Noble Corp plc (NE)

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

The following discussion is intended to assist you in understanding our financial position at December 31, 2024 and 2023, and our results of operations for the years ended December 31, 2024, 2023, and 2022.

The following discussion should be read in conjunction with the consolidated financial statements and related notes contained in this Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed by Noble.

Executive Overview

Noble is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. Our business strategy is centered around providing efficient, reliable, and safe offshore drilling services to our customers. We have one of the youngest and highest specification fleets of global scale in the industry, with diversification across asset classes, geographic regions, and customers. The Company has a track record of industry-leading utilization coupled with a commitment to best-in-class safety performance and customer satisfaction. We strive to be the leader in industry innovation and a first-mover in sustainability.

Our fleet consists predominately of technologically advanced units, equipped with sophisticated systems and components prepared to execute our customers’ complicated offshore drilling programs safely and with greater efficiency. We are primarily focused on the ultra-deepwater market and the harsh and ultra-harsh environment jackup markets, which typically are more technically challenging markets to operate in.

We emphasize safe operations, environmental stewardship, and superior performance through a structured management system, the employment of qualified and well-trained crews and onshore support staff, the care of our surroundings and the neighboring communities where we operate, and other activities advancing our environmental sustainability, social responsibility, and good governance. We also manage rig operating costs through the implementation and continuous improvement of innovative systems and processes, which includes the use of data analytics and predictive maintenance technology.

As of the filing date of this Annual Report on Form 10-K, our fleet of 40 drilling rigs consists of 27 floaters and 13 jackups strategically deployed worldwide. We typically employ each drilling unit under an individual contract, and many contracts are awarded based upon a competitive bidding process.

We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent, and government-owned or controlled oil and gas companies throughout the world.

For the year ended December 31, 2024, our financial and operating results include:

•operating revenues totaling $3.1 billion;

•net income of $448.4 million or $2.96 per diluted share;

•net cash provided by operating activities totaling $655.5 million;

•no funds drawn down on the 2023 Revolving Credit Facility as of December 31, 2024, and

•a year end cash balance of $247.3 million.

Demand for our services is driven by the offshore exploration and development programs of oil and gas operators, which in turn are influenced by many factors. Those factors include, but are not limited to, the price and price stability of oil and gas, the relative cost and carbon footprint of offshore resources within each operator’s broader energy portfolio, global macroeconomic conditions, world energy demand, the operator’s strategy toward renewable energy sources, environmental considerations, and governmental policies.

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Outlook

In recent years, oil prices have generally remained at levels that are supportive of offshore exploration and development activity and global rig demand recovered to eclipse pre-pandemic levels, albeit with some moderation over the past 12 months. Current demand and utilization levels are supported by the combination of resilient commodity prices, heightened focus on energy security, the capital intensity of depletion replacement, and relative attractiveness of offshore plays with respect to both cost and carbon emissions. The increase in global rig demand since 2021 has had a positive impact on dayrates for most rig classes although dayrates have generally plateaued more recently.

The global rig supply has come down from historic highs as Noble and other offshore drilling contractors have retired less capable and idle assets. Concurrently, the incoming supply of newbuild offshore drilling rigs has diminished materially, with several newbuild rigs stranded in shipyards. However, we expect many of these stranded newbuild rigs may continue to make their way into the global market over the next few years.

Although the market outlook in our business varies by geographical region and water depth, we remain encouraged by the long-term outlook in the ultra-deepwater floater market. However, within this ultra-deepwater market, our customers continue to focus on our highest specification floaters, which represents the majority of our floater fleet. Assuming current market fundamentals, continued customer prioritization towards these highest specification floaters is likely to result in lower utilization for our lower specification drillships and our semi-submersibles. Demand for midwater semisubmersibles is primarily driven by brownfield activity in mature basins, especially in Northwest Europe, South America, and the Asia Pacific regions, where a generally stable level of baseload demand is supported by infield drilling and plug and abandonment requirements. Despite some recent contract suspensions in select jackup markets, we have also observed an overall demand increase in the global jackup market since 2020. While we remain encouraged about overall long-term rig demand, to the extent global macroeconomic concerns become more prevalent and produce downward pressure on oil and gas prices, we could experience downward pressure on overall rig demand for both floaters and jackups.

Returning to the broader offshore drilling market, while there are a number of multi-year contracts out for tender, the overall market remains characterized by generally shorter-term contracts. This leads to an increased number of rig contract start-ups, both with different customers and among different regions, which may require incremental resources and costs. Additionally, this has resulted in, and is likely to continue to result in, lower overall effective utilization for our fleet driven by more idle time between contracts.

The energy transition from hydrocarbons to renewables poses a challenge to the oil and gas sector and our market. Energy rebalancing trends have accelerated in recent years as evidenced by promulgated or proposed government policies and commitments by many of our customers to further invest in sustainable energy sources. Our industry could be further challenged as resource holders and policy makers continue to evaluate and calibrate strategies and capital flows to address global energy needs. Ultimately, however, there continues to be a global dependence on products made from hydrocarbons and on the combustion of hydrocarbons to provide reliable and affordable energy. Low-cost and low-emission barrels are expected to be the most attractive conventional source to meet energy needs both currently and in the future. Global energy demand is predicted to increase over the coming decades, and we expect that offshore oil and gas will continue to play an important and lasting role in meeting this demand.

We expect inflationary pressures to persist, which has led, and may continue to lead, to increased costs of services. Additionally, we expect supply chain disruptions to continue, and potentially accelerate, as geopolitical crises, such as the Russia-Ukraine conflict, Middle East conflicts, the Guyana-Venezuela dispute, and their respective regional and global ramifications, may negatively impact our ability to conduct our day-to-day operations. Additionally, the impact of new or increased tariffs or trade wars could have an inflationary impact on the costs of certain products and services as well as potentially contribute to further supply chain disruptions.

Contract Drilling Services Backlog

We maintain a backlog of commitments for contract drilling services. Our contract drilling services backlog reflects estimated future revenues attributable to signed drilling contracts. While backlog did not include any letters of intent as of December 31, 2024, in the past we have included in backlog certain letters of intent that we expect to result in binding drilling contracts. As of December 31, 2024, contract drilling services backlog totaled approximately $6.1 billion.

We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period, and include certain assumptions based on the terms of certain contractual arrangements, discussed in the notes to the table below. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization, and contract preparation, which are not expected to be

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significant to our contract drilling services revenues, amounts constituting reimbursables from customers, or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.

The table below presents the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:

(1)Represents a twelve-month period beginning January 1. Some of our drilling contracts provide customers with certain early termination rights and, in limited cases, those termination rights require minimal or no notice and minimal financial penalties.

(2)Noble entered into a multi-year Commercial Enabling Agreement (the “CEA”) with ExxonMobil in February 2020. Under the CEA, dayrates for the rigs are repriced on March 1 and September 1 each year to the projected market rate at the time the new rate goes into effect, subject to a scale-based discount and a performance bonus that appropriately aligns the interests of Noble and ExxonMobil. Under the CEA, the table above includes awarded and remaining current contract term to August 18, 2028, related to each of the four following rigs: the Noble Tom Madden, Noble Bob Douglas, Noble Don Taylor, and Noble Sam Croft. Under the CEA, ExxonMobil may reassign remaining contract term among rigs, subject to maintaining certain minimum contract term on the rig from which term is removed.

(3)In 2022, Noble renewed its five-year Framework Agreement with Aker BP for the provision of ultra-harsh environment jackup rigs, the Noble Integrator and Noble Invincible, for activities offshore Norway. Under the Framework Agreement, different rate structures apply reflecting different operating modes, agreed incentive schemes, and adjustments for operating expenses. Rate structures are adjusted annually to reflect market conditions.

(4)Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period by the product of the number of our rigs, including cold-stacked rigs, and the number of calendar days in such period.

The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods presented in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, the operation of market benchmarks for dayrate resets, achievement of bonuses, weather conditions, reduced standby or mobilization rates, and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. See Part I, Item 1A, “Risk Factors—Risks Related to Our Business and Operations—Our current backlog of contract drilling revenue may not be ultimately realized.”

As of December 31, 2024, ExxonMobil, BP, and Petrobras represented approximately 37.2%, 13.1%, and 12.6% of our backlog, respectively.

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Results of Operations

Results for the years ended December 31, 2024 and 2023

Net income for the year ended December 31, 2024, was $448.4 million, or $2.96 per diluted share, on operating revenues of $3.1 billion compared to net income for the year ended December 31, 2023, of $481.9 million, or $3.32 per diluted share, on operating revenues of $2.6 billion.

Key Operating Metrics

Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates, and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “Contract Drilling Services” below.

The following table presents the average rig utilization, operating days, and average dayrates for our rig fleet for the periods indicated.

(1)We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet.

(2)An operating day is defined as a calendar day during which a rig operated under a drilling contract. We define average dayrates as revenue from contract drilling services earned per operating day. Average dayrates have not been adjusted for the non-cash amortization related to favorable and unfavorable customer contract intangibles.

Contract Drilling Services

The following table presents the operating results for our contract drilling services segment for the period indicated (dollars in thousands):

(1)We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations, or cash flows.

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Contract Drilling Services Revenues

The following table provides information about contract drilling services revenues and costs by rig types (dollars in millions except average dayrates):

Floaters. During the year ended December 31, 2024, floaters generated revenue of $2.3 billion, as compared to $2.0 billion in year ended December 31, 2023. The increase in revenue was mainly attributable to $297.0 million provided by the additional floaters acquired in connection with the Diamond Transaction. The increase also included $285.6 million from an increase in average dayrates during the current year, excluding rigs acquired in the Diamond Transaction, and $42.0 million received from a contract termination fee. These increases were partly offset by $265.6 million from rigs with net changes in operating days during the current year, excluding rigs acquired in the Diamond Transaction. Additionally, floater revenue from net non-cash amortization related to off-market customer contract assets and liabilities decreased $19.5 million during the current year. For additional information, see “Note 2 — Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Jackups. During the year ended December 31, 2024, jackups generated revenue of $569.1 million, as compared to $451.6 million in year ended December 31, 2023. The increase in revenue was mainly attributable to $60.5 million from an increase in average dayrates during the current year and $91.5 million from rigs with net changes in operating days during the current year. Additionally, jackup revenue from net non-cash amortization related to off-market customer contract assets and liabilities decreased $27.1 million during the current year.

Operating Costs and Expenses

Floaters. During the year ended December 31, 2024, total contract drilling services cost related to floaters was $1.3 billion, as compared to $1.1 billion in year ended December 31, 2023. The primary drivers of this increase were $180.1 million related to the additional floaters acquired in connection with the Diamond Transaction and $32.0 million predominately driven by labor and transportation costs across the fleet. These increases were partially offset by insurance proceeds received for a certain rig totaling $18.1 million. For additional information, see “Note 2 — Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Jackups. During the year ended December 31, 2024, total contract drilling services cost related to jackups was $381.2 million, as compared to $340.0 million in year ended December 31, 2023. The primary drivers of the aggregate increase of $99.0 million related to labor costs, repairs and maintenance, operations support, and other costs across the fleet due to increased activity. These increases were partially offset by a decrease of $58.0 million after the completion of disposal activities regarding certain rigs.

Depreciation and amortization. Depreciation and amortization totaled $428.6 million and $301.3 million during the years ended December 31, 2024 and 2023, respectively. Depreciation and amortization increased by $127.3 million in the current year primarily due to the timing of capital additions that were placed in service as compared to retirements among the periods as well as an incremental amount added in connection with the Diamond Transaction.

General and administrative. General and administrative expenses totaled $140.5 million and $128.4 million during the years ended December 31, 2024 and 2023, respectively. The increase was primarily a result of the Diamond Transaction and other individually insignificant items within certain corporate charges such as professional fees, corporate leases, and employee related costs.

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Merger and integration costs. Noble incurred $109.4 million and $60.3 million of merger and integration costs during the years ended December 31, 2024 and 2023, respectively, primarily as a result of the Diamond Transaction and the Business Combination with Maersk Drilling. During the current period, $84.5 million and $25.0 million of costs related directly to the Diamond Transaction and the Business Combination with Maersk Drilling, respectively. Costs incurred prior to 2024 related to the Business Combination with Maersk Drilling in October 2022. A majority of the costs attributable to the Diamond Transaction related to the closing of the transaction and included charges for professional fees, severance, and share-based compensation. For additional information, see “Note 2 — Acquisitions and Divestitures” and “Note 3 — Merger and Integration Costs” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Gain on sale of operating assets, net. During the year ended December 31, 2024, we sold the Noble Explorer for total proceeds of $25.0 million, $21.5 million of which was received in the fourth quarter of 2023, resulting in a pre-tax gain of $17.4 million.

Hurricane losses and recoveries, net. During the year ended December 31, 2024, costs in connection with the Hurricane Ida incident were offset by accrued recoveries. During the year ended December 31, 2023, Noble recognized $31.8 million of costs, which was offset by the recognition of insurance recoveries of $51.5 million. For additional information, see “Note 12 — Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Other Income and Expenses

Interest expense, net of amounts capitalized. Interest expense totaled $94.2 million and $59.1 million for the years ended December 31, 2024 and 2023, respectively. Interest expense primarily relates to our 2030 Notes which, in part, refinanced prior debt assumed in the Business Combination with Maersk Drilling in October 2022, as well as the Diamond Second Lien Notes. For additional information, see “Note 6 — Debt“ to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Gain (loss) on extinguishment of debt, net. Noble recognized loss on extinguishment of debt of $26.4 million for the year ended December 31, 2023, related to the redemption of the remaining balance on notes and refinancing of other debt. For additional information, see “Note 6 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Interest income and other, net. Noble recognized other expenses of $17.4 million and other income of $18.1 million for the years ended December 31, 2024 and 2023, respectively. For the year ended December 31, 2024, Noble made a tax contribution repayment of $4.0 million related to a joint taxation scheme with A.P. Møller Holding A/S. For the year ended December 31, 2023, other income primarily related to the recognition of approximately $19.1 million of compensation under the same arrangement. For additional information, see “Note 10 — Income Taxes” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Gain on bargain purchase. Noble recognized a $5.0 million gain on the bargain purchase of Maersk Drilling for the year ended December 31, 2023. For additional information, see “Note 2 — Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Income tax benefit (provision). Noble recorded an income tax provision of $44.0 million and $30.3 million during the years ended December 31, 2024 and 2023, respectively.

During the year ended December 31, 2024, our tax provision included tax benefits of $123.6 million related to releases of valuation allowances primarily in Luxembourg, and a net tax benefit of $20.2 million related to changes in uncertain tax positions. Such tax benefits were offset by various recurring quarterly accruals of $187.8 million primarily in Guyana, Nigeria, the United States, Switzerland, and Luxembourg.

During the year ended December 31, 2023, our tax provision included tax benefits of $187.2 million related to releases of valuation allowances in Luxembourg, Guyana, Switzerland, and Norway, and a tax benefit of $6.8 million related to uncertain tax position releases. Such tax benefits were offset by tax expenses related to uncertain tax positions of $20.9 million in various countries, contract fair value amortization of $23.7 million, and various recurring quarterly accruals of $179.6 million primarily in Guyana, Switzerland, and Luxembourg.

2023 Compared to 2022

Information related to a comparison of our results of operations for the year ended December 31, 2023, compared to the year ended December 31, 2022, is included in Part II, Item 7, “Management's Discussion and Analysis of Financial Condition

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and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 23, 2024.

Liquidity and Capital Resources

Sources and Uses of Cash

Our principal sources of capital in 2024 were cash generated from operating activities as well as net proceeds from the issuance of additional 2030 Notes (as defined below). Cash on hand during the current period was primarily used for the following:

•cash consideration and fees related to the Diamond Transaction;

•normal recurring operating expenses;

•capital expenditures;

•fees and expenses related to merger and integration costs;

•share repurchases and dividend payments; and

•certain contractual cash obligations and commitments.

Our anticipated cash flow needs, both in the short term and long term, may also include repurchases, redemptions, or repayments of debt and interest.

We currently expect to fund our cash flow needs with cash generated by our operations, cash on hand, proceeds from sales of assets, or borrowings under the 2023 Revolving Credit Facility, and we believe this will provide us with sufficient liquidity to fund our cash flow needs over the next 12 months. Subject to market conditions and other factors, we may also issue equity or long-term debt securities to fund our cash flow needs and for other purposes. We have been incurring expenses and capital costs related to incidents regarding one floater and one jackup. These incurred costs related to each rig each exceeded the applicable deductible. We received partial insurance recoveries in 2024 for each of these claims and we continue to seek insurance recoveries for the remainder of the incurred and anticipated costs.

Net cash provided by operating activities was $655.5 million and $574.3 million for the years ended December 31, 2024 and 2023, respectively. Net cash provided by operating activities increased mainly due to improvements in cash flows from operating assets and liabilities, with key drivers being an increase in payments from customers offset by a reduction in payments to vendors, as well as the Diamond Transaction. We had working capital balances of $448.5 million and $420.1 million at December 31, 2024 and 2023, respectively.

Net cash used in investing activities was $959.0 million for the year ended December 31, 2024, and consisted of capital expenditures on routine projects associated with overhauls and upgrades on various rigs and net cash paid related to the closing of the Diamond Transaction. Net cash used in investing activities was $366.5 million for the year ended December 31, 2023, and consisted of capital expenditures on routine projects associated with overhauls and upgrades on various rigs in the newly combined fleet.

Net cash provided by financing activities was $188.1 million and net cash used in financing activities was $325.8 million for the years ended December 31, 2024 and 2023, respectively. The year ended December 31, 2024, included the issuance of an additional $824.0 million of 2030 Notes. We also repurchased 8.4 million of our Ordinary Shares for total of $300.0 million, made dividend payments to our shareholders of $277.8 million, and paid $66.1 million in taxes withheld on vested employee share-based compensation awards. The year ended December 31, 2023, included the repayment of the DSF Credit Facility in full, the redemption of notes, the repayment of the New DNB Credit Facility, totaling $673.4 million, and the $600.0 million issuance of the initial 2030 Notes. We also repurchased 2.3 million of our Ordinary Shares for a total of $94.8 million and made dividend payments to our shareholders of $98.8 million.

At December 31, 2024, we had a total contract drilling services backlog of approximately $6.1 billion, which includes a commitment of 57% of available days for 2025. For additional information regarding our backlog, see “Contract Drilling Services Backlog.”

Capital Additions

Capital additions totaled $520.3 million and $454.3 million for the years ended December 31, 2024 and 2023, respectively. Capital additions for the year ended December 31, 2024, consisted of the following:

•$312.5 million for sustaining capital;

•$169.8 million in major projects, including subsea and other related projects;

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•$34.3 million for rebillable capital and contract modifications; and

•$3.7 million for capitalized interest.

Our total capital additions estimate for 2025, net of reimbursements, is expected to range between $375.0 million and $425.0 million. We expect to fund these capital additions with cash generated by our operations and cash on hand.

From time to time we consider possible projects and may have certain events that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, while liquidity and preservation of capital remains our top priority, we will continue to evaluate acquisitions of drilling units from time to time.

Amended and Restated Senior Secured Revolving Credit Agreement

In April 2023, certain subsidiaries of Noble amended and restated the senior secured revolving credit agreement, dated February 5, 2021, by entering into an Amended and Restated Senior Secured Revolving Credit Agreement, dated as of April 18, 2023 (as amended and otherwise modified from time to time, the “2023 Revolving Credit Agreement”), by and among Noble Finance II, Noble International Finance Company (“NIFCO”), Noble Drilling A/S, and each other designated borrower from time to time party thereto, as borrowers (the “Borrowers”), the lenders and issuing banks party thereto from time to time and JPMorgan Chase Bank, N.A., as administrative agent, collateral agent, and security trustee. The revolving credit facility under the 2023 Revolving Credit Agreement (the “2023 Revolving Credit Facility”) provides for commitments of $550.0 million with maturity in April 2028. The guarantors under the 2023 Revolving Credit Facility are the same subsidiaries of Noble Finance II that are or will be guarantors of the 2030 Notes.

As of December 31, 2024, we had no borrowings outstanding and $24.8 million of letters of credit issued under our 2023 Revolving Credit Facility and an additional $126.8 million in letters of credit and surety bonds issued under bilateral arrangements. For additional information about the 2023 Revolving Credit Facility, see “Note 6 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

8.000% Senior Notes due 2030

In April 2023, Noble Finance II, a wholly owned subsidiary of Noble, issued $600.0 million in aggregate principal amount of its 8.000% Senior Notes due 2030 (“Initial 2030 Notes”). The Initial 2030 Notes were issued pursuant to an indenture, dated April 18, 2023 (as supplemented or otherwise modified from time to time, the “Noble Indenture”), among Noble Finance II, the subsidiaries of Noble Finance II party thereto, as guarantors (the “Guarantors”), and U.S. Bank Trust Company, National Association, as trustee. In August 2024, Noble Finance II issued an additional $800.0 million in aggregate principal amount of its 8.000% Senior Notes due 2030 (the “Additional 2030 Notes” and, together with the Initial 2030 Notes, the “2030 Notes”) at a premium of 103% bringing the total outstanding principal amount to $1.4 billion. The Additional 2030 Notes were issued pursuant to the Noble Indenture and the net proceeds from the offering of the Additional 2030 Notes were primarily used to fund the cash consideration in the Diamond Transaction and to pay any premiums, fees, and expenses related to the issuance of the Additional 2030 Notes. As of December 31, 2024, we had outstanding $1.4 billion aggregate principal amount of our 2030 Notes. For additional information about the 2030 Notes, see “Note 6 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Diamond Second Lien Notes due 2030

In connection with the Diamond Transaction, the Company assumed $550.0 million aggregate principal amount of 8.500% Senior Secured Second Lien Notes due October 2030 (the “Diamond Second Lien Notes”) issued pursuant to an indenture, dated as of September 21, 2023 (as supplemented and otherwise modified from time to time, the “Diamond Second Lien Indenture”), among Diamond Foreign Asset Company and Diamond Finance, LLC, as issuers, Diamond Offshore Drilling, Inc., the other guarantors party thereto and HSBC Bank USA, National Association, as trustee and as collateral agent. As of December 31, 2024, we had outstanding $550.0 million aggregate principal amount of our Diamond Second Lien Notes. For additional information about the Diamond Second Lien Notes, see “Note 6 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Diamond Credit Agreement

In connection with the Diamond Transaction, the Company terminated Diamond’s $300.0 million senior secured revolving credit facility (the “Diamond Revolving Credit Facility”) under a credit agreement, dated as of April 23, 2021 (as amended and otherwise modified, the “Diamond Credit Agreement”), among Diamond Offshore Drilling, Inc., Diamond Foreign Asset Company, as borrower, the lenders party thereto from time to time and Wells Fargo Bank, National Association, as administrative agent, collateral agent, and issuing lender. The revolving commitments under the Diamond Credit Agreement were scheduled to mature in April 2026. At the time of the Diamond Transaction and the termination of the commitments under the Diamond Credit Agreement, Diamond had no outstanding borrowings under the Diamond Credit Agreement. For additional information about the Diamond Credit Agreement, see “Note 6 — Debt” to our consolidated

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financial statements included in Part II, Item 8 of this Annual Report on Form 10-K to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Dividends

Our most recent quarterly dividend, totaling approximately $79.7 million (or $0.50 per share), was declared on November 5, 2024, and paid on December 19, 2024, to shareholders of record at close of business on December 5, 2024. During the year ended December 31, 2024, we declared dividends of approximately $278.3 million, including accrued dividends, (or $1.80 per share), and made cash dividend payments of approximately $277.8 million.

On February 17, 2025, our Board of Directors approved a declaration of a quarterly cash interim dividend on our Ordinary Shares of $0.50 per share. This dividend is to be payable on March 20, 2025, to shareholders of record at close of business on March 5, 2025.

The declaration and payment of dividends require authorization of the Board of Directors, provided that such dividends on issued share capital may be paid only out of the Company’s “distributable reserves” as determined by reference to relevant statutory accounts in accordance with English law. The Company is not permitted to pay dividends out of share capital, which includes share premiums. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, the availability of sufficient distributable reserves, contractual and indenture restrictions, and other factors deemed relevant by our Board of Directors.

Share Repurchases

Under English law, the Company is only permitted to purchase its own Ordinary Shares by way of an “off-market purchase” pursuant to a contract approved by shareholders (except where the purchase is for the purposes of, or pursuant to, any employees’ share scheme). Such purchases may be paid for either (i) out of Noble’s “distributable reserves” as determined by reference to relevant statutory accounts in accordance with English law or (ii) from the proceeds of a fresh issue of shares made for the purpose of financing the purchase. As of the date of this report, we have shareholder authority to repurchase up to 15% per annum of the issued share capital of the Company as of the beginning of each fiscal year for a five-year period commencing on September 28, 2022 (subject to an overall aggregate maximum of 20.6 million Ordinary Shares). During the year ended December 31, 2024, we repurchased 8.4 million of our Ordinary Shares pursuant to such authority. All repurchased shares were subsequently cancelled.

Summary of Contractual Cash Obligations and Commitments

We have $196.0 million of net long-term tax reserves for uncertain tax positions, including interest and penalties, which are included in “Other liabilities” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See “Note 10 — Income Taxes” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2024, no long-term debt is due in the next twelve months and $2.0 billion will be due subsequent to 2025. See “Note 6 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. We may seek to refinance all or a portion of our long-term debt obligations, including the 2023 Revolving Credit Facility, though any such refinancing transactions are subject to market and other conditions and there are no assurances that we will complete any such transactions, in whole or in part, or as to the amount or timing of any such transactions.

At December 31, 2024, $13.0 million of pension obligations will be due in the next twelve months and the remainder of $127.3 million will be due subsequent to 2025. See “Note 11 — Employee Benefit Plans” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. In addition, $9.5 million is due on a long-term basis under the Danish Holiday Act of 2020.

For a description of our operating and finance lease obligations, refer to “Note 9 — Leases” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2024, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit that guarantee our performance as it relates to our drilling contracts, tax, and other obligations in various jurisdictions. We expect to comply with the underlying performance requirements and we expect obligations under these letters of credit and surety bonds will not be called. At December 31, 2024, $30.6 million letters of credit and commercial commitments will expire in the next twelve months and the remainder of $121.0 million will expire subsequent to 2025.

We expect to fund these obligations and commitments with cash generated by our operations and cash on hand.

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Unaudited Condensed Consolidating Financial Information

The Noble Indenture contains a covenant that requires Noble Finance II to furnish to holders of the 2030 Notes certain financial information relating to Noble Finance II and its restricted subsidiaries. The Diamond Second Lien Indenture contains a covenant that requires NODI to furnish to holders of the Diamond Second Lien Notes certain financial information relating to NODI and its subsidiaries.

The summarized financial information below reflects combined accounts of Noble Finance II, NODI, and all other subsidiaries of Noble. The financial information is presented on a combined basis and intercompany balances and transactions between entities have been eliminated.

(1)Consolidated Noble Offshore Drilling, Inc. from merger effective date on September 4, 2024.

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“US GAAP”), which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which

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form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from our estimates and assumptions and any such differences could be material to our consolidated financial statements. The following accounting policies involve critical accounting estimates because they are particularly dependent on estimates and assumptions made by Noble about matters that are inherently uncertain.

Recoverability of Assets

We evaluate our property and equipment and intangible assets for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. An impairment loss is recognized when and to the extent that an asset's carrying value exceeds its estimated fair value. To the extent actual results do not meet our estimated assumptions for a given rig, piece of equipment or intangible customer contract, we may take an impairment loss in the future. In determining the fair value of the assets, we make significant assumptions and estimates regarding future market conditions using significant unobservable inputs representative of a Level 3 fair value measurement. Critical assumptions used in our estimate include projected dayrates, utilization, and discount rate. These projections involve uncertainties that rely on assumptions about current and future market conditions, timing of future contract awards, and marketability of a unit. It can be difficult to determine the fair value based on the cyclical nature of our business, demand for offshore drilling rigs in different markets, and changes in economic conditions.

During the years ended December 31, 2024 and 2023, no impairment charges were recognized.

Impairment assessment inherently involves management judgments as to assumptions about expected future cash flows and the impact of market conditions on those assumptions. Due to the many variables inherent in this estimation, differences in assumptions may have a material effect on the results of our impairment analysis.

Income Taxes

We estimate income taxes and file tax returns in each of the taxing jurisdictions in which we operate and are required to file a tax return. At the end of each year, an estimate for income taxes is recorded in the financial statements. Tax returns are generally filed in the subsequent year. A reconciliation of the estimate to the final tax return is done at that time, which will result in changes to the original estimate. We believe that our tax return positions are appropriately supported, but tax authorities can challenge certain of our tax positions.

We currently operate, and have in the past operated, in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50% likelihood of being sustained upon challenge by a tax authority. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. A change in judgment related to the expected ultimate resolution of uncertain tax positions will be recognized in earnings in the quarter of such change. We believe that our reserve for uncertain tax positions, including related interest and penalties, is adequate. As of December 31, 2024 and 2023, the Company had $196.0 million and $202.3 million of net long-term tax reserves for unrecognized tax benefits, including interest and penalties, which are included in “Other liabilities.” The amounts ultimately paid upon resolution of audits could be materially different from the amounts previously included in our income tax expense and, therefore, could have a material impact on our tax provision, net income and cash flows.

Our gross deferred tax asset balance at year end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments, and assumptions regarding realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. In evaluating our ability to recover our deferred tax assets, in full or in part, we consider all available positive and negative evidence, including our past operating results and our forecast of future earnings, future taxable income, and prudent and feasible tax planning strategies. The assumptions utilized in determining future taxable income require significant judgment. Although we believe our assumptions, judgments, and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could have a material impact our consolidated financial statements.

Claims Reserves

We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability, and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.

Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and

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making estimates based upon historical experience with similar claims. The amount of our loss reserves for personal injury and protection claims is based on an analysis performed by a third-party actuary which uses our historical loss patterns and trends as well as industry data to estimate the unpaid loss and allocated loss adjustment expense. Claim severity experienced in each year, ranging from minor incidents to permanent disability or injuries requiring extensive medical care, is a key driver of the variability around our reserve estimates. These estimates are further subject to uncertainty because the ultimate disposition of claims incurred is subject to the outcome of events which have not yet transpired. Accordingly, we may be required to increase or decrease our reserve levels. At December 31, 2024, loss reserves for personal injury and protection claims totaled $164.1 million, of which $149.2 million was included in “Other current liabilities” and $14.9 million in “Other long-term liabilities” in the accompanying Consolidated Balance Sheets. At December 31, 2023, loss reserves for personal injury and protection claims totaled $63.9 million of which $21.9 million was included in “Other current liabilities” and $42.0 million in “Other long-term liabilities” in the accompanying Consolidated Balance Sheets.

Business Combinations

We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair value. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. To the extent the estimated fair value of the net assets acquired exceeded the purchase price, we recognize a bargain purchase gain. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of operations in periods after acquisition. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed.

Our estimates of fair value of the acquired property and equipment and contract intangibles require us to use significant unobservable inputs, representative of a Level 3 fair value measurement. Critical assumptions used in our estimate include projected dayrates, utilization, and discount rate. These projections involve uncertainties that rely on assumptions about current and future market conditions, timing of future contract awards, demand for our services, and marketability of a unit. It can be difficult to determine the fair value based on the cyclical nature of our business, demand for offshore drilling rigs in different markets, and changes in economic conditions.

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

The following discussion is intended to assist you in understanding our financial position at December 31, 2023 and 2022, and our results of operations for the years ended December 31, 2023 and 2022, the period from February 6 through December 31, 2021, and the period from January 1 through February 5, 2021.

The following discussion should be read in conjunction with the consolidated financial statements and related notes contained in this Annual Report on Form 10-K for the fiscal year ended December 31, 2023, filed by Noble.

Executive Overview

Noble is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. Our business strategy is centered around providing efficient, reliable, and safe offshore drilling services to our customers. We have one of the youngest and highest specification fleets of global scale in the industry, with diversification across asset classes, geographic regions, and customers. The Company has a track record of industry-leading utilization coupled with a commitment to best-in-class safety performance and customer satisfaction. We strive to be a leader in industry innovation and first-mover in sustainability.

Our fleet consists predominately of technologically advanced units, equipped with sophisticated systems and components prepared to execute our customers’ complicated offshore drilling programs safely and with greater efficiency. We are primarily focused on the ultra-deepwater market and the harsh and ultra-harsh environment jackup markets, which typically are more technically challenging markets in which to operate.

We emphasize safe operations, environmental stewardship, and superior performance through a structured management system, the employment of qualified and well-trained crews and onshore support staff, the care of our surroundings and the neighboring communities where we operate, and other activities advancing our environmental sustainability, social responsibility, and good governance. We also manage rig operating costs through the implementation and continuous improvement of innovative systems and processes, which includes the use of data analytics and predictive maintenance technology.

As of the filing date of this Annual Report on Form 10-K, our fleet of 32 drilling rigs consists of 19 floaters and 13 jackups strategically deployed worldwide. We typically employ each drilling unit under an individual contract, and many contracts are awarded based upon a competitive bidding process.

We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent, and government-owned or controlled oil and gas companies throughout the world.

For the year ended December 31, 2023, our financial and operating results include:

•operating revenues totaling $2.6 billion;

•net income of $481.9 million or $3.32 per diluted share;

•net cash provided by operating activities totaling $574.3 million;

•nothing drawn down on the 2023 Revolving Credit Facility as of December 31, 2023, and

•a year end cash balance of $360.8 million.

Demand for our services is driven by the offshore exploration and development programs of oil and gas operators, which in turn are influenced by many factors. Those factors include, but are not limited to, the price and price stability of oil and gas, the relative cost and carbon footprint of offshore resources within each operator’s broader energy portfolio, global macroeconomic conditions, world energy demand, the operator’s strategy toward renewable energy sources, environmental considerations, and governmental policies.

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Over the last decade, the offshore drilling industry has experienced significant volatility and change, which has meaningfully impacted both the supply of, and demand for, offshore rigs. After several years of a significantly oversupplied rig market, industry conditions had started to gradually improve in 2019, which was evidenced by increasing utilization and improving dayrates. However, in the first half of 2020, this gradual recovery was abruptly halted as oil prices experienced concurrent supply and demand shocks that were the result of disagreements among OPEC+ members and the global COVID-19 pandemic, respectively. This had a negative impact on both utilization and dayrates for the offshore drilling industry and led to further financial challenges for many drilling and other service companies. However, by early 2021, oil prices returned to pre-pandemic levels and continued to rise throughout 2021.

Since 2021, oil prices generally remained at levels that were supportive of offshore exploration and development activity. While the ongoing Russia-Ukraine conflict and related sanctions, inflationary pressures and the subsequent government and central bank efforts to curb inflation, recession concerns, and supply chain disruptions did create some uncertainty relating to future global energy demand, global rig demand has increased since 2021.

This increase in global demand has been the result of the combination of growing confidence in commodity prices remaining at or above current levels, heightened focus on energy security, recent multi-year underinvestment in the development and exploration of hydrocarbons, and relative attractiveness of offshore plays with respect to both cost and a carbon emissions perspective. This had a positive impact on both utilization and day rates for certain of our rig classes.

Outlook

In recent years, oil prices have generally remained at levels that are supportive of offshore exploration and development activity and global rig demand is increasing. This increasing demand has been caused by the combination of growing confidence in commodity prices, heightened focus on energy security, recent multi-year underinvestment in the development and exploration of hydrocarbons, and relative attractiveness of offshore plays with respect to both cost and carbon emissions. This increase had a positive impact on dayrates for certain of our rig classes.

The global rig supply has come down from historic highs as Noble and other offshore drilling contractors have retired less capable and idle assets. Concurrently, the incoming supply of newbuild offshore drilling rigs has diminished materially, with several newbuild rigs stranded in shipyards. However, we expect many of these stranded newbuild rigs may continue to make their way into the global market over the next few years.

Although the market outlook in our business varies by geographical region and water depth, we remain encouraged by the outlook in the ultra-deepwater floater market, with overall demand having increased from 2020 lows. Our customers continue to focus on the highest specification floaters, which represents the majority of our floater fleet. We have also observed an overall demand increase in the global jackup market, with the Middle East being the largest component of this increase. While we remain encouraged about the increasing overall rig demand, to the extent global macroeconomic concerns become more prevalent and produce downward pressure on oil and gas prices, we could experience downward pressure on overall rig demand for both floaters and jackups.

As of the date of this report, the majority of our jackup fleet is positioned in the North Sea. While we are starting to see some increased tender activity in the UK North Sea, overall activity levels in this region remain subdued compared to historical levels. The Norway ultra-harsh environment jackup market is similar, where current activity also remains below historical levels, despite the market being attractive to operators given it is characterized by low-cost and low-emission barrels.

While the length of contract terms has started to moderately increase, the overall market remains characterized by generally shorter-term contracts. This leads to an increased number of rig contract start-ups, both with different customers and among different regions. These rig contract start-ups and other shipyard projects may result in incremental resources and costs and, in certain cases, may delay delivery of the applicable rig which may trigger applicable late delivery clauses. The Noble Faye Kozak, currently undergoing a rig contract start-up, is delayed and currently expected to commence in early third quarter 2024 . Additionally, shorter-term contracts have resulted in, and is likely to continue to result in, lower overall utilization for our fleet driven by more idle time between contracts.

The energy transition from hydrocarbons to renewables poses a challenge to the oil and gas sector and our market. Energy rebalancing trends have accelerated in recent years as evidenced by promulgated or proposed government policies and commitments by many of our customers to further invest in sustainable energy sources. Our industry could be further challenged as our customers rebalance their capital investments more towards alternative energy sources. However, at the same time, there continues to be a global dependence on the combustion of hydrocarbons to provide reliable and affordable energy. Low-cost and low-emission barrels are expected to be the most attractive conventional source to meet

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energy needs, both currently and in the future. Global energy demand is predicted to increase over the coming decades, and we expect that offshore oil and gas will continue to play an important and lasting role in meeting this demand.

We expect inflationary pressures to persist, which has led or may lead to increased costs of services. Additionally, we expect supply chain disruptions to continue, and potentially accelerate, as geopolitical crises, such as the Russia-Ukraine conflict, Middle East conflicts, and the Guyana-Venezuela dispute, and their respective regional and global ramifications, have the potential to negatively impact our ability to conduct our day-to-day operations.

Contract Drilling Services Backlog

We maintain a backlog of commitments for contract drilling services. Our contract drilling services backlog reflects estimated future revenues attributable to signed drilling contracts. While backlog did not include any letters of intent as of December 31, 2023, in the past we have included in backlog certain letters of intent that we expect to result in binding drilling contracts. As of December 31, 2023, contract drilling services backlog totaled approximately $4.8 billion, which represents approximately 65% of available days for 2024.

We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period, and include certain assumptions based on the terms of certain contractual arrangements, discussed in the notes to the table below. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization, and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers, or amounts attributable to uncommitted option periods under drilling contracts or letters of intent.

The table below presents the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:

(1)Represents a twelve-month period beginning January 1. Some of our drilling contracts provide customers with certain early termination rights and, in limited cases, those termination rights require minimal or no notice and minimal financial penalties.

(2)One of our long-term drilling contracts with Shell plc, the Noble Globetrotter II, contains a dayrate adjustment mechanism that utilizes an average of market rates that match a set of distinct technical attributes and is subject to a modest discount, beginning on the fifth-year anniversary of the contract and continuing every six months thereafter. The contract now has a contractual dayrate floor of $275,000 per day. The dayrate for this rig will not be lower than the higher of (i) the contractual dayrate floor or (ii) the market rate as calculated under the adjustment mechanism.

(3)Noble entered into a multi-year Commercial Enabling Agreement (the “CEA”) with ExxonMobil in February 2020. Under the CEA, dayrates earned by each rig will be updated twice per year to the projected market rate at the time the new rate goes into effect, subject to a scale-based discount and a performance bonus that appropriately aligns the interests of Noble and ExxonMobil. Under the CEA, the table above includes awarded and remaining term of three years and five months related to each of the four following rigs: the Noble Tom Madden, Noble Bob Douglas, Noble Don Taylor, and Noble Sam Croft. Under the CEA, ExxonMobil may reassign terms among rigs.

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(4)In 2022, Noble renewed its five-year Framework Agreement with Aker BP for the provision of ultra-harsh environment jackup rigs, the Noble Integrator and Noble Invincible, for activities offshore Norway. Under the Framework Agreement, different rate structures apply reflecting different operating modes, agreed incentive schemes, and adjustments for operating expenses. Rate structures are adjusted annually to reflect market conditions.

(5)Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period by the product of the number of our rigs, including cold-stacked rigs, and the number of calendar days in such period.

The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods presented in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, the operation of market benchmarks for dayrate resets, achievement of bonuses, weather conditions, reduced standby or mobilization rates, and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. See Part I, Item 1A, “Risk Factors—Risks Related to Our Business and Operations—Our current backlog of contract drilling revenue may not be ultimately realized.”

As of December 31, 2023, ExxonMobil, Aker BP, and Petrobras represented approximately 42.5%, 15.3%, and 12.9% of our backlog, respectively.

Results of Operations

Results for the years ended December 31, 2023 and 2022

Net income for the year ended December 31, 2023, was $481.9 million, or $3.32 per diluted share, on operating revenues of $2.6 billion compared to net income for the year ended December 31, 2022, of $168.9 million, or $1.73 per diluted share, on operating revenues of $1.4 billion.

Key Operating Metrics

Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates, and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “Contract Drilling Services” below.

The following table presents the average rig utilization, operating days, and average dayrates for our rig fleet for the periods indicated.

(1)We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet.

(2)An operating day is defined as a calendar day during which a rig operated under a drilling contract. We define average dayrates as revenue from contract drilling services earned per operating day. Average dayrates have not been adjusted for the non-cash amortization related to favorable and unfavorable customer contract intangibles.

(3)Figures in the table include the rigs acquired in connection with the Business Combination and exclude the five jackup rigs (each a “Remedy Rig,” and collectively the “Remedy Rigs”) sold in October 2022.

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Contract Drilling Services

The following table presents the operating results for our contract drilling services segment for the period indicated (dollars in thousands):

(1)We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations, or cash flows.

Contract Drilling Services Revenues

The following table provides information about contract drilling services revenues and costs by rig types (dollars in millions except average dayrates):

Floaters. During the year ended December 31, 2023, floaters generated revenue of $2.0 billion, as compared to $997.8 million in year ended December 31, 2022. The increase in revenue was mainly attributable to $581.2 million provided by the eight additional floaters acquired in the Business Combination with Maersk Drilling in October 2022 as well as $360.2 million due to an increase in average dayrates across the remainder of the fleet in the current period. These increases were partly offset by $5.0 million from fewer operating days across the remainder of the fleet in the current period. Additionally, floater revenue from net non-cash amortization related to off-market customer contract assets and liabilities increased $76.0 million in the current period.

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Jackups. During the year ended December 31, 2023, jackups generated revenue of $451.6 million, as compared to $335.0 million in year ended December 31, 2022. The increase in revenue was mainly attributable to $201.4 million provided by the 10 additional jackups acquired in the Business Combination with Maersk Drilling in October 2022 as well as $3.4 million due to an increase in average dayrates across the remainder of the fleet in the current period. These increases were partly offset by $66.8 million pertaining to the divestiture of the Remedy Rigs in October 2022 in connection with the Business Combination with Maersk Drilling and $46.9 million from less operating days across the remainder of the fleet. Additionally, jackups revenue from net non-cash amortization related to off-market customer contract assets and liabilities increased $25.5 million in the current period.

Operating Costs and Expenses

Floaters. During the year ended December 31, 2023, total contract drilling services cost related to floaters was $1.1 billion, as compared to $600.2 million in year ended December 31, 2022. The primary drivers of the increase were $335.0 million related to the eight additional floaters acquired in the Business Combination with Maersk Drilling in October 2022 and $180.6 million in increased crew, repairs and maintenance, and material costs across the remainder of the fleet. These increases were offset by $3.9 million due to the divestiture of a semisubmersible unit late in the first quarter of 2022.

Jackups. During the year ended December 31, 2023, total contract drilling services cost related to jackups was $340.0 million, as compared to $296.9 million in year ended December 31, 2022. The increase was primarily driven by $136.2 million related to the 10 additional jackups acquired in the Business Combination with Maersk Drilling in October 2022. These increases were partially offset by the reduction of $81.5 million in expenses after the sale of the Remedy Rigs in October 2022.

Depreciation and amortization. Depreciation and amortization totaled $301.3 million and $146.9 million during the years ended December 31, 2023 and 2022, respectively. The increase of $154.5 million was primarily due to $132.1 million related to 18 rigs and related equipment acquired in the Business Combination with Maersk Drilling in October 2022. This increase was partially offset by the sale of the Remedy Rigs in October 2022 and the divestiture of a semisubmersible unit in the first quarter of 2022.

General and administrative. General and administrative expenses totaled $128.4 million and $82.2 million during the years ended December 31, 2023 and 2022, respectively. The increase was primarily related to the Business Combination with Maersk Drilling in October 2022 with increases across several categories including employee related costs.

Merger and integration costs. Noble incurred $60.3 million and $84.7 million of merger and integration costs during the years ended December 31, 2023 and 2022, respectively, primarily in connection with the Business Combination with Maersk Drilling in October 2022. Costs primarily related to severance plans and share-based compensation charges, transaction-related acquisition costs, professional fees, and certain integration-related activities that were directly attributable to the Business Combination. During the year ended December 31, 2023, merger and integration costs declined compared to the year ended December 31, 2022, primarily due to decreases in professional fees and severance costs. This decrease was partly offset by an increase in costs and professional fees incurred to integrate systems. For additional information, see “Note 4 — Acquisitions and Divestitures” and “Note 5 — Merger and Integration Costs” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Gain on sale of operating assets, net. During the year ended December 31, 2022, Noble recognized a gain, net of transaction costs, of $90.2 million in connection with the sale of the Remedy Rigs and the Noble Clyde Boudreaux. For additional information, see “Note 4 — Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Hurricane losses and recoveries, net. Noble recognized $31.8 million of costs during the year ended December 31, 2023, in connection with the Hurricane Ida incident, which was offset by the recognition of insurance recoveries of $51.5 million. During the year ended December 31, 2022, Noble recognized $22.0 million of costs, which was offset by the recognition of insurance recoveries of $21.9 million. For additional information, see “Note 14 — Commitments and Contingencies” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Other Income and Expenses

Interest expense, net of amounts capitalized. Interest expense totaled $59.1 million and $42.7 million for the years ended December 31, 2023 and 2022, respectively. The increase was due to the additional debt assumed in the Business Combination with Maersk Drilling in October 2022, which was refinanced by the issuance of 8.000% Senior Notes in April 2023. For additional information, see “Note 8 — Debt“ to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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Gain (loss) on extinguishment of debt, net. Noble recognized loss on extinguishment of debt of $26.4 million for the year ended December 31, 2023, related to the redemption of the remaining balance on our Second Lien Notes and refinancing of other debt. For additional information, see “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Interest income and other, net. Noble recognized other income of $18.1 million for the year ended December 31, 2023, primarily related to the recognition of approximately $19.1 million of compensation related to a joint taxation scheme with A.P. Møller Holding A/S. For additional information, see “Note 12 — Income Taxes” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. We recognized other income of $14.4 million for the year ended December 31, 2022.

Gain on bargain purchase. Noble recognized a $5.0 million gain on the bargain purchase of Maersk Drilling for the year ended December 31, 2023. For additional information, see “Note 4 — Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Income tax benefit (provision). Noble recorded an income tax provision of $30.3 million and $22.6 million during the years ended December 31, 2023 and 2022, respectively.

During the year ended December 31, 2023, our tax provision included tax benefits of $187.2 million related to a release of valuation allowances in Luxembourg, Guyana, Switzerland, and Norway, and a tax benefit of $6.8 million related to an uncertain tax position release. Such tax benefits were offset by tax expenses related to uncertain tax positions of $20.9 million in various countries, contract fair value amortization of $23.7 million, and various recurring quarterly accruals of $179.6 million primarily in Guyana, Switzerland, and Luxembourg.

During the year ended December 31, 2022, our tax provision included tax benefits of $42.1 million related to a release of valuation allowance in Guyana and Luxembourg, $1.3 million related primarily to other deferred tax adjustments, and $6.6 million related to a reduction in legacy Maersk tax contingencies primarily due to favorable foreign exchange movements. Such tax benefits were offset by tax expenses of $2.3 million related to the sale of the Remedy Rigs, $10.8 million related to contract fair value amortization, and various recurring items comprised of Guyana excess withholding tax on gross revenue of $34.7 million and annual current and deferred tax expense accrual of $24.9 million primarily in Luxembourg, Switzerland, US, Norway, and Ghana.

2022 Compared to 2021

Information related to a comparison of our results of operations for the year ended December 31, 2022, compared to the period from February 6 through December 31, 2021, (“Prior Year Successor Period”) and the period from January 1 through February 5, 2021, (“Prior Year Predecessor Period”) is included in Part II, Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, filed with the SEC on March 9, 2023.

Liquidity and Capital Resources

Debt Refinancing

In April 2023, Noble Finance II, LLC (“Noble Finance II”), a wholly owned subsidiary of Noble, issued $600.0 million in aggregate principal amount of its 8.000% Senior Notes due 2030 (“2030 Notes”). The 2030 Notes were issued pursuant to an indenture, dated April 18, 2023, among Noble Finance II, the subsidiaries of Noble Finance II party thereto, as guarantors, and U.S. Bank Trust Company, National Association, as trustee. The net proceeds from the offering of 2030 Notes were primarily used to (i) repay the approximately $347.5 million of outstanding borrowings under the New DNB Credit Facility (as defined below), (ii) redeem (the “Redemption”) the approximately $173.7 million aggregate principal amount of outstanding Second Lien Notes, and (iii) pay any premiums, fees, and expenses related to the Redemption and the issuance of the 2030 Notes. As of December 31, 2023, we had outstanding $600.0 million aggregate principal amount of our 2030 Notes.

Amended and Restated Senior Secured Revolving Credit Agreement

On April 18, 2023, certain subsidiaries of Noble amended and restated the senior secured credit facility, dated February 5, 2021, by entering into an Amended and Restated Senior Secured Revolving Credit Agreement, dated April 18, 2023 (the “2023 Revolving Credit Agreement”), by and among Noble Finance II, Noble International Finance Company (“NIFCO”) and Noble Drilling A/S, as borrowers (the “Borrowers”), the lenders and issuing banks party thereto from time to time and JPMorgan Chase Bank, N.A., as administrative agent, collateral agent and security trustee. The revolving credit facility under the 2023 Revolving Credit Agreement (the “2023 Revolving Credit Facility”) provides for commitments of $550.0 million with

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maturity in April 2028. The guarantors under the 2023 Revolving Credit Facility are the same subsidiaries of Noble Finance II that are or will be guarantors of the 2030 Notes.

As of December 31, 2023, we had no borrowings outstanding and $7.4 million of letters of credit issued under our 2023 Revolving Credit Facility and an additional $108.1 million in letters of credit and surety bonds issued under bilateral arrangements. For additional information about our 2023 Revolving Credit Facility, see “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Second Lien Notes

On the Emergence Effective Date, pursuant to the Backstop Commitment Agreement, dated October 12, 2020, among the Debtors and the backstop parties thereto, Noble Cayman and Finco consummated the Rights Offering of the Second Lien Notes and associated Noble Cayman Shares at an aggregate subscription price of $200.0 million. On April 18, 2023, we redeemed the remaining balance of approximately $173.7 million aggregate principal amount of outstanding Second Lien Notes using a portion of the proceeds from the offering of the 2030 Notes, and recognized a loss of approximately $25.7 million. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Debt Open Market Repurchases

In the third and fourth quarter of 2022, we purchased $42.3 million aggregate principal amount of our Second Lien Notes for approximately $48.1 million, plus accrued interest, as open market repurchases and recognized a loss of approximately $4.6 million.

DNB Credit Facility and New DNB Credit Facility

Upon the Closing Date, Noble guaranteed the Term and Revolving Facilities Agreement dated December 6, 2018, by and among Maersk Drilling, the rig owners and material intragroup charterers party thereto and DNB Bank ASA as agent (as amended from time to time, the “DNB Credit Facility”). On December 22, 2022, the DNB Credit Facility and related Noble guarantee were terminated and, Maersk Drilling, as the borrower, the Company, as parent guarantor, certain subsidiaries of Maersk Drilling as guarantors, and the lenders identified therein, with DNB Bank ASA, New York Branch acting as Agent entered into a new Term Facility Agreement (the “New DNB Credit Facility”). On April 18, 2023, we repaid the $347.5 million of outstanding borrowings under the New DNB Credit Facility using a portion of the proceeds from the offering of the 2030 Notes, and recognized a loss of approximately $0.7 million. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

DSF Credit Facility

The Company guaranteed the Term Loan Facility Agreement dated December 10, 2018, by and between Maersk Drilling and Danmarks Skibskredit A/S as lender, agent, and security agent (as amended from time to time, the “DSF Credit Facility”) in connection with the Business Combination with Maersk Drilling that closed on October 3, 2022. The DSF Credit Facility was repaid in full on February 23, 2023, using cash on hand and the facility is no longer in place as of December 31, 2023. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Sources and Uses of Cash

Our principal sources of capital in 2023 were cash generated from operating activities as well as net proceeds from the issuance of the 2030 Notes. Cash on hand during the current period was primarily used for the following:

•normal recurring operating expenses;

•planned and discretionary capital expenditures;

•repurchase, redemptions, or repayments of debt and interest;

•fees and expenses related to merger and integration costs;

•share repurchases and dividend payments; and

•certain contractual cash obligations and commitments.

Our anticipated cash flow needs, both in the short term and long term, may also include the above.

We currently expect to fund our cash flow needs with cash generated by our operations, cash on hand, proceeds from sales of assets, or borrowings under the 2023 Revolving Credit Facility and we believe this will provide us with sufficient liquidity to fund our cash flow needs over the next 12 months. Subject to market conditions and other factors, we may also issue equity or long-term debt securities to fund our cash flow needs and for other purposes. In 2022 and 2023, we incurred and, in 2024, we anticipate to incur, additional expenses and capital costs related to the damage and repair of a jackup rig. These

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incurred costs exceeded our $5.0 million deductible in 2022. We received partial insurance recoveries in 2023 and we continue to seek insurance recoveries for the remainder of the incurred and anticipated costs.

Net cash provided by operating activities was $574.3 million and $281.0 million for the years ended December 31, 2023 and 2022, respectively. Net cash provided by operating activities increased mainly due to the Business Combination with Maersk Drilling. We had working capital balances of $420.1 million and $384.7 million at December 31, 2023 and 2022, respectively.

Net cash used in investing activities was $366.5 million for the year ended December 31, 2023, and consisted of capital expenditures on routine projects associated with overhauls and upgrades on various rigs in the newly combined fleet. Net cash provided by investing activities was $375.8 million for the year ended December 31, 2022, and included proceeds from the sale of the Remedy Rigs and cash acquired in the Business Combination with Maersk Drilling.

Net cash used in financing activities was $325.8 million and $367.8 million for the years ended December 31, 2023 and 2022, respectively. The year ended December 31, 2023, included the repayment of the DSF Credit Facility in full, using cash on hand, redemption of the remaining balance of the Second Lien Notes, repayment of the DNB Credit Facility, and issuance of 2030 Notes. We also repurchased 2.3 million of our Ordinary Shares for total of $94.8 million and made dividend payments to our shareholders of $98.8 million. During the year ended December 31, 2022, we refinanced part of the assumed debt from the Business Combination, resulting in a net pay down of $277.3 million, and utilized approximately $48.1 million of cash to repurchase $42.3 million aggregate principal amount of our Second Lien Notes, plus accrued interest, as open market repurchases and recognized a loss of approximately $4.6 million. The Compulsory Purchase was completed in the fourth quarter of 2022, at a cost of $69.9 million, paid in DKK and 4.1 million shares issued.

At December 31, 2023, we had a total contract drilling services backlog of approximately $4.8 billion, which includes a commitment of 65% of available days for 2024. For additional information regarding our backlog, see “— Contract Drilling Services Backlog.”

Capital Additions

Capital additions totaled $454.3 million and $193.6 million for the years ended December 31, 2023 and 2022, respectively. Capital additions for the year ended December 31, 2023, consisted of the following:

•$258.9 million for sustaining capital;

•$166.7 million in major projects, including subsea and other related projects; and

•$28.7 million for rebillable capital and contract modifications.

Our total capital additions estimate for 2024, net of reimbursements, is expected to range between $400.0 million and $440.0 million, of which approximately $270.0 million to $300.0 million is currently anticipated to be spent for sustaining capital. We expect to fund these capital additions with cash generated by our operations and cash on hand.

From time to time we consider possible projects and may have certain events that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, while liquidity and preservation of capital remains our top priority, we will continue to evaluate acquisitions of drilling units from time to time.

Dividends

Our most recent quarterly dividend, totaling approximately $56.4 million (or $0.40 per share), was declared on October 31, 2023, and paid on December 14, 2023, to shareholders of record at close of business on November 15, 2023. During the year ended December 31, 2023, we declared dividends of approximately $101.8 million, including accrued dividends, (or $0.70 per share), and made cash dividend payments of approximately $98.8 million.

On February 22, 2024, our Board of Directors approved a declaration of a quarterly cash interim dividend on our Ordinary Shares of $0.40 per share. This dividend is to be payable on March 21, 2024, to shareholders of record at close of business on March 08, 2024.

The declaration and payment of dividends require authorization of the Board of Directors, provided that such dividends on issued share capital may be paid only out of the Company’s “distributable reserves” as determined by reference to relevant statutory accounts in accordance with English law. The Company is not permitted to pay dividends out of share capital, which includes share premiums. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, the availability of sufficient distributable reserves, contractual and indenture restrictions, and other factors deemed relevant by our Board.

Share Repurchases

Under law, the Company is only permitted to purchase its own Ordinary Shares by way of an “off-market purchase” pursuant to a contract approved by shareholders. Such purchases may be paid for only out of Noble’s “distributable

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reserves” as determined by reference to relevant statutory accounts in accordance with law. As of the date of this report, we have shareholder authority to repurchase up to 15% per annum of the issued share capital of the Company as of the beginning of each fiscal year for a five-year period (subject to an overall aggregate maximum of 20,601,161 Ordinary Shares). During the year ended December 31, 2023, we repurchased 2.3 million of our Ordinary Shares, which were subsequently cancelled.

Summary of Contractual Cash Obligations and Commitments

We have $202.3 million of long-term tax reserves for uncertain tax positions, including interest and penalties, which are included in “Other liabilities” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See “Note 12 — Income Taxes” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2023, no long-term debt is due in the next twelve months and $600.0 million will be due subsequent to 2024. See “Note 8 — Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. We may seek to refinance all or a portion of our long-term debt obligations, including the 2023 Revolving Credit Facility, though any such refinancing transactions are subject to market and other conditions and there are no assurances that we will complete any such transactions, in whole or in part, or as to the amount or timing of any such transactions.

At December 31, 2023, $12.6 million of pension obligations will be due in the next twelve months and the remainder of $125.0 million will be due subsequent to 2024. See “Note 13 — Employee Benefit Plans” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. In addition, $9.9 million is due on a long-term basis under the Danish Holiday Act of 2020.

For a description of our operating lease obligations, refer to “Note 11 — Leases” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2023, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit that guarantee our performance as it relates to our drilling contracts, tax, and other obligations in various jurisdictions. We expect to comply with the underlying performance requirements and we expect obligations under these letters of credit and surety bonds will not be called. At December 31, 2023, $16.9 million letters of credit and commercial commitments will expire in the next twelve months and the remainder of $98.6 million will expire subsequent to 2024.

We expect to fund these obligations and commitments with cash generated by our operations and cash on hand.

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“US GAAP”), which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from our estimates and assumptions and any such differences could be material to our consolidated financial statements. The following accounting policies involve critical accounting estimates because they are particularly dependent on estimates and assumptions made by Noble about matters that are inherently uncertain.

Recoverability of Assets

We evaluate our property and equipment and intangible assets for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. An impairment loss is recognized when and to the extent that an asset's carrying value exceeds its estimated fair value. To the extent actual results do not meet our estimated assumptions for a given rig, piece of equipment or intangible customer contract, we may take an impairment loss in the future. In determining the fair value of the assets, we make significant assumptions and estimates regarding future market conditions. Typical assumptions used in our estimate include current market conditions, timing of future contract awards, and expected operating dayrates, operating costs, utilization rates, discount rates, capital expenditures, market values, weighting of market values, reactivation costs, estimated economic useful lives, and marketability of a unit.

During the years ended December 31, 2023 and 2022, no impairment charges were recognized.

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Impairment assessment inherently involves management judgments as to assumptions about expected future cash flows and the impact of market conditions on those assumptions. Due to the many variables inherent in this estimation, differences in assumptions may have a material effect on the results of our impairment analysis.

Income Taxes

We estimate income taxes and file tax returns in each of the taxing jurisdictions in which we operate and are required to file a tax return. At the end of each year, an estimate for income taxes is recorded in the financial statements. Tax returns are generally filed in the subsequent year. A reconciliation of the estimate to the final tax return is done at that time, which will result in changes to the original estimate. We believe that our tax return positions are appropriately supported, but tax authorities can challenge certain of our tax positions.

We currently operate, and have in the past operated, in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50% likelihood of being sustained upon challenge by a tax authority. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. A change in judgment related to the expected ultimate resolution of uncertain tax positions will be recognized in earnings in the quarter of such change. We believe that our reserve for uncertain tax positions, including related interest and penalties, is adequate. As of December 31, 2023 and 2022, the Company had $202.3 million and $175.9 million of long-term tax reserves for unrecognized tax benefits, including interest and penalties, which are included in “Other liabilities.” The amounts ultimately paid upon resolution of audits could be materially different from the amounts previously included in our income tax expense and, therefore, could have a material impact on our tax provision, net income and cash flows.

Our gross deferred tax asset balance at year end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments, and assumptions regarding realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. In evaluating our ability to recover our deferred tax assets, in full or in part, we consider all available positive and negative evidence, including our past operating results and our forecast of future earnings, future taxable income, and prudent and feasible tax planning strategies. The assumptions utilized in determining future taxable income require significant judgment. Although we believe our assumptions, judgments, and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could have a material impact our consolidated financial statements.

Claims Reserves

We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability, and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.

Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. The amount of our loss reserves for personal injury and protection claims is based on an analysis performed by a third-party actuary which uses our historical loss patterns and trends as well as industry data to estimate the unpaid loss and allocated loss adjustment expense. Claim severity experienced in each year, ranging from minor incidents to permanent disability or injuries requiring extensive medical care, is a key driver of the variability around our reserve estimates. These estimates are further subject to uncertainty because the ultimate disposition of claims incurred is subject to the outcome of events which have not yet transpired. Accordingly, we may be required to increase or decrease our reserve levels. At December 31, 2023, loss reserves for personal injury and protection claims totaled $63.9 million, of which $21.9 million was included in “Other current liabilities” and $42.0 million in “Other long-term liabilities” in the accompanying Consolidated Balance Sheets. At December 31, 2022, loss reserves for personal injury and protection claims totaled $35.3 million of which $15.5 million was included in “Other current liabilities” and $19.8 million in “Other long-term liabilities” in the accompanying Consolidated Balance Sheets.

Business Combinations

We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair value. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. To the extent the estimated fair value of the net assets acquired exceeded the purchase price, we recognize a bargain purchase gain. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of

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operations in periods after acquisition. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed.

Our estimates of fair value of the acquired property and equipment and contract intangibles require us to use significant unobservable inputs, representative of a Level 3 fair value measurement, such as assumptions related to future marketability of each unit in light of the current market conditions and its current technical specifications, timing of future contract awards, and expected operating dayrates, operating costs, rig utilization rates, tax rates, discount rate, capital expenditures, synergies, market values, estimated economic useful lives of the rigs and, in certain cases, management’s belief that a drilling unit is no longer marketable and is unlikely to return to service in the near to medium term. It can be difficult to determine the fair value based on the cyclical nature of our business, demand for offshore drilling rigs in different markets, and changes in economic conditions.

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

The following discussion is intended to assist you in understanding our financial position at December 31, 2022 and 2021, and our results of operations for the year ended December 31, 2022, the period from February 6 through December 31, 2021, and the period from January 1 through February 5, 2021.

The following discussion should be read in conjunction with the consolidated financial statements and related notes contained in this Annual Report on Form 10-K for the fiscal year ended December 31, 2022 filed by Noble and Finco.

Executive Overview

Noble is a leading offshore drilling contractor for the oil and gas industry. We provide contract drilling services to the international oil and gas industry with our global fleet of mobile offshore drilling units. Our business strategy is centered around providing efficient, reliable and safe offshore drilling services to our customers. The Business Combination with Maersk Drilling created one of the youngest and highest specification fleets of global scale in the industry, with diversification across asset classes, geographic regions and customers. The Combined company has a track record of industry-leading utilization; coupled with an unwavering commitment to best-in-class safety performance and customer satisfaction. We strive to be a leader in industry innovation and first-mover in sustainability.

Our fleet consists predominately of technologically advanced units, equipped with sophisticated systems and components prepared to execute our customers’ increasingly complicated offshore drilling programs safely and with greater efficiency. We are primarily focused on the ultra-deepwater market and the harsh, and ultra-harsh environment jackup markets, which typically are more technically challenging markets in which to operate.

We emphasize safe operations, environmental stewardship, and superior performance through a structured management system, the employment of qualified and well-trained crews and onshore support staff, the care of our surroundings and the neighboring communities where we operate, and other activities advancing our environmental sustainability, social responsibility, and good governance. We also manage rig operating costs through the implementation and continuous improvement of innovative systems and processes, which includes the use of data analytics and predictive maintenance technology.

As of the filing date of this Annual Report on Form 10-K, our fleet of 32 drilling rigs consisted of 19 floaters and 13 jackups strategically deployed worldwide. We typically employ each drilling unit under an individual contract, and many contracts are awarded based upon a competitive bidding process.

We report our contract drilling operations as a single reportable segment, Contract Drilling Services, which reflects how we manage our business. The mobile offshore drilling units comprising our offshore rig fleet operate in a global market for contract drilling services and are often redeployed to different regions due to changing demands of our customers, which consist primarily of large, integrated, independent and government-owned or controlled oil and gas companies throughout the world.

For the year ended December 31, 2022 our financial and operating results include:

•operating revenues totaling $1,413.8 million;

•net income of $168.9 million or $1.73 per diluted share;

•net cash provided by operating activities totaling $281.0 million;

•successful completion of the Business Combination with Maersk Drilling; and

•nothing drawn down on the Revolving Credit Facility as of December 31, 2022 and cash of $476.2 million.

Demand for our services is driven by the offshore exploration and development programs of oil and gas operators, which in turn are influenced by many factors. Those factors include, but are not limited to, the price and price stability of oil and gas, the relative cost and carbon footprint of offshore resources within each operator’s broader energy portfolio, global

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macroeconomic conditions, world energy demand, the operator’s strategy toward renewable energy sources, environmental considerations and governmental policies.

Over the last decade, the offshore drilling industry has experienced significant volatility and change, which has meaningfully impacted both the supply of, and demand for, offshore rigs. After several years of a significantly oversupplied rig market, industry conditions had started to gradually improve in 2019, which was evidenced by increasing utilization and improving dayrates. However, in the first half of 2020, this gradual recovery was abruptly halted as oil prices experienced concurrent supply and demand shocks. The supply shock was driven by production disagreements among OPEC+ members that resulted in a sudden and a significant oversupply of oil, and the demand shock by the onset of the global COVID-19 pandemic that resulted in a meaningful reduction in global economic activity and produced significant uncertainty among our customers. This had a negative impact on both utilization and dayrates for the offshore drilling industry and led to further financial challenges for many drilling and other service companies. However, by early 2021, oil prices returned to pre-pandemic levels and continued to rise throughout 2021.

During 2022, oil prices generally remained at levels that were supportive of offshore exploration and development activity. While the ongoing Russia-Ukraine conflict and related sanctions, inflationary pressures and the subsequent government and central bank efforts to curb inflation, recession concerns, and supply chain disruptions did create some uncertainty relating to future global energy demand, global rig demand increased in 2022.

This rise was the result of the combination of growing confidence in commodity prices remaining at or above current levels, heightened focus on energy security, recent multi-year underinvestment in the development and exploration of hydrocarbons, and relative attractiveness of offshore plays with respect to both cost and a carbon emissions perspective resulted in an overall increase in global rig demand in 2022. This had a positive impact on both utilization and day rates for certain of our rig classes.

Recent Events

Business Combination with Maersk Drilling. On the Closing Date, pursuant to the Business Combination Agreement, Noble completed the Offer and the Compulsory Purchase was completed in mid-November 2022, at which time Maersk Drilling became a wholly owned subsidiary of Noble. On October 5, 2022, Noble and Shelf Drilling (North Sea), Ltd. and Shelf Drilling, Ltd. (together, “Shelf Drilling”) completed the sale by Noble and the purchase by Shelf Drilling (the “Rig Transaction”) of five jackup rigs (the “Remedy Rigs”) and all related support and infrastructure (collectively, and together with the related offshore and onshore personnel and related operations, the “Divestment Business”), for a purchase price of $375 million in cash.

For additional information on the Business Combination, see “Note 4— Acquisitions and Divestitures” to our consolidated financial statements included in Item 8 of Part II of this Annual Report on Form 10-K.

Listing. The Noble Cayman Shares, which traded under the symbol “NE” on the New York Stock Exchange (the “NYSE”), were suspended from trading on the NYSE prior to the open of trading on the Merger Effective Date. The Ordinary Shares began regular-way trading on the NYSE using Noble Cayman’s trading history under the symbol “NE” immediately following the suspension of trading of the Noble Cayman Shares on the Merger Effective Date. In addition, the Ordinary Shares were listed and began trading on Nasdaq Copenhagen under the symbol “NOBLE” in connection with the closing of the Business Combination.

Outlook

During 2022, oil prices generally remained at levels that were supportive of offshore exploration and development activity. While the ongoing Russia-Ukraine conflict and related sanctions, inflationary pressures and the subsequent government and central bank efforts to curb inflation, recession concerns, and supply chain disruptions did create some uncertainty relating to future global energy demand, global rig demand increased in 2022.

The global rig supply has come down from historic highs as Noble and other offshore drilling contractors have retired less capable and idle assets. Concurrently, the incoming supply of newbuild offshore drilling rigs has diminished materially, with several newbuild rigs stranded in shipyards. However, we expect many of these stranded newbuild rigs may make their way into the global market over the next few years.

Although the market outlook in our business varies by geographical region and water depth, we remain encouraged by the recovery in the ultra-deepwater floater market, with overall demand having increased from 2020 lows. Our customers continue to focus on the highest specification floaters, which represents the majority of our floater fleet. We have also

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experienced an overall increase in the global jack-up market, with the Middle East being the largest component of this increase.

The energy transition from hydrocarbons to renewables poses a challenge to the oil and gas sector and our market. Energy rebalancing trends have accelerated in recent years as evidenced by promulgated or proposed government policies and commitments by many of our customers to further invest in sustainable energy sources. Our industry could be further challenged as our customers rebalance their capital investments more towards alternative energy sources. However, at the same time, there continues to be a global dependence on the combustion of hydrocarbons to provide reliable and affordable energy. Low-cost and low-emission barrels are still necessary to meet energy needs, both current and future. Global energy demand is predicted to increase over the coming decades, and we expect that offshore oil and gas will continue to play an important and sustainable role in meeting this demand.

We expect inflationary pressures and supply chain disruptions to persist, and potentially accelerate, which has led or may lead to increased costs of services.

Contract Drilling Services Backlog

We maintain a backlog of commitments for contract drilling services. Our contract drilling services backlog reflects estimated future revenues attributable to signed drilling contracts. While backlog did not include any letters of intent as of December 31, 2022, in the past we have included in backlog certain letters of intent that we expect to result in binding drilling contracts. As of December 31, 2022, contract drilling services backlog totaled approximately $3.9 billion, which represents approximately 57 percent of available days for 2023.

We calculate backlog for any given unit and period by multiplying the full contractual operating dayrate for such unit by the number of days remaining in the period, and include certain assumptions based on the terms of certain contractual arrangements, discussed in the notes to the table below. The reported contract drilling services backlog does not include amounts representing revenues for mobilization, demobilization and contract preparation, which are not expected to be significant to our contract drilling services revenues, amounts constituting reimbursables from customers or amounts attributable to uncommitted option periods under drilling contracts or letters of intent. Backlog herein also has not been adjusted for the non-cash amortization related to favorable customer contract intangibles which were recognized on the Emergence Effective Date.

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The table below presents the amount of our contract drilling services backlog and the percent of available operating days committed for the periods indicated:

(1)Represents a twelve-month period beginning January 1. Some of our drilling contracts provide customers with certain early termination rights and, in limited cases, those termination rights require minimal or no notice and minimal financial penalties.

(2)One of our long-term drilling contracts with Shell, the Noble Globetrotter II, contains a dayrate adjustment mechanism that utilizes an average of market rates that match a set of distinct technical attributes and is subject to a modest discount, beginning on the fifth-year anniversary of the contract and continuing every six months thereafter. The contract now has a contractual dayrate floor of $275,000 per day. The dayrate for this rig will not be lower than the higher of (i) the contractual dayrate floor or (ii) the market rate as calculated under the adjustment mechanism.

(3)Noble entered into a multi-year Commercial Enabling Agreement (the “CEA”) with ExxonMobil in February 2020. Under the CEA, dayrates earned by each rig will be updated twice per year to the projected market rate at the time the new rate goes into effect, subject to a scale-based discount and a performance bonus that appropriately aligns the interests of Noble and ExxonMobil. Under the CEA, the table above includes awarded and remaining term of two years and 11 months related to each of the four following rigs: the Noble Tom Madden, Noble Bob Douglas, Noble Don Taylor and Noble Sam Croft. Under the CEA, ExxonMobil may reassign terms among rigs.

(4)Percent of available days committed is calculated by dividing the total number of days our rigs are operating under contract for such period by the product of the number of our rigs, including cold-stacked rigs, and the number of calendar days in such period.

The amount of actual revenues earned and the actual periods during which revenues are earned may be materially different than the backlog amounts and backlog periods presented in the table above due to various factors, including, but not limited to, shipyard and maintenance projects, unplanned downtime, the operation of market benchmarks for dayrate resets, achievement of bonuses, weather conditions, reduced standby or mobilization rates and other factors that result in applicable dayrates lower than the full contractual operating dayrate. In addition, amounts included in the backlog may change because drilling contracts may be varied or modified by mutual consent or customers may exercise early termination rights contained in some of our drilling contracts or decline to enter into a drilling contract after executing a letter of intent. As a result, our backlog as of any particular date may not be indicative of our actual operating results for the periods for which the backlog is calculated. See Part I, Item 1A, “Risk Factors—Risks Related to Our Business and Operations—Our current backlog of contract drilling revenue may not be ultimately realized.”

As of December 31, 2022, ExxonMobil and Aker BP represented approximately 41.1 percent and 21.5 percent of our backlog, respectively.

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Results of Operations

Results for the year ended December 31, 2022 compared to the period from February 6 through December 31, 2021 (“Prior Year Successor Period”) and the period from January 1 through February 5, 2021 (“Prior Year Predecessor Period”)

Net income for the year ended December 31, 2022 was $168.9 million, or $1.73 per diluted share, on operating revenues of $1.4 billion. Net income for the Prior Year Successor Period was $102.0 million, or $1.51 per diluted share, on operating revenues of $770.3 million. Net income for the Prior Year Predecessor Period was $250.2 million, or $0.98 per diluted share, on operating revenues of $77.5 million.

As a result of Noble conducting all of its business through Finco and its subsidiaries, the financial position and results of operations for Finco, and the reasons for material changes in the amount of revenue and expense items for the year ended December 31, 2022 and the Prior Year Successor Period and the Prior Year Predecessor Period would be the same as the information presented below regarding Noble in all material respects, with the exception of operating income (loss), the gain on bargain purchase and reorganization cost, net.

For the year ended December 31, 2022, Finco’s operating income was $75.6 million higher than that of Noble. For the Prior Year Successor Period and the Prior Year Predecessor Period, Finco’s operating income was $47.7 million and $0.3 million higher than that of Noble, respectively. The operating income (loss) difference is primarily a result of expenses related to legal costs and administration attributable to Noble for operations support and stewardship-related services.

Key Operating Metrics

Operating results for our contract drilling services segment are dependent on three primary metrics: operating days, dayrates and operating costs. We also track rig utilization, which is a function of operating days and the number of rigs in our fleet. For more information on operating costs, see “—Contract Drilling Services” below.

The following table presents the average rig utilization, operating days and average dayrates for our rig fleet for the periods indicated.

(1)We define utilization for a specific period as the total number of days our rigs are operating under contract, divided by the product of the total number of our rigs, including cold stacked rigs, and the number of calendar days in such period. Information reflects our policy of reporting on the basis of the number of available rigs in our fleet.

(2)An operating day is defined as a calendar day during which a rig operated under a drilling contract. We define average dayrates as revenue from contract drilling services earned per operating day. Average dayrates have not been adjusted for the non-cash amortization related to favorable and unfavorable customer contract intangibles.

(3)Calculations in the table include the rigs acquired in connection with the Business Combination Agreement after the Closing Date of October 3, 2022. Calculations in the above table exclude the five jackups sold in the fourth quarter of 2022 in connection with the Rig Transaction, following the closing of the sale on October 5, 2022.

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Contract Drilling Services

The following table presents the operating results for our contract drilling services segment for the period indicated (dollars in thousands):

(1)We record reimbursements from customers for out-of-pocket expenses as operating revenues and the related direct costs as operating expenses. Changes in the amount of these reimbursables generally do not have a material effect on our financial position, results of operations or cash flows.

Contract Drilling Services Revenues

Floaters. During the year ended December 31, 2022, floaters generated revenue of $997.8 million, as compared to $482.3 million in the Prior Year Successor Period. The increase in revenue is mainly attributable to (i) $170.8 million contributed by

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rigs acquired in the Business Combination with Maersk Drilling; (ii) $193.7 million due to an increase in average day rate in the current period; and (iii) $144.1 million due to increased demand in the current period. Partly off-setting these increases were (i) $20 million from rigs with fewer operating days in the current period and (ii) the divestiture of a semi-submersible in early 2022. Additionally, contract drilling revenue for the current period increased $42.0 million due to the non-cash amortization related to customer contract intangibles which were recognized on the Effective Date, as well as contract intangibles and contract liabilities recognized in connection with the Business Combination with Maersk Drilling.

Jackups. During the year ended December 31, 2022, jackups generated revenue of $335.0 million, as compared to $225.8 million in the Prior Year Successor Period. The increase in revenue is mainly attributable to (i) $103.6 million provided by rigs acquired in the Business Combination with Maersk Drilling; and (ii) $82.4 million from additional operating days in the current period. These increases were offset by (i) $1.5 million for the divestiture of the Remedy Rigs; (ii) $73.9 million for the divestiture of the jackup fleet located in Saudi Arabia; (iii) $3.4 million from rigs with few operating days in the current period; and (iv) $4.8 million from net changes in dayrates. Additionally, contract drilling revenue for the current period increased $6.8 million due to the non-cash amortization related to customer contract intangibles which were recognized in connection with the Business Combination with Maersk Drilling.

Floaters and Jackups (Prior Year Predecessor Period). During the Prior Year Predecessor Period, contract drilling services revenues totaled $50.1 million for our floaters and $24.0 million for our jackups. All six contracted floaters and seven of our eight contracted jackups operated for the entire period. This was offset by one contracted jackup not operating for the full period, which was on suspension.

Operating Costs and Expenses

Floaters. During the year ended December 31, 2022, total contract drilling services costs related to floaters was $600.2 million. Contract drilling services costs related to floaters totaled $368.7 million in the Prior Year Successor Period. The primary drivers of the increase are: (i) eight additional floaters acquired in the Business Combination with Maersk Drilling in the fourth quarter of 2022; (ii) five additional floaters acquired in April 2021 from Pacific Drilling; (iii) additional available days in the current year compared to the Prior Year Successor Period; and iv) increased crew and material costs across the fleet due to inflation. These increases were offset by the divestiture of a semi-submersible unit in early 2022 and two units in the Prior Year Successor Period.

Jackups. During the year ended December 31, 2022, contract drilling services costs related to jackups was $296.9 million. Contract drilling services costs related to jackups totaled $270.7 million in the Prior Year Successor Period. During the year ended December 31, 2022, cost increases are primarily related to: (i) the 10 jackups acquired in conjunction with the Business Combination with Maersk Drilling in October 2022 and (ii) increased crew and material costs across the fleet due to inflation. These increases were partly offset by the reduction of expenses after the sale of the four jackups in Saudi Arabia in the fourth quarter of 2021 and five Remedy Rigs in October 2022.

Floaters and Jackups (Prior Year Predecessor Period). During the Prior Year Predecessor Period, contract drilling services costs totaled $25.8 million for our floaters and $21.2 million for our jackups. Reduced operating costs in the period was a result of 4 rigs being stacked during the entire period.

Depreciation and Amortization. Depreciation and amortization totaled $146.9 million and $89.5 million during the year ended December 31, 2022, and the Prior Year Successor Period respectively. Depreciation increased by $57.4 million in 2022 primarily due to $47.9 million related to 18 rigs and related equipment acquired in the Business Combination. Additionally, the rigs acquired in the Pacific Drilling Merger had a full year of depreciation expense in 2022. The increase is offset by six rigs sold in 2022 and two drillships and four jackup rigs sold in 2021. Depreciation for the Prior Year Predecessor Period was $20.6 million.

General and Administrative Expenses. General and administrative expenses totaled $82.2 million and $62.5 million during the year ended December 31, 2022, and the Prior Year Successor Period, respectively. The increase is primarily due to increased personnel costs, innovation costs and professional fees. General and administrative expenses totaled $5.7 million for the Prior Year Predecessor Period.

Merger and Integration Costs. During the year ended December 31, 2022, Noble incurred $84.7 million of merger and integration costs primarily in connection with the Business Combination with Maersk Drilling. During the Prior Year Successor Period, Noble incurred $24.8 million of merger and integration costs in connection with the Pacific Drilling Merger and the Business Combination with Maersk Drilling. For additional information, see “Note 4— Acquisitions and Divestitures” and “Note 5— Merger and Integration Costs” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

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Gain on Sale of Operating Assets, Net. During the year ended December 31, 2022, Noble recognized a gain, net of transaction costs, of $90.2 million in connection with the sale of the Divestment Business and the Noble Clyde Boudreaux. Noble recorded a gain of $185.9 million and Finco recorded a gain of $187.5 million resulting from the sale of five jackup rigs during the Prior Year Successor Period. For additional information, see “Note 4— Acquisitions and Divestitures” and “Note 7— Property and Equipment” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Hurricane Losses and Recoveries, Net. Noble incurred $22.0 million of costs during the year ended December 31, 2022, which primarily related to additional costs as a result of the Hurricane Ida incident, which was offset by insurance recoveries of $21.9 million. Noble incurred $30.9 million of costs and received recoveries of $7.5 million from our insurance in connection to damages sustained from Hurricane Ida during the Prior Year Successor Period. For additional information, see ”Note 7— Property and Equipment” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Other Income and Expenses

Interest Expense. Interest expense totaled $42.7 million and $31.7 million for the year ended December 31, 2022, and the Prior Year Successor Period, respectively. The year ended December 31, 2022 included interest expense on our Second Lien Notes, Revolving Credit Facility, DNB Credit Facility and DSF Credit Facility (each as defined herein) acquired in the Business Combination with Maersk Drilling. The Prior Year Successor Period includes interest expense on our then newly issued Second Lien Notes as well as borrowings under our Revolving Credit Facility, slightly offset by capitalized interest of $2.0 million. Interest expense for the Prior Year Predecessor Period was $0.2 million. For additional information, see “Note 9— Debt“ to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Gain on Bargain Purchase. Noble recognized a $62.3 million gain on the bargain purchase of Pacific Drilling during the Prior Year Successor Period. For additional information, see “Note 4— Acquisitions and Divestitures” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Income Tax Provision (Benefit). We recorded income tax expense of $22.6 million and $0.4 million during the year ended December 31, 2022 and the Prior Year Successor Period, respectively. An income tax expense of $3.4 million was recorded for the Prior Year Predecessor Period.

During the year ended December 31, 2022, our tax provision included tax benefits of $42.1 million related to a release of valuation allowance in Guyana and Luxembourg, $1.3 million related primarily to other deferred tax adjustments, and $6.6 million related to a reduction in legacy Maersk tax contingencies primarily due to favorable foreign exchange movements. Such tax benefits were offset by tax expenses of $2.3 million related to the sale of the Remedy Rigs, $10.8 million related to contract fair value amortization, and various recurring items comprised of Guyana excess withholding tax on gross revenue of $34.7 million and annual current and deferred tax expense accrual of $24.9 million primarily in Luxembourg, Switzerland, U.S, Norway, and Ghana.

During the Prior Year Successor Period, our tax provision included tax benefits of $24.2 million related to US and non-US reserve releases, $12.6 million related to a US tax refund, $22.8 million related to deferred tax assets previously not recognized, $1.9 million related to recognition of a non-US refund claim and $1.2 million related primarily to deferred tax adjustments. Such tax benefits were offset by tax expenses of $21.2 million related to various recurring items primarily comprised of Guyana withholding tax on gross revenue and $42.0 million related to non-US tax reserves.

During the Prior Year Predecessor Period, our income tax provision included a tax benefit of $1.7 million related to non-US reserve release and tax expense of $2.5 million related to fresh start and reorganization adjustments, and other recurring tax expenses of approximately $2.6 million.

2021 Compared to 2020

Information related to a comparison of our results of operations for the Prior Year Successor Period and the Prior Year Predecessor Period, on the one hand, compared to our fiscal year ended December 31, 2020, on the other hand, is included in Part II, Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, filed with the SEC on February 17, 2022.

Liquidity and Capital Resources

Senior Secured Revolving Credit Facility

As of December 31, 2022, we had no loans outstanding and $21.1 million of letters of credit issued under our senior secured revolving credit agreement (the “Revolving Credit Facility”) and an additional $8.7 million in letters of credit and

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surety bonds issued under bilateral arrangements. For additional information about our Revolving Credit Facility, see “Note 9— Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Second Lien Notes Indenture

As of December 31, 2022, we had outstanding $173.7 million aggregate principal amount of our Second Lien Notes. Interest on the Second Lien Notes accrues, at Finco’s option, at a rate of: (i) 11% per annum, payable in cash; (ii) 13% per annum, with 50% of such interest to be payable in cash and 50% of such interest to be payable by issuing additional Second Lien Notes (“PIK Notes”); or (iii) 15% per annum, with the entirety of such interest to be payable by issuing PIK Notes. Finco pays interest semi-annually in arrears on February 15 and August 15 of each year, commencing August 15, 2021. For accrual purposes, we have assumed we will make the next interest payment in cash and have accrued at a rate of 11%; however, the actual interest election will be made no later than the record date for such interest payment. For additional information about our Second Lien Notes, see “Note 9— Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Debt Open Market Repurchases

In August 2022, we purchased $1.6 million aggregate principal amount of our Second Lien Notes for approximately $1.8 million, plus accrued interest, as open market repurchases and recognized a loss of approximately $0.2 million.

In the fourth quarter of 2022, we purchased $40.7 million aggregate principal amount of our Second Lien Notes for approximately $46.2 million, plus accrued interest, as open market repurchases and recognized a loss of approximately $4.4 million.

New DNB Credit Facility

On November 22, 2022, Noble entered into a Term Facility Agreement among Maersk Drilling, as the borrower, the Company, as parent guarantor, certain subsidiaries of Maersk Drilling thereto as guarantors, and the lenders identified therein, with DNB Bank ASA, New York Branch acting as Agent. On December 22, 2022, the Utilisation Date (as defined in the New DNB Credit Facility) occurred under the New DNB Credit Facility, and Maersk Drilling borrowed the full $350.0 million available thereunder. See “Note 9— Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

DSF Credit Facility

As of December 31, 2022, Maersk Drilling had $149.7 million of outstanding term loans under the DSF Credit Facility, which were paid in full with cash on hand on February 23, 2023. See “Note 9— Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

Sources and Uses of Cash

Our principal sources of capital in 2022 were cash generated from operating activities. Cash on hand during 2022 was primarily used for the following:

•normal recurring operating expenses;

•repurchases or repayments of debt and interest;

•fees and expenses related to merger and integration costs of the Business Combination; and

•capital expenditures.

Currently, our anticipated cash flow needs, both in the short-term (fiscal year 2023) and long-term (beyond fiscal year 2023), may include the following:

•normal recurring operating expenses;

•planned and discretionary capital expenditures;

•repurchase, redemptions, or repayments of debt and interest;

•fees and expenses related to merger and integration costs of the Business Combination;

•share repurchases and dividends; and

•certain contractual cash obligations and commitments.

We may, from time to time, redeem, repurchase or otherwise acquire our outstanding Second Lien Notes through open market purchases, tender offers or pursuant to the terms of such securities. We may seek to fund any such redemptions, repurchases or acquisitions of the Second Lien notes through the issuances of long-term debt securities or other similar instruments, subject to market conditions or other factors.

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We currently expect to fund our cash flow needs with cash generated by our operations, cash on hand, proceeds from sales of assets, or borrowings under our credit facilities and we believe this will provide us with sufficient ability to fund our cash flow needs over the next 12 months. Subject to market conditions and other factors, we may also issue equity or long-term debt securities to fund our cash flow needs and for other purposes.

Net cash provided by operating activities was $281.0 million for the year ended December 31, 2022 and $51.6 million for the Prior Year Successor Period, while net cash used in operating activities was $45.4 million for the Prior Year Predecessor Period. The current year ended December 31, 2022 and the Prior Year Successor Period benefited from a cash inflow from operating assets and liabilities, while the Prior Year Predecessor Period had a cash outflow from operating assets and liabilities. We had working capital of $384.7 million at December 31, 2022 and $207.3 million at December 31, 2021 .

Net cash provided by investing activities was $375.8 million for the year ended December 31, 2022, and $207.9 million during the Prior Year Successor Period while net cash used in investing activities was $14.4 million during the Prior Year Predecessor Period. The current year includes proceeds from the sale of the Remedy Rigs and cash acquired in the Business Combination with Maersk Drilling. The 2021 Successor period includes proceeds from the sale of for rigs in Saudi Arabia in November 2021, cash acquired from the Pacific Drilling merger and proceeds from the sale of two rigs in late June 2021.

Net cash used in financing activities was $367.8 million for the year ended December 31, 2022, and $176.8 million for the Prior Year Successor Period and $191.2 million for the Prior Year Predecessor Period. During the year ended December 31, 2022, Noble refinanced part of the assumed debt from the Business Combination, resulting in a net pay down of $277.3 million. In the year ended 2022, we utilized approximately $48.1 million of cash to repurchase $42.3 million aggregate principal amount of our Second Lien Notes plus accrued interest, as open market repurchases and recognized a loss of approximately $4.6 million. The Prior Year Successor Period included net payments on our Revolving Credit Facility. The Prior Year Predecessor Period included the repayment of Legacy Noble’s credit facility, issuances of the Second Lien Notes and borrowings on the Revolving Credit Facility. The Compulsory Purchase was completed in the fourth quarter of 2022, at a cost of $69.9 million, paid in DKK and 4.1 million shares issued.

At December 31, 2022, we had a total contract drilling services backlog of approximately $3.9 billion, which includes a commitment of 57 percent of available days for 2023. For additional information regarding our backlog, see “—Contract Drilling Services Backlog.”

Capital Expenditures

Capital expenditures totaled $193.6 million, $159.9 million, and $10.3 million, for the year ended December 31, 2022, the Prior Year Successor Period and the Prior Year Predecessor Period, respectively. Capital expenditures for the year ended December 31, 2022 consisted of the following:

•$111.0 million for sustaining capital;

•$45.0 million in major projects, including subsea and other related projects; and

•$37.6 million for rebillable capital and contract modifications.

Our total capital expenditure estimate for 2023, net of client reimbursables, is expected to range between $325 million and $365 million, of which approximately $210 to $230 million is currently anticipated to be spent for sustaining capital. We anticipate additional capital costs to repair the Noble Regina Allen, however, we are in the process of completing an insurance claim for reimbursement to cover the majority of the costs.

From time to time we consider possible projects that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. In addition, while liquidity and preservation of capital remains our top priority, we will continue to evaluate acquisitions of drilling units from time to time.

Share Capital

As of March 6, 2023, there were 134,820,112 Ordinary Shares outstanding. In addition, as of March 6, 2023, 6,203,133 Tranche 1 Warrants, 5,547,974 Tranche 2 Warrants and 2,774,204 Tranche 3 Warrants were outstanding and exercisable. We also have 2,075,225 Ordinary Shares authorized and reserved for issuance pursuant to equity awards under the Noble Corporation plc 2022 Long-Term Incentive Plan.

The declaration and payment of dividends require the authorization of the Board of Directors of Noble. Such dividends may be paid only out of Noble’s “distributable reserves” on its statutory balance sheet in accordance with law. Therefore, Noble is not permitted to pay dividends out of share capital, which includes share premium. The payment of future dividends will depend on our results of operations, financial condition, cash requirements, future business prospects, contractual and

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indenture restrictions and other factors deemed relevant by our Board of Directors; however, at this time, we do not expect to pay any dividends in the foreseeable future.

Share Repurchases

Under law, the Company is only permitted to purchase its own Ordinary Shares by way of an “off-market purchase” in a plan approved by shareholders. Such may be paid only out of Noble’s “distributable reserves” on its statutory balance sheet in accordance with law. As of the date of this report, we have shareholder authority to repurchase up to 15% per annum of the issued share capital of the Company as of the beginning of each fiscal year for a five-year period (subject to an overall aggregate maximum of 20,601,161 Ordinary Shares). During the year ended December 31, 2022, we repurchased 407,477 of our Ordinary Shares, which were subsequently cancelled.

Summary of Contractual Cash Obligations and Commitments

We have $175.9 million of long-term tax reserves for uncertain tax positions, including interest and penalties, which are included in “Other liabilities” due to the difficulty in making reasonably reliable estimates of the timing of cash settlements to taxing authorities. See “Note 14— Income Taxes” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2022, $159.7 million of long-term debt will be due in the next twelve months and $513.1 million will be due subsequent to 2023. See “Note 9— Debt” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. We may seek to refinance all or a portion of our long-term debt obligations, including the Revolving Credit Facility, the Second Lien Notes and the New DNB Credit Facility, though any such refinancing transactions are subject to market and other conditions and there are no assurances that we will complete any such transactions, in whole or in part, or as to the amount or timing of any such transactions.

At December 31, 2022, $12.1 million of pension obligations will be due in the next twelve months and the remainder of $121.7 million will be due subsequent to 2023. See “Note 15— Employee Benefit Plans” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. In addition, $9.5 million is due on a long-term basis under the Danish Holiday Act of 2020.

For a description of our operating lease obligations, refer to “Note 13— Leases” to our consolidated financial statements included in Part II, Item 8 of this Annual Report on Form 10-K.

At December 31, 2022, we had other commitments that we are contractually obligated to fulfill with cash if the obligations are called. These obligations include letters of credit that guarantee our performance as it relates to our drilling contracts, tax and other obligations in various jurisdictions. These letters of credit obligations are not normally called, as we typically comply with the underlying performance requirement. At December 31, 2022, $14.1 million letters of credit and commercial commitments will be due in the next twelve months and the remainder of $15.7 million will be due subsequent to 2023.

Guarantees of Registered Securities

Finco has issued the Second Lien Notes due 2028. The Second Lien Notes are fully and unconditionally guaranteed, jointly and severally, on a senior secured second-priority basis, by the direct and indirect subsidiaries of Finco that are Credit Parties under the Revolving Credit Facility (the “Guarantors”). The guarantees are unconditional, irrevocable, joint and several senior obligations of each Guarantor and rank equally in right of payment with all future senior indebtedness of such Guarantor and effectively senior to all of such Guarantor’s unsecured senior indebtedness.

The Second Lien Notes and such guarantees are secured by second priority liens on the collateral securing the obligations under the Revolving Credit Facility, including, among other things, (i) a pledge of the equity interests in Finco, (ii) pledges of the equity interests in the Guarantors and (iii) a lien on substantially all of the assets of Finco and the Guarantors (including the equity interests in substantially all of the other direct subsidiaries of Finco and the Guarantors), in each case, subject to certain exceptions and limitations (collectively, the “Collateral”). The Collateral also includes mortgages on certain rigs owned by the Guarantors. None of Pacific Drilling, Maersk Drilling or any of their respective current subsidiaries is a subsidiary guarantor of the Revolving Credit Facility or the Second Lien Notes. The Collateral does not include (i) any assets of, or equity interests in, Pacific Drilling or any of its current subsidiaries, or (ii) any assets of, or equity interests in, Maersk Drilling or any of its current subsidiaries.

Second Lien Note Guarantees

The guarantees by the Guarantors are unconditional, irrevocable, joint and several senior obligations of each Guarantor and rank equally in right of payment with all future senior indebtedness of such Guarantor and effectively senior to all of

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such Guarantor’s unsecured senior indebtedness. The guarantees rank senior in right of payment to any existing and future subordinated obligations of such Guarantor and are effectively junior to any obligations of such Guarantor that are secured by senior liens on the Collateral or secured by assets which do not constitute Collateral. Under the indenture governing the Second Lien Notes, a Guarantor may be released and relieved of its obligations under its guarantee under certain circumstances, including: (1) upon Finco’s exercise of legal defeasance in accordance with the relevant provisions of the indenture governing the Second Lien Notes, (2) in the event of any sale or other disposition of all of the capital stock of any Guarantor in compliance with the provisions of the indenture governing the Second Lien Notes, (3) upon the dissolution or liquidation of a Guarantor, (3) with the requisite consent of the noteholders, (4) if such Guarantor is properly designated as an unrestricted subsidiary in accordance with the indenture governing the Second Lien Notes, (5) upon the release or discharge of the Guarantor’s obligations under its guarantee or (6) with respect to certain future immaterial guarantors, upon a written notice from Finco to the trustee for the Second Lien Notes.

Finco is a holding company with no significant operations or material assets other than the direct and indirect equity interests it holds in the Guarantors and other non-guarantor subsidiaries. Finco conducts its operations primarily through its subsidiaries. As a result, its ability to pay principal and interest on the Second Lien Notes is dependent on the cash flow generated by its subsidiaries and their ability to make such cash available to Finco by dividend or otherwise. The earnings of Finco’s subsidiaries will depend on their financial and operating performance, which will be affected by general economic, industry, financial, competitive, operating, legislative, regulatory and other factors beyond Finco’s control. Any payments of dividends, distributions, loans or advances to Finco by its subsidiaries could also be subject to restrictions on dividends under applicable local law in the jurisdictions in which such subsidiaries operate. In the event that Finco does not receive sufficient distributions from its subsidiaries, or to the extent that the assets of the Guarantors are insufficient, Finco may be unable to make payments on the Second Lien Notes.

Pledged Equity of Affiliates

Pursuant to the terms of the Second Lien Notes collateral documents, the collateral agent under the indenture governing the Second Lien Notes may pursue remedies, or pursue foreclosure proceedings on the Collateral (including the equity of the Guarantors and certain other direct subsidiaries of Finco and the Guarantors), following an event of default under the indenture governing the Second Lien Notes. 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 pledged equity of the Guarantors constitutes substantially all of the securities of those of our affiliates which have been pledged to secure the obligations under the Second Lien Notes. 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 not under distressed circumstances. There is no trading market for the pledged equity interests.

Under the terms of the documents governing the Second Lien Notes (the “Second Lien Notes Documents”), Finco and the Guarantors will be entitled to the release of the Collateral from the liens securing the Second Lien Notes under one or more circumstances, including (1) to the extent required by or pursuant to the terms of the Second Lien Notes Documents; (2) to the extent that proceeds continue to constitute Collateral, in the event that Collateral is sold, transferred, disbursed or otherwise disposed of to third parties; or (3) as otherwise provided in the Second Lien Notes Documents, including the release of the priority lien on such Collateral. Upon the release of any Guarantor from its guarantee, if any, in accordance with the terms of the indenture governing the Second Lien Notes, the lien on any pledged equity interests issued by such Guarantor and on any assets of such Guarantor will automatically terminate.

Guarantor Summarized Financial Information

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

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Summarized Balance Sheet Information:

Summarized Statement of Operations Information:

(1)Includes operating revenue of $21.1 million, operating costs and expenses of $53.8 million and other income of $127.5 million attributable to transactions with non-guarantor subsidiaries for the year ended December 31, 2022. Includes operating revenue of $31.3 million, operating costs and expenses of $17.1 million and other expense of $26.3 million attributable to transactions with non-guarantor subsidiaries for the Prior Year Successor Period.

(2)Includes operating revenue of $3.8 million, operating costs and expenses of $1.1 million and other expense of $(1.2) million attributable to transactions with non-guarantor subsidiaries for the Prior Year Predecessor Period.

Environmental Matters

We are subject to numerous international, federal, state and local laws and regulations relating to the protection of the environment and of human health and safety. For a discussion of the most significant of these laws and regulations, see Part I, Item 1,“Business—Governmental Regulations and Environmental Matters.”

Continuing political and social attention to the issue of global climate change has resulted in a broad range of proposed or promulgated laws focusing on greenhouse gas reduction and related public disclosures. The costs of implementing these rules and continuing compliance and disclosure could be substantial. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance or reporting costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Climate change could also increase the frequency and severity of adverse weather conditions, including hurricanes, typhoons, cyclones, winter storms and rough seas. If such effects were to occur, they could have an adverse impact on our operations. For a discussion of climate change, see “Business—Governmental Regulations and Environmental Matters—Climate Change.”

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In addition, increasing social attention to ESG matters and climate change has resulted in demands for action related to climate change and energy rebalancing matters, such as promoting the use of substitutes to fossil fuel products, encouraging the divestment of fossil fuel equities, and pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. Initiatives to incentivize a shift away from fossil fuels could reduce demand for hydrocarbons, thereby reducing demand for our services and causing a material adverse effect on our earnings, cash flows and financial condition. For further discussion of these risks, see Part I, Item 1A, “Risk Factors—Regulatory and Legal Risks—Increasing attention to environmental, social and governance matters and climate change may impact our business and financial results.”

Critical Accounting Estimates

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“US GAAP”), which require us to make estimates that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying amounts of assets and liabilities that are not readily apparent from other sources. Actual results may differ from our estimates and assumptions and any such differences could be material to our consolidated financial statements. The following accounting policies involve critical accounting estimates because they are particularly dependent on estimates and assumptions made by Noble about matters that are inherently uncertain.

Recoverability of Assets

We evaluate our property and equipment and intangible assets for impairment whenever there are changes in facts that suggest that the value of the asset is not recoverable. An impairment loss is recognized when and to the extent that an asset's carrying value exceeds its estimated fair value. To the extent actual results do not meet our estimated assumptions for a given rig, piece of equipment or intangible customer contract, we may take an impairment loss in the future. In determining the fair value of the assets, we make significant assumptions and estimates regarding future market conditions. Typical assumptions used in our estimate include current market conditions, timing of future contract awards and expected operating dayrates, operating costs, utilization rates, discount rates, capital expenditures, market values, weighting of market values, reactivation costs, estimated economic useful lives and marketability of a unit.

During the years ended December 31, 2022 and 2021, no impairment charges were recognized. During the year ended December 31, 2020, we recognized non-cash, before-tax impairment charges of $3.9 billion, related to certain rigs and related capital spares. These impairments were driven by factors such as customer suspensions of drilling programs, contract cancellations, a further reduction in the number of new contract opportunities, capital spare equipment obsolescence, and our belief that a drilling unit is no longer marketable and is unlikely to return to service.

Impairment assessment inherently involves management judgments as to assumptions about expected future cash flows and the impact of market conditions on those assumptions. Due to the many variables inherent in this estimation, differences in assumptions may have a material effect on the results of our impairment analysis.

Income Taxes

We estimate income taxes and file tax returns in each of the taxing jurisdictions in which we operate and are required to file a tax return. At the end of each year, an estimate for income taxes is recorded in the financial statements. Tax returns are generally filed in the subsequent year. A reconciliation of the estimate to the final tax return is done at that time, which will result in changes to the original estimate. We believe that our tax return positions are appropriately supported, but tax authorities can challenge certain of our tax positions.

We currently operate, and have in the past operated, in a number of countries throughout the world and our tax returns filed in those jurisdictions are subject to review and examination by tax authorities within those jurisdictions. We recognize uncertain tax positions that we believe have a greater than 50 percent likelihood of being sustained upon challenge by a tax authority. We cannot predict or provide assurance as to the ultimate outcome of any existing or future assessments. A change in judgment related to the expected ultimate resolution of uncertain tax positions will be recognized in earnings in the quarter of such change. We believe that our reserve for uncertain tax positions, including related interest and penalties, is adequate. As of December 31, 2022, the Company had $175.9 million of long-term tax reserves for unrecognized tax benefits, including interest and penalties, which are included in “Other liabilities”. The amounts ultimately paid upon resolution of audits could be materially different from the amounts previously included in our income tax expense and, therefore, could have a material impact on our tax provision, net income and cash flows.

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Our gross deferred tax asset balance at year-end reflects the application of our income tax accounting policies and is based on management’s estimates, judgments and assumptions regarding realizability. If it is more likely than not that a portion of the deferred tax assets will not be realized in a future period, the deferred tax assets will be reduced by a valuation allowance based on management’s estimates. In evaluating our ability to recover our deferred tax assets, in full or in part, we consider all available positive and negative evidence, including our past operating results, and our forecast of future earnings, future taxable income and prudent and feasible tax planning strategies. The assumptions utilized in determining future taxable income require significant judgment. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could have a material impact our consolidated financial statements.

Claims Reserves

We maintain various levels of self-insured retention for certain losses including property damage, loss of hire, employment practices liability, employers’ liability and general liability, among others. We accrue for property damage and loss of hire charges on a per event basis.

Employment practices liability claims are accrued based on actual claims during the year. Maritime employer’s liability claims are generally estimated using actuarial determinations. General liability claims are estimated by our internal claims department by evaluating the facts and circumstances of each claim (including incurred but not reported claims) and making estimates based upon historical experience with similar claims. The amount of our loss reserves for personal injury and protection claims is based on an analysis performed by a third-party actuary which uses our historical loss patterns and trends as well as industry data to estimate the unpaid loss and allocated loss adjustment expense. Claim severity experienced in each year, ranging from minor incidents to permanent disability or injuries requiring extensive medical care, is a key driver of the variability around our reserve estimates. These estimates are further subject to uncertainty because the ultimate disposition of claims incurred is subject to the outcome of events which have not yet transpired. Accordingly, we may be required to increase or decrease our reserve levels. At December 31, 2022, loss reserves for personal injury and protection claims totaled $35.3 million, of which $15.5 million is included in “Other current liabilities” and $19.8 million in “Other long-term liabilities” in the accompanying Consolidated Balance Sheets. At December 31, 2021, loss reserves for personal injury and protection claims totaled $14.8 million and is included in “Other current liabilities” in the accompanying Consolidated Balance Sheets.

Pension Plans

Accounting for employee benefit plans involves numerous assumptions and estimates. Discount rate and expected return on plan assets are two critical assumptions in measuring the cost and benefit obligation of the Company’s pension plans, which we evaluate when the plans are re-measured. Other assumptions include the healthcare cost trend rate and employee demographic factors such as retirement patterns, mortality, turnover and rate of compensation increase.

The discount rate enables us to state expected future cash payments for benefits as a present value on the measurement date. A lower discount rate increases the present value of benefit obligations and increases pension expense. The discount rates used to calculate the net present value of future benefit obligations for our US plans is based on the average of current rates earned on long-term bonds that receive a Moody’s rating of “Aa” or better. We have determined that the timing and amount of expected cash outflows on our plans reasonably match this index. For our non-US plan, the discount rate used to calculate the net present value of future benefit obligations is determined by using a yield curve of high quality bond portfolios with an average maturity approximating that of the liabilities. A one percentage point change in the assumed discount rate would change total pension income for 2023 by approximately $2.0 million. A one percentage point decrease in the assumed discount rate would increase the projected benefit obligation at December 31, 2022 by approximately $27.5 million. A one percentage point increase in the assumed discount rate would decrease the projected benefit obligation by approximately $1.6 million and $22.7 million, respectively.

To determine the expected long-term rate of return on the plan assets, we consider the current level of expected returns on risk free investments (primarily government bonds), the historical level of risk premium associated with the other asset classes in which the portfolio is invested and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based on the target asset allocation to develop the expected long-term rate of return on assets for the portfolio.

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Business Combinations

We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair value. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. To the extent the estimated fair value of the net assets acquired exceeded the purchase price, we recognize a bargain purchase gain. Changes in these judgments or estimates can have a material impact on the valuation of the respective assets and liabilities acquired and our results of operations in periods after acquisition. The allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed.

Our estimates of fair value of the acquired property and equipment and contract intangibles require us to use significant unobservable inputs, representative of a Level 3 fair value measurement, such as assumptions related to future marketability of each unit in light of the current market conditions and its current technical specifications, timing of future contract awards and expected operating dayrates, operating costs, rig utilization rates, tax rates, discount rate, capital expenditures, synergies, market values, estimated economic useful lives of the rigs and, in certain cases, management’s belief that a drilling unit is no longer marketable and is unlikely to return to service in the near to medium term. It can be difficult to determine the fair value based on the cyclical nature of our business, demand for offshore drilling rigs in different markets and changes in economic conditions.