Valaris Ltd (VAL) FY 2022 MD&A

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

The following information should be read in conjunction with "Item 1A. Risk Factors" and our consolidated financial statements and the notes thereto in "Item 8. Financial Statements and Supplementary Data" of this report.

The discussion of our results of operations and liquidity in this section includes comparisons for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and for the four months ended April 30, 2021 (Predecessor). For a similar discussion, including comparisons for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the year ended December 31, 2020 (Predecessor), see “Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our annual report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 22, 2022.

INTRODUCTION

Our Business

We are a leading provider of offshore contract drilling services to the international oil and gas industry with operations in almost every major offshore market across six continents. We own the world's largest offshore drilling rig fleet, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet. We currently own 52 rigs, including 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 36 jackup rigs and a 50% equity interest in ARO, our 50/50 unconsolidated joint venture with Saudi Aramco, which owns an additional seven rigs. We also have options to purchase two recently constructed drillships on or before December 31, 2023.

Our customers include many of the leading international and government-owned oil and gas companies, in addition to many independent operators. We are among the most geographically diverse offshore drilling companies with current operations spanning six  continents. The markets in which we operate include the Gulf of Mexico, South America, the North Sea, the Middle East, Africa and Asia Pacific.

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.

Chapter 11 Proceedings, Emergence from Chapter 11 and Fresh Start Accounting

On the Petition Date, the Debtors filed voluntary petitions for reorganization under chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

In connection with the Chapter 11 Cases and the plan of reorganization, on and prior to the Effective Date, Legacy Valaris effectuated certain restructuring transactions, pursuant to which Valaris was formed and, through a series of transactions, Legacy Valaris transferred to a subsidiary of Valaris substantially all of the subsidiaries, and other assets, of Legacy Valaris.

On the Effective Date, we successfully completed our financial restructuring and together with the Debtors emerged from the Chapter 11 Cases. Upon emergence from the Chapter 11 Cases, we eliminated $7.1 billion of debt and obtained a $520 million capital injection by issuing the First Lien Notes. See “Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional

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information on the First Lien Notes. On the Effective Date, the Legacy Valaris Class A ordinary shares were cancelled and the Common Shares were issued. Also, former holders of Legacy Valaris' equity were issued Warrants to purchase Common Shares. See “Note 10 - Shareholders' Equity" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the issuance of the Common Shares and Warrants.

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

Upon emergence from the Chapter 11 Cases, we qualified for and adopted fresh start accounting. The application of fresh start accounting resulted in a new basis of accounting, and the Company became a new entity for financial reporting purposes. Accordingly, our financial statements and notes after the Effective Date are not comparable to our financial statements and notes on and prior to that date.

See “Note 2 – Chapter 11 Proceedings” and "Note 3 - Fresh Start Accounting" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional details regarding the bankruptcy, our emergence and fresh start accounting.

Our Industry

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

Over the last several years, oil price volatility, resulting from the global COVID-19 pandemic, production disputes among major oil producing countries and various other factors, significantly impacted our business. In 2020, the combined effects of the COVID-19 pandemic, the significant decline in the demand for oil and the substantial surplus in the supply of oil resulted in significantly reduced demand and day rates for offshore drilling services provided by the Company and increased uncertainty regarding long-term market conditions. These events had a significant adverse impact on our liquidity position and financial runway and led to the filing of the Chapter 11 Cases.

During 2021 and 2022, oil prices increased due to, among other factors, rebounding demand for hydrocarbons, a measured approach to production increases by OPEC+ members, reduction in supply due to Russia’s invasion of Ukraine and the subsequent sanctions placed on Russia, and a focus on cash flow and returns by major exploration and production companies. The more constructive oil price environment has led to an improvement in contracting and tendering activity.

We are experiencing the impacts of global inflation, both in increased personnel costs as well as in the prices of goods and services required to operate our rigs or execute capital projects. While we are currently unable to estimate the ultimate impact of rising prices, we do expect that our costs will continue to rise in the near term and will impact our profitability. Although certain of our long-term contracts contain provisions for escalating costs, we cannot predict with certainty our ability to successfully claim recoveries of higher costs from our customers under these contractual stipulations. See "Item 1A. Risk Factors - Our long-term contracts are subject to the risk of cost increases, which could adversely impact our profitability."

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The outlook for the offshore drilling industry has improved since the beginning of 2021, as evidenced by increasing global utilization and day rates for offshore drilling rigs, most notably for drillships. However, the combination of global inflation and a tightening of monetary policy has led to increasing concerns of a global economic recession that may have a negative impact on demand for hydrocarbons. As a result, there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for, and profitability of, offshore drilling services.

Backlog

Our contract drilling backlog reflects commitments, represented by signed drilling contracts, and is calculated by multiplying the contracted operating 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. Our backlog excludes ARO's backlog, but includes backlog from our rigs leased to ARO at the contractual rates, which are subject to adjustment under the terms of the shareholder agreement governing the joint venture.

ARO backlog is inclusive of backlog on both ARO owned rigs and rigs leased from us. As an unconsolidated 50/50 joint venture, when ARO realizes revenue from its backlog, 50% of the earnings thereon would be reflected in our results in the equity in earnings of ARO in our Consolidated Statement of Operations. The earnings from ARO backlog with respect to rigs leased from us will be net of, among other things, payments to us under bareboat charters for those rigs. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

The following table summarizes our and ARO's contract backlog of business as of February 21, 2023 and 2022 (in millions):

(1)Our backlog as of February 21, 2022 included approximately $428 million attributable to a contract awarded to VALARIS DS-11 for an eight-well deepwater project in the U.S. Gulf of Mexico that was expected to commence in mid-2024. In June 2022, the customer terminated the contract. As a result of the contract termination, we received an early termination fee of $51.0 million which is included in revenues on our Consolidated Statements of Operations for the year ended December 31, 2022 (Successor). As of the date of the termination, we had incurred costs to upgrade the rig pursuant to the requirements of the contract. Costs incurred for capital upgrades specific to the customer requirements were considered to be impaired and as such, we recorded a pre-tax, non-cash loss on impairment in the second quarter of 2022 of $34.5 million. Additional costs were recorded for penalties and other costs incurred upon cancellation of equipment ordered. See "Note 4 - Revenue from Contracts with Customers" and "Note 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

(2)Other includes the bareboat charter backlog for the 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.

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The increase in our backlog of $19.3 million is primarily due to recent contract awards and contract extensions, partially offset by the termination of the VALARIS DS-11 contract and revenues realized. As revenues are realized and if we experience customer contract cancellations, we may experience declines in backlog, which would result in a decline in revenues and operating cash flows.

The increase in ARO's backlog of $230.7 million is primarily due to contract awards and extensions, including contract awards for VALARIS 76 and 108, which are expected to be leased to ARO following completion of their existing contracts, partially offset by revenues realized.

The following table summarizes our and ARO's contract backlog of business as of February 21, 2023 and the periods in which revenues are expected to be realized (in millions):

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.

Our drilling contracts generally contain provisions permitting early termination of the contract if the rig is lost or destroyed or by the customer if operations are suspended for a specified period of time due to breakdown of major rig equipment, unsatisfactory performance, "force majeure" events beyond the control of either party or other specified conditions.  In addition, our drilling contracts generally permit early termination of the contract by the customer for convenience (without cause), exercisable upon advance notice to us, and in 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.

BUSINESS ENVIRONMENT

Floaters

Starting in 2021, the more constructive oil price environment has led to an improvement in contracting and tendering activity for floaters. The number of contracted benign environment floaters has increased to 115 from a low of 101 in early 2021, contributing to a 10% increase in utilization, from 73% to 83%, for the active fleet over the same period. This increase in activity is particularly evident for drillships. Utilization for the active drillship fleet has been sustained at above 85% for more than twelve months, resulting in a meaningful improvement in day rates for this class of assets. In 2022, we completed the reactivation of three drillships and one semisubmersible which have commenced long-term contracts, and we were awarded an additional long-term contract for one of our stacked drillships that is expected to commence in mid-2023.

Our backlog for our floater segment was $1.4 billion and $1.7 billion as of February 21, 2023 and 2022, respectively. The decrease in our backlog was due to the termination of the VALARIS DS-11 contract, which represented approximately $428 million of backlog, and revenues realized, partially offset by contract awards and contract extensions.

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Utilization for our floaters was 45% during the year ended December 31, 2022, compared to 29% during the year ended December 31, 2021. Average day rates were approximately $213,000 during the year ended December 31, 2022, compared to $193,000 during the year ended December 31, 2021. The increase in average day rate and utilization is primarily due to the four reactivated floaters commencing contracts during 2022.

As of December 31, 2022, the benign environment floater supply declined by 43% to 159 from a peak of 281 in late 2014. Globally, there were 17 newbuild drillships and benign environment semisubmersible rigs reported to be under construction that could increase global supply, of which 13 were scheduled to be delivered before the end of 2023. Most newbuild floaters were uncontracted. Further, with regard to supply, there were 28 benign environment floaters that are either older than 20 years of age and currently idle or have been stacked for more than three years. There were two additional benign environment floaters older than 20 years that have contracts expiring in six months without follow-on work. Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify or reactivate some of these aging rigs may prove cost prohibitive. Drilling contractors may elect to scrap or cold stack a portion of these rigs.

A sustained constructive oil price environment and continued demand for offshore projects or further rationalization of drilling rig supply are necessary to maintain current floater utilization and day rates.

Jackups

Contracting and tendering activity for jackups began to improve during 2021 as a result of the more constructive oil price environment. Further, we have seen a notable increase in jackup activity in 2022, primarily driven by demand from the Middle East. The number of contracted jackups has increased to 394 from a low of 341 in early 2021, contributing to a 13% increase in utilization, from 78% to 91%, for the active fleet over the same period.

Our backlog for our jackup segment was $742.3 million and $643.0 million as of February 21, 2023 and 2022, respectively. The increase in our backlog was due to contract awards and contract extensions, partially offset by revenues realized.

Utilization for our jackups was 66% during the year ended December 31, 2022, compared to 54% during the year ended December 31, 2021. The increase in utilization is primarily due to the sale of stacked jackups in 2022 and late 2021. Average day rates were approximately $94,000 during the year ended December 31, 2022, compared to approximately $95,000 during the year ended December 31, 2021.

As of December 31, 2022, jackup supply declined by 9% to 493 from a peak of 542 in early 2015. Globally, there were 20 newbuild jackup rigs reported to be under construction that could increase global supply, of which 15 were scheduled to be delivered before the end of 2023. Most newbuild jackups were uncontracted. Further, with regard to supply, there were 79 jackups that are either older than 30 years and currently idle or have been stacked for more than three years. There were a further 17 jackups that are 30 years or older and have contracts expiring within the next six months without follow-on work. Expenditures required to re-certify or reactivate some of these rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold stack these rigs.

A sustained constructive oil price environment and continued demand for offshore projects or further rationalization of drilling rig supply are necessary to maintain jackup utilization and day rates.

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RESULTS OF OPERATIONS

The following table summarizes our Consolidated Results of Operations for the year ended December 31, 2022 (Successor), eight months ended December 31, 2021 (Successor), four months ended April 30, 2021 (Predecessor) and the combined Successor and Predecessor results for the year ended December 31, 2021 (Non-GAAP) (in millions):

(1) We believe that the discussion of our results of operations for the eight months ended December 31, 2021 (Successor) combined with the four months ended April 30, 2021 (Predecessor) provides a more meaningful comparison to the year ended December 31, 2022 (Successor) and is more useful in understanding operational trends. These combined results do not comply with accounting principles generally accepted in the United States of America ("GAAP") and have not been prepared as pro forma results under applicable SEC rules.

Overview

Revenues increased $370.1 million, or 30.0%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to $227.8 million resulting from more operating days in 2022, a $51.0 million fee recognized for the early termination of the VALARIS DS-11 contract in 2022, a $47.2 million increase in amortization of deferred mobilization and capital upgrade revenue, $19.3 million from higher customer reimbursable revenue, and $18.2 million from higher average day rates on certain rigs.

Contract drilling expense increased $315.3 million, or 29.5%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to a $213.2 million increase attributable to rigs that have returned to work upon completion of reactivation projects or after being idle in the prior year period, a $36.8 million increase in the costs for certain claims, a $32.4 million increase in reactivation costs, and a $20.5 million increase in reimbursable costs.

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During 2022 (Successor), we recorded non-cash losses on impairment totaling $34.5 million with respect to customer-specific capital upgrades for VALARIS DS-11 made pursuant to the terms of the drilling contract that was terminated during the second quarter of 2022. During the four months ended April 30, 2021 (Predecessor), we recorded non-cash losses on impairment totaling $756.5 million, with respect to certain assets in our fleet. See "Note 7 - Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Depreciation expense declined $134.5 million, or 59.6%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.

General and administrative expenses declined by $8.0 million or 9.0%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to a change in incentive compensation structure following the Effective Date.

Other income (expense), net, changed from an expense of $3.5 billion in the combined Successor and Predecessor prior year period to income of $187.7 million for the year ended December 31, 2022 (Successor). In the prior year, we recorded $3.6 billion of reorganization costs incurred directly related to the Chapter 11 Cases. In 2022, we recognized a pre-tax gain on sale of property of $141.2 million primarily from the sale of VALARIS 113, VALARIS 114, VALARIS 36 and VALARIS 67 as well as additional proceeds received in 2022 from two rigs sold in prior years as a result of post-sale conditions of those sale agreements. We also recognized non-cash interest income of $14.8 million for the adjustment to the discount resulting from the partial early repayment on our Notes Receivable from ARO and $8.9 million of interest income in 2022 on investments during the period.

Rig Counts, Utilization and Average Day Rates

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

(1)During the first quarter of 2022, we sold VALARIS 67 and leased VALARIS 140 to ARO. During the second quarter of 2022, we sold VALARIS 113 and VALARIS 114. During the third quarter of 2022, we leased VALARIS 141 to ARO.

(2)This represents the jackup rigs leased to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. Rigs leased to ARO operate under contracts with Saudi Aramco. During the first quarter of 2022, VALARIS 140 was leased to ARO. During the second quarter of 2022, we sold VALARIS 36, which was previously leased to ARO. During the third quarter of 2022, VALARIS 141 was leased to ARO.

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

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

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We are a party to contracts whereby we have the option to take delivery of two recently constructed drillships that are not included in the table above. See "Note 14 - Commitments and Contingencies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

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

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

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

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

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

Operating Income by Segment

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

Our onshore support costs included within Contract drilling expenses are not allocated to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in “Reconciling Items." Further, general and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items".

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The full operating results included below for ARO are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO.

Segment information for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor) and the combined Successor and Predecessor results for the year ended December 31, 2021 (Non-GAAP) is as follows (in millions).

Year Ended December 31, 2022 (Successor)

Eight Months Ended December 31, 2021 (Successor)

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Four Months Ended April 30, 2021 (Predecessor)

Combined Year Ended December 31, 2021 (Non-GAAP)

Floaters

Floater revenue increased $330.3 million, or 89%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to $200.2 million resulting from more operating days in 2022, a $51.0 million fee recognized for the early termination of the VALARIS DS-11 contract in 2022, $29.4 million from increased average day rates on certain rigs, $24.5 million from higher customer reimbursable revenue, and a $20.1 million increase in amortization of deferred mobilization and capital upgrade revenue.

Floater contract drilling expense increased $288.8 million, or 81%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to increases of $134.4 million attributable to rigs that have returned to work upon completion of reactivation projects or after being idle in the prior year period, $82.4 million in reactivation costs, $30.6 million in the costs for certain claims, $24.7 million in reimbursable costs, and $13.1 million in repair cost for certain rigs.

During 2022 (Successor), we recorded non-cash losses on impairment totaling $34.5 million, with respect to customer-specific capital upgrades for VALARIS DS-11 made pursuant to the terms of the drilling contract that was terminated during the second quarter of 2022. During the four months ended April 30, 2021 (Predecessor), we recorded a non-cash loss on impairment totaling $756.5 million with respect to certain assets in our Floater segment.

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See "Note 7 -Property and Equipment" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

Floater depreciation expense declined $53.1 million, or 52%, for the year ended December 31, 2022 (Successor), as compared to the combined Successor and Predecessor prior year period, primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.

Jackups

Jackup revenues increased $24.7 million, or 3%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to increases of $29.8 million in amortization of deferred mobilization and capital upgrade revenue and $27.6 million resulting from more operating days in 2022. These increases were partially offset by a decrease of $25.5 million from average day rates on certain rigs and a decrease of $10.0 million from lower customer reimbursable revenue.

Jackup contract drilling expense remained consistent, declining only $1.3 million, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to a $49.6 million decrease in reactivation costs, a $15.5 million decrease due to rigs which were leased to ARO and a $10.5 million decrease due to rigs which were sold, being offset by a $78.8 million increase in costs attributable to rigs that have returned to work after being idle in the prior year period.

Jackup depreciation expense declined $65.6 million, or 65%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting on the Effective Date.

ARO

ARO currently owns a fleet of seven jackup rigs, leases another eight jackup rigs from us and has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176.0 million. While the shipyard contract contemplated delivery of these newbuild rigs in 2022, the delivery of these rigs has been delayed into 2023. ARO is expected to place orders for two additional newbuild jackups in the near term. The joint venture partners intend for the newbuild jackup rigs to be financed out of available cash from ARO's operations and/or funds available from third-party debt financing. ARO paid a 25% down payment from cash on hand for each of the newbuilds ordered in January 2020 and is actively exploring financing options for the remaining payments due upon delivery. In the event ARO has insufficient cash from operations or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, as delivered on a proportionate basis.

The joint venture partners agreed in the Shareholder Agreement that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs. The initial contracts provided by Saudi Aramco for each 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. As of December 31, 2022, we leased eight rigs to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO. All the jackup rigs leased to ARO are operating under three-year contracts, or related extensions, with Saudi Aramco. All seven ARO-owned jackup rigs are currently operating under long-term contracts with Saudi Aramco. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on ARO and related arrangements.

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The operating revenues of ARO reflect revenues earned under drilling contracts with Saudi Aramco for the seven ARO-owned jackup rigs and the rigs leased from us. Contract drilling expenses are inclusive of the bareboat charter fees for the rigs leased from us.

Revenue for the year ended December 31, 2022 decreased $11.1 million or 2% as compared to the prior year primarily due to a $51.0 million decrease from three rigs which operated in the prior year period completing their contracts in 2021 or 2022. This decrease was partially offset by a $32.5 million increase from VALARIS 140 and VALARIS 141, which were leased to ARO and commenced drilling operations during 2022, and a $6.7 million increase due to lower temporary suspension or planned maintenance days for certain rigs in 2022 as compared to the prior year period.

Contract drilling expense for the year ended December 31, 2022, decreased $20.5 million or 6% as compared to the prior year primarily due to a decrease in bareboat charter lease expense of $12.9 million, primarily as a result of fewer rigs leased from us during 2022, a $5.0 million decrease in personnel cost, and a $4.4 million decrease in repairs and maintenance cost for certain rigs.

Other

Other revenues increased $15.1 million, or 11%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to an increase of $14.3 million from average day rates on certain rigs.

Other contract drilling expenses increased $17.6 million, or 30%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to a $8.6 million increase in costs for certain claims, a $4.9 million increase in personnel costs and a $4.4 million increase in reimbursable costs.

Depreciation expense declined $13.0 million, or 74%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to the reduction in the values of property and equipment from the application of fresh start accounting on the Effective Date.

Other Income (Expense), Net

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

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Net gains on the sale of property of $141.2 million were recognized in 2022 primarily related to the sales of VALARIS 113, VALARIS 114, VALARIS 36 and VALARIS 67 as well as additional proceeds received from two rigs sold in prior years as a result of post-sale conditions of those sale agreements.

Interest income increased by $33.4 million or 104% for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period primarily due to non-cash interest income of $14.8 million recognized in the third quarter of 2022 for the discount attributable to the partial repayment on our Notes Receivable from ARO and due to incremental amortization as the discount was amortized for eight months in the combined prior year period as opposed to twelve months in 2022. Further, we recognized $8.9 million of interest income in 2022 on investments during the period.

Interest expense, net increased by $11.9 million, or 36%, for the year ended December 31, 2022 (Successor) as compared to the combined Successor and Predecessor prior year period, primarily due to our First Lien Notes which were outstanding for eight months in the combined prior year period as compared to twelve months in 2022.

Reorganization items, net of $3.6 billion for the combined Successor and Predecessor prior year period were recognized related to legal and other professional advisory service fees pertaining to the Chapter 11 Cases, contract items related to rejecting certain operating leases and the effects of the emergence from bankruptcy; including the application of fresh start accounting.

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

Net foreign currency exchange gains of $12.2 million for the year ended December 31, 2022 (Successor) primarily included gains of $7.2 million, $1.9 million and $1.7 million related to euros, Egyptian pounds and Norwegian kroner, respectively. Net foreign currency exchange gains of $21.5 million for the combined Successor and Predecessor prior year period primarily included $11.7 million and $8.8 million related to Libyan dinar and euros, respectively.

Provision for Income Taxes

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

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

Our drilling rigs frequently move from one taxing jurisdiction to another to perform contract drilling services. In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries. As a result of frequent changes in the taxing jurisdictions in

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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.

Effective Tax Rate

During the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), we recorded an income tax expense of $43.1 million, $36.4 million and $16.2 million, respectively. Our consolidated effective income tax rates during the same periods were 19.2%, 284.4%, and (0.4)%, respectively.

Our 2022 consolidated effective income tax rate includes $10.3 million associated with the impact of various discrete items, including a $17.2 million income tax benefit associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset primarily by tax expense attributable to income associated with a contract termination.

Our eight months ended December 31, 2021 (Successor) consolidated effective income tax rate includes $14.3 million associated with the impact of various discrete items, including $29.7 million income tax expense associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset by $15.4 million of tax benefit related to deferred taxes associated with Switzerland tax reform. Our four months ended April 30, 2021 (Predecessor) consolidated effective income tax rate included $2.2 million associated with the impact of various discrete items, including $21.5 million of income tax expense associated with changes in liabilities for unrecognized tax benefits and resolution of other prior period tax matters, offset by $19.3 million of tax benefit related to fresh start accounting adjustments.

Excluding the impact of the aforementioned discrete tax items, our consolidated effective income rates for the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) were 73.6%, 213.9%, and (12.9)%, respectively. The changes in our consolidated effective income tax rate excluding discrete tax items during the three-year period result primarily from changes in the relative components of our earnings from the various taxing jurisdictions in which our drilling rigs are operated and/or owned and differences in tax rates in such taxing jurisdictions.

Divestitures

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 nine jackup rigs during the two-year period ended December 31, 2022.

We continue to focus on our fleet management strategy in light of the composition of our rig fleet. While taking into account certain restrictions on the sales of assets under our Indenture, as part of our strategy, we may act opportunistically from time to time to monetize assets to enhance stakeholder value and improve our liquidity profile, in addition to reducing holding costs by selling or disposing of lower-specification or non-core rigs.

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We sold the following rigs during the year ended December 31, 2022 (Successor), the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) (in millions):

(1)Classification denotes the location of the operating results and gain on sale for each rig in our Consolidated Statements of Operations.

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LIQUIDITY AND CAPITAL RESOURCES

Liquidity

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

As of December 31, 2022 and 2021 (Successor), our cash and cash equivalents were $724.1 million and $608.7 million, respectively. We have no debt principal payments due until 2028. See "Note 8 - Debt" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the First Lien Notes.

Cash Flows and Capital Expenditures

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

During the year ended December 31, 2022 (Successor), our other primary sources of cash were proceeds of $150.3 million for the disposition of assets and $40.0 million from the partial early repayment of the Notes Receivable from ARO. For the same period, our cash provided by operating activities of $127.5 million related primarily to improving margins and the collection of $54.8 million for certain tax receivables.

In the second quarter of 2022, our customer terminated an eight-well contract for the VALARIS DS-11 and as a result, we recorded an early termination fee of $51.0 million that was collected in July 2022. As of the date of termination, we had incurred costs to upgrade the rig pursuant to the requirements of the contract, including $34.5 million of capital costs which were considered to be impaired. Additional costs were recorded for penalties and other costs incurred upon cancellation of equipment ordered.

During the eight months ended December 31, 2021 (Successor), our primary source of cash was proceeds of $25.1 million for the disposition of assets. For the same period, our uses of cash in operating activities of $26.2 million primarily relates to reorganization costs and interest payments on the First Lien Notes. During the four months ended April 30, 2021 (Predecessor), our primary sources of cash were $520.0 million from the issuance of the First Lien Notes and proceeds of $30.1 million for the disposition of assets. For the same period, our uses of cash in operating activities of $39.8 million primarily related to declining margins and reorganization costs.

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

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

Based on our current projections, we expect capital expenditures during 2023 to approximate $260 million to $300 million. This includes approximately $120 million to $130 million for capital maintenance projects and approximately $140 million to $170 million for rig enhancements and upgrades, including approximately $80 million to $90 million for rig reactivation and associated contract-specific capital expenditures. If we exercise our options to take delivery of VALARIS DS-13 for $119.1 million and/or VALARIS DS-14 for $218.3 million on the delivery date of December 31, 2023, our capital expenditures would be higher by the respective purchase prices. Depending on market conditions, contracting activity and future opportunities, we may reactivate additional rigs or make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.

As we reactivated rigs in 2022, spending levels increased beyond the levels we incurred in 2021, with more spending associated with reactivation of our floater fleet relative to our jackup fleet. In 2022, the cost and duration of reactivations increased relative to those in 2021 as a result of the rising costs of labor and materials, the depletion of spares from our initial reactivation projects and as the rigs reactivated had been preservation stacked for longer periods of time. Future reactivations could be subject to further increases in the cost of labor and materials and could take longer due to increased lead times for parts and supplies.

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

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Financing and Capital Resources

Successor First Lien Notes Indenture

On the Effective Date, in accordance with the plan of reorganization and Backstop Commitment Agreement, dated August 18, 2020 (as amended, the "BCA"), the Company consummated the rights offering of the First Lien Notes and associated Common Shares in an aggregate principal amount of $550.0 million. In accordance with the BCA, certain holders of senior notes claims and certain holders of claims under the Revolving Credit Facility who provided backstop commitments received the backstop premium in an aggregate amount equal to $50.0 million in First Lien Notes and 2.7% of the Common Shares on the Effective Date. The Debtors paid a commitment fee of $20.0 million, in cash prior to the Petition Date, which was loaned back to the reorganized company upon emergence. Therefore, upon emergence the Debtors received $520.0 million in cash in exchange for a $550.0 million note, which includes the backstop premium. See “Note 2 – Chapter 11 Proceedings” to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.

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

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

The First Lien Notes are scheduled to mature on April 30, 2028. Interest on the First Lien Notes accrues, at our option, at a rate of: (1) 8.25% per annum, payable in cash; (2) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind; or (3) 12% per annum, with the entirety of such interest to be paid in kind. Interest is due semi-annually in arrears on May 1 and November 1 of each year and shall be computed on the basis of a 360-day year of twelve 30-day months.

At any time prior to April 30, 2023, the Company may redeem up to 35% of the aggregate principal amount of the First Lien Notes at a redemption price of 104% up to the net cash proceeds received by the Company from equity offerings provided that at least 65% of the aggregate principal amount of the First Lien Notes remains outstanding and provided that the redemption occurs within 120 days after such equity offering of the Company. At any time prior to April 30, 2023 the Company may redeem the First Lien Notes at a redemption price of 104% of the principal amount plus a “make-whole” premium. On or after April 30, 2023, the Company may redeem all or part of the First Lien Notes at fixed redemption prices (which are expressed as percentages of the principal amount), beginning at 104% on April 30, 2023 and declining each 12-month period thereafter to 100% on and after April 30, 2026, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. Notwithstanding the foregoing, if a Change of Control (as defined in the Indenture, with certain exclusions as provided therein) occurs, the Company will be required to make an offer to repurchase all or any part of each note holder’s notes at a purchase price equal to 101% of the aggregate principal amount of First Lien Notes repurchased, plus accrued and unpaid interest to, but excluding, the applicable date.

The Indenture contains covenants that limit, among other things, the Company's ability and the ability of the guarantors and other restricted subsidiaries, to: (1) incur, assume or guarantee additional indebtedness; (2) pay dividends or distributions on equity interests or redeem or repurchase equity interests; (3) make investments; (4) repay or redeem junior debt; (5) transfer or sell assets; (6) enter into sale and lease back transactions; (7) create, incur or assume liens; and (8) enter into transactions with certain affiliates. These covenants are subject to a number of important limitations and exceptions.

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

The Company incurred $5.2 million in issuance costs in 2021 associated with the First Lien Notes. Also, in August 2022, the Company completed a consent solicitation pursuant to which the Company amended the Indenture to (1) implement a consolidated net income builder basket for restricted payments, increase the general basket for restricted payments from $100.0 million to $175.0 million and make other incremental changes to the Company’s restricted payments capacity and (2) increase the general basket for investments from the greater of $100.0 million and 4.0% of total assets to the greater of $175.0 million and 6.5% of total assets. The Company incurred $3.9 million of costs in connection with the consent solicitation, comprised of a consent fee paid to consenting holders and professional fees. These costs along with the issuance costs incurred in 2021 are being amortized into interest expense over the expected term of the First Lien Notes using the effective interest method.

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 Notes Receivable from ARO and from the distribution of earnings from ARO. The Notes Receivable from ARO, which are governed by the laws of Saudi Arabia, mature during 2027 and 2028. In the event that ARO is unable to repay the Notes Receivable from ARO when they become due, we would require the prior consent of our joint venture partner to enforce ARO’s payment obligations. In September 2022, the Company received a principal payment of $40.0 million from ARO representing a partial early repayment of the Notes Receivable from ARO.

The distribution of earnings to the joint-venture partners is at the discretion of the ARO board of managers, consisting of 50/50 membership of managers appointed by Saudi Aramco and managers appointed by us, with approval required by both shareholders. The timing and amount of any cash distributions to the joint-venture partners cannot be predicted with certainty and will be influenced by various factors, including the liquidity position and long-term capital requirements of ARO. ARO has not made a cash distribution of earnings to its partners since its formation. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements 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, 2022 (Successor) (in millions):

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Contractual Obligations

The following table summarizes our significant contractual obligations as of December 31, 2022 (Successor) and the periods in which such obligations are due (in millions):

(1)Interest on the First Lien Notes accrues, at our option, at a rate of: (1) 8.25% per annum, payable in cash; (2) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind; or (3) 12% per annum, with the entirety of such interest to be paid in kind. Interest in the table above assumes 8.25% per annum of cash interest payments.

(2)Contractual obligations do not include $275.0 million of unrecognized tax benefits, inclusive of interest and penalties, included on our Consolidated Balance Sheet as of December 31, 2022 (Successor).  We are unable to specify with certainty whether we would be required to and in which periods we may be obligated to settle such amounts.

In connection with our 50/50 unconsolidated joint venture, we have a potential obligation to fund ARO for newbuild jackup rigs. ARO has plans to purchase 20 newbuild jackup rigs over an approximate 10-year period. In January 2020, ARO ordered the first two newbuild jackups, each with a shipyard price of $176.0 million. We expect delivery of the rigs in 2023. ARO is expected to place orders for two additional newbuild jackups in the near term. The joint venture partners intend for the newbuild jackup rigs to be financed out of available cash from ARO's operations and/or funds available from third-party debt financing. ARO paid a 25% down payment from cash on hand for each of the newbuilds ordered in January 2020 and is actively exploring financing options for remaining payments due upon delivery. In the event ARO has insufficient cash from operations or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program. Each partner's commitment shall be reduced by the actual cost of each newbuild rig, as delivered on a proportionate basis. See "Note 5 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on our joint venture.

Other Commitments

We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances. As of December 31, 2022 (Successor), we were contingently liable for an aggregate amount of $141.4 million under outstanding letters of credit which guarantee our performance as it relates to our drilling contracts, contract bidding, customs duties, tax appeals and other obligations in various jurisdictions. Obligations under these letters of credit are not normally called, as we typically comply with the underlying performance requirement. As of December 31, 2022 (Successor) , we had collateral deposits in the amount of $20.7 million with respect to these agreements.

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The following table summarizes our other commitments as of December 31, 2022 (in millions):

Tax Assessments

During 2019, the Australian tax authorities issued aggregate tax assessments totaling approximately A$101 million (approximately $68.8 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 $29.0 million at then-current exchange rates) to the Australian tax authorities to litigate the assessment. We have an $17.8 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2022 (Successor). We believe our tax returns are materially correct as filed, and we are vigorously contesting these assessments. Although the outcome of such assessments and related administrative proceedings cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, operating results and cash flows. See "Note 13 - Income Taxes" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for additional information on the tax assessments.

Share Repurchase Program

In September 2022, our board of directors authorized a share repurchase program under which we may purchase up to $100.0 million of our outstanding Common Shares. The share repurchase program does not have a fixed expiration, and may be modified, suspended or discontinued at any time. We are under no obligation to purchase any Common Shares under the share repurchase program. Common Shares may be repurchased under the repurchase program in open market purchases, private-negotiated purchases, through block trades, by effecting a tender offer, by way of accelerated share repurchase transactions or other derivative transactions, through the purchase of call options or the sale of put options, or otherwise, or by any combination of the foregoing. The manner, timing, pricing and amount of any repurchases will be subject to our discretion and may be based upon a number of factors, including market conditions, our earnings, capital requirements, financial conditions, available cash resources and competing uses for cash that may arise in the future, debt agreement restrictions other factors. We did not repurchase any Common Shares during the year ended December 31, 2022 under the repurchase program.

Guarantees of Registered Securities

The First Lien Notes issued by Valaris Limited have been fully and unconditionally guaranteed, jointly and severally, on a senior secured basis, by certain of the direct and indirect subsidiaries (the “Guarantors”) of Valaris Limited under the Indenture governing the First Lien Notes (the “Guarantees”). The First Lien Notes and Guarantees are secured by liens on the collateral, including, among other things, subject to certain agreed security principles, (1) first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by Valaris Limited or any Guarantor and (2) a first-priority perfected lien on substantially all assets of Valaris Limited and each Guarantor, in each case subject to certain exceptions and limitations (collectively, the “Collateral”). We are providing the following information about the Guarantors and the Collateral in compliance with Rules 13-01 and 13-02 of Regulation S-X.

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First Lien Note Guarantees

The Guarantees are joint and several senior secured obligations of each Guarantor and rank equally in right of payment with existing and future senior indebtedness of such Guarantor and effectively senior to such Guarantor’s existing and future indebtedness (1) that is not secured by a lien on the Collateral securing the First Lien Notes, or (2) that is secured by a lien on the Collateral securing the First Lien Notes ranking junior to the liens securing the First Lien Notes. The Guarantees rank effectively junior to such Guarantor’s existing and future secured indebtedness (1) that is secured by a lien on the Collateral that is senior or prior to the lien securing the First Lien Notes, or (2) that is secured by liens on assets that are not part of the Collateral, to the extent of the value of such assets. The Guarantees rank equally with such Guarantor’s existing and future indebtedness that is secured by first-priority liens on the Collateral and senior in right of payment to any existing and future subordinated indebtedness of such Guarantor. The Guarantees are structurally subordinated to all existing and future indebtedness and other liabilities of any non-Guarantors, including trade payables (other than indebtedness and liabilities owed to such Guarantor).

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

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

Pledged Securities of Affiliates

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

The assets, liabilities and results of operations of the combined affiliates whose securities are pledged as collateral are not materially different than the corresponding amounts presented in Valaris Limited's consolidated financial statements, except with respect to (1) approximately $550.1 million of cash held at Valaris Limited and (2) the First Lien Notes and related accrued interest and interest expense. The value of the pledged equity is subject to fluctuations based on factors that include, among other things, general economic conditions and the ability to realize on the Collateral as part of a going concern and in an orderly fashion to available and willing buyers and outside of distressed circumstances. There is no trading market for the pledged equity interests.

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

Summarized Financial Information

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

Summarized Balance Sheet Information:

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Summarized Statement of Operations Information:

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. The United States reentered the Paris Agreement in February 2021. Further, in November 2021, the United States and other countries entered into the Glasgow Climate Pact, which includes a range of measures designed to address climate change, including but not limited to the phase-out of fossil fuel subsidies, reducing methane emissions 30% by 2030, and cooperating toward the advancement of the development of clean energy. It is expected that new executive orders, regulatory action, and/or legislation targeting greenhouse gas emissions, or prohibiting, restricting, or delaying oil and gas development activities in certain areas, will be proposed and/or promulgated. For example, the current presidential administration has issued multiple executive orders pertaining to environmental regulations and climate change, including the (1) Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis (“EO 13990”) and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad (“EO 14008”). EO 13990 established an interagency working group to recommend methods for agencies to incorporate the “social cost of carbon” into regulatory analyses and directed the EPA to review various environmental regulations for consistency with the policies and goals set forth in EO 13990. EO 14008 announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices, established climate change as a primary foreign policy and national security consideration and affirmed that achieving net-zero greenhouse gas emissions by or before mid-century is a critical priority. Ongoing legal challenges have slowed or halted the implementation of such executive orders, and the full impact of these federal actions, or any other future restrictions or prohibitions, remains unclear.

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. Governments have also proposed or implemented new or enhanced disclosure requirements related to climate change matters and GHG emissions that may increase compliance and disclosure costs, such as the SEC’s 2022 proposed rules for a climate change reporting framework.

During 2009, 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. 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

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facilities. Although a number of bills related to climate change have been introduced in the U.S. Congress in the past, comprehensive federal climate legislation has not yet been passed by Congress. If such legislation were to be adopted in the U.S., such legislation could adversely impact many industries. In the absence of federal legislation, almost half of the states have begun to address GHG emissions, primarily through the development or planned development of emission inventories or regional GHG cap and trade programs and commitments to contribute to meeting the goals of the Paris Agreement.

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

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

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

MARKET RISK

Interest Rate Risk

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

Our Notes Receivable from ARO bear interest based on a one-year LIBOR rate, set as of the end of the year prior to the year applicable, plus two percent. As the Notes Receivable from ARO bear interest on the LIBOR rate determined at the end of the preceding year, the rate governing our interest income for 2023 has already been determined. A hypothetical 1% decrease to LIBOR would decrease interest income for the year ended December 31, 2022 (Successor) by $4.0 million based on the principal amount outstanding at December 31, 2022 (Successor) of $402.7 million.

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Foreign Currency Risk

Our functional currency is the U.S. dollar. As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S. dollars; however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S. dollar. We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in the foreign currency or revenue earned differs from costs incurred in the foreign currency. We do not currently hedge our foreign currency risk as our unsecured foreign currency credit lines were terminated in the second quarter of 2020 and our access to other foreign currency credit lines is limited.

CRITICAL ACCOUNTING POLICIES 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. Concurrent with our emergence from bankruptcy, we applied fresh start accounting and elected to change our accounting policies related to property and equipment as well as materials and supplies. See "Note 1 - Description of the Business and Summary of Significant Accounting Policies" and "Note 3 - Fresh Start Accounting" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information. Our significant accounting policies are included in "Note 1 - Description of the Business and Summary of Significant Accounting Policies" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data". 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, income taxes and pension and other post-retirement benefits.

Property and Equipment

Concurrent with our emergence from bankruptcy, we applied fresh start accounting and adjusted the carrying value of our drilling rigs to estimated fair value. See "Note 3 - Fresh Start Accounting" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for more information. As of December 31, 2022 (Successor), the carrying value of our property and equipment totaled $977.2 million, which represented 34% 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.

Upon emergence, we elected to change our accounting policies and have identified the significant components of our drilling rigs and ascribed useful lives based on the expected time until the next required overhaul or the end of the expected economic lives of the components.

The judgments and assumptions used in determining the next overhaul or the economic lives of the components 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

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the establishment of our property and equipment accounting policies, especially those involving the useful lives of the significant components our rigs, would likely result in materially different asset carrying values and operating results.

The useful lives of our drilling rig components 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 rig components 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.

Our fleet of 16 floater rigs represented 50% of both the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2022 (Successor). Our fleet of 36 jackup rigs represented 46% of both the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2022.

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, 2022 (Successor), our Consolidated Balance Sheet included a $39.0 million net deferred income tax asset, a $31.1 million liability for income taxes currently payable and a $275.0 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. 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.

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

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experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future. In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:

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

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

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

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

Pension and Other Postretirement Benefits

Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, annual compensation increases, mortality rates and other factors. Key assumptions at December 31, 2022 (Successor), included (1) a weighted average discount rate of 5.21% to determine pension benefit obligations, (2) a weighted average discount rate of 2.73% to determine net periodic pension cost and (3), an expected long-term rate of return on pension plan assets of 6.26% to determine net periodic pension cost. Upon emergence, our pension and other post retirement plans were remeasured as of the Effective Date. 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.

Using our key assumptions at December 31, 2022 (Successor), a one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $60.1 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 $6.1 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 increased to 7.10% at December 31, 2022 (Successor) from 6.26% at December 31, 2021 (Successor). See "Note 12 - Pension and Other Post Retirement Benefits" to our consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data" for information on our pension and other postretirement benefit plans.

NEW ACCOUNTING PRONOUNCEMENTS

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