Noble Corporation plc
10/27/2026 | Press release | Distributed by Public on 10/27/2026 10:19
Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)
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 September 30, 2026, and our results of operations for the three and nine months ended September 30, 2026 and 2025. The following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and related notes contained in this Quarterly Report on Form 10-Q, the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2025 (the "Form 10-K"), filed by Noble Corporation plc, a public limited company incorporated under the laws of England and Wales ("Noble") and our other filings with the US Securities and Exchange Commission ("SEC"). References in this Quarterly Report on Form 10-Q to "Noble," the "Company," "we," "us," "our," and words of similar meaning refer collectively to Noble and its consolidated subsidiaries.
Forward-Looking Statements
This Quarterly Report on Form 10-Q includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements other than statements of historical facts included in this report or in the documents incorporated by reference are forward-looking statements, including, but not limited to, those regarding expected financial performance, revenues, expected utilization, fleet status, project status and project schedules, effects of new rigs on the market revenues, operating expenses, cash flows, costs, amount, effect or timing of cost savings, future cash benefit expectations, contract status, contract negotiations, terminations, options and extensions, contract awards and expected future contracts, anticipated contract start dates, tenders, terms and duration, dayrates, operational suspensions, backlog, including projections for the achievement of revenue associated with performance, rigs' availability, delivery, mobilization, stacking or reactivation, fleet condition, utilization and strategy, relocation or other movement of rigs and the timing thereof, contract claims, capital expenditures, insurance maintenance and renewals, access to financing, rig demand, peak oil, the offshore drilling market, oil prices, production levels among members of the Organization of Petroleum Exporting Countries ("OPEC") and other oil and gas producing nations (together with OPEC, "OPEC+"), and any expectations we may have with respect thereto, our future financial position, business strategy, impairments, repayment of debt, credit ratings, liquidity, borrowings under any credit facilities or other instruments, sources of funds, cost inflation, planned acquisitions or divestitures of assets, governmental regulations and permitting, taxes, tax rates, and deferred taxes, indebtedness covenant compliance, dividends and distributable reserves, share repurchases, the impacts of sustainability matters, the outcome of tax disputes, assessments and settlements, expense management, the outcome of any dispute, litigation, audit or investigation, plans, foreign currency requirements, results of joint ventures, general economic and market trends and outlook, including outlook on inflation and recessions, current or future economic trends or events and their impact on the Company, general political conditions, including political tensions, conflicts and war, timing, benefits, impacts or results of acquisitions or dispositions, and timing for compliance with any new regulations. When used in this report or in the documents incorporated by reference, the words "anticipate," "believe," "continue," "could," "estimate," "expect," "intend," "may," "might," "on track," "plan," "possible," "potential," "predict," "project," "should," "would," "shall," "target," "will," and similar expressions are intended to be among the terms that identify forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we cannot assure you that such expectations will prove to be correct. These forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q and we undertake no obligation to revise or update any forward-looking statement for any reason, except as required by law. Actual results may differ materially from any future results expressed or implied by such forward-looking statements and the expectations expressed in forward-looking statements are subject to a number of risks, uncertainties and assumptions, which could affect our business, operating results and financial condition, and include, but are not limited to: market conditions and changes in customer demand, customer actions and the general customer landscape, volatility in the price of oil or gas, reduced demand for oil and gas products and increased regulation of drilling and production, the level of drilling and production activity, price competition, and cyclicality in the oil and gas industry and the offshore drilling industry, offshore rig supply, dayrates and demand for rigs, contract duration, negotiation, renewal, terminations, and repricing, operational suspensions, national oil companies and governmental clients, backlog and realization of our current backlog of contract drilling revenue, customer and geographic concentration, operational hazards and risks, labor force unionization, labor interruptions and labor regulations, major natural disasters, including hurricanes and windstorm damage, seasonal weather events and related damages or liabilities, catastrophic events, acts of war, geopolitical conflict, including the conflict involving Iran and related geopolitical instability in the Middle East, and their impact on commodity prices, global energy markets and regional and global shipping flows, terrorism or social unrest, pandemic, or other similar events, joint ventures as well as investments in associates, risks relating to international operations and related mobilization and demobilization of rigs, operational interruptions and delays, upgrades, refurbishment and repair of rigs and any related delays and cost overruns or reduced payment of dayrates, impacts of inflation and changes in global trade policy, including tariffs and other trade restrictions, renewal of insurance, protection of sensitive information, operational technology systems and critical data, the ability to attract and retain skilled personnel or the increased cost in doing so, supplier capacity constraints or shortages in parts or equipment, supplier production disruptions, supplier quality and sourcing issues or price increases, future mergers, acquisitions or dispositions of businesses or assets or other strategic transactions, sales of drilling units, responding to long-term changes in the energy mix, impairment to our ability to raise capital for operations, nonperformance of third-parties, suppliers and subcontractors, regulatory changes and compliance with governmental laws and regulations, heightened attention to sustainability matters, including climate change and accountability for public statements about sustainability efforts, compliance with anti-bribery or anti-corruption, international trade laws and regulations, our ability to maintain effective disclosure controls and procedures and internal control over financial reporting, impairments on property and equipment, including rigs and related capital spares, operating and financial restrictions, maintenance of covenants in our debt documents, potential impacts, liabilities and costs from pending or potential litigation, investigations, claims and tax or
other disputes, and other risks that are described herein, as well as the "Risk Factors" referenced or described in Part I, Item 1A. "Risk Factors" of our Form 10-K and in our other filings with the SEC. We cannot control such risk factors and other uncertainties, and in many cases, we cannot predict the risks and uncertainties that could cause our actual results to differ materially from those indicated by the forward-looking statements. You should consider these risks and uncertainties when you are evaluating us. Future quarterly dividends and other shareholder returns will be subject to, amongst other things, approval by the Board of Directors and may be modified as market conditions dictate.
Our Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge on our website. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.
Our website address is http://www.noblecorp.com. Investors should also note that we announce material financial information in SEC filings, press releases and public conference calls. Based on guidance from the SEC, we may use the investor relations section of our website to communicate with our investors. It is possible that the financial and other information (including fleet status reports) posted there could be deemed to be material information. Noble may also use social media channels including, but not limited to, Noble's accounts on LinkedIn, Facebook, Instagram, and X, to communicate with investors and the public about its business, services, and other matters, and those communications could be deemed to be material information. Except to the extent explicitly stated herein, documents and information on our website or our social media channels are not incorporated by reference herein.
Executive Overview
Noble is a leading offshore drilling contractor for the oil and gas industry. As of the filing date of this Quarterly Report on Form 10-Q, Noble performs, through its subsidiaries, contract drilling services with a fleet of 29 drilling rigs, consisting of 24 floaters and 5 jackups (excluding certain rigs currently operating under a bareboat charter agreement), focused largely on ultra-deepwater and high-specification jackup drilling opportunities in both established and emerging regions 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.
Market 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 since early 2024. During 2026, the conflict involving Iran caused significant disruption in the normal flow of oil, refined petroleum products, and related commodities, contributing to elevated and volatile commodity prices and broader uncertainty across global energy markets and regional and global shipping flows. Current demand and utilization levels are supported by the combination of the outlook for longer-term 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 decreased moderately since recent highs in 2023 and 2024.
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 very few newbuild rigs now remaining stranded in shipyards.
Although the market outlook in our business varies by geographical region and water depth and, despite recent volatility regarding the price of oil, we remain encouraged by the long-term outlook in the ultra-deepwater floater 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 could 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. Furthermore, economic uncertainty and increased commodity price volatility, arising from, among other things, the conflict involving Iran, related shipping disruption, and elevated geopolitical tensions, collectively present potential for oil demand destruction and supply chain pressure. In addition, rising interest rates could weigh on broader economic activity, which may affect the timing or scope of industry decisions, particularly for capital-intensive, long-cycle offshore projects.
Returning to the broader offshore drilling market, recent contract awards and open tenders show an increasing proportion of multi-year contracts, although a significant number of shorter-term commitments continue to be fixed as well. Longer-term contracts can generally provide economic efficiencies by reducing the number of rig contract start-ups, both with different customers and among different regions, which is expected to reduce incremental resources and costs. On the other hand, certain multi-year contracts that are scheduled to commence a year or longer into the future can present near-term utilization inefficiency due to challenges with filling interim availability on the assets.
The energy transition from hydrocarbons to renewables poses a challenge to the oil and gas sector and our market. Energy rebalancing trends sharply accelerated over the past decade as evidenced by promulgated or proposed government policies and commitments by many of our customers to further invest in sustainable energy sources, although this trend has moderated or even reversed in certain jurisdictions in more recent years with shifting political priorities. 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.
Our cost profile remains sensitive to global labor market conditions, capital intensive repair and maintenance scopes on our rigs, global trade and sanctions regimes, including the impacts of new or increased tariffs or trade wars, and geopolitical crises (including the recent conflict involving Iran) and their respective regional and global ramifications. Each of these factors has the potential to adversely impact our ability to conduct our day-to-day operations and manage costs with uncertainty related to trade policy and tariffs also having the ability to negatively impact rig demand.
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. As of September 30, 2026, contract drilling services backlog totaled approximately $6.8 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 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 as of September 30, 2026, and the percent of available operating days committed for the periods indicated:
|
Year Ending December 31,
|
||||||||||||||||||||||||||||||||||||||||||||
|
Total
|
2026 (1)
|
2027
|
2028
|
2029
|
2030
|
Thereafter
|
||||||||||||||||||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||||||||||||||||||
|
Contract Drilling Services Backlog
|
||||||||||||||||||||||||||||||||||||||||||||
|
Floaters (2) (3)
|
$
|
6,326,201
|
$
|
522,823
|
$
|
2,217,222
|
$
|
2,078,249
|
$
|
899,932
|
$
|
488,159
|
$
|
119,816
|
||||||||||||||||||||||||||||||
|
Jackups (4)
|
483,685
|
87,205
|
281,480
|
84,180
|
30,820
|
-
|
-
|
|||||||||||||||||||||||||||||||||||||
|
Total
|
$
|
6,809,886
|
$
|
610,028
|
$
|
2,498,702
|
$
|
2,162,429
|
$
|
930,752
|
$
|
488,159
|
$
|
119,816
|
||||||||||||||||||||||||||||||
|
Percent of Available Days Committed (5)
|
||||||||||||||||||||||||||||||||||||||||||||
|
Floaters
|
63
|
%
|
71
|
%
|
62
|
%
|
27
|
%
|
15
|
%
|
3
|
%
|
||||||||||||||||||||||||||||||||
|
Jackups
|
78
|
%
|
63
|
%
|
20
|
%
|
7
|
%
|
-
|
%
|
-
|
%
|
||||||||||||||||||||||||||||||||
|
Total
|
66
|
%
|
69
|
%
|
55
|
%
|
23
|
%
|
12
|
%
|
3
|
%
|
||||||||||||||||||||||||||||||||
(1)Represents a three-month period beginning October 1, 2026.
(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 January 1 and July 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 above table includes awarded and remaining current contract term to February 18, 2029, related to each of the following four 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)Assuming approximately 40% of available performance revenue realized on a combined basis under certain long-term contracts with Shell plc (US Gulf) and TotalEnergies (Suriname).
(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 in offshore Norway. Under this 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 (i.e., idle without a contract, have reduced or no crew, or are not actively marketed in present market conditions), 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 according to their terms or 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. 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" in our Form 10-K. For example, as described under "Results of Operations" below, the actual revenues earned in the second and third quarters of 2026 from the Noble Faye Kozack and the Noble Courage differed from prior backlog amounts due to the previously disclosed temporary operational suspensions of those rigs, both of which have since resumed operations. Furthermore, the above table reflects re-sequenced commitments in the second half of 2026, including the transfer of backlog from the Noble Innovator to the Noble Intrepid as well as an earlier anticipated end date for the Noble Stanley Lafosse in December 2026 or January 2027 rather than July 2027 previously. Additionally, a customer option for the Noble Viking has been deferred from the fourth quarter of 2026 into 2027.
As of September 30, 2026, ExxonMobil, Shell, TotalEnergies, BP, and Aker BP represented approximately 20.5%, 18.8%, 13.6%, 12.8%, and 10.2% of our backlog, respectively.
Results of Operations
Results for the Three Months Ended September 30, 2026 and 2025
Net loss for the three months ended September 30, 2026 (the "current quarter"), was $117.0 million, or $(0.73) per diluted share, on operating revenues of $728.8 million compared to net loss for the three months ended September 30, 2025, of $21.1 million, or $(0.13) per diluted share, on operating revenues of $798.0 million.
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:
|
Average Rig Utilization (1)
|
Operating Days (2)
|
Average Dayrates (2)
|
||||||||||||||||||||||||||||||||||||
|
Three Months Ended
September 30, |
Three Months Ended
September 30, |
Three Months Ended
September 30, |
||||||||||||||||||||||||||||||||||||
|
2026
|
2025
|
2026
|
2025
|
2026
|
2025
|
|||||||||||||||||||||||||||||||||
|
Floaters
|
63
|
%
|
65
|
%
|
1,398
|
1,488
|
$
|
403,113
|
$
|
423,489
|
||||||||||||||||||||||||||||
|
Jackups (3)
|
79
|
%
|
54
|
%
|
579
|
627
|
207,651
|
202,982
|
||||||||||||||||||||||||||||||
|
Total
|
67
|
%
|
61
|
%
|
1,977
|
2,115
|
$
|
345,846
|
$
|
358,126
|
||||||||||||||||||||||||||||
(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)For 2026, the figures include rigs sold to Borr Drilling Limited, which are/were operating under a bareboat charter agreement.
Contract Drilling Services
The following table presents the operating results for our contract drilling services segment for the periods indicated (dollars in thousands):
|
Three Months Ended September 30,
|
Change
|
|||||||||||||||||||||||||
|
Operating revenues:
|
2026
|
2025
|
$
|
%
|
||||||||||||||||||||||
|
Contract drilling services
|
$
|
683,650
|
$
|
757,405
|
$
|
(73,755)
|
(10)
|
%
|
||||||||||||||||||
|
Reimbursables and other (1)
|
45,114
|
40,612
|
4,502
|
11
|
%
|
|||||||||||||||||||||
|
728,764
|
798,017
|
(69,253)
|
(9)
|
%
|
||||||||||||||||||||||
|
Operating costs and expenses:
|
||||||||||||||||||||||||||
|
Contract drilling services
|
$
|
468,516
|
$
|
479,894
|
$
|
(11,378)
|
(2)
|
%
|
||||||||||||||||||
|
Reimbursables (1)
|
32,026
|
30,547
|
1,479
|
5
|
%
|
|||||||||||||||||||||
|
Depreciation and amortization
|
143,432
|
147,260
|
(3,828)
|
(3)
|
%
|
|||||||||||||||||||||
|
General and administrative
|
27,286
|
33,301
|
(6,015)
|
(18)
|
%
|
|||||||||||||||||||||
|
Merger and integration costs
|
-
|
2,145
|
(2,145)
|
(100)
|
%
|
|||||||||||||||||||||
|
(Gain) loss on sale of operating assets, net
|
(2,579)
|
(6,232)
|
3,653
|
(59)
|
%
|
|||||||||||||||||||||
|
Loss on impairment
|
-
|
60,702
|
(60,702)
|
(100)
|
%
|
|||||||||||||||||||||
|
668,681
|
747,617
|
(78,936)
|
(11)
|
%
|
||||||||||||||||||||||
|
Operating income (loss)
|
$
|
60,083
|
$
|
50,400
|
$
|
9,683
|
19
|
%
|
||||||||||||||||||
(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.
The following table provides information about contract drilling revenue and costs by rig types (dollars in millions except average dayrates):
|
Three Months Ended September 30,
|
|||||||||||||||||||||||||||||
|
2026
|
2025
|
||||||||||||||||||||||||||||
|
Floaters
|
Jackups
|
Floaters
|
Jackups
|
||||||||||||||||||||||||||
|
Contract drilling services revenues
|
$
|
563.4
|
$
|
120.3
|
$
|
630.1
|
$
|
127.3
|
|||||||||||||||||||||
|
Contract drilling services costs
|
$
|
375.7
|
$
|
92.8
|
$
|
381.6
|
$
|
98.3
|
|||||||||||||||||||||
|
Average rig utilization
|
63
|
%
|
79
|
%
|
65
|
%
|
54
|
%
|
|||||||||||||||||||||
|
Operating days
|
1,398
|
579
|
1,488
|
627
|
|||||||||||||||||||||||||
|
Average dayrates
|
$
|
403,113
|
$
|
207,651
|
$
|
423,489
|
$
|
202,982
|
|||||||||||||||||||||
|
Total rigs
|
- Beginning
|
25
|
6
|
26
|
13
|
||||||||||||||||||||||||
|
- Acquired
|
-
|
-
|
-
|
-
|
|||||||||||||||||||||||||
|
- Disposed
|
(1)
|
-
|
(1)
|
(1)
|
|||||||||||||||||||||||||
|
- Ending
|
24
|
6
|
25
|
12
|
|||||||||||||||||||||||||
Contract Drilling Services Revenues
Floaters. During the third quarter of 2026, floaters generated revenue of $563.4 million, as compared to $630.1 million in the third quarter of 2025. The decrease in revenue was mainly attributable to $42.1 million due to a net change in average dayrates in the current period. There was also a decrease of $24.6 million from rigs with net changes in operating days, including approximately $6.3 million related to the previously disclosed operational suspensions of the Noble Faye Kozack and Noble Courage in Brazil, both of which have since resumed operations.
Jackups. During the third quarter of 2026, jackups generated revenue of $120.3 million, as compared to $127.3 million in the third quarter of 2025. The decrease in revenue was mainly attributable to $22.4 million due to a net change in average
dayrates in the current period. The decrease was partially offset by $15.7 million from rigs with net changes in operating days.
Operating Costs and Expenses
Floaters. During the third quarter of 2026, total contract drilling services costs related to floaters was $375.7 million, as compared to $381.6 million in the third quarter of 2025. The primary drivers of this decrease were decreases of $21.1 million in mobilization, $12.1 million in rental equipment, $9.4 million related to rigs while in shipyards, $5.6 million in insurance costs, and $4.2 million in regulatory inspections. These decreases were partially offset by increases of $13.4 million in repairs and maintenance, $11.9 million in labor, and $21.2 million in non-labor costs, operations support costs, and other costs across the fleet.
Jackups. During the third quarter of 2026, total contract drilling services cost related to jackups was $92.8 million, as compared to $98.3 million in the third quarter of 2025. The primary drivers of this decrease were decreases of $2.9 million in regulatory inspections, and $1.6 million in labor. Further, there was a decrease of $4.6 million related to certain rigs sold or no longer operated by Noble.
Depreciation and amortization. Depreciation and amortization totaled $143.4 million and $147.3 million during the third quarter of 2026 and 2025, respectively. Depreciation and amortization decreased primarily due to divestitures during the third quarter of 2026 as well as the timing of capital additions that were placed in service among the periods.
General and administrative. General and administrative expenses totaled $27.3 million and $33.3 million during the third quarter of 2026 and 2025, respectively. The decrease was primarily driven by lower labor costs of $6.6 million. The decrease was partially offset by an increase of $3.5 million in information technology costs.
Merger and integration costs. Noble incurred $2.1 million of merger and integration costs during the third quarter of 2025. The majority of the costs incurred directly related to the agreement and plan of merger, dated June 9, 2024, with Diamond Offshore Drilling, Inc. ("Diamond"), Dolphin Merger Sub 1, Inc., and Dolphin Merger Sub 2, Inc., under which Noble would acquire Diamond in a stock plus cash transaction (the "Diamond Transaction"). Such costs related primarily to professional fees and certain integration-related activities.
(Gain) loss on sale of operating assets, net. During the third quarter of 2026, we recognized a gain of $2.6 million, due primarily to a $2.4 million reduction in the estimated costs to sell the Noble Regina Allen. During the third quarter of 2025, we sold the Noble Highlander and the Pacific Meltem, resulting in a pre-tax gain of $5.6 million.
Loss on impairment. During the third quarter of 2025, we recorded a loss on impairment of $60.7 million to reduce the carrying values of the Noble Globetrotter II and Noble Reacher to their estimated fair value less costs to sell. For additional information, see "Note 4 - Property and Equipment" to our unaudited condensed financial statements.
Other Income and Expenses
Interest expense, net of amounts capitalized. Interest expense totaled $35.0 million and $40.5 million during the third quarter of 2026 and 2025, respectively. Interest expense is primarily related to our 2034 Notes, 2030 Notes, and the Diamond Second Lien Notes (each as defined below). The decrease in the current period is due to less average principal debt outstanding which accrued interest at lower rates. For additional information, see "Note 5 - Debt" to our unaudited condensed consolidated financial statements.
Interest income and other, net. Noble recognized interest income and other expenses of $(9.1) million and interest and other income of $0.7 million during the third quarter of 2026 and 2025, respectively. The current period includes $2.9 million of interest income from the seller notes received from the sale of jackup rigs to Borr Drilling Limited ("Borr"). The current period interest income was offset by the fair value adjustment of the notes receivable acquired pertaining to the transaction with Borr. For additional information, see "Note 9 - Supplemental Financial Information-Notes receivable" to our unaudited condensed consolidated financial statements.
Income tax benefit (provision). Noble recorded an income tax provision of $133.0 million and $31.7 million during the third quarter of 2026 and 2025, respectively.
During the third quarter of 2026, our tax provision included net tax expenses of $15.8 million related to adjustments to valuation allowance for deferred tax expenses primarily in Switzerland and recurring quarterly accruals of $117.3 million mostly in Ghana, Guyana, Luxembourg, Switzerland, and the United States.
During the third quarter of 2025, our tax provision included tax benefits of $6.1 million related to adjustments to valuation allowance for deferred tax benefits primarily in Luxembourg. Such tax benefits were offset by recurring quarterly accruals of $37.9 million mostly in Guyana, Luxembourg, Switzerland, and the United States.
Results for the Nine Months Ended September 30, 2026 and 2025
Net loss for the nine months ended September 30, 2026, was $33.0 million, or $(0.21) per diluted share, on operating revenues of $2.2 billion compared to net income for the nine months ended September 30, 2025, of $130.1 million, or $0.80 per diluted share, on operating revenues of $2.5 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:
|
Average Rig Utilization (1)
|
Operating Days (2)
|
Average Dayrates (2)
|
||||||||||||||||||||||||||||||||||||
|
Nine Months Ended
September 30, |
Nine Months Ended
September 30, |
Nine Months Ended
September 30, |
||||||||||||||||||||||||||||||||||||
|
2026
|
2025
|
2026
|
2025
|
2026
|
2025
|
|||||||||||||||||||||||||||||||||
|
Floaters
|
62
|
%
|
70
|
%
|
4,203
|
4,993
|
$
|
412,776
|
$
|
400,483
|
||||||||||||||||||||||||||||
|
Jackups (3)
|
80
|
%
|
63
|
%
|
1,890
|
2,222
|
196,136
|
177,321
|
||||||||||||||||||||||||||||||
|
Total
|
67
|
%
|
67
|
%
|
6,093
|
7,215
|
$
|
345,565
|
$
|
331,767
|
||||||||||||||||||||||||||||
(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)For 2026, the figures include rigs sold to Borr, which are/were operating under a bareboat charter agreement.
Contract Drilling Services
The following table presents the operating results for our contract drilling services segment for the periods indicated (dollars in thousands):
|
Nine Months Ended September 30,
|
Change
|
|||||||||||||||||||||||||
|
Operating revenues:
|
2026
|
2025
|
$
|
%
|
||||||||||||||||||||||
|
Contract drilling services
|
$
|
2,105,647
|
$
|
2,401,910
|
$
|
(296,263)
|
(12)
|
%
|
||||||||||||||||||
|
Reimbursables and other (1)
|
128,495
|
119,246
|
9,249
|
8
|
%
|
|||||||||||||||||||||
|
$
|
2,234,142
|
$
|
2,521,156
|
$
|
(287,014)
|
(11)
|
%
|
|||||||||||||||||||
|
Operating costs and expenses:
|
||||||||||||||||||||||||||
|
Contract drilling services
|
$
|
1,364,950
|
$
|
1,444,420
|
$
|
(79,470)
|
(6)
|
%
|
||||||||||||||||||
|
Reimbursables (1)
|
96,246
|
90,691
|
5,555
|
6
|
%
|
|||||||||||||||||||||
|
Depreciation and amortization
|
420,354
|
437,482
|
(17,128)
|
(4)
|
%
|
|||||||||||||||||||||
|
General and administrative
|
84,278
|
103,485
|
(19,207)
|
(19)
|
%
|
|||||||||||||||||||||
|
Merger and integration costs
|
2,615
|
22,367
|
(19,752)
|
(88)
|
%
|
|||||||||||||||||||||
|
(Gain) loss on sale of operating assets, net
|
(92,437)
|
(10,983)
|
(81,454)
|
742
|
%
|
|||||||||||||||||||||
|
Loss on impairment
|
42,270
|
60,702
|
(18,432)
|
(30)
|
%
|
|||||||||||||||||||||
|
1,918,276
|
2,148,164
|
(229,888)
|
(11)
|
%
|
||||||||||||||||||||||
|
Operating income (loss)
|
$
|
315,866
|
$
|
372,992
|
$
|
(57,126)
|
(15)
|
%
|
||||||||||||||||||
(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.
The following table provides information about contract drilling revenue and costs by rig types (dollars in millions except average dayrates):
|
Nine Months Ended September 30,
|
|||||||||||||||||||||||||||||
|
2026
|
2025
|
||||||||||||||||||||||||||||
|
Floaters
|
Jackups
|
Floaters
|
Jackups
|
||||||||||||||||||||||||||
|
Contract drilling services revenues
|
$
|
1,734.8
|
$
|
370.8
|
$
|
2,007.9
|
$
|
394.0
|
|||||||||||||||||||||
|
Contract drilling services costs
|
$
|
1,095.4
|
$
|
269.6
|
$
|
1,165.0
|
$
|
279.4
|
|||||||||||||||||||||
|
Average rig utilization
|
62
|
%
|
80
|
%
|
70
|
%
|
63
|
%
|
|||||||||||||||||||||
|
Operating days
|
4,203
|
1,890
|
4,993
|
2,222
|
|||||||||||||||||||||||||
|
Average dayrates
|
$
|
412,776
|
$
|
196,136
|
$
|
400,483
|
$
|
177,321
|
|||||||||||||||||||||
|
Total rigs
|
- Beginning
|
25
|
11
|
27
|
13
|
||||||||||||||||||||||||
|
- Acquired
|
-
|
-
|
-
|
-
|
|||||||||||||||||||||||||
|
- Disposed
|
(1)
|
(5)
|
(2)
|
(1)
|
|||||||||||||||||||||||||
|
- Ending
|
24
|
6
|
25
|
12
|
|||||||||||||||||||||||||
Contract Drilling Services Revenues
Floaters. During the nine months ended September 30, 2026, floaters generated revenue of $1.7 billion, as compared to $2.0 billion in the nine months ended September 30, 2025. The decrease in revenue was mainly attributable to $239.8 million from rigs with net changes in operating days, which included approximately $47.7 million related to the previously disclosed operational suspensions of the Noble Faye Kozack and Noble Courage in Brazil, both of which have since resumed operations. There was also a decrease of $24.7 million due to a net change in average dayrates in the current period. Additionally, floater revenue from net non-cash amortization related to off-market customer contract assets and liabilities decreased $8.3 million in the current period.
Jackups. During the nine months ended September 30, 2026, jackups generated revenue of $370.8 million, as compared to $394.0 million in the nine months ended September 30, 2025. The decrease in revenue was mainly attributable to a decrease of $17.3 million from rigs with net changes in operating days during the current period. There was also a decrease of $5.7 million due to a net change in average dayrates in the current period.
Operating Costs and Expenses
Floaters. During the nine months ended September 30, 2026, total contract drilling services costs related to floaters was $1.1 billion, as compared to $1.2 billion in the nine months ended September 30, 2025. The primary drivers of this decrease were decreases of $40.1 million in rental equipment, $26.7 million related to rigs while in shipyards, $13.5 million in regulatory inspections, $6.5 million in repairs and maintenance, and $6.3 million in insurance costs. Further, there was a decrease of $9.4 million related to certain rigs sold or no longer operated by Noble. These decreases were partially offset by increases of $7.0 million in fuel, $6.0 million in labor, and $8.4 million in non-labor costs, operations support costs, and other costs across the fleet, and a net decrease of $11.4 million in insurance proceeds received compared to prior year.
Jackups. During the nine months ended September 30, 2026, total contract drilling services cost related to jackups was $269.6 million, as compared to $279.4 million in the nine months ended September 30, 2025. The primary drivers of this decrease were decreases of $10.1 million in mobilization, $7.9 million in regulatory inspections, $3.5 million related to rigs while in shipyards, and $3.0 million in transportation and storage. Further, there was a decrease of $18.6 million related to certain rigs sold or no longer operated by Noble. These decreases were partially offset by an increase of $13.3 million in non-labor costs, operations support costs, and other costs across the fleet, and $20.0 million in insurance proceeds received during the prior year.
Depreciation and amortization. Depreciation and amortization totaled $420.4 million and $437.5 million during the nine months ended September 30, 2026 and 2025, respectively. Depreciation and amortization decreased primarily due to divestitures during the current period as well as the timing of capital additions that were placed in service among the periods.
General and administrative. General and administrative expenses totaled $84.3 million and $103.5 million during the nine months ended September 30, 2026 and 2025, respectively. The decrease was primarily driven by lower labor costs of $10.0 million, $2.1 million in training costs, $1.2 million in professional fees. The decrease was partially offset by an increase of $2.2 million in information technology costs.
Merger and integration costs. Noble incurred $2.6 million and $22.4 million of merger and integration costs during the nine months ended September 30, 2026 and 2025, respectively. During the nine months ended September 30, 2026 and 2025, all and the majority of costs incurred, respectively, directly related to the Diamond Transaction. In both periods, such costs related primarily to professional fees and certain integration-related activities.
(Gain) loss on sale of operating assets, net. During the nine months ended September 30, 2026, we sold the Noble Tom Prosser, Noble Mick O'Brien, Noble Regina Allen, Noble Resilient, Noble Resolute, and Ocean Apex resulting in a pre-tax gain of $92.4 million. During the nine months ended September 30, 2025, we sold the Noble Highlander, Pacific Meltem, and Pacific Scirocco, resulting in a pre-tax gain of $11.0 million.
Loss on impairment. During the nine months ended September 30, 2026, we recorded a loss on impairment of $42.3 million to reduce the carrying value of the Ocean Apex to its estimated fair value less costs to sell. During the nine months ended September 30, 2025, we recorded a loss on impairment of $60.7 million to reduce the carrying values of the Noble Globetrotter II and Noble Reacher to their estimated fair value less costs to sell. For additional information, see "Note 4 - Property and Equipment" to our unaudited condensed financial statements.
Other Income and Expenses
Interest expense, net of amounts capitalized. Interest expense totaled $111.8 million and $121.0 million during the nine months ended September 30, 2026 and 2025, respectively. Interest expense is primarily related to our 2034 Notes, 2030 Notes, and the Diamond Second Lien Notes (each as defined below). The decrease in the current period is due to less average principal debt outstanding which also accrued interest at lower rates. For additional information, see "Note 5 - Debt" to our unaudited condensed consolidated financial statements.
Interest income and other, net. Noble recognized interest and other income of $2.8 million and $7.3 million during the nine months ended September 30, 2026 and 2025, respectively. The current period includes $10.3 million of interest income from the seller notes received from the sale of jackup rigs to Borr. The current period interest income was offset by
the fair value adjustment of the notes receivable acquired pertaining to the transaction with Borr. For additional information, see "Note 9 - Supplemental Financial Information-Notes receivable" to our unaudited condensed consolidated financial statements.
Income tax benefit (provision). Noble recorded an income tax provision of $222.3 million and $129.2 million during the nine months ended September 30, 2026 and 2025, respectively.
During the nine months ended September 30, 2026, our tax provision included tax benefits of $23.9 million primarily related to adjustments to valuation allowances for deferred tax benefits primarily in Nigeria. Such tax benefits were offset by tax effects of $23.5 million related to the gain on sale of operating assets and recurring quarterly accruals of $222.7 million mostly in Ghana, Guyana, Luxembourg, Switzerland, and the United States.
During the nine months ended September 30, 2025, our tax provision included tax benefits of $85.1 million related to releases of valuation allowance for deferred tax benefits primarily in Luxembourg. Such tax benefits were offset by tax expenses related to recurring quarterly accruals of $214.3 million mostly in Guyana, Luxembourg, Switzerland, and the United States.
Liquidity and Capital Resources
Sources and Uses of Cash
Our principal source of capital in the current period was cash generated from operating activities as well as net proceeds from the issuance of the 2034 Notes (as defined below). Cash on hand during the current period was primarily used for the following:
•normal recurring operating expenses;
•capital expenditures;
•redemptions of debt and payment of related accrued interest;
•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 share repurchases and repurchases 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 Revolving Credit Facility (as defined below), and we believe this will provide us with sufficient liquidity to fund our cash flow needs over the next 12 months. Additional liquidity is anticipated through the sale of our notes receivable (for more information, see "Note 9 - Supplemental Financial Information" to our unaudited condensed financial statements). 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 $561.9 million and $764.6 million for the nine months ended September 30, 2026 and 2025, respectively. The decrease in net cash provided by operating activities for the nine months ended September 30, 2026, was primarily attributable to the sale of five jackup rigs to Borr as well as the operational suspensions in Brazil during the second and third quarters of 2026. We had working capital of $546.4 million at September 30, 2026, and $512.6 million at December 31, 2025.
Net cash used in investing activities was $282.8 million and $243.7 million for the nine months ended September 30, 2026 and 2025, respectively. The increase in net cash used in investing activities for the nine months ended September 30, 2026, was attributable to capital expenditures on routine projects associated with overhauls and upgrades on various rigs. This was offset by proceeds received from the disposal of rigs.
Net cash used in financing activities was $421.7 million and $288.6 million for the nine months ended September 30, 2026 and 2025, respectively. During the nine months ended September 30, 2026, we issued $800.0 million of new 2034 Notes (as defined below), including debt extinguishment and issuance costs of $40.7 million and $17.6 million, respectively, repaid $850.0 million of debt, made dividend payments to our shareholders of $243.1 million, made finance lease payments of $63.6 million, and paid $9.9 million in taxes withheld on vested employee share-based compensation awards. During the nine months ended September 30, 2025, we repurchased 0.7 million of our Ordinary Shares for a total of $20.0 million,
made dividend payments to our shareholders of $240.4 million, and paid $9.7 million in taxes withheld on vested employee share-based compensation awards.
At September 30, 2026, we had a total contract drilling services backlog of approximately $6.8 billion, which includes a commitment of 66% of available days for the remainder of 2026. For additional information regarding our backlog, see "Contract Drilling Services Backlog."
Capital Expenditures
Capital expenditures were $500.4 million and $367.8 million for the nine months ended September 30, 2026 and 2025, respectively.
Capital expenditures in each period consisted of outlays for sustaining capital, major projects, including subsea and other related projects, capital spares, rebillable capital and contract modifications, and capitalized interest.
Our total capital expenditures estimate for the year ending December 31, 2026, is expected to range between $680.0 million and $705.0 million. We expect to fund these capital expenditures with cash generated by our operations and cash on hand.
From time to time we consider possible projects and certain events may occur that would require expenditures that are not included in our capital budget, and such unbudgeted expenditures could be significant. This includes additional capital expenditures to upgrade rigs for specific customer requirements or contracts. The total amount of capital that we ultimately spend is partly dependent on broader market conditions, the actual level of current and expected contracting activity, as well as costs related to satisfying regulatory requirements. Given many of our capital related projects can take considerable time to complete, the actual costs and timing of expenditures may vary materially from estimates based on various factors, many of which are out of our control. 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
On May 29, 2026, we amended the Amended and Restated Senior Secured Revolving Credit Agreement, dated April 18, 2023, and as previously amended on June 24, 2024, and December 16, 2025 (the "Revolving Credit Facility"). The amendment to the Revolving Credit Facility increased the commitments to $650.0 million and extended the maturity date to May 2031. Subsequently, on September 16, 2026, we made an additional amendment to the Revolving Credit Facility to clarify the types of bilateral credit instruments which may be secured thereunder. The guarantors under the Revolving Credit Facility are the same subsidiaries of Noble Finance II LLC, a wholly-owned, indirect subsidiary of Noble ("Noble Finance II"), that are or will be guarantors of the 2030 Notes and the 2034 Notes (each as defined below).
As of September 30, 2026, we had no borrowings outstanding and $6.7 million of letters of credit issued under the Revolving Credit Facility and an additional $110.7 million in letters of credit and surety bonds issued under bilateral arrangements. For additional information about the Revolving Credit Facility, see "Note 5 - Debt" to our unaudited condensed consolidated financial statements.
6.250% Senior Notes due 2034
On June 11, 2026, Noble Finance II issued $800.0 million in aggregate principal amount of its 6.250% Senior Notes due 2034 (the "2034 Notes"). The 2034 Notes were issued pursuant to an indenture, dated June 11, 2026, among Noble Finance II, the subsidiaries of Noble Finance II party thereto, as guarantors, and the trustee. The net proceeds from the offering of the 2034 Notes together with cash on hand were primarily used to fund the redemption of $300.0 million of outstanding principal amount pertaining to the 8.000% Senior Notes due 2030 and the entirety of the outstanding aggregate principal amount pertaining to the 8.500% Senior Secured Second Lien Notes due 2030 as well as to pay any premiums, fees, and expenses related to the issuance of the 2034 Notes. As of September 30, 2026, we had outstanding $800.0 million aggregate principal amount of our 2034 Notes. For additional information about the 2034 Notes, see "Note 5 - Debt" to our unaudited condensed consolidated financial statements.
8.000% Senior Notes due 2030
In 2023, Noble Finance II issued $600.0 million in aggregate principal amount of its 8.000% Senior Notes due 2030 (the "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), among Noble Finance II, the subsidiaries of Noble Finance II party thereto, as guarantors, and the 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 indenture governing the Initial 2030 Notes 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. On June 11, 2026, Noble Finance II redeemed $300.0 million aggregate principal amount of the 2030 Notes for $312.0 million. As of September 30, 2026, we had outstanding $1.1 billion aggregate principal amount of our 2030 Notes. For additional information about the 2030 Notes, see "Note 5 - Debt" to our unaudited condensed consolidated financial statements.
8.500% Senior Secured Second Lien Notes due 2030
In connection with the agreement and plan of merger, dated June 9, 2024, with Diamond, Dolphin Merger Sub 1, Inc., and Dolphin Merger Sub 2, Inc., under which Noble acquired Diamond in the context of 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, Noble Offshore Drilling, Inc. (formerly known as Dolphin Merger Sub 2, Inc. and as successor by merger with Diamond) ("NODI"), certain of NODI's subsidiaries party thereto, as guarantors, and the trustee and collateral agent. On March 27, 2026, Diamond Foreign Asset Company redeemed $55.0 million aggregate principal amount of the Diamond Second Lien Notes for $56.7 million. On June 11, 2026, Diamond Foreign Asset Company redeemed the remaining $495.0 million aggregate principal amount of the Diamond Second Lien Notes for $522.1 million. As of September 30, 2026, no Diamond Second Lien Notes remained outstanding, the Diamond Second Lien Indenture had been satisfied and discharged in accordance with its terms, and the related liens and security interests had been released, in each case subject to those provisions that by their terms survive the satisfaction and discharge. For additional information about the Diamond Second Lien Notes, see "Note 5 - Debt" to our unaudited condensed consolidated financial statements.
Noble Finance II Financial Information
The indentures governing the 2030 Notes and the 2034 Notes contain covenants that require Noble Finance II to furnish to holders of the 2030 Notes and the 2034 Notes certain financial information relating to Noble Finance II and its restricted subsidiaries. The obligation to furnish such information may be satisfied by providing financial information of Noble along with a description of the differences between such information and the financial information of Noble Finance II and its restricted subsidiaries on a standalone basis. As a result of Noble conducting substantially all of its business through Noble Finance II, the financial position and results of operations for Noble Finance II are the same as the information presented for Noble in all material respects. For the three and nine months ended September 30, 2026, Noble Finance II's operating income (loss) was $10.3 million and $30.9 million higher, respectively, than that of Noble. The operating income (loss) difference is primarily a result of expenses related to corporate professional and legal costs and administration charges attributable to Noble for operations support and stewardship-related services.
Dividends
On October 26, 2026, Noble's Board of Directors declared an interim quarterly cash dividend on our Ordinary Shares of $0.50 per share. This dividend will be paid on December 17, 2026, to shareholders of record at close of business on November 25, 2026.
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. During each of the quarters ended September 30, 2026 and 2025, we declared and paid a dividend of $0.50 per share.
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 the Company'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. On October 22, 2024, the Company's Board of Directors authorized an increased share repurchase authorization of up to an additional $400.0 million and, at the 2025 annual
general meeting of shareholders, shareholders approved the repurchase of up to 23,800,068 Ordinary Shares. The authorization by the Board of Directors has approximately $370.0 million remaining, does not have a fixed expiration, and may be modified, suspended, or discontinued at any time. None of the shareholder authorization to purchase up to 23,800,068 Ordinary Shares has yet been utilized and the authorization by shareholders expires on May 8, 2030 (subject to certain exceptions). The program does not obligate the Company to acquire any particular amount of Ordinary Shares. During the three and nine months ended September 30, 2026, the Company repurchased none of the Company's Ordinary Shares. During the three and nine months ended September 30, 2025, the Company repurchased none and 0.7 million of the Company's Ordinary Shares, respectively. All repurchased shares were subsequently cancelled, and the nominal value of the repurchased shares was transferred to the Capital Redemption reserve. Under this program, repurchases may be made from time to time using a variety of methods such as open market purchases and privately negotiated transactions, in compliance with relevant rules and regulations. In establishing this program, the Board considered the benefits to shareholders of providing the business with this additional capital allocation flexibility to promote long-term value for shareholders alongside other uses of capital.
Critical Accounting Estimates
We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States, 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. Some of our significant accounting policies involve critical accounting estimates because they are particularly dependent on estimates and assumptions made by Noble about matters that are inherently uncertain. We disclose our significant accounting policies in "Note 1 - Organization and Significant Accounting Policies" to our audited consolidated financial statements included in Part II, Item 8 of our Form 10-K.
For information about our critical accounting policies and estimates, see Part II, Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical Accounting Estimates" in our Form 10-K. As of September 30, 2026, there have been no material changes to the judgments, assumptions, and estimates upon which our critical accounting policies and estimates are based.
See Part I, Item 1, Financial Statements, "Note 2 - Accounting Pronouncements," to the unaudited condensed consolidated financial statements for a description of the recent accounting pronouncements.
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