Due to the uncertainty of realization, we have a $2.7 billion valuation allowance on deferred tax assets relating to NOL carryforwards, U.S. FTCs and interest limitation carryforwards.

During 2019, we completed various restructuring transactions that generated substantial U.S. capital gains and losses. On October 8, 2020, we concluded a pre-filing agreement with the U.S. Internal Revenue Service involving the amount and characterization of a $5.6 billion loss incurred in connection with one of the restructuring transactions completed in 2019. As a result of this agreement, a $998.0 million deferred tax asset was recharacterized from a capital loss carryforward to a NOL carryforward in October 2020.

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Effective Tax Rate

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. In periods of declining profitability, our income tax expense may not decline proportionally with income, which could result in higher effective income tax rates. Further, we will continue to incur income tax expense in periods in which we operate at a loss.

Our consolidated effective income tax rate on continuing operations for each of the years in the three-year period ended December 31, 2020, differs from the U.K. statutory income tax rate as follows:


	2020		2019		2018
U.K. statutory income tax rate	19.0	%	19.0	%	19.0	%
Asset impairments	(12.5)		(31.0)		(1.4)
Non-U.K. taxes	(2.8)		(280.9)		(18.0)
U.S. tax reform and U.S. CARES Act	2.4		(21.6)		2.2
Valuation allowance	(1.5)		(145.1)		(16.9)
Restructuring transactions	1.3		7.9		1.7
Bargain purchase gain	—		189.7		(.2)
Debt repurchases	—		48.7		(1.6)
Other	(.8)		12.0		(1.4)
Effective income tax rate	5.1	%	(201.3)	%	(16.6)	%

Our 2019 consolidated effective income tax rate includes $2.3 million associated with the impact of various discrete tax items, including $28.3 million of tax expense associated with final rules related to U.S. tax reform, gains on repurchase of debt and settlement proceeds, partially offset by $26.0 million of tax benefit related to restructuring transactions, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years and other resolutions of prior year tax matters and rig sales.

Our 2018 consolidated effective income tax includes the impact of various discrete tax items, including $46.0 million of tax benefit associated with the utilization of foreign tax credits subject to a valuation allowance, the transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries and a restructuring transaction, partially offset by $21.0 million of tax expense related to recovery of certain costs associated with an ongoing legal matter, repurchase and redemption of senior notes, unrecognized tax benefits associated with tax positions taken in prior years and rig sales.

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Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years ended December 31, 2020, 2019 and 2018 were (7.6)%, (14.6)% and (24.8)%. The changes in our consolidated effective income tax rate, excluding discrete tax items, during the three-year period result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and differences in tax rates in such taxing jurisdictions.

As discussed in "Note 8 - Debt", on February 3, 2020, Rowan and RCI transferred substantially all their assets and liabilities to Valaris plc and Valaris plc became the obligor on the 4.875% 2022 Notes, 2042 Notes, 7.375% 2025 Notes, 4.75% 2024 Notes and 5.85% 2044 Notes. We recognized a tax benefit of $66.0 million during the year ended December 31, 2020 in connection with this transaction.

Unrecognized Tax Benefits

Our tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon effective settlement with a taxing authority that has full knowledge of all relevant information.

As of December 31, 2020, we had $237.7 million of unrecognized tax benefits, of which $213.0 million was included in other liabilities on our consolidated balance sheet, $20.7 million, which is associated with a tax position taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets and $4.0 million was presented as a reduction of long-term income tax receivable.

As of December 31, 2019, we had $296.7 million of unrecognized tax benefits, of which $264.2 million was included in other liabilities on our consolidated balance sheet and the remaining $32.5 million, which is associated with a tax position taken in tax years with NOL carryforwards, was presented as a reduction of deferred tax assets.

If recognized, $206.2 million of the $237.7 million unrecognized tax benefits as of December 31, 2020 would impact our consolidated effective income tax rate. A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2020 and 2019 is as follows (in millions):


	2020		2019
Balance, beginning of year	$	296.7	$	143.0
Decreases in unrecognized tax benefits as a result of tax positions taken during prior years	(89.3)		(2.4)
Increase in unrecognized tax benefits as a result of tax positions taken during prior years	22.4		1.1
Lapse of applicable statutes of limitations	(13.2)		(4.4)
Increases in unrecognized tax benefits as a result of tax positions taken during the current year	12.8		17.8
Impact of foreign currency exchange rates	9.0		(.3)
Settlements with taxing authorities	(.7)		(8.0)
Increases in unrecognized tax benefits as a result of the Rowan Transaction	—		149.9
Balance, end of year	$	237.7	$	296.7

Several of our rigs are owned by subsidiaries in Switzerland that are subject to a special finance taxation regime under Swiss income tax rules. Swiss federal and cantonal governments have enacted tax legislation (“Swiss tax reform”) effective January 1, 2020. Under Swiss tax reform, the finance taxation regime has been abolished but our Swiss subsidiaries will remain subject to the finance taxation regime through December 31, 2021 and transition to deriving income tax based on net income beginning January 1, 2022. There are various uncertainties relating to the application of Swiss tax reform to finance taxation regime taxpayers, the most prominent of which is the

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determination of the Swiss tax basis of property and equipment. Based on all information currently available, we do not expect to recognize significant deferred tax assets or liabilities in connection with Swiss tax reform. As the Swiss tax authorities further clarify the application of Swiss tax reform to finance taxation regime taxpayers, we may recognize deferred tax adjustments and they may have a material effect on our consolidated financial statements.

Accrued interest and penalties totaled $73.1 million and $58.9 million as of December 31, 2020 and 2019, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized a net expense of $13.8 million, $5.7 million and $1.9 million associated with interest and penalties during the years ended December 31, 2020, 2019, and 2018 respectively. Interest and penalties are included in current income tax expense in our consolidated statements of operations.

Three of our subsidiaries file U.S. tax returns and the tax returns of one or more of these subsidiaries is under exam for years 2009 to 2012 and for 2014 and subsequent years. None of these examinations are expected to have an impact on the Company's consolidated results of operations and cash flows. Tax years as early as 2005 remain subject to examination in the other major tax jurisdictions in which we operated.

Statutes of limitations applicable to certain of our tax positions lapsed during 2020, 2019 and 2018, resulting in net income tax benefits, inclusive of interest and penalties, of $4.3 million, $5.3 million and $5.3 million, respectively.

Absent the commencement of examinations by tax authorities, statutes of limitations applicable to certain of our tax positions will lapse during 2021. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next 12 months by $2.3 million, inclusive of $1.0 million of accrued interest and penalties, all of which would impact our consolidated effective income tax rate if recognized.

Recent Tax Assessments

During 2019, the Luxembourg tax authorities issued aggregate tax assessments totaling approximately €142.0 million (approximately $173.5 million converted using the current period-end exchange rates) related to tax years 2014, 2015 and 2016 for several of Rowan's Luxembourg subsidiaries. We recorded €93.0 million (approximately $113.6 million converted using the current period-end exchange rates) in purchase accounting related to these assessments. During the first quarter of 2020, in connection with the administrative appeals process, the tax authority withdrew assessments of €142.0 million (approximately $173.5 million converted using the current period-end exchange rates), accepting the associated tax returns as previously filed. Accordingly, we de-recognized previously accrued liabilities for uncertain tax positions and net wealth taxes of €79.0 million (approximately $96.5 million converted using the current period-end exchange rates) and €2.0 million (approximately $2.4 million converted using the current period-end exchange rates), respectively. The de-recognition of amounts related to these assessments was recognized as a tax benefit during the first quarter of 2020 and is included in changes in operating assets and liabilities on the consolidated statement of cash flows for the year-ended December 31, 2020.

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Undistributed Earnings

Dividend income received by Valaris plc from its subsidiaries is exempt from U.K. taxation. We do not provide deferred taxes on undistributed earnings of certain subsidiaries because our policy and intention is to reinvest such earnings indefinitely. As of December 31, 2020, the aggregate undistributed earnings of the subsidiaries for which we maintain a policy and intention to reinvest earnings indefinitely totaled $268.0 million. Should we make a distribution from these subsidiaries in the form of dividends or otherwise, we would be subject to additional income taxes. The unrecognized deferred tax liability related to these undistributed earnings was not practicable to estimate as of December 31, 2020.

14. COMMITMENTS AND CONTINGENCIES

Capital Commitments

The following table summarizes the timing of our remaining current contractual commitments for VALARIS DS-13 and VALARIS DS-14, which were under construction as of December 31, 2020 (in millions):


	2021		2022		Thereafter		Total(1)
VALARIS DS-13	$	83.9	$	—	$	—	$	83.9
VALARIS DS-14	—		165.0		—		165.0
	$	83.9	$	165.0	$	—	$	248.9

(1) Total commitments are based on fixed-price shipyard construction contracts, exclusive of our internal costs associated with project management, commissioning and systems integration testing. Total commitments also exclude holding costs and interest.

As of December 31, 2020, the contractual delivery dates for the VALARIS DS-13 and VALARIS DS-14 were September 30, 2021 and June 30, 2022, respectively. The remaining milestone payments for VALARIS DS-13 and VALARIS DS-14 are included in the table above in the period in which they were contractually owed.

The Amended RSA provides that on or before the effective date of the reorganization, the construction contracts for these rigs shall be rejected under Section 365 of the Bankruptcy Code, unless otherwise agreed between the shipyard and the Company with the consent of required Consenting Noteholders. If rejected, it is contemplated that we would have to pay an amount equal to the liquidation recovery, which is the amount the contract counterparty would be entitled to receive or retain if the applicable Company entity was liquidated under chapter 7 of the Bankruptcy Code. Prior to December 31, 2020, a Stipulation was filed with the Bankruptcy Court which included an Assumption Term Sheet stating amended terms of these construction agreements.

Angola Non-Drilling Event

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structures. No injuries, environmental pollution or third-party damage resulted from the BOP stack being disconnected.

As a result of the incident, the operator terminated the contract. The termination resulted in a decline in our contracted revenue backlog of approximately $150 million. We carried loss of hire insurance covering $602,500 per day, after a 45-day deductible waiting period, through the end of the contract in November 2020. The waiting period expired on April 22, 2020. We received loss of hire insurance recoveries of $118.1 million, which represents the total amount owed to us under the applicable insurance policy. The recovery was recognized and recorded in Other Operating Income on our Consolidated Statements of Operations in the year ended December 31, 2020.

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 are cooperating 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.

Middle East Dispute

On July 30, 2019, we received notice that a local partner of legacy Ensco plc in the Middle East filed a lawsuit in the U.K. against the Company alleging it induced the breach of a non-compete provision in an agreement between the local partner and a subsidiary of the Company. The lawsuit included a claim for an unspecified amount of damages in excess of £100 million and other relief. We reached an agreement to settle this matter and to acquire the local partner's interest in the subsidiary for an aggregate amount of $27.5 million, which was paid in April 2020. Of this amount, we concluded that $20.3 million was attributable to the settlement of the dispute and was recognized as a loss included in other, net, in our consolidated statement of operations for the year ended December 31, 2019. The remaining amount is attributable to the acquisition of the local partner's interest in the subsidiary and was recognized in 2020 as an adjustment to Additional paid-in-capital and is included on our Consolidated Balance Sheet as of December 31, 2020.

ARO Funding Obligations

Valaris and Saudi Aramco have agreed to take all steps necessary to ensure that ARO purchases 20 newbuild jackup rigs ratably over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups for delivery scheduled in 2022. The 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. 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. The Company's capital contributions to ARO pursuant to this requirement may require approval of the Bankruptcy Court during the Chapter 11 Cases. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis. The partners agreed that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. 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.

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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.

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 December 31, 2020 totaled $115.1 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 December 31, 2020, we had insignificant collateral deposits with respect to these agreements.

15. LEASES

We have operating leases for office space, facilities, equipment, employee housing and certain rig berthing facilities. For all asset classes, except office space, we account for the lease component and the non-lease component as a single lease component. Our leases have remaining lease terms of less than one year to 10 years, some of which include options to extend.

We evaluate the carrying value of our right-of-use assets on a periodic basis to identify events or changes in circumstances, such as lease abandonment, that indicate that the carrying value of such right-of-use assets may be impaired.

During the year ended December 31, 2019, we recorded lease impairments of $5.6 million related to the impairment of the right-of-use assets associated with an office space and a leased yard facility that were abandoned due to the consolidation of certain corporate offices and leased facilities.

On October 28, 2020, the Bankruptcy Court approved the rejection of certain unexpired office leases and related subleases. The various lease rejections were effective as of September 30, 2020 and October 31, 2020. During the fourth quarter, we recorded an estimated allowed claim of $4.4 million and recognized an expense in Reorganization items, net on our Consolidated Statement of Operations for the Year ended December 31, 2020. The estimated claim has not yet been settled or paid as of December 31, 2020. Also, in connection with the office lease rejections, as of the Bankruptcy Court approved effective dates above, we reduced our right-of-use asset by a total of $10.5 million and lease liability by a total of $20.4 million and recognized a net gain in Reorganization items of $9.8 million which includes the write off of associated leasehold improvements. Additionally, in connection with the lease rejections, we amended the terms of the lease for our corporate headquarters in Houston, Texas. The amendment reduced the associated right-of-use asset by $6.4 million and lease liability by $10.4 million and we recognized a net gain in Reorganization items of $1.7 million which includes the write-off of associated leasehold improvements.

The components of lease expense during the years ended December 31, 2020 and 2019 are as follows (in millions):


	2020		2019
Long-term operating lease cost	$	23.3	$	29.5
Short-term operating lease cost	19.2		12.2
Sublease income	(2.3)		(2.4)
Total operating lease cost	$	40.2	$	39.3

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We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $40.1 million during the year ended December 31, 2018.

Supplemental balance sheet information related to our operating leases is as follows (in millions, except lease term and discount rate) as of December 31, 2020 and 2019:


	2020			2019
Operating lease right-of-use assets	$	35.8		$	58.1

Current lease liability	$	15.7		$	21.1
Long-term lease liability	21.6			51.8
Total operating lease liabilities	$	37.3		$	72.9

Weighted-average remaining lease term (in years)	4.3			5.1

Weighted-average discount rate (1)	8.24		%	8.23		%

(1)Represents our estimated incremental borrowing cost on a secured basis for similar terms as the underlying leases.

For the years ended December 31, 2020 and 2019, cash paid for amounts included in the measurement of our operating lease liabilities were $23.5 million and $29.9 million, respectively.

Maturities of lease liabilities as of December 31, 2020 were as follows (in millions):



2021	$	17.8
2022	12.0
2023	3.0
2024	2.2
2025	2.0
Thereafter	9.0
Total lease payments	$	46.0
Less imputed interest	8.7
Total	$	37.3

16. SEGMENT INFORMATION

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." Substantially all of the expenses incurred associated with our Transition Services Agreement are included in general and administrative under "Reconciling Items" in the table set forth below. We measure segment assets as property and equipment.

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The full operating results included below for ARO (representing only results of ARO from the closing date of the Rowan Transaction) are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See "Note 5 - Equity Method Investment in ARO" for additional information on ARO and related arrangements.

Segment information for each of the years in the three-year period ended December 31, 2020 is presented below (in millions).

Year Ended December 31, 2020


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	505.8	$	765.3	$	549.4	$	156.1	$	(549.4)	$	1,427.2
Operating expenses
Contract drilling (exclusive of depreciation)	633.9		733.3		388.2		91.4		(388.2)		1,458.6
Loss on impairment	3,386.2		254.3		—		5.7		—		3,646.2
Depreciation	262.8		217.2		54.8		44.8		(38.8)		540.8
General and administrative	—		—		24.2		—		190.4		214.6
Other operating income	118.1		—		—		—		—		118.1
Equity in losses of ARO	—		—		—		—		(7.8)		(7.8)
Operating income (loss)	$	(3,659.0)	$	(439.5)	$	82.2	$	14.2	$	(320.6)	$	(4,322.7)
Property and equipment, net	$	6,413.4	$	3,912.6	$	736.2	$	577.9	$	(679.6)	$	10,960.5
Capital expenditures	$	25.1	$	58.9	$	136.1	$	—	$	(126.3)	$	93.8

Year Ended December 31, 2019


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	1,014.4	$	834.6	$	410.5	$	204.2	$	(410.5)	$	2,053.2
Operating expenses
Contract drilling (exclusive of depreciation)	898.6		788.9		280.2		118.5		(280.2)		1,806.0
Loss on impairment	88.2		10.2		—		—		5.6		104.0
Depreciation	362.3		203.3		40.3		25.5		(21.7)		609.7
General and administrative	—		—		27.1		—		161.8		188.9
Equity in losses of ARO	—		—		—		—		(12.6)		(12.6)
Operating income (loss)	$	(334.7)	$	(167.8)	$	62.9	$	60.2	$	(288.6)	$	(668.0)
Property and equipment, net	$	10,073.1	$	4,322.7	$	650.7	$	620.9	$	(570.5)	$	15,096.9
Capital expenditures	$	31.4	$	184.6	$	27.5	$	—	$	(16.5)	$	227.0

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Year Ended December 31, 2018


	Floaters		Jackups		ARO		Other		Reconciling Items		Consolidated Total
Revenues	$	1,013.5	$	630.9	$	—	$	61.0	$	—	$	1,705.4
Operating expenses
Contract drilling (exclusive of depreciation)	737.4		526.5		—		55.5		—		1,319.4
Loss on impairment	—		40.3		—		—		—		40.3
Depreciation	311.8		153.3		—		—		13.8		478.9
General and administrative	—		—		—		—		102.7		102.7
Operating income (loss)	$	(35.7)	$	(89.2)	$	—	$	5.5	$	(116.5)	$	(235.9)
Property and equipment, net	$	9,465.6	$	3,114.1	$	—	$	—	$	36.5	$	12,616.2
Capital expenditures	$	105.5	$	317.7	$	—	$	—	$	3.5	$	426.7

Information about Geographic Areas

As of December 31, 2020, our Floaters segment consisted of 11 drillships, four dynamically positioned semisubmersible rigs and one moored semisubmersible rig deployed in various locations. Our Jackups segment consisted of 36 jackup rigs which were deployed in various locations and our Other segment consisted of nine jackup rigs which are leased to our 50/50 joint venture with Saudi Aramco.

As of December 31, 2020, the geographic distribution of our and ARO's drilling rigs was as follows:


	Floaters	Jackups	Other	Total Valaris	ARO
North & South America	5	6	—	11	—
Europe & the Mediterranean	7	16	—	23	—
Middle East & Africa	2	8	9	19	7
Asia & Pacific Rim	2	6	—	8	—

Total	16	36	9	61	7

We provide management services on two rigs owned by third-parties not included in the table above.

We are a party to contracts for the construction of two drillships in South Korea, VALARIS DS-13 and VALARIS DS-14, 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.

For purposes of our long-lived asset geographic disclosure, we attribute assets to the geographic location of the drilling rig or operating lease, in the case of our right- of-use assets, as of the end of the applicable year. For new construction projects, assets are attributed to the location of future operation if known or to the location of construction if the ultimate location of operation is undetermined.

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Information by country for those countries that account for more than 10% of our long-lived assets as well as the United Kingdom, our country of domicile, was as follows (in millions):


	Long-lived Assets
	2020		2019		2018
United Kingdom	$	2,584.0	$	1,210.5	$	1,185.2
Spain	2,122.6		3,012.4		2,306.6
United States	1,811.9		2,972.4		2,270.0
Saudi Arabia	1,183.7		1,259.3		668.6
Nigeria	766.2		788.4		1,368.2
Other countries(1)	2,527.9		5,912.0		4,817.6
Total	$	10,996.3	$	15,155.0	$	12,616.2

(1)Other countries includes countries where individually we had long-lived assets representing less than 10% of total long-lived assets

17. SUPPLEMENTAL FINANCIAL INFORMATION

Consolidated Balance Sheet Information

Accounts receivable, net, as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020		2019
Trade	$	260.1	$	466.4
Income tax receivables	190.6		39.3
Other	14.7		21.0
	465.4		526.7
Allowance for doubtful accounts	(16.2)		(6.0)
	$	449.2	$	520.7

Other current assets as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020		2019
Materials and supplies	$	279.4	$	340.1
Prepaid expenses	43.4		13.5
Prepaid taxes	32.9		36.2
Deferred costs	17.4		23.3
Other	24.8		33.4
	$	397.9	$	446.5

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Other assets as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020		2019
Tax receivables	$	66.8	$	36.3
Deferred tax assets	21.9		26.6
Right-of-use assets	35.8		58.1
Supplemental executive retirement plan assets	22.6		26.0
Intangible assets	2.4		11.9
Other	26.7		29.4
	$	176.2	$	188.3

Accrued liabilities and other as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020		2019
Personnel costs	$	95.6	$	134.4
Deferred revenue	57.6		30.0
Income and other taxes payable	50.8		61.2
Lease liabilities	15.7		21.1
Accrued interest	—		115.2
Settlement of legal dispute	—		20.3
Other	30.7		35.5
	$	250.4	$	417.7

Other liabilities as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020		2019
Pension and other post-retirement benefits	$	296.6	$	246.7
Unrecognized tax benefits (inclusive of interest and penalties)	286.1		323.1
Intangible liabilities	50.4		52.1
Supplemental executive retirement plan liabilities	22.9		26.7
Lease liabilities	21.6		51.8
Deferred revenue	14.3		9.7
Deferred tax liabilities	13.7		99.0
Personnel costs	11.8		24.5
Other	45.0		33.8
	$	762.4	$	867.4

Accumulated other comprehensive income (loss) as of December 31, 2020 and 2019 consisted of the following (in millions):


	2020		2019
Pension and other post-retirement benefits	$	(98.2)	$	(21.7)
Currency translation adjustment	6.5		7.1
Derivative instruments	5.6		22.6
Other	(1.8)		(1.8)
	$	(87.9)	$	6.2

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Consolidated Statement of Operations Information

Repair and maintenance expense related to continuing operations for each of the years in the three-year period ended December 31, 2020 was as follows (in millions):


	2020		2019		2018
Repair and maintenance expense	$	200.4	$	303.7	$	198.4

Other, net, for each of the years in the three-year period ended December 31, 2020 consisted of the following (in millions):


	2020		2019		2018
Net periodic pension (cost) income, excluding service cost	$	14.6	$	5.8	$	—
Currency transaction adjustments	(11.0)		(7.4)		(17.2)
Gain on bargain purchase and measurement period adjustments	(6.3)		637.0		1.8
Gain (loss) on extinguishment of debt	3.1		194.1		(19.0)
SHI settlement	—		200.0		—
Settlement of legal dispute	—		(20.3)		—
Other income (expense)	3.8		(4.8)		(.4)
	$	4.2	$	1,004.4	$	(34.8)

Consolidated Statement of Cash Flows Information

Net cash used in operating activities of continuing operations attributable to the net change in operating assets and liabilities for each of the years in the three-year period ended December 31, 2020 was as follows (in millions):


	2020		2019		2018
(Increase) decrease in accounts receivable	$	53.3	$	29.5	$	(6.2)
Increase in other assets	(63.8)		(56.6)		(17.3)
Increase (decrease) in liabilities	(11.5)		(25.4)		2.7
	$	(22.0)	$	(52.5)	$	(20.8)

During 2020, our business contracted due to decline in oil prices and impact of the COVID-19 pandemic, resulting in negative cash flows from operating assets and liabilities. During 2019, we experienced moderate improvements in fleet utilization coupled with the Rowan Transaction that resulted in negative cash flows from changes in operating assets and liabilities. During 2018, our business contracted at a more moderate pace, resulting in modest negative cash flows from the net change in operating assets and liabilities.

Cash paid for interest and income taxes for each of the years in the three-year period ended December 31, 2020 was as follows (in millions):


	2020		2019		2018
Interest, net of amounts capitalized	$	190.0	$	410.0	$	232.6
Income taxes	78.9		107.6		58.4

Capitalized interest totaled $1.3 million, $20.9 million and $62.6 million during the years ended December 31, 2020, 2019 and 2018, respectively. Capital expenditure accruals totaling $5.4 million, $16.3 million and $27.8 million for the years ended December 31, 2020, 2019 and 2018, respectively, were excluded from investing activities in our consolidated statements of cash flows.

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For information related to cash paid for Reorganization Items, see "Note 2 - Chapter 11 Proceedings and Ability to Continue as a Going Concern".

Amortization, net, includes amortization of deferred mobilization revenues and costs, deferred capital upgrade revenues, intangible amortization and other amortization.

Other includes non-cash impress inventory expense, bad debt expense, pension and other postretirement benefits income/expense, gain/loss on asset disposals and other items.

Concentration of Risk

We are exposed to credit risk relating to our receivables from customers, our cash and cash equivalents, investments and previously our use of derivatives in connection with the management of foreign currency exchange rate risk. 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.

We mitigated our credit risk relating to counterparties of our previous derivatives through a variety of techniques, including transacting with multiple, high-quality financial institutions, thereby limiting our exposure to individual counterparties and by entering into International Swaps and Derivatives Association, Inc. ("ISDA") Master Agreements, which included provisions for a legally enforceable master netting agreement, with our derivative counterparties. The terms of the ISDA agreements may also have included credit support requirements, cross default provisions, termination events or set-off provisions. Legally enforceable master netting agreements reduce credit risk by providing protection in bankruptcy in certain circumstances and generally permitting the closeout and netting of transactions with the same counterparty upon the occurrence of certain events. See "Note 9 - Derivative Instruments" for additional information on our derivative activity and the impact of the Chapter 11 Cases.

Consolidated revenues by customer for the years ended December 31, 2020, 2019 and 2018 were as follows:


	2020		2019		2018
BP (1)	11	%	9	%	7	%
Saudi Aramco(2)	9	%	7	%	11	%
Total(3)	8	%	16	%	15	%
Other	72	%	68	%	67	%
	100	%	100	%	100	%

(1)For the year ended December 31, 2020, 30% of the revenues provided by BP were attributable to our Floaters segment, 19% were attributable to our Jackups segment, and 51% of the revenues were attributable to our managed rigs.

For the year ended December 31, 2019, 41% of the revenues provided by BP were attributable to our Jackups segment, 16% of the revenues were attributable to our Floaters segment and 43% of the revenues were attributable to our managed rigs.

For the year ended December 31, 2018, 27% of the revenues provided by BP were attributable to our Floaters segment, 20% of the revenues were attributable to our Jackups segment, and 53% of the revenues were attributable to our managed rigs.

(2)For the years ended December 31, 2020, 2019 and 2018, all Saudi Aramco revenues were attributable to the Jackup segment.

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(3)For the years ended December 31, 2020 and 2019, 71% and 93% of the revenues provided by Total were attributable to the Floaters segment and the remainder was attributable to the Jackup segment. During the year ended December 31, 2018, all the revenues provided by Total were attributable to the Floater segment.

For purposes of our geographic disclosure, we attribute revenues to the geographic location where such revenues are earned. Consolidated revenues by region, including the United Kingdom, our country of domicile, for the years ended December 31, 2020, 2019 and 2018 were as follows (in millions):


	2020		2019		2018
U.S. Gulf of Mexico(1)	$	241.4	$	301.0	$	214.7
United Kingdom(2)	211.3		213.1		192.6
Saudi Arabia(3)	200.8		313.4		182.2
Norway(2)	188.5		39.2		—
Australia(4)	117.9		204.2		283.9
Angola(5)	86.3		284.0		285.7
Other	381.0		698.3		546.3
	$	1,427.2	$	2,053.2	$	1,705.4

(1)For the years ended December 31, 2020, 2019 and 2018, 55%, 46% and 30% of the revenues earned in the U.S. Gulf of Mexico, respectively, were attributable to our Floaters segment, 11%, 28% and 42% of the revenues were attributable to our Jackups segment, respectively, and the remaining revenues were attributable to our managed rigs, respectively.

(2)For the years ended December 31, 2020, 2019 and 2018, all revenues earned in the United Kingdom and Norway were attributable to our Jackups segment.

(3)For the years ended December 31, 2020 and 2019, 63% and 65% of the revenues earned in Saudi Arabia, were attributable to our Jackups segment. The remaining revenues were attributable to our Other segment and related to our rigs leased to ARO and certain revenues related to our Secondment Agreement and Transition Services Agreement. For the year ended December 31, 2018, all revenues earned were attributable to our Jackup segment.

(4)For the years ended December 31, 2020, 2019 and 2018, 91%, 90% and 92% of the revenues earned in Australia, respectively, were attributable to our Floaters segment and the remaining revenues were attributable to our Jackups segment.

(5)For the years ended December 31, 2020, 2019 and 2018, 84%, 87% and 86% of the revenues earned in Angola, respectively, were attributable to our Floaters segment and the remaining revenues were attributable to our Jackups segment.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND PROCEDURES

Based on their evaluation as of the end of the period covered by this Annual Report on Form 10-K, our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has concluded that our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, are effective.

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.

We have appropriately implemented Financial Accounting Standards Board Accounting Standard Codification Topic No. 852 – Reorganizations (“ASC 852”), during the year and have prepared the Consolidated Financial Statements and disclosures in accordance with ASC 852.

Changes in Internal Controls – During the year ended December 31, 2020, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.

Item 9B. Other Information

Not applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item with respect to our directors, corporate governance matters and Section 16(a) of the Exchange Act is contained in this section.

The information required by this item with respect to our executive officers is set forth in "Executive Officers" in Part I of this Annual Report on Form 10-K.

Board of Directors

The guidelines and procedures of the Board of Directors are outlined in our Corporate Governance Policy. The committees of the Board of Directors operate under written charters adopted by the Board of Directors. The Corporate Governance Policy and committee charters are available on our website at www.valaris.com in the Governance Documents section and are available in print without charge by contacting our Investor Relations Department.

Set forth below are the names and certain information for the board of directors. The information presented includes each director's principal occupation and business expertise and the names of other public companies for which he or she has severed as director during the past five years.

William E. Albrecht; age 69; Chairman of the Board of Laredo Petroleum, Inc.

Mr. Albrecht has been our director since April 2019 and was a director of Rowan from October 2015 until April 2019. Since February 2020, Mr. Albrecht has served on the board of directors of Laredo Petroleum, Inc., and in May 2020, he was appointed as its Chairman. Mr. Albrecht previously served as the non-executive Chairman of the Board of California Resources Corporation (“CRC”), a publicly traded oil and natural gas exploration and production company, from May 2016 until August 2020. He previously served as Executive Chairman of CRC from July 2014 to May 2016. Mr. Albrecht served as Vice President of Occidental Petroleum from May 2008 to July 2014 and as President, Oxy Oil & Gas, Americas from January 2012 to July 2014. Mr. Albrecht also served as President-Oxy Oil & Gas, USA from April 2008 to January 2012. During his tenure with Occidental, Mr. Albrecht had extensive managerial oversight over its upstream assets. Mr. Albrecht has more than 40 years of experience in the oil and gas industry, having previously served as an executive officer for EOG Resources, a domestic energy producer, for eight years and as a petroleum engineer for Tenneco Oil Company for ten years. Since 2016, Mr. Albrecht serves on the board of directors of Halliburton Company and Terra Energy Partners, a privately-held oil and gas exploration and production company. Mr. Albrecht holds a Master of Science degree from the University of Southern California and a Bachelor of Science degree from the United States Military Academy. Mr. Albrecht is a National Association of Corporate Directors (“NACD”) Board Leadership Fellow and has completed NACD’s comprehensive program of study for directors and corporate governance professionals. Mr. Albrecht currently serves on our Nominating, Governance and Sustainability Committee and Compensation Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Albrecht should serve as a director include his experience in various executive positions with extensive managerial oversight, his over 40 years of experience in the oil and gas industry and his broad experience in proactively engaging with regulatory agencies, communities and other stakeholders.

Frederick Arnold; age 66; Retired Financial Executive

Mr. Arnold has been our director since November 2019. Mr. Arnold has 40 years of experience, including senior financial leadership positions at global organizations. Prior to his appointment to the Board, Mr. Arnold

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spent over 20 years as an investment banker advising clients on matters of corporate finance, including capital markets transactions, capital structure optimization and mergers and acquisitions across various markets and geographies. Mr. Arnold then held a series of senior financial positions with private equity portfolio companies, most recently serving as Chief Financial Officer of Convergex Group, LLC, a provider of agency brokerage and investment technology, from July 2015 until May 2017, where he was responsible for capital allocation and financial operations. Previously, Mr. Arnold served as Executive Vice President, Chief Financial Officer and a member of the executive committee of Capmark Financial Group, Inc. from September 2009 to January 2011. He also served as Executive Vice President of Finance for Masonite Corporation from February 2006 to September 2007. While at Willis Group from 2000 to 2003, Mr. Arnold served as Chief Financial and Administrative Officer of Willis North America, as Group Chief Administrative Officer of Willis Group Holdings Ltd. and as Executive Vice President of Strategic Development for Willis Group Holdings Ltd. He also served as a member of the Willis Group executive committee while holding the latter two positions. Mr. Arnold currently serves on the Board of Directors of Navient Corporation and Lehman Brothers Holdings Inc. From 2011 to 2018, Mr. Arnold served on the Board of Directors of Corporate Capital Trust, and subsequently to 2019 on the board of its successor and related companies, the Family of Funds Advised by FS/KKR Advisor, LLC: (1) FS KKR Capital Corp. (NYSE: FSK), (2) FS Investment Corp. II, (3) FS Investment Corp. III and (iv) FS Investment Corp. IV. From 2016 to 2020, Mr. Arnold served on the Board of Directors of Syncora Holdings Ltd. Mr. Arnold currently serves on our Audit Committee and Special Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Arnold should serve as a director include his extraordinary breadth and depth of experience in equity and debt capital markets, operations and governance from his 40-year career in international investment banking, leadership finance roles and experience serving on numerous boards.

Thomas P. Burke; age 53; President and Chief Executive Officer of Valaris plc

Mr. Burke has served as the President, Chief Executive Officer and a director of Valaris since April 2019. Mr. Burke was appointed President and Chief Executive Officer and elected a director of Rowan in April 2014, serving in those capacities until April 2019. He served as Chief Operating Officer beginning in July 2011 and was appointed President in March 2013. Mr. Burke first joined Rowan in December 2009, serving as Chief Executive Officer and President of LeTourneau Technologies until the sale of LeTourneau in June 2011. From 2006 to 2009, Mr. Burke was a Division President at Complete Production Services, an oilfield services company, and from 2004 to 2006, served as its Vice President for Corporate Development.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Burke should serve as a director include his extensive managerial and industry experience and his strong background in operations and investments in the global energy sector.

Mary E. Francis CBE; age 72; Former Senior Civil Servant in British Treasury and Prime Minister's Office (Retired)

Ms. Francis has been our director since May 2013. She is a former senior civil servant in the British Treasury and the Prime Minister’s office and was subsequently Director General of the Association of British Insurers. Ms. Francis served on the Board of Directors of Swiss Reinsurance Company Ltd from October 2012 until April 2018, and has previously served as a non-executive director of the Swiss Re Group. Ms. Francis was appointed to the Boards of Directors of Barclays PLC and Barclays Bank PLC in October 2016 and appointed to the Board of Directors of PensionBee in November 2020. She served on the Board of Directors of Centrica plc, an integrated energy company, between 2004 and 2014, and was Senior Independent Director from 2006 to 2014. From 2005 to 2012, she served as a non-executive director of Aviva plc, and from 2009 to 2012, she served as a non-executive director of Cable & Wireless Communications Plc. She is also a former non-executive director of the Bank of England, Alliance & Leicester plc and St. Modwen Properties PLC and is a Senior Adviser to the International Relations Institute, Chatham House. She earned a Master of Arts in History from Newnham College,

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University of Cambridge. Ms. Francis currently serves on our Audit Committee and Nominating, Governance and Sustainability Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Ms. Francis should serve as a director include her experience as a director for various British and international public companies, including Swiss Reinsurance Company Ltd, Barclays PLC and Barclays Bank PLC, her tenure as a non-executive director of the Bank of England, Alliance & Leicester plc and St. Modwen Properties PL, her role as a Senior Adviser to the International Relations Institute, Chatham House, her experience as the chairman of board committees for several public companies, her expertise in matters of corporate governance and her experience in senior positions within the U.K. government.

Georges J. Lambert; age 43; Former Partner and Senior Vice President of The Capital Group (Retired)

Mr. Lambert has been our director since November 2019. Prior to his appointment to the Board, Mr. Lambert spent more than 20 years as an investment professional, with a focus on value/dividend, cyclicals and complex turnaround situations. Most recently, he was a Partner and Senior Vice President of The Capital Group from 1999 to June 2019, where he served in various capacities as a portfolio manager and equity analyst across multiple sectors including energy services, telecommunications and shipping, and chaired research teams in both energy and telecommunications. Mr. Lambert also led Capital International Group’s investment-side European corporate governance efforts between 2008 and 2017. Mr. Lambert earned a Master of Science in Finance from HEC Paris. Mr. Lambert currently serves on our Special Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Lambert should serve as a director include his management expertise and capital markets and equity analyst experience, including in the energy services sector, his significant corporate governance experience, his tenure as an investment representative for Capital International Group’s governance and stewardship engagements, his in-depth knowledge of the energy industry and the stock market, and his ability to bring a shareholder perspective to the Board, given his extensive experience as a portfolio manager at The Capital Group.

Suzanne P. Nimocks; age 62; Former Director of McKinsey & Company (Retired)

Ms. Nimocks has been our director since April 2019 and was a director of Rowan from December 2010 until April 2019. Ms. Nimocks was formerly a Director (Senior Partner) of McKinsey & Company, a global management consulting firm, from June 1999 to March 2010, and was with the firm in various capacities since 1989, including leader of the firm’s Global Petroleum Practice, Electric Power & Natural Gas Practice, Organization Practice, Risk Management Practice and Strategy Practice. Ms. Nimocks served on several of the firm’s worldwide personnel committees for many years and formerly served as the Houston Office Manager for eight years. Ms. Nimocks currently serves on the boards of ArcelorMittal, Ovintiv Inc. (formerly named Encana Corporation) and Owens Corning, including service on the Appointments, remuneration & corporate governance and sustainability committee of ArcelorMittal; Audit Committee and Corporate Responsibility and Governance Committee (Chair) of Ovintiv Inc.; and the Finance Committee (Chair) and Compensation Committee of Owens Corning. Ms. Nimocks currently serves as Chairman of our Compensation Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Ms. Nimocks should serve as a director include her global management consulting and energy sector experience and her service on the Boards and various committees of publicly traded companies, including extensive experience in executive compensation through her roles as the Chair of the Human Resources and Compensation Committee of Ovintiv Inc. and as a member of the Compensation Committee of Owens Corning.

Thierry Pilenko; age 63; Former Executive Chairman of TechnipFMC plc (Retired)

Mr. Pilenko has been our director since April 2019 and was a director of Rowan from 2017 until April 2019. In May 2019, Mr. Pilenko retired from the Board of Directors and as Executive Chairman of TechnipFMC

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plc, a global oil and gas company. He was the former Chairman and Chief Executive Officer of Technip S.A., a leading provider of project management, engineering, and construction services for the energy industry, from April 2007 to January 2017, when FMC Technologies, Inc. consummated its merger with Technip S.A. From March 2004 to January 2007, Mr. Pilenko served as the Chairman and Chief Executive Officer of Veritas DGC, Inc., a seismic services company. Previously, Mr. Pilenko served as Managing Director of SchlumbergerSema, a Schlumberger Ltd. company in Paris, from 2001 to March 2004. From 1998 to 2001, he served as President of Schlumberger GeoQuest. Mr. Pilenko formerly served as a director of TechnipFMC plc, Hercules Offshore, Inc., CGG Veritas (formerly Veritas DGC) and Peugeot SA. Mr. Pilenko currently serves on our Nominating, Governance, Sustainability Committee and Special Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Pilenko should serve as a director include his significant international oil and energy policy expertise, his service on boards and committees of publicly traded companies, his extensive experience in the oil and gas energy industry, including CEO leadership positions, and his strong background in finance, operations, management and investments in the global energy sector.

Paul E. Rowsey, III; age 66; Former Chief Executive Officer of Compatriot Capital, Inc. (Retired)

Mr. Rowsey has served as a director since 2000. In September 2017, he retired as the President and Chief Executive Officer of Compatriot Capital, Inc., a real estate investment and operating company, where he was employed since 2011. Prior to joining Compatriot, he was a founder and the managing partner of E2M Partners, LLC, a sponsor and manager of private real estate equity funds and an affiliate of Compatriot. He serves as a member of the Board of Directors of Powdr Corporation, one of the largest alpine skiing and outdoor sports companies in the United States, based in Park City, Utah; KDC Holdings, a national real estate investment and development firm, based in Dallas, Texas; JLB Partners, LLC, a multifamily housing development firm and its affiliate, Longbrook Capital Partners, LLC, based in Dallas, Texas; and Invesco Real Estate Income Trust, Inc., a real estate investment company, based in Dallas, Texas. Mr. Rowsey is a 1977 magna cum laude graduate of Duke University with a degree in management science and a 1980 cum laude graduate of Southern Methodist University School of Law. Mr. Rowsey also serves on our Compensation Committee, and as the Chairman of our Nominating, Governance, and Sustainability Committee and our Special Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Rowsey should serve as a director include his expertise in financial, business and legal matters, including his experience as the President and Chief Executive Officer of Compatriot Capital, Inc., his experience as the founder and the managing partner of E2M Partners, LLC, a sponsor and manager of private real estate equity funds and an affiliate of Compatriot and his extensive negotiating experience in complex business transactions and his general business acumen.

Charles L. Szews; age 64; Former Chief Executive Officer of Oshkosh Corporation (Retired)

Mr. Szews has been our director since April 2019 and was a director of Rowan from August 2016 until April 2019. In December 2015, Mr. Szews retired from Oshkosh Corporation, a leading global manufacturer of specialty vehicles and vehicle bodies serving access equipment, defense, fire and emergency and commercial markets. He joined Oshkosh in 1996 as Vice President and CFO, was appointed Executive Vice President in October 1997, and was appointed President, Chief Operating Officer and as a director in October 2007. Mr. Szews was appointed Chief Executive Officer of Oshkosh in January 2011. Prior to joining Oshkosh, he began his career with Ernst & Young, and was Vice President and Controller at Fort Howard Corporation during its leveraged buyout. Since 2014, Mr. Szews has served as a director for Commercial Metals Company, an operator of mini- and micro-steel mills located in the Southern United States and Poland. In November 2016, Mr. Szews joined the board of Group1 Automotive, a Fortune 500 automotive retailer. In April 2018, Mr. Szews was appointed to the board of directors of Allegion plc, a provider of security products and solutions for homes, businesses, schools and other institutions. From 2006 to 2013, Mr. Szews also served on the board of directors and on the Audit and Nominating and Corporate Governance Committees of Gardner Denver Inc., a recognized leader in compressed air and gas,

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vacuum and fluid transfer technologies to industries throughout the world. Mr. Szews holds a degree in Business Administration from the University of Wisconsin - Eau Claire. Mr. Szews currently serves on our Special Committee and as Chair of our Audit Committee.

The particular experience, qualifications, attributes and skills that led our Board to conclude that Mr. Szews should serve as a director include extensive executive management experience, public company directorships and committee appointments and his significant experience with international sales, capital allocation, mergers and acquisitions, business management and finance.

Audit Committee

The Audit Committee currently consists of Chair Szews, Mr. Arnold and Ms. Francis, all of whom meet the independence criteria in accordance with the charter of our Audit Committee, which incorporates independence standards prescribed by the SEC and NYSE. None of the members of our Audit Committee serve on more than three public company audit committees. Our Board has determined that each of the three members of the Audit Committee meets the requisite SEC criteria to qualify as an audit committee financial expert, is financially literate and has accounting or related financial management expertise as defined in the NYSE Corporate Governance Standards. In making recommendations and determinations regarding audit committee financial experts, our Board and the Audit Committee considered the relevant academic and professional experience of the Audit Committee members.

Code of Business Conduct

Our Code of Business Conduct applies to all of our officers, directors and employees, including our principal executive officer, principal financial officer, principal accounting officer and Controller. Our Code of Business Conduct includes provisions addressing conflicts of interest, corporate opportunities, confidentiality, fair dealing, protection and proper use of our assets and compliance with our policies and with laws, rules and regulations, including laws addressing insider trading, antitrust and anti-bribery, including the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010. No waivers of the provisions of our Code of Business Conduct have been requested or granted since the Code of Business Conduct was first issued on 1 November 2002. Our Code of Business Conduct provides for confidential and anonymous submission of reports of non-compliance with our standards, policies, practices and procedures to a management committee and also establishes a means for submission of reports of accounting, auditing or other business irregularities by any employee or other person directly to our Board or relevant Board Committee.

The Code of Business Conduct is available on our website at www.valarisplc.com in the Governance Documents section and is available in print without charge by contacting our Investor Relations Department. We intend to disclose any amendments to or waivers from our Code of Conduct by posting such information on our website.

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Item 11. Executive Compensation

This section discusses the material elements of our executive compensation policies for our Named Executive Officers ("NEOs") and the most important factors relevant to an analysis of these policies. The 2020 NEOs include Thomas P. Burke, President and Chief Executive Officer, the two other most highly compensated executive officers who were serving as of December 31, 2020, Jonathan Baksht, Executive Vice President and Chief Financial Officer, and Michael McGuinty, Senior Vice President, General Counsel and Secretary and Carl G. Trowell, former Executive Chairman. In addition, this section provides qualitative information regarding the manner and context in which compensation is awarded to and earned by our NEOs and is intended to place in perspective the data presented in the following tables and the corresponding narrative.

The following table sets forth the total compensation paid or awarded to each of our NEOs for the fiscal years ended December 31, 2020 and 2019.

Summary Compensation Table


Name and Principal Position	Year	Salary ($)(1)	Bonus ($)(2)	Share Awards ($)(3)	Non-Equity Incentive Plan Compensation ($)(4)	All Other Compensation ($)(5)	Total ($)
Thomas P. Burke	2020	855,000	1,282,500	1,423,447	3,397,129	609,014	7,567,090
President and Chief Executive Officer	2019	676,927	—	—	882,367	4,228,794	5,788,088
Jonathan Baksht	2020	550,000	1,375,000	582,699	1,628,022	83,847	4,219,568
Executive Vice President and Chief Financial Officer	2019	533,333	—	1,349,997	1,001,075	471,818	3,356,223
Michael McGuinty	2020	510,000	1,275,000	449,512	1,235,704	299,844	3,770,060
Senior Vice President, General Counsel and Secretary	2019	501,667	175,000	1,200,000	875,231	410,758	3,162,656


Carl G. Trowell	2020	189,150	—	—	—	4,838,803	5,027,953
Former Executive Chairman(6)	2019	629,168	—	4,999,996	802,288	5,071,499	11,502,951

(1)The amounts disclosed in this column include amounts voluntarily deferred under the Ensco Savings Plan, the 2005 Ensco Supplemental Executive Retirement Plan (referred to collectively, along with the Ensco Supplemental Retirement Plan, as the "SERP") and the Rowan Companies, Inc. Savings & Investment Plan. Amounts in this table for Mr. Trowell have been converted from pounds to U.S. dollars using the exchange rate of 1.261, which was the average rate during the period in 2020 where payments were made.

(2)The amounts disclosed in this column for 2020 consist of cash retention payments awarded to Messrs. Burke, Baksht and McGuinty in February and May 2020. As a condition to receipt of these full payments, each NEO was required to forfeit all previously granted 2020 restricted share units and 2020 performance units. In addition, Mr. Burke's full retention bonus and a total of $1.1 million and $1.0 million for each of Messrs. Baksht and McGuinty is subject to repayment on an after-tax basis in the event the NEO resigns without good reason or is terminated for cause prior to the earlier of May 15, 2021, a change in control or completion of our restructuring. The amounts disclosed in this column for 2019 consists of the discretionary bonus adjustment approved for Mr. McGuinty in 2019.

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(3)The amounts disclosed in this column represent the aggregate grant date fair value of restricted share units granted in 2020 and 2019 and Relative TSR performance units granted in 2019 as follows:


	Year	Restricted Share Units ($)	Performance Unit Awards ($)	Total ($)
Thomas P. Burke	2020*	1,423,447	—	1,423,447
Jonathan Baksht	2020*	582,699	—	582,699
	2019	674,997	675,000	1,349,997
Michael McGuinty	2020*	449,512	—	449,512
	2019	600,000	600,000	1,200,000


Carl G. Trowell	2020**	—	—	—
	2019	2,499,996	2,500,000	4,999,996

*These 2020 restricted share units were subsequently forfeited as a condition to receipt of the cash retention bonuses described in footnote 2.

** In accordance with his 2019 employment agreement, Mr. Trowell forfeited his 2019 restricted share units. Additionally, in accordance with the April 2020 amendment to his employment agreement, Mr. Trowell forfeited all remaining unvested equity awards as of April 30, 2020.

Grant date fair value for restricted share units and TSR performance unit awards accounted for as equity awards are measured using the market value of our shares on the date of grant and the estimated probable payout on the date of grant, respectively, as described in "Note 1 1 Share Based Compensation" included in "Item 8 Financial Statements and Supplementary Data".

If the maximum level of payout is achieved under the 2019 Relative TSR performance unit award grants, the aggregate grant date fair value of such awards would be as follows:


	Maximum Payout
Thomas P. Burke	$	—
Jonathan Baksht	$	1,350,000
Michael McGuinty	$	1,200,000

Carl G. Trowell	$	5,000,000

The TSR performance unit awards granted in 2019 are payable in cash. Mr. Trowell forfeited this award in accordance with the April 2020 amendment to his employment agreement.

(4)The amounts disclosed in this column represent bonuses earned for 2020 and 2019 pursuant to the Valaris plc 2018 Cash Incentive Plan ("VCIP").

The 2020 VCIP was redesigned to provide for quarterly incentives earned over the period of April 1, 2020 through June 30, 2021 based on the achievement of personal safety, process safety, downtime and expense reduction performance metrics. The second quarter 2020 and third quarter 2020 VCIP was prepaid at 100% of target in June 2020. Upon approval of the Bankruptcy Court, the Company resumed payout of VCIP, subject to certain revisions. The revisions resulted in a true-up to the second quarter and third quarter 2020 performance awards, which will be paid upon emergence from bankruptcy. The earned fourth quarter 2020 VCIP will paid in March 2021. Although all such amounts were not paid by December 31, 2020, amounts shown in this column include all amounts earned for second quarter through fourth quarter 2020 performance.

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The 2020 and 2019 amounts disclosed in this column also include the payout of the relative ROCE component of the performance awards granted in 2017 and 2018. The components of the 2020 and 2019 amounts are as follows:


	2020						2019
	2020 VCIP		2018 Relative ROCE Payout		Total Value Earned		2019 VCIP		2017 Relative ROCE Payout		Total Value Earned
Thomas P. Burke	$	3,397,129	$	—	$	3,397,129	$	882,367	$	—	$	882,367
Jonathan Baksht	$	1,202,772	$	425,250	$	1,628,022	$	515,075	$	486,000	$	1,001,075
Michael McGuinty	$	857,704	$	378,000	$	1,235,704	$	443,231	$	432,000	$	875,231

Carl G. Trowell	$	—	$	—	$	—	$	802,288	$	—	$	802,288

(5)The amounts disclosed here represent overseas allowances, premiums paid for group term life insurance, contributions to various benefit plans we sponsor, dividends on share awards, payments in lieu of profit share and certain other payments. Additionally, the 2020 amount disclosed in this column for Mr. Trowell reflects (1) a lump sum cash severance payment of £800,000 (which reflects 60% reduction from his severance entitlement under his employment agreement entered into upon closing the Rowan Transaction); (2) an additional lump sum of £3,000,000 in connection with exceeding pre-defined synergy targets set in connection with the Rowan Transaction; and (3) £29,530 in compensation he received for his services as a non-executive director. Mr. Trowell's payments were made in GBP. However, for disclosure purposes, the payments have been converted from pounds to U.S. dollars using the exchange rate of 1.261, which was the average rate during the period in 2020 where payments were made.

(6)Mr. Trowell stepped down as Executive Chairman on April 30, 2020 and continued to serve as a non-executive director of the Company through our 2020 Annual General Meeting of Shareholders.

Narrative Disclosures to Summary Compensation Tables

Mr. Burke’s Employment Agreement

In connection with his appointment as President and CEO upon the Closing of the Rowan Transaction, Mr. Burke entered into an employment agreement with Rowan Companies Inc., ENSCO Global Resources Limited and Valaris plc (the “Burke Employment Agreement”). The Burke Employment Agreement provides that Mr. Burke will serve as CEO for a term of two years commencing on April 11, 2019 and automatically renews thereafter for successive 12-month periods absent 90 days’ prior notice of nonrenewal.

•Cash & Equity Compensation. The Burke Employment Agreement provides for an initial, annual base salary of $950,000, which he elected to reduce to $855,000 effective January 1, 2020, and an annual target bonus of 110% of base salary. Subject to the approval of the Board or the Compensation Committee, for the first two years of the term, Mr. Burke will be entitled to awards under the Company’s long-term incentive award plans with a target award level of no less than 500% of his base salary, which percentage may be increased or decreased in future years as determined by the Board or the Compensation Committee.

•Benefits. Mr. Burke is eligible to participate in employee benefit plans, programs and arrangements of the Company, including the Company’s expatriate assignment and tax equalization policy in light of Mr. Burke’s required relocation to London, England. Mr. Burke also received benefits under the Company’s relocation policy, including a payment of $20,000 to help cover his relocation expenses.

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•Legacy Rowan Retirement Plans. Mr. Burke also participates in certain legacy Rowan Retirement Plans. These plans consist of a frozen defined benefit plan (the “Rowan Pension Plan”) and a frozen benefit restoration plan of Rowan Companies, Inc. (the “Rowan SERP”), which provides additional retirement benefit accrual opportunities to mitigate the effects of legal limitations on retirement benefits under the Rowan Pension Plan.

•Payment in Lieu of Single Trigger Vesting. In consideration of Mr. Burke’s (1) waiver of single trigger vesting for certain equity awards previously granted to him, (2) waiver of certain change in control and good reason rights pursuant to his existing compensation arrangements, and (3) the cost of living and tax burden associated with his relocation from the United States, Mr. Burke received a one-time payment of $3,750,000 in 2019. This payment is subject to pro-rata reimbursement should Mr. Burke resign without good reason or be terminated for cause prior to April 11, 2022.

•Severance Payments and Benefits. In the event of a termination of Mr. Burke’s employment without cause or his resignation for good reason, subject to his execution of a customary release, he will be entitled to (1) a lump sum payment equal to two times his base salary, (2) a lump sum payment equal to two times the greater of his average annual bonus over the three calendar years preceding his termination or his target annual bonus amount, (3) a pro-rated bonus for the year of termination, (4) subsidized medical, dental and vision coverage for a 24-month period, (5) reimbursement of costs incurred to relocate to the United States, and (6) accelerated vesting of outstanding equity awards. The Burke Employment Agreement also includes customary non-solicitation, non-competition, non-disparagement, confidentiality and intellectual property assignment provisions.

Mr. Trowell's Employment Agreement and Consultancy Agreement

Concurrently with the execution of the transaction agreement with Rowan, Mr. Trowell entered into an employment agreement with ENSCO Services Limited (the "Trowell Employment Agreement"). The Trowell Employment Agreement originally provided that Mr. Trowell would serve as Executive Chairman for a term of eighteen months commencing on April 11, 2019, but was amended in April of 2020 to provide that his term as Executive Chairman and employment with the Company would end on April 30, 2020. Mr. Trowell's non-competition restricted period was extended from 1 year to 2 years, and he agreed to provide consulting services to the Chairman of the Board through December 31, 2020 for no additional remuneration.

•Cash Compensation; VCIP; LTIP. The Trowell Employment Agreement provided for an annual base salary of £450,000 and specified that Mr. Trowell would be eligible to participate in the VCIP. In connection with his separation, Mr. Trowell forfeited his pro-rated VCIP payment for 2020 and any unvested equity awards.

•Benefits. Mr. Trowell was eligible to participate in the same benefit plans and programs in which other executive non-expatriate employees who are based in the United Kingdom are eligible to participate. Since Mr. Trowell was not eligible to participate in the retirement plans in which U.S.-based employees participate, Mr. Trowell was also eligible to receive cash payments equal to the cash amounts that would have been contributed by ENSCO Services Limited on Mr. Trowell's behalf to such retirement plans had he participated in such plans.

•Severance Payments and Benefits. In connection with the termination of Mr. Trowell’s employment as Executive Chairman, Mr. Trowell received (1) a lump sum severance payment of £800,000 and (2) an additional lump sum of £3,000,000 in connection with exceeding pre-defined synergy targets set in connection with the Rowan Transaction. Mr. Trowell agreed to waive his right to receive private medical insurance for a period of up to twenty-four months following the termination date.

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On April 26, 2020, we entered into a consultancy agreement with Mr. Trowell pursuant to which he agreed to provide services (including advisory services) to the Company through December 31, 2020, to facilitate a transition period between his role as Executive Chairman and that of his successor. Mr. Trowell did not receive any remuneration from the Company for providing such services.

2020 Cash Bonuses for Messrs. Baksht and McGuinty

In February 2020, our Board approved the grant of performance-based cash retention payments to each of Messrs. Baksht and McGuinty, in the amounts of $550,000 and $510,000, respectively. Each of the retention payments was to be paid in two, equal installments subject to such officer’s continuous employment through each payment date. The first installment was paid on June 5, 2020. The second installment was included in the upfront retention payments provided to these NEOs in May 2020 as part of the Company's revised VCIP approved on April 30, 2020. All such retention payments are reflected in the “Bonus” column of the Summary Compensation Table and further described in footnote (2) to such table above and under “2020 Cash-Based Awards” below.

2020 Cash-Based Awards

In response to the ongoing significant market uncertainty, the Board of Directors redesigned the Company’s overall compensation program to more appropriately retain and motivate its key employees. Pursuant to this new compensation program, approved by the Board on April 30, 2020 and further revised in November 2020 as part of the Company's ongoing chapter 11 proceedings, the Company implemented strategically designed incentive and retention arrangements to reward its key employees, including its NEOs, if pre-established goals were achieved. The new compensation program started in the second quarter of 2020. No retention payments or incentive payments were earned for the period of January 1, 2020 through March 31, 2020.

The redesigned compensation program included a restructuring of the Valaris Cash Incentive Plan (“VCIP”) for all participants to provide for incentive payments based on quarterly objectives focused on safety, efficiency and cost savings and a retention program. Participation by the executive officers in the new compensation program was contingent upon forfeiture of all 2020 restricted share units and 2020 performance units. For each of the executives, a portion of the executive’s target total direct compensation for 2020 was paid as soon as practicable following May 1, 2020, as a cash retention payment, which is subject to repayment on an after-tax basis in the event of a resignation without good reason or termination by the Company for cause prior to the earlier of the first anniversary of such payment, a change in control or completion of a restructuring. Although the Board approved a cash retention payment for Mr. Burke representing 200% of his annual base pay, he voluntarily reduced such retention payment to 150% of his annual base pay. In addition, as set out in the Company’s definitive proxy statement filed on April 27, 2020, effective January 1, 2020, Mr. Burke had voluntarily reduced his base salary by 10% in light of challenging industry conditions, which reduction will proportionately decrease Mr. Burke’s 2020 target quarterly incentive and retention awards. The remainder of each executive’s target total direct compensation for 2020 (other than base salary) was earned pursuant to quarterly incentive bonuses under the VCIP. The target amount of each executive’s quarterly incentives could be earned at levels ranging from 0% to 150% of the target award value based on the achievement of personal safety, process safety, downtime and expense reductions. See the “Non-Equity Incentive Plan Compensation” column and footnote (4) to the Summary Compensation Table above for additional information on these awards, which were earned at 125% of target for second quarter 2020, 93% of target for third quarter 2020, and 127.5% of target for fourth quarter 2020.

2020 Long-Term Incentive Awards

Each of the named executive officers other than Mr. Trowell were granted restricted share units and performance units on February 27, 2020. The restricted share units were originally scheduled to vest in equal annual installments over a period of three years, and the full grant date fair value of the awards is included in the “Stock Awards” column of the Summary Compensation Table above as required by SEC rules. The performance units could be earned at between 0% and 250% of the target award value based upon the Company’s recurring

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EBITDA improvement over a period from March 31, 2020 through September 30, 2022. These awards were all forfeited as a condition of participation in the VCIP and cash retention program described above.

Perquisites and Other Personal Benefits

In conformity with our Compensation Committee's philosophy, and except with regard to the redomestication benefits described herein, our executive officers receive only limited perquisites. Other than in connection with qualifying terminations of employment, our executive officers are eligible to receive company-paid or company-subsidized life insurance, medical and disability coverage on the same basis as our other employees. Certain of our executives also receive overseas allowances and reimbursements, which include monthly housing, cost of living, annual vacation and a dependence tuition allowance. Such amounts provided to our NEOs during 2020 are included in the "All Other Compensation Table". The London-based executive expatriate package provides tax equalization on housing allowances and non-cash expatriate benefits, such as dependent tuition allowance.

Outstanding Equity Awards at Fiscal Year-End Table for the Year Ended December 31, 2020

The following table sets forth the outstanding equity awards held by each of our NEOs as of December 31, 2020. In accordance with his 2019 separation agreement, Mr. Trowell forfeited his 2019 restricted share units. Additionally, in accordance with the April 2020 amendment to his employment agreement, Mr. Trowell forfeited all remaining unvested equity awards as of April 30, 2020. Grants under the 2018 LTIP are subject to applicable bankruptcy law and settlement of vested share awards and cash-settled awards (each as defined below) held by insiders has been delayed until the Company’s emergence from Chapter 11, at which point, such awards are expected to be cancelled unless the insider elects to have their award treated in accordance with the terms of the Chapter 11 plan.


	Options/ SAR Awards			Share Awards				Equity Incentive Plan Awards
Name	Securities Underlying Exercisable Options/ SARs (#)	Option/ SARs Exercise Price ($)	Option/ SARs Expiration Date	Year Granted	Shares That Have Not Vested (#)		Market Value of Shares That Have Not Vested ($)		Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)(1)(2)
Thomas P. Burke	244,025	25.58	2/22/2024	2020	—	(3)	—		—
	18,385	61.40	2/25/2021	2019	184,812	(3)	9,241		N/A
	21,594	51.60	3/07/2022	2018	39,795	(3)	1,990		N/A
	32,078	49.97	3/06/2023	2017	195,478	(3)	9,774		N/A

Carl G. Trowell	—	—	—	2020	—	(4)	—		—
	—	—	—	2019	—	(4)	—		—
	—	—	—	2018	—	(4)	—		—

Jonathan Baksht	—	—	—	2020	—	(5)	—		—
	—	—	—	2019	26,658	(5)	1,333		—
	—	—	—	2018	12,045	(5)	602		270,000

Michael McGuinty	—	—	—	2020	—	(6)	—		—
	—	—	—	2019	23,696	(6)	1,185		—
	—	—	—	2018	10,707	(6)	535		240,000

(1)The TSR performance unit awards granted in 2018 and 2019 are disclosed within this column. The 2018 and 2019 TSR performance unit awards are valued at target. As for 2020 performance awards, these awards were forfeited and cash retention bonuses were awarded in place of shares and awards.

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(2)Mr. Trowell forfeited his 2017, 2018 and 2019 performance awards upon the close of the Rowan Transaction and loss of office as President & Chief Executive Officer.

(3)195,478 shares vested on February 22, 2021; 30,521 shares vested on February 27, 2021; 9,274 shares are scheduled to vest on March 1, 2021; and 92,406 shares are scheduled to vest annually until February 26, 2022, in each case except as may be deferred during certain specified regular or special blackout periods.

(4)In accordance with his 2019 separation agreement, Mr. Trowell forfeited his 2019 restricted share units. Additionally, in accordance with the April 2020 amendment to his employment agreement, Mr. Trowell forfeited all remaining unvested equity awards as of April 30, 2020.

(5)12,045 shares are scheduled to vest on March 5, 2021; and 13,329 shares are scheduled to vest annually until March 6, 2022, in each case except as may be deferred during certain specified regular or special blackout periods.

(6)10,707 shares are scheduled to vest on March 5, 2021; and 11,848 shares are scheduled to vest annually until March 6, 2022, in each case except as may be deferred during certain specified regular or special blackout periods.

Other Compensation Matters

Retirement Benefits

Executive officers may participate on the same basis as other employees in the employer matching provisions of our defined contribution savings plans on a tax-deferred basis. For 2019, the maximum total matching contribution available to executive officers and other employees who participated in the Ensco Savings Plan (a qualified 401(k) plan), SERP, Ensco Multinational Savings Plan or the Ensco Limited Retirement Plan was 5% of eligible salary. The matching contributions to our NEOs are reported in the "All Other Compensation" column of the Summary Compensation Table.

The SERP was created to provide an additional tax-deferred savings vehicle for certain highly-compensated employees, including our NEOs, whose participation in the 401(k) savings plan features of the Ensco Savings Plan was restricted due to contribution limitations of the U.S. Internal Revenue Code of 1986, as amended. Executive officers who participate in the SERP could elect to defer a portion of their base salary and/or annual cash bonus payments up to a percentage specified annually by our Compensation Committee and ratified by our Board. For 2019, the maximum salary deferral was 50%, inclusive of the 5% 401(k) contribution, and 100% of the annual VCIP bonus payments made in 2019, consistent with prior years.

The SERP is administered by a third party, and deferred compensation may be invested in authorized funds similar to the investment options available under the Ensco Savings Plan. Investments also may be made in funds or publicly-traded securities on a self-directed basis. The SERP was frozen to new participants in November of 2019 and frozen to new contributions effective January 1, 2020.

Termination or Change in Control Payments and Benefits

Severance Payments and Benefits under Burke Employment Agreement.

Upon a termination of Mr. Burke’s employment without cause or a resignation for good reason, Mr. Burke would be eligible to receive severance payments and benefits, subject to his execution and non-revocation of a release of claims. He would only be eligible to receive such payments and benefits under the Burke Employment Agreement if he is not eligible to receive benefits under his change-in-control agreement, which is further described below.

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Commencing on April 11, 2022, Mr. Burke would be eligible to receive the following payments and benefits:

•an amount in cash equal to two times his base salary;

•an amount in cash equal to two times his ‘‘Average Bonus Amount’’ (i.e., the greater of: (A) the average of the combined annual bonus awards received by Mr. Burke pursuant to Valaris’ annual incentive plan in the three calendar years immediately before the date of termination (including the annual bonus awards received from Rowan) and (B) Mr. Burke’s target annual bonus for the year during which the termination of employment occurs);

•a pro-rated portion of the annual bonus award that Mr. Burke would have earned had he remained employed through the end of the fiscal year in which the date of termination occurs based upon actual performance for such year (and, to the extent there is any discretionary component thereof, with the discretionary aspects being determined at not less than the target level);

•continued coverage in the employer provided medical, dental and vision plans available to Mr. Burke and his eligible dependents immediately prior to the date of termination, to the extent such coverage is elected by Mr. Burke pursuant to COBRA, for a period of twenty-four months following the date of termination;

•reimbursement of the reasonable cost of return relocation-related expenses (not including make-whole payments for any loss incurred on the sale of Mr. Burke’s principal residence);

•any of Mr. Burke’s unvested equity, equity-based or long-term incentive awards granted under any equity or long-term incentive plans of Valaris or Rowan will immediately become 100% vested in all of the rights and interests then held by Mr. Burke, provided, however, that unless a provision more favorable to Mr. Burke is included in an applicable award agreement, all performance-based awards will remain subject to attaining the applicable performance goals and conditions.

Severance Payments and Benefits under Legacy Rowan Change in Control Agreement.

Until April 11, 2022, Mr. Burke will be eligible for severance under his change in control agreement. This agreement provides for severance payments and benefits upon a qualifying termination that occurs within six months prior to a change in control or twenty-four months following a change in control (and the Rowan transaction constituted a change in control for these purposes). A qualifying termination includes a termination without cause or a resignation by the executive for good reason. Upon a qualifying termination Mr. Burke would be eligible to receive the following payments and benefits:

•a lump-sum cash payment equal to (I) 2.99 times the sum of (a) his base salary plus (b) the greater of (1) the average short-term incentive bonuses awarded to him in respect of the three calendar years prior to the year in which the date of termination occurs or (2) his target short-term incentive bonus under the then-current annual incentive plan for the calendar year in which the date of termination occurs, plus (II) an amount equal to the sum of (a) with respect to the non-discretionary portion of any short-term incentive bonus opportunity for the calendar year of his termination, a pro-rated portion of the amount that would be payable assuming the applicable performance period ended as of the month-end immediately preceding the date of termination and based on the attainment of such measures as of such month-end, and (b) with respect to any discretionary portion of his short-term incentive bonus opportunity for the calendar year of termination, a pro-rated portion of the target amount of such bonus, plus (III) any accrued but unused vacation and sick pay as of the date of termination;

•continued medical coverage substantially similar to that provided prior to Mr. Burke’s termination of employment at no greater cost than that paid by him prior to the termination of employment through the earlier of 3 years following the termination of employment or the date Mr. Burke otherwise becomes eligible for healthcare under a subsequent employer's health plan; and

•outplacement services for a period of one year from the date of termination or, if earlier, until the first acceptance by Mr. Burke of an offer of employment from a subsequent employer. However, the aggregate amount of the cost for such outplacement services will not exceed $25,000.

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Executive Severance Plan

The Company adopted an Executive Severance Plan (the “Severance Plan”), which was most recently amended and restated effective April 30, 2020. The Severance Plan provides eligible individuals, including each of the Company’s Senior Vice Presidents and Executive Vice Presidents, with the following separation payments and benefits in the event of a qualifying termination, subject to the executive executing and not revoking a release of claims and complying with certain restrictive covenants:

•Cash severance in an amount equal to 100% (for Senior Vice Presidents) or 150% (for Executive Vice Presidents) of the executive’s annual base salary;

•A cash payment equal to the participant's target bonus for the performance period in which the termination occurs;

•Forfeiture of all outstanding restricted share units, restricted shares and cash performance units granted prior to November 10, 2019;

•Accelerated vesting of all outstanding restricted share units and restricted shares granted on or following November 10, 2019;

•Accelerated vesting of a pro-rata portion of outstanding cash performance units granted on or following November 10, 2019 based on actual results realized over the performance period;

•Continued group health plan coverage (or a cash payment equivalent thereto) and eligibility to receive outplacement services for a period of twelve months; and

•Discretionary reimbursement of up to $1,500 or £1000, for any legal fees actually incurred by or on behalf of the Severance Plan participant in connection with the execution of a release of claims.

Director Compensation

Compensation of Non-Executive Directors

For 2020, the Board used retainer fees to attract and retain qualified candidates to serve on the Board. Our Board periodically reviews non-executive director compensation, which includes review of data received from third party compensation consultants and, from time to time, recommends changes to the Board. Alvarez & Marsal was engaged in 2020 to review non-executive director compensation in light of the market uncertainty caused by the COVID-19 pandemic, the precipitous decline in the price of oil and the Company's possible balance sheet restructuring. Following the review of this information, our Board converted the annual director equity grant to cash. Effective May 1, 2020, non-executive director compensation consisted entirely of a cash-based retainer paid quarterly. Non-executive directors did not receive an annual equity award for the 2020-2021 service year. Total non-executive director compensation generally is intended to approximate the median of our compensation peer group companies.

Annual Retainer Fees

The compensation of our non-executive directors for the 2020-2021 service year consisted entirely of cash with an annual retainer of $300,000. Additional annual retainers were paid as follows: Independent Lead Director $25,000; Audit Committee Chair $20,000; Compensation Committee Chair $15,000; Finance Committee Chair $15,000; the Special Committee & NGS Committee Chair $10,000 and Non-Executive Chairman $75,000. All retainer fees are paid quarterly in advance and are prorated for a partial quarter of service as a director, Non-Executive Chairman, Independent Lead Director or Committee Chair.

Mr. Burke did not receive any additional compensation for his services as an executive director in 2020. Mr. Trowell's services as an executive director ended on June 15, 2020, and he also did not receive any additional compensation for his services as an executive director. Mr. Trowell received payments in accordance with the non-

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executive director compensation program described above for the period from his April 30, 2020 resignation as Executive Chairman through his June 15, 2020 retirement from the Board, which amounts are included in the All Other Compensation column of the Summary Compensation table above.

The compensation paid to non-executive directors that served on our Board in 2020 is reported in the Director Compensation Table as follows:

Director Compensation Table

For the Year Ended 31 December 2020


Name	Fees Earned or Paid in Cash ($)	Share Awards ($)(1)	All Other Compensation ($)(2)	Total ($)
William E. Albrecht	239,583	—	354	239,937
Fredrick Arnold	233,333	—	7,333	240,666
Mary E. Francis CBE	233,333	—	997	234,330
Georges J. Lambert	233,333	—	—	233,333
Suzanne P. Nimocks	245,833	—	7,688	253,521
Thierry Pilenko	233,333	—	—	233,333
Keith O. Rattie(3)	49,130	—	2,306	51,436
Paul E. Rowsey, III	297,917	—	—	297,917
Charles L. Szews	258,388	—	11,649	270,037
Adam Weitzman(4)	164,652	65,575	—	230,227

____________________

(1)The amounts disclosed in this column represent the aggregate grant date fair value of restricted share units awarded to current directors during 2020. Grant date fair value for restricted share units is measured using the market value of our shares on the date of grant. Mr. Weitzman received a pro-rated equity award on February 4, 2020 in connection with his partial 2019-2020 service year. Non-executive directors did not receive any equity compensation for the 2020-2021 service year.

As of 31 December 2020, the total number of share and unit awards held by each of our non-executive directors was as follows:


Name	Number of Non-Deferred RSUs Held	Number of Deferred RSUs Held
William E. Albrecht	—	35,492
Fredrick Arnold	—	—
Mary E. Francis CBE	2,533	—
Georges J. Lambert	—	—
Suzanne P. Nimocks	—	30,085
Thierry Pilenko	—	42,186
Paul E. Rowsey, III	3,483	—
Charles L. Szews	—	6,076

No stock options were granted to our directors during 2020, and there were no stock options held by any of our non-executive directors as of December 31, 2020.

(2)Amounts disclosed primarily represent payments made by the Company on behalf of the directors during 2020 for contributions to group health and welfare insurance.

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(3)Mr. Rattie retired from the Board on June 15, 2020.

(4)Mr. Weitzman was appointed as a director on February 1, 2020 and resigned from the Board on August 28, 2020 at which time he forfeited all remaining unvested equity awards.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

Ownership of Voting Securities

The following tables show amounts and percentages of our Class A ordinary shares (the only class of our securities outstanding and eligible to vote) owned beneficially as of February 22, 2021 by (1) each person or group known by us to beneficially own more than 5% of our outstanding shares; (2) each of our directors as of the date of this annual report; (3) each of our NEOs identified in the 2020 Summary Compensation Table; and (4) all of our directors and executive officers as a group as of the date of this annual report.

Beneficial Ownership Table


	Beneficial Ownership(1)
Name of Beneficial Owner	Amount	Percentage
Luminus Management LLC	10,183,145	5.11	%	(2)
1700 Broadway, 26th Floor
New York, NY 10019

Named Executive Officers
Thomas P. Burke	737,066	—	%	(3)
President and Chief Executive Officer
Jonathan Baksht	56,872	—	%	(3)
Executive Vice President and Chief Financial Officer
Michael McGuinty	48,144	—	%	(3)
Senior Vice President, General Counsel and Secretary
Carl G. Trowell	225,402	—	%	(3)
Former Executive Chairman
Independent Directors
Paul E. Rowsey, III	57,426	—	%	(3)
Director
Mary E. Francis CBE	15,386	—	%	(3)
Director
Suzanne P. Nimocks	20,457	—	%	(3)
Director
William E. Albrecht	—	—	%	(3)
Director
Frederick Arnold	3,750	—	%	(3)
Director
Georges J. Lambert	—	—	%	(3)
Director
Thierry Pilenko	687	—	%	(3)
Director
Charles L. Szews	38,751	—	%	(3)
Director
All current directors and executive officers as a group (13 persons)	1,136,928	—	%	(3)

____________________

(1)As of February 22, 2021, there were 199,613,642 shares outstanding. Unless otherwise indicated, each person or group has sole voting and dispositive power with respect to all shares.

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(2)Based on the Schedule 13D/A filed on September 15, 2020, Luminus Management LLC ("Luminus") may be deemed the beneficial owner of 10,183,145 shares, Luminus reports shared voting power over 10,183,145 shares and shared dispositive power over 10,183,145 shares.

(3)Ownership is less than 1% of our shares outstanding.

Equity Compensation Plan Information

The following table summarizes certain information related to our compensation plans under which our shares are authorized for issuance as of December 31, 2020:


Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))(1)
	(a)	(b)(1)		(c)
Equity compensation plans approved by security holders	—	$	—	12,213,179
Equity compensation plans not approved by security holders(2)	744,426	49.68		2,776,266
Total	744,426	$	49.68	14,989,445

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(1)			Restricted share units and restricted shares do not have an exercise price and, thus, are not reflected in this column.
(2)			Under the 2018 Long-Term Incentive Plan, 12.2 million shares remained available for future issuances of non-vested share awards, share option awards and performance awards as of December 31, 2020.
			In connection with the Pride acquisition, we assumed Pride's option plan and the outstanding options thereunder. As of December 31, 2020, options to purchase 5,000 shares at a weighted-average exercise price of $170.52 per share were outstanding under this plan. No shares are available for future issuance under this plan, no further options will be granted under this plan and the plan will be terminated upon the earlier of the exercise or expiration date of the last outstanding option. In connection with the Atwood acquisition, we assumed Atwood’s Amended and Restated 2007 Long-Term Incentive Plan (the “Atwood LTIP”) and the options outstanding thereunder. As of December 31, 2020, options to purchase 69,352 shares at a weighted-average exercise price of $104.00 per share were outstanding under this plan. There were also 199,669 shares remaining available for future issuance, which we may grant to employees and other service providers who were not employed or engaged with us prior to the Atwood acquisition. The Atwood LTIP, which we adopted in connection with the Atwood acquisition, provides for discretionary equity compensation awards. Awards may be granted in the form of share options, restricted share awards, share appreciation rights and performance share or unit awards. All future awards granted under the Atwood LTIP will be subject to such terms and conditions, including vesting terms, as may be determined by the plan administrator at the time of grant. Following the Atwood acquisition, the Atwood LTIP is administered by and all award decisions will be made on a discretionary basis by our Compensation Committee or Board of Directors. In connection with the Rowan Transaction, we assumed the Amended and Restated 2013 Rowan Companies plc Incentive Plan (the “Rowan LTIP”) and the non-vested share awards, options, and share appreciation rights outstanding thereunder. As of December 31, 2020, options to purchase 244,025 shares at a weighted-average exercise price of $25.58 per share, 426,049 share appreciation rights at a weighted-average exercise price of $53.23 per share and 1,281,899 restricted share units were outstanding under this plan. There were also 2,576,597 shares remaining available for future issuance, which we may grant to employees and other service providers who were not employed or engaged with us prior to the Rowan Transaction. The Rowan LTIP, which we adopted in connection with the Rowan Transaction, provides for discretionary equity compensation awards. Awards may be granted in the form of share options, restricted share or unit awards, share appreciation rights and performance share or unit awards. All future awards granted under the Rowan LTIP will be subject to such terms and conditions, including vesting terms, as may be determined by the plan administrator at the time of grant. Following the Rowan Transaction, the Rowan LTIP is administered by and all award decisions will be made on a discretionary basis by our Compensation Committee or Board of Directors.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Related Party Transactions

On January 24, 2020, the Company entered into a Cooperation and Support Agreement (the “Support Agreement”) with Luminus Management LLC ("Luminus") pursuant to which the Company agreed to reimburse Luminus for certain reasonable, documented out-of-pocket fees and expenses incurred in connection with Luminus' engagement with the Company. In 2020, the Company paid $3,000,000 to Luminus and $575,324.74 to Torque Point, an advisor that Luminus required the Company to hire pursuant to the Support Agreement. There were no related party transactions required to be reported for 2019 as defined under SEC rules.

Director Independence

Our Articles of Association and Corporate Governance Policy state that at least a majority of the Board shall be independent, as the term is defined by SEC rules and NYSE Corporate Governance Standards. Except with

199

respect to their directorships and as set forth below, we do not have any business or other relationships with our independent directors. Only independent directors serve on the Board's standing committees (audit, compensation and nominating, governance and sustainability committees). In this regard, our Board has affirmatively determined that all directors (with the exception of Mr. Burke) (being Mr. Albrecht, Mr. Arnold, Ms. Francis, Mr. Lambert, Ms. Nimocks, Mr. Pilenko. Mr. Rowsey and Mr. Szews) are independent and have no material relationship with us. In addition, the Board affirmatively determined that each of Messrs. Rattie and Weitzman were independent during the period in 2020 when each such person served on the Board. Accordingly, a substantial majority of our Board currently is independent as defined above. In reaching its independence determinations, the Nominating, Governance and Sustainability Committee and the Board considered the following:

•During 2019, Mr. Pilenko was employed by an organization that does business with Valaris. The amount received by Valaris or such other organization in each of the last three fiscal years did not exceed the greater of $1 million or 1% of either Valaris' or such organization's consolidated gross revenues.

•During 2019 and 2020, Mr. Albrecht served on the Board of Directors of organizations that does business with Valaris. The amount received by Valaris or such other organization in each of the last three fiscal years did not exceed the greater of $1 million or 1% of either Valaris’s or such organization's consolidated gross revenues.

•During 2019, Ms. Francis served on the Board of Directors of an organization that did business with Valaris. The amount received by Valaris or such other organization in each of the last three fiscal years did not exceed the greater of $1 million or 1% of either Valaris’s or such organization's consolidated gross revenues.

Our Corporate Governance Policy provides that a director who changes his or her principal occupation shall promptly notify the Board of the change and submit a pro-forma letter of resignation to the Board. Under this policy, the other directors shall then meet in private session, determine whether the change of occupation impacts the director's independence or creates a conflict of interest and decide whether to accept or reject the pro-forma resignation.

Each of our directors has prepared a Director Declaration of Interest, disclosing existing or potential conflicts of interest, in conformity with U.K. law, custom and practice. The declarations are prepared and reviewed by the Board at least annually. The Board conducted an annual review of Director Declarations of Interest during its February 2021 Board meeting.

Item 14. Principal Accounting Fees and Services

Fees and Services

Consistent with SEC rules and policies regarding auditor independence, the Audit Committee has responsibility for appointing and approving the compensation and overseeing the work of our U.S. independent registered public accounting firm. In recognition of this responsibility, the Audit Committee has established a policy to pre-approve all audit and permissible non-audit services provided by our U.S. independent registered public accounting firm. Under the policy, we submit an itemized listing of all services to the Audit Committee for which pre-approval is requested. Such listing includes a description of each proposed service, the associated estimated fees and other terms of the engagement. To the extent any such service is a non-audit service, the submission includes an explanation as to why such service qualifies as a permitted non-audit service and why providing such service would not impair the independence of our U.S. independent registered public accounting firm or our U.K. statutory auditors.

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The aggregate fees (excluding value added taxes) billed to us for the fiscal years ended 31 December 2020 and 2019 by KPMG LLP (U.S.) and its affiliates (including KPMG LLP (U.K.)) were as follows (in thousands):


	2020		2019
Audit Fees(1)	$	3,270	$	4,226
Tax Fees(2)	787		1,094
	$	4,057	$	5,320

____________________

(1)Includes fees for the audit of our annual consolidated financial statements and audit of the effectiveness of our internal control over financial reporting included in our annual report on Form 10-K, reviews of condensed consolidated financial statements included in our quarterly reports on Form 10-Q, the audit of our U.K. statutory accounts, audits of certain subsidiary statutory accounts and procedures conducted in connection with debt or equity transactions and consents to incorporate KPMG LLP (U.S.)'s reports into registration statements filed with the SEC for each respective year.

(2)Represents fees for tax compliance and other tax-related services.

Our Audit Committee pre-approved the services provided during 2020 and 2019 described above, in accordance with our Audit Committee's policy and the pre-approval requirements of the Sarbanes-Oxley Act of 2002, as amended (the "Sarbanes-Oxley Act"). Accordingly, there were no services for which the de minimus exception, as defined in Section 202 of the Sarbanes-Oxley Act, was applicable. Our Audit Committee has considered whether the provision of non-audit services by KPMG LLP (U.S.) were compatible with maintaining KPMG LLP (U.S.)'s independence and has determined that the provision of such non-audit services does not undermine KPMG LLP (U.S.)'s independence.

PART IV

Item 15. Exhibits, Financial Statement Schedules


(a)	The following documents are filed as part of this report:
	1. Financial Statements
	Reports of Independent Registered Public Accounting Firm	102

	Consolidated Statements of Operations	107

	Consolidated Statements of Comprehensive Income	108

	Consolidated Balance Sheets	109

	Consolidated Statements of Cash Flows	110

	Notes to Consolidated Financial Statements	111


			2. Exhibits

201


Exhibit Number						Exhibit


3.1						Certificate of Incorporation on Change of Name (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on April 1, 2010, File No. 1-8097).

3.2						Articles of Association of Valaris plc (incorporated by reference to Annex 2 to the Registrant's Proxy Statement on Form DEF 14A filed on April 5, 2013, as adopted by Special Resolution passed on May 20, 2013, File No. 1-8097).

3.3						Articles of Association adopted by Ensco Jersey Finance Limited, a wholly-owned subsidiary of the Registrant on December 6, 2016 (incorporated by reference to Exhibit 3.1 to the Registrant's Current Report on Form 8-K filed on December 12, 2016, File No. 1-8097).

4.1						Indenture, dated November 20, 1997, between ENSCO International Incorporated and Deutsche Bank Trust Company Americas (successor to Bankers Trust Company), as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).

4.2						First Supplemental Indenture, dated November 20, 1997, between ENSCO International Incorporated and Deutsche Bank Trust Company Americas (successor to Bankers Trust Company, as Trustee (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on November 24, 1997, File No. 1-8097).

4.3						Second Supplemental Indenture, dated December 22, 2009, among ENSCO International Incorporated, Ensco International plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

4.4						Form of Debenture (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on November 24, 1997, File No. 1-8097).

4.5						Indenture, dated July 1, 2004, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (successor to JPMorgan Chase Bank) (incorporated by reference to Exhibit 4.1 to Pride's Registration Statement on Form S-4 filed on August 10, 2004, File No. 333-118104).

4.6						Third Supplemental Indenture, dated August 6, 2010, between Pride International, Inc. and The Bank of New York Mellon, as Trustee, including the form of notes issued pursuant thereto (incorporated by reference to Exhibit 4.3 to Pride's Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 1-13289).

4.7						Fourth Supplemental Indenture, dated May 31, 2011, among Valaris plc, Pride International, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).

4.8						Form of Guarantee by Valaris plc (incorporated by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K filed on May 31, 2011, File No. 1-8097).

4.9						Indenture, dated March 17, 2011, between Valaris plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.22 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).

4.10						First Supplemental Indenture, dated March 17, 2011, between Valaris plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).

4.11						Second Supplemental Indenture, dated as of September 29, 2014, between Valaris plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q filed on October 30, 2014, File No.1-8097).

4.12						Third Supplemental Indenture, dated as of March 12, 2015, between Valaris plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on March 12, 2015, File No. 1-8097).

4.13						Fourth Supplemental Indenture, dated as of January 9, 2017, between Valaris plc and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on January 11, 2017, File No. 1-8097).

202


4.14						Fifth Supplemental Indenture dated as of January 26, 2018, by and between the Company and Deutsche Bank Trust Company Americas, as trustee (incorporated herein by reference to Exhibit 4.2 to Registrant's Current Report on Form 8-K filed on January 26, 2018, File No. 001-08097).

4.15						Sixth Supplemental Indenture, dated July 12, 2019, among Valaris plc and Deutsche Bank Trust Company Americas, as trustee, incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K filed on July 12, 2019 (File No. 1-08097).

4.16						Form of Note for 4.50% Senior Notes due 2024 (incorporated by reference to Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No.1-8097).

4.17						Form of Note for 5.75% Senior Notes due 2044 (incorporated by reference to Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No.1-8097).

4.18						Form of Note for 5.20% Senior Notes due 2025 (incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on March 12, 2015, File No. 1-8097).

4.19						Form of Note for 7.75% Senior Notes due 2026 (incorporated herein by reference to Exhibit 4.2 to Registrant's Current Report on Form 8-K filed on January 26, 2018, File No. 001-08097).

4.20						Form of Global Note for 4.700% Senior Notes due 2021 (incorporated by reference to Exhibit B of Exhibit 4.23 to Post-Effective Amendment No. 2 to the Registrant's Registration Statement on Form S-3 filed on March 17, 2011, File No. 333-156705).

4.21						Form of Note for 8.00% Senior Notes due 2024 (incorporated by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K filed on January 11, 2017, File No. 1-8097).

4.22						Form of Deed of Release of Shareholders (incorporated by reference to Annex A to the Registrant's Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).

4.23						Indenture, dated as of December 12, 2016, among Ensco plc, Ensco Jersey Finance Limited and Deutsche Bank Trust Company Americas, as Trustee (incorporated by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on December 12, 2016, File No. 1-8097).

4.24						Form of 3.00% Exchangeable Senior Note due 2024 (incorporated by reference to Exhibit A of Exhibit 4.1 to the Registrant's Current Report on Form 8-K filed on December 12, 2016, File No. 1-8097).

4.25						Deed Poll, dated as of December 12, 2016, executed by Ensco plc (incorporated by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K filed on December 12, 2016, File No. 1-8097).

4.26						Indenture for Senior Debt Securities dated as of July 21, 2009, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.1 of Rowan's Current Report on Form 8-K filed on July 21, 2009 (File No. 1-5491).

4.27						Third Supplemental Indenture dated as of May 4, 2012, among Rowan Companies, Inc., Rowan and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.4 to Rowan's Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).

4.28						Fourth Supplemental Indenture, dated as of May 21, 2012, among Rowan Companies, Inc., Rowan and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Rowan's Current Report on Form 8-K filed on May 21, 2012, File No. 1-5491).

4.29						Form of 4.875% Senior Note due 2022, incorporated by reference to Exhibit 4.2 to Rowan's Current Report on Form 8-K filed on May 21, 2012 (File No. 1-5491).

4.30						Fifth Supplemental Indenture dated as of December 11, 2012, among Rowan Companies, Inc., Rowan and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.3 to Rowan ’s Current Report on Form 8-K filed on December 11, 2012 (File No. 1-5491).

4.31						Form of 5.4% Senior Note due 2042, incorporated by reference to Exhibit 4.3 to Rowan's Current Report on Form 8-K filed on December 11, 2012 (File No. 1-5491).

4.32						Sixth Supplemental Indenture dated as of January 15, 2014, among Rowan Companies, Inc., Rowan and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of Rowan's Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).

4.33						Form of 4.75% Senior Note due 2024, incorporated by reference to Exhibit 4.2 of Rowan's Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).

203


4.34						Seventh Supplemental Indenture dated as of January 15, 2014, among Rowan Companies, Inc., Rowan and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.3 of Rowan ’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).

4.35						Form of 5.85% Senior Note due 2044, incorporated by reference to Exhibit 4.3 of Rowan's Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).

4.36						Eighth Supplemental Indenture dated as of December 19, 2016, among Rowan Companies, Inc., Rowan's and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of Rowan's Current Report on Form 8-K filed on December 19, 2016 (File No. 1-5491).

4.37						Form of 7.375% Senior Note due 2025, incorporated by reference to Exhibit 4.2 of Rowan's Current Report on Form 8-K filed on December 19, 2016 (File No. 1-5491).

4.38						Ninth Supplemental Indenture, dated as of June 7, 2019, among Rowan Companies, Inc., Rowan Companies Limited, as guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on June 11, 2019, File No. 1-8097).

4.39						Tenth Supplemental Indenture, dated as of February 3, 2020, among Rowan Companies, LLC (formerly Rowan Companies, Inc.), Rowan Companies Limited, Valaris plc and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on February 3, 2020, File No. 1-8097).

4.40						Eleventh Supplemental Indenture, dated as of September 10, 2020, among Valaris plc, U.S. Bank National Association, as trustee and prior trustee, and UMB Bank, National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of the Registrant’s Quarterly Report on Form 10-Q filed on October 29, 2020, File No. 1-8097).

4.41						Interim Order [I] Approving Notification and Hearing Procedures for Certain Transfers of and Declarations of Worthlessness with Respect to Common Stock, and [II] Granting Related Relief Docket No. 110 (incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on August 25, 2020, File No. 1-8097).

4.42						Description of the Company’s Class A Ordinary Shares (incorporated by reference to Exhibit 4.42 of the Registrant’s Annual Report on Form 10-K filed on February 21, 2020, File No. 1-8097).

10.1						Fourth Amended and Restated Credit Agreement, dated May 7, 2013, by and among Ensco plc, and Pride International, Inc., as Borrowers, the Banks named therein, Citibank, N.A., as Administrative Agent, DNB Bank ASA, as Syndication Agent, Deutsche Bank Securities Inc., HSBC Bank USA, NA and Wells Fargo Bank, National Association, as Co-Documentation Agents, and Citigroup Global Markets Inc., DNB Markets, Inc., Deutsche Bank Securities Inc., HSBC Securities (USA) Inc. and Wells Fargo Securities, LLC, as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 13, 2013, File No. 1-8097).

10.2						First Amendment to the Fourth Amended and Restated Credit Agreement, dated as of September 30, 2014, by and among Ensco plc, and Pride International, Inc., the lenders named therein, and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on October 1, 2014 File No. 1-8097).

10.3						Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of March 9, 2015, by and among Ensco plc, Pride International, Inc., the lenders party thereto and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on March 12, 2015 File No. 1-8097).

10.4						Third Amendment to Fourth Amended and Restated Credit Agreement, dated as of July 1, 2016, by and among Ensco plc, Pride International, Inc., the lenders party thereto and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report filed on Form 10-Q on October 27, 2016 File No. 1-8097).

10.5						Extension Agreement to Fourth Amended and Restated Credit Agreement, dated October 4, 2016, by and among Ensco plc, Pride International, Inc., the lenders party thereto and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report filed on Form 10-Q on October 27, 2016 File No. 1-8097).

10.6						Fourth Amendment to Fourth Amended and Restated Credit Agreement, dated as of December 15, 2016, by and among Ensco plc, Pride International, Inc., the lenders party thereto and Citibank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on December 16, 2016 File No. 1-8097).

204


10.7						Commitment Agreement and Fifth Amendment to Fourth Amended and Restated Credit Agreement, dated as of October 3, 2017, among Ensco plc, Pride International LLC, certain other subsidiaries of Ensco plc party thereto, Citibank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on October 6, 2017 File No. 1-8097).

10.8						Commitment Increase Agreement and Sixth Amendment to Fourth Amended and Restated Credit Agreement, dated as of April 9, 2019, among Ensco plc, Pride International LLC, certain other subsidiaries of Ensco plc party thereto, Citibank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 of the Registrant's Current Report on Form 8-K filed on April 11, 2019, File No. 1-8097).

10.9						Waiver to Fourth Amended and Restated Credit Agreement, dated as of June 1, 2020 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report filed on Form 8-K filed on June 1, 2020, File No. 1-8097).

10.10						Amended and Restated Waiver to Fourth Amended and Restated Credit Agreement, dated as of June 30, 2020 (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097).

10.11						Second Amended and Restated Waiver to Fourth Amended and Restated Credit Agreement, dated as of July 15, 2020 (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report filed on Form 10-Q on October 29, 2020, File No. 1-8097).

10.12						Third Amended and Restated Waiver to Fourth Amended and Restated Credit Agreement, dated as of August 3, 2020 (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report filed on Form 10-Q on October 29, 2020, File No. 1-8097).

10.13						Senior Secured Superpriority Debtor-in-Possession Credit Agreement, dated as of September 25, 2020, by and among Valaris plc, the subsidiary guarantors party thereto, the lenders party thereto and Wilmington Savings Fund Society, FSB (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report filed on Form 8-K on September 28, 2020, File No. 1-8097).

10.14						Rowan Asset Transfer and Contribution Agreement, dated as of November 21, 2016, between Rowan Rex Limited and Saudi Aramco Development Company (incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097).

10.15						Amendment No. 1 to Rowan Asset Transfer and Contribution Agreement, dated as of October 17, 2017, by and between Saudi Aramco Development Company, Rowan Rex Limited and Saudi Aramco Rowan Offshore Drilling Company (incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097).

10.16						Shareholders’ Agreement dated 21 November 2016 (G) between Saudi Aramco Development Company and Rowan Rex Limited Relating to the Offshore Drilling Joint Venture (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report filed on Form 10-Q on August 1, 2019, File No. 1-8097).
10.17*						Amendment No. 1 to the Shareholders' Agreement dated December 18, 2017 between Saudi Aramco Development Company, Rowan Rex Limited and ARO

10.18*						Amendment No. 2 to the Shareholders' Agreement dated June 28, 2018 between Saudi Aramco Development Company, Rowan Rex Limited, ARO and Mukamala Oil Field Services Limited

10.19*						Amendment No. 3 to the Shareholders' Agreement dated August 13, 2020 between Rowan Rex Limited, Mukamala Oil Field Services Limited and ARO

10.20*						Amendment No. 4 to the Shareholders' Agreement dated December 1, 2020 between Rowan Rex Limited, ARO and Mukamala Oil Field Services Limited

+10.21						Form of Deed of Release of Directors (incorporated by reference to Annex B to the Registrant's Proxy Statement on Schedule 14A filed on April 5, 2011, File No. 1-8097).

+10.22						Form of Deed of Indemnity for Directors and Executive Officers of Ensco plc (incorporated by reference to Exhibit 10.27 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 1-8097).

+10.23						ENSCO Non-Employee Director Deferred Compensation Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).

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+10.24						Amendment No. 1 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated March 11, 2008 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).

+10.25						Amendment No. 2 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated August 4, 2009 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.26						Amendment No. 3 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated December 22, 2009 (incorporated by reference to Exhibit 10.11 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.27						Amendment No. 4 to the ENSCO Non-Employee Director Deferred Compensation Plan, dated May 14, 2012 (incorporated by reference to Exhibit 10.7 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).

+10.28						ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).

+10.29						Amendment No. 1 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated March 11, 2008 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, File No. 1-8097).

+10.30						Amendment No. 2 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated November 4, 2008 (incorporated by reference to Exhibit 10.57 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).

+10.31						Amendment No. 3 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated August 4, 2009 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.32						Amendment No. 4 to the ENSCO Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated December 22, 2009 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.33						Amendment No. 5 to the Ensco Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2004), dated May 14, 2012 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).

+10.34						ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 4, 2008 (incorporated by reference to Exhibit 10.56 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2008, File No. 1-8097).

+10.35						Amendment No. 1 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated August 4, 2009 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, File No. 1-8097).

+10.36						Amendment No. 2 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated November 3, 2009 (incorporated by reference to Exhibit 10.31 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2009, File No. 1-8097).

+10.37						Amendment No. 3 to the ENSCO 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated December 22, 2009 (incorporated by reference to Exhibit 10.8 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.38						Amendment No. 4 to the Ensco 2005 Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 14, 2012 (incorporated by reference to Exhibit 10.10 to the Registrant's Current Report on Form 8-K filed on May 15, 2012, File No. 1-8097).

+10.39						Amendment No. 5 to the Ensco 2005 Amended and Restated Supplemental Executive Retirement Plan (As Amended and Restated Effective January 1, 2005), dated May 21, 2013 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 24, 2013, File No. 1-8097).

206


+10.40						Amendment No. 6 to the ENSCO 2005 Supplemental Executive Retirement Plan (as amended and restated effective January 1, 2005), dated December 19, 2019. (incorporated by reference to Exhibit 10.28 to the Registrant's Annual Report on Form 10-K for the year ended December 31, 2019 , File No. 1-8097).

+10.41						ENSCO 2005 Benefit Reserve Trust, effective January 1, 2005 (incorporated by reference to Exhibit 99.3 to the Registrant's Current Report on Form 8-K filed on January 5, 2005, File No. 1-8097).

+10.42						Deed of Assumption relating to Equity Incentive Plans of ENSCO International Incorporated, dated December 22, 2009, executed by Ensco International plc (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.43						Form of Deed of Indemnity of Ensco International plc (incorporated by reference to Exhibit 10.13 to the Registrant's Current Report on Form 8-K filed on December 23, 2009, File No. 1-8097).

+10.44						Ensco plc 2012 Long-Term Incentive Plan, effective January 1, 2012 (incorporated by reference to Annex A to the Registrant's Proxy Statement filed on April 4, 2012, File No. 1-8097).

+10.45						First Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective August 21, 2012 (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, File No. 1-8097).

+10.46						Second Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective January 1, 2013 (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 1-8097).

+10.47						Third Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective March 30, 2015 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 19, 2015, File No. 1-8097).

+10.48						Fourth Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective March 24, 2016 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 25, 2016, File No. 1-8097).

+10.49						Fifth Amendment to the Ensco plc 2012 Long-Term Incentive Plan, effective March 24, 2017 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 23, 2017, File No. 1-8097).

+10.50						Form of Ensco plc 2012 Long-Term Incentive Plan Restricted Share Award Agreement (executives) (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, File No. 1-8097).

+10.51						Form of Ensco plc 2012 Long-Term Incentive Plan Restricted Share Unit Award Agreement (executives) (incorporated by reference to Exhibit 10.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, File No. 1-8097).

+10.52						Form of Ensco plc 2012 Long-Term Incentive Plan Performance Unit Award Agreement (executives) (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, File No. 1-8097).


+10.53						Form of Ensco plc 2012 Long-Term Incentive Plan Restricted Share Unit Award Agreement (non-employee directors) (incorporated by reference to Exhibit 10.6 the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, File No. 1-8097).

+10.54						Form of Deed of Indemnity entered into between Ensco plc and Carl Trowell as of June 2, 2014 (incorporated by reference to Exhibit 10.2 of the Registrant's Quarterly Report on Form 10-Q filed on August 1, 2014, File No. 1-8097).

+10.55						Form of Change in Control Severance Agreement for Executive Officers (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q filed on April 28, 2016, File No. 1-8097).

+10.56						Ensco plc 2018 Long-Term Incentive Plan (incorporated to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on May 22, 2018, File No. 1-8097).


+10.57						Form of Ensco plc 2018 Long-Term Incentive Plan Non-Employee Director Restricted Share Unit Award Agreement (incorporated to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on May 22, 2018, File No. 1-8097).

+10.58						Amendment to 2018 Valaris plc Long Term Incentive Plan (incorporated by reference to Annex 2 to the Registrant’s Proxy Statement on Schedule DEF 14A filed on April 27, 2020, File No. 1-8097).

207


+10.59						Amended and Restated Employment Agreement, dated as of October 7, 2018, by and between Carl Trowell and Ensco Services Limited (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 9, 2018, File No. 1-8097).

+10.60						Deed of Amendment No. 1 to Restated Employment Agreement of Carl Trowell, dated as of April 26, 2020 (incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097).

+10.61						Consultancy Agreement of Carl Trowell, dated as of April 26, 2020 (incorporated by reference to Exhibit 10.6 to the Registrant's Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097).

+10.62						Employment Agreement, dated as of October 7, 2018, by and between Dr. Thomas Burke, Rowan Companies Inc., ENSCO Global Resources Limited and, solely for the purposes of guaranteeing ENSCO Global Resources Limited’s obligations thereunder, Ensco plc (incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on October 9, 2018, File No. 1-8097).

+10.63						Form of Ensco plc 2018 Long-Term Incentive Plan Restricted Share Unit Award Agreement (Executives) (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on March 11, 2019, File No. 1-8097).


+10.64						Restoration Plan of Rowan Companies, Inc. (as amended and restated effective January 1, 2013), incorporated by reference to Exhibit 10.7 to Rowan's Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-5491).

+10.65						Form of Restricted Share Notice pursuant to the 2009 Rowan Companies, Inc. Incentive Plan, incorporated by reference to Exhibit 10.5 to Rowan's Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).

+10.66						Form of Non-Employee Director Restricted Share Unit Notice pursuant to 2009 Rowan Companies, Inc. Incentive Plan, incorporated by reference to Exhibit 10.8 of Rowan's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2012 (File No. 1-5491).

+10.67						Forms of Share Appreciation Right Award Notice pursuant to the 2009 Rowan Companies, Inc. Incentive Plan, incorporated by reference to Exhibit 10.1 to Rowan's Current Report on Form 8-K filed on March 8, 2013 (File No. 1-5491).

+10.68						Retirement Policy of Rowan, effective March 6, 2013, incorporated by reference to Exhibit 10.2 to Rowan's Current Report on Form 8-K filed on March 8, 2013 (File No. 1-5491).

+10.69						Form of Employee Restricted Share Unit Notice pursuant to the 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Exhibit 10.2 to Rowan's Current Report on Form 8-K filed on April 30, 2013 File No. 1-5491).

+10.70						Form of Share Appreciation Right Notice pursuant to the 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Exhibit 10.3 to Rowan's Current Report on Form 8-K filed on April 30, 2013 (File No. 1-5491).

+10.71						Non-Employee Director Restricted Share Unit Notice pursuant to Annex 1 to the 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Exhibit 10.5 to Rowan's Current Report on Form 8-K filed on April 30, 2013 (File No. 1-5491).

+10.72						Form of Change in Control Agreement entered into with executives on or after April 25, 2014, incorporated by reference to Exhibit 10.31 to Rowan's Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 1-5491).

+10.73						Form of Restricted Share Unit Award Notice , incorporated by reference to Exhibit 10.1 of Rowan's Current Report on Form 8-K file on February 24, 2017 (File No. 1-5491).

+10.74						Valaris Executive Severance Plan (incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097).

+10.75						Amended and Restated 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Annex A to the Company’s proxy statement filed on March 13, 2013 (File No. 1-5491)

+10.76						2009 Rowan Companies, Inc. Incentive Plan (as Amended and Restated and as Assumed and Adopted by the Company, effective May 4, 2012), incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 4, 2012

208


+10.77						Cooperation and Support Agreement between Valaris plc and Luminus Management LLC, effective January 24, 2020 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on January 27, 2020, File No. 1-8097).

+10.78						First Amendment to Cooperation and Support Agreement, dated as of August 28, 2020, by and among Valaris plc and Luminus Management, LLC (incorp orated by reference to Exhibi t 10.1 to the Registrant's Current Report filed on Form 8-K on August 28, 2020, File No. 1-8097).

+10.79						Form of 2020 Performance Unit Award Agreement (Non-UK resident Executives)(incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report filed on Form 10-Q on April 30, 2020, File No. 1-8097)

+10.80						Form of 2020 Performance Unit Award Agreement (UK resident Executives)(incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report filed on Form 10-Q on April 30, 2020, File No. 1-8097).

+10.81						Form of 2020 Restricted Share Unit Award Agreement (CEO)(incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report filed on Form 10-Q on April 30, 2020, File No. 1-8097).

+10.82						Valaris Cash Incentive Plan (incorporated by reference to Exhibit 10.8 to the Registrant's Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097)

+10.83						Forbearance Agreement, dated as of June 30, 2020 (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097)

+10.84						Forbearance Agreement, dated as of July 15, 2020, a mong ce rtain beneficial holders or investment managers or advisors for such beneficial holders of the Company 's outsta nding senior notes (incorporated by reference to Exhibit 10.1 to the Registrant's Quarterly Re p ort filed on Form 10-Q on October 29 , 2020 Fi le No. 1-8097).

+10.85						Form of Executive STI Retention Bonus Letter Agreement (incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097).

+10.86						Form of Executive STI Retention Bonus Letter Agreement (Messrs. Baksht and McGuinty) (incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report filed on Form 10-Q on July 30, 2020, File No. 1-8097).

+10.87						Form of Executive STI Retention Bo nus Letter Ag reement (Retention) (incorporated by refere nce to E xhibit 10.11 to the Registrant's Q uarterly Report f il ed on Form 10-Q on July 30, 2020, File No. 1-80 97).

+10.88						Restructuring Support Agreement, dated August 18, 2020 (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report filed on Form 8-K on August 19, 2020, File No. 1-8097).

+10.89						Backstop Commitment Agreement, dated August 18, 2020, by and among the company and the commitment parties named therein (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report filed on Form 8-K on August 19, 2020, File No. 1-8097).

+10.90						Amendment to Restructuring Support Agreement and Backstop Commitment Agreement dated as of September 10, 2020 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on September 11, 2020, File No. 1-8097).

+10.91						Second Amendment to Restructuring Support Agreement, by and among Valaris plc, its Affiliate Debtors and the noteholders party thereto, dated as of February 5, 2021 (incorporated by reference to Exhibit 10.1 to the Registrant's Current Report filed on Form 8-K on February 8, 2021, File No. 1-8097).

+10.92						Third Amendment to Backstop Commitment Agreement, by and among Valaris plc, its Affiliate Debtors and the Commitment Parties, dated as of February 5, 2021 (incorporated by reference to Exhibit 10.2 to the Registrant's Current Report filed on Form 8-K on February 8, 2021, File No. 1-8097).

*21.1						Subsidiaries of the Registrant.

*23.1						Consent of Independent Registered Public Accounting Firm.

*31.1						Certification of the Chief Executive Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

209


*31.2						Certification of the Chief Financial Officer of Registrant pursuant to Rule 13a-14 or 15d-14 of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**32.1						Certification of the Chief Executive Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**32.2						Certification of the Chief Financial Officer of Registrant pursuant to 18 U.S.C. Section 1350, as adopted 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2020, formatted in Inline XBRL (included with Exhibit 101 attachments).

* ** +						Filed herewith. Furnished herewith. Management contracts or compensatory plans and arrangements required to be filed as exhibits pursuant to Item 15(b) of this report.

Certain agreements relating to our long-term debt have not been filed as exhibits as permitted by paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K since the total amount of securities authorized under any such agreements do not exceed 10% of our total assets on a consolidated basis. Upon request, we will furnish to the SEC all constituent agreements defining the rights of holders of our long-term debt not filed herewith.

Item 16. Form 10-K Summary

None.

210

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on March 2, 2021.


Valaris plc (Registrant)

By /s/ THOMAS P. BURKE Thomas P. Burke President and Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities and on the date indicated.

Signatures

Title

Date

/s/ THOMAS P. BURKE

Thomas P. Burke

President and Chief Executive Officer and Director

March 2, 2021

/s/ WILLIAM E. ALBRECHT

William E. Albrecht

Director

March 2, 2021

/s/ FREDERICK ARNOLD

Frederick Arnold

Director

March 2, 2021

/s/ MARY E. FRANCIS CBE

Mary E. Francis CBE

Director

March 2, 2021

/s/ GEORGES J. LAMBERT

Georges J. Lambert

Director

March 2, 2021

/s/ SUZANNE P. NIMOCKS

Suzanne P. Nimocks

Director

March 2, 2021

/s/ THIERRY PILENKO

Thierry Pilenko

Director

March 2, 2021

/s/ PAUL E. ROWSEY, III

Paul E. Rowsey, III

Board Chairman

March 2, 2021

/s/ CHARLES L. SZEWS

Charles L. Szews

Director

March 2, 2021

/s/ JONATHAN H. BAKSHT

Jonathan H. Baksht

Executive Vice President and
Chief Financial Officer
(principal financial officer)

March 2, 2021

/s/ COLLEEN W. GRABLE

Colleen W. Grable

Controller (principal accounting officer)

March 2, 2021

211