Valaris Ltd - Annual Report: 2019 (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, 2019



	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.)

110 Cannon Street

London, England EC4N6EU

(Address of principal executive offices) (Zip Code)

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



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



Title of each class	Ticker Symbol(s)	Name of each exchange on which registered
Class A ordinary shares, U.S. $0.40 par value	VAL	New York Stock Exchange
4.70% Senior Notes due 2021	VAL21	New York Stock Exchange
4.50% Senior Notes due 2024	VAL24	New York Stock Exchange
8.00% Senior Notes due 2024	VAL24A	New York Stock Exchange
5.20% Senior Notes due 2025	VAL25A	New York Stock Exchange
7.75% Senior Notes due 2026	VAL26	New York Stock Exchange
5.75% Senior Notes due 2044	VAL44	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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 (Check one):



Large accelerated filer	x	Accelerated filer	o

Non-Accelerated filer	o	Smaller reporting company	☐

		Emerging growth company	☐

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

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

Yes ☐ No ☒

The aggregate market value of the Class A ordinary shares (based upon the closing price on the New York Stock Exchange on June 30, 2019 of $8.73 of Valaris plc held by non-affiliates of Valaris plc at that date was approximately $21,353,000

As of February 17, 2020, there were 197,280,817 Class A ordinary shares of Valaris plc issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Company's Proxy Statement for the 2020 General Meeting of Shareholders are incorporated by reference into Part III of this report.




TABLE OF CONTENTS


PART I	ITEM 1.	BUSINESS	5
	ITEM 1A.	RISK FACTORS	16
	ITEM 1B.	UNRESOLVED STAFF COMMENTS	42
	ITEM 2.	PROPERTIES	43
	ITEM 3.	LEGAL PROCEEDINGS	46
	ITEM 4.	MINE SAFETY DISCLOSURES	47


PART II	ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED SHAREHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	48
	ITEM 6.	SELECTED FINANCIAL DATA	54
	ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	55
	ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	87
	ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	87
	ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	168
	ITEM 9A.	CONTROLS AND PROCEDURES	168
	ITEM 9B.	OTHER INFORMATION	168


PART III	ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	169
	ITEM 11.	EXECUTIVE COMPENSATION	169
	ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SHAREHOLDER MATTERS	170
	ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	171
	ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	171


PART IV	ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	172
	ITEM 16.	FORM 10-K SUMMARY	180
		SIGNATURES	181

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; synergies and expected additional cost savings; dividends; expected utilization, day rates, revenues, operating expenses, cash flow, contract terms, contract backlog, capital expenditures, insurance, financing and funding; 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; 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; 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; our program to high-grade the rig fleet by investing in new equipment and divesting selected assets and underutilized rigs; 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 our projected negative cash flows in 2020 and highly leveraged balance sheet, including:


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


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


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

•

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 uncertainty or instability resulting from the U.K.'s withdrawal from the European Union, 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;


•	possible cancellation, suspension, renegotiation or termination (with or without cause) of drilling contracts as a result of general and industry-specific economic conditions, mechanical difficulties, performance or other reasons;


•	our ability to enter into, and the terms of, future drilling contracts, including contracts for our newbuild units 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 and any failure to execute definitive contracts following announcements of letters of intent;


•	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;


•	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;


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


•	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;


•	our ability to obtain financing, service our indebtedness, fund negative cash flow and capital expenditures and pursue other business opportunities may be limited by our significant debt levels, debt agreement restrictions and the credit ratings assigned to our debt by independent credit rating agencies;


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


•	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;


•	delays in contract commencement dates or the cancellation of drilling programs by operators;


•	activism by our security holders;


•	economic volatility and political, legal and tax uncertainties following the June 23, 2016, vote in the U.K. to exit from the European Union;


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


•	adverse changes in foreign currency exchange rates, including their effect on the fair value measurement of our derivative instruments;


•	the occurrence or threat of epidemic or pandemic diseases and any government response to such occurrence or threat and the impacts of such events on oil prices and the demand for offshore drilling services; and


•	potential long-lived asset impairments, including the impact of any impairment on our compliance with debt covenants.

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. Exclusive of two rigs under construction and one rig marked for retirement and classified as held-for-sale, we currently own and operate an offshore drilling rig fleet of 74 rigs, with drilling operations in almost every major offshore market across six continents. Inclusive of rigs under construction, our fleet includes 16 drillships, eight dynamically positioned semisubmersible rigs, two moored semisubmersible rigs and 50 jackup rigs, nine of which are leased to our 50/50 joint venture with Saudi Aramco. We operate the world's largest fleet of offshore drilling 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 24 countries on six continents. The markets in which we operate include the Gulf of Mexico, Brazil, the Mediterranean, the North Sea, Norway, 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.

The decline in oil prices from 2014 highs led to a significant reduction in global demand for offshore drilling services. Customers significantly reduced their capital spending budgets, including the cancellation or deferral of existing programs, resulting in fewer contracting opportunities for offshore drilling rigs. Declines in capital spending levels, together with the oversupply of rigs from newbuild deliveries, resulted in significantly reduced day rates and utilization that led to one of the most severe downturns in the industry's history.

More recently, oil prices have increased meaningfully from the decade lows reached during 2016, leading to signs of a gradual recovery in demand for offshore drilling services. However, macroeconomic and geopolitical headwinds triggered a decline in Brent crude prices in late 2018. In 2019, oil prices experienced a gradual recovery before falling again in early 2020.

While this market volatility will likely continue over the near-term, we continue to observe improvements in the shallow-water market, particularly with respect to higher-specification rigs, as higher levels of customer demand and rig retirements have led to gradually increasing jackup utilization over the past year. However, the timing and extent of this improvement is uncertain. Moreover, global floater utilization has increased as compared to a year ago due to a higher number of contracted rigs and lower global supply resulting from rig retirements. However, the floater recovery has lagged the jackup recovery as average contract durations remain relatively short-term and pricing improvements to date have been modest.

Despite the recent increase in customer activity, contract awards remain subject to an extremely competitive bidding process, and the corresponding pressure on operating day rates in recent periods has resulted in low margin contracts, particularly for floaters. Therefore, our results from operations may continue to decline over the near-term as current contracts with above-market rates expire and new contracts are executed at lower rates. We believe further

improvements in demand coupled with a reduction in rig supply are necessary to improve the commercial landscape for day rates.

Valaris plc is a public limited company incorporated under the laws of England and Wales in 2009. Our principal executive office is located at 110 Cannon Street, London EC4N6EU, England, United Kingdom, and our telephone number is +44 (0) 20 7659 4660. Our website is www.valaris.com. Information contained on our website is not included as part of, or incorporated by reference into, this report.

Rowan Transaction

On October 7, 2018, we entered into a transaction agreement (the "Transaction Agreement") with Rowan, and on April 11, 2019 (the "Transaction Date"), we completed our combination with Rowan pursuant to the Transaction Agreement (the "Rowan Transaction") and changed our name to Ensco Rowan plc. On July 30, 2019, we changed our name to Valaris plc. Rowan's financial results are included in our consolidated results beginning on the Transaction Date.

As a result of the Rowan Transaction, Rowan shareholders received 2.750 Valaris Class A ordinary shares for each 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. All share and per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split (as defined herein).

Prior to the Rowan Transaction, Rowan and Saudi Aramco formed a 50/50 joint venture to own, manage and operate drilling rigs offshore Saudi Arabia ("Saudi Aramco Rowan Offshore Drilling Company" or "ARO"). ARO currently owns a fleet of seven jackup rigs, leases another nine jackup rigs from us and has plans to purchase up to 20 newbuild jackup rigs over an approximate 10 year period. In January 2020, ARO ordered the first two newbuild jackups scheduled for delivery in 2022. The rigs we lease to ARO are done so through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All nine jackup rigs leased to ARO and all seven ARO-owned jackup rigs are under long-term contracts with Saudi Aramco. For additional information about our ARO joint venture, See Note 4 of our consolidated financial statements included in Item 8 of this annual report.

The Rowan Transaction enhanced the market leadership of the combined company with a fleet of high-specification floaters and jackups and positions us well to meet increasing and evolving customer demand. The increased scale, diversification and financial strength of the combined company provides us advantages to better serve our customers. Exclusive of two older jackup rigs marked for retirement, Rowan’s offshore rig fleet at the Transaction Date consisted of four ultra-deepwater drillships and 19 jackup rigs.

Reverse Stock Split

Upon closing of the Rowan Transaction, we effected a consolidation (being a reverse stock split under English law) where every four existing Valaris 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"). Our shares began trading on a reverse stock split-adjusted basis on April 11, 2019. All share and per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split.

Contract Drilling Operations

Prior to the Rowan Transaction, our business consisted of three operating segments: (1) Floaters, which included our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consisted of management services on rigs owned by third-parties. Our Floaters and Jackups were also reportable segments.

As a result of the Rowan Transaction, we concluded that we would maintain the aforementioned segment structure while adding ARO as a reportable segment for the new combined company. We also concluded that the activities associated with our arrangements with ARO, consisting of our Transition Services Agreement, Rig Lease Agreements and Secondment Agreement, do not constitute reportable segments and are therefore included within Other in our segment disclosures. See Note 4 for additional information on ARO and related arrangements.

Of our 76 rigs (excluding held-for-sale rigs), 37 are located in the Middle East, Africa and Asia Pacific (including two rigs under construction), 18 are located in North and South America and 21 are located in Europe and the Mediterranean as of December 31, 2019.

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 (i) if the rig is lost or destroyed, (ii) 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 (iii) 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 unit 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 unit, including crew labor and incidental rig supply and maintenance costs,


•	mobilization and demobilization requirements of us to move the drilling unit 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, recent 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 February 21, 2020 and February 28, 2019, respectively. Our backlog excludes ARO's backlog, but includes bareboat charter and related revenue for the jackup rigs leased to ARO.

The following table summarizes our contract backlog of business as of December 31, 2019 and 2018 (in millions):



	2019		2018
Floaters	$	847.3	$	941.5
Jackups	1,281.2		1,071.0
Other⁽¹⁾	324.3		169.9
Total	$	2,452.8	$	2,182.4


⁽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, 2019, our backlog was $2.5 billion as compared to $2.2 billion as of December 31, 2018. Our floater backlog declined $94.2 million and our jackup backlog increased $210.2 million. Changes resulted from revenues realized during the period, partially offset by the addition of backlog from the Rowan Transaction, new contract awards and contract extensions. Our other segment backlog increased $154.4 million due to the addition of backlog from the Rowan Transaction related to the rigs leased to ARO.

The following table summarizes our contract backlog of business as of December 31, 2019 and the periods in which such revenues are expected to be realized (in millions):



	2020		2021		2022		2023 and Beyond		Total
Floaters	$	720.5	$	126.8	$	—	$	—	$	847.3
Jackups	748.5		365.6		166.8		0.3		1,281.2
Other⁽¹⁾	168.9		145.3		10.1		—		324.3
Total	$	1,637.9	$	637.7	$	176.9	$	0.3	$	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.

Our drilling contracts generally contain provisions permitting early termination of the contract (i) if the rig is lost or destroyed or (ii) 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, 2020. 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 unit. 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 flow from the 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 first party coverage to us for physical damage to, including total loss or constructive total loss of, our rigs, generally 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 decided not to purchase first party windstorm insurance for our rigs in the U.S. Gulf of Mexico. Accordingly, we have retained the risk for windstorm damage to our four jackups and eight floaters 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 2019, our five largest customers accounted for 44% of consolidated revenues. Total, our only customer who accounts for 10% or more of consolidated revenues, accounted for 16% 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 Macondo, the 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 mobile offshore drilling units ("MODUs") and jackup 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. On July 12, 2017, the USCG announced the availability of and requested comments on draft guidelines for addressing cyber risks at MTSA-regulated facilities.

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. Based on our current assessment of the rules, we do not expect to incur 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 MODUs and onshore facilities. For example, on May 11, 2017, President Trump issued EO 13800, 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 MODUs, 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 depleting natural 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. 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.

If new laws are enacted or other government actions are taken that restrict or prohibit offshore drilling in our principal areas of operation or 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, 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 85%, 87% and 92% of our total consolidated revenues during 2019, 2018 and 2017, 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 17, 2020:



Name	Age	Position
Dr. Thomas Burke	52	President and Chief Executive Officer
Jonathan Baksht	45	Executive Vice President and Chief Financial Officer
Gilles Luca	48	Senior Vice President - Chief Operating Officer
Alan Quintero	56	Senior Vice President - Business Development
Michael T. McGuinty	57	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:

Dr. 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. Dr. 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, Dr. 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. He serves on the executive committee of the International Association of Drilling Contractors. Dr. 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 - 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, 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

Excluding contract employees, we employed approximately 5,800 personnel worldwide as of December 31, 2019. 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 at 713-430-4607 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.

Item 1A. Risk Factors

Risks Related to Our Business

There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company. Additional risks and uncertainties not specified herein, not currently known to us or currently deemed to be immaterial also may materially adversely affect our business, financial position, operating results or cash flows.

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. More recently, oil prices have increased meaningfully from the decade lows reached during 2016, with Brent crude averaging nearly $55 per barrel in 2017 and more than $70 per barrel through most of 2018, leading to signs of a gradual recovery in demand for offshore drilling services. However, macroeconomic and geopolitical headwinds triggered a decline in Brent crude prices in the fourth quarter of 2018, resulting in a decline in prices from more than $85 per barrel to approximately $50 per barrel at year-end. Oil prices have experienced a gradual recovery from this decline in 2019 with Brent crude prices averaging approximately $64 per barrel. Commodity prices 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 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,


•	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,


•	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,


•	the occurrence or threat of epidemic or pandemic diseases and any government response to such occurrence or threat, 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 prior to the current downturn, 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 expenditures for exploration and production for a variety of reasons, including 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, particularly our high-specification floaters, 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 that we expect to be exercised are not so exercised.

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 options 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.

Our two rigs under construction, which are scheduled for delivery between 2021 and 2022, 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 and flexibility in refinancing our debt, obtaining additional financing and pursuing other business opportunities.

As of December 31, 2019, we had $6.5 billion in total debt outstanding, representing approximately 41.2% of our total capitalization, including 6.785% senior notes due 2020 with an aggregate outstanding principal balance of $122.9 million. As of December 31, 2019, $2.6 billion outstanding principal amount of our debt had a maturity date prior to year-end 2024. 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,

•

covenants contained in our debt arrangements require us to meet certain financial tests, which may affect our flexibility in planning for, and reacting to, changes in our business and may limit our ability to dispose of assets or place restrictions on the use of proceeds from such dispositions, withstand current or future economic or industry downturns and compete with others in our industry for strategic opportunities, 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 2019 and 2018, our cash flows from operating activities of continuing operations were negative $276.9 million and $55.7 million, respectively, and we further incurred capital expenditures on continuing operations of $227.0 million and $426.7 million, respectively. Our operating activities and capital expenditures are expected to continue to result in significant negative annual cash flow in 2020. Meaningful recovery in drilling demand and day rates are required for annual cash flow to turn positive in 2021 and beyond. We cannot be certain that our future cash flows will be sufficient to meet all of our debt obligations, working capital requirements and contractual commitments. Any cash flow insufficiency would have a material adverse impact on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.

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. In addition, we may pursue various liability management transactions to extend our debt maturities and reduce the outstanding principal amount of our debt. These liability management efforts may be unsuccessful or may not improve our financial position to the extent anticipated.

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, 2019, such ratio was 41.2%. If we incur material impairments in future periods, we may not be able to comply with such financial covenant. In addition, these restrictions may limit our flexibility in obtaining additional financing and in pursuing various business opportunities.

Further, if for any reason we are unable to meet our debt service and repayment obligations or to comply with the payment, financial and other covenants in the agreements governing our debt, we would be in default under the terms of such agreements, which could allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our credit facilities could terminate their commitments to extend credit, and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our credit facility or any of our other significant indebtedness were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to the lenders or to our other debt holders.

In addition, our access to credit and capital markets, in part, depends on the credit ratings assigned to our credit facility and our notes by independent credit rating agencies. In recent years, we have experienced significant downgrades in our corporate credit rating and the credit rating of our senior notes. Our access to credit and capital markets is more limited due to these downgrades and the associated weakening of our credit metrics. Any additional actual or anticipated downgrades in our corporate credit rating or the credit rating of our notes will further limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. Furthermore, future financings or refinancings may result in higher borrowing costs, require collateral, or contain more restrictive terms and covenants, which will further restrict our operations. With our current credit ratings, we have no access to the commercial paper market. Limitations on our ability to access credit and capital markets could have a material adverse impact on our financial position, operating results or cash flows.

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 resulting from operations under the contract.

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. 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.

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 $5.4 billion. Further asset impairments may be necessary if market conditions remain depressed for longer than we expect. See Note 6 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 2019, our five largest customers accounted for 44% of our consolidated revenues in the aggregate, with our largest customer representing 16% of our consolidated revenues and a significant percentage of our operating cash flows. 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, which may have a material adverse effect on our financial position, operating results or cash flows.

As of December 31, 2019, our contract backlog was approximately $2.5 billion, which represents an increase of $270.4 million to the reported backlog of $2.2 billion as of December 31, 2018. 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 and it 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 units and contributing capital as the foundation of the new company. The new entity, 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, and integrating our existing employees, business systems, technologies and services with those of Saudi Aramco in order to operate the joint venture efficiently. 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. 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, 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. Our cost-reduction initiatives may not be successful.

We have announced that we are targeting significant synergies and cost savings in connection with the Rowan Transaction. We also have announced that we are implementing additional initiatives targeting significant additional operating cost savings. 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-reductions 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 operation 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 deductible periods to cover these risks.

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 shore-based 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, which could adversely affect our business.

Certain areas in and near the U.S. Gulf of Mexico experience hurricanes and other 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 jackup rigs in the U.S. Gulf of Mexico than most of our competitors. We currently have four jackup rigs and eight floaters in the U.S. Gulf of Mexico. 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 do not purchase 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 opted out of windstorm insurance for our jackups in the U.S. Gulf of Mexico during 2009 and have not

since renewed that insurance. 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 four jackups and eight floaters arising from windstorm damage in the U.S. Gulf of Mexico.

We have established operational procedures designed to mitigate risk to our jackup rigs 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 MODU 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 jackup rigs in the U.S. Gulf of Mexico.

Our annual insurance policies are up for renewal effective May 31, 2020, 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 non-U.S. operations involve additional risks not typically associated with U.S. operations.

Revenues from non-U.S. operations were 85%, 87% and 92% of our total revenues during 2019, 2018 and 2017, 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.

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. We evaluate applicable tax laws and employ various business structures and operating strategies to obtain the optimal level of taxation on our revenues, income, assets and personnel. 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 substantially increase 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. During 2019, we received income tax assessments totaling approximately €142.0 million (approximately $159.0 million converted using the current period-end exchange rates) and A$101 million (approximately $70.9 million converted at current period-end exchange rates) from taxing authorities in Luxembourg and Australia, respectively. See Note 12 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on income taxes.

assessments. 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.

We may not achieve the intended results from the Rowan Transaction, and we may not be able to successfully integrate our operations after the Rowan Transaction. Failure to successfully integrate Rowan may adversely affect our future results, and consequently, the value of our shares.

We consummated the Rowan Transaction with the expectation that it would result in various benefits, including, among others, expanding our geographic presence and customer base and creating synergies, including $165 million of merger synergies and at least $100 million of other operating cost savings. We closed the Rowan Transaction on April 11, 2019; however, achieving the anticipated benefits of the Rowan Transaction is subject to a number of uncertainties, including whether the Rowan business can be integrated in an efficient and effective manner.

While we have successfully merged companies into our operations in the past, the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of our ongoing business, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the Rowan Transaction. Our combined operations could be adversely affected by issues attributable to Rowan’s historical operations that arose or are based on events or actions that occurred prior to the completion of the Rowan Transaction. In addition, integrating Rowan’s employees and operations will require the time and attention of management, which may negatively impact our business. Events outside of our control, including changes in regulation and laws, could adversely affect our ability to realize the expected benefits, including merger synergies and other cost savings, from the Rowan Transaction.

The results of the U.K.'s referendum on 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 provides that the U.K.’s withdrawal is followed by a “transition period”, during which, in summary, the U.K. is not a member of the E.U. but most E.U. rules and regulations continue to apply to the U.K. During the transition period, the U.K. and the E.U. will seek 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 provided for in the Withdrawal Agreement will expire on December 31, 2020 (unless both the U.K. and the E.U. agree to extend the period of transition by one or two years).

The political negotiation surrounding the terms of the U.K.’s withdrawal from the E.U. has created significant uncertainty about the future relationship between the U.K. and the E.U., including with respect to the laws and regulations that will apply. This is because, once the “transition period” expires then, subject to the terms of any long-term trading relationship agreed between the U.K. and the E.U., the U.K. will determine which E.U.-derived laws to replace or replicate. 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.

If no long-term trading relationship is agreed between the U.K. and the E.U. by the end of the transition period provided for in the Withdrawal Agreement, the U.K.’s membership of the E.U. could ultimately terminate under a so-called “hard Brexit.” Under this scenario, there could be increased costs from the imposition of tariffs on trade or non-tariff barriers between the U.K. and E.U., shipping delays because of the need for customs inspections and temporary shortages of certain goods. Any of the foregoing might cause our U.K. suppliers to pass along these increased costs, if realized, to us in the U.K. In addition, trade and investment between the U.K., the E.U. and other countries would be impacted by the fact that the U.K. currently operates under tax and trade treaties concluded between the E.U. and other countries. Following a “hard Brexit”, the U.K. would need to negotiate its own tax and trade treaties with other countries, as well as with the E.U.. Any new, or changes to existing, U.K. tax laws could make the U.K. a less desirable jurisdiction of incorporation for our parent company, Valaris plc. In addition, one of our U.K. subsidiaries owns two jackup rigs, and following a “hard Brexit,” the E.U. might require some form of importation fee or guarantee on certain U.K. owned rigs that operate outside U.K. waters.

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 and restrict the ability of key market participants to operate in certain financial markets. Any of these factors could depress economic activity, result in changes to currency exchange rates, tariffs, treaties, 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 10% of our total revenues were generated in the U.K. for the year ended December 31, 2019.

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 13 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.

We do not currently pay dividends and cannot assure you that we will pay dividends or otherwise return capital to shareholders in the future. Our indebtedness limits our ability to pay dividends and repurchase shares.

Our Board of Directors declared a $0.01 (pre-reverse stock split) quarterly cash dividend per Class A ordinary share for each quarter during 2017 and 2018 and the first quarter of 2019. In the second quarter of 2019, our Board of Directors determined that we will not pay a regular quarterly cash dividend. 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, restrictions and limitations in our credit facility and other debt documents and other factors and restrictions our Board of Directors deems relevant. Our revolving credit facility restricts payment of dividends in excess of a regular quarterly dividend of $0.01 per share and prohibits the repurchase of shares, except in certain limited circumstances. Future agreements may have similar restrictions. There can be no assurance that we will pay a dividend or otherwise return capital to shareholders in the future.

Legal and regulatory proceedings could adversely affect us.

We are involved in litigation, including various claims, disputes and regulatory proceedings that arise in the ordinary course of business, many of which are uninsured and relate to intellectual property, commercial, operational, employment, regulatory or other activities.

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 under a contract and 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.

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.

Hurricanes Katrina and Rita in 2005 and Hurricanes Gustav and Ike in 2008 caused damage to a number of rigs in the Gulf of Mexico. Rigs that were moved off location by the storms damaged platforms, pipelines, wellheads and other drilling rigs. 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.

Following the 2010 Macondo well incident in the U.S. Gulf of Mexico, the U.S. Department of the Interior issued Notices to Lessees, implementing new requirements and/or guidelines that are applicable to drilling operations in the U.S. Gulf of Mexico. Current or future Notice to Lessees 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. In 2016, BSEE promulgated the 2016 Well Control Rule imposing 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. In May 2018, BSEE proposed revisions to the 2016 Well Control Rule. This proposed rule 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.

Also, as a result of the Macondo well incident, BSEE and its predecessor agency promulgated regulations regarding SEMS. Although only operators are currently required to have a SEMS, the SEMS regulations 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. In addition, BSEE has in the past stated that future rulemaking may require offshore drilling contractors to implement their own SEMS programs. The current SEMS regulations and the possibility of additional SEMS rules for contractors could expose us to increased costs.

In 2012, BSEE issued an IPD for use by BSEE inspectors in INCs to contractors operating under BSEE jurisdiction on the Outer Continental Shelf of the U.S. Gulf of Mexico. The stated purpose of the policy was to provide for consistency in application of BSEE enforcement authority by establishing guidelines for issuance of INCs to contractors in addition to operators. The policy indicated that BSEE’s enforcement actions would continue to focus primarily on lessees and operators, but that “in appropriate circumstances” BSEE also would issue INCs to contractors 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.

Since 2014, the United States Coast Guard has proposed new regulations that would impose GPS equipment and positioning requirements for MODUs and jackup 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. In 2016, BSEE adopted the 2016 Well Control Rule, which will be implemented in phases over the next several years. This new rule includes more stringent design requirements for well-control equipment used in offshore drilling operations. As described above, revisions to this rule have been proposed by BSEE, which could reduce the regulatory burden of the rule. We are continuing to evaluate the cost and effect that these new rules will have on our operations. However, based on our current assessment of the rules, we do not expect to incur significant costs to comply with the rule. Implementation of further guidelines and regulations may subject us to increased costs and limit the operational capabilities of 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.

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.

Laws and governmental regulations may add to costs, limit our drilling activity or reduce demand for our drilling services.

Our operations are affected by political developments and by laws and regulations that relate directly to the oil and gas industry. 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.

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, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds, promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and 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.

Geopolitical events, terrorist attacks, piracy and military action 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. 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 such 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 operations and financial results.

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 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. If such labor trends continue, they could further increase our costs or limit our ability to fully staff and operate our rigs.

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.

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, which could adversely affect our financial condition, operating results or cash flows.

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.

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 industry consolidation has reduced the number of available suppliers. 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 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 legal claims or proceedings, including under data privacy laws and regulations such as the European Union General Data Protection Regulation, disrupt 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 is no assurance that such impacts will not be material in the future.

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

Under U.S. GAAP, we must separately account for the liability and equity components of convertible debt instruments, such as our 3.00% exchangeable senior notes due 2024 (the “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 carrying value of the debt component is recorded with a corresponding discount that will result in a significant amount of non-cash interest expense from the accretion of the discounted carrying value up to the principal amount over the term of the

2024 Convertible Notes. 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.

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 6 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes.

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 appropriately treated as 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, which could adversely affect our financial position, operating results or cash flows.

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.

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 are also contesting the Luxembourg tax assessments. We may make a payment to the Luxembourg tax authorities in advance of the final resolution of these assessments. Although the outcome of such assessments cannot be predicted with certainty, unfavorable outcomes could have a material adverse effect on our liquidity.

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 from one reporting period to another.

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.

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 NYSE 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, our shares may become ineligible for continued listing on a U.S. securities exchange, and 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.

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.

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 in 2019 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, 2020 (whichever is earlier). An ordinary resolution will be put to shareholders at our next annual shareholder meeting seeking their approval to renew the board's authority to allot up to a prescribed amount of shares for an additional term.

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. A special resolution was passed, in conjunction with an allotment authority at our last annual general meeting in 2019, to disapply pre-emption rights in respect of new shares up to a prescribed amount until the conclusion of the next annual general meeting or the close of business on August 19, 2020 (whichever is earlier). Special resolutions will be put to shareholders at our next annual shareholder meeting seeking their approval to renew the board's authority to disapply pre-emption rights in respect of new shares up to a prescribed amount for an additional term.

English law prohibits us from conducting "on-market purchases" as our shares will not be traded on a “recognized investment exchange”. English law also generally prohibits a company from repurchasing its own shares by way of "off-market purchases" without the approval by a special 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. A special resolution was passed at our annual shareholder meeting in May 2018 to permit 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 the 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.

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 Company is not subject to the U.K.'s Code on Takeovers and Mergers (the “Code”).

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 in capital taken 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 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.

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.

During 2019, one of our shareholders, who acquired and may continue to own a material portion of our outstanding shares, publicly stated its intent to initiate a proxy contest. Pursuant to a cooperation and support agreement, such shareholder nominated a representative who was appointed to our Board of Directors in February 2020. It is possible such shareholder, after the expiration of the cooperation and support agreement, or future activist investors may attempt to affect the actions described above or acquire control over us, engage in proxy solicitations and advance shareholder proposals.

In addition, we have received correspondence from purported holders of our debt securities alleging, among other things, breach of fiduciary duty and fraudulent conveyance, including with respect to our recently completed internal reorganization and our internal cash management system. Such holders and other holders of such debt securities may commence litigation against us based on those or other claims. We believe these allegations are without merit and, if litigation is commenced, we intend to defend ourselves vigorously. Even if we are successful in defending against such claims, however, we may expend significant management time and attention and funds to defend against such claims. Any adverse judgment against us could have a material adverse impact on our business, operations and financial condition.

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 by reportable segment as of February 13, 2020:



Rig Name	Rig Type	Year Built/ Rebuilt	Design	Maximum Water Depth/ Drilling Depth	Location	Status
Floaters
VALARIS DS-3	Drillship	2010	Dynamically Positioned	10,000'/40,000'	Spain	Preservation stacked⁽¹⁾
VALARIS DS-4	Drillship	2010	Dynamically Positioned	10,000'/40,000'	Spain	Available
VALARIS DS-5	Drillship	2011	Dynamically Positioned	10,000'/40,000'	Spain	Preservation stacked⁽¹⁾
VALARIS DS-6	Drillship	2012	Dynamically Positioned	10,000'/40,000'	Spain	Available
VALARIS DS-7	Drillship	2013	Dynamically Positioned	10,000'/40,000'	Egypt	Under contract
VALARIS DS-8	Drillship	2015	Dynamically Positioned	10,000'/40,000'	Angola	Under contract
VALARIS DS-9	Drillship	2015	Dynamically Positioned	10,000'/40,000'	Brazil	Under contract
VALARIS DS-10	Drillship	2018	Dynamically Positioned	10,000'/40,000'	Nigeria	Under contract
VALARIS DS-11	Drillship	2013	Dynamically Positioned	12,000'/40,000'	Spain	Available
VALARIS DS-12	Drillship	2013	Dynamically Positioned	12,000'/40,000'	Egypt	Under contract
VALARIS DS-13	Drillship	Under construction	Dynamically Positioned	12,000'/40,000'	South Korea	Under construction⁽²⁾
VALARIS DS-14	Drillship	Under construction	Dynamically Positioned	12,000'/40,000'	South Korea	Under construction⁽²⁾
VALARIS DS-15	Drillship	2014	Dynamically Positioned	12,000'/40,000'	Gulf of Mexico	Under contract
VALARIS DS-16	Drillship	2014	Dynamically Positioned	12,000'/40,000'	Gulf of Mexico	Under contract
VALARIS DS-17	Drillship	2014	Dynamically Positioned	12,000'/40,000'	Spain	Available
VALARIS DS-18	Drillship	2015	Dynamically Positioned	12,000'/40,000'	Gulf of Mexico	Under contract
VALARIS 5004	Semisubmersible	1982/2001/2014	F&G Enhanced Pacesetter	1,500'/25,000'	Mediterranean	Under contract
VALARIS 8500	Semisubmersible	2008	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Preservation stacked⁽¹⁾
VALARIS 8501	Semisubmersible	2009	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Preservation stacked⁽¹⁾
VALARIS 8502	Semisubmersible	2010/2012	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Preservation stacked⁽¹⁾
VALARIS 8503	Semisubmersible	2010	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Under contract
VALARIS 8504	Semisubmersible	2011	Dynamically Positioned	8,500'/35,000'	Malaysia	Available
VALARIS 8505	Semisubmersible	2012	Dynamically Positioned	8,500'/35,000'	Mexico	Under contract
VALARIS 8506	Semisubmersible	2012	Dynamically Positioned	8,500'/35,000'	Gulf of Mexico	Preservation stacked⁽¹⁾
VALARIS DPS-1	Semisubmersible	2012	Dynamically Positioned	10,000'/35,000'	Australia	Under contract
VALARIS MS-1	Semisubmersible	2011	F&G ExD Millennium	8200'/32,000'	Malaysia	Available

Jackups
VALARIS JU-22	Jackup	1980	LT 116-C	250'/25,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-36	Jackup	1981	LT 116-C	250'/25,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-37	Jackup	1981	LT 116-C	250'/25,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-54	Jackup	1982/1997/2014	F&G L-780 MOD II-C	300'/25,000'	Saudi Arabia	Under contract
VALARIS JU-67	Jackup	1976/2005	MLT 84-CE	400'/30,000'	Indonesia	Under contract
VALARIS JU-70	Jackup	1981/1996/2014	Hitachi K1032N	250'/30,000	United Kingdom	Preservation stacked⁽¹⁾
VALARIS JU-71	Jackup	1982/1995/2012	Hitachi K1032N	225'/25,000'	United Kingdom	Preservation stacked⁽¹⁾
VALARIS JU-72	Jackup	1981/1996	Hitachi K1025N	225'/25,000'	United Kingdom	Under contract



Rig Name	Rig Type	Year Built/ Rebuilt	Design	Maximum Water Depth/ Drilling Depth	Location	Status
Jackups
VALARIS JU-75	Jackup	1999	MLT Super 116-C	400'/30,000'	Gulf of Mexico	Under contract
VALARIS JU-76	Jackup	2000	MLT Super 116-C	350'/30,000'	Saudi Arabia	Under contract
VALARIS JU-84	Jackup	1981/2005/2012	MLT 82-SD-C	250'/25,000'	Saudi Arabia	Under contract
VALARIS JU-87	Jackup	1982/2006	MLT 116-C	350'/25,000'	Gulf of Mexico	Under contract
VALARIS JU-88	Jackup	1982/2004/2014	MLT 82-SD-C	250'/25,000'	Saudi Arabia	Under contract
VALARIS JU-92	Jackup	1982/1996	MLT 116-C	225'/25,000'	United Kingdom	Under contract
VALARIS JU-100	Jackup	1987	MLT 150-88-C	328'/25,000'	United Kingdom	Under contract
VALARIS JU-101	Jackup	2000	KFELS MOD V-A	400'/30,000'	United Kingdom	Under contract
VALARIS JU-102	Jackup	2002	KFELS MOD V-A	400'/30,000'	Gulf of Mexico	Under contract
VALARIS JU-104	Jackup	2002	KFELS MOD V-B	400'/30,000'	UAE	Available
VALARIS JU-105	Jackup	2002	KFELS MOD V-B	400'/30,000'	Singapore	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	KFELS MOD V-B	400'/30,000'	Saudi Arabia	Under contract
VALARIS JU-109	Jackup	2008	KFELS MOD V-Super B	350'/35,000'	Angola	Under contract
VALARIS JU-110	Jackup	2015	KFELS MOD V-B	400'/30,000'	Qatar	Under contract
VALARIS JU-111	Jackup	2003	KFELS MOD V-B	400'/36,000'	Malta	Cold stacked
VALARIS JU-113	Jackup	2012	Pacific Class 400	400'/30,000'	Philippines	Cold stacked
VALARIS JU-114	Jackup	2012	Pacific Class 400	400'/30,000'	Philippines	Cold stacked
VALARIS JU-115	Jackup	2013	Pacific Class 400	400'/30,000'	Thailand	Under contract
VALARIS JU-116	Jackup	2008	LT 240- C	375'/35,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-117	Jackup	2009	LT 240- C	350'/35,000'	Trinidad	Under contract
VALARIS JU-118	Jackup	2011	LT 240- C	350'/35,000	Trinidad	Available
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'	Netherlands	Under contract
VALARIS JU-122	Jackup	2014	KFELS Super A	400'/40,000'	United Kingdom	Under contract
VALARIS JU-123	Jackup	2019	KFELS Super A	400'/40,000'	United Kingdom	Under contract
VALARIS JU-140	Jackup	2016	Cameron Letourneau Super 116E	400'/30,000'	Saudi Arabia	Under contract
VALARIS JU-141	Jackup	2016	Cameron Letourneau Super 116E	400'/30,000'	Saudi Arabia	Under contract
VALARIS JU-142	Jackup	2008	LT Super 116-E	400'/30,000'	Malta	Cold stacked
VALARIS JU-143	Jackup	2010	LT Super 116-E	400'/30,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-144	Jackup	2010	LT Super 116-E	400'/30,000'	Mexico	Under contract
VALARIS JU-145	Jackup	2010	LT Super 116-E	400'/30,000'	Gulf of Mexico	Available
VALARIS JU-146	Jackup	2011	LT Super 116-E	400'/30,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-147	Jackup	2013	LT Super 116-E	400'/30,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-148	Jackup	2013	LT Super 116-E	400'/30,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-247	Jackup	1998	LT Super Gorilla	400'/30,000'	United Kingdom	Under contract
VALARIS JU-248	Jackup	2000	LT Super Gorilla	400'/30,000'	United Kingdom	Under contract
VALARIS JU-249	Jackup	2002	LT Super Gorilla	400'/30,000'	United Kingdom	Under contract
VALARIS JU-250	Jackup	2003	LT Super Gorilla XL	400'/30,000'	Saudi Arabia	Leased to ARO drilling
VALARIS JU-290	Jackup	2010	KEFLS N Class	400'/30,000'	Norway	Under contract
VALARIS JU-291	Jackup	2011	KEFLS N Class	400'/30,000'	Norway	Under contract
VALARIS JU-292	Jackup	2011	KEFLS N Class	400'/30,000'	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⁾	Rig is currently under construction and is not contracted.

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 MODUs 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 three hybrid semisubmersibles, VALARIS 8503, VALARIS 8504 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 21, 2020, we owned all rigs in our fleet. We also manage the drilling operations for two rigs owned by third-parties.

We lease our executive offices in London, England in addition to office space in Houston, Aberdeen, Abu Dhabi, Australia, Dubai, Indonesia, Malaysia, Malta, Mexico, Nigeria, The Netherlands, Saudi Arabia, Singapore, Thailand, Vietnam and Qatar. We own offices and other facilities in Louisiana, Angola, Australia and Brazil.

Item 3. Legal Proceedings

Shareholder Derivative Lawsuit

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. Under applicable law, the court appointed a lead plaintiff and lead counsel. We anticipate that an amended complaint will be filed in the second quarter of 2020. We strongly disagree and intend to vigorously defend against these claims. At this time, we are unable to predict the outcome of these matters or the extent of any resulting liability.

DSA Dispute

On January 4, 2016, Petrobras sent a notice to us declaring the drilling services agreement with Petrobras (the "DSA") for VALARIS DS-5, a drillship ordered from Samsung Heavy Industries, a shipyard in South Korea ("SHI"), void effective immediately, reserving its rights and stating its intention to seek any restitution to which it may be entitled. The previously disclosed arbitral hearing on liability related to the matter was held in March 2018. Prior to the arbitration tribunal issuing its decision, we and Petrobras agreed in August 2018 to a settlement of all claims relating to the DSA. No payments were made by either party in connection with the settlement agreement. The parties agreed to normalize business relations, and the settlement agreement provides for our participation in current and future Petrobras tenders on the same basis as all other companies invited to these tenders. No losses were recognized during 2018 with respect to this settlement as all disputed receivables with Petrobras related to the DSA were fully reserved in 2015. See Item 1 “Legal Proceedings” in our quarterly report on Form 10-Q for the quarter ended June 30, 2018 for further information about the DSA dispute.

In April 2016, we initiated separate arbitration proceedings in the U.K. against SHI for the losses incurred in connection with the foregoing Petrobras arbitration and certain other losses relating to the DSA. In January 2018, the arbitration tribunal for the SHI matter issued an award on liability fully in our favor. The January 2018 arbitration award provides that SHI is liable to us for $10.0 million or damages that we can prove. We submitted our claim for damages to the tribunal, and the arbitral hearing on damages owed to us by SHI took place during the first quarter of 2019.

In May 2019, the arbitration tribunal for the SHI matter awarded us $180.0 million in damages, in addition to the right to claim interest and costs, in connection with this matter. In June 2019, we and SHI filed separate applications with the English High Court to seek leave to appeal the damages awarded.

In December 2019, the English High Court denied the parties’ applications for leave to appeal the tribunal’s $180.0 million damages award. Following this decision, the parties reached an agreement and SHI paid us $200.0 million in cash. Collection of this payment resulted in the recognition of a gain of the same amount, which is included in other, net, in our consolidated statement of operations for the year ended December 31, 2019. This payment, along with the previously disclosed settlement and normalization of our business relationship with Petrobras, concludes our dispute surrounding VALARIS DS-5.

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 $145,000 liability related to these matters was included in accrued liabilities and other on our consolidated balance sheet as of December 31, 2019.

We currently are subject to a pending administrative proceeding initiated during 2009 by a Spanish government authority seeking payment in an aggregate amount of approximately $3.0 million for an alleged environmental spill originating from VALARIS 5006 while it was operating offshore Spain. Our customer has posted guarantees with the Spanish government to cover potential penalties. Additionally, we expect to be indemnified for any payments resulting from this incident by our customer under the terms of the drilling contract. A criminal investigation of the incident was initiated during 2010 by a prosecutor in Tarragona, Spain, and the administrative proceedings have been suspended pending the outcome of this investigation. In May 2019, we were informed that the criminal investigation has been completed. We have not received any indication from the Spanish government if or when the administrative proceedings will resume.

We intend to vigorously defend ourselves in the administrative proceeding and any criminal investigation. At this time, we are unable to predict the outcome of these matters 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.

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.

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

Our Class A ordinary shares are traded on the NYSE under the ticker symbol "VAL." Many of our shareholders hold shares electronically, all of which are owned by a nominee of DTC. We had 131 shareholders of record on February 1, 2020.

Dividends

Our Board of Directors declared a $0.01 quarterly cash dividend, on a pre-Reverse Stock Split basis, for the first quarter of 2019. Starting in the second quarter of 2019, our Board of Directors determined that we will not pay a regular quarterly cash dividend. The declaration and amount of future dividends is at the discretion of our Board of Directors and could change in future periods.

Our revolving credit facility prohibits us from paying dividends in excess of $0.01 per share per fiscal quarter. Dividends in excess of this amount would require the amendment or waiver of such provision.

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 2019/2020 (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 2018/2019:


•	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 2019 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 2019/2020 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 2019. 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 the depository in 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. 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, 2019.



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	5,090	$	4.87	—	$	500,000,000
November 1 - November 30	4,721	$	4.40	—	$	500,000,000
December 1 - December 31	16,585	$	4.45	—	$	500,000,000
Total	26,396	$	4.52	—


⁽¹⁾	During the quarter ended December 31, 2019, 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 of Valaris plc to have sufficient distributable reserves, 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, 2019, there had been no share repurchases under the repurchase program. Our revolving credit facility prohibits the repurchase of shares for cash, except in certain limited circumstances.

Performance Chart

The chart below presents a comparison of the five-year cumulative total return, assuming $100 invested on December 31, 2014 for Valaris plc, the Standard & Poor's SmallCap 600 Index, and a self-determined peer group.Total return assumes the reinvestment of dividends, if any, in the security on the ex-dividend date. The Standard & Poor's SmallCap 600 Index includes Valaris and has been included as a comparison. Since Valaris operates exclusively as an offshore drilling company, a self-determined peer group composed exclusively of major offshore drilling companies has been included as a comparison.^*

COMPARISON OF 5 YEAR CUMULATIVE TOTAL RETURN⁽¹⁾

Among Valaris plc, the S&P SmallCap 600 Index and Peer Group

⁽¹⁾$100 invested on 12/31/14; includes the reinvestment of dividends in the same security on the ex-dividend date.



	Fiscal Year Ended December 31,
	2014	2015	2016	2017	2018	2019
Valaris plc	100.0	53.0	33.6	20.6	12.5	5.8
S&P SmallCap 600	100.0	96.6	120.6	134.7	121.6	146.9
Peer Group	100.0	56.4	53.1	37.1	22.0	17.3

____________________________________

*The self-determined peer group is weighted according to market capitalization at the beginning of each year and consists of the following companies: Transocean Ltd., Diamond Offshore Drilling Inc., Noble Corp., and Seadrill Ltd^**.

**The return from Seadrill Ltd consists of the company's results prior to its Chapter 11 U.S. Bankruptcy Code restructuring in 2017 and after it emerged from bankruptcy in 2018.

Item 6. Selected Financial Data

The financial data below should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and notes thereto included in "Item 8. Financial Statements and Supplementary Data."



	Year Ended December 31,
	2019			2018			2017			2016			2015
	(in millions, except per share amounts)
Consolidated Statement of Operations Data
Revenues	$	2,053.2		$	1,705.4		$	1,843.0		$	2,776.4		$	4,063.4
Operating expenses
Contract drilling (exclusive of depreciation)	1,806.0			1,319.4			1,189.5			1,301.0			1,869.6
Loss on impairment	104.0			40.3			182.9			—			2,746.4
Depreciation	609.7			478.9			444.8			445.3			572.5
General and administrative	188.9			102.7			157.8			100.8			118.4
Total operating expenses	2,708.6			1,941.3			1,975.0			1,847.1			5,306.9
Equity in Earnings of ARO	(12.6		)	—			—			—			—
Operating income (loss)	(668.0		)	(235.9		)	(132.0		)	929.3			(1,243.5		)
Other income (expense), net	604.2			(303.0		)	(64.0		)	68.2			(227.7		)
Income tax expense (benefit)	128.4			89.6			109.2			108.5			(13.9		)
Income (loss) from continuing operations	(192.2		)	(628.5		)	(305.2		)	889.0			(1,457.3		)
Income (loss) from discontinued operations, net⁽¹⁾	—			(8.1		)	1.0			8.1			(128.6		)
Net income (loss)	(192.2		)	(636.6		)	(304.2		)	897.1			(1,585.9		)
Net (income) loss attributable to noncontrolling interests	(5.8		)	(3.1		)	0.5			(6.9		)	(8.9		)
Net income (loss) attributable to Valaris	$	(198.0	)	$	(639.7	)	$	(303.7	)	$	890.2		$	(1,594.8	)
Earnings (loss) per share – basic and diluted
Continuing operations	$	(1.14	)	$	(5.82	)	$	(3.66	)	$	12.40		$	(25.30	)
Discontinued operations	—			(.08		)	—			0.12			(2.20		)
	$	(1.14	)	$	(5.90	)	$	(3.66	)	$	12.52		$	(27.50	)
Weighted-average shares outstanding
Basic and diluted	173.4			108.5			83.1			69.8			58.1


⁽¹⁾	See Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on discontinued operations.



	Year Ended December 31,
	2019			2018			2017		2016		2015
	(in millions)
Consolidated Balance Sheet and Cash Flow Statement Data
Working capital	$	233.7		$	781.2		$	853.5	$	2,424.9	$	1,509.6
Total assets	$	16,931.2		$	14,023.7		$	14,625.9	$	14,374.5	$	13,610.5
Long-term debt	$	5,923.5		$	5,010.4		$	4,750.7	$	4,942.6	$	5,868.6
Valaris shareholders' equity	$	9,310.9		$	8,091.4		$	8,732.1	$	8,250.6	$	6,512.9
Cash flows from operating activities of continuing operations	$	(276.9	)	$	(55.7	)	$	259.4	$	1,077.4	$	1,697.9

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. Exclusive of two rigs under construction and one rig marked for retirement and classified as held-for-sale, we currently own and operate an offshore drilling rig fleet of 74 rigs, with drilling operations in almost every major offshore market across six continents. Inclusive of our rigs under construction, our rig fleet includes 16 drillships, eight dynamically positioned semisubmersible rigs, two moored semisubmersible rigs and 50 jackup rigs, nine of which are leased to our 50/50 joint venture with Saudi Aramco. 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.

Rowan Transaction

per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split (as defined herein).

Prior to the Rowan Transaction, Rowan and Saudi Aramco formed a 50/50 joint venture to own, manage and operate drilling rigs offshore Saudi Arabia ("Saudi Aramco Rowan Offshore Drilling Company" or "ARO"). ARO currently owns a fleet of seven jackup rigs, leases another nine jackup rigs from us and has plans to purchase up to 20 newbuild jackup rigs over an approximate 10 year period. In January 2020, ARO ordered the first two newbuild jackups scheduled for delivery in 2022. The rigs we lease to ARO are done so through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All nine jackup rigs leased to ARO and all seven ARO-owned jackup rigs are under long-term contracts with Saudi Aramco. For additional information about our ARO joint venture, see Note 4 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."

Reverse Stock Split

Upon closing of the Rowan Transaction, we effected a consolidation (being a reverse stock split under English law) whereby every four existing Valaris 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”). Our shares began trading on a reverse stock split-adjusted basis on April 11, 2019. All share and per share data included in this report have been retroactively adjusted to reflect the Reverse Stock Split.

Our Industry

Operating results in the offshore contract drilling industry are highly cyclical and are directly related to the demand for drilling rigs 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.

Drilling Rig Demand

More recently, oil prices have increased meaningfully from the decade lows reached during 2016, with Brent crude averaging nearly $55 per barrel in 2017 and more than $70 through most of 2018, leading to signs of a gradual recovery in demand for offshore drilling services. However, macroeconomic and geopolitical headwinds triggered a decline in Brent crude prices in late 2018, from more than $85 per barrel to approximately $50 per barrel. In 2019, oil prices experienced a gradual recovery from this decline with Brent crude prices averaging approximately $64 per barrel before falling near $55 per barrel in early 2020.

While this market volatility will likely continue over the near-term, we expect long-term oil prices to remain at levels sufficient to support a continued gradual recovery in demand for offshore drilling services. However, uncertainty remains regarding global trade and other geopolitical tensions in the Middle East and China and their resulting impact on the global economy. Adverse changes in the macro-economic environment resulting from trade

discussions, geopolitical events or other factors, including the impact of the coronavirus on global trade, could have a significant adverse impact on global economic growth and ultimately the demand for our offshore drilling services.

We continue to observe improvements in the shallow-water market, particularly with respect to higher-specification rigs, as higher levels of customer demand and rig retirements have led to gradually increasing jackup utilization over the past year. Moreover, global floater utilization has increased as compared to a year ago due to a higher number of contracted rigs and lower global supply resulting from rig retirements. However, the floater recovery has lagged the jackup recovery as average contract durations remain relatively short-term and pricing improvements to date have been modest.

Despite the increase in customer activity, contract awards remain subject to an extremely competitive bidding process, and the corresponding pressure on operating day rates in recent periods has resulted in low margin contracts, particularly for floaters. Therefore, our results from operations may continue to decline over the near-term as current contracts with above-market rates expire and new contracts are executed at lower rates. We believe further improvements in demand coupled with a reduction in rig supply are necessary to improve the commercial landscape for day rates.

Drilling Rig Supply

Drilling rig supply continues to exceed drilling rig demand for both floaters and jackups. However, the decline in customer capital expenditure budgets over the past several years has led to a lack of contracting opportunities resulting in meaningful global fleet attrition. Since the beginning of the downturn, drilling contractors have retired approximately 135 floaters and 100 jackups. As demand for offshore drilling has slowly begun to improve, newer more capable rigs have been the first to obtain new contract awards, increasing the likelihood that older, less capable rigs do not return to the global active fleet.

Approximately 20 floaters older than 30 years are idle, 10 additional floaters older than 30 years have contracts expiring by the end of 2020 without follow-on work and a further five floaters aged between 15 and 30 years have been idle for more than two years. 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.

Approximately 90 jackups older than 30 years are idle, and 60 jackups that are 30 years or older have contracts expiring by the end of 2020 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. We expect jackup scrapping and cold-stacking to continue during 2020.

There are 26 newbuild drillships and semisubmersibles reported to be under construction, of which 16 are scheduled to be delivered before the end of 2020. 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.

There are 51 newbuild jackups reported to be under construction, of which 41 are scheduled to be delivered before the end of 2020. 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.

Liquidity, Debt Maturities and Backlog

We proactively manage our capital structure in an effort to most effectively execute our strategic priorities and maximize value for shareholders. In support of these objectives, we are focused on our liquidity, debt levels and maturity profile and cost of capital. Over the past several years we have executed a number of financing transactions to improve our financial statement position and manage our debt maturities, including the July 2019 tender offers discussed below. Based on our balance sheet, our contractual backlog and $1.6 billion available under our credit facility, we expect to fund our anticipated 2020 liquidity needs, including negative operating cash flows, debt service and other contractual obligations, anticipated capital expenditures, as well as working capital requirements, from cash and short-term investments and funds borrowed under our credit facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction.

Our credit facility is an integral part of our financial flexibility and liquidity. We also may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs. In addition, we may seek to extend our maturities and reduce the overall principal amount of our debt through exchange offers or other liability management transactions. We have significant financial flexibility within our capital structure, including the ability to issue debt that would be structurally senior to our currently outstanding debt, on both an unsecured and secured basis, subject to restrictions contained in our existing debt arrangements. Our liability management efforts, if undertaken, may be unsuccessful or may not improve our financial position to the extent anticipated.

Our ability to maintain a sufficient level of liquidity to meet our financial obligations will also 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 example, if we experience further deterioration in demand for offshore drilling, our ability to maintain a sufficient level of liquidity could be materially and adversely impacted, which could have a material adverse impact on our business, financial condition, results of operations, cash flows and our ability to repay or refinance our debt.

Cash and Debt

As of December 31, 2019, we had $6.5 billion in total principal debt outstanding, representing 41.2% of our total capitalization. We also had $97.2 million in cash and $1.6 billion undrawn capacity under our credit facility, which expires in September 2022.

In December 2019, we received $200.0 million in cash resulting from the settlement of a dispute with Samsung Heavy Industries. See Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."

As a result of the Rowan Transaction, we acquired the following debt: (1) $201.4 million in aggregate principal amount of 7.875% unsecured senior notes, which was repaid at maturity in August 2019, (2) $620.8 million in aggregate principal amount of 4.875% unsecured senior notes due 2022, (3) $398.1 million in aggregate principal amount of 4.75% unsecured senior notes due 2024, (4) $500.0 million in aggregate principal amount of 7.375% unsecured senior notes due 2025, (5) $400.0 million in aggregate principal amount of 5.4% unsecured senior notes due 2042 and (6) $400.0 million in aggregate principal amount of 5.85% unsecured senior notes due 2044. Upon closing of the Rowan Transaction, we terminated Rowan's outstanding credit facilities.

On June 25, 2019, we commenced cash tender offers for certain senior notes issued by us, Ensco International Incorporated and Rowan Companies, Inc., our wholly-owned subsidiaries. The tender offers expired on July 23, 2019, and we repurchased $951.8 million aggregate principal amount of notes for a total purchase price of approximately $724.1 million, plus accrued interest.

As of December 31, 2019, our principal debt maturities include $122.9 million in 2020, $113.5 million in 2021, $620.8 million in 2022 and $1.8 billion in 2024.

Backlog

As of December 31, 2019, our backlog was $2.5 billion as compared to $2.2 billion as of December 31, 2018. Our floater backlog declined $94.2 million and our jackup backlog increased $210.2 million. These changes resulted from the addition of backlog from the Rowan Transaction, new contract awards and contract extensions offset by revenues realized during the period. Our other segment backlog increased $154.4 million due to the addition of backlog from the Rowan Transaction related to the rigs leased to ARO.

Contract backlog includes the impact of drilling contracts signed or terminated after each respective balance sheet date but prior to filing our annual reports on February 21, 2020 and February 28, 2019, respectively.

BUSINESS ENVIRONMENT

Floaters

The floater contracting environment remains challenging due to limited demand and excess newbuild 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. During the past year, we have observed increased tendering activity that may translate into marginal improvements in near-term utilization; however, further improvements in demand and/or reductions in supply will be necessary before meaningful increases in utilization and day rates are realized.

During the first quarter of 2019, we executed a four-well contract for VALARIS DS-9 that commenced offshore Brazil in June 2019 and a six-month contract for VALARIS DS-7 that commenced offshore Egypt in April 2019. Additionally, we executed a two-well contract for VALARIS DPS-1 that is expected to commence in March 2020 and a four-well contract for VALARIS 8503 that commenced in July 2019.

During the second quarter of 2019, we executed a one-well contract for VALARIS DS-18 in the U.S. Gulf of Mexico that commenced in February 2020. We also entered into short-term contract extensions for VALARIS DS-12 and VALARIS DPS-1.

During the third quarter of 2019, we executed a four-well contract for VALARIS DS-12 that is expected to commence offshore Angola in April 2020, a one-well contract for VALARIS DS-15 that is expected to commence in the U.S. Gulf of Mexico in January 2020 and a one-well contract for VALARIS DS-4 that is expected to commence offshore Ghana in March 2020. We also extended contracts for VALARIS DPS-1 by seven-wells with an estimated duration of 420 days, VALARIS 8505 by three-wells, VALARIS DS-16 by approximately 180 days and VALARIS DS-7 by approximately 165 days. Additionally, we began marketing the VALARIS 5006 for sale and classified the rig as held-for-sale. As a result, we recognized an impairment charge of $88.2 million in our consolidated statement of operations.

During the fourth quarter of 2019, we executed a one-year contract extension for VALARIS DS-10. VALARIS DS-7 was awarded a five-well contract that is expected to commence in September and has an estimated duration of 320 days. VALARIS DS-18 was awarded a two-well contract that is expected to commence in July 2020 and has an estimated duration of 180 days. VALARIS DS-18 also had a contract extension due to the exercise of one-well option. VALARIS DS-15 was awarded two contracts, a one-well contract that commenced in November 2019 and a two-well

contract expected to commence in May 2020. VALARIS DS-15 also had a contract extension due to the exercise of a one-well priced option, the contract has an estimated duration of 45 days and is expected to commence in March 2020. VALARIS DS-12 and VALARIS MS-1 were awarded one-well contracts that are expected to commence in February 2020 and July 2020, respectively. We also executed a one-well contract for VALARIS DS-9 that is expected to commence in July 2020. We also entered into a short-term contract extension for VALARIS 8503.

During the fourth quarter of 2019, we sold VALARIS 5006 for scrap value resulting in an insignificant pre-tax gain. We also began marketing the VALARIS 6002 and classified the rig as held-for-sale on our December 31, 2019 consolidated balance sheet. The VALARIS 6002 was subsequently sold in January 2020 resulting in an insignificant pre-tax gain.

Jackups

Demand for jackups has improved with increased contracting activity observed over the past year, leading to slight improvements in day rates.

During the first quarter of 2019, we executed a nine-well contract for VALARIS JU-100 that commenced in November 2019. As a result, a previously disclosed contract for VALARIS JU-100 has been fulfilled by VALARIS JU-248. Additionally, we executed a three-well contract for VALARIS JU-121 that commenced in April 2019 and three-well and one-well contracts for VALARIS JU-72 and VALARIS JU-68, respectively, that commenced during May 2019. We also executed short-term contract extensions for VALARIS JU-101 and VALARIS JU-96.

With respect to the Rowan jackups, a six-month contract extension with a two-month option was executed for VALARIS JU-248 during the first quarter. Additionally, short-term contracts were executed for VALARIS JU-292, VALARIS JU-290 and VALARIS JU-144. The VALARIS JU-290 and VALARIS JU-292 contracts include four additional one-well priced options and two short-term option periods, respectively.

During the second quarter of 2019, we executed a two-year contract for VALARIS JU-120, a two-well contract for VALARIS JU-122, a forty-well P&A contract for VALARIS JU-72, a five-month contract for VALARIS JU-107, two one-well contracts for VALARIS JU-102 and a one-well contract for VALARIS JU-101. Additionally, we executed a two-year extension for VALARIS JU-109, a seven-month extension for VALARIS JU-104, a six-month extension for VALARIS JU-247, a three-month extension for VALARIS JU-96 and one-well extensions for VALARIS JU-118 and VALARIS JU-144.

During the second quarter of 2019, we scrapped ENSCO 97 and the Gorilla IV and recognized an insignificant pre-tax gain.

During the third quarter of 2019, we executed a four-well contract for VALARIS JU-248, an accommodation contract for VALARIS JU-290, a one-well contract for VALARIS JU-107 and a one-well contract for VALARIS JU-87 that commenced in September. We also extended the contracts for VALARIS JU-291 by two-wells, VALARIS JU-247 by approximately eight months and received short-term extensions for VALARIS JU-88, VALARIS JU-115, VALARIS JU-117, VALARIS JU-123 and VALARIS JU-248.

During the fourth quarter of 2019, we executed a 200-day contract for VALARIS JU-249 and a 21-well contract for VALARIS JU-87, both of which commenced in November 2019, and a one-well contract for VALARIS JU-75 that commenced in December 2019. We also executed a 12-well contract for VALARIS JU-144 that is expected to commence in April 2020, a six-well contract for VALARIS JU-292 that is expected to commence in May 2020, and a three-well contract for VALARIS JU-101 that is expected to commence in March 2020. VALARIS JU-107 had a contract extension due to the exercise of one-well option and was also warded a two-well contract that is expected to commence in June 2020. Additionally, we executed short-term contract extensions for VALARIS JU-115, VALARIS JU-117, VALARIS JU-122, and VALARIS JU-290.

Additionally, in the fourth quarter of 2019, we sold VALARIS JU-42 for scrap value and recognized an insignificant gain. We also began marketing the VALARIS JU-68 and VALARIS JU-70 and classified the rigs as held-for-sale on our December 31, 2019 consolidated balance sheet. We recognized a pre-tax impairment charge of $10.2 million on the VALARIS JU-70. The VALARIS JU-68 was subsequently sold in January 2020 resulting in an insignificant pre-tax loss.

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. The operator could seek to terminate the contract under certain circumstances. If this drilling contract were to be terminated for cause, it would result in an approximate $8.5 million decrease in our backlog as of December 31, 2019. See Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."

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, 2019 (in millions):



	2019			2018			2017
Revenues	$	2,053.2		$	1,705.4		$	1,843.0
Operating expenses
Contract drilling (exclusive of depreciation)	1,806.0			1,319.4			1,189.5
Loss on impairment	104.0			40.3			182.9
Depreciation	609.7			478.9			444.8
General and administrative	188.9			102.7			157.8
Total operating expenses	2,708.6			1,941.3			1,975.0
Equity in earnings of ARO	(12.6		)	—			—
Operating loss	(668.0		)	(235.9		)	(132.0		)
Other income (expense), net	604.2			(303.0		)	(64.0		)
Provision for income taxes	128.4			89.6			109.2
Loss from continuing operations	(192.2		)	(628.5		)	(305.2		)
Income (loss) from discontinued operations, net	—			(8.1		)	1.0
Net loss	(192.2		)	(636.6		)	(304.2		)
Net (income) loss attributable to noncontrolling interests	(5.8		)	(3.1		)	.5
Net loss attributable to Valaris	$	(198.0	)	$	(639.7	)	$	(303.7	)

Overview

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 period, primarily due to transaction and integration costs associated with the Rowan Transaction.

Year Ended December 31, 2018

Revenues declined by $137.6 million, or 7%, as compared to the prior year. The decline was primarily due to a decline in average day rates in both our floater and jackup fleets and the sale of several rigs during the year that operated in the year-ago period, partially offset by increased utilization and the addition of Atwood rigs to the fleet in late 2017.

Contract drilling expense increased by $129.9 million, or 11%, as compared to the prior year. The increase was primarily due to addition of rigs to the fleet from the acquisition of Atwood Oceanics, Inc. (Atwood) and the commencement of drilling operations for several of our newbuild rigs. This increase was partially offset by the sale of several rigs during the year that operated in the year-ago period and cost incurred during the prior year to settle a previously disclosed legal contingency.

Excluding the impact of $7.5 million of transaction costs during 2018 and $51.6 million of transaction costs during 2017 from the Atwood acquisition, general and administrative expenses declined by $11.0 million, or 10%, as compared to the prior year. The decline was primarily due to lower compensation costs and the recovery of certain legal costs awarded to us in connection with the SHI litigation.

Rig Counts, Utilization and Average Day Rates

The following table summarizes our offshore drilling rigs by reportable segment, rigs under construction and rigs held-for-sale as of December 31, 2019, 2018 and 2017:



	2019	2018	2017
Floaters⁽¹⁾	24	22	24
Jackups⁽²⁾	41	34	37
Other⁽³⁾	9	—	—
Under construction⁽⁴⁾	2	3	3
Held-for-sale⁽⁵⁾	3	—	1
Total Valaris	79	59	65
ARO⁽⁶⁾	7	—	—


⁽¹⁾	During 2019, we added VALARIS DS-18, VALARIS DS-17, VALARIS DS-16 and VALARIS DS-15 from the Rowan Transaction, sold VALARIS 5006 and classified VALARIS 6002 as held-for-sale. During 2018, we sold ENSCO 5005 and ENSCO 6001.


⁽²⁾	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. During 2018, we sold ENSCO 80, ENSCO 81 and ENSCO 82.


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


⁽⁴⁾	During 2019, we accepted the delivery of VALARIS JU-123.


⁽⁵⁾	During 2019, we classified VALARIS JU-68, VALARIS JU-70 and VALARIS 6002 as held-for-sale. During 2018, we sold ENSCO 7500.


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

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, 2019. Rig utilization and average day rates include results for Rowan rigs and ARO from the transaction date through December 31, 2019:



	2019		2018		2017
Rig Utilization⁽¹⁾
Floaters	47%		46%		45%
Jackups	66%		63%		60%
Other⁽²⁾	100%		100%		100%
Total Valaris	63%		56%		55%
ARO	93%		—%		—%
Average Day Rates⁽³⁾
Floaters	$	218,837	$	248,395	$	327,736
Jackups	78,133		77,086		84,913
Other⁽²⁾	49,236		81,751		79,566
Total Valaris	$	108,313	$	128,365	$	153,306
ARO	$	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 managed 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

Prior to the Rowan Transaction, our business consisted of three operating segments: (1) Floaters, which included our drillships and semisubmersible rigs, (2) Jackups and (3) Other, which consisted only of our management services provided on rigs owned by third parties. Our Floaters and Jackups were also reportable segments.

activities associated with our arrangements with ARO, consisting of our Transition Services Agreement, Rig Lease Agreements and Secondment Agreement, do not constitute reportable segments and are therefore included within Other in the following segment disclosures. 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.

General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items." The full operating results included below for ARO (representing only results of ARO from the Transaction Date) are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See Note 4 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, 2019 is presented below (in millions).

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	378.6			212.4			40.3		—		(21.6		)	609.7
General and administrative	—			—			27.1		—		161.8			188.9
Equity in earnings of ARO	—			—			—		—		(12.6		)	(12.6		)
Operating income (loss)	$	(351.0	)	$	(176.9	)	$	62.9	$	85.7	$	(288.7	)	$	(668.0	)

Year Ended December 31, 2018



	Floaters			Jackups			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	)

Year Ended December 31, 2017



	Floaters		Jackups			Other		Reconciling Items			Consolidated Total
Revenues	$	1,143.5	$	640.3		$	59.2	$	—		$	1,843.0
Operating expenses
Contract drilling (exclusive of depreciation)	624.2		512.1			53.2		—			1,189.5
Loss on impairment	174.7		8.2			—		—			182.9
Depreciation	297.4		131.5			—		15.9			444.8
General and administrative	—		—			—		157.8			157.8
Operating income (loss)	$	47.2	$	(11.5	)	$	6.0	$	(173.7	)	$	(132.0	)

Floaters

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 $66.8 million, or 21%, 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.

During 2018, revenues declined by $130.0 million, or 11%, as compared to the prior year primarily due to lower average day rates resulting from the expiration of above-market, older contracts that were replaced with new market-rate contracts and sale of ENSCO 6001. The decline was partially offset by the addition of Atwood rigs to the fleet and commencement of VALARIS DS-10 drilling operations.

Contract drilling expense increased by $113.2 million, or 18%, as compared to the prior year primarily due to the addition of Atwood rigs to the fleet and commencement of VALARIS DS-10 drilling operations. This increase was partially offset by the sale of ENSCO 6001, lower rig reactivation costs and costs incurred in the prior year to settle a previously disclosed legal contingency.

Depreciation expense increased by $14.4 million, or 5%, compared to the prior year primarily due to the addition of Atwood rigs and commencement of VALARIS DS-10 drilling operations. The increase was partially offset by lower depreciation expense on non-core assets that were impaired to scrap value during the fourth quarter of 2017.

Jackups

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 $59.1 million, or 39%, as compared to the prior year primarily due to the addition of Rowan rigs to the fleet and the commencement of VALARIS JU-123 drilling operations.

During 2018, revenues declined by $9.4 million, or 1%, as compared to the prior year primarily due to the sale of ENSCO 52 and ENSCO 80 and lower average day rates across the fleet. These declines were partially offset by more days under contract across the fleet, the commencement of VALARIS JU-140 and VALARIS JU-141 contracts and the addition of Atwood rigs to the fleet.

Contract drilling expense increased by $14.4 million, or 3%, as compared to the prior year primarily due to more days under contract across the fleet, the addition of Atwood rigs and contract commencements for VALARIS JU-140 and VALARIS JU-141. These increases were partially offset by lower rig reactivation costs and the sale of ENSCO 52 and ENSCO 80.

Depreciation expense increased by $21.8 million, or 17%, as compared to the prior year primarily due to the addition of Atwood rigs and VALARIS JU-140 and VALARIS JU-141 to the fleet. The increase was partially offset by lower depreciation expense on a non-core rig that was impaired to scrap value during the fourth quarter of 2017.

ARO

ARO currently owns a fleet of seven jackup rigs, leases another nine jackup rigs from us and plans to purchase up to 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 rigs we lease to ARO are done so 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 and the nine rigs leased from us that operated during the period from the Transaction Date through December 31, 2019.

The contract drilling, depreciation and general and administrative expenses are also for the period from the Transaction Date through December 31, 2019. Contract drilling expenses are inclusive of the bareboat charter fees for the rigs leased from us and costs incurred under the Secondment Agreement. General and administrative expenses include costs incurred under the Transition Services Agreement and other administrative costs.

Other

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 6 and Note 14 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, 2019 (in millions):



	2019			2018			2017
Interest income	$	28.1		$	14.5		$	25.8
Interest expense, net:
Interest expense	(449.2		)	(345.3		)	(296.7		)
Capitalized interest	20.9			62.6			72.5
	(428.3		)	(282.7		)	(224.2		)
Other, net	1,004.4			(34.8		)	134.4
	$	604.2		$	(303.0	)	$	(64.0	)

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 4 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on ARO) acquired in the Rowan Transaction. Interest income declined during 2018 as compared to the respective prior-year period as a result of a decrease in our average short-term investment balances.

Interest expense increased during 2019 by $103.9 million, or 30%, as compared to the prior year due to interest expense incurred on Rowan's senior notes. Interest expense increased during 2018 by $48.6 million, or 16%, as compared to the prior year due to debt transactions we undertook during the first quarter of 2018 (see Note 7 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on debt).

Interest expense capitalized declined during 2019 and 2018 by $41.7 million, or 67%, and $9.9 million, or 14%, 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.

Other, net, during 2019 included a gain on bargain purchase recognized in connection with the Rowan Transaction of $637.0 million, a pre-tax gain related to the settlement award from the SHI matter of $200.0 million discussed in Note 13 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" 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 13 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 $7.4 million, $17.2 million and $5.1 million, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, respectively. Net foreign currency exchange losses incurred during 2019 included $3.3 million and $2.8 million, related to euros and Angolan kwanza, respectively. Net foreign currency exchange losses incurred during 2018 included $5.8 million, $3.6 million and $2.0 million, related to Angolan kwanza, euros and Brazilian reals, respectively. During 2017, the net foreign currency exchange losses incurred were $2.1 million, $1.9 million and $1.0 million, related to euros, Indonesian rupiahs and Brazilian reals, respectively.

Net unrealized gains of $5.0 million, unrealized losses of $0.7 million and unrealized gains of $4.5 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, 2019, 2018 and 2017, respectively. Information on the fair value measurement of our marketable securities held in the SERP is presented in Note 5 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

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, including a reduction in the statutory income tax rate from 35% to 21% effective January 1, 2018, 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.

Due to the timing of the enactment of U.S. tax reform and the complexity involved in applying its provisions, we made reasonable estimates of its effects and recorded such amounts in our consolidated financial statements as of December 31, 2017 on a provisional basis. Throughout 2018, we continued to analyze applicable information and data, interpret rules and guidance issued by the U.S. Treasury Department and Internal Revenue Service, and make adjustments to the provisional amounts, as provided for in Staff Accounting Bulletin No. 118. 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. We recognized a net tax expense of $16.5 million during the fourth quarter of 2017 in connection with enactment of U.S. tax reform, consisting of a $38.5 million tax expense associated with the one-time transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries, a $17.3 million tax expense associated with revisions to rules over the taxation of income of foreign subsidiaries, a $20.0 million tax benefit resulting from the re-measurement of our deferred tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate and a $19.3 million tax benefit resulting from adjustments to the valuation allowance on deferred tax assets.

See Note 12 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Effective Tax Rate

During the years ended December 31, 2019, 2018 and 2017, we recorded income tax expense of $128.4 million, $89.6 million and $109.2 million, respectively. Our consolidated effective income tax rates were (201.3)%, (16.6)% and (55.7)% during the same periods, respectively.

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 and rig sales.

Our 2017 consolidated effective income tax rate included $32.2 million associated with the impact of various discrete tax items, including $16.5 million of tax expense associated with U.S. tax reform and $15.7 million of tax expense associated with the exchange offers and debt repurchases, rig sales, a restructuring transaction, settlement of a previously disclosed legal contingency, the effective settlement of a liability for unrecognized tax benefits associated with a tax position taken in prior years and other resolutions of prior year tax matters.

Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years ended December 31, 2019, 2018 and 2017 were (14.6)%, (24.8)% and (96.0)%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-year period result primarily from U.S. tax reform and 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

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. Consistent with this strategy, we sold 12 jackup rigs, two dynamically positioned semisubmersible rigs and two moored semisubmersible rigs during the three-year period ended December 31, 2019.

We continue to focus on our fleet management strategy in light of the composition of our rig fleet. As part of this strategy, we may act opportunistically from time to time to monetize assets to enhance shareholder value and improve our liquidity profile, in addition to selling or disposing of older, lower-specification or non-core rigs.

We sold the following rigs during the three-year period ended December 31, 2019 (in millions):



Rig	Date of Sale	Classification⁽¹⁾	Segment⁽¹⁾	Net Proceeds		Net Book Value⁽²⁾		Pre-tax Gain/(Loss)
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
ENSCO 52	August 2017	Continuing	Jackups	.8		.4		.4
ENSCO 86	June 2017	Continuing	Jackups	.3		.3		—
ENSCO 90	June 2017	Discontinued	Jackups	.3		.3		—
ENSCO 99	June 2017	Continuing	Jackups	.3		.3		—
ENSCO 56	April 2017	Continuing	Jackups	1.0		.3		.7
				$	30.3	$	19.4	$	10.9


⁽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

We proactively manage our capital structure in an effort to most effectively execute our strategic priorities and maximize value for shareholders. In support of these objectives, we are focused on our liquidity, debt levels and maturity profile and cost of capital. Over the past several years, we have executed a number of financing transactions to improve our financial position and manage our debt maturities, including the July 2019 tender offers discussed below. Based on our balance sheet, our contractual backlog and $1.6 billion of undrawn capacity under our credit facility, we expect to fund our liquidity needs, including expected negative operating cash flows, contractual obligations, anticipated capital expenditures, as well as working capital requirements, from cash and funds borrowed under our credit facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction.

Additionally, as a result of the Rowan Transaction, we acquired the following debt: (1) $201.4 million in aggregate principal amount of 7.875% unsecured senior notes, which was repaid at maturity in August 2019, (2) $620.8 million in aggregate principal amount of 4.875% unsecured senior notes due 2022, (3) $398.1 million in aggregate principal amount of 4.75% unsecured senior notes due 2024, (4) $500.0 million in aggregate principal amount of 7.375% unsecured senior notes due 2025, (5) $400.0 million in aggregate principal amount of 5.4% unsecured senior notes due 2042 and (6) $400.0 million in aggregate principal amount of 5.85% unsecured senior notes due 2044. Upon closing of the Rowan Transaction, we terminated Rowan's outstanding credit facilities.

During the three-year period ended December 31, 2019, our primary sources of cash were $1.4 billion from net maturities of short-term investments, $1.0 billion in proceeds from the issuance of senior notes, and Rowan cash acquired of $931.9 million. Our primary uses of cash during the same period included $2.2 billion for the repurchase and redemption of outstanding debt, $1.2 billion for the construction, enhancement and other improvement of our drilling rigs, including $813.7 million invested in newbuild construction, $871.6 million for the repayment of Atwood debt and $36.2 million for dividend payments.

Explanations of our liquidity and capital resources for each of the years in the three-year period ended December 31, 2019 are set forth below.

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, 2019 were as follows (in millions):



	2019			2018			2017
Net cash provided by (used in) operating activities of continuing operations	$	(276.9	)	$	(55.7	)	$	259.4
Capital expenditures:
New rig construction	$	42.8		$	341.1		$	429.8
Rig enhancements	114.9			45.2			45.1
Minor upgrades and improvements	69.3			40.4			61.8
	$	227.0		$	426.7		$	536.7

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. As our remaining above-market contracts expire and utilization increases with the execution of new market-rate contracts, coupled with the potential impact of rig reactivation costs, our operating cash flows will remain negative through at least 2020.

During 2018, cash flows from continuing operations declined by $315.1 million, or 121%, as compared to the prior year due primarily to declining margins and higher cash interest expense due to the debt financing transactions we undertook during the first quarter of 2018.

Based on our current projections, excluding integration-related capital expenditures, we expect capital expenditures during 2020 to approximate $160.0 million for newbuild construction, rig enhancement projects and minor upgrades and improvements. Approximately $30 million of our projected capital expenditures is reimbursable by our customers. Depending on market conditions and opportunities, we may reduce our planned expenditures or make additional capital expenditures to upgrade rigs for customer requirements or acquire additional rigs.

Dividends

Our Board of Directors declared a $0.01 quarterly cash dividend, on a pre-reverse stock split basis, for the first quarter of 2019. Beginning in the second quarter of 2019, our Board of Directors determined that we will not pay a regular quarterly cash dividend. The declaration and amount of future dividends is at the discretion of our Board of Directors and could change in future periods.

Financing and Capital Resources

Debt to Capital

Our total debt, total capital and total debt to total capital ratios as of December 31, 2019, 2018 and 2017 are summarized below (in millions, except percentages):



	2019			2018			2017
Total debt ⁽¹⁾	$	6,528.1		$	5,161.0		$	4,882.8
Total capital⁽²⁾	$	15,839.0		$	13,252.4		$	13,614.9
Total debt to total capital	41.2		%	38.9		%	35.9		%

(1)Total debt consists of the principal amount outstanding.

(2)Total capital consists of total debt and Valaris shareholders' equity.

During 2019, our total debt principal increased by $1.4 billion and total capital increased by $2.6 billion as a result of debt acquired and equity issued in connection with the Rowan Transaction (see Note 3 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data").

During 2018, our total debt increased by $278.2 million and total capital declined by $362.5 million. Our total debt increased as a result of the debt transactions we undertook during the first quarter of 2018 (see Note 7 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data") and our total capital declined as a result of our net loss incurred in that period, partially offset by the aforementioned increase in our total debt.

Convertible Senior Notes

In December 2016, Ensco Jersey Finance Limited, a wholly-owned subsidiary of Valaris plc, issued $849.5 million aggregate principal amount of unsecured 2024 Convertible Notes (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 and are exchangeable into cash, our Class A ordinary shares or a combination thereof, at our election. 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.

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 7 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our 2024 Convertible Notes.

Senior Notes

As a result of the Rowan Transaction, we acquired the following debt issued by 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 was repaid at maturity in August 2019, (2) $620.8 million in aggregate principal amount of 4.875% unsecured senior notes due 2022 (the "Rowan 2022 Notes"), (3) $398.1 million in aggregate principal amount of 4.75% unsecured senior notes due 2024 (the "Rowan 2024 Notes"), (4) $500.0 million in aggregate principal amount of 7.375% unsecured senior notes due 2025 (the "Rowan 2025 Notes"), (5) $400.0 million in aggregate principal amount of 5.4% unsecured senior notes due 2042 (the "Rowan 2042 Notes") and (6) $400.0 million in aggregate principal amount of 5.85% unsecured senior notes due 2044 (the "Rowan 2044 Notes" and collectively, the "Rowan Notes"). Upon closing of the Rowan Transaction, we terminated Rowan's outstanding credit facilities. 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 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, $500.0 million aggregate principal amount of unsecured 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of unsecured 7.875% senior notes due 2040 (collectively, the "Acquired Notes" and together with the Rowan Notes, 2021 Notes, 8% 2024 Notes, 2024 Notes, 2025 Notes, 2026 Notes and 2044 Notes, the "Senior Notes"). Valaris plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes. See "Note 17 - Guarantee of Registered Securities" included in "Item 8. Financial Statements and Supplementary Data" for additional information on the guarantee of the Acquired Notes.

We may redeem the Senior Notes in whole at any time, or in part from time to time, prior to maturity. If we elect to redeem the Rowan 2022 Notes, Rowan 2024 Notes, 8% 2024 Notes, 2024 Notes, 2025 Notes, Rowan 2025 Notes and 2026 Notes before the date that is three months prior to the maturity date or the Rowan 2042 Notes, Rowan 2044 Notes and 2044 Notes before the date that is six months prior to the maturity date, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest and a "make-whole" premium. If we elect to redeem these notes on or after the aforementioned dates, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, but we are not required to pay a "make-whole" premium.

We may redeem each series of the 2021 Notes and the Acquired Notes, in whole or in part, at any time at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a "make-whole" premium.

The indentures governing the Senior Notes contain customary events of default, including failure to pay principal or interest on such notes when due, among others. The indentures governing the Senior Notes also contain 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. See "Note 17 - Guarantee of Registered Securities" included in "Item 8. Financial Statements and Supplementary Data" for additional information on the guarantee of the Debentures.

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.

Tender Offers and Open Market Repurchases

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.

During 2017, we repurchased $194.1 million of our outstanding senior notes on the open market for an aggregate purchase price of $204.5 million with cash on hand and recognized an insignificant pre-tax loss, net of discounts, premiums and debt issuance costs.

Our tender offers and open market repurchases during the three-year period ended December 31, 2019 are summarized in the following table (in millions):



	Aggregate Principal Amount Repurchased		Aggregate Repurchase Price⁽¹⁾
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
Year Ended December 31, 2017
8.50% Senior notes due 2019	$	54.6	$	60.1
6.875% Senior notes due 2020	100.1		105.1
4.70% Senior notes due 2021	39.4		39.3
	$	194.1	$	204.5

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

Exchange Offers

During 2017, we completed exchange offers to exchange our outstanding 2019, 2020 and 2021 notes for the 8% 2024 Notes and cash. The exchange offers resulted in the tender of $649.5 million aggregate principal amount of our outstanding notes that were settled and exchanged as follows (in millions):



	Aggregate Principal Amount Repurchased		8% Senior Notes Due 2024 Consideration		Cash Consideration		Total Consideration
8.50% Senior notes due 2019	$	145.8	$	81.6	$	81.7	$	163.3
6.875% Senior notes due 2020	129.8		69.3		69.4		138.7
4.70% Senior notes due 2021	373.9		181.1		181.4		362.5
	$	649.5	$	332.0	$	332.5	$	664.5

During the year ended December 31, 2017, we recognized a pre-tax loss on the exchange offers of approximately $6.2 million.

Revolving Credit

Effective upon closing of the Rowan Transaction, we amended our credit facility to, among other changes, increase the borrowing capacity. Previously, our credit facility had a borrowing capacity of $2.0 billion through September 2019 that declined to $1.3 billion through September 2020 and $1.2 billion through September 2022. Subsequent to the amendment, our borrowing capacity was $1.7 billion through September 2022. Following the amendment, our borrowing capacity was reduced by $75 million to $1.6 billion. The reduction occurred after we became aware that a signatory for a purported lender was not an authorized representative of that lender and therefore concluded the $75 million was not binding. The credit agreement governing the credit facility includes an accordion feature allowing us to increase the future commitments by up to an aggregate amount not to exceed $250.0 million.

Advances under the credit facility bear interest at Base Rate or LIBOR plus an applicable margin rate, depending on our credit ratings. We are required to pay a quarterly commitment fee on the undrawn portion of the $1.6 billion commitment, which is also based on our credit ratings.

On December 6, 2019, Moody's downgraded our corporate family rating from B3 to Caa1 and our senior unsecured notes from Caa1 to Caa2. Previously, in September 2019, Standard & Poor's downgraded our senior unsecured bonds from B to B- and our issuer rating from B- to CCC+. The rating actions did not impact the interest rates applicable to our borrowings and the quarterly commitment fee on the undrawn portion of the $1.6 billion commitment. The applicable margin rates are 3.25% per annum for Base Rate advances and 4.25% per annum for LIBOR advances. The quarterly commitment fee is 0.75% per annum on the undrawn portion of the $1.6 billion commitment.

The credit facility requires us to maintain a total debt to total capitalization ratio that is less than or equal to 60% and to provide guarantees from certain of our rig-owning subsidiaries sufficient to meet certain guarantee coverage ratios. The credit facility also contains customary restrictive covenants, including, among others, prohibitions on creating, incurring or assuming certain debt and liens (subject to customary exceptions, including a permitted lien basket that permits us to raise secured debt up to the lesser of $1 billion or 10% of consolidated tangible net worth (as defined in the credit facility)); entering into certain merger arrangements; selling, leasing, transferring or otherwise disposing of all or substantially all of our assets; making a material change in the nature of the business; paying or distributing dividends on our ordinary shares (subject to certain exceptions, including the ability to pay a quarterly dividend of $0.01 per share); borrowings, if after giving effect to any such borrowings and the application of the proceeds thereof, the aggregate amount of available cash (as defined in the credit facility) would exceed $200 million; and entering into certain transactions with affiliates.

The credit facility also includes a covenant restricting our ability to repay indebtedness maturing after September 2022, which is the final maturity date of our credit facility. This covenant is subject to certain exceptions that permit us to manage our balance sheet, including the ability to make repayments of indebtedness (i) of acquired companies within 90 days of the completion of the acquisition or (ii) if, after giving effect to such repayments, available cash is greater than $250 million and there are no amounts outstanding under the credit facility.

As of December 31, 2019, we were in compliance in all material respects with our covenants under the credit facility. We expect to remain in compliance with our credit facility covenants during 2020. We had no amounts outstanding under the credit facility as of December 31, 2019 and 2018. As of January 31, 2020, we had $90 million of total outstanding borrowings under our credit facility.

Our access to credit and capital markets is limited because of our credit rating. Our current credit ratings, and any additional actual or anticipated downgrades in our corporate credit ratings or the credit rating of our notes will limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. In addition, future financings or refinancings will result in higher borrowing costs and may require collateral and/or more restrictive terms and covenants, which may further restrict our operations. Limitations on our ability to access credit and capital markets could have a material adverse impact on our financial position, operating results or cash flows.

Maturities

The descriptions of our senior notes above reflect the original principal amounts issued, which have subsequently changed as a result of our tenders, repurchases, exchanges, redemptions and new debt issuances such that the maturities of our debt at December 31, 2019 were as follows (in millions):



Senior Notes	Original Principal		2016 Tenders, Repurchases and Equity Exchange			2017 Exchange Offers and Repurchases			2018 Tender Offers, Redemption			2019 Tender Offers and Acquired Debt			Remaining Principal
6.875% due 2020	$	900.0	$	(219.2	)	$	(229.9	)	$	(328.0	)	$	—		$	122.9
4.70% due 2021	1,500.0		(817.0		)	(413.3		)	(156.2		)	—			113.5
4.875% due 2022 ⁽¹⁾	—		—			—			—			620.8			620.8
3.00% Exchangeable senior notes due 2024	849.5		—			—			—			—			849.5
4.50% due 2024	625.0		(1.7		)	—			—			(320.0		)	303.3
4.75% due 2024 ⁽¹⁾	—		—			—			—			318.6			318.6
8.00% due 2024	—		—			332.0			—			(39.7		)	292.3
5.20% due 2025	700.0		(30.7		)	—			—			(335.5		)	333.8
7.375% due 2025 ⁽¹⁾	—		—			—			—			360.8			360.8
7.75% due 2026	—		—			—			1,000.0			—			1,000.0
7.20% due 2027	150.0		—			—			—			(37.9		)	112.1
7.875% due 2040	300.0		—			—			—						300.0
5.40% due 2042 ⁽¹⁾	—		—			—			—			400.0			400.0
5.75% due 2044	1,025.0		(24.5		)	—			—			—			1,000.5
5.85% due 2044 ⁽¹⁾	—		—			—			—			400.0			400.0
Total	$	6,549.5	$	(1,155.1	)	$	(511.6	)	$	278.2		$	1,367.1		$	6,528.1

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

Other Financing Arrangements

We filed an automatically effective shelf registration statement on Form S-3 with the U.S. Securities and Exchange Commission on November 21, 2017, which provides us the ability to issue debt securities, equity securities, guarantees and/or units of securities in one or more offerings. The registration statement expires in November 2020.

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, 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, 2019, there had been no share repurchases under this program. Our credit facility prohibits us from repurchasing our shares, except in certain limited circumstances. Any share repurchases, outside of such limited circumstances, would require the amendment or waiver of such provision.

From time to time, we and our affiliates may repurchase our outstanding senior notes in the open market, in privately negotiated transactions, through tender offers, exchange offers or otherwise, or we may redeem senior notes, pursuant to their terms. In connection with any exchange, we may issue equity, issue new debt (including debt that is structurally senior to our existing senior notes) and/or pay cash consideration. Any future repurchases, exchanges or redemptions will depend on various factors existing at that time. There can be no assurance as to which, if any, of these alternatives (or combinations thereof) we may choose to pursue in the future or, if any such alternatives are pursued, that they will be successful. There can be no assurance that an active trading market will exist for our outstanding senior notes following any such transaction.

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 earn interest at LIBOR plus two percent and mature during 2027 and 2028.

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 4 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, 2019 (in millions):



Maturity Date	Principal amount
October 2027	$	275.2
October 2028	177.7
Total	$	452.9

Contractual Obligations

We have various contractual commitments related to our new rig construction and rig enhancement agreements, long-term debt and operating leases. We expect to fund these commitments from existing cash and short-term investments and funds borrowed under our credit facility or other future financing arrangements, including available shipyard financing options for our two drillships under construction. The actual timing of our new rig construction and rig enhancement payments may vary based on the completion of various milestones, which are beyond our control. The following table summarizes our significant contractual obligations as of December 31, 2019 and the periods in which such obligations are due (in millions):



	Payments due by period
	2020		2021 and 2022		2023 and 2024		Thereafter		Total
Principal payments on long-term debt	$	122.9	$	734.3	$	1,763.7	$	3,907.2	$	6,528.1
Interest payments on long-term debt	377.4		714.8		634.7		2,536.1		4,263.0
New rig construction agreements^{(1) (2)}	—		248.9		—		—		248.9
Operating leases	25.4		31.0		18.8		17.2		92.4
Total contractual obligations⁽³⁾	$	525.7	$	1,729.0	$	2,417.2	$	6,460.5	$	11,132.4

(1)During 2019, we entered into amendments to our construction agreements with the shipyard for VALARIS DS-13 and VALARIS DS-14 to provide for, among other things, two-year extensions of the delivery date of each rig in exchange for payment of all accrued holding costs through March 31, 2019, totaling approximately $23 million. The new delivery dates for the VALARIS DS-13 and VALARIS DS-14 are September 30, 2021 and June 30, 2022, respectively. We can elect to request earlier delivery in certain circumstances. The interest rate on the final milestone payments increased from 5% to 7% per annum from October 1, 2019, for the VALARIS DS-13, and from July 1, 2020, for the VALARIS DS-14, until the actual delivery dates. The final milestone payments and applicable interest are due at the new delivery dates (or, if accelerated, the actual delivery dates) and are estimated to be approximately $313.3 million in aggregate for both rigs, inclusive of interest, assuming we take delivery on the new delivery date. In lieu

of making the final milestone payments, we have the option to take delivery of the rigs and issue a promissory note for each rig to the shipyard owner for the amount due. If we issue the promissory note to the shipyard owner, we would also be required to provide a guarantee from Valaris plc.

(2)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.

(3)Contractual obligations do not include $323.1 million of unrecognized tax benefits, inclusive of interest and penalties, included on our consolidated balance sheet as of December 31, 2019. 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. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis. See Note 3 and Note 4 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data." for additional information on the Rowan Transaction and our joint venture with ARO, respectively.

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, 2019, we had not been required to make collateral deposits with respect to these agreements. The following table summarizes our other commitments as of December 31, 2019 (in millions):



	Commitment expiration by period
	2020		2021 and 2022		2023 and 2024		Thereafter		Total
Letters of credit	$	82.7	$	10.6	$	—	$	6.2	$	99.5

Liquidity

Our liquidity position as of December 31, 2019, 2018 and 2017 is summarized below (in millions, except ratios):



	2019		2018		2017
Cash and cash equivalents	$	97.2	$	275.1	$	445.4
Short-term investments	—		329.0		440.0
Available credit facility borrowing capacity	1,622.2		2,000.0		2,000.0
Total liquidity	$	1,719.4	$	2,604.1	$	2,885.4
Working capital	$	233.7	$	781.2	$	853.5
Current ratio	1.3		2.5		2.1

We expect to fund our liquidity needs, including contractual obligations and anticipated capital expenditures, as well as working capital requirements, from our cash, and funds borrowed under our credit facility or future financing arrangements, including available shipyard financing options for our two drillships under construction. We may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs. As of December 31, 2019, we had no amounts drawn under our credit facility and $1.6 billion in remaining borrowing capacity.

Recent Tax Assessments

During 2019, we received income tax assessments totaling approximately €142.0 million (approximately $159.0 million converted using the current period-end exchange rates) and A$101 million (approximately $70.9 million converted at current period-end exchange rates) from taxing authorities in Luxembourg and Australia, respectively. We are contesting these assessments and have filed applications for appeal. 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 may make a payment to the Luxembourg tax authorities in advance of the final resolution of these assessments. Although the outcome of such assessments cannot be predicted with certainty, unfavorable outcomes could have a material adverse effect on our liquidity. We have recorded a $119.0 million liability for these assessments as of December 31, 2019. See Note 12 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. However, in 2019, the United States formally initiated the process of withdrawing from participation in the Paris Agreement, with such withdrawal taking place no earlier than November 4, 2020. In response to the announced withdrawal plan, a number of state and local governments in the United States have expressed intentions to take GHG-related actions by implementing their own programs to reduce GHG emissions. 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.

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.

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, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and 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.

MARKET RISK

We use derivatives to reduce our exposure to foreign currency exchange rate risk. Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar. We maintain a foreign currency exchange rate risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates.

We utilize cash flow hedges to hedge forecasted foreign currency denominated transactions, primarily to reduce our exposure to foreign currency exchange rate risk on future expected contract drilling expenses and capital expenditures denominated in various foreign currencies. 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. As of December 31, 2019, we had cash flow hedges outstanding to exchange an aggregate $199.1 million for various foreign currencies.

We have net assets and liabilities denominated in numerous foreign currencies and use various strategies to manage our exposure to changes in foreign currency exchange rates. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities, thereby reducing exposure to earnings fluctuations caused by changes in foreign currency exchange rates. We do not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes in the carrying value of the underlying hedged items. As of December 31, 2019, we held derivatives not designated as hedging instruments to exchange an aggregate $47.1 million for various foreign currencies.

If we were to incur a hypothetical 10% adverse change in foreign currency exchange rates, net unrealized losses associated with our foreign currency denominated assets and liabilities as of December 31, 2019 would approximate $27.1 million. Approximately $1.6 million of these unrealized losses would be offset by corresponding gains on the derivatives utilized to offset changes in the fair value of net assets and liabilities denominated in foreign currencies.

We utilize derivatives and undertake foreign currency exchange rate hedging activities in accordance with our established policies for the management of market risk. We mitigate our credit risk relating to counterparties of our 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 include provisions for a legally enforceable master netting agreement, with our derivative counterparties. The terms of the ISDA agreements may also include 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.

We do not enter into derivatives for trading or other speculative purposes. We believe that our use of derivatives and related hedging activities reduces our exposure to foreign currency exchange rate risk and does not expose us to material credit risk or any other material market risk. All our derivatives mature during the next 18 months. See Note 8 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our derivative instruments.

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 to our consolidated financial statements. 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, 2019, the carrying value of our property and equipment totaled $15.1 billion, which represented 89% 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 2019, we recorded a pre-tax, non-cash loss on impairment of $98.4 million related to one floater and one jackup rig, both of which are older, less capable, non-core assets in our fleet. We estimate the aforementioned impairment will cause a decline in depreciation expense of approximately $8.6 million for the year ended December 31, 2020.

Our fleet of 24 floater rigs, excluding two rigs under construction, represented 64% of the gross cost and 63% of the net carrying amount of our depreciable property and equipment as of December 31, 2019. Our floater rigs are depreciated over useful lives ranging from 10 to 35 years. Our fleet of 50 jackup rigs, represented 31% of both the gross cost and of the net carrying amount of our depreciable property and equipment as of December 31, 2019. Our jackup rigs are depreciated over useful lives ranging from 10 to 30 years.

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, 2019 for various assumed changes in the useful lives of our drilling rigs effective January 1, 2019:



Increase (decrease) in useful lives of our drilling rigs		Estimated (decrease) increase in depreciation expense that would have been recognized (in millions)
10%		$(50.8)
20%		(93.2)
(10%)		61.9
(20%)		138.6

Impairment of Property and Equipment

We recorded pre-tax, non-cash losses on impairment of long-lived assets of $98.4 million, $40.3 million and $182.9 million during 2019, 2018 and 2017, respectively. See Note 6 to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our property and equipment.

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. 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 most subjective 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,


•	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, 2019, our consolidated balance sheet included a $72.4 million net deferred income tax liability, a $45.6 million liability for income taxes currently payable and a $323.1 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, and we currently anticipate that this trend will continue.


•	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, 2019, included (i) a weighted average discount rate of 3.16% to determine pension benefit obligations, (ii) a weighted average discount rate of 3.82% to determine net periodic pension cost and (iii), an expected long-term rate of return on pension plan assets of 6.48%. 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 $108.8 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 $4.0 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 was 6.48% at December 31, 2019.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 1 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

Information required under Item 7A. has been incorporated into "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."

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, 2019 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.

Management's assessment of the effectiveness of the Company's internal control over financial reporting as of December 31, 2019 excluded Rowan Companies plc internal control over financial reporting associated with total revenue of $135.0 million and total expenses of $259.0 million included in the consolidated financial statements of Valaris plc and subsidiaries for the year ended December 31, 2019.

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.

February 21, 2020

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, 2019 and 2018, the related consolidated statements of operations, comprehensive loss, and cash flows for each of the years in the three‑year period ended December 31, 2019 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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2019, 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, 2019, 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 February 21, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

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.

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.

Assessment of the valuation of property and equipment and investment in joint venture acquired in the Rowan Transaction

As discussed in Notes 1 and 3 to the consolidated financial statements, the Company merged with Rowan Companies plc on April 11, 2019 (the Rowan Transaction). In connection with the Rowan Transaction, the assets acquired and liabilities assumed were recorded at their estimated fair value at the acquisition date. The key assumptions used to estimate the acquisition-date fair values of the acquired property and equipment and investment were forecasted day rates, forecasted utilization and risk-adjusted discount rates. The Company, with the use of a third-

party valuation expert, estimated the fair value of the assets acquired and liabilities assumed at $4.8 billion and $2.8 billion, respectively.

We identified the evaluation of the Company's valuation of property and equipment and investment in joint venture acquired in the Rowan Transaction as a critical audit matter. The use of unobservable inputs and subjective assumptions necessary to estimate the fair value of those assets required a high degree of subjective auditor judgment to evaluate the assumptions described above. In addition, the discounted cash flow model included the internally-developed assumptions described above for which there were limited observable market information, and the calculated fair value of such assets was sensitive to possible changes to these assumptions.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s acquisition-date valuation process, including controls over the development of the relevant assumptions listed above. We evaluated the Company’s forecasted day rates and utilization by comparing them to historical information, data from the Company’s peers and industry reports. We challenged the Company's information and assumptions based on evidence we identified that was contrary to that used by the Company. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating the Company’s discount rates by comparing the Company's discount rates against discount rate ranges that we independently developed using publicly available market data for comparable entities.

Assessment of property and equipment impairment triggering events

As discussed in Notes 1 and 6 to the consolidated financial statements, the net carrying value of property and equipment as of December 31, 2019 was $15.1 billion. The Company evaluates the carrying value of property and equipment for impairment, on a quarterly basis, by identifying events or changes in circumstances, including global macroeconomic conditions, that indicate the carrying value may not be recoverable (triggering events). Generally, extended periods of idle time or the inability to contract rigs at economical rates are an indication that a rig may be impaired.

We identified the assessment of property and equipment impairment triggering events as a critical audit matter. The Company's evaluation of possible triggering events uses both internal and external data, including the following key indicators and internally-developed assumptions: historical utilization trends, oil price projections and global rig supply and demand trends. Assessing these indicators and assumptions requires a high degree of subjective auditor judgment to perform procedures and evaluate the audit evidence obtained.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company's identification of possible property and equipment impairment triggering events, including controls to develop the indicators and assumptions listed above. We evaluated the information used by the Company in its triggering event assessment by comparing such information to historical information, external third-party expectations, peer company results, and other industry data.

Assessment of income tax positions pertaining to certain transactions

As discussed in Notes 1 and 12 to the consolidated financial statements, the Company evaluates the income tax effect of certain transactions which often require local country tax expertise and judgment. This requires the Company to interpret complex tax laws in multiple jurisdictions to assess if 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 transactions as a critical audit matter. Complex auditor judgment was required to: (1) evaluate the Company's assessment that the tax position has a more than 50 percent likelihood of being sustained with the taxing authorities; and (2) evaluate the Company's measurement of the tax effects resulting from these transactions. In addition, specialized skills were required to evaluate the Company's interpretation of tax laws in the applicable jurisdictions.

The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company's income tax process, including controls related to the interpretation of tax laws applicable to certain transactions, assessment that tax positions pertaining to those transactions have a more

than 50 percent likelihood of being sustained with taxing authorities and measurement of the tax effects resulting from those transactions. We involved tax professionals with specialized skills and knowledge, who assisted in reading the Company's documentation and evaluating the Company's interpretation of local tax laws, assessing the likelihood that the tax position has a greater than 50 percent likelihood of being sustained with taxing authorities, and measuring the tax effects resulting from those transactions.

/s/ KPMG LLP

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

Houston, Texas

February 21, 2020

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, 2019, 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, 2019, 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, 2019 and 2018, the related consolidated statements of operations, comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 21, 2020 expressed an unqualified opinion on those consolidated financial statements.

The Company acquired Rowan Companies plc during 2019, and management excluded from its assessment of the effectiveness of the Company's internal controls over financial reporting as of December 31, 2019, Rowan Companies plc's internal control over financial reporting associated with total revenue of $135.0 million and total expenses of $259.0 million included in the consolidated financial statements of the Company for the year ended December 31, 2019. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of Rowan Companies plc.

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 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

February 21, 2020

VALARIS PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share amounts)



	Year Ended December 31,
	2019			2018			2017
OPERATING REVENUES	$	2,053.2		$	1,705.4		$	1,843.0
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	1,806.0			1,319.4			1,189.5
Loss on impairment	104.0			40.3			182.9
Depreciation	609.7			478.9			444.8
General and administrative	188.9			102.7			157.8
	2,708.6			1,941.3			1,975.0
EQUITY IN EARNINGS OF ARO	(12.6		)	—			—
OPERATING LOSS	(668.0		)	(235.9		)	(132.0		)
OTHER INCOME (EXPENSE)
Interest income	28.1			14.5			25.8
Interest expense, net	(428.3		)	(282.7		)	(224.2		)
Other, net	1,004.4			(34.8		)	134.4
	604.2			(303.0		)	(64.0		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(63.8		)	(538.9		)	(196.0		)
PROVISION FOR INCOME TAXES
Current income tax expense	104.5			33.0			54.2
Deferred income tax expense	23.9			56.6			55.0
	128.4			89.6			109.2
LOSS FROM CONTINUING OPERATIONS	(192.2		)	(628.5		)	(305.2		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET	—			(8.1		)	1.0
NET LOSS	(192.2		)	(636.6		)	(304.2		)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(5.8		)	(3.1		)	.5
NET LOSS ATTRIBUTABLE TO VALARIS	$	(198.0	)	$	(639.7	)	$	(303.7	)
LOSS PER SHARE - BASIC AND DILUTED
Continuing operations	$	(1.14	)	$	(5.82	)	$	(3.66	)
Discontinued operations	—			(0.08		)	—
	$	(1.14	)	$	(5.90	)	$	(3.66	)

WEIGHTED-AVERAGE SHARES OUTSTANDING
Basic and Diluted	173.4			108.5			83.1

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

VALARIS PLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(in millions)



	Year Ended December 31,
	2019			2018			2017
NET LOSS	$	(192.2	)	$	(636.6	)	$	(304.2	)
OTHER COMPREHENSIVE INCOME (LOSS), NET
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive loss, net of income tax benefits of ($5.9 million) for the year ended December 31, 2019	(21.7		)	—			—
Net change in fair value of derivatives	1.6			(9.7		)	8.5
Reclassification of net (gains) losses on derivative instruments from other comprehensive income (loss) into net loss	8.3			(1.0		)	.4
Other	(.2		)	(.5		)	.7
NET OTHER COMPREHENSIVE INCOME (LOSS)	(12.0		)	(11.2		)	9.6

COMPREHENSIVE LOSS	(204.2		)	(647.8		)	(294.6		)
COMPREHENSIVE (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(5.8		)	(3.1		)	.5
COMPREHENSIVE LOSS ATTRIBUTABLE TO VALARIS	$	(210.0	)	$	(650.9	)	$	(294.1	)

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

VALARIS PLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in millions, except share and par value amounts)



	December 31,
ASSETS	2019			2018
CURRENT ASSETS
Cash and cash equivalents	$	97.2		$	275.1
Short-term investments	—			329.0
Accounts receivable, net	520.7			344.7
Other	446.5			360.9
Total current assets	1,064.4			1,309.7
PROPERTY AND EQUIPMENT, AT COST	18,393.8			15,517.0
Less accumulated depreciation	3,296.9			2,900.8
Property and equipment, net	15,096.9			12,616.2
LONG-TERM NOTES RECEIVABLE FROM ARO	452.9			—
INVESTMENT IN ARO	128.7			—
OTHER ASSETS	188.3			97.8
	$	16,931.2		$	14,023.7
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable - trade	$	288.2		$	210.5
Accrued liabilities and other	417.7			318.0
Current maturities of long-term debt	124.8			—
Total current liabilities	830.7			528.5
LONG-TERM DEBT	5,923.5			5,010.4
OTHER LIABILITIES	867.4			396.0
COMMITMENTS AND CONTINGENCIES
VALARIS SHAREHOLDERS' EQUITY
Class A ordinary shares, U.S. $.40 par value, 205.9 million and 115.2 million shares issued as of December 31, 2019 and 2018	82.4			46.1
Class B ordinary shares, £1 par value, 50,000 shares issued as of December 31, 2019 and 2018	.1			.1
Additional paid-in capital	8,627.8			7,225.0
Retained earnings	671.7			874.2
Accumulated other comprehensive income	6.2			18.2
Treasury shares, at cost, 7.9 million and 5.9 million shares as of December 31, 2019 and 2018	(77.3		)	(72.2		)
Total Valaris shareholders' equity	9,310.9			8,091.4
NONCONTROLLING INTERESTS	(1.3		)	(2.6		)
Total equity	9,309.6			8,088.8
	$	16,931.2		$	14,023.7

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

VALARIS PLC AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)

	Year Ended December 31,
	2019			2018			2017
OPERATING ACTIVITIES
Net loss	$	(192.2	)	$	(636.6	)	$	(304.2	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities of continuing operations:
Bargain purchase gain	(637.0		)	(1.8		)	(140.2		)
Depreciation expense	609.7			478.9			444.8
(Gain) loss on debt extinguishment	(194.1		)	19.0			2.6
Loss on impairment	104.0			40.3			182.9
Share-based compensation expense	37.3			29.9			34.2
Deferred income tax expense	23.9			56.6			55.0
Amortization, net	(16.8		)	(40.2		)	(61.6		)
Equity in earnings of ARO	12.6			—			—
Other	16.8			4.5			(26.5		)
Changes in operating assets and liabilities, net of acquisition	(27.9		)	(6.3		)	72.4
Contributions to pension plans and other post-retirement benefits	(13.2		)	—			—
Net cash provided by (used in) operating activities of continuing operations	(276.9		)	(55.7		)	259.4
INVESTING ACTIVITIES
Acquisition of Rowan, net of cash acquired	931.9			—			—
Maturities of short-term investments	474.0			1,030.0			2,042.5
Additions to property and equipment	(227.0		)	(426.7		)	(536.7		)
Purchases of short-term investments	(145.0		)	(919.0		)	(1,040.0		)
Net proceeds from disposition of assets	17.7			11.0			2.8
Acquisition of Atwood, net of cash acquired	—			—			(871.6		)
Net cash provided by (used in) investing activities of continuing operations	1,051.6			(304.7		)	(403.0		)
FINANCING ACTIVITIES
Reduction of long-term borrowings	(928.1		)	(771.2		)	(537.0		)
Borrowings on credit facility	215.0			—			—
Repayments of credit facility borrowings	(215.0		)	—			—
Debt solicitation fees	(9.5		)	—			—
Cash dividends paid	(4.5		)	(17.9		)	(13.8		)
Proceeds from issuance of senior notes	—			1,000.0			—
Debt issuance costs	—			(17.0		)	(12.0		)
Other	(10.2		)	(5.7		)	(7.7		)
Net cash provided by (used in) financing activities	(952.3		)	188.2			(570.5		)
Net cash provided by (used in) discontinued operations	—			2.5			(.8		)
Effect of exchange rate changes on cash and cash equivalents	(.3		)	(.6		)	.6
DECREASE IN CASH AND CASH EQUIVALENTS	(177.9		)	(170.3		)	(714.3		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	275.1			445.4			1,159.7
CASH AND CASH EQUIVALENTS, END OF YEAR	$	97.2		$	275.1		$	445.4

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

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. Exclusive of two rigs under construction and one rigs marked for retirement and classified as held-for-sale, we currently own and operate an offshore drilling rig fleet of 74 rigs, with drilling operations in almost every major offshore market across six continents. Inclusive of our rigs under construction, our fleet includes 16 drillships, eight dynamically positioned semisubmersible rigs, two moored semisubmersible rigs and 50 jackup rigs, nine of which are leased to our 50/50 joint venture with Saudi Aramco. 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.

Rowan Transaction

On October 7, 2018, we entered into a transaction agreement (the "Transaction Agreement") with Rowan Companies Limited (formerly Rowan Companies plc ("Rowan")) and on April 11, 2019 (the "Transaction Date"), we completed our combination with Rowan pursuant to the Transaction Agreement (the "Rowan Transaction") and changed our name to Ensco Rowan plc. On July 30, 2019, we changed our name to Valaris plc. Rowan's financial results are included in our consolidated results beginning on the Transaction Date.

Prior to the Rowan Transaction, Rowan and Saudi Aramco formed a 50/50 joint venture to own, manage and operate drilling rigs offshore Saudi Arabia ("Saudi Aramco Rowan Offshore Drilling Company" or "ARO"). ARO currently owns a fleet of seven jackup rigs, leases another nine jackup rigs from us and has plans to purchase up to 20 newbuild jackup rigs over an approximate 10 year period. In January 2020, ARO ordered the first two newbuild jackups scheduled for delivery in 2022. The rigs we lease to ARO are done so 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.

increased scale, diversification and financial strength of the combined company provides us advantages to better serve our customers. Exclusive of two older jackup rigs marked for retirement, Rowan’s offshore rig fleet at the Transaction Date consisted of four ultra-deepwater drillships and 19 jackup rigs.

Reverse Stock Split

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.

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, 2019 and 2018 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. statutory accounts for the year ended December 31, 2018; their report was (i) unqualified, (ii) did not include a reference to any matters to which the auditor drew attention by way of emphasis without qualifying their report and (iii) 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, 2019 have yet to be finalized and will be delivered to the U.K. registrar of companies during 2020.

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.

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

$7.4 million, $17.2 million and $5.1 million, and were included in other, net, in our consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, 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.

Short-term investments consisted of time deposits with initial maturities in excess of three months but less than one year and totaled $329.0 million as of December 31, 2018. There were no short-term investments as of December 31, 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, 2018 and 2017. To mitigate our credit risk, our investments in time deposits are diversified across multiple, high-quality financial institutions.

Property and Equipment

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

We evaluate the carrying value of our property and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets 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 $104.0 million, $40.3 million and $182.9 million during 2019, 2018 and 2017, respectively. See "Note 6 - Property and Equipment" for additional information on our impairment charges.

If the global economy deteriorates and/or our expectations relative to future offshore drilling industry conditions decline, it is reasonably possible that additional impairment charges may occur with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.

Operating Revenues and Expenses

See "Note 2 - 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 use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. See "Note 8 - Derivative Instruments" for additional information on how and why we use derivatives.

All 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 previously recorded in AOCI are reclassified currently into earnings and included in other, net, in our consolidated statement of operations.

We occasionally 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.

100

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.

Share-Based Compensation

We sponsor share-based compensation plans that provide equity compensation to our key employees, officers and non-employee directors. 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 10 - 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

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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.

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 5 - 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, 2019, 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 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, 2019, 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, 2019 (in millions):



	2019			2018			2017
Loss from continuing operations attributable to Valaris	$	(198.0	)	$	(631.6	)	$	(304.7	)
Income from continuing operations allocated to non-vested share awards	(.1		)	(.5		)	(.4		)
Loss from continuing operations attributable to Valaris shares	$	(198.1	)	$	(632.1	)	$	(305.1	)

Anti-dilutive share awards totaling 300,000, 1.5 million and 2.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, were excluded from the computation of diluted EPS.

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. See "Note 7 - Debt" for additional information on this issuance. 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 the remainder of 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 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, 2019, 2018 and 2017.

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New Accounting Pronouncements

Recently adopted accounting pronouncements

Leases - During 2016, the FASB issued ASU 2016-02, Leases (Topic 842) ("Update 2016-02"), which requires an entity to recognize lease assets and lease liabilities on the balance sheet and to disclose key qualitative and quantitative information about the entity's leasing arrangements. This update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. During our evaluation of Update 2016-02, we concluded that our drilling contracts contain a lease component. In July 2018, the FASB issued Accounting Standard Update 2018-11, Leases (Topic 842), Targeted Improvements, which (1) provided for a new transition method whereby entities could elect to adopt the Update using a prospective with cumulative catch-up approach (the "effective date method") and (2) provided lessors with a practical expedient, by class of underlying asset, to not separate lease and non-lease components and account for the combined component under Topic 606 when the non-lease component is the predominant element of the combined component. The lessor practical expedient is limited to circumstances in which the lease, if accounted for separately, would be classified as an operating lease under Topic 842. We adopted Update 2016-02, effective January 1, 2019, using the effective date method.

With respect to our drilling contracts, which contain a lease component, we elected to apply the practical expedient to not separate the lease and non-lease components and account for the combined component under Topic 606. With respect to all of our drilling contracts that existed on the adoption date, we concluded that the criteria to elect the lessor practical expedient had been met. As a result, we will continue to recognize the revenue associated with our drilling contracts under Topic 606. Therefore, we do not expect any change in our revenue recognition patterns or disclosures as a result of our adoption of Topic 842.

With respect to leases whereby we are the lessee, we elected several practical expedients afforded under Topic 842. We elected the package of practical expedients permitted under the transition guidance of Topic 842, including the hindsight practical expedient which permits entities to use hindsight in determining the lease term and assessing impairment. We also elected the practical expedient to not separate lease components from non-lease components for all asset classes, with the exception of office space. Furthermore, we also elected the practical expedient that permits entities not to apply the recognition requirements for leases with a term of 12 months or less. Upon adoption of Update 2016-02 on January 1, 2019, we recognized lease liabilities and right-of-use assets of $64.6 million and $53.7 million, respectively. See "Note 14 - Leases" for additional information.

Derivatives and Hedging - In August 2017, the Financial Accounting Standards Board (the "FASB") issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities ("Update 2017-12"), which makes more hedging strategies eligible for hedge accounting, amends presentation and disclosure requirements and changes how companies assess effectiveness, including the elimination of separate measurement and recognition of ineffectiveness on designated hedging instruments. This update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. We adopted Update 2017-12 effective January 1, 2019. As a result, beginning on the effective date, we no longer separately measure and recognize ineffectiveness on our designated cash flow hedges. Update 2017-02 requires a modified retrospective adoption approach whereby amounts previously recorded to earnings for hedge ineffectiveness on hedging relationships that existed as of the adoption date are recorded as a cumulative effect adjustment to opening retained earnings. As of our adoption date, we had no amounts previously recorded for ineffectiveness for hedging relationships that existed as of our adoption date and therefore no cumulative effect adjustment to retained earnings was recorded.

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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 will be required to adopt the amended guidance in annual and interim periods beginning after December 15, 2020, with early adoption permitted. 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.

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 will be required to adopt the amended guidance in annual and interim reports beginning January 1, 2021, with early adoption permitted. Adoption is required to be applied on a retrospective basis to all periods presented. We will adopt the new standard effective January 1, 2021 and do not expect the adoption of Update 2018-14 to have a material impact on our consolidated financial statements.

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. Update 2016-13 is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. We will adopt the new standard effective January 1, 2020 and do not expect the adoption of Update 2016-13 to have a material impact 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. 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 integrated 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 Update 2014-09, Revenue from Contracts with Customers (Topic 606), and have not disclosed the variable

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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, 2019 was between approximately one month and four 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 unit 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.

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.

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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.

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



	December 31, 2019		December 31, 2018
Current contract assets	$	3.5	$	4.0
Current contract liabilities (deferred revenue)	$	30.0	$	56.9
Noncurrent contract liabilities (deferred revenue)	$	9.7	$	20.5

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



	Contract Assets			Contract Liabilities
Balance as of January 1, 2019	$	4.0		$	77.4
Contract assets and liabilities acquired in the Rowan Transaction	8.4			5.3
Revenue recognized in advance of right to bill customer	1.3			—
Increase due to cash received	—			42.9
Decrease due to amortization of deferred revenue that was included in the beginning contract liability balance	—			(56.3		)
Decrease due to amortization of deferred revenue that was added during the period	—			(29.6		)
Decrease due to transfer to receivables during the period	(10.2		)	—
Balance as of December 31, 2019	$	3.5		$	39.7

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. Such 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 $19.7 million and $23.5 million as of December 31, 2019 and 2018, respectively. Amortization of such costs totaled $42.1 million, $34.0 million and $28.1 million for the years ended December 31, 2019, 2018 and 2017, 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 $10.8 million and $13.6 million as of December 31, 2019 and 2018, respectively. Amortization of such costs totaled $10.3 million, $12.4 million and $12.1 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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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. Expected future amortization of our contract liabilities and deferred costs recorded as of December 31, 2019 is set forth in the table below (in millions):



	2020		2021		2022		2023 & Thereafter		Total
Amortization of contract liabilities	$	30.0	$	7.8	$	1.9	$	—	$	39.7
Amortization of deferred costs	$	23.2	$	5.7	$	1.2	$	0.4	$	30.5

3. ROWAN TRANSACTION

On October 7, 2018, we entered into a transaction agreement (the "Transaction Agreement") with Rowan. On April 11, 2019 (the "Transaction Date"), we completed our combination with Rowan pursuant to the Transaction Agreement (the "Rowan Transaction"). Rowan's financial results are included in our consolidating results beginning on the Transaction Date. The Rowan Transaction enhanced the market leadership of the combined company with a fleet of high-specification floaters and jackups and positions us well to meet increasing and evolving customer demand. The increased scale, diversification and financial strength of the combined company provides us advantages to better serve our customers.

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. With the exception of certain legal and tax exposures as well as the fair value of materials and supplies, we have substantially completed our fair value assessments of assets acquired and liabilities assumed. While certain adjustments may be recorded during the remainder of the measurement period, we do not expect them to be material.

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The provisional amounts recorded for assets and liabilities acquired are based on preliminary estimates of their fair values as of the Transaction Date 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			(3.6		)	203.5
Other current assets	101.6			(2.4		)	99.2
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			(25.8		)	2,964.0
Other assets	41.7			1.3			43.0
Liabilities:
Accounts payable and accrued liabilities	259.4			13.7			273.1
Current portion of long-term debt	203.2			—			203.2
Long-term debt	1,910.9			—			1,910.9
Other liabilities	376.3			34.1			410.4
Net assets acquired	2,115.6			(75.8		)	2,039.8
Less: Merger consideration	(1,402.8		)	—			(1,402.8		)
Bargain purchase gain	$	712.8		$	(75.8	)	$	637.0

⁽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.

⁽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.

Transaction-Related Costs

Merger-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 are included in general and administrative expense in our consolidated statements of operations.

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 4 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. The various factors considered in the determination of these fair values were (1) the contracted day rate for each contract, (2) the remaining term of each contract, (3) the rig class and (4) the market conditions for each respective rig class at the Transaction Date. The intangible assets and liabilities were calculated based on the present value of the difference in cash flows over the remaining contract term as compared to a hypothetical contract with the same remaining term at an estimated then-current market day rate using a risk-adjusted discount rate and an estimated effective income tax rate.

Amortization of the intangible assets and liabilities resulted in a net reduction in operating revenues of $3.6 million for the year ended December 31, 2019. The remaining balance of intangible assets and liabilities of $11.9 million and $1.4 million, respectively, was included in other assets and other liabilities, respectively, on our consolidated balance sheet of December 31, 2019. These balances will be amortized to operating revenues over the respective remaining contract terms on a straight-line basis. As of December 31, 2019, the remaining terms of the underlying contracts is approximately 2 years. Amortization of these intangibles is expected to result in a reduction to revenue of $5.1 million and $5.4 million in 2020 and 2021, respectively.

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.

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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 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.

During 2019, we received income tax assessments from Luxembourg tax authorities related to certain filing positions taken by Rowan in prior years for several of Rowan’s Luxembourg subsidiaries totaling approximately €142.0 million (approximately $159.0 million converted using the current period-end exchange rate). We are contesting these assessments and have filed applications for appeal. As of the Transaction Date, we recognized liabilities under acquisition accounting of €47.0 million (approximately $52.0 million converted using the current period-end exchange rate) in connection with the Luxembourg assessments, which reflected the amount of the Rowan filing positions that we concluded, on a preliminary basis, we would not more-likely-than-not sustain. As a result of our continued review and analysis of facts and circumstances that existed at the Transaction Date, we recognized additional liabilities of €46.0 million (approximately $52.6 million converted using the current period-end exchange rate) as measurement period adjustments.

As a result, the amount recognized on our consolidated balance sheet related to the Luxembourg income tax assessments totaled €93.0 million (approximately $104.6 million converted using the current period-end exchange rates) as of December 31, 2019. Our ongoing evaluation of the relevant facts and circumstances surrounding these positions may result in further revisions to this estimate, which could be material. We cannot predict or provide assurance as to the ultimate outcome of the Luxembourg tax assessments.

Revenues and Earnings of Rowan

Our consolidated statement of operations for the year ending December 31, 2019 included revenues of $448.0 million and net losses of $122.7 million.

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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, 2018. 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, (4) removal of the historical amortization of unrealized gains and losses related to Rowan's pension plans and (5) 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)	Year Ended
	2019⁽¹⁾			2018⁽²⁾
Revenues	$	2,240.5		$	2,530.4
Net loss	$	(994.3	)	$	(796.5	)
Earnings per share - basic and diluted	$	(3.80	)	$	(4.05	)

⁽¹⁾ Pro forma net loss per share was adjusted to exclude an aggregate $108.1 million of transaction-related and integration costs incurred by Ensco and Rowan during 2019 and the $637.0 million bargain purchase gain.

⁽²⁾ Pro forma net loss per share was adjusted to exclude an aggregate $13.8 million of transaction-related and integration costs incurred by Ensco and Rowan during 2018.

Note 4 - Equity Method Investment in ARO

Background

During 2016, Rowan and Saudi Aramco entered into an agreement to create a 50/50 joint venture (the "Shareholders' Agreement") to own, manage and operate offshore drilling rigs in Saudi Arabia. The new entity, ARO, was formed in May 2017 with each of Rowan and Saudi Aramco contributing $25 million to be used for working capital needs.

In October 2017, Rowan sold rigs Bob Keller, J.P. Bussell and Gilbert Rowe to ARO and Saudi Aramco sold SAR 201 and related assets to ARO in each case for cash. Upon completion of the rig sales, ARO was deemed to have commenced operations. Saudi Aramco subsequently sold another rig, SAR 202, to ARO in December 2017 for cash and in October 2018, Rowan sold two additional jackup rigs, the Scooter Yeargain and the Hank Boswell, to ARO for cash. As a result of these rig sales, ARO owned seven jackup rigs as of the Transaction Date.

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, 2019, the carrying amount of the long-term notes receivable from ARO was $452.9 million. The Shareholders’ Agreement prohibits the sale or transfer of the shareholder note to a third party, except in certain limited circumstances.

Rigs purchased by ARO will receive contracts from Saudi Aramco for an aggregate 15 years, renewed and re-priced every three years, provided that the rigs meet the technical and operational requirements of Saudi Aramco. Each of the seven rigs owned by ARO is currently operating under its initial three-year contract.

Additionally, prior to the Rowan Transaction, Rowan entered into agreements with ARO to lease nine rigs to ARO (the "Lease Agreements"). The rigs are leased to ARO through bareboat charter arrangements whereby substantially all operating costs are incurred by ARO. As of December 31, 2019, all nine of the rigs were operating under three-year drilling contracts with Saudi Aramco.

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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 price of $176 million, 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. In the event ARO has insufficient cash from operations or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, 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 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 also 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 remain 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.

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 and the rigs leased from us that operated from the Transaction Date through December 31, 2019.

The contract drilling expenses, depreciation and general and administrative expenses presented below are also for the period from the Transaction Date through December 31, 2019. 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 relates. 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):



	April 11, 2019 - December 31, 2019
Revenues	$	410.5
Operating expenses
Contract drilling (exclusive of depreciation)	280.2
Depreciation	40.3
General and administrative	27.1
Operating income	62.9
Other expense, net	28.6
Provision for income taxes	9.7
Net income	$	24.6

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	December 31, 2019
Current assets	$	407.2
Non-current assets	874.8
Total assets	$	1,282.0

Current liabilities	$	183.2
Non-current liabilities	1,015.5
Total liabilities	$	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.

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 US 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):



	April 11, 2019 - December 31, 2019
50% interest in ARO net income	$	12.3
Amortization of basis differences	(24.9		)
Equity in earnings of ARO	$	(12.6	)

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, 2019
Lease revenue	$	58.2
Secondment revenue	49.9
Transition Services revenue	17.3
Total revenue from ARO ⁽¹⁾	$	125.4


⁽¹⁾	All of the revenues presented above are included in our Other segment in our segment disclosures. See Note 15 for additional information.

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Amounts receivable from ARO related to the above items totaled $21.8 million as of December 31, 2019 and are included in accounts receivable, net, on our consolidated balance sheet. Accounts payable to ARO totaled $0.7 million as of December 31, 2019.

We also have an agreement between us and ARO, pursuant to which ARO will reimburse us for certain capital expenditures related to the shipyard upgrade projects for VALARIS JU-147 and VALARIS JU-148. As of December 31, 2019, $14.2 million related to reimbursement of these expenditures was included in accounts receivable, net, on our consolidated balance sheet.

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. Interest is recognized as interest income in our consolidated statement of operations and totaled $16.8 million for the period from the Transaction Date through December 31, 2019, respectively. As of December 31, 2019, we had no interest receivable from ARO.

The following table summarizes the maturity schedule of our notes receivable from ARO as of December 31, 2019 (in millions):



Maturity Date	Principal Amount
October 2027	$	275.2
October 2028	177.7
Total	$	452.9

Maximum Exposure to Loss

The following summarizes the total assets and liabilities as reflected in our consolidated balance sheet 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 for services provided to ARO, partially offset by payables for services received.



	December 31, 2019
Total assets	$	623.5
Less: total liabilities	.7
Maximum exposure to loss	$	622.8

5. 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 as of December 31, 2019 and 2018 (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, 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
As of December 31, 2018
Supplemental executive retirement plan assets	$	27.2	$	—		$	—	$	27.2
Total financial assets	27.2		—			—		27.2
Derivatives, net	—		(10.7		)	—		(10.7		)
Total financial liabilities	$	—	$	(10.7	)	$	—	$	(10.7	)

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Supplemental Executive Retirement Plans

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 the SERP were 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, 2019 and 2018. The fair value measurements of assets held in the SERP were based on quoted market prices. Net unrealized gains of $5.0 million, losses of $700,000 and gains of $4.5 million from marketable securities held in our SERP were included in other, net, in our consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, respectively.

Derivatives

Our derivatives were measured at fair value on a recurring basis using Level 2 inputs as of December 31, 2019 and 2018. See "Note 8 - 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.

Other Financial Instruments

The carrying values and estimated fair values of our debt instruments as of December 31, 2019 and 2018 were as follows (in millions):



	December 31, 2019				December 31, 2018
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
6.875% Senior notes due 2020	$	124.8	$	117.3	$	127.5	$	121.6
4.70% Senior notes due 2021	113.2		95.5		112.7		101.8
4.875% Senior notes due 2022 ⁽²⁾	599.2		460.5		—		—
3.00% Exchangeable senior notes due 2024 ⁽¹⁾	699.0		607.4		666.8		575.5
4.50% Senior notes due 2024	302.0		167.2		619.8		405.2
4.75% Senior notes due 2024 ⁽²⁾	276.5		201.4		—		—
8.00% Senior notes due 2024	295.7		181.7		337.0		273.7
5.20% Senior notes due 2025	331.7		186.7		664.4		443.9
7.375% Senior notes due 2025 ⁽²⁾	329.2		218.6		—		—
7.75% Senior notes due 2026	987.1		575.1		985.0		725.5
7.20% Debentures due 2027	111.7		70.0		149.3		109.1
7.875% Senior notes due 2040	373.3		153.5		375.0		223.2
5.40% Senior notes due 2042 ⁽²⁾	262.8		194.4		—		—
5.75% Senior notes due 2044	973.3		450.0		972.9		566.3
5.85% Senior notes due 2044 ⁽²⁾	268.8		194.8		—		—
Total debt	$	6,048.3	$	3,874.1	$	5,010.4	$	3,545.8
Less: current maturities	124.8		—		—		—
Total long-term debt	$	5,923.5	$	3,874.1	$	5,010.4	$	3,545.8


⁽¹⁾	Our 2024 Convertible Notes were issued with a conversion feature. The 2024 Convertible Notes were separated 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 that will be amortized to interest expense over

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the life of the instrument. Excluding the unamortized discount, the carrying value of the 2024 Convertible Notes was $838.3 million and $836.3 million as of December 31, 2019 and 2018, respectively. See "Note 7 - Debt" for additional information on this issuance.


⁽²⁾	These senior notes were assumed by Valaris as a result of the Rowan Transaction.

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, short-term investments, accounts receivable, notes receivable, trade payables and other liabilities approximated their carrying values as of December 31, 2019 and 2018. Our short-term investments consisted of time deposits with initial maturities in excess of three months but less than one year as of December 31, 2018.

6. PROPERTY AND EQUIPMENT

Property and equipment as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019		2018
Drilling rigs and equipment	$	17,714.0	$	14,542.5
Work-in-progress	473.6		779.2
Other	206.2		195.3
	$	18,393.8	$	15,517.0

Drilling rigs and equipment as of December 31, 2019 increased by $3.2 billion, or 22%, as compared to prior period, primarily due to $3.0 billion of assets acquired from the Rowan Transaction, and $385.0 million due to VALARIS JU-123 which was placed into service in the current period.

Work-in-progress as of December 31, 2019 primarily consisted of $417.4 million related to the construction of ultra-deepwater drillships VALARIS DS-13 and VALARIS DS-14.

Work-in-progress as of December 31, 2018 primarily consisted of $416.8 million related to the construction of ultra-deepwater drillships VALARIS DS-13 and VALARIS DS-14 and $352.4 million related to the construction of VALARIS JU-123, an ultra-premium harsh environment jackup rig.

VALARIS JU-123 was placed into service and reclassified from work-in-progress to drilling rigs and equipment during the year ended December 31, 2019.

Impairment of Long-Lived Assets

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. 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 2019, we recorded a pre-tax, non-cash loss on impairment of $98.4 million on two older, non-core assets in our fleet upon classification as held-for-sale. We determined that the fair value less cost to sell was lower than each rig's carrying value and concluded that the rigs were impaired.

During 2018, we recorded a pre-tax, non-cash loss on impairment of $40.3 million related to one older non-core jackup 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

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the remaining useful life of the rig were not sufficient to recover the rig’s carrying value and concluded the rig was impaired as of December 31, 2018.

During 2017, we recognized a pre-tax, non-cash loss on impairment of $182.9 million related to older, less capable, non-core assets in our fleet. We determined that the remaining useful life of certain non-core rigs would not extend substantially beyond their current contracts, resulting in triggering events and the performance of recoverability tests. Our estimates of undiscounted cash flows over the revised estimated remaining useful lives were not sufficient to recover each asset’s carrying value. Accordingly, we concluded that two semisubmersibles and one jackup were impaired as of December 31, 2017.

For rigs classified as held-for-sale, we recorded an impairment for the difference between their carrying value and the fair value less costs to sell. We estimated fair value using significant other observable inputs including indicative scrap values based on historical sale prices.

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. 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 require significant judgments for which there is 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.

If the global economy, our overall business outlook and/or our expectations regarding the marketability of one or more of our drilling rigs deteriorate further, we may conclude that a triggering event has occurred and perform a recoverability test that could lead to a material impairment charge in future periods.

7. DEBT

The carrying value of our long-term debt as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019		2018
6.875% Senior notes due 2020	$	124.8	$	127.5
4.70% Senior notes due 2021	113.2		112.7
4.875% Senior notes due 2022⁽³⁾	599.2		—
3.00% Exchangeable senior notes due 2024⁽²⁾	699.0		666.8
4.50% Senior notes due 2024⁽¹⁾	302.0		619.8
4.75% Senior notes due 2024⁽³⁾	276.5		—
8.00% Senior notes due 2024⁽¹⁾	295.7		337.0
5.20% Senior notes due 2025⁽¹⁾	331.7		664.4
7.375% Senior notes due 2025⁽³⁾	329.2		—
7.75% Senior notes due 2026	987.1		985.0
7.20% Debentures due 2027⁽¹⁾	111.7		149.3
7.875% Senior notes due 2040	373.3		375.0
5.40% Senior notes due 2042⁽³⁾	262.8		—
5.75% Senior notes due 2044	973.3		972.9
5.85% Senior notes due 2044⁽³⁾	268.8		—
Total debt	$	6,048.3	$	5,010.4
Less: current maturities	124.8		—
Total long-term debt	$	5,923.5	$	5,010.4

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⁽¹⁾	The decline in the carrying value of our 4.50% and 8.00% senior notes due 2024, 5.20% senior notes due 2025 and 7.20% debentures due 2027 resulted from repurchases made pursuant to the tender offer discussed below.

⁽²⁾

Our 2024 Convertible Notes were issued with a conversion feature. The 2024 Convertible Notes were separated 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 that will be amortized to interest expense over the life of the instrument. Excluding the unamortized discount, the carrying value of the 2024 Convertible Notes was $838.3 million and $836.3 million as of December 31, 2019 and 2018, respectively.


⁽³⁾	These senior notes were acquired in the Rowan Transaction.

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 unsecured 2024 Convertible Notes in a private offering. The 2024 Convertible Notes are fully and unconditionally guaranteed, on a senior, unsecured basis, by Valaris plc and are exchangeable into cash, our Class A ordinary shares or a combination thereof, at our election. 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.

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 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.

The 2024 Convertible Notes were separated into their liability and equity components and included in long-term debt and additional paid-in capital on our consolidated balance sheet, respectively. The carrying amount of the liability component was calculated by measuring the estimated fair value of a similar liability that does not include an associated conversion feature. The carrying amount of the equity component representing the conversion feature was 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 is 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% per annum. 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 allocated to the liability and equity components based on their relative fair values. Issuance costs attributable to the liability component are 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.

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As of December 31, 2019 and 2018, the 2024 Convertible Notes consist of the following (in millions):



Liability component:	2019			2018
Principal	$	849.5		$	849.5
Less: Unamortized debt discount and issuance costs	(150.5		)	(182.7		)
Net carrying amount	699.0			666.8
Equity component, net	$	220.0		$	220.0

During the year ended December 31, 2019, 2018 and 2017, we recognized $25.5 million associated with coupon interest. Amortization of debt discount and issuance costs were $32.5 million, $31.0 million and $31.4 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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.

Senior Notes

As a result of the Rowan Transaction, we acquired the following debt issued by Rowan Companies, Inc. ("RCI") and guaranteed by Rowan: (1) $201.4 million in aggregate principal amount of 7.875% unsecured senior notes, which was repaid at maturity in August 2019, (2) $620.8 million in aggregate principal amount of 4.875% unsecured senior notes due 2022 (the "Rowan 2022 Notes"), (3) $398.1 million in aggregate principal amount of 4.75% unsecured senior notes due 2024 (the "Rowan 2024 Notes"), (4) $500.0 million in aggregate principal amount of 7.375% unsecured senior notes due 2025 (the "Rowan 2025 Notes"), (5) $400.0 million in aggregate principal amount of 5.4% unsecured senior notes due 2042 (the "Rowan 2042 Notes") and (6) $400.0 million in aggregate principal amount of 5.85% unsecured senior notes due 2044 (the "Rowan 2044 Notes" and collectively, the "Rowan Notes"). Upon closing of the Rowan Transaction, we terminated Rowan's outstanding credit facilities. 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 of 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 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" and together with the New 2044 Notes, the "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 and the New 2044 Notes are treated as a single series of debt securities under the indenture governing the notes.

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Upon consummation of the Pride International LLC ("Pride") acquisition during 2011, we assumed outstanding debt comprised of $900.0 million aggregate principal amount of unsecured 6.875% senior notes due 2020, $500.0 million aggregate principal amount of unsecured 8.5% senior notes due 2019 and $300.0 million aggregate principal amount of unsecured 7.875% senior notes due 2040 (collectively, the "Acquired Notes" and together with the Rowan Notes, 2021 Notes, 8% 2024 Notes, 2024 Notes, 2025 Notes, 2026 Notes and 2044 Notes, the "Senior Notes"). Valaris plc has fully and unconditionally guaranteed the performance of all Pride obligations with respect to the Acquired Notes. See "Note 17 - Guarantee of Registered Securities" for additional information on the guarantee of the Acquired Notes.

We may redeem the Senior Notes in whole at any time, or in part from time to time, prior to maturity. If we elect to redeem the Rowan 2022 Notes, Rowan 2024 Notes, 8% 2024 Notes, 2024 Notes, 2025 Notes, Rowan 2025 Notes and 2026 Notes before the date that is three months prior to the maturity date or the Rowan 2042 Notes, Rowan 2044 Notes and 2044 Notes before the date that is six months prior to the maturity date, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest and a "make-whole" premium. If we elect to redeem these notes on or after the aforementioned dates, we will pay an amount equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest but we are not required to pay a "make-whole" premium.

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, Ensco plc entered into a supplemental indenture to unconditionally guarantee the principal and interest payments on the Debentures. See "Note 17 - Guarantee of Registered Securities" for additional information on the guarantee of the Debentures.

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Tender Offers and Open Market Repurchases

On June 25, 2019, we commenced cash tender offers for certain series of senior notes issued by us, 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 in other, net, in the consolidated statement of operations.

During 2017, we repurchased $194.1 million of our outstanding senior notes on the open market for an aggregate purchase price of $204.5 million with cash on hand and recognized an insignificant pre-tax gain, net of discounts, premiums and debt issuance costs.

Our tender offers and open market repurchases during the three-year period ended December 31, 2019 were as follows (in millions):



	Aggregate Principal Amount Repurchased		Aggregate Repurchase Price⁽¹⁾
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
Year Ended December 31, 2017
8.50% Senior notes due 2019	$	54.6	$	60.1
6.875% Senior notes due 2020	100.1		105.1
4.70% Senior notes due 2021	39.4		39.3
	$	194.1	$	204.5


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

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Exchange Offers

During 2017, we completed exchange offers to exchange our outstanding 2019, 2020 and 2021 Notes for our 8% 2024 Notes and cash. The exchange offers resulted in the tender of $649.5 million aggregate principal amount of our outstanding notes that were settled and exchanged as follows (in millions):



	Aggregate Principal Amount Repurchased		8% Senior Notes Due 2024 Consideration		Cash Consideration		Total Consideration
8.50% Senior notes due 2019	$	145.8	$	81.6	$	81.7	$	163.3
6.875% Senior notes due 2020	129.8		69.3		69.4		138.7
4.70% Senior notes due 2021	373.9		181.1		181.4		362.5
	$	649.5	$	332.0	$	332.5	$	664.5

During the year ended December 31, 2017, we recognized a pre-tax loss on the exchange offers of approximately $6.2 million.

Revolving Credit Facility

On December 6, 2019, Moody's downgraded our corporate family rating from B3 to Caa1 and our senior unsecured notes from Caa1 to Caa2. Previously, in September 2019, Standard & Poor's downgraded our senior unsecured bonds from B to B- and our issuer rating from B- to CCC+. The applicable margin rates are 3.25% per annum for Base Rate advances and 4.25% per annum for LIBOR advances. The quarterly commitment fee is 0.75% per annum on the undrawn portion of the $1.6 billion commitment.

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cash is greater than $250 million and there are no amounts outstanding under the credit facility. The July 2019 tender offers discussed above were in compliance with these covenants.

Our access to credit and capital markets depends on the credit ratings assigned to our debt. As a result of rating actions by credit rating agencies, we no longer maintain an investment-grade status. Our current credit ratings, and any additional actual or anticipated downgrades in our credit ratings, could limit our available options when accessing credit and capital markets, or when restructuring or refinancing our debt. In addition, future financings or refinancings are likely to involve higher borrowing costs and require more restrictive terms and covenants, which may further restrict our operations.

Maturities



Senior Notes	Original Principal		2016 Tenders, Repurchases and Equity Exchange			2017 Exchange Offers and Repurchases			2018 Tender Offers, Redemption and Debt Issuance			2019 Tender Offers, Redemption and Debt Issuance			Remaining Principal
6.875% due 2020	$	900.0	$	(219.2	)	$	(229.9	)	$	(328.0	)	$	—		$	122.9
4.70% due 2021	1,500.0		(817.0		)	(413.3		)	(156.2		)	—			113.5
4.875% due 2022 ⁽¹⁾	—		—			—			—			620.8			620.8
3.00% Exchangeable senior notes due 2024	849.5		—			—			—			—			849.5
4.50% due 2024	625.0		(1.7		)	—			—			(320.0		)	303.3
4.75% due 2024 ⁽¹⁾	—		—			—			—			318.6			318.6
8.00% due 2024	—		—			332.0			—			(39.7		)	292.3
5.20% due 2025	700.0		(30.7		)	—			—			(335.5		)	333.8
7.375% due 2025 ⁽¹⁾	—		—			—			—			360.8			360.8
7.75% due 2026	—		—			—			1,000.0			—			1,000.0
7.20% due 2027	150.0		—			—			—			(37.9		)	112.1
7.875% due 2040	300.0		—			—			—			—			300.0
5.40% due 2042 ⁽¹⁾	—		—			—			—			400.0			400.0
5.75% due 2044	1,025.0		(24.5		)	—			—			—			1,000.5
5.85% due 2044 ⁽¹⁾	—		—			—			—			400.0			400.0
Total	$	6,049.5	$	(1,093.1	)	$	(311.2	)	$	515.8		$	1,367.1		$	6,528.1


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

Interest Expense

Interest expense totaled $428.3 million, $282.7 million and $224.2 million for the years ended December 31, 2019, 2018 and 2017, respectively, which was net of capitalized interest of $20.9 million, $62.6 million and $72.5 million associated with newbuild rig construction and other capital projects.

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8. 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 use derivatives to reduce our exposure to various market risks, primarily foreign currency exchange rate risk. We maintain a foreign currency exchange rate risk management strategy that utilizes derivatives to reduce our exposure to unanticipated fluctuations in earnings and cash flows caused by changes in foreign currency exchange rates. We mitigate our credit risk relating to the counterparties of our derivatives by transacting with multiple, high-quality financial institutions, thereby limiting exposure to individual counterparties, and by entering into International Swaps and Derivatives Association, Inc. (“ISDA”) Master Agreements, which include provisions for a legally enforceable master netting agreement, with our derivative counterparties. See "Note 16 - Supplemental Financial Information" for additional information on the mitigation of credit risk relating to counterparties of our derivatives. We do not enter into derivatives for trading or other speculative purposes.

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 depends on the use of the derivative and whether it qualifies 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 and "Note 5 - Fair Value Measurements" for additional information on the fair value measurement of our derivatives.

As of December 31, 2019 and 2018, our consolidated balance sheets included net foreign currency derivative assets of $5.4 million and liabilities of $10.7 million, respectively. All of our derivatives mature within the next 18 months.

Derivatives recorded at fair value on our consolidated balance sheets as of December 31, 2019 and 2018 consisted of the following (in millions):



	Derivative Assets				Derivative Liabilities
	2019		2018		2019		2018
Derivatives Designated as Hedging Instruments
Foreign currency forward contracts - current⁽¹⁾	$	4.2	$	.2	$	.7	$	8.3
Foreign currency forward contracts - non-current⁽²⁾	.8		—		—		.4
	5.0		.2		.7		8.7
Derivatives not Designated as Hedging Instruments
Foreign currency forward contracts - current⁽¹⁾	1.3		.4		.2		2.6
Total	$	6.3	$	.6	$	.9	$	11.3


⁽¹⁾	Derivative assets and liabilities that have maturity dates equal to or less than 12 months from the respective balance sheet dates were included in other current assets and accrued liabilities and other, respectively, on our consolidated balance sheets.


⁽²⁾	Derivative assets and liabilities that have maturity dates greater than 12 months from the respective balance sheet dates were included in other assets and other liabilities, respectively, on our consolidated balance sheets.

We utilize 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. As of December 31, 2019, we had cash flow hedges outstanding to exchange an aggregate $199.1 million for various foreign currencies, including $114.8 million for British pounds, $45.9 million

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for Australian dollars, $15.9 million for euros, $10.9 million for Norwegian krone, $7.9 million for Singapore dollars and $3.7 million for Brazilian reals.

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, 2019 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⁾
	2019		2018			2017		2019		2018			2017		2019		2018			2017
Interest rate lock contracts⁽³⁾	$	—	$	—		$	—	$	1.9	$	.2		$	.2	$	—	$	—		$	—
Foreign currency forward contracts⁽⁴⁾	1.6		(9.7		)	8.5		6.4		(1.2		)	.2		—		(1.9		)	(.7		)
Total	$	1.6	$	(9.7	)	$	8.5	$	8.3	$	(1.0	)	$	.4	$	—	$	(1.9	)	$	(.7	)


⁽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.

⁽⁴⁾

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. During the year ended December 31, 2017, $1.1 million of losses were reclassified from AOCI into contract drilling expense and $900,000 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. We occasionally enter into derivatives that hedge the fair value of recognized foreign currency denominated assets or liabilities but do not designate such derivatives as hedging instruments. In these situations, a natural hedging relationship generally exists whereby changes in the fair value of the derivatives offset changes in the fair value of the underlying hedged items. As of December 31, 2019, we held derivatives not designated as hedging instruments to exchange an aggregate $47.1 million for various foreign currencies, including $15.4 million for British pounds, $6.6 million for Israeli New shekel, $5.9 million for Norwegian krone, $4.9 million for Nigerian naira, $4.5 million for Thai baht, $4.3 million for Australian dollars and $5.5 million for other currencies.

Net losses of $6.4 million and $11.8 million and gains of $10.0 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, 2019, 2018 and 2017, respectively.

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As of December 31, 2019, the estimated amount of net gains associated with derivatives, net of tax, that will be reclassified to earnings during the next 12 months was as follows (in millions):



Net unrealized losses to be reclassified to contract drilling expense	$	3.4
Net realized gains to be reclassified to depreciation expense	.8
Net losses to be reclassified to earnings	$	4.2

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9. SHAREHOLDERS' EQUITY

Activity in our various shareholders' equity accounts for each of the years in the three-year period ended December 31, 2019 was as follows (in millions):



	Shares	Par Value		Additional Paid-in Capital			Retained Earnings			AOCI			Treasury Shares			Non-controlling Interest
BALANCE, December 31, 2016	77.6	$	31.1	$	6,402.2		$	1,864.1		$	19.0		$	(65.8	)	$	4.4
Net loss	—	—		—			(303.7		)	—			—			(.5		)
Dividends paid ($0.16 per share)	—	—		—			(13.6		)	—			—			—
Cumulative-effect reduction from adoption of ASU 2016-16							(14.1		)
Distributions to noncontrolling interests	—	—		—			—			—			—			(6.0		)
Equity issuance in connection with Atwood Merger	33.1	13.2		757.5			—			—			—			—
Shares issued under share-based compensation plans, net	1.1	.5		(.4		)	—			—			(1.3		)	—
Repurchase of shares	—	—		—			—			—			(1.9		)	—
Share-based compensation cost	—	—		35.7			—			—			—			—
Net other comprehensive income	—	—		—			—			9.6			—			—
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			—			—
Shares issued under share-based compensation plans, net	3.4	1.4		(.6		)	—			—			(1.3		)	—
Distributions to noncontrolling interests	—	—		—			—			—			—			(3.6		)
Repurchase of shares	—	—		—			—			—			(1.9		)	—
Share-based compensation cost	—	—		30.6			—			—			—			—
Net other comprehensive income	—	—		—			—			(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		)	—
Repurchase of shares	—	—		—			—			—			(4.5		)	—
Share-based compensation cost	—	—		37.2			—			—			—			—
Equity issuance cost	—	—		(.6		)	—			—			—			—
Net changes in pension and other postretirement benefits	—	—		—			—			(21.7		)	—			—
Distributions to noncontrolling interests	—	—		—			—			—			—			(4.5		)
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	)

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 3 for additional information.

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On April 11, 2019, we completed our combination with Rowan and effected the Reverse Stock Split. All share and per-share amounts in these consolidated financial statements have been retrospectively adjusted to reflect the Reverse Stock Split.

In October 2017, as a result of our acquisition of Atwood Oceanics, Inc. (the "Atwood Merger"), we issued 33.1 million of our Class A Ordinary shares, representing total equity consideration of $770.7 million based on a closing price of $5.83 per Class A ordinary share on October 5, 2017, the last trading day before the Merger Date.

As a U.K. company governed in part by the U.K. Companies Act 2006, we cannot issue new shares (other than in limited circumstances) without being authorized by our shareholders. At our 2019 annual general meeting, our shareholders authorized the allotment of 67.6 million Class A ordinary shares (or 135.3 million Class A ordinary shares in connection with an offer by way of a rights issue or other similar issue), subject to the completion of the Rowan Transaction.

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 share repurchase program at our annual shareholder meeting held in May 2018. Subject to certain provisions under English law, including the requirement of Valaris plc to have sufficient distributable reserves, 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, 2019, there had been no share repurchases under this program.

10. 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, 14.8 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. As of December 31, 2019, there were 2.5 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.

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, 2019, there were 2.3 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, 2019, there were 100,000 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 2019, no cash-settled awards were granted while 4.5 million share unit awards were granted to our employees and non-employee directors pursuant to the LTIP Plans. 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, 2019 (in millions):



	2019			2018			2017
Contract drilling	$	22.1		$	18.9		$	18.3
General and administrative	17.4			14.5			14.5
	39.5			33.4			32.8
Tax benefit	(2.5		)	(2.8		)	(4.8		)
Total	$	37.0		$	30.6		$	28.0

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, 2019:



	Share Awards						Cash-Settled Awards
	2019		2018		2017		2019		2018		2017
Weighted-average grant-date fair value of share awards granted (per share)	$	11.50	$	24.62	$	31.48	$	—	$	21.35	$	25.08
Total fair value of share awards vested during the period (in millions)	$	17.7	$	7.5	$	8.2	$	3.5	$	9.9	$	3.9

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The following table summarizes share awards and cash-settled awards activity for the year ended December 31, 2019 (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, 2018	2,017		$	31.36	1,279		$	29.20
Granted	4,460		11.50		—		—
Rowan share awards assumed	2,329		15.88		—		—
Vested	(1,519	)	10.53		(453	)	7.97
Forfeited	(854	)	8.87		(129	)	11.58
Share awards and cash-settled awards as of December 31, 2019	6,433		$	19.89	697		$	46.28

As of December 31, 2019, there was $115.9 million of total unrecognized compensation cost related to share awards, which is expected to be recognized over a weighted-average period of 1.7 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 intends to share-settle any exercises of SARs and has therefore accounted for SARs as equity awards. As of December 31, 2019, SARs granted to purchase 530,923 shares with a weighted-average exercise price of $50.70 were outstanding under the Rowan LTIP. No SARs have been granted since 2010 under the Rowan LTIP, and there was no unrecognized compensation cost related to SARs as of December 31, 2019.

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, 2019, options granted to purchase 375,701 shares with a weighted-average exercise price of $52.77 were outstanding under the Company LTIPs. Excluding options assumed under the Atwood LTIP, no options have been granted since 2011, and there was no unrecognized compensation cost related to options as of December 31, 2019.

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 2017 and 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 performance goals are determined by a committee or subcommittee of the Board of Directors. Awards are payable in either Valaris shares or cash upon attainment of relative TSR and ROCE performance goals. Performance awards granted since 2017 are payable in cash.

Performance awards generally vest at the end of a three-year measurement period based on attainment of performance goals. Our performance awards granted during 2017, 2018 and 2019 are classified as liability awards, all

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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, 2018 and 2017 totaled $6.7 million. The aggregate fair value of performance awards vested during 2019, 2018 and 2017 totaled $2.2 million, $0.7 million and $2.9 million, respectively.

During the years ended December 31, 2019, 2018 and 2017, we recognized $3.2 million, $8.2 million and $8.4 million of compensation expense for performance awards, respectively, which was included in general and administrative expense in our consolidated statements of operations. As of December 31, 2019, there was $0.8 million of total unrecognized compensation cost related to unvested performance awards, which is expected to be recognized over a weighted-average period of 1.1 years.

Savings Plans

We have savings plans, (the Ensco Savings Plan, the Ensco Multinational Savings Plan, the Ensco Limited Retirement Plan, the Rowan Companies, Inc. Savings & Investment Plan (the "Rowan Savings Plan"), the RDIS International Savings Plan and the Rowan Drilling UK Pension Scheme), which cover eligible employees as defined within each plan. The Ensco Savings Plan and the Rowan Savings Plan include a 401(k) savings plan feature, which allows eligible employees to make tax-deferred contributions to the plans. The Ensco Limited Retirement Plan and the Rowan Drilling UK Pension Scheme also allows eligible employees to make tax-deferred contributions to the plan. Contributions made to the Ensco Multinational Savings Plan and the RDIS International Savings Plan may or may not qualify for tax deferral based on each plan participant's local tax requirements.

We generally make matching cash contributions to the plans. The legacy Ensco plans match 100% of the amount contributed by the employee up to a maximum of 5% of eligible salary, where the legacy Rowan plans also provide up to a 5% match of eligible salary; however, depending on the plan and the tier, the match percentage could vary. Matching contributions totaled $18.7 million, $14.4 million and $12.2 million for the years ended December 31, 2019, 2018 and 2017, respectively. Any additional discretionary contributions made into the plans require approval of the Board of Directors and are generally paid in cash. As of January 1, 2019, the plans were modified such that all previous, current and future employer contributions become 100% vested. We have 1.0 million shares reserved for issuance as matching contributions under the Ensco Savings Plan.

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Note 11 - 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.

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, 2019 and the funded status and weighted-average assumptions used to determine the benefit obligation at year end (dollars in millions):



	2019
	Pension Benefits			Other Benefits			Total
Projected benefit obligation:
Balance, April 11	$	800.1		$	15.9		$	816.0
Interest cost	21.3			0.4			21.7
Service cost	1.5			—			1.5
Actuarial loss	43.8			0.2			44.0
Benefits paid	(34.1		)	(0.4		)	(34.5		)
Foreign currency adjustments	(0.2		)	—			(0.2		)
Balance, December 31	$	832.4		$	16.1		$	848.5

Plan assets
Fair value, April 11	$	576.8		$	—		$	576.8
Actual return	43.6			—			43.6
Employer contributions	12.8			—			12.8
Benefits paid	(34.1		)	—			(34.1		)
Foreign currency adjustments	(0.2		)	—			(0.2		)
Fair value, December 31	$	598.9		—			$	598.9
Net benefit liabilities	$	233.5		$	16.1		$	249.6

Amounts recognized in consolidated balance sheet:
Accrued liabilities	$	(1.4	)	$	(1.5	)	$	(2.9	)
Other liabilities (long-term)	(232.1		)	(14.6		)	(246.7		)
Net benefit liabilities	$	(233.5	)	$	(16.1	)	$	(249.6	)

Accumulated contributions in excess of (less than) net periodic benefit cost	$	(206.2	)	$	(15.9	)	$	(222.1	)

Amounts not yet reflected in net periodic benefit cost:
Actuarial loss	$	(27.3	)	$	(0.2	)	$	(27.5	)
Total accumulated other comprehensive loss	(27.3		)	(0.2		)	(27.5		)
Net benefit liabilities	$	(233.5	)	$	(16.1	)	$	(249.6	)

Weighted-average assumptions:
Discount rate	3.16		%	3.06		%
Rate of compensation increase	—		%	—		%

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.

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The accumulated benefit obligations, which are presented below for all plans in the aggregate at December 31, 2019, are based on services rendered to date, but exclude the effect of future salary increases (in millions):



	2019
Accumulated benefit obligation	$	844.3

The components of net periodic pension cost and the weighted-average assumptions used to determine net periodic pension cost were as follows (dollars in millions):



	April 11, 2019 - December 31, 2019
Service cost ⁽¹⁾	$	1.5
Interest cost ⁽²⁾	21.3
Expected return on plan assets ⁽²⁾	(27.1		)
Net periodic pension cost (benefit)	$	(4.3	)
Discount rate	3.82		%


⁽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.

Target allocations among asset categories and the fair value of each category of plan assets as of December 31, 2019, classified by level within the US GAAP 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):

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	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, 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%
Cash and equivalents	0% to 10%	6.5		6.5		—		—
Aggregate	9% to 19%	76.7		—		76.7		—
Core plus	9% to 19%	77.6		77.6		—		—
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 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, 2019:


•	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.

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•	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 6.48% at December 31, 2019.

We currently expect to contribute approximately $35.7 million to our pension plans in 2020 and to directly pay other post-retirement benefits of approximately $1.5 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,
2020	$	45.0	$	1.5
2021	45.0		1.4
2022	44.6		1.3
2023	44.2		1.3
2024	43.9		1.3
2025 through 2029	213.6		5.3

12. INCOME TAXES

We generated profits of $39.0 million, losses of $115.1 million and profits of $6.3 million from continuing operations before income taxes in the U.S. and losses of $102.8 million, $423.8 million and $202.3 million from continuing operations before income taxes in non-U.S. jurisdictions for the years ended December 31, 2019, 2018 and 2017, 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, 2019 (in millions):



	2019		2018			2017
Current income tax expense (benefit):
U.S.	$	31.3	$	(19.9	)	$	(2.2	)
Non-U.S.	73.2		52.9			56.4
	104.5		33.0			54.2
Deferred income tax expense:
U.S.	19.7		52.9			36.0
Non-U.S.	4.2		3.7			19.0
	23.9		56.6			55.0
Total income tax expense	$	128.4	$	89.6		$	109.2

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U.S. Tax Reform

U.S. tax reform was enacted on December 22, 2017 and introduced significant changes to U.S. income tax law, including a reduction in the statutory income tax rate from 35% to 21% effective January 1, 2018, 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.

Due to the timing of the enactment of U.S. tax reform and the complexity involved in applying its provisions, we made reasonable estimates of its effects and recorded such amounts in our consolidated financial statements as of December 31, 2017 on a provisional basis. Throughout 2018, we continued to analyze applicable information and data, interpret rules and guidance issued by the U.S. Treasury Department and Internal Revenue Service, and make adjustments to the provisional amounts as provided for in Staff Accounting Bulletin No. 118. 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. We recognized a net tax expense of $16.5 million during 2017 in connection with enactment of U.S. tax reform, consisting of a $38.5 million tax expense associated with the one-time transition tax on deemed repatriation of the deferred foreign income of our U.S. subsidiaries, a $17.3 million tax expense associated with revisions to rules over the taxation of income of foreign subsidiaries, a $20.0 million tax benefit resulting from the re-measurement of our deferred tax assets and liabilities as of December 31, 2017 to reflect the reduced tax rate and a $19.3 million tax benefit resulting from adjustments to the valuation allowance on deferred tax assets.

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Deferred Taxes

The following table summarizes significant components of deferred income tax assets and liabilities as of December 31, 2019 and 2018 (in millions):



	2019			2018
Deferred tax assets:
Net operating loss carryforwards	$	1,546.7		$	148.4
Net capital loss carryforwards	998.0			—
Foreign tax credits	142.9			123.6
Interest limitation carryforwards	41.5			40.2
Premiums on long-term debt	—			23.8
Employee benefits, including share-based compensation	73.9			15.4
Deferred revenue	0.1			10.3
Other	11.6			14.5
Total deferred tax assets	2,814.7			376.2
Valuation allowance	(2,588.7		)	(316.0		)
Net deferred tax assets	226.0			60.2
Deferred tax liabilities:
Property and equipment	(156.0		)	(54.5		)
Net discounts on long-term debt	(49.5		)	—
Deferred U.S. tax on foreign income	(36.7		)	(31.5		)
Other	(23.7		)	(9.0		)
Total deferred tax liabilities	(265.9		)	(95.0		)
Net deferred tax asset (liability)	$	(39.9	)	$	(34.8	)

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, 2019, we had deferred tax assets of $142.9 million for U.S. foreign tax credits (“FTCs”), $1.5 billion related to $6.4 billion of net operating loss (“NOL”) carryforwards and $41.5 million for U.S. interest limitation carryforwards, which can be used to reduce our income taxes payable in future years. The FTCs expire between 2022 and 2029. NOL carryforwards, which were generated in various jurisdictions worldwide, include $5.6 billion that do not expire and $773.0 million that will expire, if not utilized, between 2020 and 2037. Deferred tax assets for NOL carryforwards at December 31, 2019 includes $1.3 billion acquired in the Rowan Transaction, substantially all of which pertains to NOL in Luxembourg. U.S. interest limitation carryforwards do not expire. Due to the uncertainty of realization, we have a $1.5 billion valuation allowance on FTC, NOL carryforwards and U.S. interest limitation carryforwards.

During 2019, we completed certain restructuring transactions that generated substantial U.S. capital gains and losses. As of December 31, 2019, we had recognized a deferred tax asset of $998 million associated with the net capital loss arising from these transactions. Based on our current assessment, this deferred tax asset is subject to a full valuation allowance because we more-likely-than-not will be unable to realize a future benefit from it.

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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, 2019, differs from the U.K. statutory income tax rate as follows:



	2019		2018		2017
U.K. statutory income tax rate	19.0	%	19.0	%	19.2	%
Non-U.K. taxes	(280.9	)	(18.0	)	(40.4	)
Bargain purchase gain	189.7		(.2	)	13.8
Valuation allowance	(145.1	)	(16.9	)	(18.0	)
Debt repurchases	48.7		(1.6	)	(2.8	)
Asset impairments	(31.0	)	(1.4	)	(17.1	)
U.S. tax reform	(21.6	)	2.2		(8.4	)
Restructuring transaction	7.9		1.7		—
Other	12.0		(1.4	)	(2.0	)
Effective income tax rate	(201.3	)%	(16.6	)%	(55.7	)%

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.

Our 2017 consolidated effective income tax rate includes $32.2 million associated with the impact of various discrete tax items, including $16.5 million of tax expense associated with U.S. tax reform and $15.7 million of tax expense associated with the exchange offers and debt repurchases, rig sales, a restructuring transaction, settlement of a previously disclosed legal contingency, the effective settlement of a liability for unrecognized tax benefits associated with a tax position taken in prior years and other resolutions of prior year tax matters.

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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, 2019, 2018 and 2017 were (14.6)%, (24.8)% and (96.0)%. The changes in our consolidated effective income tax rate, excluding discrete tax items, during the three-year period result primarily from U.S. tax reform and 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 7, 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 Rowan Notes. We expect to recognize a deferred tax benefit ranging from $40 million to $60 million during the first quarter of 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, 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. As of December 31, 2018, we had $143.0 million of unrecognized tax benefits, of which $136.5 million was included in other liabilities on our consolidated balance sheet and the remaining $6.5 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, $253.9 million of the $296.7 million unrecognized tax benefits as of December 31, 2019 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, 2019 and 2018 is as follows (in millions):



	2019			2018
Balance, beginning of year	$	143.0		$	147.6
Increases in unrecognized tax benefits as a result of the Rowan Transaction	149.9			—
Increases in unrecognized tax benefits as a result of tax positions taken during the current year	17.8			6.5
Impact of foreign currency exchange rates	(.3		)	(5.0		)
Lapse of applicable statutes of limitations	(4.4		)	(4.5		)
Increase in unrecognized tax benefits as a result of tax positions taken during prior years	1.1			2.5
Decreases in unrecognized tax benefits as a result of tax positions taken during prior years	(2.4		)	(3.8		)
Settlements with taxing authorities	(8.0		)	(.3		)
Balance, end of year	$	296.7		$	143.0

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 determination of the Swiss tax basis of property and equipment. After considering these uncertainties and all information currently available, we have concluded the tax basis of the property and equipment of our Swiss subsidiaries will more likely than not approximate its U.S. GAAP basis and, accordingly, we have not recognized deferred taxes. 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.

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Accrued interest and penalties totaled $58.9 million and $40.5 million as of December 31, 2019 and 2018, respectively, and were included in other liabilities on our consolidated balance sheets. We recognized a net expense of $5.7 million, $1.9 million and $4.4 million associated with interest and penalties during the years ended December 31, 2019, 2018, and 2017 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 2019, 2018 and 2017, resulting in net income tax benefits, inclusive of interest and penalties, of $5.3 million, $5.3 million and $1.1 million, respectively.

Absent the commencement of examinations by tax authorities, statutes of limitations applicable to certain of our tax positions will lapse during 2020. Therefore, it is reasonably possible that our unrecognized tax benefits will decline during the next 12 months by $800,000, inclusive of $550,000 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 $159.0 million converted using the current period-end exchange rates) related to tax years 2014, 2015 and 2016 for several of Rowan's Luxembourg subsidiaries, which assessments accrue interest at the rate of 7.2% per annum. We may make a payment to the Luxembourg tax authorities in advance of the final resolution of these assessments. Although the outcome of such assessments cannot be predicted with certainty, unfavorable outcomes could have a material adverse effect on our financial position, operating results and cash flows. We have recorded a $104 million liability for these assessments as of December 31, 2019.

During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $70.9 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 recorded a $15 million liability for these assessments as of December 31, 2019. 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 predicated with certainty, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows.

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. Each of the subsidiaries for which we maintain such policy has sufficient net assets, liquidity, contract backlog and/or other financial resources available to meet operational and capital investment requirements, which allows us to continue to maintain our policy of reinvesting the undistributed earnings indefinitely.

As of December 31, 2019, the aggregate undistributed earnings of the subsidiaries for which we maintain a policy and intention to reinvest earnings indefinitely totaled $289.0 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, 2019.

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13. COMMITMENTS AND CONTINGENCIES

Capital Commitments

The following table summarizes the estimated timing of our remaining contractual payments of our rigs under construction as of December 31, 2019 for our rigs under construction and (in millions):



	2020		2021		2022		Thereafter		Total⁽¹⁾
VALARIS DS-13⁽²⁾	$	—	$	83.9	$	—	$	—	$	83.9
VALARIS DS-14⁽²⁾	—		—		165.0		—		165.0
	$	—	$	83.9	$	165.0	$	—	$	248.9


⁽¹⁾	Total commitments are based on fixed-price shipyard construction contracts, exclusive of costs associated with project management, commissioning and systems integration testing. Total commitments also exclude holding costs and interest.

Based on our current projections, excluding integration-related capital expenditures, we expect capital expenditures during 2020 to approximate $160 million for newbuild construction, rig enhancement projects and minor upgrades and improvements. Approximately $30 million of our projected capital expenditures is reimbursable by our customers. Depending on market conditions and opportunities, we may reduce our planned expenditures or make additional capital expenditures to upgrade rigs for customer requirements or acquire additional rigs.

⁽²⁾

During the third quarter of 2019, we entered into amendments to our construction agreements with the shipyard for VALARIS DS-13 and VALARIS DS-14 to provide for, among other things, two-year extensions of the delivery date of each rig in exchange for payment of all accrued holding costs through March 31, 2019, totaling approximately $23 million. The new delivery dates for the VALARIS DS-13 and VALARIS DS-14 are September 30, 2021 and June 30, 2022, respectively. We can elect to request earlier delivery in certain circumstances. The interest rate on the final milestone payments increased from 5% to 7% per annum from October 1, 2019, for the VALARIS DS-13, and from July 1, 2020, for the VALARIS DS-14, until the actual delivery dates. The final milestone payments and interest are due at the new delivery dates (or, if accelerated, the actual delivery dates) and are estimated to be approximately $313.3 million in aggregate for both rigs, inclusive of interest, assuming we take delivery on the new delivery dates. In lieu of making the final milestone payments, we have the option to take delivery of the rigs and issue a promissory note for each rig to the shipyard owner for the amount due. If we issue the promissory note to the shipyard owner, we would also be required to provide a guarantee from Valaris plc.

Upon delivery, the remaining milestone payments and accrued interest thereon may be financed through a promissory note with the shipyard for each rig. The promissory notes will bear interest at a rate of 9% per annum with a maturity date of December 30, 2022 and will be secured by a mortgage on each respective rig. The remaining milestone payments for VALARIS DS-13 and VALARIS DS-14 are included in the table above in the period in which we expect to take delivery of the rig. However, we may elect to execute the promissory notes and defer payment until December 2022.

DSA Dispute

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to normalize business relations and the settlement agreement provides for our participation in current and future Petrobras tenders on the same basis as all other companies invited to these tenders. No losses were recognized during 2018 with respect to this settlement as all disputed receivables with Petrobras related to the DSA were fully reserved in 2015.

In April 2016, we initiated separate arbitration proceedings in the U.K. against SHI for the losses incurred in connection with the foregoing Petrobras arbitration and certain other losses relating to the DSA. In January 2018, the arbitration tribunal for the SHI matter issued an award on liability fully in our favor. The January 2018 arbitration award provides that SHI is liable to us for $10 million or damages that we can prove. We submitted our claim for damages to the tribunal, and the arbitral hearing on damages owed to us by SHI took place during the first quarter of 2019.

In May 2019, the arbitration tribunal for the SHI matter awarded us $180.0 million in damages. Further, we are entitled to claim interest on this award and costs incurred in connection with this matter. In June 2019, we and SHI filed separate applications with the English High Court to seek leave to appeal the damages awarded.

Indonesian Well-Control Event

Indonesian authorities have initiated a preliminary 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 preliminary investigation or whether the Indonesian authorities will open a full investigation into our involvement in this matter. 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. The Company expects to reach 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. 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 will be recorded to equity in 2020.

ARO Funding Obligations

Valaris and Saudi Aramco have agreed to take all steps necessary to ensure that ARO purchases at least 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

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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 ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, 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.

Other Matters

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, 2019 totaled $99.5 million and are issued under facilities provided by various banks and other financial institutions. Obligations under these letters of credit and surety bonds are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2019, we had not been required to make collateral deposits with respect to these agreements.

14. 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. Additionally, we sublease certain office space to third parties.

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.

The components of lease expense as of December 31, 2019 is as follows (in millions):




Long-term operating lease cost	$	29.5
Short-term operating lease cost	12.2
Sublease income	(2.4		)
Total operating lease cost	$	39.3

Supplemental balance sheet information related to our operating leases is as follows (in millions, except lease term and discount rate) as of December 31, 2019:

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Operating lease right-of-use assets⁽¹⁾	$	58.1

Current lease liability⁽¹⁾	$	21.1
Long-term lease liability⁽¹⁾	51.8
Total operating lease liabilities	$	72.9

Weighted-average remaining lease term (in years)	5.1

Weighted-average discount rate ⁽²⁾	8.23		%


⁽¹⁾	The right-of-use assets include $12.2 million acquired in the Rowan Transaction. The current and long-term lease liabilities include $3.9 million and $10.6 million, respectively, assumed in the Rowan Transaction.


⁽²⁾	Represents our estimated incremental borrowing cost on a secured basis for similar terms as the underlying leases.

For the year ended December 31, 2019, cash paid for amounts included in the measurement of our operating lease liabilities was $29.9 million.

We are obligated under leases for certain of our offices and equipment. Rental expense relating to operating leases was $40.1 million and $37.0 million during the years ended December 31, 2018 and 2017, respectively.

Maturities of lease liabilities as of December 31, 2019 were as follows (in millions):




2020	$	25.4
2021	18.4
2022	12.6
2023	10.7
2024	8.1
Thereafter	17.2
Total lease payments	$	92.4
Less imputed interest	19.5
Total	$	72.9

Future minimum rental payments under non-cancelable operating leases as of December 31, 2018 were as follows (in millions):




2019	$	32.3
2020	18.7
2021	11.9
2022	9.2
2023	8.9
Thereafter	15.2
Total lease payments	$	96.2

145

15. SEGMENT INFORMATION

Prior to the Rowan Transaction, our business consisted of three operating segments: (1) Floaters, which included our drillships and semisubmersible rigs, (2) Jackups, and (3) Other, which consisted of management services on rigs owned by third-parties. Floaters and Jackups were also reportable segments.

As a result of the Rowan Transaction, we concluded that we would maintain the aforementioned segment structure while adding ARO as a reportable segment for the new combined company. We also concluded that the activities associated with our arrangements with ARO, consisting of our Transition Services Agreement, Rig Lease Agreements and Secondment Agreement, do not constitute reportable segments and are therefore included within Other in the following segment disclosures. 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.

General and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items." We measure segment assets as property and equipment. The full operating results included below for ARO (representing only results of ARO from the Transaction Date) are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO. See Note 4 for additional information on ARO and related arrangements.

Segment information for each of the years in the three-year period ended December 31, 2019 is presented below (in millions).

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	378.6			212.4			40.3		—		(21.6		)	609.7
General and administrative	—			—			27.1		—		161.8			188.9
Equity in earnings of ARO	—			—			—		—		(12.6		)	(12.6		)
Operating income (loss)	$	(351.0	)	$	(176.9	)	$	62.9	$	85.7	$	(288.7	)	$	(668.0	)
Property and equipment, net	$	10,073.1		$	4,322.7		$	650.7	$	701.1	$	(650.7	)	$	15,096.9
Capital expenditures	$	31.4		$	184.6		$	27.5	$	—	$	(16.5	)	$	227.0

146

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

Year Ended December 31, 2017



	Floaters		Jackups			ARO		Other		Reconciling Items			Consolidated Total
Revenues	$	1,143.5	$	640.3		$	—	$	59.2	$	—		$	1,843.0
Operating expenses													—
Contract drilling (exclusive of depreciation)	624.2		512.1			—		53.2		—			1,189.5
Loss on impairment	174.7		8.2			—		—		—			182.9
Depreciation	297.4		131.5			—		—		15.9			444.8
General and administrative	—		—			—		—		157.8			157.8
Operating income (loss)	$	47.2	$	(11.5	)	$	—	$	6.0	$	(173.7	)	$	(132.0	)
Property and equipment, net	$	9,650.9	$	3,177.6		$	—	$	—	$	45.2		$	12,873.7
Capital expenditures	$	470.3	$	62.1		$	—	$	—	$	4.3		$	536.7

Information about Geographic Areas

As of December 31, 2019, our Floaters segment consisted of 16 drillships, eight dynamically positioned semisubmersible rigs and two moored semisubmersible rigs deployed in various locations. Of the drillships included in our Floaters segment, two ultra-deepwater drillships are under construction in South Korea. Our Jackups segment consisted of 41 jackup rigs which were deployed in various locations and our Other segment consisted of nine jackup rigs that are leased to our 50/50 joint venture with Saudi Aramco. Additionally, we had three rigs classified as held-for-sale.

147

As of December 31, 2019, the geographic distribution of our and ARO's drilling rigs was as follows:



	Floaters	Jackups	Other	Total	ARO
North & South America	10	8	—	18	—
Europe & the Mediterranean	7	14	—	21	—
Middle East & Africa	4	12	9	25	7
Asia & Pacific Rim	3	7	—	10	—
Asia & Pacific Rim (under construction)	2	—	—	2	—
Held-for-sale	1	2	—	3	—
Total	27	43	9	79	7

We provide management services on two rigs owned by third-parties 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 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.

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
	2019		2018		2017
Spain	$	3,012.4	$	2,306.6	$	2,004.2
United States	2,943.9		2,270.0		2,764.9
Saudi Arabia	1,257.7		668.6		93.6
United Kingdom	1,204.0		1,185.2		609.4
Nigeria	787.3		1,368.2		583.3
Singapore	22.6		23.9		2,859.3
Other countries	5,869.0		4,793.7		3,959.0
Total	$	15,096.9	$	12,616.2	$	12,873.7

16. SUPPLEMENTAL FINANCIAL INFORMATION

Consolidated Balance Sheet Information

Accounts receivable, net, as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019			2018
Trade	$	466.4		$	301.7
Other	60.3			46.4
	526.7			348.1
Allowance for doubtful accounts	(6.0		)	(3.4		)
	$	520.7		$	344.7

148

Other current assets as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019		2018
Materials and supplies	$	340.1	$	268.1
Prepaid taxes	36.2		35.0
Deferred costs	23.3		23.5
Prepaid expenses	13.5		15.2
Other	33.4		19.1
	$	446.5	$	360.9

Other assets as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019		2018
Right-of-use assets	$	58.1	$	—
Tax receivables	36.3		8.4
Deferred tax assets	26.6		29.4
Supplemental executive retirement plan assets	26.0		27.2
Intangible assets	11.9		2.5
Deferred costs	7.1		13.5
Other	22.3		16.8
	$	188.3	$	97.8

Accrued liabilities and other as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019		2018
Personnel costs	$	134.4	$	82.5
Accrued interest	115.2		100.6
Income and other taxes payable	61.2		36.9
Deferred revenue	30.0		56.9
Lease liabilities	21.1		—
Other	55.8		41.1
	$	417.7	$	318.0

Other liabilities as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019		2018
Unrecognized tax benefits (inclusive of interest and penalties)	$	323.1	$	177.0
Pension and other post-retirement benefits	246.7		—
Deferred tax liabilities	99.0		70.7
Intangible liabilities	52.1		53.5
Lease liabilities	51.8		—
Supplemental executive retirement plan liabilities	26.7		28.1
Personnel costs	24.5		25.1
Deferred revenue	9.7		20.5
Other	33.8		21.1
	$	867.4	$	396.0

149

Accumulated other comprehensive income as of December 31, 2019 and 2018 consisted of the following (in millions):



	2019			2018
Derivative instruments	$	22.6		$	12.6
Pension and other post-retirement benefits	(21.7		)	—
Currency translation adjustment	7.1			7.3
Other	(1.8		)	(1.7		)
	$	6.2		$	18.2

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, 2019 was as follows (in millions):



	2019		2018		2017
Repair and maintenance expense	$	303.7	$	198.4	$	188.7

Other, net, for each of the years in the three-year period ended December 31, 2019 consisted of the following (in millions):



	2019			2018			2017
Gain on bargain purchase and measurement period adjustments	$	637.0		$	1.8		$	140.2
SHI settlement	200.0			—			—
Gain (loss) on extinguishment of debt	194.1			(19.0		)	(2.6		)
Settlement of legal dispute	(20.3		)	—			—
Currency translation adjustments	(7.4		)	(17.2		)	(5.1		)
Other	1.0			(.4		)	1.9
	$	1,004.4		$	(34.8	)	$	134.4

Consolidated Statement of Cash Flows Information

Net cash provided by (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, 2019 was as follows (in millions):



	2019			2018			2017
(Increase) decrease in accounts receivable	$	29.5		$	(6.2	)	$	83.2
Increase in other assets	(32.0		)	(2.8		)	(14.0		)
Increase (Decrease) in liabilities	(25.4		)	2.7			3.2
	$	(27.9	)	$	(6.3	)	$	72.4

During periods in which our business contracts, resulting in significantly lower revenues and expenses as compared to the prior year, we typically generate positive cash flows from the net change in operating assets and liabilities as the impact from the collection of receivables that were accrued during the prior period is generally larger than the impact from the payment of expenses incurred in the prior period. 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. During 2017, our business contracted significantly as compared to the respective prior year periods resulting in positive cash generated from the net change in operating assets and liabilities.

150

Cash paid for interest and income taxes for each of the years in the three-year period ended December 31, 2019 was as follows (in millions):



	2019		2018		2017
Interest, net of amounts capitalized	$	410.0	$	232.6	$	199.8
Income taxes	107.6		58.4		62.8

Capitalized interest totaled $20.9 million, $62.6 million and $72.5 million during the years ended December 31, 2019, 2018 and 2017, respectively. Capital expenditure accruals totaling $16.3 million, $27.8 million and $243.3 million for the years ended December 31, 2019, 2018 and 2017, respectively, were excluded from investing activities in our consolidated statements of cash flows.

Amortization, net, includes amortization of deferred mobilization revenues and costs, deferred capital upgrade revenues, intangible amortization and other amortization.

Other includes amortization of debt discounts and premiums, deferred financing costs, deferred charges for income taxes incurred on intercompany transfers of drilling rigs 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 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. Short-term investments consist of a portfolio of time deposits held with several well-capitalized financial institutions, and we monitor the financial condition of those financial institutions.

We mitigate our credit risk relating to counterparties of our 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 ISDA Master Agreements, which include provisions for a legally enforceable master netting agreement, with our derivative counterparties. See "Note 8 - Derivative Instruments" for additional information on our derivative activity.

The terms of the ISDA agreements may also include 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.

Consolidated revenues by customer for the years ended December 31, 2019, 2018 and 2017 were as follows:



	2019		2018		2017
Total⁽¹⁾	16	%	15	%	22	%
BP ⁽²⁾	9	%	7	%	15	%
Saudi Aramco⁽³⁾	7	%	11	%	9	%
Petrobras⁽⁴⁾	4	%	8	%	11	%
Other	64	%	59	%	43	%
	100	%	100	%	100	%

151


⁽¹⁾	For the years ended December 31, 2019, 93% of revenues provided by Total were attributable to the Floaters segment and the remainder was attributable to the Jackup segment. During the years 2018 and 2017, all Total revenues were attributable to the Floater segment.


⁽²⁾	For the year ended December 31, 2019, 16%, 43% and 41% of BP revenues were attributable to our Floater, Other and Jackup segments, respectively.

For the year ended December 31, 2018, 27%, 53% and 20% of BP revenues were attributable to our Floater, Other and Jackup segments, respectively.

For the year ended December 31, 2017, 78% of BP revenues were attributable to our Floater segment and the remaining revenues were attributable to our Other segment.


⁽³⁾	For the years ended December 31, 2019, 2018 and 2017, all Saudi Aramco revenues were attributable to the Jackup segment.


⁽⁴⁾	For the years ended December 31, 2019, 2018 and 2017, all Petrobras revenues 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, 2019, 2018 and 2017 were as follows (in millions):



	2019		2018		2017
Saudi Arabia⁽¹⁾	$	313.4	$	182.2	$	171.8
U.S. Gulf of Mexico⁽²⁾	301.0		214.7		149.8
Angola⁽³⁾	284.0		285.7		445.7
United Kingdom⁽⁴⁾	213.1		192.6		164.6
Australia⁽⁵⁾	204.2		283.9		206.7
Brazil⁽⁶⁾	117.8		139.6		196.2
Egypt⁽⁷⁾	40.4		31.2		214.8
Other	579.3		375.5		293.4
	$	2,053.2	$	1,705.4	$	1,843.0


⁽¹⁾	For the years ended December 31, 2019, 65% and 35% of revenues were attributable to our Jackup and Other segments, respectively. For the years ended December 31, 2018 and 2017, all revenues earned were attributable to our Jackup segment.


⁽²⁾	For the years ended December 31, 2019, 2018 and 2017, 46%, 30% and 29% of revenues earned in the U.S. Gulf of Mexico, respectively, were attributable to our Floaters segment, 28%, 42% and 31% of revenues were attributable to our Jackup segment, respectively, and the remaining revenues were attributable to our Other segment, respectively.


⁽³⁾	For the years ended December 31, 2019, 2018 and 2017, 87%, 86% and 88% of revenues earned in Angola, respectively, were attributable to our Floaters segment with the remaining revenues attributable to our Jackup segment.


⁽⁴⁾	For the years ended December 31, 2019, 2018 and 2017, all revenues earned in the United Kingdom were attributable to our Jackup segment.

152


⁽⁵⁾	For the years ended December 31, 2019, 2018 and 2017, 90%, 92% and 87% of revenues earned in Australia, respectively, were attributable to our Floaters segment with the remaining revenues attributable to our Jackup segment.


⁽⁶⁾	For the years ended December 31, 2019, 2018 and 2017, all revenues earned in Brazil were attributable to our Floaters segment.


⁽⁷⁾	For the years ended December 31, 2019, 2018 and 2017, all revenues earned in Egypt were attributable to our Floaters segment.

153

17. GUARANTEE OF REGISTERED SECURITIES

In connection with the Pride acquisition, Valaris and Pride entered into a supplemental indenture to the indenture dated as of July 1, 2004 between Pride and the Bank of New York Mellon, as indenture trustee, providing for, among other matters, the full and unconditional guarantee by Valaris of Pride’s 6.875% senior notes due 2020 and 7.875% senior notes due 2040, which had an aggregate outstanding principal balance of $422.9 million as of December 31, 2019. The Valaris guarantee provides for the unconditional and irrevocable guarantee of the prompt payment, when due, of any amount owed to the holders of the notes.

Valaris is also a full and unconditional guarantor of the 7.2% Debentures due 2027 issued by Ensco International Incorporated in November 1997, which had an aggregate outstanding principal balance of $112.1 million as of December 31, 2019.

Pride International LLC and Ensco International Incorporated are 100% owned subsidiaries of Valaris. All guarantees are unsecured obligations of Valaris ranking equal in right of payment with all of its existing and future unsecured and unsubordinated indebtedness.

The following tables present our condensed consolidating statements of operations for each of the years in the three-year period ended December 31, 2019; our condensed consolidating statements of comprehensive income (loss) for each of the years in the three-year period ended December 31, 2019; our condensed consolidating balance sheets as of December 31, 2019 and 2018; and our condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2019, in accordance with Rule 3-10 of Regulation S-X.

154



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS Year Ended December 31, 2019 (in millions)
	Valaris plc			ENSCO International Incorporated			Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments			Total
OPERATING REVENUES	$	56.7		$	165.5		$	—		$	2,168.9		$	(337.9	)	$	2,053.2
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	82.6			147.1			—			1,914.2			(337.9		)	1,806.0
Loss on impairment	—			—			—			104.0			—			104.0
Depreciation	.1			17.3			—			592.3			—			609.7
General and administrative	85.5			.4			—			103.0			—			188.9
	168.2			164.8			—			2,713.5			(337.9		)	2,708.6
EQUITY IN EARNINGS OF ARO	—			—			—			(12.6		)	—			(12.6		)
OPERATING INCOME (LOSS)	(111.5		)	0.7			—			(557.2		)	—			(668.0		)
OTHER INCOME (EXPENSE), NET	723.9			(35.7		)	(80.8		)	(20.2		)	17.0			604.2
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	612.4			(35.0		)	(80.8		)	(577.4		)	17.0			(63.8		)
INCOME TAX EXPENSE	—			39.8			—			88.6			—			128.4
EQUITY EARNINGS (LOSSES) IN AFFILIATES, NET OF TAX	(810.4		)	47.8			25.0			—			737.6			—
NET LOSS	(198.0		)	(27.0		)	(55.8		)	(666.0		)	754.6			(192.2		)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(5.8		)	—			(5.8		)
NET LOSS ATTRIBUTABLE TO VALARIS	$	(198.0	)	$	(27.0	)	$	(55.8	)	$	(671.8	)	$	754.6		$	(198.0	)

155



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS Year Ended December 31, 2018 (in millions)
	Valaris plc			ENSCO International Incorporated			Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments			Total
OPERATING REVENUES	$	49.5		$	155.2		$	—		$	1,802.8		$	(302.1	)	$	1,705.4
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	51.0			139.5			—			1,431.0			(302.1		)	1,319.4
Loss on impairment	—			—			—			40.3			—			40.3
Depreciation	—			14.2			—			464.7			—			478.9
General and administrative	46.3			.4			—			56.0			—			102.7
OPERATING INCOME (LOSS)	(47.8		)	1.1			—			(189.2		)	—			(235.9		)
OTHER INCOME (EXPENSE), NET	2.7			(135.2		)	(89.0		)	(109.0		)	27.5			(303.0		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(45.1		)	(134.1		)	(89.0		)	(298.2		)	27.5			(538.9		)
INCOME TAX EXPENSE	—			43.3			—			46.3			—			89.6
DISCONTINUED OPERATIONS, NET	—			—			—			(8.1		)	—			(8.1		)
EQUITY EARNINGS (LOSSES) IN AFFILIATES, NET OF TAX	(594.6		)	121.8			93.3			—			379.5			—
NET INCOME (LOSS)	(639.7		)	(55.6		)	4.3			(352.6		)	407.0			(636.6		)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(3.1		)	—			(3.1		)
NET INCOME (LOSS) ATTRIBUTABLE TO VALARIS	$	(639.7	)	$	(55.6	)	$	4.3		$	(355.7	)	$	407.0		$	(639.7	)

156



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS Year Ended December 31, 2017 (in millions)
	Valaris plc			ENSCO International Incorporated			Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments			Total
OPERATING REVENUES	$	52.9		$	163.3		$	—		$	1,941.2		$	(314.4	)	$	1,843.0
OPERATING EXPENSES
Contract drilling (exclusive of depreciation)	50.0			149.9			—			1,304.0			(314.4		)	1,189.5
Loss on impairment	—			—			—			182.9			—			182.9
Depreciation	—			15.9			—			428.9			—			444.8
General and administrative	45.4			50.8			—			61.6			—			157.8
OPERATING LOSS	(42.5		)	(53.3		)	—			(36.2		)	—			(132.0		)
OTHER INCOME (EXPENSE), NET	(6.8		)	(110.5		)	(71.7		)	110.5			14.5			(64.0		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(49.3		)	(163.8		)	(71.7		)	74.3			14.5			(196.0		)
INCOME TAX EXPENSE	—			45.0			—			64.2			—			109.2
DISCONTINUED OPERATIONS, NET	—			—			—			1.0			—			1.0
EQUITY EARNINGS (LOSSES) IN AFFILIATES, NET OF TAX	(254.4		)	129.6			84.2			—			40.6			—
NET INCOME (LOSS)	(303.7		)	(79.2		)	12.5			11.1			55.1			(304.2		)
NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			.5			—			.5
NET INCOME (LOSS) ATTRIBUTABLE TO VALARIS	$	(303.7	)	$	(79.2	)	$	12.5		$	11.6		$	55.1		$	(303.7	)

157

VALARIS PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2019

(in millions)



	Valaris plc			ENSCO International Incorporated			Pride International LLC			Other Non-Guarantor Subsidiaries of Valaris			Consolidating Adjustments		Total

NET LOSS	$	(198.0	)	$	(27.0	)	$	(55.8	)	$	(666.0	)	$	754.6	$	(192.2	)
OTHER COMPREHENSIVE INCOME (LOSS), NET
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive loss, net of income tax benefits of ($5.9 million)	—			—			—			(21.7		)	—		$	(21.7	)
Net change in fair value of derivatives	—			1.6			—			—			—		1.6
Reclassification of net gains on derivative instruments from other comprehensive loss into net loss	—			8.3			—			—			—		8.3
Other	—			—			—			(.2		)	—		(.2		)
NET OTHER COMPREHENSIVE INCOME (LOSS)	—			9.9			—			(21.9		)	—		(12.0		)

COMPREHENSIVE LOSS	(198.0		)	(17.1		)	(55.8		)	(687.9		)	754.6		(204.2		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—			(5.8		)	—		(5.8		)
COMPREHENSIVE LOSS ATTRIBUTABLE TO VALARIS	$	(198.0	)	$	(17.1	)	$	(55.8	)	$	(693.7	)	$	754.6	$	(210.0	)

158

VALARIS PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2018

(in millions)



	Valaris plc			ENSCO International Incorporated			Pride International LLC		Other Non-Guarantor Subsidiaries of Valaris			Consolidating Adjustments		Total

NET INCOME (LOSS)	$	(639.7	)	$	(55.6	)	$	4.3	$	(352.6	)	$	407.0	$	(636.6	)
OTHER COMPREHENSIVE LOSS, NET
Net change in fair value of derivatives	—			(9.7		)	—		—			—		(9.7		)
Reclassification of net losses on derivative instruments from other comprehensive income into net income	—			(1.0		)	—		—			—		(1.0		)
Other	—			—			—		(.5		)	—		(.5		)
NET OTHER COMPREHENSIVE LOSS	—			(10.7		)	—		(.5		)	—		(11.2		)

COMPREHENSIVE INCOME (LOSS)	(639.7		)	(66.3		)	4.3		(353.1		)	407.0		(647.8		)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—		(3.1		)	—		(3.1		)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO VALARIS	$	(639.7	)	$	(66.3	)	$	4.3	$	(356.2	)	$	407.0	$	(650.9	)

159

VALARIS PLC AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

Year Ended December 31, 2017

(in millions)



	Valaris plc			ENSCO International Incorporated			Pride International LLC		Other Non-Guarantor Subsidiaries of Valaris		Consolidating Adjustments		Total

NET INCOME (LOSS)	$	(303.7	)	$	(79.2	)	$	12.5	$	11.1	$	55.1	$	(304.2	)
OTHER COMPREHENSIVE INCOME, NET
Net change in fair value of derivatives	—			8.5			—		—		—		8.5
Reclassification of net gains on derivative instruments from other comprehensive income into net loss	—			.4			—		—		—		.4
Other	—			—			—		.7		—		.7
NET OTHER COMPREHENSIVE INCOME	—			8.9			—		.7		—		9.6

COMPREHENSIVE INCOME (LOSS)	(303.7		)	(70.3		)	12.5		11.8		55.1		(294.6		)
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	—			—			—		.5		—		.5
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO VALARIS	$	(303.7	)	$	(70.3	)	$	12.5	$	12.3	$	55.1	$	(294.1	)

160



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2019 (in millions)
	Valaris plc			ENSCO International Incorporated		Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments			Total
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	21.5		$	—	$	—		$	75.7		$	—		$	97.2
Short-term investments	—								—						—
Accounts receivable, net	0.2			19.7					500.8			—			520.7
Accounts receivable from affiliates	4,031.4			386.0					897.2			(5,314.6		)	—
Other	.6			11.6					434.3						446.5
Total current assets	4,053.7			417.3		—			1,908.0			(5,314.6		)	1,064.4
PROPERTY AND EQUIPMENT, AT COST	1.9			108.8					18,283.1						18,393.8
Less accumulated depreciation	1.9			84.7					3,210.3						3,296.9
Property and equipment, net	—			24.1		—			15,072.8			—			15,096.9
SHAREHOLDER NOTE FROM ARO	—			—		—			452.9			—			452.9
INVESTMENT IN ARO	—			—		—			128.7			—			128.7
DUE FROM AFFILIATES	73.8			—		38.9			1,775.7			(1,888.4		)	—
INVESTMENTS IN AFFILIATES	9,778.5			788.8		1,224.9			—			(11,792.2		)	—
OTHER ASSETS	7.9			3.8		—			182.6			(6.0		)	188.3
	$	13,913.9		$	1,234.0	$	1,263.8		$	19,520.7		$	(19,001.2	)	$	16,931.2
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	99.2		$	29.3	$	12.2		$	565.2		$	—		$	705.9
Accounts payable to affiliates	818.8			147.8		815.1			3,532.9			(5,314.6		)	—
Current maturities of long - term debt	—			—		124.8			—			—			124.8
Total current liabilities	918.0			177.1		952.1			4,098.1			(5,314.6		)	830.7
DUE TO AFFILIATES	710.3			478.8		586.6			112.7			(1,888.4		)	—
LONG-TERM DEBT	2,990.6			111.7		373.3			2,447.9			—			5,923.5
OTHER LIABILITIES	(14.6		)	90.6		—			797.4			(6.0		)	867.4
VALARIS SHAREHOLDERS' EQUITY (DEFICIT)	9,309.6			375.8		(648.2		)	12,065.9			(11,792.2		)	9,310.9
NONCONTROLLING INTERESTS	—			—		—			(1.3		)	—			(1.3		)
Total equity (deficit)	9,309.6			375.8		(648.2		)	12,064.6			(11,792.2		)	9,309.6
	$	13,913.9		$	1,234.0	$	1,263.8		$	19,520.7		$	(19,001.2	)	$	16,931.2

161



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING BALANCE SHEETS December 31, 2018 (in millions)
	Valaris plc		ENSCO International Incorporated		Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments			Total
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	199.8	$	—	$	2.7		$	72.6		$	—		$	275.1
Short-term investments	329.0		—		—			—			—			329.0
Accounts receivable, net	7.3		25.4		—			312.0			—			344.7
Accounts receivable from affiliates	1,861.2		171.4		—			131.7			(2,164.3		)	—
Other	.6		6.0		—			354.3			—			360.9
Total current assets	2,397.9		202.8		2.7			870.6			(2,164.3		)	1,309.7
PROPERTY AND EQUIPMENT, AT COST	1.8		125.2		—			15,390.0			—			15,517.0
Less accumulated depreciation	1.8		91.3		—			2,807.7			—			2,900.8
Property and equipment, net	—		33.9		—			12,582.3			—			12,616.2
DUE FROM AFFILIATES	2,413.8		234.5		125.0			2,715.1			(5,488.4		)	—
INVESTMENTS IN AFFILIATES	8,522.6		3,713.7		1,199.9			—			(13,436.2		)	—
OTHER ASSETS	8.1		—		—			89.7			—			97.8
	$	13,342.4	$	4,184.9	$	1,327.6		$	16,257.7		$	(21,088.9	)	$	14,023.7
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	85.3	$	32.0	$	12.7		$	398.5		$	—		$	528.5
Accounts payable to affiliates	59.7		139.5		38.2			1,926.9			(2,164.3		)	—
Total current liabilities	145.0		171.5		50.9			2,325.4			(2,164.3		)	528.5
DUE TO AFFILIATES	1,432.0		1,226.9		1,366.5			1,463.0			(5,488.4		)	—
LONG-TERM DEBT	3,676.5		149.3		502.6			682.0			—			5,010.4
OTHER LIABILITIES	0.1		64.3		—			331.6			—			396.0
VALARIS SHAREHOLDERS' EQUITY (DEFICIT)	8,088.8		2,572.9		(592.4		)	11,458.3			(13,436.2		)	8,091.4
NONCONTROLLING INTERESTS	—		—		—			(2.6		)	—			(2.6		)
Total equity (deficit)	8,088.8		2,572.9		(592.4		)	11,455.7			(13,436.2		)	8,088.8
	$	13,342.4	$	4,184.9	$	1,327.6		$	16,257.7		$	(21,088.9	)	$	14,023.7

162



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2019 (in millions)
	Valaris plc			ENSCO International Incorporated			Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments		Total
OPERATING ACTIVITIES
Net cash provided by (used in) operating activities of continuing operations	$	(181.2	)	$	(57.9	)	$	(111.3	)	$	73.5		$	—	$	(276.9	)
INVESTING ACTIVITIES
Acquisition of Rowan, net of cash acquired	—			—			—			931.9			—		931.9
Maturities of short-term investments	474.0			—			—			—			—		474.0
Purchases of short-term investments	(145.0		)	—			—			—			—		(145.0		)
Additions to property and equipment	—			—			—			(227.0		)	—		(227.0		)
Net proceeds from disposition of assets				—			—			17.7			—		17.7
Other	(.1		)	—			—			.1			—		—
Net cash provided by investing activities of continuing operations	328.9			—			—			722.7			—		1,051.6
FINANCING ACTIVITIES
Reduction of long-term borrowings	(536.6		)	(30.4		)	—			(361.1		)	—		(928.1		)
Borrowings on credit facility	215.0			—			—			—			—		215.0
Repayments of credit facility borrowings	(215.0		)	—			—			—			—		(215.0		)
Advances from (to) affiliates	220.6			88.3			108.6			(417.5		)	—		—
Debt solicitation fees	—			—			—			(9.5		)	—		(9.5		)
Cash dividends paid	(4.5		)	—			—			—			—		(4.5		)
Other	(5.5		)	—			—			(4.7		)	—		(10.2		)
Net cash provided by (used in) financing activities	(326.0		)	57.9			108.6			(792.8		)	—		(952.3		)
Effect of exchange rate changes on cash and cash equivalents	—			—			—			(.3		)	—		(.3		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(178.3		)	—			(2.7		)	3.1			—		(177.9		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	199.8			—			2.7			72.6			—		275.1
CASH AND CASH EQUIVALENTS, END OF YEAR	$	21.5		$	—		$	—		$	75.7		$	—	$	97.2

163



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2018 (in millions)
	Valaris plc			ENSCO International Incorporated			Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments			Total
OPERATING ACTIVITIES
Net cash provided by (used in) operating activities of continuing operations	$	18.1		$	(135.1	)	$	(97.6	)	$	158.9		$	—		$	(55.7	)
INVESTING ACTIVITIES
Maturities of short-term investments	1,030.0			—			—			—			—			1,030.0
Purchases of short-term investments	(919.0		)	—			—			—			—			(919.0		)
Additions to property and equipment	—			—			—			(426.7		)	—			(426.7		)
Net proceeds from disposition of assets	—			—			—			11.0			—			11.0
Purchase of affiliate debt	(551.7		)	—			—			—			551.7			—
Sale of affiliate debt	479.0			—			—			—			(479.0		)	—
Net cash provided by (used in) investing activities of continuing operations	38.3			—			—			(415.7		)	72.7			(304.7		)
FINANCING ACTIVITIES
Proceeds from issuance of senior notes	1,000.0			—			—			—			—			1,000.0
Advances from (to) affiliates	(845.0		)	135.1			612.5			97.4			—			—
Reduction of long-term borrowings	(159.9		)	—			(537.8		)	(0.8		)	(72.7		)	(771.2		)
Debt issuance costs	(17.0		)	—			—			—			—			(17.0		)
Cash dividends paid	(17.9		)	—			—			—			—			(17.9		)
Other	(2.0		)	—			—			(3.7		)	—			(5.7		)
Net cash provided by (used in) financing activities	(41.8		)	135.1			74.7			92.9			(72.7		)	188.2
Net cash provided by discontinued operations	—			—			—			2.5			—			2.5
Effect of exchange rate changes on cash and cash equivalents	—			—			—			(.6		)	—			(.6		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	14.6			—			(22.9		)	(162.0		)	—			(170.3		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	185.2			—			25.6			234.6			—			445.4
CASH AND CASH EQUIVALENTS, END OF YEAR	$	199.8		$	—		$	2.7		$	72.6		$	—		$	275.1

164



VALARIS PLC AND SUBSIDIARIES CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS Year Ended December 31, 2017 (in millions)
	Valaris plc			ENSCO International Incorporated			Pride International LLC			Other Non-guarantor Subsidiaries of Valaris			Consolidating Adjustments			Total
OPERATING ACTIVITIES
Net cash provided by (used in) operating activities of continuing operations	$	(18.2	)	$	(117.6	)	$	(100.1	)	$	495.3		$	—		$	259.4
INVESTING ACTIVITIES
Purchases of short-term investments	(1,022.9		)	—			—			(17.1		)	—			(1,040.0		)
Additions to property and equipment	—			—			—			(536.7		)	—			(536.7		)
Maturities of short-term investments	1,748.0			5.5			—			289.0			—			2,042.5
Net proceeds from disposition of assets	—			—			—			2.8			—			2.8
Purchase of affiliate debt	(316.3		)	—			—			—			316.3			—
Acquisition of Atwood, net of cash acquired	—			—			—			(871.6		)	—			(871.6		)
Net cash provided by (used in) investing activities of continuing operations	408.8			5.5			—			(1,133.6		)	316.3			(403.0		)
FINANCING ACTIVITIES
Reduction of long-term borrowing	(220.7		)	—			—			—			(316.3		)	(537.0		)
Cash dividends paid	(13.8		)	—			—			—			—			(13.8		)
Debt issuance costs	(12.0		)	—			—			—			—			(12.0		)
Advances from (to) affiliates	(848.9		)	112.1			105.9			630.9			—			—
Other	(2.6		)	—			—			(5.1		)	—			(7.7		)
Net cash provided by (used in) financing activities	(1,098.0		)	112.1			105.9			625.8			(316.3		)	(570.5		)
Net cash used in discontinued operations	—			—			—			(.8		)	—			(.8		)
Effect of exchange rate changes on cash and cash equivalents	—			—			—			.6			—			.6
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(707.4		)	—			5.8			(12.7		)	—			(714.3		)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR	892.6			—			19.8			247.3			—			1,159.7
CASH AND CASH EQUIVALENTS, END OF YEAR	$	185.2		$	—		$	25.6		$	234.6		$	—		$	445.4

165

18. UNAUDITED QUARTERLY FINANCIAL DATA

The following tables summarize our unaudited quarterly condensed consolidated income statement data for the years ended December 31, 2019 and 2018 (in millions, except per share amounts):



	2019
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
Operating revenues	$	405.9		$	583.9		$	551.3		$	512.1		$	2,053.2
Operating expenses
Contract drilling (exclusive of depreciation)	332.6			500.3			496.5			476.6			1,806.0
Loss on impairment⁽¹⁾	—			2.5			88.2			13.3			104.0
Depreciation	125.0			157.9			163.0			163.8			609.7
General and administrative	29.6			81.2			36.1			42.0			188.9
Equity in earnings of ARO	—			0.6			(3.7		)	(9.5		)	(12.6		)
Operating loss	(81.3		)	(157.4		)	(236.2		)	(193.1		)	(668.0		)
Other income (expense), net	(75.2		)	597.3			40.2			41.9			604.2
Income (loss) from continuing operations before income taxes	(156.5		)	439.9			(196.0		)	(151.2		)	(63.8		)
Income tax expense	31.5			32.6			1.5			62.8			128.4
Net income (loss)	(188.0		)	407.3			(197.5		)	(214.0		)	(192.2		)
Net (income) loss attributable to noncontrolling interests	(2.4		)	(1.8		)	.4			(2.0		)	(5.8		)
Net income (loss) attributable to Valaris	$	(190.4	)	$	405.5		$	(197.1	)	$	(216.0	)	$	(198.0	)
Income (loss) per share – basic and diluted
Continuing operations	$	(1.75	)	$	2.09		$	(1.00	)	$	(1.09	)	$	(1.14	)
Discontinued operations	—			—			—			—			—
	$	(1.75	)	$	2.09		$	(1.00	)	$	(1.09	)	$	(1.14	)


⁽¹⁾	The quarterly periods included losses associated with the impairment of older, less capable, non-core rigs and operating lease impairments. See "Note 6 - Property and Equipment" and "Note 14 - Leases" for additional information.

166



	2018
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year
Operating revenues	$	417.0		$	458.5		$	430.9		$	399.0		$	1,705.4
Operating expenses
Contract drilling (exclusive of depreciation)	325.2			344.3			327.1			322.8			1,319.4
Loss on impairment⁽¹⁾	—			—			—			40.3			40.3
Depreciation	115.2			120.7			120.6			122.4			478.9
General and administrative	27.9			26.1			25.1			23.6			102.7
Operating loss	(51.3		)	(32.6		)	(41.9		)	(110.1		)	(235.9		)
Other expense, net	(70.7		)	(84.8		)	(77.7		)	(69.8		)	(303.0		)
Loss from continuing operations before income taxes	(122.0		)	(117.4		)	(119.6		)	(179.9		)	(538.9		)
Income tax expense	18.4			24.7			23.3			23.2			89.6
Loss from continuing operations	(140.4		)	(142.1		)	(142.9		)	(203.1		)	(628.5		)
Loss from discontinued operations, net	(.1		)	(8.0		)	—			—			(8.1		)
Net loss	(140.5		)	(150.1		)	(142.9		)	(203.1		)	(636.6		)
Net (income) loss attributable to noncontrolling interests	.4			(.9		)	(2.1		)	(.5		)	(3.1		)
Net loss attributable to Valaris	$	(140.1	)	$	(151.0	)	$	(145.0	)	$	(203.6	)	$	(639.7	)
Loss per share – basic and diluted
Continuing operations	$	(1.29	)	$	(1.31	)	$	(1.34	)	$	(1.88	)	$	(5.82	)
Discontinued operations	—			(0.08		)	—			—			(0.08		)
	$	(1.29	)	$	(1.39	)	$	(1.34	)	$	(1.88	)	$	(5.90	)


⁽¹⁾	Fourth quarter included an aggregate loss of $40.3 million associated with the impairment of an older, non-core jackup rig. See "Note 6 - Property and Equipment" for additional information.

167

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 under the Exchange Act, are effective.

During the year ended December 31, 2019, 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.

In 2019, we completed our merger with Rowan (See Note 3 to our consolidated financial statements for more information). We are currently integrating Rowan into our operations and internal control processes and, pursuant to the SEC's guidance that a recently acquired business may be excluded from the scope of an assessment of internal control over financial reporting in the year of acquisition, the scope of our assessment of the effectiveness of our internal controls over financial reporting at December 31, 2019 excludes Rowan to the extent not integrated into our control environment.

See "Item 8. Financial Statements and Supplementary Data" for Management's Report on Internal Control Over Financial Reporting.

Item 9B. Other Information

Not applicable.

168

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item with respect to our directors, corporate governance matters, committees of the Board of Directors and Section 16(a) of the Exchange Act is contained in our Proxy Statement for the Annual General Meeting of Shareholders ("Proxy Statement") to be filed with the SEC not later than 120 days after the end of our fiscal year ended December 31, 2019 and incorporated herein by reference.

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.

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.valarisplc.com in the Governance Documents section and are available in print without charge by contacting our Investor Relations Department at 713-430-4607.

We have a Code of Conduct that applies to all employees, including our principal executive officer, principal financial officer and principal accounting officer. The Code of 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. Our Proxy Statement contains governance disclosures, including information on our Code of Conduct, our Corporate Governance Policy, the director nomination process, shareholder director nominations, shareholder communications to the Board of Directors and director attendance at the Annual General Meeting of Shareholders.

Item 11. Executive Compensation

The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

169

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

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, 2019:



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	—	$	—	2,471,736
Equity compensation plans not approved by security holders⁽²⁾	906,624	51.56		2,425,751
Total	906,624	$	51.56	4,897,487

170



(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 LTIP, 2.3 million shares remained available for future issuances of non-vested share awards, share option awards and performance awards as of December 31, 2019.
	In connection with the Pride acquisition, we assumed Pride's option plan and the outstanding options thereunder. As of December 31, 2019, options to purchase 7,500 shares at a weighted-average exercise price of $165.51 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, 2019, options to purchase 124,176 shares at a weighted-average exercise price of $99.39 per share were outstanding under this plan. There were also 96,626 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, 2019, options to purchase 244,025 shares at a weighted-average exercise price of $25.58 per share, 530,923 share appreciation rights at a weighted-average exercise price of $50.70 per share and 2,075,426 restricted share units were outstanding under this plan. There were also 2.3 million 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.

Additional information required by this item is included in our Proxy Statement and incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The information required by this item is contained in our Proxy Statement and incorporated herein by reference.

PART IV

171

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	88
	Consolidated Statements of Operations	93
	Consolidated Statements of Comprehensive Income	94
	Consolidated Balance Sheets	95
	Consolidated Statements of Cash Flows	96
	Notes to Consolidated Financial Statements	97
	2. Financial Statement Schedules:
	The schedules for which provision is made in the applicable accounting regulations of the SEC are not required under the related instructions or are inapplicable or provided elsewhere in the financial statements and, therefore, have been omitted.



	3. Exhibits



Exhibit Number		Exhibit

2.1		Transaction Agreement, dated as of October 7, 2018, by and between Valaris plc and Rowan Companies plc (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on October 9, 2018, File No. 1-8097).

2.2		Deed of Amendment No. 1 to the Transaction Agreement, dated as of January 28, 2019, by and between Valaris plc and Rowan Companies plc (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on January 29, 2019, File No. 1-8097).

2.3		Deed of Amendment No. 2 to the Transaction Agreement, dated as of April 4, 2019, by and between Ensco plc and Rowan (incorporated by reference to Exhibit 2.1 to the Registrant’s Quarterly Report on Form 10-Q filed on May 2, 2019. File No. 1-8097)

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).

172



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		Second Supplemental Indenture, dated June 2, 2009, 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 4.1 to Pride's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13289).

4.7		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).

4.8		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).

4.9		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).

4.10		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).

4.11		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).

4.12		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).

4.13		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).

4.14		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).

4.15		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).

4.16		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).

4.17		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).

4.18		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).

4.19		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).

173



4.20		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).

4.21		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).

4.22		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).

4.23		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).

4.24		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).

4.25		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).

4.26		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).

4.27		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).

4.28		First Supplemental Indenture dated as of July 21, 2009, between Rowan Companies, Inc. 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 July 21, 2009 (File No. 1-5491).

4.29		Form of 7.875% Senior Note due 2019, incorporated by reference to Exhibit 4.2 of Rowan's Current Report on Form 8-K filed on July 21, 2009 (File No. 1-5491).

4.30		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).

4.31		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).

4.32		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).

4.33		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 the Company’s Current Report on Form 8-K filed on December 11, 2012 (File No. 1-5491).

4.34		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).

4.35		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 the Company’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).

4.36		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).

4.37		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 the Company’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).

4.38		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).

4.39		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).

174



4.40		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).

4.41		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).

*4.42		Description of the Company’s Class A Ordinary Shares

*4.43		Description of the Company’s 4.70% Senior Notes due 2021

*4.44		Description of the Company’s 4.50% Senior Notes due 2024

*4.45		Description of the Company’s 8.00% Senior Notes due 2024

*4.46		Description of the Company’s 5.20% Senior Notes due 2025

*4.47		Description of the Company’s 7.75% Senior Notes due 2026

*4.48		Description of the Company’s 5.75% Senior Notes due 2044

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).

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		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).

+10.9		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).

175



+10.10		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).

+10.11		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).

+10.12		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).

+10.13		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).

+10.14		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).

+10.15		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).

+10.16		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).

+10.17		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).

+10.18		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).

+10.19		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).

+10.20		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).

+10.21		ENSCO Supplemental Executive Retirement Plan and Non-Employee Director Deferred Compensation Plan Trust Agreement (As Revised and Restated Effective January 1, 2004), dated August 27, 2003 (incorporated by reference to Exhibit 10.3 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, File No. 1-8097).

+10.22		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).

+10.23		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).

+10.24		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).

+10.25		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).

176



+10.26		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).

+10.27		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).

+*10.28		Amendment No. 6 to the ENSCO 2005 Supplemental Executive Retirement Plan (as amended and restated effective January 1, 2005), dated December 19, 2019.

+10.29		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).

+10.30		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).

+10.31		Amended and Restated ENSCO International Incorporated 2005 Cash Incentive Plan (as revised and restated for amendments through March 30, 2015) (incorporated by reference to Annex 3 to the Registrant's Proxy Statement on Schedule 14A filed on April 3, 2015, File No. 1-8097).

+10.32		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).

+10.33		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).

+10.34		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).

+10.35		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).

+10.36		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).

+10.37		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).

+10.38		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).

+10.39		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).

+10.40		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).

+10.41		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).

+10.42		Form of Ensco plc 2012 Long-Term Incentive Plan Restricted Share Award Agreement (Carl Trowell) (incorporated by reference to Exhibit 10.4 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, File No. 1-8097).

+10.43		Form of Ensco plc 2012 Long-Term Incentive Plan Performance Unit Award Agreement (Carl Trowell) (incorporated by reference to Exhibit 10.5 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, File No. 1-8097).

177



+10.44		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).

+10.45		Deed of Variation among Ensco Global Resources Limited, Carl Trowell and Ensco Services Limited, dated June 2, 2014, together with the Employment Agreement between Ensco Global Resources Limited and Carl Trowell, dated May 3, 2014 and attached as a schedule to the Deed of Variation (incorporated by reference to Exhibit 10.1 of the Registrant's Quarterly Report on Form 10-Q filed on August 1, 2014, File No. 1-8097).

+10.46		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).

+10.47		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).

+10.48		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).

+10.49		Ensco plc 2018 Cash Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on February 22, 2018, File No. 001-08097).

+10.50		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).

+10.51		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).

+10.52		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).

+10.53		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).

+10.54		Form of Ensco plc 2018 Long-Term Incentive Plan Restricted Share Unit Award Agreement (CEO) (incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on March 11, 2019, File No. 1-8097).

+10.55		Form of Ensco plc 2018 Long-Term Incentive Plan Performance Unit Award Agreement (Executives) (incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on March 11, 2019, File No. 1-8097).

+10.56		Form of Ensco plc 2018 Long-Term Incentive Plan Performance Unit Award Agreement (CEO) (incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K filed on March 11, 2019, File No. 1-8097).

10.57		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).

10.58		Separation Agreement, dated July 24, 2019, by and between Ensco Global Resources Limited and Steve Brady

+*10.59		Thomas P. Burke Salary Reduction Letter, dated December 3, 2019

+*10.60		Consulting Agreement, dated December 31, 2019, by and between ENSCO Incorporated and Patrick Carey Lowe

+*10.61		Severance Agreement, dated December 31, 2019, by and between Ensco Global Resources Limited and Patrick Carey Lowe

178



+10.62		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).

+10.63		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).

+10.64		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).

+10.65		Forms of Restricted Share Unit Award Notice, Share Appreciation Right Award Notice and Performance Unit 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).

+10.66		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).

+10.67		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).

+10.68		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).

+10.69		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).

+10.70		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).

+10.71		Summary of the Company’s Annual Incentive Plan, incorporated by reference to Exhibit 10.34 to Rowan's Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-5491).

+10.72		Form of Non-Employee Director Restricted Share Award Notice, incorporated by reference to Exhibit 10.1 to Rowan's Current Report on Form 8-K filed on May 2, 2016 (File No. 1-5491).

+10.73		Forms of Retention Award Notices, incorporated by reference to Exhibit 10.2 of Rowan's Current Report on Form 8-K filed on February 24, 2017 (File No. 1-5491).

+10.74		Forms of Restricted Share Unit Award Notice and Performance 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).

+10.75		Form of non-Employee Director Non-Deferred Restricted Share Unit Notice, incorporated by reference to Exhibit 10.1 to Rowan's Current Report on Form 8-K file on May 25, 2017 (File No. 1-05491).

+10.76		Form of Letter Agreement to Retention Award Agreement, incorporated by reference to Exhibit 10.1 of Rowan's Current Report on Form 8-K filed on January 30, 2018 (File No. 1-5491).

+*10.77		Valaris Executive Severance Plan

+10.78		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)

+10.79		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

*21.1		Subsidiaries of the Registrant.

*23.1		Consent of Independent Registered Public Accounting Firm.

179



*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.

*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

*101.SCH		XBRL Taxonomy Extension Schema

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase

*101.DEF		XBRL Taxonomy Extension Definition Linkbase

*101.LAB		XBRL Taxonomy Extension Label Linkbase

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase

* ** +		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.

180

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 February 21, 2020.

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	February 21, 2020

/s/ CARL G. TROWELL Carl G. Trowell	Executive Chairman	February 21, 2020

/s/ WILLIAM E. ALBRECHT William E. Albrecht	Independent Lead Director	February 21, 2020

/s/ FREDERICK ARNOLD Frederick Arnold	Director	February 21, 2020

/s/ MARY E. FRANCIS CBE Mary E. Francis CBE	Director	February 21, 2020

/s/ GEORGES J. LAMBERT Georges J. Lambert	Director	February 21, 2020

/s/ SUZANNE P. NIMOCKS Suzanne P. Nimocks	Director	February 21, 2020

/s/ THIERRY PILENKO Thierry Pilenko	Director	February 21, 2020

/s/ KEITH O. RATTIE Keith O. Rattie	Director	February 21, 2020

/s/ PAUL E. ROWSEY, III Paul E. Rowsey, III	Director	February 21, 2020

/s/ CHARLES L. SZEWS Charles L. Szews	Director	February 21, 2020

/s/ ADAM WEITZMAN Adam Weitzman	Director	February 21, 2020

/s/ JONATHAN H. BAKSHT Jonathan H. Baksht	Executive Vice President and Chief Financial Officer (principal financial officer)	February 21, 2020

/s/ TOMMY E. DARBY Tommy E. Darby	Vice President - Finance (principal accounting officer)	February 21, 2020

181