What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-02-21 compared with 2022-02-22 · 312 added, 552 removed, 362 unchanged (70% of the section changed)

Management's Discussion and Analysis of Financial Condition and Results of Operations

We are a leading provider of offshore contract drilling services to the international oil and gas industry.

We currently own an offshore drilling rig fleet of 56 rigs, with drilling operations in almost every major offshore market across six continents.

Our rig fleet includes 11 drillships, four dynamically positioned semisubmersible rigs, one moored semisubmersible rig, 40 jackup rigs and a 50% equity interest in ARO, our 50/50 joint venture with Saudi Aramco, which owns an additional seven rigs.

We operate the world's largest fleet amongst competitive rigs, including one of the newest ultra-deepwater fleets in the industry and a leading premium jackup fleet.

Our customers include many of the leading national and international oil companies, in addition to many independent operators.

We are among the most geographically diverse offshore drilling companies, with current operations spanning 14 countries.

The markets in which we operate include the Gulf of Mexico, the North Sea, the Middle East, West Africa, Australia and Southeast Asia.

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.

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.

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.

8 unchanged sentences

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.

Financial Statements and Supplementary Data" for additional

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 the Warrants to purchase Common Shares.

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.

12 unchanged sentences

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.

As we entered 2020, we expected the volatility that began with the oil price decline in 2014 to continue over the near-term with the expectation that long-term oil prices would remain at levels sufficient to support a continued gradual recovery in the demand for offshore drilling services.

We were focused on opportunities to put our rigs to work, manage liquidity, extend our financial runway, and reduce debt as we sought to navigate the extended market downturn and improve our balance sheet.

Recognizing our ability to maintain a sufficient level of liquidity to meet our financial obligations depended upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control, we had significant financial flexibility within our capital structure to support our liability management efforts.

However, starting in early 2020, the COVID-19 pandemic and the response thereto negatively impacted the macro-economic environment and global economy.

Global oil demand fell sharply at the same time global oil supply increased as a result of certain oil producers competing for market share, leading to a supply glut.

As a consequence, the price of Brent crude oil fell from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020.

In response to dramatically reduced oil price expectations, our customers reviewed, and in most cases lowered significantly, their capital expenditure plans in light of revised pricing expectations.

This caused our customers, primarily in the second and third quarters of 2020, to cancel or shorten the duration of many of our drilling contracts, cancel future drilling programs and seek pricing and other contract concessions which led to material operating losses and liquidity constraints for us.

In 2020, the combined effects of the global COVID-19 pandemic, the significant decline in the demand for oil and the substantial surplus in the supply of oil resulted in significantly reduced demand and day rates for offshore drilling provided by the Company and increased uncertainty regarding long-term market conditions.

These events had a significant adverse impact on our current and expected liquidity position and financial runway and led to the filing of the Chapter 11 Cases.

In 2021, Brent crude oil prices increased from approximately $50 per barrel at the beginning of 2021 to nearly $80 per barrel by the end of the year and have subsequently increased to over $90 per barrel in early 2022.

Increased oil prices are due to, among other factors, rebounding demand for hydrocarbons, a measured approach to production increases by OPEC+ members and a focus on cash flow and returns by major exploration and production companies.

The constructive oil price environment led to an improvement in contracting and tendering activity in 2021 as compared to 2020.

Benign floater rig years awarded in 2021 were more than double the amount awarded in 2020.

This increase in activity is particularly evident for drillships with several multi-year contracts awarded and a meaningful improvement in day rates for this class of assets.

Jackup contracting activity also increased in 2021, but at a more modest pace than for floaters;

however, demand for jackups did not decline as significantly in 2020 as it did for floaters.

While the near-term outlook for the offshore drilling industry has improved, particularly for floaters, since the beginning of 2021, the global recovery from the COVID-19 pandemic remains uneven, and there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.

Additionally, the full impact that the pandemic and the volatility of oil prices will have on our results of operations, financial condition, liquidity and cash flows is uncertain due to numerous factors, including the duration and severity of the pandemic, the continued effectiveness of the ongoing vaccine rollout, the general resumption of global economic activity along with the injection of substantial government monetary and fiscal stimulus and the sustainability of the improvements in oil prices and demand in the face of market volatility.

To date, the COVID-19 pandemic has resulted in limited operational downtime.

Our rigs have had to shut down operations while crews are tested and incremental sanitation protocols are implemented and while crew changes have been restricted as replacement crews are quarantined.

We continue to incur additional personnel, housing and logistics costs in order to mitigate the potential impacts of COVID-19 to our operations.

In limited instances, we have been reimbursed for these costs by our customers.

Our operations and business may be subject to further economic disruptions as a result of the spread of COVID-19 among our workforce, the extension or imposition of further public health measures affecting supply chain and logistics, and the impact of the pandemic on key customers, suppliers, and other counterparties.

There can be no assurance that these, or other issues caused by the COVID-19 pandemic, will not materially affect our ability to operate our rigs in the future.

Our contract drilling backlog reflects commitments, represented by signed drilling contracts, and is calculated by multiplying the contracted day rate by the contract period.

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."

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.

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.

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 Condensed Consolidated Statement of Operations.

The earnings from ARO backlog with respect to rigs leased from us will be net of, among other things, payments to us under bareboat charters for those rigs.

1 unchanged sentence

Financial Statements and Supplementary Data" for additional information.

The following table summarizes our and ARO's contract backlog of business as of February 21, 2022 and December 31, 2020 (in millions):

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

February 21, 2023 February 21, 2022

$ 1,376.9 $ 1,665.3

2 unchanged sentences

ARO $ 1,731.8 $ 1,501.1

(1) Approximately $428 million of backlog as of February 21, 2022 is attributable to our contract awarded to VALARIS DS-11 for an eight-well contract for a deepwater project in the U.S.

Gulf of Mexico expected to commence in mid-2024.

In February 2022, the customer decided not to sanction and therefore withdraw from the project associated with this contract.

As of the date hereof, the customer has not terminated the contract, but may do so upon the payment of an early termination fee should the project not receive a final investment decision (FID).

The project has not received FID.

We are in discussions with the customer and its partner on the project to determine next steps.

(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.

The increase in our backlog of $1.4 billion is due to recent contract awards and contract extensions, partially offset by revenues realized.

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 $1.2 billion is primarily due to contracts awarded to seven ARO owned rigs during 2021 and four rigs leased from us to ARO, partially offset by revenues realized.

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):

2022 2023 2024

2023 2024 2025 and beyond Total

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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.

See "Item 1A.

Risk Factors - Our current backlog of contract drilling revenue may not be fully realized and may decline significantly in the future, which may have a material adverse effect on our financial position, results of operations and cash flows” and “Item 1A.

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

BUSINESS ENVIRONMENT

Limited demand and excess supply continue to affect our floater fleet.

Floater demand declined materially in March and April 2020, as our customers reduced capital expenditures particularly for capital-intensive, long-lead deepwater projects in the wake of oil price declines from around $60 per barrel at year-end 2019 to around $20 per barrel in mid-April 2020.

This caused our customers, primarily in the second and third quarters of 2020, to cancel or delay drilling programs, to terminate drilling contracts and to request contract concessions.

As discussed above, the more constructive oil price environment led to an improvement in contracting and tendering activity in 2021 as compared to 2020.

However, the global recovery from the COVID-19 pandemic remains uneven, and there is still uncertainty around the sustainability of the improvement in oil prices and the recovery in demand for offshore drilling services.

Our backlog for our floater segment was $1.7 billion (including approximately $428 million for the VALARIS DS-11 discussed above) and $163.7 million as of February 21, 2022 and December 31, 2020, respectively.

The increase in our backlog was due to new contract awards and contract extensions, partially offset by revenues realized.

A majority of these awards were executed at the end of 2021 for contracts expected to commence in 2022.

As a result, we expect utilization and day rates to improve upon those of 2020 and 2021.

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.

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 $193,000 and $192,000 during the years ended December 31, 2021 and 2020, respectively.

Globally, there are 20 newbuild drillships and benign environment semisubmersible rigs reported to be under construction, of which 6 are scheduled to be delivered before the end of 2022.

Most newbuild floaters are uncontracted.

Several newbuild deliveries have been delayed into future years, and more uncontracted newbuilds may be delayed or cancelled.

Drilling contractors have retired 134 benign environment floaters since the beginning of 2014.

Seven benign environment floaters older than 20 years of age are currently idle, five additional benign environment floaters older than 20 years have contracts that will expire within six months without follow-on work, and there are a further 13 benign environment floaters that have been stacked for more than three years.

Operating costs associated with keeping these rigs idle as well as expenditures required to re-certify some of these aging rigs may prove cost prohibitive.

Drilling contractors will likely elect to scrap or cold-stack a portion of these rigs.

Continued improvements in demand and/or reductions in supply are necessary to maintain the improving utilization and day rate trajectory.

During 2020, demand for jackups declined in light of increased market uncertainty.

This caused our customers, primarily in the second and third quarters of 2020, to cancel or delay drilling programs, to terminate drilling contracts and to request contract concessions.

We have observed a slight increase in customer tendering activity for jackups that commenced in the latter part of 2020.

Our backlog for our jackup segment was $643.0 million and $737.6 million as of February 21, 2022 and December 31, 2020, respectively.

The decrease in our backlog was due to customer contract cancellations, customer concessions and revenues realized, partially offset by the addition of backlog from new contract awards and contract extensions.

Utilization for our jackups was 54% during the years ended December 31, 2021 and 2020.

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.

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.

Globally, there are 29 newbuild jackup rigs reported to be under construction, of which 18 are scheduled to be delivered before the end of 2022.

Most newbuild jackups are uncontracted.

Over the past year, some jackup orders have been cancelled, and many newbuild jackups have been delayed.

We expect that scheduled jackup deliveries will continue to be delayed until more rigs are contracted.

Drilling contractors have retired 161 jackups since the beginning of the downturn.

There are 63 jackups older than 30 years which are idle, 21 jackups that are 30 years or older have contracts expiring within the next six months without follow-on work, and there are a further 15 jackups that have been stacked for more than three years.

Expenditures required to re-certify some of these aging rigs may prove cost prohibitive and drilling contractors may instead elect to scrap or cold-stack these rigs.

We expect jackup scrapping and cold-stacking to continue in 2022.

Improvements in demand and/or reductions in supply will be necessary before meaningful and sustained increases in utilization and day rates are realized.

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.

RESULTS OF OPERATIONS

In analyzing our results of operations, we are not able to compare the results of operations for the four-month period ended April 30, 2021 (the “2021 Predecessor Period”) to any of the previous periods reported in the consolidated financial statements, and we do not believe reviewing this period in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance.

With the exception of certain one-time charges as separately described below, we believe that the discussion of our results of operations for the eight months ended December 31, 2021 (the “Successor Period”) combined with the 2021 Predecessor Period provides a more meaningful comparison to the year ended December 31, 2020 and is more useful in understanding operational trends.

These combined results do not comply with GAAP and have not been prepared as pro forma results under applicable SEC rules, but are presented because we believe they provide the most meaningful comparison of our results to prior periods.

The following table summarizes our Consolidated Results of Operations (in millions):

Successor Predecessor Combined (Non-GAAP) Predecessor

Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019

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):

Successor Predecessor Combined (Non-GAAP)(1)

Year Ended December 31, 2022 Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2021

Revenues $ 1,602.5 $ 835.0 $ 397.4 $ 1,232.4

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Total operating expenses 1,589.8 848.4 1,290.6 2,139.0

Other operating income — — — 118.1 —

Equity in earnings (losses) of ARO 6.1 3.1 9.2 (7.8) (12.6)

Operating loss (11.9) (890.1) (902.0) (4,334.5) (669.8)

Equity in earnings of ARO 24.5 6.1 3.1 9.2

Operating income (loss) 37.2 (7.3) (890.1) (897.4)

Other income (expense), net 187.7 20.1 (3,557.5) (3,537.4)

Provision (benefit) for income taxes 37.4 16.2 53.6 (259.4) 128.4

Net loss (29.2) (4,463.8) (4,493.0) (4,857.6) (192.2)

Net (income) loss attributable to noncontrolling interests (3.8) (3.2) (7.0) 2.1 (5.8)

Net loss attributable to Valaris $ (33.0) $ (4,467.0) $ (4,500.0) $ (4,855.5) $ (198.0)

Year Ended December 31, 2021

Revenues declined $194.8 million, or 13.6%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year.

This decline is primarily due to $199.8 million resulting from fewer operating days in the current year, $46.3 million due to termination fees received for certain rigs in the prior year period and $19.0 million due to lower revenues earned under an agreement to provide certain Rowan employees through secondment arrangements to assist with various onshore and offshore services for the benefit of ARO (the "Secondment Agreement").

See " Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

This decline was partially offset by a $111.2 million increase in revenue for certain rigs with higher average day rates in the combined Successor and Predecessor revenues as a result of suspension periods at lower rates in the prior year.

Contract drilling expense declined $397.9 million, or 27.1%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year.

This decline is primarily due to $279.8 million of lower costs for idle rigs, $77.8 million from rigs sold between the comparative periods, a $26.5 million reduction in costs related to contract preparation projects in 2020 and approximately $40.0 million of lower costs due to spend control efforts.

Additionally, there was a decline of $19.0 million related to the Secondment Agreement with ARO as almost all remaining seconded employees became employees of ARO during the second quarter of 2020.

This decrease was partially offset by an increase of $84.4 million in reactivation costs for c ertain rigs stacked in the prior year.

During the 2021 Predecessor Period, we recorded non-cash losses on impairment totaling $756.5 million with respect to certain assets in our fleet.

During the first and second quarters of 2020 (Predecessor), we recorded non-cash losses on impairment totaling $3.6 billion, with respect to assets in our fleet, primarily due to the adverse change in the current and anticipated market for these assets.

See " Note 8 - Property and Equipment" for additional information.

Depreciation expense declined $315.1 million, or 58.3%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to lower depreciation resulting from the reduction in values of property and equipment from the application of fresh start accounting and lower depreciation due to the impairment of certain non-core assets in 2020 and the first quarter of 2021.

Certain of the assets impaired in the first and second quarters of 2020 were also sold during that year.

General and administrative expenses decreased by $125.7 million or 59%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to charges incurred in the prior year for professional fees incurred in relation to the Chapter 11 Cases prior to the Petition Date, professional fees associated with shareholder activism defense, organizational change initiatives, as well as merger integration related costs.

This decline is partially offset by executive severance cost incurred in the Successor Period in connection with the separations of certain former members of executive management.

Other operating income decrease of $118.1 million was due to loss of hire insurance recoveries collected for the VALARIS DS-8 during the year ended December 31, 2020.

Other expense, net, includes reorganization expenses of $15.5 million, $3.6 billion and $527.6 million in the Successor Period, the 2021 Predecessor Period and the year ended December 31, 2020, respectively, for costs incurred as a direct result of the Chapter 11 Cases.

Other expense, net, also includes interest expense of $31.0 million, $2.4 million and $291.9 million in the Successor Period, the 2021 Predecessor Period and the year ended December 31, 2020, respectively.

The decrease in interest expense in the Successor Period results from our lower debt level following emergence from chapter 11.

See “ Note 2 – Chapter 11 Proceedings” for details related to reorganization items as well as changes in our debt and related interest .

Year Ended December 31, 2020 (Predecessor)

Revenues declined by $626.0 million, or 30%, as compared to the prior year.

This decline is primarily attributable to a $287.4 million decline in revenue resulting from the sale of VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88, and VALARIS 96, which operated in the prior year comparative period, a $286.7 million decline in revenue as a result of fewer days under contract across our fleet, a $150.0 million decline in revenue due to the termination of the VALARIS DS-8 contract and a $28.3 million and $16.0 million decline in revenues earned under the Secondment Agreement and Transition Services Agreement with ARO, respectively.

Further, the additional revenues earned under Lease Agreements with ARO due to the inclusion of a full year of results in 2020 as compared to the period from the date of the combination with Rowan in April 11, 2019 (the "Rowan Transaction") to December 31, 2019 from the comparable period was offset by a reduction of our rental revenues to reflect an amendment to the Shareholder Agreement that impacted the bareboat charter rate in the lease agreements.

See " Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

The decline in revenue was partially offset by $113.6 million of revenue earned by rigs added from the Rowan Transaction, and $46.3 million of contract termination fees received for certain rigs.

Contract drilling expense declined by $337.4 million, or 19%, as compared to the prior year primarily due to a $184.4 million decline as a result of lower costs for idle rigs, $136.4 million lower costs on VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5, VALARIS DS-6, VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88 and VALARIS 96, as these rigs were sold, and reduced costs resulting primarily from spend control efforts.

Additionally, there was a decline in expenses due to a decrease in services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO during the second quarter of 2020.

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

During the year ended December 31, 2020 (Predecessor), we recorded non-cash losses on impairment totaling $3.6 billion, with respect to assets in our fleet, primarily due to the adverse change in the current and anticipated market for these assets.

Provision for income taxes 43.1 36.4 16.2 52.6

Net income (loss) 181.8 (23.6) (4,463.8) (4,487.4)

Net income attributable to noncontrolling interests (5.3) (3.8) (3.2) (7.0)

Net income (loss) attributable to Valaris $ 176.5 $ (27.4) $ (4,467.0) $ (4,494.4)

(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.

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.

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 by $68.9 million, or 11%, as compared to the prior year primarily due to lower depreciation expense on certain assets which were impaired during the first and second quarters of 2020, some of which were subsequently sold in the third and fourth quarters of 2020.

This decrease was partially offset by depreciation expense recorded for rigs added in the Rowan Transaction as well as for the VALARIS 123 which commenced operations in August 2019.

General and administrative expenses increased by $25.7 million, or 14%, as compared to the prior year primarily due to the backstop commitment fee and legal and other professional advisor fees incurred in relation to the Chapter 11 Cases, but prior to the Petition Date.

This increase was partially offset by merger related costs incurred in the prior year comparative period.

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

Other expense, net, increased by $1.4 billion as compared to the prior year, primarily due to the prior period $637.0 million gain on bargain purchase recognized in connection with the Rowan Transaction, pre-tax gain related to the settlement award from the SHI matter of $200.0 million and $194.1 million of pre-tax gain on debt extinguishment related to the repurchase of senior notes in connection with July 2019 tender offers.

Additionally, the current year period includes $527.6 million of reorganization items directly related to the Chapter 11 Cases.

Partially offsetting these increases, our Interest Expense, net decreased $137.7 million primarily due to a $140.7 million reduction as we discontinued accruing interest on our outstanding debt subsequent to the chapter 11 filing.

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 offshore drilling rigs by reportable segment, rigs held-for-sale and ARO's offshore drilling rigs as of December 31, 2021 (Successor), 2020 (Predecessor) and 2019 (Predecessor):

2021 2020 2019

Held-for-sale (4)

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

Floaters 16 16

Total Valaris 52 56

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

(2) During 2021, we sold VALARIS 100, VALARIS 101, VALARIS 142.

During 2020, we sold VALARIS 71, VALARIS 84, VALARIS 87, VALARIS 88 and VALARIS 105.

(3) This represents the rigs leased to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO.

All jackup rigs leased to ARO are under three-year contracts with Saudi Aramco.

During 2021, we sold VALARIS 37 and VALARIS 22, which were previously leased to ARO.

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

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

(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.

We are a party to contracts whereby we have the option to take delivery of two drillships, VALARIS DS-13 and VALARIS DS-14, that are not included in the table above.

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

The first of these newbuild rigs is expected to be delivered in the fourth quarter of 2022 with the second rig expected either late in the fourth quarter of 2022 or in the first quarter of 2023.

The following table summarizes our and ARO's rig utilization and average day rates by reportable segment for each of the years in the three-year period ended December 31, 2021.

Rig utilization and average day rates include results of rigs added in the Rowan Transaction or ARO from the date the Rowan Transaction closed in April 2019:

2021 2020 2019

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:

Rig Utilization (1)

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Jackups 66% 54%

100% 98% 100%

Total Valaris 66% 55%

ARO 87% 89% 93%

Average Day Rates (3)

6 unchanged sentences

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.

Beginning in 2021, our method for calculating rig utilization has been updated to remove the impact of suspension periods.

To the extent applicable, comparative period calculations have been retroactively adjusted.

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

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, demobilizations and shipyard contracts.

Beginning in 2021, our method for calculating average day rates has been updated to remove the impact of suspension periods.

To the extent applicable, comparative period calculations have been retroactively adjusted.

Operating Income by Segment

Our business consists of four operating segments:

(1) Floaters, which includes our drillships and semisubmersible rigs, (2) Jackups, (3) ARO and (4) Other, which consists of management services on rigs owned by third-parties and the activities associated with our arrangements with ARO under the Rig Lease Agreements, the Secondment Agreement and the Transition Services Agreement.

(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.

Upon emergence, we ceased allocation of our onshore support costs included within contract drilling expenses to our operating segments for purposes of measuring segment operating income (loss) and as such, those costs are included in “Reconciling Items”.

We have adjusted the historical periods to conform with current period presentation.

Further, general and administrative expense and depreciation expense incurred by our corporate office are not allocated to our operating segments for purposes of measuring segment operating income (loss) and are included in "Reconciling Items".

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

The full operating results included below for ARO (representing only results of ARO from the closing date of the Rowan Transaction) are not included within our consolidated results and thus deducted under "Reconciling Items" and replaced with our equity in earnings of ARO.

Upon establishment of ARO, Rowan entered into (1) an agreement to provide certain back-office services for a period of time until ARO develops its own infrastructure (the "Transition Services Agreement"), and (2) the Secondment Agreement.

These agreements remained in place subsequent to the Rowan Transaction.

Pursuant to these agreements, we or our seconded employees provide various services to ARO, and in return, ARO provides remuneration for those services.

During the quarter ended June 30, 2020, almost all remaining employees seconded to ARO became employees of ARO.

Further, our services to ARO under the Transition Services Agreement were completed as of December 31, 2020.

See " Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information on ARO and related arrangements.

Segment information for the eight months ended December 31, 2021 (Successor), the four months ended April 30, 2021 (Predecessor), the years ended December 31, 2020 and 2019 (Predecessor), respectively are presented below (in millions).

Eight Months Ended December 31, 2021 (Successor)

Floaters Jackups ARO Other Reconciling Items Consolidated Total

Revenues $ 254.5 $ 487.1 $ 307.1 $ 93.4 $ (307.1) $ 835.0

Operating expenses

Contract drilling

(exclusive of depreciation) 250.7 365.2 246.2 38.9 (172.3) 728.7

Depreciation 31.0 32.0 44.2 2.8 (43.9) 66.1

General and administrative — — 13.6 — 44.6 58.2

Equity in earnings of ARO — — — — 6.1 6.1

Operating income (loss) $ (27.2) $ 89.9 $ 3.1 $ 51.7 $ (129.4) $ (11.9)

Four Months Ended April 30, 2021 (Predecessor)

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".

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)

Floaters Jackups ARO Other Reconciling Items Consolidated Total

6 unchanged sentences

General and administrative — — 18.7 — 62.2 80.9

Equity in losses of ARO — — — — 3.1 3.1

Equity in earnings of ARO — — — — 24.5 24.5

Operating income (loss) $ (30.0) $ 169.2 $ 35.6 $ 76.8 $ (214.4) $ 37.2

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

Eight Months Ended December 31, 2021 (Successor)

Floaters Jackups ARO Other Reconciling Items Consolidated Total

3 unchanged sentences

(exclusive of depreciation) 250.7 365.2 246.2 38.9 (176.9) 724.1

Loss on impairment 756.5 — — — — 756.5

Depreciation 31.0 32.0 44.2 2.8 (43.9) 66.1

2 unchanged sentences

Operating income (loss) $ (27.2) $ 89.9 $ 3.1 $ 51.7 $ (124.8) $ (7.3)

Year Ended December 31, 2020 (Predecessor)

Four Months Ended April 30, 2021 (Predecessor)

Floaters Jackups ARO Other Reconciling Items Consolidated Total

6 unchanged sentences

General and administrative — — 4.2 — 26.5 30.7

Other operating income 118.1 — — — — 118.1

Equity in losses of ARO — — — — (7.8) (7.8)

Equity in earnings of ARO — — — — 3.1 3.1

Operating income (loss) $ (819.4) $ (12.3) $ 22.2 $ 14.6 $ (95.2) $ (890.1)

Year Ended December 31, 2019 (Predecessor)

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

Floaters Jackups ARO Other Reconciling Items Consolidated Total

6 unchanged sentences

General and administrative — — 17.8 — 71.1 88.9

Equity in losses of ARO — — — — (12.6) (12.6)

Equity in earnings of ARO — — — — 9.2 9.2

Operating income (loss) $ (846.6) $ 77.6 $ 25.3 $ 66.3 $ (220.0) $ (897.4)

2021 compared to 2020

Floater revenue declined $135.6 million, or 27%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to $121.0 million resulting from fewer operating days in the current year and $46.3 million due to termination fees received for certain rigs in the prior year.

This decline was partially offset by a $45.9 million increase in revenue from certain rigs with higher average day rates in the combined Successor and Predecessor revenues as a result of suspension periods at lower rates in the prior year.

Floater contract drilling expense declined $208.9 million, or 37%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year.

This decline is primarily due to $190.8 million as a result of lower costs for idle rigs in addition to lower costs of $31.4 million from rigs sold between the comparative periods.

This decrease was partially offset by an increase of $35.1 million in reactivation cost for c ertain rigs stacked in the prior year.

During the 2021 Predecessor Period, we recorded a non-cash loss on impairment totaling $756.5 million with respect to certain assets in our Floater segment.

During 2020, we recorded a non-cash loss on impairment of $3.4 billion, with respect to assets in our Floater segment due to the adverse change in the current and anticipated market for these assets.

See " Note 8 -Property and Equipment" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

Floater depreciation expense declined $159.7 million, or 61%, for the combined Successor and Predecessor results for the year ended December 31, 2021, as compared to the prior year period, primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting and lower depreciation due to impairment of certain non-core assets in 2020 and the first quarter of 2021.

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

2020 compared to 2019 (Predecessor)

During 2020, revenues declined by $508.6 million, or 50%, as compared to the prior year due to $241.0 million from the sale of VALARIS 5004, VALARIS 5006, and VALARIS 6002, which operated in the prior year comparative period, $189.4 million as a result of fewer days under contract across the floater fleet and $150.0 million due to the termination of the VALARIS DS-8 contract.

This decline was partially offset by $46.3 million of contract termination fees received for certain rigs and $40.1 million earned by rigs added in the Rowan Transaction.

Contract drilling expense declined by $218.9 million, or 28%, as compared to the prior year primarily due to $131.1 million lower cost on idle rigs, $93.2 million lower costs on VALARIS 5004, VALARIS 5006, VALARIS 6002, VALARIS 8500, VALARIS 8501, VALARIS 8502, VALARIS 8504, VALARIS DS-3, VALARIS DS-5 and VALARIS DS-6, as such rigs were sold, and reduced costs resulting primarily from spend control efforts.

This decrease was partially offset by $53.8 million of contract drilling expense incurred by rigs added in the Rowan Transaction.

During 2020, we recorded a non-cash loss on impairment of $3.4 billion, with respect to assets in our Floater segment due to the adverse change in the current and anticipated market for these assets.

See " Note 8 -Property and Equipment" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

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

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

2021 compared to 2020

Jackup revenues declined $45.8 million, or 6%, for the combined Successor and Predecessor results for the year ended December 31, 2021, as compared to the prior year, primarily due to declines of $80.1 million resulting from fewer operating days in the current year.

This decline was partially offset by a $71.4 million increase in revenue for certain rigs with higher average day rates in the combined Successor and Predecessor revenues as a result of suspension periods at lower rates in the prior year.

Jackup contract drilling expense declined $119.3 million, or 18%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year.

This decline was primarily due to $89.0 million of lower costs for idle rigs, $46.4 million from rigs sold between the comparative periods and $26.5 million in reduced costs for contract preparation projects in 2020.

This decrease was partially offset by an increase of $49.3 million in reactivation costs for certain rigs stacked in the prior year.

Jackup depreciation expense declined $115.5 million, or 53%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily as a result of the reduction in values of property and equipment from the application of fresh start accounting and lower depreciation due to impairments of certain non-core assets in the first and second quarters of 2020.

2020 compared to 2019 (Predecessor)

During 2020, revenues declined by $69.3 million, or 8%, as compared to the prior year primarily due to $97.3 million as a result of fewer days under contract across the jackup fleet and $46.4 million due to the sale of VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88, and VALARIS 96, which operated in the prior year period.

This decrease was partially offset by $73.5 million of revenue earned by rigs added in the Rowan Transaction.

Contract drilling expense declined by $51.8 million, or 7%, as compared to the prior year primarily due to $53.3 million lower cost on idle rigs, $43.2 million from the sale of VALARIS 68, VALARIS 84, VALARIS 87, VALARIS 88 and VALARIS 96 which operated in the prior year period, and reduced costs resulting from spend control efforts.

This decrease was partially offset by $86.3 million of contract drilling expense incurred by rigs added in the Rowan Transaction.

During 2020, we recorded a non-cash loss on impairment of $254.3 million with respect to assets in our Jackup segment primarily due to the adverse change in the current and anticipated market for these assets.

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.

See " Note 7 -Property and Equipment" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

Depreciation expense increased by $13.9 million, or 7%, as compared to the prior year primarily due to the addition of rigs in our combination with Rowan in April 2019 as well as the commencement of operations of the VALARIS 123 in August 2019.

This increase was partially offset by lower depreciation on certain non-core assets which were impaired during 2020 of which three of these jackups were sold in 2020.

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.

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 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.

The first rig is expected to be delivered in the fourth quarter of 2022, and the second rig is expected either late in the fourth quarter of 2022 or in the first quarter of 2023.

ARO is expected to place orders for two additional newbuild jackups later this year.

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.

1 unchanged sentence

In the event ARO has insufficient cash from operations or is unable to obtain third-party financing, each partner may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion from each partner to fund the newbuild program.

Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis.

The joint venture partners agreed that Saudi Aramco, as a customer, will provide drilling contracts to ARO in connection with the acquisition of the newbuild rigs.

The initial contracts for each newbuild rig will be determined using a pricing mechanism that targets a six-year payback period for construction costs on an EBITDA basis.

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.

We lease eight rigs to ARO through bareboat charter agreements whereby substantially all operating costs are incurred by ARO.

Seven jackup rigs leased to ARO are operating under three-year contracts, or related extensions, with Saudi Aramco.

We expect ARO to execute a long-term contract with Saudi Aramco for the remaining leased rig in the first quarter of 2022.

All seven ARO-owned jackup rigs are operating under long-term contracts with Saudi Aramco.

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.

The results of ARO reflect the periods from the date of the Rowan Transaction in April 2019 through December 31, 2021.

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.

Costs incurred under the Secondment Agreement are included in Contract drilling expense and general and administrative, depending on the function to which the seconded employees' services related.

General and administrative expenses include costs incurred under the Transition Services Agreement and other administrative costs.

Services under the Transition Services Agreement were completed as of December 31, 2020.

2021 compared to 2020

Revenue for 2021 decreased $78.8 million or 14% as compared to the prior year primarily due to $56.0 million from lower day rates, as well as, $8.7 million decrease from fewer operating days related to certain rigs for which operations were temporarily suspended or which were undergoing maintenance.

Additionally, a decrease of $9.3 million related to one rig leased to ARO which completed its contract in August 2021.

Contract drilling expense for 2021 decreased $25.9 million or 7% as compared to the prior year primarily due to $17.7 million lower costs for repairs and maintenance and an $8.1 million reduction in expenses related to lower support costs as compared to the prior year.

Depreciation expense for 2021 increased $10.4 million or 19% as compared to the prior year primarily due to capital expenditures.

General and administrative expenses for 2021 decreased $6.4 million or 26% as compared to the prior year, primarily due to a reduction in labor cost, professional fees and services received under the Transition Services Agreement which was completed as of December 31, 2020.

2020 compared to 2019

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

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

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

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

See " Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information on ARO.

2021 compared to 2020

Other revenues declined $13.4 million, or 9%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year, primarily due to $19.0 million of lower revenues earned under the Secondment Agreement, partially offset by a $4.9 million increase in revenue from the Lease Agreements with ARO.

See " Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

Other contract drilling expenses declined $24.0 million, or 29%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year, primarily due to a $19.0 million decrease in cost for services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO during the second quarter of 2020.

Depreciation expense declined $27.2 million, or 61%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to the reduction in the values of property and equipment from the application of fresh start accounting.

2020 compared to 2019 (Predecessor)

Other revenues declined $48.1 million, or 24%, for the year ended December 31, 2020, as compared to the prior year, primarily due to lower revenues earned under the Secondment Agreement and Transition Services Agreement with ARO of $28.3 million and $16.0 million, respectively.

Further, the additional revenues earned under Lease Agreements due to the inclusion of a full year of results in 2020 as compared to the period from April 11, 2019 to December 31, 2019 from the comparable period was offset by a reduction of our rental revenues to reflect an amendment to the Shareholder Agreement that impacted the bareboat charter rate in the lease agreements.

See " Note 6 - Equity Method Investment in ARO" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

Other contract drilling expenses declined $28.2 million, or 25%, for the year ended December 31, 2020, as compared to the prior year, primarily due to a decrease in services provided to ARO under the Secondment Agreement as almost all remaining employees seconded to ARO became employees of ARO during the second quarter of 2020.

During 2020, we recorded a non-cash loss on impairment of $5.7 million, with respect to a certain contract intangible due to current market conditions.

See " Note 5 - Rowan Transaction" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

Depreciation expense increased $19.3 million, or 76%, as compared to the prior year primarily due to the impact of full year results for 2020 as compared to the prior year period from the date of the Rowan Transaction in April 2019 through December 31, 2019 as well as additional depreciation due to capital expenditures and the commencement of the VALARIS 147 and VALARIS 148 which were in the shipyard most of the comparative period.

Impairment of Long-Lived Assets

See " Note 8 - Property and Equipment" and " Note 1 6 - Leases" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for information on impairment of long-lived assets.

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 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):

Successor Predecessor Combined (Non-GAAP) Predecessor

Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019

Successor Predecessor Combined (Non-GAAP)

Year Ended December 31, 2022 Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2021

Net gain on sale of property $ 141.2 $ 21.2 $ 6.0 $ 27.2

Interest income 65.5 28.5 3.6 32.1

Interest expense, net (45.3) (31.0) (2.4) (33.4)

Interest expense (31.0) (2.4) (33.4) (291.9) (449.2)

Capitalized interest — — — 1.3 20.9

(31.0) (2.4) (33.4) (290.6) (428.3)

Net foreign currency exchange gains 12.2 8.1 13.4 21.5

Reorganization items, net (2.4) (15.5) (3,584.6) (3,600.1)

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$ 187.7 $ 20.1 $ (3,557.5) $ (3,537.4)

Interest income increased by $12.4 million or 63% for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to $20.8 million in amortization of the discount on our note receivable from ARO recorded in fresh start accounting.

This increase was partially offset by a $5.8 million decrease due to lower LIBOR rates earned on our note receivable from ARO.

Interest income decreased during 2020 (Predecessor) as compared to 2019 (Predecessor) primarily due to fewer investments.

Interest expense decreased by $258.5 million, or 89%, for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year, primarily due to a $258.7 million decrease in interest cost as a result of our lower debt level following emergence from chapter 11.

Interest expense decreased during 2020 by $157.3 million, or 35%, as compared to the prior year as we did not accrue interest of $140.7 million on our outstanding debt or amortize discounts, premiums and debt issuance costs of $29.8 million subsequent to the chapter 11 filing.

Further, debt repurchases resulted in interest savings of $19.2 million.

These declines were partially offset by increased interest on debt acquired from Rowan totaling $35.7 million.

Interest expense capitalized in the year ended December 31, 2019, was attributable to capital invested in newbuild construction.

Following the delivery of our last newly constructed rig in 2019, capitalized interest declined significantly.

Reorganization items, net of $3.6 billion recognized for the 2021 Predecessor Period, was related to the effects of the emergence from bankruptcy including the application of fresh start accounting, legal and other professional advisory service fees pertaining to the Chapter 11 Cases and contract items related to rejecting certain operating leases.

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

See " Note 2 - Chapter 11 Proceedings" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information.

Other, net, increased by $48.0 million for the combined Successor and Predecessor results for the year ended December 31, 2021 as compared to the prior year primarily due to $32.5 million of net foreign currency exchange gains and losses, as discussed further below, and $15.4 million increase on gain from sale of certain assets.

Other, net, decreased by $990 million during the year ended December 31, 2020 (Predecessor) as compared to the prior year.

Other, net in 2020 (Predecessor) included $14.6 million of net periodic income, excluding service cost, for our pension and retiree medical plans, $11.8 million gain from sale of certain assets, a $3.2 million of net unrealized gains from marketable securities held in our supplemental executive retirement plans ("the SERP") and a $3.1 million pre-tax gain on extinguishment of debt.

We also incurred $11.0 million of losses on net foreign currency exchange, as discussed further below, and had a $6.3 million reduction to gain on bargain purchase as a result of measurement adjustments made in the first quarter 2020 related to the Rowan Transaction.

Other, net in 2019 (Predecessor) included a gain on bargain purchase recognized in connection with the Rowan Transaction of $637.0 million, a pre-tax gain related to the settlement with Samsung Heavy Industries of $200.0 million, a pre-tax gain from debt extinguishment of $194.1 million related to the senior notes repurchased in connection with the July 2019 tender offers, and net unrealized gains of $5.0 million from marketable securities held in our SERP.

During the same period, we also recognized a pre-tax loss of $20.3 million related to settlement of a dispute with a local partner of legacy Ensco plc in the Middle East, and a net foreign currency exchange loss of $7.4 million, as further discussed below.

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 a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than 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.

These transactions are remeasured in U.S.

dollars based on a combination of both current and historical exchange rates.

Net foreign currency exchange gain of $21.5 million, and losses (inclusive of offsetting fair value derivatives) of $11.0 million and $7.4 million, were included in Other, net, in our Consolidated Statements of Operations for the combined Successor and Predecessor results for the year ended December 31, 2021, 2020 (Predecessor) and 2019 (Predecessor), respectively.

Net foreign currency exchange gains for the combined Successor and Predecessor results for the year ended December 31, 2021 primarily included $11.7 million and $8.8 million related to Libyan dinar and euros, respectively.

Net foreign currency exchange losses incurred during 2020 primarily included $7.3 million and $1.4 million related to euros and Angolan kwanza, respectively.

Net foreign currency exchange losses incurred during 2019 included $3.3 million and $2.8 million, related to euros and Angolan kwanza, respectively.

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, the Successor Company and our parent company, is domiciled and resident in Bermuda.

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.

Valaris plc, the Predecessor Company and our former parent company, was domiciled and resident in the U.K.

Legacy Valaris was domiciled and resident in the U.K.

The income of our non-U.K.

6 unchanged sentences

In some instances, the movement of drilling rigs among taxing jurisdictions will involve the transfer of ownership of the drilling rigs among our subsidiaries.

As a result of frequent changes in the taxing jurisdictions in which our drilling rigs are operated and/or owned, changes in profitability levels and changes in tax laws, our annual effective income tax rate may vary substantially from one reporting period to another.

Tax Reform and CARES Act

Tax Cuts and Jobs Act (“U.S.

tax reform”) was enacted on December 22, 2017 and introduced significant changes to U.S.

income tax law, effective January 1, 2018.

Due to the timing of the enactment of U.S.

tax reform and the complexity involved in applying its provisions, the U.S.

Treasury Department continued finalizing rules associated with U.S.

tax reform during 2018 and 2019.

During 2019, we recognized a tax expense of $13.8 million associated with final rules issued related to U.S.

Coronavirus Aid, Relief, and Economic Security Act (the "CARES Act") was enacted on March 27, 2020 and introduced various corporate tax relief measures into law.

Among other things, the CARES Act allows net operating losses ("NOLs") generated in 2018, 2019 and 2020 to be carried back to each of the five preceding years.

During 2020, we recognized a tax benefit of $122.1 million associated with the carryback of NOLs to recover taxes paid in prior years.

As a result of frequent changes in the taxing jurisdictions in

which our drilling rigs are operated and/or owned, changes in profitability levels and changes in tax laws, our annual effective income tax rate may vary substantially from one reporting period to another.

Effective Tax Rate

During the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor), we recorded an income tax expense of $37.4 million and $16.2 million, respectively.

During the year ended December 31, 2020, we recorded an income tax benefit of $259.4 million and during the year ended December 31, 2019, we recorded an income tax expense of $128.4 million, respectively.

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.

Our 2020 consolidated effective income tax rate included a $322.4 million tax benefit associated with the impact of various discrete tax items, including restructuring transactions, impairments of rigs and other assets, implementation of the U.S.

CARES Act, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years, rig sales, reorganization items and the resolution of other prior period tax matters.

Our 2019 consolidated effective income tax rate included $2.3 million associated with the impact of various discrete tax items, including $28.3 million of tax expense associated with final rules relating to U.S.

tax reform, gains on repurchase of debt and settlement proceeds, partially offset by $26.0 million of tax benefit related to restructuring transactions, changes in liabilities for unrecognized tax benefits associated with tax positions taken in prior years and other resolutions of prior year tax matters and rig sales.

Excluding the impact of the aforementioned discrete tax items, our consolidated effective income rates for the eight months ended December 31, 2021 (Successor) and the four months ended April 30, 2021 (Predecessor) were 387.7% and (12.9)%, respectively.

Excluding the impact of the aforementioned discrete tax items, our consolidated effective income tax rates for the years ended December 31, 2020 and 2019 (Predecessor) were (7.6)% and (14.6)%, respectively.

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.

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 16 jackup rigs, five dynamically positioned semisubmersible rigs, two moored semisubmersible rigs and three drillships during the three-year period ended December 31, 2021.

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.

We sold the following rigs during the eight months ended December 31, 2021 (Successor) and the period January 1, 2019 to April 30, 2021 (Predecessor) (in millions):

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):

Rig Date of Sale Segment (1)

Net Proceeds Net Book Value (2)

Pre-tax Gain/(Loss)

Net Proceeds Net Book Value Pre-tax Gain

Year Ended December 31, 2022 (Successor)

VALARIS 36 May 2022 Jackups $ 8.8 $ 0.3 $ 8.5

VALARIS 113 April 2022 Jackups 62.0 2.0 60.0

VALARIS 114 April 2022 Jackups 62.0 2.0 60.0

VALARIS 67 March 2022 Jackups 5.0 3.0 2.0

$ 137.8 $ 7.3 $ 130.5

Eight Months Ended December 31, 2021 (Successor)

VALARIS 37 November 2021 Jackups $ 4.2 $ 0.3 $ 3.9

3 unchanged sentences

$ 24.3 $ 3.6 $ 20.7

Four Months Ended April 30, 2021 (Predecessor)

VALARIS 101 April 2021 Jackups $ 26.4 $ 21.1 $ 5.3

VALARIS 8504 October 2020 Floater 4.7 4.0 0.7

VALARIS 88 October 2020 Jackups 1.4 0.3 1.1

VALARIS 84 October 2020 Jackups 1.2 0.3 0.9

VALARIS 105 September 2020 Jackups 2.1 0.8 1.3

VALARIS DS-6 August 2020 Floaters 5.7 6.1 (0.4)

VALARIS 87 August 2020 Jackups 0.3 0.2 0.1

VALARIS 8500 July 2020 Floaters 4.0 0.7 3.3

VALARIS 8501 July 2020 Floaters 4.0 0.7 3.3

VALARIS 8502 July 2020 Floaters 1.8 0.7 1.1

VALARIS DS-3 July 2020 Floaters 6.1 6.1 —

VALARIS DS-5 July 2020 Floaters 6.1 6.1 —

VALARIS 71 June 2020 Jackups 0.2 0.8 (0.6)

VALARIS 70 June 2020 Jackups 0.6 1.0 (0.4)

VALARIS 5004 April 2020 Floaters 1.9 2.0 (0.1)

VALARIS 68 January 2020 Jackups 0.3 0.3 —

VALARIS 6002 January 2020 Floaters 2.1 0.9 1.2

VALARIS 96 December 2019 Jackups 1.9 0.3 1.6

VALARIS 5006 November 2019 Floaters 7.0 6.0 1.0

VALARIS 42 October 2019 Jackups 2.9 2.5 0.4

Gorilla IV May 2019 Jackups 2.5 2.5 —

ENSCO 97 April 2019 Jackups 1.7 1.0 0.7

$ 26.4 $ 21.1 $ 5.3

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

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.

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 and, if necessary, we may rely on the issuance of debt and/or equity securities in the future to supplement our liquidity needs.

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.

Our liquidity position is summarized in the table below (in millions, except ratios):

Successor Predecessor

December 31, 2021 December 31, 2020 December 31, 2019

Cash and cash equivalents $ 608.7 $ 325.8 $ 97.2

Available DIP facility capacity (1)

Available credit facility borrowing capacity — — 1,622.2

Total liquidity $ 608.7 $ 825.8 $ 1,719.4

Working capital $ 784.6 $ 746.1 $ 233.7

Current ratio 2.9 2.7 1.3

(1) On September 25, 2020, we entered into a $500.0 million DIP facility to provide liquidity when the Chapter 11 Cases were pending.

However, the same was terminated upon our emergence from the Chapter 11 Cases on the Effective Date.

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 or business combinations, our primary sources and uses of cash are driven by cash generated from or used in operations and capital expenditures.

Our net cash used in operating activities and capital expenditures were as follows (in millions):

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

Our net cash provided by or used in operating activities and capital expenditures were as follows (in millions):

Successor Predecessor

Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019

Net cash used in operating activities $ (26.2) $ (39.8) $ (251.7) $ (276.9)

Year Ended December 31, 2022 Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021

Net cash provided by (used in) operating activities

$ 127.5 $ (26.2) $ (39.8)

Capital expenditures $ (207.0) $ (50.2) $ (8.7)

During the eight months ended December 31, 2021 (Successor), our primary source of cash was proceeds of $25.1 million from the disposition of assets.

Our primary uses of cash for the same period were $26.2 million used in operating activities and $50.2 million for the enhancement and other improvements of our drilling rigs.

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 from the disposition of assets.

Our primary uses of cash for the same period were $39.8 million used in operating activities and $8.7 million for the enhancement and other improvements of our drilling rigs.

Net cash used in operating activities during the eight months ended December 31, 2021 (Successor) primarily relates to reorganization costs and interest payments on the First Lien Notes while net cash used in operating activities for the four months ended April 30, 2021 (Predecessor) primarily relates to reorganization costs, partially offset by cash received from a tax refund.

During the year ended December 31, 2020 (Predecessor), our primary sources of cash were $596 million from borrowings on our credit facility and proceeds of $51.8 million for the disposition of assets.

Our primary uses of cash for the same period were $251.7 million used in operating activities and $93.8 million for the enhancement and other improvements of our drilling rigs.

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

During the year ended December 31, 2019 (Predecessor), our primary sources of cash were cash acquired of $931.9 million in the Rowan acquisition and proceeds of $474.0 million from the maturity of short-term investments.

Our primary uses of cash for the same period were $928.1 million used to repay long-term borrowings, $276.9 million used in operating activities and $227.0 million for the enhancement and other improvements of our drilling rigs.

Prior to our chapter 11 filing, we had contractual commitments for the construction of VALARIS DS-13 and VALARIS DS-14.

On February 26, 2021, we entered into amended agreements with the shipyard that became effective upon our emergence from bankruptcy.

The amendments provide for, among other things, an option construct whereby the Company has the right, but not the obligation, to take delivery of either or both rigs on or before December 31, 2023.

Under the amended agreements, the purchase price for the rigs is estimated to be approximately $119.1 million for VALARIS DS-13 and $218.3 million for VALARIS DS-14, assuming a December 31, 2023 delivery date.

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.

For the same period, our uses of cash in operating activities of $39.8 million primarily related to declining margins and reorganization costs.

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 the Company elects not to purchase the rigs, the Company has no further obligations to the shipyard.

The amended agreements removed any parent company guarantee.

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 this reactivation cost will be operating expenses, recognized in the income statement, related to de-preservation activities, including reinstalling key pieces of equipment and crewing up the rigs.

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 these customer-specific enhancements.

Based on our current projections, we expect capital expenditures during 2022 to approximate $225 million to $250 million for rig enhancement, reactivation and upgrade projects.

We expect that customers will reimburse us for a significant portion of the 2022 expenditures.

Depending on market conditions and future opportunities, we may make additional capital expenditures to upgrade rigs for customer requirements and construct or acquire additional rigs.

Approximately $70 million of our expected capital expenditures for 2022 relate to the reactivation and upgrade of the VALARIS DS-11 for an eight-well contract for a deepwater project in the U.S.

Gulf of Mexico expected to commence in mid-2024.

The contract requires the rig to be upgraded with 20,000 psi well-control equipment.

In February 2022, the customer decided not to sanction and therefore withdraw from the project associated with this contract.

As of the date hereof, the customer has not terminated the contract, but may do so upon the payment of an early termination fee should the project not receive a final investment decision (FID).

The project has not received FID.

We are in discussions with the customer and its partner on the project to determine next steps.

In the event of termination, the early termination fee and contractual reimbursements from the customer will be more than sufficient to cover expenses and commitments incurred by Valaris on the project.

As we begin to reactivate rigs, we expect future spending levels to increase beyond the levels we incurred in 2020 and 2021, with more spending associated with reactivation of our floater fleet relative to our jackup fleet and for rigs that have been preservation stacked for longer periods of time.

We 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.

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Financing and Capital Resources

Successor First Lien Notes

On the Effective Date, in accordance with the plan of reorganization and Backstop Commitment Agreement, dated August 18, 2020 (as amended, the "BCA"), the Company consummated the rights offering of the First Lien Notes and associated shares in an aggregate principal amount of $550 million.

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.

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Interest on the First Lien Notes accrues, at our option, at a rate of:

(i) 8.25% per annum, payable in cash;

(ii) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind;

or (iii) 12% per annum, with the entirety of such interest to be paid in kind.

(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.

The first cash interest payment was made on November 1, 2021.

At any time prior to April 30, 2023, the Company may redeem up to 35% of the aggregate principal amount of the First Lien Notes at a redemption price of 104% up to the net cash proceeds received by the Company from equity offerings provided that at least 65% of the aggregate principal amount of the First Lien Notes remains outstanding and provided that the redemption occurs within 120 days after such equity offering of the Company.

At any time prior to April 30, 2023 the Company may redeem the First Lien Notes at a redemption price of 104% plus a “make-whole” premium.

On or after April 30, 2023, the Company may redeem all or part of the First Lien Notes at fixed redemption prices (expressed as percentages of the principal amount), plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

The Company may also redeem the First Lien Notes, in whole or in part, at any time and from time to time on or after April 30, 2026 at a redemption price equal to 100% of the principal amount plus accrued and unpaid interest, if any, to, but excluding, the applicable redemption date.

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:

(i) incur, assume or guarantee additional indebtedness;

(ii) pay dividends or distributions on equity interests or redeem or repurchase equity interests;

(iii) make investments;

(iv) repay or redeem junior debt;

(v) transfer or sell assets;

(vi) enter into sale and lease back transactions;

(vii) create, incur or assume liens;

and (viii) enter into transactions with certain affiliates.

(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.

As of December 31, 2021, we were in compliance with our covenants under the Indenture.

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.

Predecessor Senior Notes

The commencement of the Chapter 11 Cases was considered an event of default under each series of our senior notes and all obligations thereunder were accelerated.

However, any efforts to enforce payment obligations related to the acceleration of our debt were automatically stayed as a result of the filing of the Chapter 11 Cases.

Accordingly, the $6.5 billion in aggregate principal amount outstanding under the Predecessor senior notes as well as $201.9 million in associated accrued interest as of the Petition Date were classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020.

On the Effective Date, pursuant to the plan of reorganization, each series of our senior notes were cancelled and the holders thereunder received the treatment as set forth in the plan of reorganization.

See " Note 2 - Chapter 11 Proceedings" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for more information related to our emergence from Chapter 11 Cases and cancellation of Predecessor debt.

Tender Offers and Open Market Repurchases (Predecessor)

In early March 2020, we repurchased $12.8 million of our outstanding 4.70% senior notes due 2021 on the open market for an aggregate purchase price of $9.7 million, excluding accrued interest, with cash on hand.

As a result of the transaction, we recognized a pre-tax gain of $3.1 million net of discounts in other, net, in the Consolidated Statements of Operations.

On June 25, 2019, we commenced cash tender offers for certain series of senior notes issued by us and certain of our wholly-owned subsidiaries.

The tender offers expired on July 23, 2019, and we repurchased $951.8 million of our outstanding senior notes for an aggregate purchase price of $724.1 million.

As a result of the transaction, we recognized a pre-tax gain from debt extinguishment of $194.1 million, net of discounts, premiums and debt issuance costs.

Predecessor Revolving Credit Facility

The commencement of the Chapter 11 Cases constituted an event of default under our then existing Revolving Credit Facility.

However, the ability of the lenders to exercise remedies in respect of the Revolving Credit Facility was stayed upon commencement of the Chapter 11 Cases.

Accordingly, the $581.0 million of outstanding borrowings as well as accrued interest as of the Petition Date were classified as Liabilities Subject to Compromise in our Consolidated Balance Sheet as of December 31, 2020.

On the Effective Date, pursuant to the plan of reorganization, the Revolving Credit Facility was cancelled and the holders thereunder received the treatment as set forth in the plan of reorganization.

Prior to the Effective Date, pursuant to the plan of reorganization, all undrawn letters of credit issued under the Revolving Credit Facility were collateralized pursuant to the terms of the Revolving Credit Facility.

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 long-term notes receivable and from the distribution of earnings from ARO.

The long-term notes receivable, which are governed by the laws of Saudi Arabia, mature during 2027 and 2028.

In the event that ARO is unable to repay these notes when they become due, we would require the prior consent of our joint venture partner to enforce ARO’s payment obligations.

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.

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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, 2021 (in millions):

The following table summarizes the maturity schedule of our Notes Receivable from ARO as of December 31, 2022 (Successor) (in millions):

Maturity Date Principal amount

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Contractual Obligations

The following table summarizes our significant contractual obligations as of December 31, 2021 and the periods in which such obligations are due (in millions):

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):

Payments due by period

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(1) Interest on the First Lien Notes accrues, at our option, at a rate of:

(i) 8.25% per annum, payable in cash;

(ii) 10.25% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be paid in kind;

or (iii) 12% per annum, with the entirety of such interest to be paid in kind.

(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 $320.2 million of unrecognized tax benefits, inclusive of interest and penalties, included on our Consolidated Balance Sheet as of December 31, 2021.

(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 joint venture, we have a potential obligation to fund ARO for newbuild jackup rigs.

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, with the first rig expected to be delivered in the fourth quarter of 2022 and the second rig is expected either late in the fourth quarter or in the first quarter of 2023.

ARO is expected to place orders for two additional newbuild jackups in 2022.

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.

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Each partner's commitment shall be reduced by the actual cost of each newbuild rig, on a proportionate basis.

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.

Prior to our chapter 11 filing, we had contractual commitments for the construction of VALARIS DS-13 and VALARIS DS-14.

On February 26, 2021, we entered into amended agreements with the shipyard that became effective upon our emergence from bankruptcy.

The amendments provide for, among other things, an option construct whereby the Company has the right, but not the obligation, to take delivery of either or both rigs on or before December 31, 2023.

Under the amended agreements, the purchase price for the rigs are estimated to be approximately $119.1 million for VALARIS DS-13 and $218.3 million for VALARIS DS-14, assuming a December 31, 2023 delivery date.

Delivery can be requested any time prior to December 31, 2023 with a downward purchase price adjustment based on predetermined terms.

If the Company elects not to purchase the rigs, the Company has no further obligations to the shipyard.

The amended agreements removed any parent company guarantee.

Other Commitments

We have other commitments that we are contractually obligated to fulfill with cash under certain circumstances.

As of December 31, 2021, we were contingently liable for an aggregate amount of $36.5 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.

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, 2021, we had collateral deposits in the amount of $31.1 million with respect to these agreements.

As of December 31, 2022 (Successor) , we had collateral deposits in the amount of $20.7 million with respect to these agreements.

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

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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 $18 million liability for unrecognized tax benefits relating to these assessments as of December 31, 2021.

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.

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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, (i) first-priority perfected liens on 100% of the equity interests of each restricted subsidiary directly owned by Valaris Limited or any Guarantor and (ii) a first-priority perfected lien on substantially all assets of Valaris Limited and each Guarantor, in each case subject to certain exceptions and limitations (collectively, the “Collateral”).

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.

First Lien Note Guarantees

The Guarantees are joint and several senior secured obligations of each Guarantor and rank equally in right of payment with existing and future senior indebtedness of such Guarantor and effectively senior to such Guarantor’s existing and future indebtedness (i) that is not secured by a lien on the Collateral securing the First Lien Notes, or (ii) that is secured by a lien on the Collateral securing the First Lien Notes ranking junior to the liens securing the First Lien Notes.

The Guarantees rank effectively junior to such Guarantor’s existing and future secured indebtedness (i) that is secured by a lien on the Collateral that is senior or prior to the lien securing the First Lien Notes, or (ii) that is secured by liens on assets that are not part of the Collateral, to the extent of the value of such assets.

The Guarantees 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.

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The Collateral Agent’s ability to exercise such remedies is limited by the intercreditor agreement for so long as any priority lien debt is outstanding.

The combined value of the affiliates whose securities are pledged as Collateral constitutes substantially all of the Company’s value, including assets, liabilities and results of operations.

As such, the assets, liabilities and results of operations of the combined affiliates whose securities are pledged as Collateral are not materially different than the corresponding amounts presented in the consolidated financial statements of the Company.

The 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.

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Summarized Balance Sheet Information:

Successor Predecessor

(in millions) December 31,

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Successor Predecessor

(in millions) Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019

(in millions) Year Ended December 31, 2022 Eight Months Ended December 31, 2021 Four Months Ended April 30, 2021

Operating revenues $ 1,471.6 $ 818.7 $ 388.8

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Income (loss) from continuing operations before income taxes 72.3 184.9 (4,343.4)

Net income (loss) attributable to noncontrolling interest (3.8) (3.2) 2.1 (5.8)

Net income attributable to noncontrolling interest (5.3) (3.8) (3.2)

Net income (loss) 67.0 181.1 (4,346.6)

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Greenhouse gas (“GHG”) emissions have increasingly become the subject of international, national, regional, state and local attention.

At the December 2015 Conference of the Parties to the United Nations Framework Convention on Climate Change held in Paris, an agreement was reached that requires countries to review and “represent a progression” in their intended nationally determined contributions to the reduction of GHG emissions, setting GHG emission reduction goals every five years beginning in 2020.

This agreement, known as the Paris Agreement, entered into force on November 4, 2016.

The United Nations Climate Change Conference held in Katowice, Poland in December 2018 adopted further rules regarding the implementation of the Paris Agreement and, in connection with this conference, numerous countries issued commitments to increase their GHG emission reduction targets.

Although the United States had withdrawn from the Paris Agreement in November 2020, the current Presidential Administration officially reentered the United States into the agreement in February 2021.

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 and (2) Executive Order on Tackling the Climate Crisis at Home and Abroad.

The latter executive order announced a moratorium on new oil and gas leasing on federal lands and offshore waters pending completion of a comprehensive review and reconsideration of Federal oil and gas permitting and leasing practices, established climate change as a primary foreign policy and national security consideration and affirmed that achieving net-zero greenhouse gas emissions by or before mid-century is a critical priority.

In June 2021, a federal judge for the U.S.

District Court of the Western District of Louisiana issued a nationwide preliminary injunction against the pause of oil and natural gas leasing on public lands or in offshore waters while litigation challenging that aspect of the executive order is ongoing.

On January 27, 2022, the United States District Court for the District of Columbia found that the Bureau of Ocean Energy Management’s failure to calculate the potential emissions from foreign oil consumption violated the agency’s approval of oil and gas leases in the Gulf of Mexico under the National Environmental Policy Act.

The full impact of these federal actions, or any other future restrictions or prohibitions, remains unclear.

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.

During 2009, the United States Environmental Protection Agency (the “EPA”) officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.

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 facilities.

Although a number of bills related to climate change have been introduced in the U.S.

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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.

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.

Foreign Currency Risk

Our functional currency is the U.S.

As is customary in the oil and gas industry, a majority of our revenues and expenses are denominated in U.S.

however, a portion of the revenues earned and expenses incurred by certain of our subsidiaries are denominated in currencies other than the U.S.

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" to our consolidated financial statements included in "Item 8.

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.

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We identify our critical accounting policies as those that are the most pervasive and important to the portrayal of our financial position and operating results and that require the most difficult, subjective and/or complex judgments regarding estimates in matters that are inherently uncertain.

Our critical accounting policies are those related to property and equipment, impairment of property and equipment, income taxes and pension and other post-retirement benefits.

Our critical accounting policies are those related to property and equipment, income taxes and pension and other post-retirement benefits.

Property and Equipment

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Financial Statements and Supplementary Data" for more information.

As of December 31, 2021, the carrying value of our property and equipment totaled $890.9 million, which represented 34% of total assets.

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.

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We establish property and equipment accounting policies that are designed to depreciate our assets over their estimated useful lives.

Prior to emergence from bankruptcy, we recorded our drilling rigs as a single asset with a useful life ascribed by the expected useful life of that asset.

Upon emergence, we 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.

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 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 rigs are difficult to estimate due to a variety of factors, including technological advances that impact the methods or cost of oil and natural gas exploration and development, changes in market or economic conditions and changes in laws or regulations affecting the drilling industry.

We evaluate the remaining useful lives of our rigs on a periodic basis, considering operating condition, functional capability and market and economic factors.

The use of different estimates, judgments and assumptions in

the establishment of our property and equipment accounting policies, especially those involving the useful lives of 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 45% of the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2021.

Our fleet of 33 jackup rigs represented 44% of the gross cost and the net carrying amount of our depreciable property and equipment as of December 31, 2021.

Impairment of Property and Equipment

We do not consider Impairment of Property and Equipment to be a critical accounting policy for Valaris Limited (Successor) due to the significantly reduced carrying values.

However, for Legacy Valaris (Predecessor), this was a critical accounting policy and have included disclosure below for historical periods.

During the four months ended April 30, 2021, we recorded an aggregate pre-tax, non-cash impairment with respect to certain floaters of $756.5 million.

During the year ended December 31, 2020 and the year ended December 31, 2019, we recorded an aggregate pre-tax, non-cash impairment with respect to certain floaters, jackups and spare equipment of $3.6 billion and $98.4 million, respectively.

See " Note 8 - Property and Equipment" to our consolidated financial statements included in "Item 8.

Financial Statements and Supplementary Data" for additional information on our impairments of property and equipment.

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, on a quarterly basis to identify events or changes in circumstances ("triggering events") that indicate that the carrying value of such rigs may not be recoverable.

Generally, extended periods of idle time and/or inability to contract rigs at economical rates are an indication that a rig may be impaired.

Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic location.

For property and equipment used in our operations, recoverability generally is determined by comparing the carrying value of an asset to the expected undiscounted future cash flows of the asset.

If the carrying value of an asset is not recoverable, the amount of impairment loss is measured as the difference between the carrying value of the asset and its estimated fair value.

The determination of expected undiscounted cash flow amounts requires significant estimates, judgments and assumptions, including utilization levels, day rates, expense levels and capital requirements, as well as cash flows generated upon disposition, for each of our drilling rigs.

Due to the inherent uncertainties associated with these estimates, we perform sensitivity analysis on key assumptions as part of our recoverability test.

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

• global macroeconomic and political environment,

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

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

• remaining useful lives of our rigs,

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

• weighted-average cost of capital,

• oil price projections,

• sanctioned and unsanctioned offshore project data,

• offshore economic project break-even data,

• global rig supply and construction orders,

• global rig fleet capabilities and relative rankings, and

• expectations of global rig fleet attrition.

We collect and analyze the above information to develop a range of estimated utilization levels, day rates, expense levels and capital requirements, as well as estimated cash flows generated upon disposition.

The drivers of these assumptions that impact our impairment analyses include projections of future oil prices and timing of global rig fleet attrition, which, in large part, impact our estimates on timing and magnitude of recovery from the current industry downturn.

However, there are numerous judgments and assumptions unique to the projected future cash flows of each rig that individually, and in the aggregate, can significantly impact the recoverability of its carrying value.

The highly cyclical nature of our industry cannot be reasonably predicted with a high level of accuracy and, therefore, differences between our historical judgments and assumptions and actual results will occur.

We reassess our judgments and assumptions in the period in which significant differences are observed and may conclude that a triggering event has occurred and perform a recoverability test.

We recognized impairment charges in recent periods upon observation of significant unexpected changes in our business climate and estimated useful lives of certain assets.

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

• changes in global economic conditions and demand,

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

• production levels of non-OPEC countries,

• advances in exploration and development technology,

• offshore and onshore project break-even economics,

• development and exploitation of alternative fuels,

• natural disasters or other operational hazards,

• changes in relevant law and governmental regulations,

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

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

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

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

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.

We conduct operations and earn income in numerous countries and are subject to the laws of numerous tax jurisdictions.

As of December 31, 2021, our Consolidated Balance Sheet included an $47.3 million net deferred income tax asset, a $31.0 million liability for income taxes currently payable and a $320.2 million liability for unrecognized tax benefits, inclusive of interest and penalties.

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.

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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 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.

While we historically have not

experienced significant adjustments to previously recognized tax assets and liabilities as a result of finalizing tax returns, there can be no assurance that significant adjustments will not arise in the future.

In addition, there are several factors that could cause the future level of uncertainty relating to our tax liabilities to increase, including the following:

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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, 2021, included (1) a weighted average discount rate of 2.73% to determine pension benefit obligations, (2) a weighted average discount rate of 2.84% to determine net periodic pension cost and (3), an expected long-term rate of return on pension plan assets of 6.03% to determine net periodic pension cost.

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.

Key assumptions at the Effective Date included (1) a weighted average discount rate of 2.81% to determine pension benefit obligations and (2) an expected long-term rate of return on pension plan assets of 6.03% to determine net periodic pension cost.

The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds, and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations.

Using our key assumptions at December 31, 2021, a one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $109.1 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 $4.1 million.

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 6.26% at December 31, 2021 from 6.03% at December 31, 2020.

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.

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Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Information required under this Item 7A.

has been incorporated herein from "Item 7.

Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk."

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What changed 10-K

Item 7. Management’s Discussion and Analysis