Helix Energy Solutions Group HLX Form 10-Q filing Q3 FY2025

​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​ ​ ​ ​

​

​

​

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

​

​

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

​

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)

​

​

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

​

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)

​

​

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

​

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)

​

​

​

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

​

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

​

​

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

​

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

​

Note 1 — Basis of Presentation and New Accounting Standards

The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its subsidiaries (collectively, “Helix”). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this report refer collectively to Helix and its subsidiaries. All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements in U.S. dollars have been prepared in accordance with instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (the “SEC”) and do not include all information and footnotes normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”).

The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. We have made all adjustments, which, unless otherwise disclosed, are of normal recurring nature, that we believe are necessary for a fair presentation of the condensed consolidated balance sheets, statements of operations, statements of comprehensive loss, statements of shareholders’ equity and statements of cash flows, as applicable. The operating results for the three- and nine-month periods ended September 30, 2025 are not necessarily indicative of the results that may be expected for the year ending December 31, 2025. Our balance sheet as of December 31, 2024 included herein has been derived from the audited balance sheet as of December 31, 2024 included in our 2024 Annual Report on Form 10-K (our “2024 Form 10-K”). These unaudited condensed consolidated financial statements should be read in conjunction with the audited annual consolidated financial statements and notes thereto included in our 2024 Form 10-K.

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.

New accounting standards

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. ASU No. 2023-09 will be effective for us for annual periods beginning January 1, 2025. This ASU is not expected to have a material impact on our consolidated financial statements other than increased disclosure requirements.

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 2 — Company Overview

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:

• Production maximization — our assets and methodologies are specifically designed to safely and efficiently enhance and extend the lives of existing oil and gas reserves;
• Decommissioning — we are a full-field abandonment contractor and believe that regulatory push for plug and abandonment (“P&A”) and transition to renewable energy will facilitate the continued growth of the abandonment market; and
• Renewables — we are an established global leader in jet trenching and provide specialty support services to renewable energy developments (primarily offshore wind farms), including boulder removal and unexploded ordnance clearance.

We provide a range of services to the oil and gas and renewable energy markets primarily in the Gulf of America (deepwater and shelf), U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations and our Gulf of America shelf operations are usually subject to seasonal changes in activity levels, which generally peak in the summer months and decline in the winter months. Our services are segregated into four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities.

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 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 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 away from a carbon-based economy. 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 Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the Gulf of America shelf, including offshore oilfield decommissioning and ‎reclamation, well intervention, IRM, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes Helix Alliance that was acquired in July 2022, a vertically integrated company that offers a diversified fleet of marine assets including liftboats, offshore supply vessels (“OSVs”), dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat, P&A systems and coiled tubing (“CT”) systems.

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 3 — Details of Certain Accounts

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

​

​

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

​

(1) Represents prepayments to the owner of the Siem 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 oil and gas properties we acquired from Marathon Oil Corporation in 2019.

​

Accrued liabilities consist of the following (in thousands):

​

​

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

​

​

​

​

Note 4 — Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2034.

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

​

​

Maturities of our operating lease liabilities as of September 30, 2025 are as follows (in thousands):

​

​

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

​

​

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

​

​

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

​

(1) Our operating lease additions are primarily related to the charter for the Trym during the nine-month period ended September 30, 2025, and the charter extensions for the Siem Helix 1, the Siem Helix 2, the Grand Canyon II and the Shelia Bordelon during the nine-month period ended September 30, 2024 (Note 13).

​

Note 5 — Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of September 30, 2025 are as follows (in thousands):

​

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

​

Below is a summary of our indebtedness:

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 September 30, 2025, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity, based on the borrowing base, totaled $94.3 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.

​

​

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 Redemption

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 condensed consolidated statement of operations. The 2026 Notes had a coupon interest rate of 6.75% per annum and an effective interest rate of 7.6%. For the nine-month period ended September 30, 2024, total interest expense related to the 2026 Notes was $0.4 million with coupon interest expense of $0.3 million and the amortization of debt issuance costs of $0.1 million.

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 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 condensed consolidated balance sheets.

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 September 30, 2025, we were in compliance with these covenants.

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

​

​

​

Note 6 — 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 condensed 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 three- and nine-month periods ended September 30, 2025.

For the three- and nine-month periods ended September 30, 2025, we recorded income tax provision of $19.2 million and $13.6 million, respectively, resulting in effective tax rates of 46.5% and 37.7% respectively. The effective tax rates for these periods were impacted by certain discrete items and the jurisdictional mix of earnings. For the three- and nine-month periods ended September 30, 2024, we recorded income tax provision of $9.5 million and $22.5 million, respectively, resulting in effective tax rates of 24.4% and 38.8%, respectively. The effective rate for the three-month period ended September 30, 2024 was impacted by certain non-deductible expenses and non-creditable foreign income taxes. The effective rate for the nine-month period ended September 30, 2024 was impacted by the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event.

​

​

​

​

Note 7 — Share Repurchase Programs

In February 2023, our Board of Directors (our “Board”) authorized a share repurchase program to repurchase issued and outstanding shares of our common stock up to $200 million (the “2023 Repurchase Program”). As of September 30, 2025, approximately $128.4 million remained authorized for the repurchase of shares under the 2023 Repurchase Program. During the nine-month period ended September 30, 2025, we repurchased a total of 4,643,060 shares of our common stock pursuant to the 2023 Repurchase Program for approximately $30.0 million. During the nine-month period ended September 30, 2024, we repurchased a total of 937,585 shares of our common stock pursuant to the 2023 Repurchase Program for approximately $10.2 million.

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 8 — Revenue from Contracts with Customers

Disaggregation of Revenue

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.

Our revenues are primarily derived from short-term and long-term service contracts with customers. Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration. 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 tables provide information about disaggregated revenue by contract duration and by market strategy (in thousands):

​

​

(1) For the three- and nine-month periods ended September 30, 2024, $8.1 million and $20.1 million, respectively, have been removed from Well Intervention segment revenues and related intersegment eliminations. See Note 11 regarding this change in prior year reported segment information.

​

Contract Balances

Net contract assets were $8.8 million as of September 30, 2025 and $12.2 million as of December 31, 2024 and are reflected in “Other current assets” in the accompanying condensed consolidated balance sheets (Note 3). 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 three- and nine-month periods ended September 30, 2025 and 2024.

Net contract liabilities totaled $31.1 million as of September 30, 2025 and $15.6 million as of December 31, 2024 and are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” in the accompanying condensed consolidated balance sheets (Note 3). The increase was primarily attributable to a larger amount of deferred mobilization fees for work that has not yet been completed as well as more prepayments on work not yet performed. Revenue recognized for the three- and nine-month periods ended September 30, 2025 included $19.8 million and $19.4 million, respectively, that were included in the contract liability balance at the beginning of each period. Revenue recognized for the three- and nine-month periods ended September 30, 2024 included $12.6 million and $34.4 million, respectively, that were included in the contract liability balance at the beginning of each period.

Performance Obligations

As of September 30, 2025, $1.3 billion related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $207.6 million, $542.0 million and $559.9 million in 2025, 2026 and 2027 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 September 30, 2025.

For the three- and nine-month periods ended September 30, 2025 and 2024, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods 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 condensed consolidated balance sheets (Note 3). Our deferred contract costs totaled $29.1 million as of September 30, 2025 and $37.2 million as of December 31, 2024. For the three- and nine-month periods ended September 30, 2025, we recorded $20.5 million and $53.7 million, respectively, related to amortization of these deferred contract costs. For the three- and nine-month periods ended September 30, 2024, we recorded $9.9 million and $41.1 million, respectively, related to amortization of these deferred contract costs. There were no associated impairment losses for any period presented.

For additional information regarding revenue recognition, see Notes 2 and 11 to our 2024 Form 10-K.

​

Note 9 — Earnings Per Share

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

​

​

​

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

​

​

We have outstanding restricted stock units (“RSUs”) (Note 10) 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 10 — 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”). As of September 30, 2025, there were approximately 8.1 million shares of our common stock available for issuance under the 2005 Incentive Plan, assuming outstanding performance share units (“PSUs”) vest in shares of our common stock at 100% of the original awards and outstanding RSUs are settled in cash. During the nine-month period ended September 30, 2025, the following grants of share-based awards were made under the 2005 Incentive Plan:

​

(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 who have elected to take their quarterly fees in stock in lieu of cash.

​

We have restricted stock outstanding granted to members of our Board. For the three- and nine-month periods ended September 30, 2025, we recognized $0.2 million and $0.7 million, respectively, as share-based compensation related to restricted stock. For the three- and nine-month periods ended September 30, 2024, we recognized $0.1 million and $0.7 million, respectively, as share-based compensation related to restricted stock.

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 of our Board 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.

For the three- and nine-month periods ended September 30, 2025, $1.3 million and $3.8 million, respectively, were recognized as share-based compensation related to PSUs. For the three- and nine-month periods ended September 30, 2024, $1.6 million and $4.4 million, respectively, were recognized as share-based compensation related to PSUs. In the first quarter 2025, based on the performance of our common stock price as compared to our performance peer group and our cumulative total Free Cash Flow, in each case over a three-year performance period, 1,065,705 PSUs granted in 2022 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.

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 of our Board upon vesting and generally have been accounted for as liability awards. For the three- and nine-month periods ended September 30, 2025, $0.8 million and $2.3 million, respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2024, $1.5 million and $5.2 million, respectively, were recognized as compensation cost.

During the nine-month period ended September 30, 2025 and the year ended December 31, 2024, we granted fixed-value cash awards of $6.7 million and $6.1 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 three- and nine-month periods ended September 30, 2025, $1.3 million and $4.2 million, respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2024, $1.4 million and $4.1 million, respectively, were recognized as compensation cost.

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 three- and nine-month periods ended September 30, 2025, we made contributions to our defined contribution plans totaling $1.3 million and $4.2 million, respectively. For the three- and nine-month periods ended September 30, 2024, we made contributions to our defined contribution plans totaling $1.3 million and $4.1 million, respectively.

Employee Stock Purchase Plan (“ESPP”)

As of September 30, 2025, 0.7 million shares were available for issuance under the ESPP. The ESPP currently has a purchase limit of 260 shares per employee per purchase period.

For more information regarding our employee benefit plans, including the 2005 Incentive Plan, the defined contribution plans and the ESPP, see Note 13 to our 2024 Form 10-K.

​

Note 11 — Business Segment Information

We have four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. 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 mix of vessels and/or equipment to perform different types of services. All material intercompany transactions between the segments have been eliminated. See Note 2 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):

​

​

(1) Intersegment amounts are derived primarily from equipment and services provided to other business segments. Beginning with the full-year 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. Accordingly, for the three- and nine-month periods ended September 30, 2024, $8.1 million and $20.1 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 relate to gain (loss) on disposition of assets, net.

​

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

​

​

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

​

(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 recertification 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.

​

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 12 — Asset Retirement Obligations

Our asset retirement obligations (“AROs”) relate to mature offshore oil and gas properties (Droshky 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):

​

​

​

Note 13 — Commitments and Contingencies and Other Matters

Commitments

Our Well Intervention segment has long-term charter agreements with Sea1 Offshore (formerly Siem Offshore) for the Siem 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, the North Sea Enabler and the Glomar Wave, whose charter terms expire in December 2030, May 2028, June 2026, December 2025 and December 2025, 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 to April 1, 2029.

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 14 — Statement of Cash Flow Information

We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of three months or less. The following table provides supplemental cash flow information (in thousands):

​

(1) Exclusive of any income tax refunds.

​

Our capital additions include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions were $1.4 million at September 30, 2025 and $0.1 million at December 31, 2024.

​

Note 15 — Allowance for 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. The following table sets forth the activity in our allowance for credit losses (in thousands):

​

(1) Additions reflect reserves for expected credit losses during the respective periods.

​

Note 16 — 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.

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

​

(1) Principal amount includes current maturities and excludes any related unamortized debt discount and debt issuance costs. See Note 5 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.

​

​

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

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. 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. Our Well Intervention segment includes seven purpose-built well intervention vessels and 12 intervention systems. Our Robotics segment includes 39 work-class ROVs, six trenchers, three IROV boulder grabs, and robotics support vessels chartered on long-term, short-term and flexible bases to facilitate our ROV and trenching operations. Our Shallow Water Abandonment segment includes nine liftboats, six OSVs, three DSVs, one heavy lift derrick barge, one crew boat, 20 P&A systems and six CT systems. Our Production Facilities segment includes the HP I, the HFRS and our ownership of mature oil and gas properties.

Demand for our services is primarily influenced by the condition of the oil and gas and the renewable energy markets and, in particular, the level of spending of offshore energy companies on operational activities and capital projects. The level of spending by our customers is significantly affected by the prevailing market prices for oil and natural gas, which are impacted by many factors including domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, global health, and various other factors. Demand for decommissioning is affected by commodity prices as well as governmental regulations and political forces globally.

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 day 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 day 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 and Shallow Water Abandonment segments. We believe that our well intervention vessels have a competitive advantage in performing these services more efficiently than rigs, and with our suite of shallow water assets and capabilities, we are the only provider capable of providing all facets of decommissioning services in the Gulf of America shelf.

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 pace of consumer 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 remained volatile during the third quarter 2025 and averaged in the $60s during most of the quarter. The current market environment is uncertain following the ongoing escalation of tariffs globally and the production increases by the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”). 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 (windfall tax), geopolitical instability and uncertainty, regional conflicts, unrest in the Middle East, and customer spending declines following mergers in the U.K. North Sea. These factors have shifted spending decisions of our customers into 2026, which has caused a slow-down in activity levels in the second half of 2025. These factors have also 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 is 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.

Outlook

We anticipate ongoing headwinds for 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 in our Shallow Water Abandonment segment during the remainder of 2025 and into 2026, during which time we expect a soft rate environment and low potential utilization of our vessels and systems. Our performance should be supported by our backlog from new contracting and by increasing demand for our decommissioning services internationally, which should grow over mid- to long-term as the subsea tree base expands and as customers reduce their decommissioning obligations. We expect the demand for shallow water decommissioning services in the Gulf of America to improve over time as former owners address their decommissioning obligations related to oil and gas properties that have reverted to them following bankruptcies. 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 September 30, 2025, our consolidated backlog totaled approximately $1.3 billion, of which $208 million is expected to be performed over the remainder of 2025. Our various contracts with Shell and Subsea 7 globally, our contracts with Petrobras in Brazil, and our new multi-year trenching agreement with NKT in the North Sea represented approximately 80% of our total backlog as of September 30, 2025. 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 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 on EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt. EBITDA, 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 EBITDA, 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 EBITDA, 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 EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, 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 EBITDA as earnings before income taxes, net interest expense, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude gains or losses on disposition of assets, acquisition and integration costs, gains or losses related to convertible senior notes, the change in fair value of contingent consideration 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 condensed consolidated financial statements unless otherwise noted.

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

​

​

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

​

​

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

​

​

Comparison of Three Months Ended September 30, 2025 and 2024

We have four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements. The following table details our financial and operational highlights for the periods presented (dollars in thousands):

​

(1) Represents the number of vessels, Robotics assets or Shallow Water Abandonment systems 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, vessels managed on behalf of third parties 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, Robotics assets or Shallow Water Abandonment systems 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.

(4) Consists of liftboats, OSVs, DSVs, a heavy lift derrick barge and a crew boat.

(5) Consists of P&A and CT systems.

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

​

​

Net Revenues. Our consolidated net revenues for the three-month period ended September 30, 2025 increased by 10% as compared to the same period in 2024, primarily reflecting higher revenues in our Well Intervention, Robotics and Shallow Water Abandonment business segments, offset in part by lower revenues in our Production Facilities segment.

Our Well Intervention revenues increased by 11% for the three-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting fewer transit and mobilization days on the Q7000 and higher rates in Brazil, offset in part by lower utilization on the Seawell. During the third quarter 2024, the Q7000 incurred approximately 38 days of paid transit and mobilization during which period revenues and costs were deferred and not recognized. Revenues increased on the Siem Helix 1 and the Siem Helix 2, which operated at higher contractual rates as compared to the third quarter 2024. Revenues decreased on the Seawell, which was warm-stacked during the third quarter 2025 as compared to having near full utilization during the third quarter 2024.

Our Robotics revenues increased by 18% for the three-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting higher rates on our chartered vessels and increased site clearance and third-party trenching activities, offset in part by fewer integrated vessel trenching days and lower overall ROV utilization. The third quarter 2025 included 536 chartered vessel days (including 28 spot vessel days at full utilization), which included 192 days of site clearance operations using three IROV boulder grabs, as compared to 532 chartered vessel days (including 92 spot vessel days at full utilization), which included 92 days of site clearance operations using one IROV boulder grab, during the third quarter 2024. The third quarter 2025 also included 165 days of trenching on third-party vessels with the T-1400-1 and T-1400-2 jet trenchers as compared to 92 days with the i-Plough during the third quarter 2024. Integrated vessel trenching decreased to 210 days during the third quarter 2025 as compared to 249 days during the third quarter 2024, and ROV utilization decreased to 63% during the third quarter 2025 as compared to 77% during the third quarter 2024.

Our Shallow Water Abandonment revenues increased by 4% for the three-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting higher utilization on our systems, offset in part by lower rates on our systems and lower overall utilization and rates on our vessels during the third quarter 2025. Utilization on P&A systems and CT systems increased to 1,003 days, or 42%, during the third quarter 2025 as compared to 607 days, or 25%, during the third quarter 2024. Overall vessel utilization was 67% during the third quarter 2025 as compared to 76% during the third quarter 2024.

Our Production Facilities revenues decreased by 11% for the three-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting lower oil and gas production and prices, offset in part by higher HFRS revenues during the third quarter 2025. The Thunder Hawk field remained shut in during the entire third quarter 2025 whereas the field had one month of production prior to being shut in during the third quarter 2024. Additionally, oil prices were approximately $10 per barrel lower during the third quarter 2025 as compared to the third quarter 2024. HFRS rates were higher during the third quarter 2025 as compared to the third quarter 2024.

Gross Profit (Loss). Our consolidated gross profit increased slightly for the three-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting increased profitability from our Robotics and Shallow Water Abandonment business segments, offset in part by reduced profitability from our Well Intervention and Production Facilities segments.

Our Well Intervention gross profit decreased by $7.7 million for the three-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting higher costs during the third quarter 2025 due to acceleration of the amortization of deferred regulatory costs related to the Q4000 and a higher number of transit and mobilization days during the third quarter 2024 over which period costs were deferred, offset in part by higher revenues during the third quarter 2025.

Our Robotics gross profit increased by $3.8 million for the three-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting higher rates, offset in part by higher costs and lower margins on certain projects due to the mix of contracting during the third quarter 2025.

Our Shallow Water Abandonment gross profit increased by $6.9 million for the three-month period ended September 30, 2025 as compared to the same period in 2024 primarily due to higher revenues and lower costs during the third quarter 2025.

Our Production Facilities gross profit decreased by $2.8 million for the three-month period ended September 30, 2025 as compared to the same period in 2024 primarily due to lower revenues during the third quarter 2025.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $18.2 million for the three-month period ended September 30, 2025 as compared to $21.1 million for the same period in 2024, primarily reflecting lower employee compensation costs.

Other Expense, Net. Net other expense was $1.0 million for the three-month period ended September 30, 2025 as compared to a minimal net other expense for the same period in 2024. Net other expense primarily includes net foreign currency losses related to the British pound on our U.K. subsidiaries’ foreign currency positions.

Income Tax Provision. Income tax provision was $19.2 million for the three-month period ended September 30, 2025 as compared to $9.5 million for the same period in 2024. The effective tax rate for the third quarter 2025 was impacted by certain discrete items and the jurisdictional mix of earnings. The effective rate for the third quarter 2024 was impacted by certain non-deductible expenses and non-creditable foreign income taxes.

Comparison of Nine Months Ended September 30, 2025 and 2024

We have four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements. The following table details our financial and operational highlights for the periods presented (dollars in thousands):

​

(1) Represents the number of vessels, Robotics assets or Shallow Water Abandonment systems 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, vessels managed on behalf of third parties 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, Robotics assets or Shallow Water Abandonment systems 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.

(4) Consists of liftboats, OSVs, DSVs, a heavy lift derrick barge and a crew boat.

(5) Consists of P&A and CT systems.

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

​

​

Net Revenues. Our consolidated net revenues for the nine-month period ended September 30, 2025 decreased by 5% as compared to the same period in 2024, reflecting lower revenues in our Well Intervention, Shallow Water Abandonment and Production Facilities business segments, offset in part by higher revenues in our Robotics segment.

Our Well Intervention revenues decreased by 9% for the nine-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting lower utilization on the Seawell, the Q4000, the Q5000 and the Q7000, offset in part by higher rates on the Q4000 and in Brazil during the nine-month period ended September 30, 2025. Revenues decreased on the Seawell, which has been warm-stacked during the nine-month period ended September 30, 2025 as compared to being nearly fully utilized during the nine-month period ended September 30, 2024. Revenues on the Q4000 were lower as the vessel underwent an approximate 33-day docking following a 45-day demobilization during the nine-month period ended September 30, 2025 as compared to a 67-day mobilization during the nine-month period ended September 30, 2024. Utilization on the Q5000 was lower as the vessel underwent an approximate 57-day planned regulatory dry dock during the second quarter 2025. Revenues on the Q7000 were lower due to the vessel recognizing only six days of revenue during the first quarter 2025 following the vessel’s completed mobilization and regulatory docking and commencement of its 400-day contract in Brazil as compared to being fully utilized in Australia during the nine-month period ended September 30, 2024. During the nine-month period ended September 30, 2025, the Q4000 completed its Nigeria campaign at higher integrated project rates and transited back to the Gulf of America. Revenues in Brazil increased as the Siem Helix 1 and the Siem Helix 2 operated under new contract terms at higher contractual rates during the nine-month period ended September 30, 2025.

Our Robotics revenues increased by 9% for the nine-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting higher chartered vessel rate and increased site clearance and third-party trenching activities, offset in part by a reduction in chartered vessel and ROV utilization. The nine-month period ended September 30, 2025 included 1,317 chartered vessel days (including 75 spot vessel days at full utilization), which included 403 days of site clearance operations using three IROV boulder grabs, as compared to 1,393 chartered vessel days (including 274 spot vessel days at full utilization), which included 260 days of site clearance operations using two IROV boulder grabs, during the nine-month period ended September 30, 2024. The nine-month period ended September 30, 2025 also included 346 days of trenching on third-party vessels as compared to 141 days during the nine-month period ended September 30, 2024. Integrated vessel trenching declined to 502 days during the nine-month period ended September 30, 2025 as compared to 566 days during the nine-month period ended September 30, 2024, and ROV utilization decreased to 59% during the nine-month period ended September 30, 2025 as compared to 70% during the nine-month period ended September 30, 2024.

Our Shallow Water Abandonment revenues decreased by 5% for the nine-month period ended September 30, 2025 as compared to the same period in 2024 primarily due to lower rates on our vessels and systems and lower overall utilization on our vessels, offset in part by higher utilization on our systems. Overall vessel utilization was 52% during the nine-month period ended September 30, 2025 as compared to 59% during the same period in 2024. Utilization on P&A systems and CT systems increased to 2,065 days, or 29%, during the nine-month period ended September 30, 2025 as compared to 1,865 days, or 26%, during the nine-month period ended September 30, 2024.

Our Production Facilities revenues decreased by 21% for the nine-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting lower oil and gas production and prices during the nine-month period ended September 30, 2025. The Thunder Hawk field remained shut in for the entire nine-month period in 2025 whereas the field had seven months of production prior to being shut in during the third quarter 2024. The Droshky wells were shut in for approximately one month in the second quarter 2025 whereas the field had a full nine months of production in 2024.

Gross Profit (Loss). Our consolidated gross profit decreased by $52.2 million for the nine-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting reduced profitability from our Well Intervention and Robotics business segments, offset in part by increased profitability from our Shallow Water Abandonment and Production Facilities segments.

Our Well Intervention segment gross profit decreased by $52.4 million for the nine-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting lower overall revenues during the nine-month period ended September 30, 2025 and higher vessel costs on the Q4000 during the third quarter 2025, offset in part by lower vessel costs on the Seawell due to the vessel being warm-stacked in 2025 and cost deferrals on the Q7000 during its mobilization and regulatory docking in the first quarter 2025.

Our Robotics gross profit decreased by $5.6 million for the nine-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting higher costs and lower margins on certain projects due to the mix of contracting during the nine-month period ended September 30, 2025.

Our Shallow Water Abandonment gross profit increased by $4.9 million for the nine-month period ended September 30, 2025 as compared to the same period in 2024, primarily reflecting lower costs, offset in part by lower overall revenues during the nine-month period ended September 30, 2025.

Our Production Facilities gross profit increased by $0.9 million for the nine-month period ended September 30, 2025 as compared to the same period in 2024 primarily due to the incurrence of well workover costs related to the Thunder Hawk wells during the first quarter 2024.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $55.6 million for the nine-month period ended September 30, 2025 as compared to $64.1 million for the same period in 2024, primarily reflecting lower employee compensation costs.

Net Interest Expense. Our net interest expense totaled $17.2 million for the nine-month period ended September 30, 2025 as compared to $17.1 million for the same period in 2024, primarily reflecting lower interest income on our invested cash (Note 5).

Losses Related to Convertible Senior Notes. The losses during the nine-month period ended September 30, 2024 were associated with the redemption of our 2026 Notes (Note 5).

Other Expense, Net. Net other expense was $0.9 million for the nine-month period ended September 30, 2025 as compared to net other expense of $2.6 million for the same period in 2024. Net other expense primarily includes net foreign currency losses related to the British pound on our U.K. subsidiaries’ foreign currency positions.

Income Tax Provision. Income tax provision was $13.6 million for the nine-month period ended September 30, 2025 as compared to $22.5 million for the same period in 2024. The effective tax rate for the nine-month period ended September 30, 2025 was impacted by certain discrete items and the jurisdictional mix of earnings. The effective rate for the nine-month period ended September 30, 2024 was impacted by the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event.

​

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):

​

​

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.

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 at September 30, 2025 and $9.2 million at December 31, 2024. See Note 5 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 September 30, 2025 included $338.0 million of cash and cash equivalents and $94.3 million of available borrowing capacity under the Amended ABL Facility (Note 5) 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.

We believe that our cash on hand, internally generated cash flows 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 condensed consolidated statements of cash flows (in thousands):

​

​

Operating Activities

Cash flows provided by operating activities for the nine-month period ended September 30, 2025 decreased as compared to the same period in 2024 despite the absence of an earnout payment, primarily reflecting lower earnings, higher regulatory recertification costs on our vessels and systems and higher working capital outflows. Our operating cash outflows during the nine-month period ended September 30, 2024 included $58.3 million of the $85.0 million earnout payment on April 3, 2024. Regulatory recertification spending on our vessels and systems was $48.3 million and $29.2 million, respectively, during the comparable year over year periods.

Investing Activities

Cash flows used in investing activities for the nine-month period ended September 30, 2025 increased slightly as compared to the same period in 2024. Our investing cash outflows during the nine-month period ended September 30, 2024 were offset in part by cash proceeds from the sale of assets and insurance recoveries.

Financing Activities

Net cash outflows from financing activities for the nine-month period ended September 30, 2025 primarily reflect the repurchases of $30.2 million in our common stock under the 2023 Repurchase Program (including $0.2 million of excise tax paid), 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 the nine-month period ended September 30, 2024 primarily reflect cash outflows of $60.7 million related to the 2026 Notes, $26.7 million of the $85.0 million earnout payment, the principal repayment of $8.7 million related to the MARAD Debt and $10.2 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.

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 property and equipment and operating lease obligations, as of September 30, 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 maturities. Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory recertification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of September 30, 2025.

​

(1) Operating leases include vessel charters and facility and equipment leases, including commitments related to leases executed but not yet commenced. At September 30, 2025, our commitment related to long-term vessel charters that have commenced totaled approximately $719.8 million, of which $363.8 million was related to the non-lease (services) components that are not included in operating lease liabilities in the condensed consolidated balance sheet as of September 30, 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 12). Those obligations, which are presented on a discounted basis on the condensed consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk Field oil and gas properties and $37.1 million (undiscounted) for Droshky oil and gas properties as of September 30, 2025, none of which is expected to be paid during the next 12 months. We are entitled to receive $30.0 million (undiscounted) from Marathon Oil Corporation as certain decommissioning obligations associated with Droshky oil and gas properties are fulfilled.

Regulatory recertification and dry dock. Our vessels and systems are subject to certain regulatory recertification requirements that must be satisfied in order for the vessels and systems to operate. Recertification 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 $0.2 million to $15.0 million per vessel and $0.5 million to $5.0 million per system.

We expect the sources of funds to satisfy our material cash requirements to come from our ongoing operations and existing cash on hand. Although not currently expected, 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 condensed consolidated financial statements and related footnotes, 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. For information regarding our critical accounting estimates, see our “Critical Accounting Estimates” as disclosed in our 2024 Form 10-K.

​

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As a multi-national organization, we are subject to market risks associated with foreign currency exchange rates, interest rates and commodity prices.

Foreign Currency Exchange Rate Risk. Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. As such, our earnings are impacted by movements in foreign currency exchange rates when (i) transactions are denominated in currencies other than the functional currency of the relevant Helix entity or (ii) the functional currency of our subsidiaries is not the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the U.S., we endeavor to pay a portion of our expenses in local currencies to partially offset revenues that are denominated in the same local currencies. In addition, a substantial portion of our contracts are denominated, and provide for collections from our customers, in U.S. dollars.

Assets and liabilities of our subsidiaries that do not have the U.S. dollar as their functional currency are translated using the exchange rates in effect at the balance sheet date, and changes in the exchange rates can result in translation adjustments that are reflected in “Accumulated other comprehensive loss” in the shareholders’ equity section of our condensed consolidated balance sheets. For the nine-month period ended September 30, 2025, we recorded foreign currency translation gains of $63.2 million to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments as any outside stock basis differences would be realized in a tax-free manner.

When currencies other than the functional currency are to be paid or received, the resulting transaction gain or loss associated with changes in the applicable foreign currency exchange rate is recognized in the condensed consolidated statements of operations as a component of “Other income (expense), net.” 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 three- and nine-month periods ended September 30, 2025, we recorded net foreign currency losses of $1.0 million and $0.9 million, respectively, primarily related to the British pound on our U.K. subsidiaries’ foreign currency positions.

Interest Rate Risk. In order to minimize the risk of changes to our cash flow due to changing interest rates, we generally borrow at fixed rates, but may borrow at variable rates from time to time. For fixed rate debt, changes in interest rates may not affect our interest expense, but could result in changes in the fair value of the debt instrument prior to maturity and we may be at risk upon refinancing maturing debt. For variable rate debt, changes in interest rates could affect our future interest expense and cash flows. We currently have no amounts outstanding under the Amended ABL Facility or other debt subject to floating rates.

Commodity Price Risk. We are exposed to market price risks related to oil and natural gas with respect to offshore oil and gas production in our Production Facilities business. Prices are volatile and unpredictable and are dependent on many factors beyond our control. See Item 1A. Risk Factors in our 2024 Form 10-K for a list of factors affecting oil and gas prices.

​

Item 4. Controls and Procedures

(a) Evaluation of disclosure controls and procedures. Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of September 30, 2025. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2025 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

(b) Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the three-month period ended September 30, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

​

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 13 — Commitments and Contingencies and Other Matters to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

​

Item 1A. Risk Factors

There have been no material changes during the period ended September 30, 2025 in our “Risk Factors” as discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024.

​

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

​

(1) See Note 7 to this Quarterly Report on Form 10-Q and Note 10 to our 2024 Annual Report on Form 10-K for additional information regarding our share repurchase programs.

​

Item 3. Defaults Upon Senior Securities

None.

​

Item 4. Mine Safety Disclosures

Not applicable.

​

Item 5. Other Information

(c) During the three-month period ended September 30, 2025, no director or “officer” of Helix adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

​

Item 6. Exhibits

​

Exhibit Number Description Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)

3.1 2005 Amended and Restated Articles of Incorporation, as amended, of Helix Energy Solutions Group, Inc. Exhibit 3.1 to the Current Report on Form 8-K filed on March 1, 2006 (000-22739) 3.2 Second Amended and Restated By-Laws of Helix Energy Solutions Group, Inc., as amended. Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936) 31.1 Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer. Filed herewith 31.2 Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Erik Staffeldt, Chief Financial Officer. Filed herewith 32.1 Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes–Oxley Act of 2002. Furnished herewith 101.INS XBRL Instance Document. The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document 101.SCH Inline XBRL Taxonomy Extension Schema Document. Filed herewith 101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document. Filed herewith 101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document. Filed herewith 101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document. Filed herewith 101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document. Filed herewith (104) Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101). Filed herewith

​

​

​

​

​ ​ ​ ​

​ ​ HELIX ENERGY SOLUTIONS GROUP, INC.

​ ​ ​ (Registrant)

​ ​ ​

Date: October 23, 2025 ​ By: /s/ Owen Kratz

​ ​ ​ Owen Kratz

​ ​ ​ President and Chief Executive Officer

​ ​ ​ (Principal Executive Officer)

​ ​ ​ ​

Date: October 23, 2025 ​ By: /s/ Erik Staffeldt

​ ​ ​ Erik Staffeldt

​ ​ ​ Executive Vice President and

​ ​ ​ Chief Financial Officer

​ ​ ​ (Principal Financial Officer)

​

​

​

​

42