EXHIBIT 99.1

Explanatory Note

Helix Energy Solutions Group, Inc. (the “Company,” “we,” “us” or “our”) is filing this Exhibit 99.1 to recast certain financial information and related disclosures originally presented in Part II, Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations), and Item 8 (Financial Statements and Supplementary Data) of our Annual Report on Form 10-K for the year ended December 31, 2025 (the “2025 Form 10-K”), which was filed with the Securities and Exchange Commission (the “SEC”) on February 26, 2026.

On May 1, 2026, we completed the sale of Helix Alliance, which comprised our former Shallow Water Abandonment reportable segment. Because the disposition represents a strategic shift that has a major effect on our operations and financial results, the historical results of Helix Alliance are presented as discontinued operations for all periods presented. Unless otherwise noted, amounts and disclosures reflect only our continuing operations.

This Exhibit 99.1 recasts the affected portions of the 2025 Form 10-K solely to reflect the presentation of Helix Alliance as discontinued operations. The information contained in this Exhibit 99.1 is not an amendment to, or a restatement of, the 2025 Form 10-K. Except for the discontinued-operations disclosures included herein, this Exhibit 99.1 does not update the 2025 Form 10-K for events, developments, risks, trends or other information occurring after the original filing date, and it does not modify or update the forward-looking statements made in the 2025 Form 10-K, which speak only as of the date of the original filing. Accordingly, this Exhibit 99.1 should be read in conjunction with the 2025 Form 10-K and our subsequent filings with the SEC, including our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2026. Unaffected items and unaffected portions of the 2025 Form 10-K have not been repeated in, and are not amended or modified by, this Exhibit 99.1.

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

The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements located in Item 8. Financial Statements and Supplementary Data of this Exhibit 99.1. Any reference to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Item 8. Financial Statements and Supplementary Data of this Exhibit 99.1. The results of operations reported and summarized below are not necessarily indicative of future operating results. This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under Item 1A. Risk Factors in the 2025 Form 10-K and in our subsequent filings with the SEC.

EXECUTIVE SUMMARY

Our Business

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention, robotics and decommissioning operations. We operate through our three business segments: Well Intervention, Robotics and Production Facilities. We previously reported the Shallow Water Abandonment segment, which was comprised entirely of Helix Alliance, prior to the sale of Helix Alliance on May 1, 2026 and which included nine liftboats, six OSVs, three DSVs, one heavy lift derrick barge, one crew boat, 20 P&A systems and six CT systems. The sale of Helix Alliance reflects a strategic shift away from the shallow-water decommissioning market in the Gulf of America shelf and a renewed focus on our deepwater operations. The financial results of Helix Alliance are presented as discontinued operations for all periods presented. Our services are key in supporting a global energy transition by maximizing production of existing oil and gas reserves, decommissioning end-of-life oil and gas fields and supporting renewable energy developments.

We maximize production of existing oil and gas reserves for our customers primarily in our Well Intervention segment. Historically, drilling rigs have been the asset class used for offshore well intervention work, and rig rates are a pricing indicator for our services. Our customers have used drilling rigs on existing long-term contracts (rig overhang) to perform well intervention work instead of new drilling activities. Current volumes of work, rig utilization rates, the rates quoted by drilling rig contractors and existing rig overhang affect the utilization and/or rates we can achieve for our well intervention assets and services.

Once end-of-life oil and gas wells have depleted their production, we P&A and decommission wells and infrastructure in our Well Intervention segment. We believe that our purpose-built well intervention vessels have a competitive advantage in performing these services more efficiently than rigs.

We support renewable energy primarily in our Robotics segment through our services in offshore wind farm developments, including subsea cable trenching and burial as well as seabed clearance and preparation services. Demand for our services in the renewable energy market is affected by various factors, including the level of offshore wind farm projects, the pace of industry shift towards renewable energy sources, global electricity demand, technological advancements that increase the generation and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water and other regions, and government subsidies for renewable energy projects and/or other governmental regulations supporting or restricting renewable energy developments.

Current Market Environment

Commodity prices dropped 20% during 2025 and have been volatile throughout the year. The current energy market remains uncertain following the ongoing escalation of tariffs and geopolitical tensions globally and their impact on the global economy and energy demands. The offshore oil and gas market continues to evaluate governmental regulations and changes thereto, including the ongoing effects of the U.K. government’s Energy Profits Levy, geopolitical instability and uncertainty, regional conflicts and tensions, unrest in the Middle East, Ukraine and Venezuela, and customer spending declines following mergers in the U.K. North Sea. These factors have shifted spending decisions of our customers into 2026 and prolonged a supply and demand imbalance for offshore vessels, which has negatively impacted activity levels and rates in regions in which we operate.

The international wind market continues to be robust, with continued activity and sanctioned work primarily in Europe and Asia Pacific. U.S. wind farm activity has decreased and remains uncertain following the 2025 Wind Energy Ban, a Presidential Memorandum issued in the U.S. in January 2025 temporarily withdrawing wind energy leasing in the U.S. Outer Continental Shelf.

Business Activity Summary

During 2025, we experienced declined activity levels in the North Sea and Gulf of America with lower customer spending due to the uncertain market environment. However, we were able to maintain significant backlog that will provide strong utilization for our vessels and equipment over multiple years. Notable new contracts executed in 2025 include:

●

Four-year trenching agreement with NKT in the North Sea;

●

Renewables trenching contract with Seaway 7 for estimated 300 days in the North Sea;

●

Three-year framework agreement with ExxonMobil for well decommissioning work in the Gulf of America shelf, which related to our discontinued operations;

●

Well Intervention contract in the Gulf of America for a minimum of 150 days over a three-year period;

●

Multi-year riserless P&A contract in the North Sea on up to 34 subsea wells;

●

Extension of the agreement with HWCG for the HFRS through March 31, 2027; and

●

Extension of the agreement for the HP I for one year until at least June 1, 2027.

During 2025, we executed and/or extended various leases including the charters on the Trym, the North Sea Enabler, and the Patriot, which was delivered to us in January 2026.

We continue to maintain our capital allocation policy of maintaining low levels of Net Debt, maintaining our existing assets, opportunistically targeting markets that complement and further our strategy, and using Free Cash Flow to return cash to shareholders through share repurchases (See “Results of Operations — Non-GAAP Financial Measures” below for definitions of Net Debt and Free Cash Flow).

Outlook

Our 2026 performance should be supported by our existing backlog, of which $676 million is for contracts over the next 12 months, as well as expected new contracting and the materialization of work that had been deferred from 2025. We expect to see continued strong market demand for our Robotics services, in particular our trenching and site preparation offerings. We anticipate an ongoing challenged market for certain of our assets not under long-term contracts, namely in spot markets for our Well Intervention segment, specifically in the North Sea and on the Q4000 and the Q7000, during which time we expect a soft rate environment and uncertain utilization of those vessels and systems.

Beyond 2026, we anticipate increasing energy consumption will continue to place demand for our services in both the oil and gas and renewable energy sectors. We believe these needs will continue to increase customer operating expenditure budgets and demand for our production enhancement offerings and decommissioning services internationally, which should grow over the mid- to long-term as the subsea tree base expands and as customers discharge their decommissioning obligations. We expect long-term growth in our renewables services as the global demand for energy increases and the international energy market continues offshore renewable energy developments.

Backlog

Our backlog is represented by signed contracts. As of December 31, 2025, our consolidated backlog totaled $1.3 billion, of which $676 million is expected to be performed in 2026. As of December 31, 2025, our various contracts with Shell and Subsea 7 globally, our contracts with Petrobras in Brazil, our contract with Talos in the Gulf of America, and our new multi-year agreements with NKT and CNR in the North Sea collectively represented approximately 83% of our total backlog. As of December 31, 2024, our consolidated backlog totaled $1.4 billion. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as (i) services are often added but may sometimes be subtracted; (ii) contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and (iii) reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in backlog.

RESULTS OF OPERATIONS

Non-GAAP Financial Measures

A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under U.S. generally accepted accounting principles (“GAAP”). Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.

We evaluate our operating performance and financial condition based primarily on Adjusted EBITDA, Free Cash Flow and Net Debt. Adjusted EBITDA, Free Cash Flow and Net Debt are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use Adjusted EBITDA, Free Cash Flow and Net Debt to monitor and facilitate internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of Adjusted EBITDA, Free Cash Flow and Net Debt provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand and compare our results to other companies that have different financing, capital and tax structures. Other companies may calculate their measures of Adjusted EBITDA, Free Cash Flow and Net Debt differently from the way we do, which may limit their usefulness as comparative measures. Adjusted EBITDA, Free Cash Flow and Net Debt should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other data prepared in accordance with GAAP.

We define Adjusted EBITDA as earnings before income taxes, net interest expense, depreciation and amortization expense, net other income or expense, gains or losses on disposition of assets, long-lived asset impairment losses, gains or losses related to convertible notes, and the general provision for (release of) current expected credit losses, if any. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from asset sales and insurance recoveries (related to property and equipment), if any. Net Debt is calculated as long-term debt including current maturities of long-term debt less cash and cash equivalents. In the following reconciliations, we provide amounts as reflected in the consolidated financial statements unless otherwise noted.

The reconciliation of our net income (loss) to Adjusted EBITDA is as follows (in thousands):


		Year Ended December 31,
		2025			2024			2023
Net income (loss)		$	30,827		$	55,637		$	(10,838)
Less: Income (loss) from discontinued operations			(12,891)			8,342			(19,328)
Income from continuing operations			17,936			63,979			(30,166)
Adjustments:
Income tax provision			12,305			28,581			13,580
Net interest expense			23,882			23,857			17,324
Other expense, net			1,666			1,493			4,389
Depreciation and amortization			164,337			152,829			143,966
(Gain) loss on disposition of assets, net			—			329			(300)
Long-lived asset impairment			18,064			—			—
General provision for (release of) current expected credit losses			(136)			(161)			1,149
Losses related to convertible senior notes			—			20,922			37,277
Adjusted EBITDA from continuing operations			238,054			291,829			187,219
Adjusted EBITDA from discontinued operations			33,903			11,318			86,184
Adjusted EBITDA		$	271,957		$	303,147		$	273,403

The reconciliation of our cash flows from operating activities to Free Cash Flow is as follows (in thousands):


		Year Ended December 31,
		2025			2024			2023
Cash flows from continuing operating activities		$	116,888		$	237,399		$	95,386
Less: Net capital expenditures from continuing operations			(14,332)			(21,800)			(12,398)
Free Cash Flow from continuing operations			102,556			215,599			82,988
Free Cash Flow from discontinued operations			17,851			(52,411)			50,810
Free Cash Flow		$	120,407		$	163,188		$	133,798

The reconciliation of our long-term debt to Net Debt is as follows (in thousands):


		December 31,
		2025			2024
Long-term debt including current maturities		$	307,995		$	315,157
Less: Cash and cash equivalents ⁽¹⁾			(445,196)			(368,030)
Net Debt		$	(137,201)		$	(52,873)

(1)	Includes cash and cash equivalents of continuing and discontinued operations.

Comparison of Years Ended December 31, 2025 and 2024

We have three reportable business segments in our continuing operations: Well Intervention, Robotics and Production Facilities. We previously reported the Shallow Water Abandonment segment, which was comprised entirely of Helix Alliance, prior to the sale of Helix Alliance on May 1, 2026. The financial results of Helix Alliance are reflected as discontinued operations for all periods presented (Note 4). All material intercompany transactions between the segments have been eliminated in our consolidated financial statements. The following table details various financial and operational highlights of our continuing operations for the periods presented (dollars in thousands):


		Year Ended December 31,						Increase/(Decrease)
		2025			2024			Amount			Percent
Net revenues —
Well Intervention		$	729,371		$	829,862		$	(100,491)		(12)	%
Robotics			323,353			297,678			25,675		9	%
Production Facilities			72,693			88,709			(16,016)		(18)	%
Intercompany eliminations			(33,512)			(44,429)			10,917
		$	1,091,905		$	1,171,820		$	(79,915)		(7)	%

Gross profit —
Well Intervention		$	40,594		$	110,612		$	(70,018)		(63)	%
Robotics			81,781			88,287			(6,506)		(7)	%
Production Facilities			21,147			23,766			(2,619)		(11)	%
Corporate, eliminations and other			(2,316)			(2,324)			8
		$	141,206		$	220,341		$	(79,135)		(36)	%

Gross margin —
Well Intervention			6	%		13	%
Robotics			25	%		30	%
Production Facilities			29	%		27	%
Total company			13	%		19	%

Number of vessels or Robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels			7 / 72	%		7 / 90	%
Robotics assets ⁽³⁾			48 / 59	%		47 / 69	%
Chartered Robotics vessels			7 / 88	%		6 / 92	%

(1)	Represents the number of vessels or Robotics assets as of the end of the period, including spot vessels and those under term charters, and excluding acquired vessels prior to their in-service dates, and vessels or assets disposed of and/or taken out of service.

(2)	Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or Robotics assets generated revenues by the total number of calendar days (excluding vessel charter off-hire days) in the applicable period.

(3)	Consists of ROVs, trenchers and IROV boulder grabs.

Intercompany segment amounts are derived primarily from equipment and services provided to other business segments. Intercompany segment revenues are as follows (in thousands):


		Year Ended December 31,						Increase/
		2025			2024			(Decrease)
Well Intervention		$	—		$	6,390		$	(6,390)
Robotics			33,512			38,039			(4,527)
		$	33,512		$	44,429		$	(10,917)

The following table sets forth significant financial statement items below the gross profit line (in thousands):


		Year Ended December 31,
		2025			2024
Long-lived asset impairment		$	18,064		$	—
Selling, general and administrative expenses			68,865			83,282
Net interest expense			23,882			23,857
Losses related to convertible senior notes			—			20,922
Income tax provision			12,305			28,581
Income (loss) from discontinued operations, net of tax			12,891			(8,342)

Net Revenues. Our consolidated net revenues decreased by 7% in 2025 as compared to 2024, reflecting lower revenues in our Well Intervention and Production Facilities business segments, offset in part by higher revenues in our Robotics segment.

Our Well Intervention revenues decreased by 12% in 2025 as compared to 2024, primarily reflecting overall lower utilization, offset in part by higher rates during 2025. Utilization declined primarily due to the stacking of the Seawell in the North Sea during the entirety of 2025 whereas the vessel had 86% utilization during 2024. Utilization also declined as the Q4000, the Q5000 and the Q7000 collectively underwent 131 docking days during 2025 as compared to 10 days on the Sea Helix 1 during 2024. Additionally, revenues in 2024 included $14 million of contract cancellation fees related to work that had been planned for 2025. Revenue decreases were offset in part by higher rates on the Well Enhancer, and in Brazil in 2025.

Our Robotics revenues increased by 9% in 2025 as compared to 2024, primarily reflecting increased trenching on third party vessels and higher project rates on our vessel activities, offset in part by lower overall vessel and ROV utilization during 2025. Robotics generated 483 days of trenching on third-party vessels during 2025 as compared to 167 days during 2024. However, vessel utilization decreased to 1,808 days (including 75 spot vessel days at full utilization) during 2025 as compared to 1,901 days (including 371 spot vessel days at full utilization) during 2024. Included in vessel days are integrated vessel trenching days, which decreased to 635 days in 2025 as compared to 835 days in 2024, and site clearance vessel days, which increased to 503 days as compared to 325 days in 2024. Overall ROV utilization decreased to 59% during 2025 as compared to 69% during 2024.

Our Production Facilities revenues decreased by 18% in 2025 as compared to 2024, primarily reflecting lower oil and gas production volumes with the Thunder Hawk field being shut in during 2025 after having had approximately seven months of production in 2024. The Droshky field had lower production in 2025 as compared to 2024 and realized oil prices were lower by 12% year over year.

Gross Profit. Our consolidated 2025 gross profit decreased by $79.1 million as compared to 2024, primarily reflecting reduced profitability from our Well Intervention, Robotics and Production Facilities business segments.

Our Well Intervention gross profit decreased by $70.0 million in 2025 as compared to 2024, primarily reflecting lower overall revenues, offset in part by lower vessel costs on the Seawell due to the vessel being warm-stacked in 2025 and higher cost deferrals related to the dockings during 2025.

Our Robotics gross profit decreased by $6.5 million in 2025 as compared to 2024, primarily reflecting lower margins on certain projects due to the mix of contracting, offset in part by higher revenues during 2025.

Our Production Facilities gross profit decreased by $2.6 million in 2025 as compared to 2024, primarily due to lower revenues, offset in part by lower workover costs on the Thunder Hawk field during 2025.

Long-Lived Asset Impairment. The $18.1 million non-cash impairment loss in 2025 was attributable to the impairment of the remaining net book value of the Thunder Hawk field (Note 6).

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $68.9 million in 2025 as compared to $83.3 million in 2024, primarily reflecting decreases in employee compensation-related costs during 2025.

Losses Related to Convertible Senior Notes. The losses during 2024 were associated with the redemption of our Convertible Senior Notes due 2026 (the “2026 Notes”) (Note 8).

Income Tax Provision. Income tax provision was $12.3 million for 2025 as compared to $28.6 million for 2024. The effective tax rate for 2025 was impacted by certain discrete items, additional foreign tax credit benefits and the jurisdictional mix of earnings. The effective rate for 2024 was impacted by the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event.

Income (Loss) from Discontinued Operations, Net of Tax. Net income from discontinued operations was $12.9 million in 2025 as compared to a net loss of $8.3 million in 2024, primarily reflecting higher utilization on Helix Alliance’s systems and on the Epic Hedron heavy lift barge as well as higher margin contracting during 2025.

Comparison of Years Ended December 31, 2024 and 2023

The following table details various financial and operational highlights of our continuing operations for the periods presented (dollars in thousands):


		Year Ended December 31,						Increase/(Decrease)
		2024			2023			Amount			Percent
Net revenues —
Well Intervention		$	829,862		$	707,718		$	122,144		17	%
Robotics			297,678			257,875			39,803		15	%
Production Facilities			88,709			87,885			824		1	%
Intercompany eliminations			(44,429)			(38,616)			(5,813)
		$	1,171,820		$	1,014,862		$	156,958		15	%

Gross profit —
Well Intervention		$	110,612		$	47,164		$	63,448		135	%
Robotics			88,287			60,618			27,669		46	%
Production Facilities			23,766			23,494			272		1	%
Corporate, eliminations and other			(2,324)			(2,181)			(143)
		$	220,341		$	129,095		$	91,246		71	%

Gross margin —
Well Intervention			13	%		7	%
Robotics			30	%		24	%
Production Facilities			27	%		27	%
Total company			19	%		13	%

Number of vessels or Robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels			7 / 90	%		7 / 88	%
Robotics assets ⁽³⁾			47 / 69	%		46 / 62	%
Chartered Robotics vessels			6 / 92	%		6 / 96	%

(1)	Represents the number of vessels or Robotics assets as of the end of the period, including spot vessels and those under term charters, and excluding acquired vessels prior to their in-service dates, and vessels or assets disposed of and/or taken out of service.

(2)	Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or Robotics assets generated revenues by the total number of calendar days (excluding vessel charter off-hire days) in the applicable period.

(3)	Consists of ROVs, trenchers and IROV boulder grabs.

Intercompany segment amounts are derived primarily from equipment and services provided to other business segments. Intercompany segment revenues are as follows (in thousands):


		Year Ended December 31,						Increase/
		2024			2023			(Decrease)
Well Intervention		$	6,390		$	3,353		$	3,037
Robotics			38,039			35,263			2,776
		$	44,429		$	38,616		$	5,813

The following table sets forth significant financial statement items below the gross profit line (in thousands):


	Year Ended December 31,
	2024			2023
Selling, general and administrative expenses	$	83,282		$	89,200
Net interest expense		23,857			17,324
Losses related to convertible senior notes		20,922			37,277
Other expenses, net		1,493			4,389
Income tax provision		28,581			13,580
Income (loss) from discontinued operations, net of tax		(8,342)			19,328

Net Revenues. Our consolidated net revenues increased by 15% in 2024 as compared to 2023, reflecting higher revenues in our Well Intervention, Robotics and Production Facilities business segments.

Our Well Intervention revenues increased by 17% in 2024 as compared to 2023, primarily reflecting higher overall utilization and rates. Utilization increased on the Q4000 and the Q5000 during 2024 as both vessels underwent their regulatory dry docks in 2023. The Q7000 had higher utilization and higher integrated project rates during 2024 as compared to 2023. The Seawell‘s contract in the western Mediterranean, which completed in June 2024, has provided higher rates and utilization during 2024 as compared to 2023. The Well Enhancer in the North Sea had lower utilization as compared to the prior year as the vessel underwent a scheduled dry dock during the first quarter 2024 and both vessels saw a fourth quarter seasonal slowdown in 2024 whereas the vessels were nearly fully utilized in 2023. Our North Sea revenues in 2024 also included a contract cancellation fee of approximately $14 million related to work that had been scheduled for 2025. The Siem Helix 1 had higher revenues during 2024 as compared to 2023 due to Trident contract extensions with higher rates. The Siem Helix 2 had lower utilization during 2024 as the vessel commenced its unpaid vessel acceptance period at the end of December 2024 on its new contract with Petrobras.

Our Robotics revenues increased by 15% in 2024 as compared to 2023, primarily reflecting higher chartered vessel days and trenching and ROV activities. Chartered vessel activity increased to 1,901 days during 2024 as compared to 1,699 days during 2023, although chartered vessel days in 2024 included approximately 64 days of standby utilization at reduced rates. Overall ROV and trencher utilization increased to 69% in 2024 from 62% during 2023 and included 835 days of integrated vessel trenching in 2024 as compared to 807 days in 2023.

Our Production Facilities revenues increased slightly in 2024 as compared to 2023, primarily reflecting higher oil and gas production and lower number of shut-in days on our owned oil and gas wells, offset in part by lower rates on the HFRS, which were reduced in the second half 2024 when the Q4000 left the U.S. Gulf Coast to execute the Nigeria project.

Gross Profit. Our consolidated 2024 gross profit increased by $91.2 million as compared to 2023, primarily reflecting increased profits from our Well Intervention, Robotics and Production Facilities business segments.

Our Well Intervention gross profit increased by $63.4 million in 2024 as compared to 2023, primarily reflecting higher segment revenues and increased activity levels and included a contract cancellation fee of approximately $14 million.

Our Robotics gross profit increased by $27.7 million in 2024 as compared to 2023, primarily reflecting higher revenues and higher profit margin projects during 2024.

Our Production Facilities gross profit increased slightly in 2024 as compared to 2023, primarily reflecting higher segment revenues.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $83.3 million in 2024 as compared to $89.2 million in 2023, primarily reflecting a net decrease in compensation related costs offset partially by an increase in other facilities and professional fees in 2024.

Net Interest Expense. Our net interest expense totaled $23.9 million in 2024 as compared to $17.3 million in 2023, primarily reflecting higher debt levels and rates on our $300 million Senior Notes due 2029 (the “2029 Notes”) in 2024 as compared to our 2026 Notes in 2023, offset in part by higher interest income due to the higher level of our invested cash (Note 8).

Losses Related to Convertible Senior Notes. The losses during 2024 and 2023 were primarily associated with the retirement of our 2026 Notes (Note 8).

Other Expense, Net. Net other expense was $1.5 million in 2024 as compared to $4.4 million in 2023. Net other expense during 2024 primarily reflects foreign currency losses due to the weakening of the British pound and Brazilian real in 2024. Net other expense during 2023 primarily reflects foreign currency losses related to the devaluation of the Nigerian naira on our naira cash holdings, offset in part by foreign currency gains due to the strengthening of the British pound in 2023.

Income Tax Provision. Income tax provision was $28.6 million for 2024 as compared to $13.6 million for 2023. The effective tax rates for 2024 and 2023 were 30.9% and (81.9)%, respectively. These variances were primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions, non-deductible losses on the extinguishment of long-term debt as well as losses for which no financial statement benefits have been recognized.

Income (Loss) from Discontinued Operations, Net of Tax Net loss from discontinued operations was $8.3 million in 2024 as compared to net income of $19.3 million in 2023, primarily reflecting lower revenues due to a softer market and lower activity levels. See Note 4 to our consolidated financial statements for additional information regarding discontinued operations.

LIQUIDITY AND CAPITAL RESOURCES

Financial Condition and Liquidity

The following table presents certain information useful in the analysis of our financial condition and liquidity (in thousands):


		December 31,
		2025			2024
Net working capital		$	525,314		$	405,266
Long-term debt (excluding current maturities)			298,351			305,971
Liquidity			553,550			429,586

Net Working Capital

Net working capital is equal to current assets minus current liabilities and includes cash and cash equivalents, current maturities of long-term debt and current operating lease liabilities. Net working capital measures short-term liquidity and is important for predicting cash flow and debt requirements. Net working capital at December 31, 2025 and 2024 included current assets and current liabilities of discontinued operations.

Long-Term Debt

Long-term debt in the table above, presented net of unamortized debt discount and debt issuance costs, includes the 2029 Notes and the MARAD Debt, excluding current maturities of $9.6 million and $9.2 million, respectively, at December 31, 2025 and 2024. See Note 8 to our consolidated financial statements for information relating to our long-term debt.

Liquidity

We define liquidity as cash and cash equivalents plus available capacity under our credit facility, but excluding cash pledged as collateral toward the Amended ABL Facility. Our liquidity at December 31, 2025 included $445.2 million of cash and cash equivalents and $110.9 million of available borrowing capacity under the Amended ABL Facility (Note 8) and excluded $2.5 million of pledged cash. Our liquidity at December 31, 2024 included $368.0 million of cash and cash equivalents and $66.6 million of available borrowing capacity under the Amended ABL Facility and excluded $5.0 million of pledged cash. Cash and cash equivalents at December 31, 2025 and 2024 included of $26.9 million and $24.2 million, respectively, from discontinued operations.

We have considered Helix Alliance as discontinued operations in evaluating our liquidity and capital resources, including our ability to fund continuing operations, expected capital spending, debt service and other obligations over the next 12 months. We believe that our cash on hand, internally generated cash flows from continuing operations and availability under the Amended ABL Facility will be sufficient to fund our operations and expected capital spending, service our debt and other obligations, and execute our share repurchase program over at least the next 12 months. We currently do not anticipate borrowing under the Amended ABL Facility except for the issuance of letters of credit.

Cash Flows

The following table provides summary data from our consolidated statements of cash flows, which include cash flows from discontinued operations for all periods presented (in thousands):


		Year Ended December 31,
		2025			2024		2023
Cash provided by (used in):
Operating activities		$	136,749		$	186,028	$	152,457
Investing activities			(16,342)			(22,840)		(18,659)
Financing activities			(45,059)			(125,310)		25,109

The cash flows of Helix Alliance are included in our consolidated operating, investing and financing cash flows for all periods presented, and the following discussion identifies the impacts of discontinued operations, where material.

Operating Activities

Cash flows provided by operating activities for 2025 decreased as compared to 2024, primarily reflecting lower earnings, higher regulatory certification costs for our vessels and systems in our continuing operations and net working capital outflows. Regulatory certification costs, which are considered part of our capital spending program but are classified in operating cash flows, were $48.8 million in 2025 compared to $28.8 million in 2024 for continuing operations.

The increase in our operating cash flows for 2024 as compared to 2023 primarily reflects higher operating income, lower regulatory recertification costs for our vessels and systems in our continuing operations and working capital inflows. Operating cash outflows during 2024 included net interest expense and taxes paid of $25.4 million and $14.1 million, respectively. Regulatory recertification spend on our vessels and systems amounted to $28.8 million and $59.9 million, respectively, for continuing operations during the comparable year over year periods.

Helix Alliance generated (utilized) operating cash flows of $19.9 million, $(51.4) million, and $57.1 million in 2025, 2024 and 2023, respectively. Operating cash outflows from Helix Alliance during 2024 were primarily driven by $58.3 million of the $85.0 million earnout payment on April 3, 2024.

Investing Activities

Cash flows used in investing activities for 2025 decreased as compared to 2024 primarily due to lower capital expenditures in our Well Intervention and Robotics segments. Cash flows used in investing activities for 2024 increased as compared to 2023 primarily due to higher capital expenditures with increased activity in our Robotics segment. Capital expenditures attributable to Helix Alliance were $2.0 million, $1.4 million and $6.9 million in 2025, 2024 and 2023, respectively.

Financing Activities

Net cash outflows from financing activities for 2025 primarily reflect the repurchases of $30.2 million in our common stock under the 2023 Repurchase Program and related excise tax payments, principal repayment of $9.2 million related to the MARAD Debt and payments in satisfaction of tax obligations upon vesting of share-based awards.

Net cash outflows from financing activities for 2024 primarily reflect cash outflows of $60.7 million related to the 2026 Notes, the principal repayment of $8.7 million related to the MARAD Debt and $29.6 million in repurchases of our common stock under the 2023 Repurchase Program. These outflows were offset in part by $4.4 million of cash inflows from the proportionate settlement of the 2026 Capped Calls. Financing cash outflows during 2024 included $26.7 million of the $85.0 million earnout payment related to Helix Alliance.

Net cash inflows from financing activities for 2023 primarily reflect net proceeds of $292.0 million from the issuance of $300.0 million 2029 Notes and of $15.6 million from the proportionate settlement of the 2026 Capped Calls, offset in part by cash outflows of $230.7 million related to the repurchase of the 2026 Notes, $30.4 million related to the maturity of the Convertible Senior Notes due 2023, the principal repayment of $8.3 million related to the MARAD Debt and $12.0 million in repurchases of our common stock under the 2023 Repurchase Program.

Material Cash Requirements

Our material cash requirements include our obligations to repay our long-term debt, satisfy other contractual cash commitments and fund other obligations.

Long-term debt and other contractual commitments

The following table summarizes (in thousands) the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for operating lease obligations and property and equipment, as of December 31, 2025 and the portions of those amounts that are short-term (due in less than one year) and long-term (due in one year or greater) based on their stated terms. Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory certification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of December 31, 2025. The table below excludes commitments relating to discontinued operations.


		Total			Short-Term			Long-Term
MARAD debt		$	14,645		$	9,644		$	5,001
2029 Notes			300,000			—			300,000
Interest related to debt			95,369			30,282			65,087
Property and equipment			5,067			5,067			—
Operating leases ⁽¹⁾			787,101			163,904			623,197
Total cash obligations		$	1,202,182		$	208,897		$	993,285

(1)

Operating leases include vessel charters and facility and equipment leases, including commitments related to leases executed but not yet commenced. At December 31, 2025, our commitment related to long-term vessel charters that have commenced totaled approximately $724.9 million, of which $366.9 million was related to the non-lease (services) components that are not included in operating lease liabilities in the consolidated balance sheet as of December 31, 2025.

Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 16). Those obligations, which are presented on a discounted basis on the consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk field oil and gas properties and $37.1 million (undiscounted) for Droshky field oil and gas properties as of December 31, 2025. We are entitled to receive $30.0 million (undiscounted) from Marathon Oil Corporation as certain decommissioning obligations associated with Droshky field oil and gas properties are fulfilled.

Regulatory certification and dry dock. Our vessels and systems are subject to certain regulatory certification requirements that must be satisfied in order for the vessels and systems to operate. Certification may require dry dock and other compliance costs on a periodic basis, usually every 30 months. Although the amount and timing of these costs may vary and are dependent on the timing of the certification renewal period, they generally range between $5.0 million to $15.0 million per vessel and $0.5 million to $5.0 million per system, excluding discontinued operations.

We expect the sources of funds to satisfy our material cash requirements to primarily come from our ongoing operations and existing cash on hand. Although not currently expected to be utilized, we also have availability under the Amended ABL Facility and access to capital markets.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our discussion and analysis of our financial condition and results of operations, as reflected in the consolidated financial statements and related footnotes included in Item 8. Financial Statements and Supplementary Data of this Exhibit 99.1, are prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that have had or are reasonably likely to have a material impact on our financial condition or results of operations. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates involve a significant level of estimation uncertainty and may change over time as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We believe that the most critical accounting estimates are described below. See Note 2 to our consolidated financial statements for a detailed discussion on the application of our accounting policies.

Property and Equipment

We review our property and equipment for impairment indicators at least quarterly or whenever changes in facts and circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. We evaluate impairment indicators considering the nature of the asset or asset group, the future economic benefits of the asset or asset group, historical and estimated future profitability measures, and other external market conditions or factors that may be present. We often estimate future earnings and cash flows of our assets to corroborate our determination of whether impairment indicators exist. If impairment indicators suggest that the carrying amount of an asset may not be recoverable, we determine whether an impairment has occurred by estimating undiscounted cash flows of the asset and comparing those cash flows to the asset’s carrying value. If the undiscounted cash flows are less than the asset’s carrying value (i.e., the asset is unrecoverable), impairment, if any, is recognized for the difference between the asset’s carrying value and its estimated fair value. The expected future cash flows used for the assessment of recoverability are based on judgmental assessments of operating costs, project margins and capital project spending, considering information available at the date of review. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible.

The review of property and equipment for impairment indicators, the projection of future cash flows of property and equipment, and the estimated fair value of any property and equipment that may be deemed unrecoverable involve significant judgment and estimation by our management. Changes to those judgments and estimations could require us to recognize impairment charges in the future.

New Accounting Standards

For discussion on the potential impact of new accounting standards issued but not yet adopted, see Note 2 to our consolidated financial statements.

Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

Helix Energy Solutions Group, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Helix Energy Solutions Group, Inc. and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of property and equipment impairment triggering events

As discussed in Note 2 to the consolidated financial statements, the Company evaluates property and equipment for impairment at least quarterly or whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable, or triggering events. The Company performs this evaluation considering the future economic benefits of the asset or asset groups, historical and estimated future profitability measures, and other factors that may be present, such as extended periods of idle time or the inability to contract the Company’s equipment at economical rates.

We identified the evaluation of property and equipment impairment triggering events as a critical audit matter. Sustained decreases in commodity prices and uncertainty regarding spending trends by customers in the industry may lead to periods of low utilization and low day rates for those assets or asset groups not under a long-term contract, and the evaluation of the impact of these factors required a higher degree of subjective auditor judgment.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the evaluation of property and equipment for impairment. This included controls related to the Company’s process to identify and evaluate triggering events that indicate that the carrying value of an asset or asset group may not be recoverable, including the consideration of forecasted to actual results and market conditions in determination of a triggering event. We evaluated the Company’s identification of triggering events, including consideration of future expected revenues from executed contracts. We compared data used by the Company against analyst and industry reports. We compared the Company’s historical forecasts to actual results by asset group to assess the Company’s ability to accurately forecast.

/s/ KPMG LLP

We have served as the Company’s auditor since 2016.

Houston, Texas

February 26, 2026, except for the effects of the discontinued operations as discussed in Note 4, as to which the date is August 11, 2026.

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


		December 31,
		2025			2024
ASSETS
Current assets:
Cash and cash equivalents		$	418,289		$	343,873
Accounts receivable, net of allowance for credit losses of $2,564 and $2,700, respectively			240,604			210,322
Other current assets			65,321			74,471
Current assets of discontinued operations			100,778			81,016
Total current assets			824,992			709,682
Property and equipment			3,024,768			2,938,916
Less accumulated depreciation			(1,735,287)			(1,590,149)
Property and equipment, net			1,289,481			1,348,767
Operating lease right-of-use assets			301,711			327,651
Deferred certification and dry dock costs, net			69,959			65,581
Other assets, net			50,442			47,053
Non-current assets of discontinued operations			79,319			98,346
Total assets		$	2,615,904		$	2,597,080

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	111,587		$	127,608
Accrued liabilities			90,965			85,606
Current maturities of long-term debt			9,644			9,186
Current operating lease liabilities			60,208			58,922
Current liabilities of discontinued operations			27,274			23,094
Total current liabilities			299,678			304,416
Long-term debt			298,351			305,971
Operating lease liabilities			260,608			285,046
Deferred tax liabilities			105,571			113,973
Other non-current liabilities			71,433			66,971
Non-current liabilities of discontinued operations			351			938
Total liabilities			1,035,992			1,077,315
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 147,186 and 150,243 shares issued, respectively			1,218,494			1,252,253
Retained earnings			398,914			368,087
Accumulated other comprehensive loss			(37,496)			(100,575)
Total shareholders’ equity			1,579,912			1,519,765
Total liabilities and shareholders’ equity		$	2,615,904		$	2,597,080

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Year Ended December 31,
	2025			2024			2023
Net revenues	$	1,091,905		$	1,171,820		$	1,014,862
Cost of sales		950,699			951,479			885,767
Gross profit		141,206			220,341			129,095
Gain (loss) on disposition of assets, net		—			(329)			300
Long-lived asset impairment		(18,064)			—			—
Selling, general and administrative expenses		(68,865)			(83,282)			(89,200)
Income from operations		54,277			136,730			40,195
Net interest expense		(23,882)			(23,857)			(17,324)
Losses related to convertible senior notes		—			(20,922)			(37,277)
Other expense, net		(1,666)			(1,493)			(4,389)
Royalty income and other		1,512			2,102			2,209
Income (loss) from continuing operations before income taxes		30,241			92,560			(16,586)
Income tax provision		12,305			28,581			13,580
Income (loss) from continuing operations		17,936			63,979			(30,166)
Income (loss) from discontinued operations, net of tax		12,891			(8,342)			19,328
Net income (loss)	$	30,827		$	55,637		$	(10,838)

Basic earnings (loss) per share of common stock:
Continuing operations	$	0.12		$	0.42		$	(0.20)
Discontinued operations		0.09			(0.05)			0.13
Net income (loss) per common share	$	0.21		$	0.37		$	(0.07)

Diluted earnings (loss) per share of common stock:
Continuing operations	$	0.12		$	0.41		$	(0.20)
Discontinued operations		0.09			(0.05)			0.13
Net income (loss) per common share	$	0.21		$	0.36		$	(0.07)

Weighted average common shares outstanding:
Basic		148,349			151,989			150,917
Diluted		148,454			154,699			150,917

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	Year Ended December 31,
	2025			2024		2023
Net income (loss)	$	30,827		$	55,637	$	(10,838)
Other comprehensive income (loss) - foreign currency translation gain (loss), net of tax		63,079			(17,560)		22,304
Comprehensive income	$	93,906		$	38,077	$	11,466

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in thousands)


								Accumulated
								Other		Total
		Common Stock				Retained		Comprehensive		Shareholders’
		Shares		Amount		Earnings		Loss		Equity
Balance, December 31, 2022		151,935		$	1,298,740	$	323,288	$	(105,319)	$	1,516,709
Net loss		—			—		(10,838)		—		(10,838)
Foreign currency translation adjustments		—			—		—		22,304		22,304
Repurchase of convertible senior notes		1,500			(35,469)		—		—		(35,469)
Termination of capped calls		—			14,225		—		—		14,225
Repurchases of common stock		(1,584)			(11,988)		—		—		(11,988)
Activity in company stock plans, net and other		440			(92)		—		—		(92)
Share-based compensation		—			6,149		—		—		6,149
Balance, December 31, 2023		152,291		$	1,271,565	$	312,450	$	(83,015)	$	1,501,000
Net income		—			—		55,637		—		55,637
Foreign currency translation adjustments		—			—		—		(17,560)		(17,560)
Settlement of convertible debt conversion		—			(84)		—		—		(84)
Termination of capped calls		—			4,381		—		—		4,381
Repurchases of common stock		(2,867)			(29,821)		—		—		(29,821)
Activity in company stock plans, net and other		819			(468)		—		—		(468)
Share-based compensation		—			6,680		—		—		6,680
Balance, December 31, 2024		150,243		$	1,252,253	$	368,087	$	(100,575)	$	1,519,765
Net income		—			—		30,827		—		30,827
Foreign currency translation adjustments		—			—		—		63,079		63,079
Repurchases of common stock		(4,643)			(30,164)		—		—		(30,164)
Activity in company stock plans, net and other		1,586			(5,047)		—		—		(5,047)
Share-based compensation		—			6,086		—		—		6,086
Reclassification of fair value of modified liability awards		—			(4,634)		—		—		(4,634)
Balance, December 31, 2025		147,186		$	1,218,494	$	398,914	$	(37,496)	$	1,579,912

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


		Year Ended December 31,
		2025		2024		2023
Cash flows from operating activities:
Net income (loss)		$	30,827	$	55,637	$	(10,838)
Less: Income (loss) from discontinued operations, net of tax			(12,891)		8,342		(19,328)
Income (loss) from continuing operations			17,936		63,979		(30,166)
Adjustments to reconcile income (loss) from continuing operations to net cash provided by continuing operating activities:
Depreciation and amortization, excluding amortization of deferred certification and dry dock costs			116,381		120,561		120,838
Amortization of deferred certification and dry dock costs			47,956		32,268		23,128
Long-lived asset impairment			18,064		—		—
Deferred certification and dry dock costs			(48,841)		(28,756)		(59,917)
Amortization of debt discount			240		218		17
Amortization of debt issuance costs			2,063		2,132		2,485
Share-based compensation			6,504		7,192		6,510
Deferred income taxes			(4,746)		(3,053)		9,579
(Gain) loss on disposition of assets, net			—		329		(300)
Losses related to convertible senior notes			—		20,922		37,277
Unrealized foreign currency losses			374		623		8,310
Changes in operating assets and liabilities:
Accounts receivable, net			(22,487)		(8,294)		(43,259)
Other current assets			18,585		4,334		(22,068)
Income tax receivable, net of income tax payable			(12,181)		17,732		(3,237)
Accounts payable and accrued liabilities			(23,114)		3,373		36,395
Other, net			154		3,839		9,794
Net cash provided by continuing operating activities			116,888		237,399		95,386
Net cash provided by (used in) discontinued operating activities			19,861		(51,371)		57,071
Net cash provided by operating activities			136,749		186,028		152,457

Cash flows from investing activities:
Capital expenditures			(14,332)		(21,900)		(12,698)
Proceeds from sale of assets			—		100		300
Net cash used in continuing investing activities			(14,332)		(21,800)		(12,398)
Net cash used in discontinued investing activities			(2,010)		(1,040)		(6,261)
Net cash used in investing activities			(16,342)		(22,840)		(18,659)

Cash flows from financing activities:
Proceeds from senior notes, net of discount			—		—		298,578
Payments related to convertible senior notes			—		(60,720)		(261,147)
Repayment of MARAD Debt			(9,186)		(8,749)		(8,333)
Proceeds from settlement of capped calls			—		4,381		15,591
Debt issuance costs			—		(1,530)		(6,817)
Repurchases of common stock and payments of related excise tax			(30,214)		(29,620)		(11,988)
Payments related to tax withholding for share-based compensation			(7,404)		(4,231)		(1,757)
Proceeds from issuance of ESPP shares			1,745		1,859		982
Net cash provided by (used in) continuing financing activities			(45,059)		(98,610)		25,109
Net cash used in discontinued financing activities			—		(26,700)		—
Net cash provided by (used in) financing activities			(45,059)		(125,310)		25,109

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

(in thousands)


	Year Ended December 31,
	2025		2024		2023
Effect of exchange rate changes on cash and cash equivalents		1,818		(2,039)		(15,827)
Net increase in cash and cash equivalents		77,166		35,839		143,080
Cash and cash equivalents ⁽¹⁾:
Balance, beginning of year		368,030		332,191		189,111
Balance, end of year	$	445,196	$	368,030	$	332,191

(1)Includes cash and cash equivalents of continuing and discontinued operations.

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization

Unless the context indicates otherwise, the terms “we,” “us” and “our” in this Annual Report refer collectively to Helix Energy Solutions Group, Inc. and its subsidiaries (“Helix” or the “Company”). We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention, robotics and decommissioning operations. Our services are key in supporting a global energy transition by maximizing production of existing oil and gas reserves, decommissioning end-of-life oil and gas fields and supporting renewable energy developments. We provide a range of services to the oil and gas and renewable energy markets primarily in the Gulf of America, Brazil, North Sea, West Africa and Asia Pacific regions. Our North Sea operations are usually subject to seasonal changes in activity levels, which generally peaks in the summer months and declines in the winter months.

Our Operations

Our services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities. We previously reported the Shallow Water Abandonment segment, which was comprised entirely of Helix Alliance, prior to the sale of Helix Alliance on May 1, 2026, as further discussed below under Basis of Presentation.

Our Well Intervention segment provides services enabling our customers to safely access subsea offshore wells for the purpose of performing production enhancement or decommissioning operations, thereby mitigating the need to drill new wells by extending the useful lives of existing wells and preserving the environment by preventing uncontrolled releases of oil and natural gas. Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and two chartered vessels, the Sea Helix 1 (formerly Siem Helix 1) and the Siem Helix 2. Our well intervention equipment includes intervention systems such as intervention riser systems (“IRSs”), subsea intervention lubricators (“SILs”) and the Riserless Open-water Abandonment Module, some of which we provide on a stand-alone basis.

Our Robotics segment provides subsea trenching, seabed clearance, offshore construction and inspection, repair and maintenance (“IRM”) services to both the oil and gas and the renewable energy markets globally, thereby assisting the delivery of renewable energy and supporting the responsible transition to additional energy sources. Additionally, our robotics services are used in and complement our well intervention services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers, IROV boulder grabs and robotics support vessels under term charters as well as spot vessels as needed. We offer our ROVs, trenchers and IROV boulder grabs on a stand-alone basis or on an integrated basis with chartered robotics support vessels.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamically positioned floating production vessel, the Helix Fast Response System (the “HFRS”), which combines our capabilities with certain well control equipment that can be deployed to respond to a well control incident, and our ownership of mature oil and gas properties. All of our current Production Facilities activities are located in the Gulf of America.

Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of our majority-owned subsidiaries. All material intercompany accounts and transactions have been eliminated.

Basis of Presentation

Our consolidated financial statements have been prepared in U.S. dollars in conformity with accounting principles generally accepted in the U.S. (“GAAP”). Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format. We have made all adjustments that we believe are necessary for a fair presentation of our consolidated financial statements.

On May 1, 2026, we completed the sale of Helix Alliance, which comprised our former Shallow Water Abandonment reportable segment. The transaction represented a strategic shift that had a major effect on our operations and financial results. Accordingly, the historical results of Helix Alliance are presented as discontinued operations in our consolidated financial statements for all periods presented. Unless otherwise noted, amounts and disclosures in the Notes to the Consolidated Financial Statements reflect only our continuing operations. See Note 4 for additional information.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are highly liquid financial instruments with original maturities of three months or less. They are carried at cost plus accrued interest, which approximates fair value. Cash includes amounts pledged toward our asset-based credit agreement (Note 8) unless our ability to withdraw those amounts is restricted.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are recognized when our right to consideration becomes unconditional. Accounts receivable are stated at the historical carrying amount, net of write-offs and allowance for credit losses. We perform ongoing credit evaluations of our customers and provide allowances for expected credit losses. We estimate current expected credit losses on our accounts receivable at each reporting date based on our credit loss history, adjusted for current factors including global economic and business conditions, offshore energy industry and market conditions, customer mix, contract payment terms and past due accounts receivable. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when we have determined that the balance will not be collected (Note 19).

Business Combinations

Business combinations are accounted for using the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, Business Combinations. The purchase price consideration is allocated to the assets acquired and liabilities assumed based upon estimates of their fair values as of the acquisition date. Fair values of the assets acquired and liabilities assumed are measured in accordance with ASC Topic 820, Fair Value Measurement, using income approach, cost approach and other applicable valuation techniques. The fair value of property, plant and equipment acquired from the acquisition was estimated primarily by applying the cost approach. The key assumptions of the cost approach include replacement cost new, physical deterioration, functional and economic obsolescence and economic useful life. The fair value of intangible assets acquired from the acquisition was estimated primarily by applying the income approach. The key assumptions of the income approach include revenue projections, royalty rates and economic useful life. For certain other assets and liabilities, those fair values are consistent with historical carrying values.

The purchase price allocation is subject to revision to reflect new information obtained about facts and circumstances that existed at the acquisition date. The purchase price consideration, as well as the estimated fair values of the assets acquired and liabilities assumed, is finalized as soon as practicable, but no later than one year from the closing of the acquisition.

Contingent consideration payable in cash is initially measured at fair value and included as part of the purchase price and subsequently measured at fair value at the end of each reporting period with changes in value reported the consolidated statements of discontinued operations until the liability is no longer contingent. Cash paid for the contingent consideration in an amount equaling to its initial fair value at the acquisition date is reported in financing cash flows from discontinued operations and any amounts paid in excess of the initial fair value are reported in operating cash flows from discontinued operations.

Acquisition and integration costs consist of legal and professional fees as well as costs incurred to integrate the acquiree’s operations and systems and to align its financial processes and procedures with those of Helix. Those costs are expensed as incurred and are presented separately from “Selling, general and administrative expenses” in income (loss) from discontinued operations.

Property and Equipment

Property and equipment (including oil and gas properties) acquired separately from a business combination is recorded initially at cost and subsequently depreciated on a straight-line basis over its estimated useful life. The cost of improvements is capitalized whereas the cost of repairs and maintenance is expensed as incurred.

Assets used in operations are assessed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable because such carrying amount may exceed the asset’s or asset group’s expected undiscounted cash flows. If the carrying amount of the asset or asset group is not recoverable and is greater than its fair value, an impairment charge is recorded. The amount of the impairment recorded is calculated as the difference between the carrying amount of the asset or asset group and its estimated fair value. Individual assets are evaluated for impairment at the lowest level where there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

Leases

Leases with a term greater than one year are recognized in the consolidated balance sheet as lease liabilities and right-of-use (“ROU”) assets. We have not recognized in the consolidated balance sheet leases with an initial term of one year or less. Lease liabilities and their corresponding ROU assets are recorded at the commencement date based on the present value of lease payments over the expected lease term. The lease term may include the option to extend or terminate the lease when it is reasonably certain that we will exercise the option. We use our incremental borrowing rate, which would be the rate incurred to borrow on a collateralized basis over a similar term in a similar economic environment, to calculate the present value of lease payments. ROU assets are adjusted for any initial direct costs paid or incentives received.

We separate our long-term vessel charters between their lease components and non-lease services. We estimate the lease component using the residual approach by estimating the non-lease services, which primarily include crew, repair and maintenance, and regulatory certification costs. For all other leases, we have not separated the lease components and non-lease services.

We recognize operating lease cost on a straight-line basis over the lease term for both (i) leases that are recognized in the consolidated balance sheet and (ii) short-term leases. We recognize lease cost related to variable lease payments that are not recognized in the consolidated balance sheet in the period in which the obligation is incurred.

Deferred Certification and Dry Dock Costs

Our vessels and systems are required by regulation to be periodically recertified. Certification costs for a vessel are typically incurred while the vessel is in regulatory docking. We defer and amortize certification costs, including vessel dry dock costs, over the period that the certification applies, which generally ranges from 24 to 60 months. Major replacements and improvements that extend the economic useful life or functional operating capability of a vessel or system are capitalized and depreciated over the asset’s remaining economic useful life. Routine repairs and maintenance costs are expensed as incurred.

Revenue Recognition

Revenue from Contracts with Customers

We generate revenue in our Well Intervention segment by supplying vessels, personnel and equipment to provide well intervention services, which involve providing marine access, serving as a deployment mechanism to the subsea well, connecting to and maintaining a secure connection to the subsea well and maintaining well control through the duration of the intervention services. We may also perform down-hole intervention work and provide certain engineering services. We generate revenue in our Robotics segment by operating ROVs and trenchers to provide subsea trenching and burial of pipelines and cables as well as seabed clearance for the oil and gas and the renewable energy markets and to provide offshore construction, well intervention support and IRM services to oil and gas companies. We also provide integrated robotic services by supplying vessels that deploy ROVs and trenchers. We generate revenue in our Production Facilities segment by supplying vessels, personnel and equipment for oil and natural gas processing, well control response services, and oil and gas production from owned properties.

Our service contracts generally contain provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) but we occasionally contract on a lump sum basis (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities.

We generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments during which we provide our services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration received under a contract is allocated to the single performance obligation on a systematic basis that depicts the pattern of the provision of our services to the customer. We generally consider integrated offerings to be a single performance obligation due to the interdependencies of the offerings.

The total transaction price for a contract is determined by estimating both fixed and unconstrained variable consideration expected to be earned over the term of the contract and excludes certain amounts that have been disputed by our customers. We generally do not provide significant financing or extended payment terms to our customers and do not adjust contract consideration for the time value of money. Estimated variable consideration, if any, is considered to be constrained and therefore is not included in the transaction price until it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our estimates of variable consideration and amounts of that variable consideration that should be constrained.

Dayrate Contracts. Revenues generated from dayrate contracts generally provide for payment according to the rates per day as stipulated in the contract (e.g., operating rate, standby rate, and repair rate). Invoices billed to the customer are typically based on the varying rates applicable to operating status on an hourly basis. Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month.

Dayrate contracts may also contain fees charged to the customer for mobilizing and/or demobilizing equipment and personnel. Mobilization and demobilization are considered contract fulfillment activities, and related fees (subject to any constraint on estimates of variable consideration) are allocated to the single performance obligation and recognized ratably over the term of the contract. Mobilization fees are generally billable to the customer in the initial phase of a contract and generate contract liabilities until they are recognized as revenue. Demobilization fees are generally received at the end of the contract and generate contract assets when they are recognized as revenue prior to becoming receivables from the customer.

We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request. Reimbursable revenues are variable as the amounts received are generally subject to uncertainty. Accordingly, these revenues are constrained and not recognized until the related costs are incurred on behalf of the customer. We are generally considered a principal in these transactions and record the associated revenues at the gross amounts billed to the customer.

A dayrate contract modification involving an extension of the contract by adding days of services is generally accounted for prospectively as a separate contract, but may be accounted for as a termination of the existing contract and creation of a new contract if the consideration for the extended services does not represent their stand-alone selling prices.

Lump Sum Contracts. Revenues generated from lump sum contracts are recognized over time. Revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. Consideration, including lump sum mobilization and demobilization fees billed to the customer, is recorded proportionally as revenue in accordance with the cost-to-cost measure of progress. Consideration for lump sum contracts is generally due from the customer based on the achievement of milestones. As such, contract assets are generated to the extent we recognize revenues in advance of our rights to collect contract consideration and contract liabilities are generated when contract consideration due or received is greater than revenues recognized to date.

We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified. A modification to a lump sum contract is generally accounted for as part of the existing contract and recognized as an adjustment to revenue on a cumulative catch-up basis.

Income from Oil and Gas Production

Income from oil and gas production is recognized according to monthly oil and gas production volumes from the oil and gas properties that we own, and is included in revenues from our Production Facilities segment.

Income from Royalty Interests

Income from royalty interests is recognized according to our share of monthly oil and gas production volumes and is included in “Royalty income and other” in the consolidated statements of operations.

Contract Balances

Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) amounts billed to or advance payments received from customers, including upfront mobilization fees allocated to a single performance obligation and recognized ratably over the contract term and/or (ii) amounts billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.

Contract Fulfillment Costs

Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract.

Income Taxes

Deferred income taxes are based on the differences between financial reporting and tax bases of assets and liabilities. We utilize the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

We operate in multiple tax jurisdictions and our tax returns are subject to review and examination by local taxing authorities. We provide for uncertain tax positions and related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by local taxing authorities. Interest and penalties are not reported as a component of income taxes.

Share-Based Compensation

Share-based payment awards are classified as either equity or liability awards based on various factors such as award conditions, settlement features, substantive terms and past practices. Shared-based compensation is initially measured at the grant date based on the estimated fair value of an award and subsequently measured depending on their award conditions and classification. Forfeitures are recognized as they occur.

Our restricted stock awards are based solely on service conditions and are accounted for as equity awards. Compensation cost for restricted stock is the product of the grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting period on a straight-line basis.

For the portions of our performance share unit (“PSU”) awards with a service and a market condition that are accounted for as equity awards, compensation cost is measured based on the grant date estimated fair value determined using a Monte Carlo simulation model and subsequently recognized over the vesting period on a straight-line basis. For the portions of our PSUs with a service and a performance condition that are accounted for as equity awards, compensation cost is initially measured based on the grant date fair value. Cumulative compensation cost is subsequently adjusted at the end of each reporting period to reflect the current estimation of achieving the performance condition. For equity PSU awards that are subsequently modified, if, at the modification date, it is probable that the original award would have vested, the cumulative compensation cost to be recognized would equal the grant date fair value of the original equity awards plus any incremental fair value of the modified liability awards.

Our restricted stock unit (“RSU”) awards accounted for as liability awards are measured at their estimated fair value based on the closing share price of our common stock as of each balance sheet date, and subsequent changes in the fair value of the awards are recognized in earnings for the portion of the award for which the requisite service period has elapsed. Cumulative compensation cost for vested liability RSUs equals the actual payout value upon vesting.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are recorded initially at fair value and consist of estimated costs for subsea infrastructure decommissioning and P&A activities associated with our oil and gas properties. The estimated costs are discounted to present value using a credit-adjusted risk-free discount rate. After its initial recognition, an ARO liability is increased for the passage of time as accretion expense, which is a component of our depreciation and amortization expense. An ARO liability may also change based on revisions in estimated costs and/or timing to settle the obligations.

Foreign Currency

Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. Results of operations for our non-U.S. dollar subsidiaries are translated into U.S. dollars using average exchange rates during the period. Assets and liabilities of these non-U.S. dollar subsidiaries are translated into U.S. dollars using the exchange rate in effect at the end of the reporting period, and the resulting translation adjustments are included in other comprehensive income (loss) (“OCI”).

For transactions denominated in a currency other than a subsidiary’s functional currency, the effects of changes in exchange rates are reported in “Other income (expense), net” in the consolidated statements of operations. Foreign currency gains or losses from the remeasurement of monetary assets and liabilities as well as unsettled foreign currency transactions, including intercompany transactions that are not of a long-term investment nature, are also recognized as a component of “Other income (expense), net.” For the years ended December 31, 2025, 2024 and 2023, our foreign currency transaction losses totaled $1.7 million, $1.5 million and $4.4 million, respectively.

Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. Because holders of shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our unrestricted common stock, we are required to compute earnings per share (“EPS”) under the two-class method in periods in which we have earnings. Under the two-class method, net income for each period is allocated based on the participation rights of both common shareholders and the holders of any participating securities as if earnings for the respective periods had been distributed. For periods in which we have a net loss we do not use the two-class method as holders of our restricted shares are not obligated to share in such losses.

Basic EPS is computed by dividing net income allocated to common shareholders or net loss by the weighted average shares of our common stock outstanding. Diluted EPS is computed in a similar manner after considering the potential dilutive effect of share-based awards and convertible senior notes and taking the more dilutive of the two-class method and the treasury stock method or if-converted method, as applicable. The dilutive effect of share-based awards is computed using the treasury stock method, as applicable, which includes the incremental shares that would be hypothetically vested in excess of the number of shares assumed to be hypothetically repurchased with the assumed proceeds. The effect of convertible senior notes is computed for the periods in which they are outstanding using the if-converted method, if dilutive, which assumes conversion of the convertible senior notes into shares of our common stock at the beginning of the period, giving income recognition for the add-back of related interest expense (net of tax).

Major Customers and Concentration of Risk

We offer our products and services primarily in the offshore oil and gas and renewable energy markets. Oil and gas companies spend capital on exploration, drilling and production operations, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices and volatility, which are subject to many external factors. Our customers consist primarily of major and independent oil and gas producers and suppliers, pipeline transmission companies, renewable energy companies and offshore engineering and construction firms. The percentages of consolidated revenue from major customers (those representing 10% or more of our consolidated revenues) were as follows: 2025 — Shell (21%) and Petrobras (12%); 2024 — Shell (12%); and 2023 — Shell (12%). The revenue concentrations are reported in our Well Intervention and Production Facilities segments.

As of December 31, 2025, 20% of our labor force was covered by collective bargaining agreements or similar arrangements and 18% of our labor force was covered by those agreements that will expire within one year.

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

●

Level 1. Observable inputs such as quoted prices in active markets;

●

Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

●

Level 3. Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities measured at fair value are based on one or more of three valuation approaches as follows:

(a)

Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

(b)

Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).

(c)

Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

New Accounting Standards

New accounting standards adopted

In December 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2023-09, “Improvements to Income Tax Disclosures,” which requires entities to disclose, on an annual basis, specific categories in a tabular rate reconciliation using both percentages and reporting currency amounts and to provide additional information for reconciling items that meet a quantitative threshold. This ASU also requires that entities disclose on an annual basis: a) income taxes paid (net) disaggregated by federal, state and foreign taxes; b) income taxes paid (net) by individual jurisdiction; c) income (or loss) from continuing operations before income tax expense (or benefit) between domestic and foreign; and d) income tax expense (or benefit) from continuing operations by federal, state and foreign. Certain previous disclosure requirements on unrecognized tax benefits and cumulative amount of temporary differences are eliminated. We adopted ASU No. 2023-09 prospectively starting with this Annual Report for the year ended December 31, 2025. The adoption of this ASU had no impact on our earnings or financial condition and did not have a material impact on our consolidated financial statements other than increased income tax disclosures which are reflected in Note 9.

New accounting standards issued but not yet effective

In November 2024, the FASB issued ASU No. 2024-03, “Disaggregation of Income Statement Expenses,” which requires entities to disclose, on an annual and interim basis, specified information about certain costs and expenses: a) the amounts of (i) purchases of inventory, (ii) employee compensation, (iii) depreciation, (iv) intangible asset amortization, and (v) depreciation, depletion, and amortization recognized as part of oil and gas-producing activities (or other amounts of depletion expense) included in each relevant expense caption; b) certain amounts that are already required to be disclosed under current GAAP in the same disclosure as the other disaggregation requirements; c) a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively; and d) the total amount of selling expenses and, in annual periods, an entity’s definition of selling expenses. ASU No. 2024-03 will be effective for us for annual periods beginning January 1, 2027 and for interim periods beginning January 1, 2028. This ASU is not expected to have a material impact on our consolidated financial statements other than increased disclosure requirements.

We do not expect other recently issued accounting standards to have a material impact on our financial position, results of operations or cash flows when they become effective.

Note 3 — Business Combinations

Alliance Acquisition

We expanded our service capabilities to the Gulf of America shelf market with the acquisition of the Alliance group of companies (collectively “Alliance”) on July 1, 2022, which we re-branded as Helix Alliance. During the fourth quarter 2023, we finalized the calculation and agreed with the seller in the Alliance transaction on an $85.0 million earnout, which was paid in cash on April 3, 2024. For the year ended December 31, 2023, we recorded $42.2 million for the change in fair value of the earnout consideration, which is reported in discontinued operations.

Note 4 — Discontinued Operations

On May 1, 2026, we entered into an equity purchase agreement with C-Dive, L.L.C., a Louisiana limited liability company (“C-Dive”), and completed the sale of all equity interests of Helix Alliance for cash consideration of $107.5 million, subject to customary post-closing and working capital adjustments. As of June 30, 2026, the estimated sale price was $104.2 million, which included a nominal estimated working capital adjustment and was net of $3.3 million of cash retained by Helix Alliance at closing. These customary and transaction-specific price adjustments are subject to further changes through the date of the final closing adjustments.

Helix Alliance represented our Gulf of America-focused Shallow Water Abandonment business that predominantly provided decommissioning services with a diversified fleet of marine assets including liftboats, offshore supply vessels (“OSVs”), dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat, plug and abandonment (“P&A”) systems and coiled tubing (“CT”) systems. Following the sale of Helix Alliance, we no longer have a prominent presence in the decommissioning market in the Gulf of America shelf, which reflects a strategic shift back to focusing on our deepwater operations. Because Helix Alliance was a major component of our business operations and its financial results constituted the entirety of the Shallow Water Abandonment business segment, we have classified Helix Alliance as discontinued operations.

In connection with the sale of Helix Alliance on May 1, 2026, we entered into an arrangement with C-Dive to retain the contractual rights and obligations to complete certain lump-sum full-field decommissioning work. Under the arrangement, we will utilize equipment of Helix Alliance, and Helix Alliance will invoice the customer on our behalf and remit those collections to us. This ongoing involvement with the discontinued operation will continue until the completion of the decommissioning work under the arrangement, which is expected within 12 months from the sale date.

Financial Information of Discontinued Operations

The following table presents the components of assets and liabilities classified as discontinued operations (in thousands):


		December 31,
		2025			2024
Cash and cash equivalents		$	26,907		$	24,157
Accounts receivable, net			63,335			48,308
Other current assets			10,536			8,551
Current assets of discontinued operations		$	100,778		$	81,016

Property and equipment, net		$	73,013		$	89,086
Operating lease right-of-use assets			938			1,998
Deferred certification and dry dock costs, net			4,392			6,137
Other assets, net			976			1,125
Non-current assets of discontinued operations		$	79,319		$	98,346

Accounts payable		$	22,700		$	17,185
Accrued liabilities			3,986			4,849
Current operating lease liabilities			588			1,060
Current liabilities of discontinued operations		$	27,274		$	23,094

Operating lease liabilities		$	351			938
Non-current liabilities of discontinued operations		$	351		$	938

The following table presents the components of “Income (loss) from discontinued operations, net of tax” (in thousands):


		Year Ended December 31,
		2025			2024			2023
Net revenues		$	199,569		$	186,740		$	274,866
Cost of sales			181,637			187,517			203,605
Gross profit (loss)			17,932			(777)			71,261
Gain (loss) on disposition of assets, net			—			(150)			67
Acquisition and integration costs			—			—			(540)
Change in fair value of contingent consideration			—			—			(42,246)
Selling, general and administrative expenses			(7,074)			(8,368)			(5,227)
Income (loss) from operations			10,858			(9,295)			23,315
Net interest income (expense)			1,105			1,228			(14)
Other income (expense), net			276			(2,429)			799
Income (loss) from discontinued operations before income taxes			12,239			(10,496)			24,100
Income tax provision (benefit)			(652)			(2,154)			4,772
Income (loss) from discontinued operations, net of tax		$	12,891		$	(8,342)		$	19,328

The following table presents certain cash flow items related to discontinued operations (in thousands):


		Year Ended December 31,
		2025			2024			2023
Capital expenditures		$	2,010		$	1,403		$	6,890
Deferred certification and dry dock costs			3,155			6,631			2,605
Depreciation and amortization			23,045			20,463			20,150

Note 5 — Details of Certain Accounts

Other current assets consist of the following (in thousands):


		December 31,
		2025			2024
Prepaids		$	28,949		$	26,356
Income tax receivable			7,383			2,635
Contract assets (Note 12)			3,156			5,123
Deferred costs (Note 12)			18,678			31,874
Other			7,155			8,483
Total other current assets		$	65,321		$	74,471

Other assets, net consist of the following (in thousands):


		December 31,
		2025			2024
Prepaid charter ⁽¹⁾		$	12,544		$	12,544
Deferred costs (Note 12)			6,910			5,348
Other receivable ⁽²⁾			27,291			24,827
Intangible assets with finite lives, net			2,287			2,505
Other			1,410			1,829
Total other assets, net		$	50,442		$	47,053

(1)	Represents prepayments to the owner of the Sea Helix 1 and the Siem Helix 2, which may be used to offset certain payment obligations associated with the vessels at the end of their respective charter term.

(2)	Represents the present value of receivables for P&A work to be performed by us on Droshky field oil and gas properties we acquired from Marathon Oil Corporation in 2019.

Accrued liabilities consist of the following (in thousands):


		December 31,
		2025			2024
Accrued payroll and related benefits		$	41,926		$	45,823
Accrued interest			10,102			10,278
Deferred revenue (Note 12)			17,115			14,914
Other			21,822			14,591
Total accrued liabilities		$	90,965		$	85,606

Other non-current liabilities consist of the following (in thousands):


		December 31,
		2025			2024
Deferred revenue (Note 12)		$	—		$	699
Asset retirement obligations (Note 16)			68,770			62,947
Other			2,663			3,325
Total other non-current liabilities		$	71,433		$	66,971

Note 6 — Property and Equipment

The following is a summary of the gross components of property and equipment (dollars in thousands):


				December 31,
		Estimated Useful Life		2025			2024
Vessels		15 to 30 years		$	2,374,632		$	2,288,884
Systems and equipment		5 to 15 years			331,436			312,970
ROVs and trenchers		5 to 10 years			265,483			261,417
Buildings and other		5 to 39 years			53,217			75,645
Total property and equipment				$	3,024,768		$	2,938,916

The Thunder Hawk field under our Production Facilities segment ceased production beginning mid-year 2024 due to a blockage in a well. Multiple attempts to resolve the blockage previously failed and a well workover was completed late February 2026. Given the combination of low oil prices and the increase in estimated costs associated with a workover, we determined that the remaining net book value was not recoverable as of December 31, 2025 and performed an asset impairment assessment review by comparing the fair value of the Thunder Hawk field to its remaining net book value. We estimated the fair value using an income approach by discounting the estimated future cash flows (Level 3 input) as of the trigger date and concluded that the remaining net book value of the Thunder Hawk field was fully impaired. As such, we recorded a long-lived asset impairment charge of $18.1 million for the year ended December 31, 2025.

Note 7 — Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2034. We also sublease some of our facilities under non-cancelable sublease agreements. As of December 31, 2025, the minimum sublease income to be received in the future was minimal.

The following table details the components of our lease cost (in thousands):


		Year ended December 31,
		2025			2024			2023
Operating lease cost		$	89,623		$	86,260		$	71,526
Variable lease cost			12,532			11,112			21,422
Short-term lease cost			32,531			33,566			35,055
Sublease income			(117)			(99)			(1,113)
Net lease cost		$	134,569		$	130,839		$	126,890

Maturities of our operating lease liabilities as of December 31, 2025 are as follows (in thousands):


					Facilities and
		Vessels			Equipment			Total
Less than one year		$	77,129		$	3,628		$	80,757
One to two years			76,334			4,129			80,463
Two to three years			65,278			3,905			69,183
Three to four years			53,006			3,869			56,875
Four to five years			59,020			4,635			63,655
Over five years			27,237			11,950			39,187
Total lease payments		$	358,004		$	32,116		$	390,120
Less: imputed interest			(60,775)			(8,529)			(69,304)
Total operating lease liabilities		$	297,229		$	23,587		$	320,816

Current operating lease liabilities		$	57,239		$	2,969		$	60,208
Non-current operating lease liabilities			239,990			20,618			260,608
Total operating lease liabilities		$	297,229		$	23,587		$	320,816

Maturities of our operating lease liabilities as of December 31, 2024 are as follows (in thousands):


					Facilities and
		Vessels			Equipment			Total
Less than one year		$	78,442		$	4,152		$	82,594
One to two years			66,020			2,803			68,823
Two to three years			61,771			3,672			65,443
Three to four years			55,933			3,185			59,118
Four to five years			52,748			3,185			55,933
Over five years			86,257			15,736			101,993
Total lease payments		$	401,171		$	32,733		$	433,904
Less: imputed interest			(80,564)			(9,372)			(89,936)
Total operating lease liabilities		$	320,607		$	23,361		$	343,968

Current operating lease liabilities		$	55,643		$	3,279		$	58,922
Non-current operating lease liabilities			264,964			20,082			285,046
Total operating lease liabilities		$	320,607		$	23,361		$	343,968

The following table presents the weighted average remaining lease term and discount rate:


		December 31,
		2025		2024		2023
Weighted average remaining lease term		5.0	years	6.0	years	3.1	years
Weighted average discount rate		7.68	%	7.89	%	8.18	%

The following table presents other information related to our operating leases (in thousands):


		Year ended December 31,
		2025			2024			2023
Cash paid for operating lease liabilities		$	87,151		$	79,772		$	67,539
Right-of-use assets related to new operating lease obligations ⁽¹⁾			37,658			220,039			24,879

(1)

Our operating lease additions are primarily related to the charter for the Trym and charter extensions for the North Sea Enabler during the year ended December 31, 2025, the charter extensions for the Sea Helix 1, the Siem Helix 2, the Grand Canyon II and the Shelia Bordelon during the year ended December 31, 2024, and the charters for the Glomar Wave and the North Sea Enabler during the year ended December 31, 2023.

See Note 17 for additional information on our significant leases including those not yet commenced as of December 31, 2025.

Note 8 — Long-Term Debt

Long-term debt consists of the following (in thousands):


		December 31,
		2025			2024
MARAD Debt (matures February 2027)		$	14,645		$	23,831
2029 Notes (mature March 2029)			300,000			300,000
Gross debt			314,645			323,831
Unamortized debt discount			(946)			(1,186)
Unamortized debt issuance costs			(5,704)			(7,488)
Total debt			307,995			315,157
Less current maturities ⁽¹⁾			(9,644)			(9,186)
Long-term debt		$	298,351		$	305,971

(1)	Current maturities as of December 31, 2025 and 2024 both included the current portion of the MARAD Debt.

Credit Agreement

On September 30, 2021 we entered into an asset-based credit agreement with Bank of America, N.A. (“Bank of America”), Wells Fargo Bank, N.A. and Zions Bancorporation and subsequently we entered into various amendments (collectively, the “Amended ABL Facility”). The Amended ABL Facility provides a $120 million asset-based revolving credit line that matures on August 2, 2029, with a springing maturity 91 days prior to the maturity of any outstanding indebtedness with a principal amount in excess of $50 million. The Amended ABL Facility permits us to request an increase of the facility of up to $30 million, subject to certain conditions.

Commitments under the Amended ABL Facility are comprised of separate U.S. and U.K. revolving credit facility commitments of $85 million and $35 million, respectively. The Amended ABL Facility provides funding based on a borrowing base calculation that includes eligible U.S. and U.K. customer accounts receivable and cash, and provides for a $55 million sub-limit for the issuance of letters of credit. As of December 31, 2025, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity, based on the borrowing base, totaled $110.9 million, net of $1.5 million of letters of credit issued and includes $2.5 million of cash pledged to the facility.

We and certain of our U.S. and U.K. subsidiaries are the current borrowers under the Amended ABL Facility, whose obligations under the Amended ABL Facility are guaranteed by those borrowers and certain other U.S. and U.K. subsidiaries, excluding Cal Dive I – Title XI, Inc. (“CDI Title XI”), Helix Offshore Services Limited and certain other enumerated subsidiaries. Other subsidiaries may be added as guarantors of the facility in the future. The Amended ABL Facility is secured by all accounts receivable and designated deposit accounts of the U.S. borrowers and guarantors, and by substantially all of the assets of the U.K. borrowers and guarantors.

U.S. borrowings under the Amended ABL Facility bear interest at the Term SOFR rate (also known as CME Term SOFR as administered by CME Group, Inc.) plus a margin of 1.50% to 2.00% or at a base rate plus a margin of 0.50% to 1.00%. U.K. borrowings under the Amended ABL Facility denominated in U.S. dollars bear interest at the Term SOFR rate with SOFR adjustment of 0.10% and U.K. borrowings denominated in the British pound bear interest at the SONIA daily rate, each plus a margin of 1.50% to 2.00%. We also pay a commitment fee of 0.375% to 0.50% per annum on the unused portion of the facility.

The Amended ABL Facility includes certain limitations on our ability to incur additional indebtedness, grant liens on assets, pay dividends and make distributions on equity interests, dispose of assets, make investments, repay certain indebtedness, engage in mergers, and other matters, in each case subject to certain exceptions. The Amended ABL Facility contains customary default provisions which, if triggered, could result in acceleration of all amounts then outstanding. The Amended ABL Facility requires us to satisfy and maintain a fixed charge coverage ratio of not less than 1.0 to 1.0 if availability is less than the greater of 10% of the borrowing base or $12 million.

The Amended ABL Facility also (i) limits the amount of permitted debt for the deferred purchase price of property not to exceed $50 million, and (ii) provides for potential ESG-related pricing adjustments based on specific metrics and performance targets determined by us and Bank of America, as agent with respect to the Amended ABL Facility.

MARAD Debt

In 2005, Helix’s subsidiary CDI-Title XI issued its U.S. Government Guaranteed Ship Financing Bonds, Q4000 Series, to refinance the construction financing originally granted in 2002 of the Q4000 vessel (the “MARAD Debt”). The MARAD Debt is guaranteed by the U.S. government pursuant to Title XI of the Merchant Marine Act of 1936, administered by the Maritime Administration (“MARAD”). The obligation of CDI-Title XI to reimburse MARAD in the event CDI-Title XI fails to repay the MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. In addition, we have agreed to bareboat charter the Q4000 from CDI-Title XI for so long as the MARAD Debt remains outstanding. The MARAD Debt is payable in equal semi-annual installments through February 2027 and bears interest at a rate of 4.93%.

Senior Notes Due 2029 (“2029 Notes”)

On December 1, 2023, we issued $300 million aggregate principal amount of the 2029 Notes. The net proceeds from the issuance of the 2029 Notes were approximately $291.1 million, after deducting the purchasers’ discount and debt issuance costs. We used cash proceeds from the offering to redeem our former Convertible Senior Notes due 2026 (the “2026 Notes”). See details regarding the redemption of the 2026 Notes below.

The 2029 Notes bear interest at a coupon interest rate of 9.75% per annum payable semi-annually in arrears on March 1 and September 1 of each year, beginning on March 1, 2024. The 2029 Notes mature on March 1, 2029 unless earlier redeemed or repurchased by us.

Prior to March 1, 2026, we may, at our option, redeem the 2029 Notes, in whole or in part, at a price equal to 100% of the aggregate principal amount of the notes to be redeemed, plus a make-whole premium and accrued and unpaid interest, if any, to, but excluding, the redemption date. On or after March 1, 2026, we may, at our option, redeem the 2029 Notes, in whole or in part, at the redemption prices (expressed as percentages of the principal amount of the notes to be redeemed) set forth below, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. Prior to March 1, 2026, following certain equity offerings we may, at our option, on any one or more occasions, redeem up to 40% of the 2029 Notes at a price equal to 109.750% of the aggregate principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, in an amount not exceeding the proceeds of such equity offerings.


		Redemption
Year		Price
2026		104.875%
2027		102.438%
2028 and thereafter		100.000%

Upon the occurrence of a Change of Control Triggering Event, as defined in the indenture governing the 2029 Notes, we may be required to make an offer to repurchase all of the notes then outstanding at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the repurchase date.

The indenture governing the 2029 Notes contains customary terms and covenants, including limitations on additional indebtedness, restricted payments, liens, asset sales, transactions with affiliates, mergers and consolidations, designation of unrestricted subsidiaries, and dividend and other restrictions affecting restricted subsidiaries.

The 2029 Notes are guaranteed on a senior unsecured basis by the subsidiaries that guarantee the Amended ABL Facility, as well as certain future subsidiaries that may guarantee certain of our indebtedness, including the Amended ABL Facility. The 2029 Notes are junior in right of payment to all our existing and future secured indebtedness and obligations and rank equally in right of payment with all our existing and future senior unsecured indebtedness. The 2029 Notes rank senior in right of payment to any of our future subordinated indebtedness and are fully and unconditionally guaranteed by the guarantors described above on a senior basis.

2026 Notes

During December 2023 and the first quarter 2024, we retired the 2026 Notes through various transactions using proceeds from the 2029 Notes as well as the issuance of our common stock.

In December 2023, we entered into privately negotiated agreements with certain holders of the 2026 Notes to repurchase $159.8 million aggregate principal amount of the 2026 Notes (the “2026 Notes Repurchases”) for 1.5 million shares of our common stock and aggregate cash payments of $229.7 million, plus accrued and unpaid cash interest of $3.8 million. We recognized pre-tax inducement charges of $37.4 million for the 2026 Notes Repurchases in the fourth quarter 2023, representing the total settlement value in excess of the total conversion value of the 2026 Notes Repurchases when the final negotiated offers were accepted. The conversion value paid in excess of the carrying amount of the 2026 Notes Repurchases is reflected in “Common stock” in the shareholders’ equity section of the accompanying consolidated balance sheets.

In December 2023, $0.2 million aggregate principal amount of the 2026 Notes was tendered for conversion. We settled the conversions for $0.3 million cash in March 2024. The conversion value paid in excess of the $0.2 million carrying amount of the 2026 Notes that were tendered for conversion is reflected in “Common stock” in the shareholders’ equity section of the accompanying consolidated balance sheets.

In January 2024, we issued a notice for the redemption of the remaining $40.0 million aggregate principal amount of the 2026 Notes to be settled in March 2024 (the “2026 Notes Redemptions”). The redemption price consisted of the principal amount and the make-whole premium, plus accrued and unpaid interest. Our redemption notice enabled holders of $39.7 million aggregate principal amount of the 2026 Notes to tender their notes for conversion prior to the redemption date, with the remaining $0.3 million aggregate principal amount of the notes redeemed. We settled both the conversions and redemptions for an aggregate $60.2 million cash in March 2024 and recognized pre-tax losses of $20.9 million. These losses are reflected in “Losses related to convertible senior notes” in the accompanying consolidated statement of operations.

In connection with the 2026 Notes offering, we entered into capped call transactions (the “2026 Capped Calls”) with three separate counterparties to hedge the dilution risk of the 2026 Notes. Concurrent with the settlement of the 2026 Notes Repurchases and the 2026 Notes Redemptions, we terminated the 2026 Capped Calls and received $20.0 million in cash (Note 10).

The 2026 Notes had a coupon interest rate of 6.75% per annum and an effective interest rate of 7.6%. For the years ended December 31, 2024 and 2023, total interest expense related to the 2026 Notes was $0.4 million and $14.6 million, respectively, with coupon interest expense of $0.3 million and $13.3 million, respectively, and the amortization of debt issuance costs of $0.1 million and $1.3 million, respectively.

Other

In accordance with the Amended ABL Facility, the MARAD Debt and the 2029 Notes, we are required to comply with certain covenants, including minimum liquidity and a springing fixed charge coverage ratio (applicable under certain conditions that are currently not applicable) with respect to the Amended ABL Facility and the maintenance of net worth, working capital and debt-to-equity requirements with respect to the MARAD Debt. As of December 31, 2025, we were in compliance with these covenants.

The Convertible Senior Notes due 2023 (the “2023 Notes”) matured on September 15, 2023. Upon maturity of the 2023 Notes, we paid $29.6 million in cash to settle the conversion of $29.2 million aggregate principal amount of the notes, plus accrued and unpaid interest. We recorded the conversion value in excess of such principal amount converted to “Common stock” in the accompanying consolidated balance sheets. Notes representing the remaining $0.8 million aggregate principal amount of the 2023 Notes were redeemed at par, plus accrued and unpaid interest. The 2023 Notes had a coupon interest rate of 4.125% per annum and an effective interest rate of 4.8%. For the year ended December 31, 2023, total interest expense related to the 2023 Notes was $1.0 million, primarily from coupon interest expense.

Scheduled maturities of our long-term debt outstanding as of December 31, 2025 are as follows (in thousands):


		MARAD			2029
		Debt			Notes			Total
Less than one year		$	9,644		$	—		$	9,644
One to two years			5,001			—			5,001
Two to three years			—			—			—
Three to four years			—			300,000			300,000
Gross debt			14,645			300,000			314,645
Unamortized debt discount ⁽¹⁾			—			(946)			(946)
Unamortized debt issuance costs ⁽¹⁾			(610)			(5,094)			(5,704)
Total debt			14,035			293,960			307,995
Less current maturities			(9,644)			—			(9,644)
Long-term debt		$	4,391		$	293,960		$	298,351

(1)	Debt discount and debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.

The following table details the components of our net interest expense (in thousands):


	Year Ended December 31,
	2025			2024			2023
Interest expense	$	32,973		$	33,901		$	21,345
Interest income		(9,091)			(10,044)			(4,021)
Net interest expense	$	23,882		$	23,857		$	17,324

Note 9 — Income Taxes

We operate in multiple jurisdictions with complex tax laws subject to interpretation and judgment. We believe that our application of such laws and the tax impact thereof are reasonable and fairly presented in our consolidated financial statements.

On July 4, 2025, the One Big Beautiful Bill Act was passed into law. The legislation provides us with benefits that are temporary in nature with no material impact on our income tax expense or effective tax rate for the year ended December 31, 2025.

Components of income tax provision reflected in the consolidated statements of operations consist of the following (in thousands):


		Year Ended December 31,
		2025			2024			2023
Current tax provision (benefit):
Federal		$	(943)		$	15,716		$	(1,309)
Foreign			17,994			15,918			5,310
Total current		$	17,051		$	31,634		$	4,001
Deferred tax provision (benefit):
Federal		$	(8,626)		$	(2,021)		$	6,736
Foreign			3,880			(1,032)			2,843
Total deferred		$	(4,746)		$	(3,053)		$	9,579
Total income tax provision		$	12,305		$	28,581		$	13,580

Components of income (loss) from continuing operations before income taxes are as follows (in thousands):


		Year Ended December 31,
		2025			2024			2023
Domestic		$	(61,208)		$	(22,484)		$	(55,746)
Foreign			91,449			115,044			39,160
Income (loss) from continuing operations before income taxes		$	30,241		$	92,560		$	(16,586)

Reconciling items between the U.S. statutory rate and our effective tax rate for the year ended December 31, 2025 are as follows (dollars in thousands):


	Year Ended
	December 31, 2025
U.S. federal statutory tax rate		$	6,351	21.0	%
Domestic federal:
Foreign tax credits			(7)	0.0
Non-taxable or non-deductible items:
Non-deductible compensation			1,266	4.2
Other permanent adjustments			69	0.2
Effect of cross-border tax laws ⁽¹⁾			4,281	14.2
Return-to-provision			(7,507)	(24.8)
Changes in valuation allowances			6,227	20.6
Foreign tax effects:
U.K.:
Internal restructuring			(17,310)	(57.2)
Changes in valuation allowances			15,685	51.9
Other reconciling items			(598)	(2.0)
Brazil:
Statutory tax rate difference			5,025	16.6
Other reconciling items			22	0.1
Luxembourg:
Rate change			2,430	8.0
Changes in valuation allowances			(4,812)	(15.9)
Other reconciling items			638	2.1
Taiwan:
Non-taxable or non-deductible items			(1,906)	(6.3)
Return-to-provision			(949)	(3.1)
Other reconciling items			310	1.0
Nigeria:
Statutory tax rate difference			646	2.1
Non-refundable income taxes withheld			1,947	6.4
Return-to-provision			(2,094)	(6.9)
Withholding taxes			1,430	4.7
Malaysia – Withholding taxes			1,707	5.6
Other foreign jurisdictions			(546)	(1.8)
Effective tax rate		$	12,305	40.7	%

(1)	Net of jurisdictional foreign tax credits.

The primary differences between the income tax provision at the U.S. statutory rate and our actual income tax provision for the years ended December 31, 2024 and 2023 are as follows (dollars in thousands):


	Year Ended December 31,
	2024				2023
Taxes at U.S. statutory rate	$	19,438	21.0	%	$	(3,483)	21.0	%
Foreign tax provision		7,944	8.6			1,590	(9.6)
Change in valuation allowance		(5,230)	(5.7)			6,374	(38.4)
Non-deductible expenses		3,105	3.4			2,926	(17.7)
Losses related to convertible senior notes ⁽¹⁾		4,078	4.4			6,372	(38.4)
Other		(754)	(0.8)			(199)	1.2
Income tax provision	$	28,581	30.9	%	$	13,580	(81.9)	%

(1)	Relates to the non-deductibility for U.S. federal income tax purposes of certain charges associated with the 2026 Notes Repurchases and the 2026 Notes Redemptions (Note 8).

Our operations are subject to current taxation in the U.S. (21% statutory rate) and the U.K. (25% statutory rate), or subject to taxation in jurisdictions with statutory rates greater than the Pillar Two threshold of 15%. After applying the existing Pillar Two laws, we have no incremental Pillar Two taxes.

For the year ended December 31, 2025, the valuation allowance increased by $9.6 million, which was predominantly driven by current year activity, including adjustments to prior year returns, and an internal restructuring.

For the year ended December 31, 2024, the valuation allowance decreased by $5.7 million, which included a $3.2 million decrease related to a valuation allowance release in Brazil, a $5.2 million increase in assessment on the realizability of U.S. group foreign tax credit carryforward, and a $7.7 million decrease in valuation allowance, which was predominantly driven by current year activity, including adjustments to prior year returns.

For the year ended December 31, 2023, the valuation allowance increased by $59.0 million, which included a $51.4 million increase for a change in assessment of our Luxembourg net operating losses, and a $7.6 million increase in valuation allowance, which was predominantly driven by current year activity, including adjustments to prior year returns.

Deferred income taxes result from the effect of transactions that are recognized in different periods for financial and tax reporting purposes. The nature of these differences and the income tax effect of each are as follows (in thousands):


		December 31,
		2025			2024
Deferred tax liabilities:
Depreciation		$	102,597		$	126,218
Operating leases			71,064			77,773
Prepaid and other			13,641			14,090
Total deferred tax liabilities		$	187,302		$	218,081
Deferred tax assets:
Net operating losses		$	(62,107)		$	(71,244)
Operating leases			(71,064)			(77,773)
Asset retirement obligations			(14,442)			(13,219)
Reserves, accrued liabilities and other			(19,069)			(17,253)
Total deferred tax assets			(166,682)			(179,489)
Valuation allowance			84,951			75,381
Net deferred tax liabilities		$	105,571		$	113,973

At December 31, 2025, our U.S. tax attributes included $8.1 million in foreign tax credit carryforwards, which expire between 2033 and 2035. Our non-U.S. net operating losses totaled $257.6 million, which included $210.7 million net operating losses in Luxembourg, which expire between 2035 and 2041, and $46.9 million net operating losses in the U.K., which do not expire under local tax law.

We operate in multiple tax jurisdictions and our tax returns are subject to review and examination by local taxing authorities. We have filed, and will continue to file, our income tax returns based on the tax laws in effect for each year and have recorded and paid our tax liabilities appropriately. Although we cannot predict the final outcome of any review and/or examination by such taxing authorities, we do not believe their resolution would have a material impact on our consolidated financial statements. The tax periods from 2021 through 2025 are open to review and examination by the U.S. Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2020 through 2025.

Components of income taxes paid (net of refunds received) by jurisdiction during the year ended December 31, 2025 are as follows (in thousands):


		Year Ended
		December 31, 2025
U.S. federal		$	9,500
U.S. state and local:
Louisiana			53
Foreign:
Brazil			9,060
Malaysia			1,707
Nigeria			6,868
Norway			2,360
Other			(316)
Total foreign			19,679
Total taxes paid, net		$	29,232

Note 10 — Shareholders’ Equity

Our amended and restated Articles of Incorporation provide for authorized Common Stock of 240,000,000 shares with no stated par value per share and 5,000,000 shares of preferred stock, $0.01 par value per share, issuable in one or more series.

In connection with the 2026 Notes offering (Note 8), we entered into the 2026 Capped Calls with three separate option counterparties. The 2026 Capped Calls were intended to offset some or all of the potential dilution to Helix common shares or increases to the economic cost caused by any conversion of the 2026 Notes up to the cap price. Concurrent with the 2026 Notes Repurchases in December 2023, we terminated a proportionate amount of the 2026 Capped Calls and received $15.6 million in cash, recognizing an increase to “Common stock” of $14.2 million and a $1.4 million gain. Concurrent with the settlement of the 2026 Notes Redemptions in March 2024, we terminated the remaining 2026 Capped Calls and received $4.4 million in cash, recognizing an increase to “Common stock” in the shareholders’ equity section of the accompanying consolidated balance sheet.

Note 11 — Share Repurchase Programs

In February 2023, our Board of Directors (our “Board”) authorized a share repurchase program (the “2023 Repurchase Program”). Under the 2023 Repurchase Program, we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. Concurrent with the authorization of the 2023 Repurchase Program, our Board revoked the prior authorization to repurchase shares of our common stock in an amount equal to any equity issued to our employees, officers and directors under our share-based compensation plans, including share-based awards under our existing long-term incentive plans and shares issued to our employees under our Employee Stock Purchase Plan (the “ESPP”) (Note 14). Pursuant to the 2023 Repurchase Program, we repurchased a total of 4,643,060 shares of our common stock for approximately $30.0 million during 2025, a total of 2,867,293 shares of our common stock for approximately $29.6 million during 2024, and a total of 1,584,045 shares of our common stock for approximately $12.0 million during 2023. As of December 31, 2025, approximately $128.4 million remained authorized for the repurchase of shares under the 2023 Repurchase Program.

The 2023 Repurchase Program has no set expiration date. Repurchases under the 2023 Repurchase Program have been made through open market purchases in compliance with Rule 10b-18 as well as a plan established under Rule 10b5-1 under the Exchange Act, and may also be made through privately negotiated transactions or future plans, instructions or contracts established under Rule 10b5-1. The manner, timing and amount of any purchase will be determined by management at its discretion based on an evaluation of market conditions, stock price, liquidity and other factors. The 2023 Repurchase Program does not obligate us to acquire any particular amount of common stock and may be modified or superseded at any time at our discretion. Any repurchased shares are cancelled.

Note 12 — Revenue from Contracts with Customers

Disaggregation of Revenue

We provide services to our customers in the following markets that are key to our energy transition strategy: Production maximization, Decommissioning and Renewables. The following table provides information about disaggregated revenue by market strategy (in thousands):


		Well						Production			Intercompany			Total
		Intervention			Robotics			Facilities			Eliminations			Revenue
Year ended December 31, 2025
Production maximization		$	211,589		$	111,006		$	72,693		$	(10,451)		$	384,837
Decommissioning			507,977			36,052			—			(21,987)			522,042
Renewables			—			157,226			—			—			157,226
Other			9,805			19,069			—			(1,074)			27,800
Total		$	729,371		$	323,353		$	72,693		$	(33,512)		$	1,091,905

Year ended December 31, 2024 ⁽¹⁾
Production maximization		$	408,791		$	117,207		$	88,709		$	(29,439)		$	585,268
Decommissioning			416,057			17,717			—			(14,272)			419,502
Renewables			—			152,306			—			—			152,306
Other			5,014			10,448			—			(718)			14,744
Total		$	829,862		$	297,678		$	88,709		$	(44,429)		$	1,171,820

Year ended December 31, 2023 ⁽¹⁾
Production maximization		$	228,649		$	103,692		$	87,885		$	(17,736)		$	402,490
Decommissioning			458,437			47,768			—			(18,690)			487,515
Renewables			—			99,861			—			—			99,861
Other			20,632			6,554			—			(2,190)			24,996
Total		$	707,718		$	257,875		$	87,885		$	(38,616)		$	1,014,862

(1)	For the years ended December 31, 2024 and 2023, $27.6 million and $25.0 million, respectively, have been removed from Well Intervention segment revenues and related intersegment eliminations. See Note 15 regarding this change in prior year reported segment information.

Contract Balances

Net contract assets as of December 31, 2025 and 2024 were $3.2 million and $5.1 million, respectively, and are reflected in “Other current assets” in the accompanying consolidated balance sheets (Note 5). The decrease in net contract assets was primarily attributable to less accrued revenues related to lump sum demobilization fees. We had no credit losses on our contract assets for the years ended December 31, 2025, 2024 and 2023.

Net contract liabilities as of December 31, 2025 and 2024 totaled $17.1 million and $15.6 million, respectively, and are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets (Note 5). The increase was primarily attributable to a larger amount of deferred mobilization fees for work that has not yet been completed. Revenue recognized for the years ended December 31, 2025, 2024 and 2023 included $19.9 million, $36.3 million and $8.7 million, respectively, that were included in the contract liability balance at the beginning of each period.

Performance Obligations

As of December 31, 2025, $1.3 billion related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $676.0 million, $391.4 million and $225.7 million in 2026, 2027 and 2028 and beyond, respectively. These amounts include fixed consideration and estimated variable consideration for both wholly and partially unsatisfied performance obligations, including mobilization and demobilization fees. These amounts are derived from the specific terms of our contracts, and the expected timing for revenue recognition is based on the estimated start date and duration of each contract according to the information known at December 31, 2025.

For the years ended December 31, 2025, 2024 and 2023, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were immaterial.

Contract Fulfillment Costs

Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying consolidated balance sheets (Note 5). Our deferred contract costs as of December 31, 2025 and 2024 totaled $25.6 million and $37.2 million, respectively. For the years ended December 31, 2025, 2024 and 2023, we recorded $68.0 million, $62.9 million and $43.2 million, respectively, related to amortization of deferred contract costs. There were no material impairment losses on deferred contract costs for any period presented.

Note 13 — Earnings Per Share

The computations of the numerator (earnings or loss) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying consolidated statements of operations are as follows (in thousands, except per share amounts):


		Year ended December 31,
		2025					2024					2023
		Income			Shares		Income			Shares		Income			Shares
Basic:
Continuing operations:
Net income (loss)		$	30,827				$	55,637				$	(10,838)
Less: Income (loss) from discontinued operations, net of tax			(12,891)					8,342					(19,328)
Less: Undistributed earnings allocated to participating securities - continuing operations			(13)					(61)					—
Income (loss) available to common shareholders - continuing operations		$	17,923		148,349		$	63,918		151,989		$	(30,166)		150,917

Earnings (loss) per share, basic		$	0.12				$	0.42				$	(0.20)

Discontinued operations:
Income (loss) available to common shareholders - discontinued operations		$	12,882		148,349		$	(8,334)		151,989		$	19,328		150,917

Earnings (loss) per share, basic		$	0.09				$	(0.05)				$	0.13

Diluted:
Continuing operations:
Income (loss) available to common shareholders - continuing operations		$	17,923		148,349		$	63,918		151,989		$	(30,166)		150,917
Effect of dilutive securities:
Share-based awards other than participating securities			—		105			—		2,710			—		—
Undistributed earnings reallocated to participating securities			—		—			1		—			—		—
Net income (loss) available to common shareholders - continuing operations		$	17,923		148,454		$	63,919		154,699		$	(30,166)		150,917

Earnings (loss) per share, diluted		$	0.12				$	0.41				$	(0.20)

Discontinued operations:
Income (loss) available to common shareholders - discontinued operations		$	12,882		148,454		$	(8,334)		154,699		$	19,328		150,917

Earnings (loss) per share, diluted		$	0.09				$	(0.05)				$	0.13

We had a net loss for the year ended December 31, 2023. Accordingly, our diluted EPS calculation for this period excluded the dilutive effect of share-based awards because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable period. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):


			Year Ended
			December 31, 2023
Diluted shares (as reported)			150,917
Share-based awards			3,154
Total			154,071

The following potentially dilutive shares related to the 2023 Notes and the 2026 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands):


	Year Ended December 31,
		2025	2024	2023
2023 Notes		—	—	2,247
2026 Notes		—	1,297	28,139

We have outstanding RSUs (Note 14) that can be settled in either cash or shares of our common stock, or a combination thereof, which are not included in the computation of diluted EPS as cash settlement is assumed.

Note 14 — Employee Benefit Plans

Long-Term Incentive Plan

We currently have one active long-term incentive plan, the 2005 Long-Term Incentive Plan, as amended and restated (the “2005 Incentive Plan”). The 2005 Incentive Plan is administered by the Compensation Committee of our Board (the “Compensation Committee”). The Compensation Committee also determines the type of award to be made to each recipient and, as set forth in the related award agreement, the terms, conditions and limitations applicable to each award. The Compensation Committee may grant various forms of award in accordance with the 2005 Incentive Plan. Awards that have been granted to employees under the 2005 Incentive Plan have a vesting period of three years (or 33% per year) with the exception of PSUs, which vest in amounts in accordance with their terms on the third anniversary date of the grant.

On May 15, 2024, our shareholders approved an amendment to and restatement of the 2005 Incentive Plan, which, among other things, authorizes 7.0 million additional shares for issuance pursuant to our equity incentive compensation strategy. The 2005 Incentive Plan currently has 24.3 million shares authorized for issuance, which includes a maximum of 2.0 million shares that may be granted as incentive stock options. As of December 31, 2025, there were approximately 8.5 million shares of our common stock available for issuance under the 2005 Incentive Plan, assuming outstanding equity classified PSUs vest in shares of our common stock at 100% of the original awards and outstanding liability classified PSUs and RSUs are settled in cash. No incentive stock options are currently outstanding.

The following grants of share-based awards were made in 2025 under the 2005 Incentive Plan:


			Grant Date
			Fair Value
Date of Grant	Award Type	Shares/Units	Per Share/Unit		Vesting Period/Vesting Date
January 1, 2025 ⁽¹⁾	RSU	443,401	$	9.32	33% per year over three years
January 1, 2025 ⁽²⁾	PSU	397,264	$	10.56	100% on December 31, 2027
January 1, 2025 ⁽³⁾	Restricted stock	3,018	$	9.32	100% on January 1, 2027
December 10, 2025 ⁽³⁾	Restricted stock	124,140	$	7.25	100% on December 10, 2026

(1)	Reflects grants to our executive officers and certain other officers.

(2)	Reflects grants to our executive officers.

(3)	Reflects grants to certain independent members of our Board.

In January 2026, we granted certain officers 719,298 RSUs and 605,661 PSUs under the 2005 Incentive Plan. The grant date fair value of the RSUs was $6.27 per unit or $4.5 million. The grant date fair value of the PSUs was $6.93 per unit or $4.2 million. PSUs and RSUs issued in 2026 are payable in either cash or stock, or a combination thereof, at the discretion of the Compensation Committee. Also in January 2026, we granted $5.9 million of fixed value cash awards to select management employees under the 2005 Incentive Plan.

Restricted Stock Awards

We grant restricted stock to members of our Board and from time to time our executive officers and select management employees. The following table summarizes information about our restricted stock:


		Year Ended December 31,
		2025					2024					2023
				Grant Date					Grant Date					Grant Date
		Shares		Fair Value ⁽¹⁾			Shares		Fair Value ⁽¹⁾			Shares		Fair Value ⁽¹⁾
Awards outstanding at beginning of year		114,331		$	9.90		193,129		$	7.52		387,628		$	6.70
Granted		127,158			7.30		102,547			10.18		148,224			8.68
Vested ⁽²⁾		(104,110)			9.79		(146,947)			7.25		(342,723)			7.10
Forfeited		—			—		(34,398)			8.70		—			—
Awards outstanding at end of year		137,379		$	7.58		114,331		$	9.90		193,129		$	7.52

(1)	Represents the weighted average grant date fair value, which is based on the quoted closing market price of our common stock on the trading day prior to the date of grant.

(2)	During the years ended December 31, 2025, 2024 and 2023, total fair value of vested restricted stock was $0.8 million, $1.5 million and $2.9 million, respectively.

For the years ended December 31, 2025, 2024 and 2023, $1.0 million, $1.0 million and $1.3 million, respectively, were recognized as share-based compensation related to restricted stock. Future compensation cost and the weighted average vesting period associated with unvested restricted stock at December 31, 2025 were approximately $0.9 million and 0.9 years, respectively.

PSU Awards

Our outstanding PSUs can be settled in either cash or shares of our common stock, or a combination thereof, at the discretion of the Compensation Committee upon vesting and generally have been accounted for as equity awards. Those PSUs consist of two components measured across a three-year performance period: (i) 50% containing a service and market condition based on the performance of our common stock against peer group companies, and (ii) 50% containing a service and performance condition based on cumulative total Free Cash Flow. Free Cash Flow is calculated as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. Our PSUs cliff vest at the end of the three-year period with the maximum amount of the award being 200% of the original PSU awards and the minimum amount being zero.

The following table summarizes information about our PSU awards:


		Year Ended December 31,
		2025					2024					2023
				Grant Date					Grant Date					Grant Date
		Units		Fair Value ⁽¹⁾			Units		Fair Value ⁽¹⁾			Units		Fair Value ⁽¹⁾
PSU awards outstanding at beginning of year		1,906,613		$	7.01		2,007,584		$	5.71		1,888,024		$	6.25
Granted		397,264			10.56		351,410			12.30		489,498			9.26
Vested ⁽²⁾		(1,065,705)			4.25		(452,381)			5.33		(369,938)			13.15
PSU awards outstanding at end of year		1,238,172		$	10.53		1,906,613		$	7.01		2,007,584		$	5.71

(1)	Represents the weighted average grant date fair value.

(2)

During the year ended December 31, 2025, our 2022 PSU awards vested at 200%, resulting in 1,958,334 shares of our common stock with a total market value of $18.3 million and $1.6 million of cash. During the years ended December 31, 2024 and 2023, our 2021 and 2020 PSU awards vested at 818,812 shares and 285,778 shares, respectively, with a total market value of $8.4 million and $3.6 million, respectively.

For the years ended December 31, 2025, 2024 and 2023, $5.1 million, $7.3 million and $4.8 million, respectively, were recognized as share-based compensation related to PSUs. In connection with the Compensation Committee’s decision in December 2025 to cash settle the 2023 PSU awards in 2026, 489,498 PSUs, which were previously accounted for as equity awards, were reclassified as liability awards with a liability balance of $4.6 million, reflecting the estimated fair value of the modified awards as of December 31, 2025. The cumulative compensation cost recognized in excess of the estimated fair value of the modified liability PSU awards is reflected in equity. For the year ended December 31, 2024, we recognized incremental compensation cost of $1.1 million related to the equity-to-liability award modification of 86,538 PSUs granted in 2022 to one of our officers. Future compensation cost and the weighted average vesting period associated with unvested PSU awards at December 31, 2025 were approximately $4.4 million and 0.9 year, respectively.

RSU Awards

Our outstanding RSUs can be settled in either cash or shares of our common stock, or a combination thereof, at the discretion of the Compensation Committee upon vesting and generally have been accounted for as liability awards.

The following table summarizes information about our RSU awards:


		Year Ended December 31,
		2025					2024					2023
				Grant Date					Grant Date					Grant Date
		Units		Fair Value ⁽¹⁾			Units		Fair Value ⁽¹⁾			Units		Fair Value ⁽¹⁾
RSU awards outstanding at beginning of year		1,068,592		$	6.98		1,367,702		$	4.82		1,367,294		$	3.36
Granted		443,401			9.32		375,730			10.28		506,436			7.38
Vested		(649,289)			5.61		(674,840)			4.43		(506,028)			3.44
RSU awards outstanding at end of year		862,704		$	9.22		1,068,592		$	6.98		1,367,702		$	4.82

(1)	Represents the weighted average grant date fair value, which is based on the quoted closing market price of our common stock on the trading day prior to the date of grant.

Compensation cost recognized for the years ended December 31, 2025, 2024 and 2023 was $2.9 million and $5.8 million and $6.8 million, respectively, which approximated the fair value of RSUs vested in January 2026, 2025 and 2024, respectively. Future compensation cost based on the fair value of unvested RSUs at December 31, 2025 totaled approximately $2.6 million. The weighted average vesting period related to unvested RSUs at December 31, 2025 was approximately 1.3 years.

Cash Awards

In 2025, 2024 and 2023, we granted fixed value cash awards of $5.7 million, $5.3 million and $5.8 million, respectively, to select management employees under the 2005 Incentive Plan. The value of these cash awards is recognized on a straight-line basis over a vesting period of three years. For the years ended December 31, 2025, 2024 and 2023, we recognized compensation costs of $5.0 million and $5.1 million and $4.5 million, respectively, which reflect the cash payouts made in January 2026, 2025 and 2024, respectively.

Defined Contribution Plans

We sponsor a defined contribution 401(k) retirement plan in the U.S. We also contribute to various other defined contribution plans globally. For the years ended December 31, 2025, 2024 and 2023, we made contributions to our defined contribution plans totaling $4.7 million, $4.7 million and $3.7 million, respectively.

Employee Stock Purchase Plan

As of December 31, 2025, 0.7 million shares were available for issuance under the ESPP. Eligible employees who participate in the ESPP may purchase shares of our common stock through payroll deductions on an after-tax basis over a four-month period beginning on January 1, May 1, and September 1 of each year during the term of the ESPP, subject to certain restrictions and limitations established by the Compensation Committee and Section 423 of the Internal Revenue Code. The per share price of common stock purchased under the ESPP is equal to 85% of the lesser of its fair market value on (i) the first trading day of the purchase period or (ii) the last trading day of the purchase period. The ESPP currently has a purchase limit of 260 shares per employee per purchase period.

Note 15 — Business Segment Information

We have three reportable business segments: Well Intervention, Robotics and Production Facilities. We previously reported the Shallow Water Abandonment segment, which was comprised entirely of Helix Alliance, prior to the sale of Helix Alliance on May 1, 2026. Our U.S., U.K. and Brazil Well Intervention operating segments are aggregated into the Well Intervention segment for financial reporting purposes. These reportable segments are strategic business units that utilize different mixes of vessels and/or equipment to perform different types of services. All material intercompany transactions between the segments have been eliminated. See Note 1 for more information on our business segments.

Our chief operating decision maker (“CODM”) is the chief operating officer. The CODM uses segment operating income or loss as the measure of segment profit or loss to evaluate segment performance by comparing the results of each segment with its annual budgeted amounts and monthly forecasts as well as the results of other segments. The CODM also uses segment operating income or loss to allocate company resources (including employees, property, and financial resources) to each segment.

Information about our segment revenues and our measure of segment profit or loss is shown as follows (in thousands):


	Well						Production
	Intervention			Robotics			Facilities		Total
Year ended December 31, 2025
External revenues	$	729,371		$	289,841		$	72,693	$	1,091,905
Intersegment revenues ⁽¹⁾		—			33,512			—		33,512
Segment revenues		729,371			323,353			72,693		1,125,417
Elimination of intersegment revenues										(33,512)
Total consolidated net revenues									$	1,091,905

Less ⁽²⁾:
Direct cost of revenues		(673,111)			(235,975)			(50,997)
Operations support		(15,666)			(5,597)			(549)
Selling, general and administrative expenses		(16,227)			(10,456)			(849)
Segment operating income	$	24,367		$	71,325		$	20,298	$	115,990

Year ended December 31, 2024
External revenues	$	823,472		$	259,639		$	88,709	$	1,171,820
Intersegment revenues ⁽¹⁾		6,390			38,039			—		44,429
Segment revenues		829,862			297,678			88,709		1,216,249
Elimination of intersegment revenues										(44,429)
Total consolidated net revenues									$	1,171,820

Less ⁽²⁾:
Direct cost of revenues		(704,120)			(203,849)			(64,429)
Operations support		(15,130)			(5,542)			(514)
Selling, general and administrative expenses		(16,991)			(10,944)			(2,513)
Other segment items ⁽³⁾		(416)			—			87
Segment operating income (loss)	$	93,205		$	77,343		$	21,340	$	191,888


	Well						Production
	Intervention			Robotics			Facilities		Total
Year ended December 31, 2023
External revenues	$	704,365		$	222,612		$	87,885	$	1,014,862
Intersegment revenues ⁽¹⁾		3,353			35,263			—		38,616
Segment revenues		707,718			257,875			87,885		1,053,478
Elimination of intersegment revenues										(38,616)
Total consolidated net revenues									$	1,014,862

Less ⁽²⁾:
Direct cost of revenues		(646,127)			(192,419)			(63,785)
Operations support		(14,427)			(4,838)			(606)
Selling, general and administrative expenses		(14,766)			(8,468)			(2,662)
Other segment items ⁽³⁾		—			300			—
Segment operating income	$	32,398		$	52,450		$	20,832	$	105,680

(1)

Intersegment amounts are derived primarily from equipment and services provided to other business segments. Beginning in 2024, certain intersegment revenues of Well Intervention are no longer evaluated by the CODM in his assessment of the segment’s results as those revenues are pass-through amounts related to non-core services. For the years ended December 31, 2024 and 2023, $27.6 million and $25.0 million, respectively, have been removed from Well Intervention segment revenues and related intersegment eliminations. This change has no impact on our segment profit or our consolidated revenues and operating income (loss).

(2)	The significant expense categories and amounts align with the segment-level information that is regularly provided to the CODM. Intersegment expenses are included within the amounts shown.

(3)	Other segment items in 2024 and 2023 relate to gain (loss) on disposition of assets, net.

The table below provides a reconciliation of segment profit to income (loss) from continuing operations before income taxes (in thousands):


	Year Ended December 31,
	2025			2024		2023
Reconciliation of segment profit —
Segment operating income	$	115,990		$	191,888	$	105,680
Long-lived asset impairment ⁽¹⁾		(18,064)			—		—
Corporate, eliminations and other		(43,649)			(55,158)		(65,485)
Net interest expense		(23,882)			(23,857)		(17,324)
Losses related to convertible senior notes ⁽²⁾		—			(20,922)		(37,277)
Other non-operating income (expense), net		(154)			609		(2,180)
Income (loss) from continuing operations before income taxes	$	30,241		$	92,560	$	(16,586)

(1)	Represents the impairment charge on the remaining net book value of the Thunder Hawk field (Note 6)

(2)	Represent the losses from the repurchases and redemptions of the 2026 Notes during December 2023 and the first quarter 2024 (Note 8).

The following items are also regularly provided to the CODM (in thousands):


	Year Ended December 31,
	2025			2024		2023
Capital expenditures ⁽¹⁾ —
Well Intervention	$	6,062		$	10,955	$	7,763
Robotics		7,900			10,402		3,957
Production Facilities		—			—		—
Corporate, eliminations and other		370			543		978
Total	$	14,332		$	21,900	$	12,698

Depreciation and amortization ⁽²⁾ —
Well Intervention	$	140,211		$	123,517	$	113,025
Robotics		4,805			7,601		9,604
Production Facilities		19,080			21,279		21,028
Corporate and eliminations		241			432		309
Total	$	164,337		$	152,829	$	143,966

(1)	Represent cash paid principally for the acquisition, construction, upgrade, modification and refurbishment of long-lived property and equipment.

(2)

Represents an aggregate of depreciation and amortization expense related to property and equipment and deferred certification and dry dock costs, which is included within the segment expense captions “Direct cost of revenues” and “Selling, general and administrative expenses” as well as the line item caption “Corporate, eliminations and other” presented above.

Revenues by individually significant geographic location are as follows (in thousands):


		Year Ended December 31,
		2025			2024			2023
U.S.		$	294,975		$	356,120		$	369,889
North Sea ⁽¹⁾			272,254			249,968			274,745
Brazil			354,509			185,538			177,070
Asia Pacific			68,415			222,119			163,957
West Africa			95,519			71,960			8,423
Other			6,233			86,115			20,778
Total		$	1,091,905		$	1,171,820		$	1,014,862

(1)	Includes revenues generated from the U.K. of $194.3 million, $181.8 million and $236.2 million, respectively, during the years ended December 31, 2025, 2024 and 2023.

Vessels, systems and other property and equipment work in various offshore basins around the world such as the Gulf of America, Brazil, North Sea, West Africa and Asia Pacific regions. Vessels and equipment may temporarily work in a region other than the country in which those assets are based. For instance, the Q4000 and related IRS system, which are based in the U.S., are temporarily operating offshore West Africa. The following table provides our property and equipment, net of accumulated depreciation, by individually significant country where those assets are based (in thousands):


		December 31,
		2025			2024
U.S.		$	508,284		$	570,635
U.K.			583,464			578,505
Brazil			197,733			199,627
Total		$	1,289,481		$	1,348,767

We have not included a disclosure of total assets by segment as management’s focus is on operating performance and cash flow generation and the CODM does not regularly review segment asset information.

Note 16 — Asset Retirement Obligations

Our AROs relate to mature offshore oil and gas properties (Droshky field and Thunder Hawk field) that we acquired with the intention to perform decommissioning work at the end of their life cycles. The following table describes the changes in our AROs (in thousands):


	2025		2024		2023
AROs at January 1,	$	62,947	$	61,356	$	51,956
Revisions in estimates		—		(4,010)		3,257
Accretion expense		5,823		5,601		6,143
AROs at December 31,	$	68,770	$	62,947	$	61,356

Note 17 — Commitments and Contingencies and Other Matters

Commitments

Our Well Intervention segment has long-term charter agreements with Sea1 Offshore (formerly Siem Offshore) for the Sea Helix 1 and Siem Helix 2 vessels, whose charter terms expire in December 2030 and December 2031, respectively. Our Robotics segment has long-term vessel charters for the Grand Canyon II, the Grand Canyon III, the Shelia Bordelon and the North Sea Enabler, whose charter terms expire in December 2030, May 2028, June 2026, and March 2026, respectively. In February 2025, our Robotics segment took delivery of the Trym with a three-year charter that expires in February 2028. On April 1, 2025, we extended the Trym charter by one year. In December 2025, we executed a new two-year charter agreement for the North Sea Enabler starting in July 2026. In January 2026, our Robotics segment took delivery of the Patriot with a four-year charter that expires in January 2030.

Contingencies and Claims

From time to time, we may incur losses related to our contracts for matters such as costs in excess of contract consideration or claims related to disputes with customers and any obligations thereunder. While we believe we maintain appropriate accruals for such matters, the actual cost to us may be more or less than the amounts reserved.

We are involved in various legal proceedings and other matters in the normal course of business, including claims under the General Maritime Laws of the United States and the Merchant Marine Act of 1920 (commonly referred to as the Jones Act), contract-related disputes and employee-related disputes. We recognize losses for contingencies when the probability of an unfavorable outcome is probable and we can reasonably estimate the amount of the loss. For insured claims, we recognize such losses to the extent they exceed applicable insurance coverage. Although we can give no assurance about the outcome of litigation, claims or other proceedings, we do not currently believe that any loss resulting from litigation, claims or other proceedings, to the extent not otherwise accrued for or covered by insurance, will have a material adverse impact on our consolidated financial statements.

Note 18 — Statement of Cash Flow Information

The following table provides supplemental cash flow information (in thousands):


	Year Ended December 31,
	2025		2024		2023
Interest paid	$	30,844	$	25,447	$	20,984
Income taxes paid ⁽¹⁾		30,753		14,124		7,394

(1)	Exclusive of any income tax refunds.

Our capital additions include the acquisition of property and equipment for which payment has not been made. As of December 31, 2025 and 2024, these non-cash capital additions totaled $1.0 million and $0.1 million, respectively.

Non-cash financing activities for the year ended December 31, 2023 included the issuance of 1.5 million shares of our common stock for the repurchase of a portion of our 2026 Notes.

Note 19 — Allowance Accounts

The following table sets forth the activity in our valuation accounts for each of the three years in the period ended December 31, 2025 (in thousands):


	Allowance for		Deferred Tax Asset
	Credit Losses		Valuation Allowance
Balance at December 31, 2022	$	1,731	$	22,157
Additions ^{(1) (2)}		1,149		51,354
Write-offs		(19)		—
Adjustments ⁽³⁾		—		7,604
Balance at December 31, 2023		2,861		81,115
Reductions ⁽¹⁾		(161)		—
Adjustments ⁽⁴⁾		—		(5,734)
Balance at December 31, 2024		2,700		75,381
Reductions ⁽¹⁾		(136)		—
Adjustments ⁽³⁾		—		9,570
Balance at December 31, 2025	$	2,564	$	84,951

(1)	The additions/reductions in allowance for credit losses relate to reserves (releases) for expected credit losses during the respective years.

(2)	The addition in valuation allowance relates to the adjustment for a change in assessment on the realizability of our Luxembourg net operating losses from remote to less likely than not.

(3)	The increase in valuation allowance relates to current year activity, including adjustments to prior year returns, and an internal restructuring.

(4)

The net decrease in valuation allowance included a $3.2 million decrease related to a valuation allowance release in Brazil, a $5.2 million increase in assessment on the realizability of U.S. group foreign tax credit carryforward, and a $7.7 million decrease in valuation allowance, which was predominantly driven by current year activity, including adjustments to prior year returns.

See Note 2 for a detailed discussion regarding our accounting policy on accounts receivable and allowance for credit losses. See Note 9 for a detailed discussion of the valuation allowance related to our deferred tax assets.

Note 20 — Fair Value Measurements

Our financial instruments include cash and cash equivalents, receivables, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments.

We used Level 3 input to estimate the fair value of the Thunder Hawk field during our asset impairment assessment in 2025. See Note 6 for additional disclosures.

The principal amount and estimated fair value of our long-term debt are as follows (in thousands):


	December 31, 2025				December 31, 2024
	Principal		Fair		Principal		Fair
	Amount ⁽¹⁾		Value ⁽²⁾		Amount ⁽¹⁾		Value ⁽²⁾
MARAD Debt (matures February 2027)	$	14,645	$	14,611	$	23,831	$	23,505
2029 Notes (mature March 2029)		300,000		317,250		300,000		319,500
Total debt	$	314,645	$	331,861	$	323,831	$	343,005

(1)	Principal amount includes current maturities and excludes any related unamortized debt discount and debt issuance costs. See Note 8 for additional disclosures on our long-term debt.

(2)	The estimated fair value was determined using Level 2 fair value inputs under the market approach, which was determined using quotes in inactive markets.