Helix Energy Solutions Group HLX Form 10-Q filing Q3 FY2024

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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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 U.S. generally accepted accounting principles (“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, 2024 are not necessarily indicative of the results that may be expected for the year ending December 31, 2024. Our balance sheet as of December 31, 2023 included herein has been derived from the audited balance sheet as of December 31, 2023 included in our 2023 Annual Report on Form 10-K (our “2023 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 2023 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 November 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, “Improvements to Reportable Segment Disclosures,” which requires entities to disclose, on an annual and interim basis, significant segment expenses that are regularly provided to the chief operating decision maker (the “CODM”) and included within each reported measure of segment profit or loss as well as an amount for other segment items by reportable segment and a description of its composition. ASU No. 2023-07 requires all annual disclosures about a reportable segment’s profit or loss and assets to be provided in interim periods as well. Among other things, this ASU also requires that a public entity disclose the title and position of the CODM and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. ASU No. 2023-07 will be effective on a retrospective basis for annual periods beginning January 1, 2024 and for interim 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 December 2023, the FASB issued 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.

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.

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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 efficiently enhance and extend the lives of existing oil and gas reserves; we also offer an alternative to take over end-of-life reserves in preparation for their abandonment;
• 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 such as 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 Mexico (deepwater and shelf), U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations and our Gulf of Mexico shelf operations are usually subject to seasonal changes in demand, which generally peaks in the summer months and declines 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 monohull 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 Mexico shelf, including offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes Helix Alliance that was acquired in July 2022, which 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 the HP I, the Q4000 and the Q5000 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 Mexico.

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Note 3 — Details of Certain Accounts

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

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

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

(2) Represents the present value of the agreed-upon amounts that we are entitled to receive from Marathon Oil Corporation (“Marathon Oil”) for remaining P&A work to be performed by us on Droshky oil and gas properties we acquired from Marathon Oil in 2019.

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Accrued liabilities consist of the following (in thousands):

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(1) Represents the final amount of the earn-out consideration associated with the acquisition of the Alliance group of companies (collectively “Alliance”) on July 1, 2022, which was paid to the seller of Alliance in cash on April 3, 2024.

(2) Amounts as of December 31, 2023 included $9.0 million of credits towards future services that we granted for the purchase of five P&A systems and other assets. These credits were increased by $2.4 million with a charge to “Other expense, net” during the third quarter 2024 and were fully utilized as of September 30, 2024.

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

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(1) Amount as of December 31, 2023 included $2.6 million of credits offered by us in exchange for the purchase of P&A equipment, which were fully utilized as of September 30, 2024 (see above).

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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):

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Maturities of our operating lease liabilities as of September 30, 2024 are as follows (in thousands):

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Maturities of our operating lease liabilities as of December 31, 2023 are as follows (in thousands):

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

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

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(1) Our operating lease additions during the nine-month period ended September 30, 2024 are primarily related to the charter extensions for the Siem Helix 1, the Siem Helix 2, the Grand Canyon II and the Shelia Bordelon (Note 13). Our operating lease additions during the nine-month period ended September 30, 2023 are primarily related to the vessel charter for the Glomar Wave.

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Note 5 — Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of September 30, 2024 are as follows (in thousands):

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

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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 most recent amendment on August 2, 2024 extended the maturity of the Amended ABL Facility and increased the letter of credit basket size. The Amended ABL Facility provides a $120 million asset-based revolving credit facility, which 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 also permits us to request an increase of the facility by 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, 2024, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity, based on the borrowing base, totaled $74.7 million, net of $31.6 million of letters of credit issued.

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%. We believe the agreements relating to the bonds and the terms and conditions of our obligations to MARAD in respect of the MARAD Debt were typical for U.S. government-guaranteed ship financing transactions when they were entered into, including customary restrictions on incurring additional liens on the Q4000 and trading restrictions with respect to the vessel as well as working capital requirements.

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 retire the Convertible Senior Notes due 2026 (the “2026 Notes”). See details regarding 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.

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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 condensed 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 tentered for conversion is reflected in “Common stock” in the shareholders’ equity section of the accompanying condensed consolidated balance sheet.

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. For the three- and nine-month periods ended September 30, 2023, total interest expense related to the 2026 Notes was $3.7 million and $11.1 million, respectively, with coupon interest expense of $3.4 million and $10.1 million, respectively, and the amortization of debt issuance costs of $0.3 million and $1.0 million, respectively.

2026 Capped Calls

In connection with the 2026 Notes offering, we had entered into capped call transactions (the “2026 Capped Calls”) with three separate counterparties to hedge the dilution risk of the 2026 Notes. Concurrently 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 condensed consolidated balance sheet.

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, 2024, 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 condensed 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 three- and nine-month periods ended September 30, 2023, total interest expense related to the 2023 Notes was $0.3 million and $1.0 million, respectively, primarily from coupon interest expense.

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

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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.

For the three- and nine-month periods ended September 30, 2024, we recognized 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 tax rate for the three-month period ended September 30, 2024 was higher than the U.S. statutory rate primarily due to the jurisdicational mix of earnings, certain non-deductible expenses and non-creditable foreign income taxes. The effective rate for the nine-month period ended September 30, 2024 was higher than the U.S. statutory rate primarily due to the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event and reported in the first quarter. For the three- and nine-month periods ended September 30, 2023, we recognized income tax expense of $8.3 million and $9.6 million, respectively, resulting in effective tax rates of 34.9% and 35.5%, respectively. The effective tax rates for these periods were higher than the U.S. statutory rate primarily due to certain non-deductible expenses and non-creditable foreign income taxes.

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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”). 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 or an average of $10.87 per share.

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 under the Exchange Act, but may also be made through privately negotiated transactions or plans, instructions or contracts established under Rule 10b5-1 under the Exchange Act. 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.

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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. The following table provides information about disaggregated revenue by contract duration (in thousands):

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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):

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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) 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.

Net contract assets were $12.9 million as of September 30, 2024 and $5.8 million as of December 31, 2023 and are reflected in “Other current assets” in the accompanying condensed consolidated balance sheets (Note 3). We had no credit losses on our contract assets for the three- and nine-month periods ended September 30, 2024 and 2023.

Net contract liabilities totaled $25.6 million as of September 30, 2024 and $32.8 million as of December 31, 2023 and are reflected as “Deferred revenue,” a component of “Accrued liabilities” in the accompanying condensed consolidated balance sheets (Note 3). 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. Revenue recognized for the three- and nine-month periods ended September 30, 2023 included $15.2 million and $8.4 million, respectively, that were included in the contract liability balance at the beginning of each period.

Performance Obligations

As of September 30, 2024, $1.6 billion related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $260.6 million, $637.2 million and $712.9 million in 2024, 2025 as well as 2026 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, 2024.

For the three- and nine-month periods ended September 30, 2024 and 2023, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.

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. 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 $42.8 million as of September 30, 2024 and $36.6 million as of December 31, 2023. 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. For the three- and nine-month periods ended September 30, 2023, we recorded $13.7 million and $32.8 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 2023 Form 10-K.

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Note 9 — 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). 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 condensed consolidated statements of operations are as follows (in thousands):

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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):

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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.

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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”). 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. As of September 30, 2024, there were approximately 9.5 million shares of our common stock available for issuance under the 2005 Incentive Plan. During the nine-month period ended September 30, 2024, the following grants of share-based awards were made under the 2005 Incentive Plan:

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(1) Reflects grants to our executive officers.

(2) Reflects grants to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash.

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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. Forfeitures are recognized as they occur. No restricted stock awards have been granted to our executive officers or other employees since 2020. 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. For the three- and nine-month periods ended September 30, 2023, we recognized $0.3 million and $1.0 million, respectively, as share-based compensation related to restricted stock.

Our performance share units (“PSUs”) granted beginning in January 2021 may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee of our Board and have been accounted for as equity awards. Those PSUs consist of two components: (i) 50% based on the performance of our common stock against peer group companies, which component contains a service and a market condition, and (ii) 50% based on cumulative total Free Cash Flow, which component contains a service and a performance condition. 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 a three-year period with the maximum amount of the award being 200% of the original PSU awards and the minimum amount being zero.

For PSUs 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 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 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. For the three- and nine-month periods ended September 30, 2023, $1.2 million and $3.5 million, respectively, were recognized as share-based compensation related to PSUs. In the first quarter 2024, 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, 452,381 PSUs granted in 2021 vested at 181%, representing 818,812 shares of our common stock with a total market value of $8.4 million.

Our currently outstanding RSUs may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee and have been accounted for as liability awards. Liability RSUs 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. For the three- and nine-month periods ended September 30, 2024, $1.5 million and $5.2 million, respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2023, $3.2 million and $5.5 million, respectively, were recognized as compensation cost.

In 2024 and 2023, we granted fixed-value cash awards of $6.1 million and $6.0 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, 2024, $1.4 million and $4.1 million, respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2023, $1.1 million and $3.5 million, respectively, were recognized as compensation cost.

Defined Contribution Plans

We sponsor a defined contribution 401(k) retirement plan (the “401(k) 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, 2024, we made contributions to our defined contribution plans totaling $1.3 million and $4.1 million, respectively. For the three- and nine-month periods ended September 30, 2023, we made contributions to our defined contribution plans totaling $1.0 million and $3.2 million, respectively.

Employee Stock Purchase Plan (“ESPP”)

As of September 30, 2024, 1.0 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 2023 Form 10-K.

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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. All material intercompany transactions between the segments have been eliminated. See Note 2 for more information on our business segments.

We evaluate our performance based on operating income of each reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands):

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

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Segment assets are comprised of all assets attributable to each reportable segment. Corporate and other includes all assets not directly identifiable with our business segments, most notably the majority of our cash and cash equivalents. The following table reflects total assets by reportable segment (in thousands):

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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. 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. The following table describes the changes in our AROs (in thousands):

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Note 13 — Commitments and Contingencies and Other Matters

Commitments

Our Well Intervention segment has long-term charter agreements with Siem Offshore AS for the Siem Helix 1 and Siem Helix 2 vessels, whose terms expire in December 2030 and December 2031, respectively. Our Robotics segment has vessel charters for the Grand Canyon II, the Grand Canyon III, the Shelia Bordelon, the North Sea Enabler and the Glomar Wave. Our time charter agreement for the Grand Canyon II expires in December 2030. Our time charter agreement for the Grand Canyon III expires in May 2028. Our time charter agreement for the Shelia Bordelon in the Gulf of Mexico expires in June 2026. Our time charter agreement for the North Sea Enabler expires in December 2025. We have a three-year charter agreement for the Glomar Wave in the North Sea that expires in 2025.

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 in the normal couse 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, employee-related disputes and subsequently identified legacy issues related to Alliance. We recognize losses for lawsuits 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 covered by insurance, will have a material adverse impact on our consolidated financial statements.

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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):

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(1) Exclusive of any income tax refunds.

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Our capital additions include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions were $0.4 million at September 30, 2024 and $1.1 million at December 31, 2023.

Non-cash financing activities during the nine-month period ended September 30, 2024 included the non-cash settlement of the entire $14.0 million financing liabilities with certain customer receivables. We incurred these financing liabilities as a result of the purchase of P&A equipment in the third quarter 2023 (Note 3).

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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):

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

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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):

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(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.

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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 fleet includes seven purpose-built well intervention vessels and 12 subsea intervention systems. Our robotics equipment includes 39 work-class ROVs, six trenchers and two IROV boulder grabs. We charter robotics support vessels on long-term, short-term, flexible and spot 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.

Industry Influences and Market Environment

Demand for our services is primarily influenced by the condition of the oil and gas and the renewable energy markets and, in particular, the willingness of offshore energy companies to spend on operational activities and capital projects. The performance of our business is largely affected by the prevailing market prices for oil and natural gas, which are impacted by 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.

Oil prices continue to be volatile but have generally remained robust since 2020. Global demand for oil continues to experience growth albeit at slower rates, and we expect the current market conditions will maintain continued customer spending for the industry. However, factors that could threaten the current commodity price environment persist, including regional conflicts, unrest in the Middle East, decisions from members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”), the global economy and the demand for oil and gas in China in particular, various governmental and customer sustainability initiatives and continued shifting of resource allocation to renewable energy. We expect these factors will continue to contribute to commodity price volatility with the potential to temper customer spending for oil and gas projects.

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 assets and services.

We are seeing oil and gas companies continue to invest in long-cycle exploration projects in addition to maintaining and/or increasing production from their existing reserves. As historically production enhancement through well intervention is less expensive per incremental barrel of oil than exploration, we expect oil and gas companies to continue to focus on optimizing production of their existing subsea wells.

Once end-of-life oil and gas wells have depleted their production, we decommission wells and infrastructure in our Well Intervention and Shallow Water Abandonment segments. Our operations service the life cycle of an oil and gas field and provide P&A and decommissioning services at the end of the life of a field as required by governmental regulations. We believe that our well intervention vessels have a competitive advantage in performing these services efficiently and with our suite of shallow water assets and capabilities, we are the only provider of full-field decommissioning services in the Gulf of Mexico shelf. The demand for P&A services should grow over the mid- to long-term as the subsea tree base expands, as government regulations continue to place stronger emphasis on decommissioning aged wells worldwide (including subsea trees as well as mature dry tree wells in the shallow waters of the Gulf of Mexico), as customers look to reduce their decommissioning obligations and as customers shift resources to renewable energy.

We support the energy transition to renewable energy primarily in our Robotics segment through our services in offshore wind farm developments, primarily 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. We expect growth in our renewables services as the energy market transitions to continued offshore renewable energy developments.

Backlog

Our backlog is represented by signed contracts. As of September 30, 2024, our consolidated backlog totaled approximately $1.6 billion, of which $261 million is expected to be performed over the remainder of 2024. Our various contracts with Shell and ExxonMobil globally, our contracts with Trident Energy and Petrobras in Brazil, and our contracts with Talos in the Gulf of Mexico represented approximately 86% of our total backlog as of September 30, 2024. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as services are often added but may sometimes be subtracted; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and 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.

Outlook

For the remainder of 2024 going into 2025, we expect to continue our strong performance driven by increasing demand for our decommissioning services internationally and continued growth in the offshore renewables trenching market. We expect the demand for shallow water decommissioning services in the Gulf of Mexico to remain soft in the near term but should grow over the mid- to long-term.

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 (release) for 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):

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

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

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Comparison of Three Months Ended September 30, 2024 and 2023

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, including our condensed consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars in thousands):

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(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 in the applicable period. Utilization rates of chartered Robotics vessels during the three-month periods ended September 30, 2024 and 2023 each included 92 spot vessel days at near full utilization.

(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):

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Net Revenues. Our consolidated net revenues for the three-month period ended September 30, 2024 decreased by 13% as compared to the same period in 2023, 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 19% for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting a higher number of transit and mobilization days, during which period revenues and costs were deferred and not recognized. The Q4000 incurred approximately 67 days of paid mobilization and transit to West Africa and the Q7000 incurred approximately 38 days of paid mobilization and transit between contracts offshore Australia during the third quarter 2024, whereas both vessels had no transit and mobilization days during the third quarter 2023.

Our Robotics revenues increased by 12% for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting higher vessel, trenching and ROV activities during the third quarter 2024. Chartered vessel activity increased to 532 days during the third quarter 2024 as compared to 506 days during the third quarter 2023. Integrated vessel trenching decreased to 249 days during the third quarter 2024 as compared to 276 days during the third quarter 2023, and the third quarter 2024 included 92 days utilization on the i-Plough trencher on a third-party vessel and 92 days utilization on the IROV boulder grab whereas the i-Plough and IROV were idle during the third quarter 2023. Overall ROV and trencher utilization increased to 77% in the third quarter 2024 from 67% during the third quarter 2023.

Our Shallow Water Abandonment revenues decreased by 18% for the three-month period ended September 30, 2024 as compared to the same period in 2023. The decrease in revenues was due to lower activity levels and an overall softer Gulf of Mexico shelf market in 2024 coupled with the impact of two hurricanes affecting our operations in September 2024, resulting in lower vessel and system utilization during the third quarter 2024 as compared to the third quarter 2023, offset in part by higher pass-through revenues on the P&A systems. Overall vessel utilization was 76% during the third quarter 2024 as compared to 89% during the third quarter 2023. P&A systems and CT systems utilization declined to 607 days of utilization, or 25%, during the third quarter 2024 as compared to 1,531 days of utilization, or 74%, during the third quarter 2023.

Our Production Facilities revenues decreased by 15% for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting lower oil and gas production and prices during the third quarter 2024. Oil and gas production declined during the third quarter 2024 due to an ongoing unplanned shut-in of the Thunder Hawk wells.

Gross Profit (Loss). Our consolidated gross profit decreased by $14.9 million for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting a reduction in profit from our Shallow Water Abandonment business segment, offset in part by an increase in profit from our Robotics segment.

Our Well Intervention segment gross profit remained relatively flat despite lower revenues for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting lower revenues, offset by lower costs due in part to the deferral of transit and mobilization costs during the third quarter 2024.

Our Robotics gross profit increased by $4.0 million for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting higher revenues during the third quarter 2024.

Our Shallow Water Abandonment gross profit decreased by $18.4 million for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting lower revenues, in addition to higher costs due to an increase in lower margin pass-through activities during the third quarter 2024.

Our Production Facilities gross profit decreased by $0.9 million for the three-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting lower revenues, offset in part by lower production costs.

Change in Fair Value of Contingent Consideration. The change in fair value of contingent consideration in the third quarter 2023 reflects an improvement in Helix Alliance’s results during the quarter. We entered into an agreement and set the final earn-out during the fourth quarter 2023, which was paid on April 3, 2024.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $21.1 million for the three-month period ended September 30, 2024 as compared to $27.8 million for the same period in 2023, primarily reflecting lower employee compensation costs.

Net Interest Expense. Our net interest expense totaled $5.7 million for the three-month period ended September 30, 2024 as compared to $4.2 million for the same period in 2023, primarily reflecting higher debt levels and rates on our 2029 Notes in 2024 as compared to our 2026 Notes in 2023, offset in part by higher interest income on our invested cash reserves (Note 5).

Other Expense, Net. Net other expense was minimal for the three-month period ended September 30, 2024 as compared to $8.3 million for the same period in 2023. Net other expense during the third quarter 2024 primarily reflects a $2.4 million increase in the value of incentive credits granted to the seller of P&A equipment acquired in 2023 (Note 3), offset by foreign currency gains due to the strengthening of the British pound. Net other expense during the third quarter 2023 primarily reflects foreign currency losses related to U.S. dollar denominated intercompany debt in our U.K. entities.

Income Tax Provision. Income tax provision was $9.5 million for the three-month period ended September 30, 2024 as compared to $8.3 million for the same period in 2023. The effective tax rates for the three-month periods ended September 30, 2024 and 2023 were 24.4% and 34.9%, respectively. The increase in income tax expense was primarily attributable to higher net income (Note 6).

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Comparison of Nine Months Ended September 30, 2024 and 2023

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, including our condensed consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars in thousands):

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(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 in the applicable period. Utilization rates of chartered Robotics vessels during the nine-month periods ended September 30, 2024 and 2023 included 274 and 218 spot vessel days, respectively, at near full utilization.

(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):

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Net Revenues. Our consolidated net revenues for the nine-month period ended September 30, 2024 increased by 5% as compared to the same period in 2023, reflecting higher revenues in our Well Intervention, Robotics and Production Facilities business segments, offset in part by lower revenues in our Shallow Water Abandonment segment.

Our Well Intervention revenues increased by 19% for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting higher revenues across our well intervention fleet except for the Well Enhancer. Utilization increased on the Q4000 and the Q5000 during the nine-month period ended September 30, 2024 as both vessels underwent their regulatory dry docks in 2023. The Q7000 had higher utilization during the nine-month period ended September 30, 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 the nine-month period ended September 30, 2024 as compared to the nine-month period ended September 30, 2023. The Well Enhancer in the North Sea had lower utilization as compared to the prior year period as the vessel underwent a scheduled dry dock during the first quarter 2024.

Our Robotics revenues increased by 11% for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting higher chartered vessel days and trenching and ROV activities. Chartered vessel activity increased to 1,393 days during the nine-month period ended September 30, 2024 as compared to 1,236 days during the nine-month period ended September 30, 2023, although chartered vessel days in the first quarter 2024 included approximately 64 days of standby utilization at reduced rates. Overall ROV and trencher utilization increased to 70% in the nine-month period ended September 30, 2024 from 60% during the nine-month period ended September 30, 2023 and included 566 days of integrated vessel trenching in 2024 as compared to 536 days in 2023.

Our Shallow Water Abandonment revenues decreased by 30% for the nine-month period ended September 30, 2024 as compared to the same period in 2023. The decrease in revenues was due to lower activity levels and an overall softer Gulf of Mexico shelf market in 2024, resulting in lower vessel and system utilization during the nine-month period ended September 30, 2024 as compared to the nine-month period ended September 30, 2023. Overall vessel utilization was 59% during the nine-month period ended September 30, 2024 as compared to 75% during the same period in 2023. P&A systems and CT systems achieved 1,865 days of utilization, or 26%, during the nine-month period ended September 30, 2024 as compared to 4,362 days of utilization, or 74%, during the nine-month period ended September 30, 2023.

Our Production Facilities revenues increased by 3% for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting higher oil and gas production and lower number of shut-in days.

Gross Profit (Loss). Our consolidated gross profit increased by $9.6 million for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting increased profits from our Well Intervention and Robotics business segments, offset in part by losses from our Shallow Water Abandonment and Production Facilities segments.

Our Well Intervention segment gross profit increased by $54.6 million for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting higher segment revenues and increased activity levels.

Our Robotics gross profit increased by $16.5 million for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting higher revenues and higher profit margin projects during the nine-month period ended September 30, 2024.

Our Shallow Water Abandonment gross profit decreased by $55.0 million for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting lower segment revenues.

Our Production Facilities gross profit decreased by $6.7 million for the nine-month period ended September 30, 2024 as compared to the same period in 2023, primarily reflecting well workover costs of approximately $8.6 million related to the Thunder Hawk wells during the first quarter 2024, offset in part by higher segment revenues.

Change in Fair Value of Contingent Consideration. The change in fair value of contingent consideration in the nine-month period ended September 30, 2023 reflects an improvement in Helix Alliance’s results during the first half 2023. We entered into an agreement and set the final earn-out during the fourth quarter 2023, which was paid on April 3, 2024.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $64.1 million for the nine-month period ended September 30, 2024 as compared to $71.5 million for the same period in 2023, primarily reflecting lower employee compensation costs.

Net Interest Expense. Our net interest expense totaled $17.1 million for the nine-month period ended September 30, 2024 as compared to $12.6 million for the same period in 2023, primarily reflecting higher debt levels and rates on our 2029 Notes in 2024 as compared to our 2026 Notes in 2023, offset in part by higher interest income on our invested cash reserves (Note 5).

Losses Related to Convertible Senior Notes. The $20.9 million loss for the nine-month period ended September 30, 2024 was associated with the retirement of our 2026 Notes (Note 5).

Other Expense, Net. Net other expense was $2.6 million for the nine-month period ended September 30, 2024 as compared to $10.6 million for the same period in 2023. Net other expense during the nine-month period ended September 30, 2024 primarily reflects a $2.4 million increase in the value of incentive credits granted to the seller of P&A equipment acquired in 2023 (Note 3). Net other expense during the nine-month period ended September 30, 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 related U.S. dollar denominated intercompany debt in our U.K. entities.

Income Tax Provision. Income tax provision was $22.5 million for the nine-month period ended September 30, 2024 as compared to $9.6 million for the same period in 2023. The effective tax rates for the nine-month periods ended September 30, 2024 and 2023 were 38.8% and 35.5%, respectively. The increase in effective tax rates was primarily attributable to the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event and reported in the first quarter 2024 (Note 6).

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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):

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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, 2023 included $85.0 million of Alliance earn-out consideration that was paid in cash on April 3, 2024.

Long-Term Debt

Long-term debt in the table above includes our MARAD Debt, the 2026 Notes and the 2029 Notes and excludes current maturities of $9.2 million at September 30, 2024 and $48.3 million at December 31, 2023, and is net of unamortized debt discount and debt issuance costs. 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. Our liquidity at September 30, 2024 included $324.1 million of cash and cash equivalents and $74.7 million of available borrowing capacity under the Amended ABL Facility (Note 5). Our liquidity at December 31, 2023 included $332.2 million of cash and cash equivalents and $99.3 million of available borrowing capacity under the Amended ABL Facility. The reduction in availability on the Amended ABL Facility was attributable to higher letter of credit usage due to the Nigeria project on the Q4000.

In the current market environment, we expect strong ongoing operating performance and cash flows. 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 other than for the issuance of letters of credit. We expect lower levels of availability on the Amended ABL Facility while the Q4000 performs work in Nigeria due to fewer eligible receivables and higher letter of credit usage.

A period of weak industry activity may make it difficult to comply with the covenants and other restrictions in our debt agreements. Our failure to comply with the covenants and other restrictions could lead to an event of default. Decreases in our borrowing base may limit our ability to fully access the Amended ABL Facility.

Cash Flows

The following table provides summary data from our condensed consolidated statements of cash flows (in thousands):

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Operating Activities

The increase in our operating cash flows for the nine-month period ended September 30, 2024 as compared to the same period in 2023 primarily reflects higher operating income, lower regulatory recertification costs for our vessels and systems and lower working capital outflows. Operating cash outflows during the nine-month period ended September 30, 2024 included $58.3 million of the $85.0 million earn-out payment on April 3, 2024, representing the amount in the excess of the $26.7 million initial fair value of earn-out consideration at the Alliance acquisition date. Regulatory recertification spend on our vessels and systems were $29.2 million and $59.2 million, respectively, during the comparable year over year periods.

Investing Activities

Cash flows used in investing activities for the nine-month periods ended September 30, 2024 decreased as compared to the same period in 2023 primarily due to lower capital expenditures.

Financing Activities

Net cash outflows from financing activities for the nine-month period ended September 30, 2024 primarily reflect the final retirement of our 2026 Notes and the earn-out payment. Cash outflows in 2024 included $60.7 million related to the 2026 Notes, $26.7 million of the $85.0 million earn-out payment, $10.2 million in repurchases of our common stock under the 2023 Repurchase Program and the principal repayment of $8.7 million related to the MARAD Debt, offset in part by $4.4 million of cash inflows from the proportionate settlement of the 2026 Capped Calls.

Net cash outflows from financing activities for the nine-month period ended September 30, 2023 primarily reflect $12.0 million in repurchases of our common stock under the 2023 Repurchase Program, the principal repayment of $8.3 million related to the MARAD Debt and $30.4 million related to the 2023 Notes (Note 5).

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, 2024 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, 2024.

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(1) Operating leases include vessel charters and facility and equipment leases. At September 30, 2024, our commitment related to long-term vessel charters totaled approximately $844.4 million, of which $424.1 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, 2024.

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, 2024, 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 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 primarily come from our ongoing operations and existing cash on hand, but may also come from 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 2023 Form 10-K.

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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, 2024, we recorded foreign currency translation gains of $35.3 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, 2024, we recorded net foreign currency gains (losses) of $2.4 million and $(0.2) million, respectively, primarily related to U.S. dollar denominated intercompany debt in our U.K. entities.

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 our 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 2023 Form 10-K for a list of factors affecting oil and gas prices.

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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, 2024. 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, 2024 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, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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.

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Item 1A. Risk Factors

There have been no material changes during the period ended September 30, 2024 in our “Risk Factors” as discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2023.

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

Issuer Purchases of Equity Securities

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(1) Includes shares repurchased in open-market transactions pursuant to the 2023 Repurchase Program and shares forfeited in satisfaction of tax obligations upon vesting of share-based awards under our existing long-term incentive plans.

(2) Represents shares repurchased under the 2023 Repurchase Program.

(3) See Note 7 to this Quarterly Report on Form 10-Q and Note 10 to our 2023 Annual Report on Form 10-K for additional information regarding our share repurchase programs.

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Item 3. Defaults Upon Senior Securities

None.

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Item 4. Mine Safety Disclosures

Not applicable.

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Item 5. Other Information

(c) During the three-month period ended September 30, 2024, 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.

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Item 6. Exhibits

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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) 4.1 Amendment No. 4, dated as of August 2, 2024, to Loan, Security and Guaranty Agreement dated as of September 30, 2021, among Helix Energy Solutions Group, Inc., Helix Well Ops Inc., Helix Robotics Solutions, Inc., Deepwater Abandonment Alternatives, Inc., Alliance Offshore, L.L.C., Triton Diving Services, LLC, Alliance Energy Services, LLC, Helix Well Ops (U.K.) Limited and Helix Robotics Solutions Limited as borrowers, the guarantors party thereto, the lenders party thereto, and Bank of America, N.A., as agent and security trustee for the lenders, as previously amended. Exhibit 4.1 to the Current Report on Form 8-K filed on August 2, 2024 (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

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​ ​ HELIX ENERGY SOLUTIONS GROUP, INC.

​ ​ ​ (Registrant)

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Date: October 24, 2024 ​ By: /s/ Owen Kratz

​ ​ ​ Owen Kratz

​ ​ ​ President and Chief Executive Officer

​ ​ ​ (Principal Executive Officer)

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Date: October 24, 2024 ​ By: /s/ Erik Staffeldt

​ ​ ​ Erik Staffeldt

​ ​ ​ Executive Vice President and

​ ​ ​ Chief Financial Officer

​ ​ ​ (Principal Financial Officer)

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