HELIX ENERGY SOLUTIONS GROUP INC (HLX)

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

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

EXECUTIVE SUMMARY

Our Business

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention, robotics and decommissioning operations. We operate through our four business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. 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.

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 level of spending of offshore energy companies 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 during 2024. Global demand for oil continues to experience growth albeit at slower rates, and although we believe the current oil and gas pricing warrants continued customer spending for the industry, higher levels of economic and industry uncertainty may temper such customer spending. Factors that could threaten the current commodity price environment persist, including regional conflicts, governmental regulations, geopolitical instability and uncertainty, unrest in the Middle East, OPEC+ decisions, 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.

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In the current market environment, we continue to see oil and gas companies invest in long-cycle offshore exploration projects in addition to maintain and/or increase production from their existing reserves. As 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 in addition to their exploration activities.

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 capable of providing all facets of decommissioning services in the U.S. Gulf Coast 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 U.S. Gulf Coast), 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 and/or other governmental regulations supporting or restricting renewable energy developments, for instance, the 2025 Wind Energy Ban. We expect growth in our renewables services as the global energy market continues offshore renewable energy developments.

Business Activity Summary

During 2024, our operating results improved significantly as we continued to execute on our energy transition strategy with significant improvements in utilization and rates in our Well Intervention and Robotics segments. During 2024, we also executed significant new contracts on the strength of the market and the demand for our services. These contracts added significant backlog and will provide strong utilization for our vessels and equipment over multiple years. Notable contracts include:

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During 2024, we extended the charters on the Siem Helix 1, the Siem Helix 2, the Grand Canyon II and the Shelia Bordelon. We also entered in or extended various facility leases across all regions.

We completed the redemption of the Convertible Senior Notes due 2026 (the “2026 Notes”) during the first quarter 2024. In August 2024, we extended the maturity of the Amended ABL Facility to August 2029 and increased the letter of credit basket size in order to facilitate increased bonding needs on the Q4000 Nigeria campaign and various windfarm projects. We maintain our capital allocation policy of maintaining low levels of Net Debt, maintaining our existing assets, investing in targeted acquisitions that complement and further our strategy, and using Free Cash Flow to return cash to shareholders through share repurchases (See “Results of Operations — Non-GAAP Financial Measures” below for definitions of Net Debt and Free Cash Flow).

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Backlog

Our backlog is represented by signed contracts. As of December 31, 2024, our consolidated backlog totaled $1.4 billion, of which $681 million is expected to be performed in 2025. As of December 31, 2024, our various contracts with Shell and ExxonMobil globally, our contracts with Trident Energy and Petrobras in Brazil, our contracts with Talos in the U.S. Gulf Coast represented approximately 90% of our total backlog. As of December 31, 2023, our consolidated backlog totaled $850 million. 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

In 2025, we expect to continue our strong performance, supported by new contracting in 2024 at improved rates that increased backlog and 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 U.S. Gulf Coast to improve as oil and gas properties revert to former owners due to bankruptcies, who are expected to address their decommissioning obligations.

RESULTS OF OPERATIONS

Non-GAAP Financial Measures

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

We evaluate our operating performance and financial condition based 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, gains and losses on equity investments, 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 consolidated financial statements unless otherwise noted.

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The reconciliation of our net income (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 Years Ended December 31, 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 consolidated financial statements, including our consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars 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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Net Revenues. Our consolidated net revenues increased by 5% in 2024 as compared to 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 17% in 2024 as compared to 2023, primarily reflecting higher overall utilization and rates. Utilization increased on the Q4000 and the Q5000 during 2024 as both vessels underwent their regulatory dry docks in 2023. The Q7000 had higher utilization and higher integrated project rates during 2024 as compared to 2023. The Seawell‘s contract in the western Mediterranean, which completed in June 2024, has provided higher rates and utilization during 2024 as compared to 2023. The Well Enhancer in the North Sea had lower utilization as compared to the prior year as the vessel underwent a scheduled dry dock during the first quarter 2024 and both vessels saw a fourth quarter seasonal slowdown in 2024 whereas the vessels were nearly fully utilized in 2023. Our North Sea revenues also included a contract cancellation fee of approximately $14 million related to work that had been scheduled for 2025. The Siem Helix 1 had higher revenues during 2024 as compared to 2023 due to Trident contract extensions with higher rates. The Siem Helix 2 had lower utilization during 2024 as the vessel commenced its unpaid vessel acceptance period at the end of December 2024 on its new contract with Petrobras.

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

Our Shallow Water Abandonment revenues in 2024 decreased by 32% in 2024 as compared to 2023. The decrease in revenues was due to lower activity levels and an overall softer U.S. Gulf Coast shelf market in 2024, resulting in lower vessel and system utilization during 2024 as compared to 2023. Overall vessel utilization was 60% during 2024 as compared to 74% during 2023. P&A systems and CT systems achieved 2,281 days of utilization, or 24%, during 2024 as compared to 5,748 days of utilization, or 70%, during 2023.

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

Gross Profit (Loss). Our consolidated 2024 gross profit increased by $19.2 million as compared to 2023, primarily reflecting increased profits from our Well Intervention, Robotics and Production Facilities business segments, offset in part by losses from our Shallow Water Abandonment segment.

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

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

Our Shallow Water Abandonment gross loss was $0.8 million in 2024 as compared to a gross profit of $71.3 million in 2023, primarily reflecting lower segment revenues without a commensurate cost reduction.

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

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

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $91.7 million in 2024 as compared to $94.4 million in 2023, primarily reflecting a net decrease in compensation related costs offset partially by an increase in other facilities and professional fees in 2024.

Net Interest Expense. Our net interest expense totaled $22.6 million in 2024 as compared to $17.3 million in 2023, primarily reflecting higher debt levels and rates on our $300 million Senior Notes due 2029 (the “2029 Notes”) in 2024 as compared to our 2026 Notes in 2023, offset in part by higher interest income on our invested cash (Note 7).

Losses Related to Convertible Senior Notes. The losses during 2024 and 2023 were primarily associated with the retirement of our 2026 Notes (Note 7).

Other Expense, Net. Net other expense was $3.9 million in 2024 as compared to $3.6 million in 2023. Net other expense during 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 4) and foreign currency losses due to the weakening of the British pound and Brazilian real in 2024. Net other expense during 2023 primarily reflects foreign currency losses related to the devaluation of the Nigerian naira on our naira cash holdings, offset in part by foreign currency gains due to the strengthening of the British pound in 2023.

Income Tax Provision. Income tax provision was $26.4 million for 2024 as compared to $18.4 million for 2023. The effective tax rates for 2024 and 2023 were 32.2% and 244.2%, respectively. These variances were primarily attributable to the increase in income before taxes as well as the earnings mix between our higher and lower tax rate jurisdictions.

Comparison of Years Ended December 31, 2023 and 2022

Various financial and operational highlights for the years ended December 31, 2023 and 2022 were previously presented in our 2023 Annual Report on Form 10-K.

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 earnout consideration that was paid in cash on April 3, 2024.

Long-Term Debt

Long-term debt in the table above, presented net of unamortized debt discount and debt issuance costs, includes our MARAD Debt, the 2026 Notes and the 2029 Notes and excludes current maturities of $9.2 million and $48.3 million, respectively, at December 31, 2024 and 2023. For information relating to our long-term debt, see Note 7 to our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report.

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Liquidity

We define liquidity as cash and cash equivalents plus available capacity under our credit facility, but excluding cash pledged as collateral toward the Amended ABL Facility. Our liquidity at December 31, 2024 included $368.0 million of cash and cash equivalents and $66.6 million of available borrowing capacity under the Amended ABL Facility (Note 7) and excluded $5.0 million of pledged cash. 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 facility at December 31,2024 was attributable to higher letter of credit usage in order to support 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. Although 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, we currently do not anticipate borrowing under the Amended ABL Facility and expect to only use the facility for the issuance of letters of credit.

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 consolidated statements of cash flows (in thousands):

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Operating Activities

The increase in our operating cash flows for 2024 as compared to 2023 primarily reflects higher operating income, lower regulatory recertification costs for our vessels and systems and working capital inflows. Operating cash outflows during 2024 included net interest expense and taxes paid of $25.4 million and $14.1 million, respectively. Operating cash outflows during 2024 also included $58.3 million of the $85.0 million earnout payment on April 3, 2024, representing the amount in the excess of the $26.7 million initial fair value of earnout consideration at the Alliance acquisition date. Regulatory recertification spend on our vessels and systems amounted to $35.4 million and $62.5 million, respectively, during the comparable year over year periods.

Investing Activities

Cash flows used in investing activities for 2024 increased as compared to 2023 primarily due to higher capital expenditures with increased activity in our Robotics segment.

Financing Activities

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

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

Material Cash Requirements

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

Long-term debt and other contractual commitments

The following table summarizes (in thousands) the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for property and equipment and operating lease obligations, as of December 31, 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 December 31, 2024.

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Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 15). Those obligations, which are presented on a discounted basis on the consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk Field oil and gas properties and $37.1 million (undiscounted) for Droshky oil and gas properties as of December 31, 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 Corporation as certain decommissioning obligations associated with Droshky oil and gas properties are fulfilled.

Regulatory certification 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.

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CRITICAL ACCOUNTING ESTIMATES AND POLICIES

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

Property and Equipment

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

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

New Accounting Standards

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

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

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

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 full-field decommissioning operations. We operate through our four business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. 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.

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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, which has been an area of growth for us in recent years, is affected by commodity prices as well as governmental regulations and political forces globally.

Oil prices came down from their highs in 2022 but have remained robust during 2023. Global demand for oil continues to experience growth, and we expect the current market conditions will maintain continued customer spending for the industry. Despite the current commodity price environment, uncertainties to commodity price stability persist, including regional conflicts, unrest in the Middle East, OPEC+ decisions, 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.

We support the energy transition to renewable energy 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 renewable energy developments.

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 we have a competitive advantage in performing these services efficiently. The demand for P&A services should grow 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), and as customers shift resources to renewable energy.

Business Activity Summary

During 2023, we continued to reap the benefits of our energy transition strategy with significant improvements in our results as compared to 2022. Utilization and rates improved across all of our operating segments in 2023, benefitting from a strong oil and gas market, continued customer demand for our renewables offerings and robust decommissioning demand across the globe.

We made significant improvements in our balance sheet in 2023, extending the maturity of our debt to 2029, removing the dilution overhang associated with 22.9 million shares underlying the Convertible Senior Notes due 2026 (the “2026 Notes”) repurchased in December 2023, and simplifying our capital structure. We maintain our capital allocation policy of maintaining low levels of Net Debt, investing in targeted acquisitions that complement and further our strategy, and using Free Cash Flow to return cash to shareholders through share repurchases (See “Results of Operations — Non-GAAP Financial Measures” below for definitions of Net Debt and Free Cash Flow).

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We also executed a number of transactions during 2023 that demonstrate our commitment to our strategy and outlook for the markets we serve.

During 2023, we extended the charters on two of our robotics vessels in support of our trenching and site clearance operations. In January 2023, we entered into a three-year charter agreement for the Glomar Wave in the North Sea with options to extend. In July 2023, we entered into a new agreement to extend the Horizon Enabler charter until December 2025, with further options to extend.

In September 2023, we acquired assets primarily consisting of five operable P&A systems to be used in our shallow water decommissioning operations in the Gulf of Mexico.

In November 2023, we extended the agreement for the HP 1 for one year until at least June 1, 2025.

Outlook

In 2024, despite a backdrop of a somewhat uncertain macro environment globally, we expect to experience another strong year of performance driven by increasing demand for our decommissioning services internationally and continued growth in the offshore renewables trenching market. The Gulf of Mexico shallow water decommissioning demands are expected to experience volatility as customers balance their spending between decommissioning obligations and production needs.

Backlog

Our backlog is represented by signed contracts. As of December 31, 2023, our consolidated backlog totaled $850 million, of which $700 million is expected to be performed in 2024. As of December 31, 2023, our various contracts with Shell globally, our contracts with Trident Energy and Petrobras in Brazil, our contracts with Repsol globally, and our agreement for the HP I in the Gulf of Mexico represented approximately 55% of our total backlog. As of December 31, 2022, our consolidated backlog totaled $847 million. 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.

RESULTS OF OPERATIONS

Non-GAAP Financial Measures

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

We evaluate our operating performance and financial condition based 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.

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We define EBITDA as earnings before income taxes, net interest expense, gains and losses on equity investments, 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 on extinguishment of long-term debt, 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 and restricted cash. In the following reconciliations, we provide amounts as reflected in the 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 Years Ended December 31, 2023 and 2022

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 consolidated financial statements, including our consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars 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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Net Revenues. Our consolidated net revenues increased by 48% in 2023 as compared to 2022, reflecting the addition of Shallow Water Abandonment segment in the third quarter 2022 and higher revenues from all of our segments.

Our Well Intervention revenues increased by 40% in 2023 as compared to 2022, primarily reflecting higher vessel utilization and rates in Brazil and the North Sea and higher rates in the Gulf of Mexico. Revenues in Brazil increased primarily due to both the Siem Helix 1 and the Siem Helix 2 working a full year on their long-term contracts with improved rates as compared to 2022. Revenues in the North Sea and Gulf of Mexico both benefitted from improved spot rates in 2023 as compared to 2022. Revenues on the Q7000 were also higher, despite the vessel incurring a higher number of transit and docking days in 2023 as compared to 2022, as the vessel’s operations in New Zealand were on an integrated project with higher project revenues and costs. The increase in revenues was offset in part by lower utilization in the Gulf of Mexico due to a higher number of regulatory docking days during 2023 as compared to 2022.

Our Robotics revenues increased by 34% in 2023 as compared to 2022, primarily reflecting higher utilization and rates on vessels, ROVs and trenchers. Chartered vessel days increased to 1,699 days during 2023 as compared to 1,401 days during 2022. Integrated vessel trenching days increased to 807 days in 2023 as compared to 483 days in 2022. ROV and trencher utilization increased to 62% in 2023 from 53% in 2022.

Our Shallow Water Abandonment revenues in 2023 reflect a full year of revenue generated by Helix Alliance with 74% utilization across vessels and 5,748 days, or 70%, of utilization across P&A systems and CT systems. Our Shallow Water Abandonment revenues in 2022 reflect six months of revenue generated by Helix Alliance since July 1, 2022 (Note 3) with 73% utilization across vessels and 2,324 days, or 62%, of utilization across P&A systems and CT systems.

Our Production Facilities revenues increased by 7% in 2023 as compared to 2022, primarily reflecting higher oil and gas production volumes, offset in part by lower oil and natural gas prices during 2023 as compared to 2022.

Gross Profit (Loss). Our consolidated 2023 gross profit increased by $149.7 million as compared to 2022, primarily reflecting increases in our Well Intervention, Robotics and Shallow Water Abandonment segments in 2023, offset in part by lower profitability in our Production Facilities segment.

Our Well Intervention gross profit was $47.2 million in 2023 as compared to a gross loss of $40.1 million in 2022, primarily reflecting higher revenues in 2023.

Our Robotics gross profit increased by $23.1 million in 2023 as compared to 2022, primarily reflecting higher revenues in 2023 due to increased activities.

Our Shallow Water Abandonment gross profit increased by $47.3 million in 2023 as compared to 2022, primarily reflecting full year of operating results from Helix Alliance in 2023 as compared to six months of operating results from Helix Alliance following its acquisition on July 1, 2022.

Our Production Facilities gross profit decreased by $7.2 million in 2023 as compared to 2022, primarily reflecting higher oil and gas production costs and well maintenance costs, offset in part by revenue increases during 2023.

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Acquisition and Integration Costs. Our acquisition and integration costs decreased by $2.1 million in 2023 as compared to 2022, reflecting lower spend during the later stages of the Alliance integration process.

Change in Fair Value of Contingent Consideration. The change in fair value of contingent consideration related to the Alliance acquisition reflects an increase in the value of the earn-out consideration expected to be paid in cash in April 2024 (Notes 3 and 19).

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $94.4 million in 2023 as compared to $76.8 million in 2022, primarily reflecting higher employee incentive and share-based compensation costs and the addition of Helix Alliance.

Equity in Earnings of Investment. Equity in earnings of investment of $8.3 million in 2022 primarily reflects the gain on the sale of the “Independence Hub” platform (Note 2).

Net Interest Expense. Our net interest expense totaled $17.3 million in 2023 as compared to $19.0 million in 2022, primarily reflecting higher interest income on our invested cash reserves and the repayment of certain indebtedness, offset in part by interest expense on our $300 million Senior Notes due 2029 (the “2029 Notes”) during the fourth quarter 2023 (Note 7).

Loss on Extinguishment of Long-term Debt. The $37.3 million loss on extinguishment of long-term debt in 2023 was primarily associated with $38.6 million inducement charges incurred from the repurchase of $159.8 million principal amount of the 2026 Notes during the fourth quarter 2023 (Note 7), offset in part by changes in fair value of the associated 2026 Capped Calls until settlement (Note 9).

Other Expense, Net. Net other expense was $3.6 million in 2023, primarily reflecting losses from the devaluation of our Nigerian naira holdings and conversion of naira into U.S. dollars during 2023, offset in part by foreign currency gains due to the strengthening of the British pound in 2023. Net other expense was $23.3 million in 2022, primarily reflecting foreign currency losses due to the weakening of the British pound in 2022.

Income Tax Provision. Income tax provision was $18.4 million for 2023 as compared to $12.6 million for 2022. The effective tax rates for 2023 and 2022 were 244.2% and (16.8)%, respectively. These variances were primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions, non-deductible losses on the extinguishment of long-term debt as well as losses for which no financial statement benefits have been recognized (Note 8).

Comparison of Years Ended December 31, 2022 and 2021

Various financial and operational highlights for the years ended December 31, 2022 and 2021 were previously presented in our 2022 Annual Report on Form 10-K.

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 and restricted cash, current maturities of long-term debt and current operating lease liabilities. Net working capital measures short-term liquidity and is important for predicting cash flow and debt requirements.

Long-Term Debt

Long-term debt in the table above is net of unamortized debt discount and debt issuance costs and excludes current maturities of $48.3 million and $38.2 million, respectively, at December 31, 2023 and 2022. For information relating to our long-term debt, see Note 7 to our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report.

Liquidity

We define liquidity as cash and cash equivalents, excluding restricted cash, plus available capacity under our credit facility. 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 ABL Facility (Note 7). In December 2023, we issued $300.0 million of the 2029 Notes with proceeds of approximately $291.1 million, net of debt discount and issuance costs. We used a portion of the proceeds, as well as 1.5 million shares of our common stock, to repurchase $159.8 million aggregate principal amount of the 2026 Notes for approximately $229.7 million, and we unwound a proportionate amount of the associated 2026 Capped Calls for approximately $15.6 million. In January 2024, we issued a redemption notice for the remaining $40.0 million aggregate principal amount of the 2026 Notes to be settled March 20, 2024. Investors are permitted to convert their notes, and we will settle all conversions and/or redemptions in cash at amounts that we expect will exceed the 2026 Notes’ current carrying values. Our liquidity at December 31, 2022 included $186.6 million of cash and cash equivalents and $98.1 million of available borrowing capacity under the ABL Facility and excluded $2.5 million of restricted cash. The increase in cash and cash equivalents, excluding the impact of our debt refinancing activities, was primarily attributable to strong operating cash flows during 2023.

Following the slowdown triggered by the COVID-19 pandemic and beginning 2022, we have seen an improvement in the markets we serve as evidenced by increases in our revenues and gross profit. We expect strong ongoing operating performance, increases in our cash position, high availability on the Amended ABL Facility and reductions in Net Debt (See “Results of Operations — Non-GAAP Financial Measures” for the definition of Net Debt). 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 service our debt and other obligations over at least the next 12 months.

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. We currently do not anticipate borrowing under the Amended ABL Facility other than for the issuance of letters of credit.

In February 2023, we announced that our Board authorized a new share repurchase program under which we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. 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 expected to be cancelled. During 2023, pursuant to the 2023 Repurchase Program we repurchased a total of 1,584,045 shares of our common stock for approximately $12.0 million.

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Cash Flows

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

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Operating Activities

The increase in our operating cash flows for 2023 as compared to 2022 primarily reflects higher earnings, offset in part by higher regulatory recertification costs for our vessels and systems and higher working capital outflows. Regulatory recertification spend on our vessels and systems amounted to $62.5 million and $35.1 million, respectively, during the comparable year over year periods.

Investing Activities

Cash flows used in investing activities for 2023 decreased as compared to 2022. The decrease is primarily due to the $112.6 million in net cash paid to acquire Alliance (Note 3) during 2022 as well as lower capital expenditures during 2023.

Financing Activities

Net cash inflows from financing activities for 2023 primarily reflect proceeds from the issuance of $300.0 million 2029 Notes and the proportionate settlement of the 2026 Capped Calls, offset in part by cash outflows of $230.7 million related to the 2026 Notes, $30.4 million related to Convertible Senior Notes due 2023, the principal repayment of $8.3 million related to the MARAD Debt and $12.0 million in repurchases of our common stock under the 2023 Repurchase Program. Net cash outflows from financing activities for 2022 primarily reflect the repayment of $7.9 million related to the MARAD Debt and $35.0 million related to Convertible Senior Notes due 2022.

Material Cash Requirements

Our material cash requirements include our obligations to repay our long-term debt, including additional funds needed to settle the conversion and/or redemption of the remaining 2026 Notes, satisfy other contractual cash commitments and fund other obligations, including the payment of the earn-out consideration to the seller in the Alliance transaction.

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, operating lease obligations and Alliance earn-out consideration, as of December 31, 2023 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 December 31, 2023.

We acquired Helix Alliance in July 2022 for total consideration that included cash plus an earn-out to the extent Helix Alliance’s financial results exceed certain thresholds in 2022 and 2023 (Note 3). During the fourth quarter 2023, we finalized the calculation and agreed with the seller in the Alliance transaction on an $85.0 million earn-out expected to be paid in cash in April 2024. Accordingly, we reported $85.0 million of Alliance earn-out consideration in “Accrued liabilities” in the consolidated balance sheet as of December 31, 2023 (Note 4).

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The 2026 Notes have certain early conversion and redemption features that could affect the timing and amount of any cash requirements. On December 29, 2023, we announced that the 2026 Notes are convertible at the option of the holders from January 1, 2024 through March 31, 2024 as a result of the closing price of our common stock exceeding 130% of the conversion price for at least 20 days of the last 30 consecutive trading days in the quarter ended December 31, 2023. The 2026 Notes are also redeemable by us when the closing price of our common stock exceeds 130% of the conversion price for at least 20 days of the last 30 consecutive trading days in a quarter.

On January 16, 2024, we issued a notice for the redemption of all remaining 2026 Notes on March 20, 2024 to be settled in cash (Note 7). Holders can convert their 2026 Notes prior to the redemption date and any conversion thereof will be settled in cash. The ultimate settlement amount of the 2026 Notes will depend on various factors, including the number of notes converted and the volume weighted average trading price of our common stock during the measurement period preceding their settlement. The fair value of the 2026 Notes as of December 31, 2023 was approximately $64.1 million (Note 19).

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Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 15). Those obligations, which are presented on a discounted basis on the consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk Field oil and gas properties and $37.1 million (undiscounted) for Droshky oil and gas properties as of December 31, 2023, 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 certification 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 $3.0 million to $15.0 million per Well Intervention vessel and $0.5 million to $5.0 million per system or Helix Alliance asset.

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.

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CRITICAL ACCOUNTING ESTIMATES AND POLICIES

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

Business Acquisition

We account for business acquisitions under the acquisition method of accounting. We determine the purchase price to be the cash and other assets transferred to the seller and the value of any liabilities, such as contingent consideration or other seller financing incurred. The estimate of any contingent consideration and its fair value on the acquisition date and subsequent reporting periods is a significant estimate.

We allocate the purchase price of businesses we acquire to identifiable assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill. The allocation of the purchase price requires management to make significant estimates in determining the fair values of assets acquired and liabilities assumed. These estimates and assumptions may include, but are not limited to, the cash flows that an asset is expected to generate in the future, the appropriate weighted average cost of capital, and the estimated useful lives. Changes in these assumptions could affect the carrying value of these assets, the amount of future depreciation or amortization and any possible impairment charges.

We use available and relevant information to estimate fair values (including quoted market prices when available) and the nominal value of acquired assets and assumed liabilities as well as deploy various valuation techniques such as discounted cash flows. We may engage third party specialists to assist in the fair value determination of acquired assets and liabilities, including identifiable long-lived assets and identifiable intangible assets, as well as any contingent earn-out consideration to be paid to the seller if certain future conditions are met. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, the estimated fair value of contingent earn-out considerations, as well as the remaining useful lives of these assets, could materially impact our financial condition or results of operations. See Note 3 to our consolidated financial statements for further discussion on our acquisition of Alliance during 2022.

Property and Equipment

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

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

New Accounting Standards

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

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

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

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 full-field decommissioning operations. Our services are centered on a three-legged business model well positioned for a global energy transition by maximizing production of remaining oil and gas reserves, supporting renewable energy developments and decommissioning end-of-life oil and gas fields. Our well intervention fleet includes seven purpose-built well intervention vessels and 12 intervention systems. Our robotics equipment includes 41 work-class ROVs, seven trenchers and the IROV boulder grab. We charter robotics support vessels on long-term, short-term, flexible and spot bases to facilitate our ROV and trenching operations. Our Production Facilities segment includes the HP I, the HFRS and our ownership of oil and gas properties including the recently acquired interest in the Thunder Hawk Field. On July 1, 2022, we completed our acquisition of Alliance and formed a new reporting segment in the third quarter 2022 comprised of the Helix Alliance business. Our new Shallow Water Abandonment segment includes 10 liftboats, six OSVs, three DSVs, one 1760T heavy lift derrick barge, one crew boat, 15 marketable P&A systems (with the ability to scale up to 20 systems) and six coiled tubing systems.

Economic Outlook and Industry Influences

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, including:

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Oil and gas prices reached ten-year highs during the middle of 2022 and experienced moderate declines and volatility during the remainder of 2022. Global demand for oil and gas continues to recover as supply has been disrupted by regional conflicts. We expect oil and gas prices will remain robust for the near term, which should lead to higher customer spending for the industry. However, despite the current strong commodity price environment, there remain headwinds to commodity price stability, including those regional conflicts, high inflation and in particular governments’ and central banks’ efforts to taper economic growth, COVID-related uncertainties, various governmental and customer ESG initiatives and continued shifting of resource allocation to renewable energy. We expect these factors will continue to contribute to commodity price volatility and may temper customer spending for oil and gas projects.

We maximize production of remaining 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.

Over the near-term, with the current high commodity price environment we expect oil and gas companies to invest in new long-cycle exploration projects in addition to maintaining and/or increasing production from their remaining reserves. As historically production enhancement through well intervention is less expensive per incremental barrel of oil than exploration, we continue to expect oil and gas companies to increasingly focus on optimizing production of their existing subsea wells. We expect the fundamentals for our business will remain favorable over the longer term as the need to prolong well life in oil and gas production is the primary driver of demand for our production enhancement services. This expectation is based on multiple factors, including (1) maintaining the optimal production of a well through enhancement is fundamental to maximizing the overall economics of well production; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling; and (3) extending the production of offshore wells not only maximizes a well’s production economics but also enables the financial benefit of delaying P&A costs, which can be substantial.

We support the energy transition to renewables 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 production and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water, and government subsidies for renewable energy projects. We expect growth in our renewables services as the energy market transitions to continued renewable energy developments.

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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. As the subsea tree base expands and ages and customers shift resources to renewable energy, the demand for P&A services should persist. Our operations service the life cycle of an oil and gas field and provide P&A services at the end of the life of a field as required by governmental regulations, and we believe that we have a competitive advantage in performing these services efficiently.

We are subject to the effects of changing prices. Inflation rates have been relatively low and stable over the previous three decades; however, inflation rates have risen significantly since 2021 due in part to supply chain disruptions and the effects of the COVID-19 pandemic. Although we may be able to mitigate our exposure to price increases through the rates we charge, we bear the costs of operating and maintaining our assets, including labor and material costs as well as recertification and dry dock costs. While the cost outlook is not certain, we believe that we can manage these inflationary pressures by introducing appropriate sales price adjustments and by actively pursuing internal cost management efforts. However, competitive market pressures may affect our ability to recoup these price increases through the rates we charge, which may result in reductions in our operating margins and cash flows in the future. The recent high inflation rates seen in various major economies have caused concerns for central banks’ tightening of monetary policies. These concerns have contributed to stock market volatility as well as higher interest rates, which, combined with ongoing regional conflicts and unrest and continued COVID-related disruptions throughout the globe, could provide a strained macroeconomic outlook and in turn affect energy markets.

The COVID-19 pandemic resulted in new market dynamics and challenges to us, including contributing significantly to oil and gas price volatility and increased costs related to our supply chain, logistics and human capital resources. While the COVID-19 pandemic has significantly receded since its peak, the full impact of the COVID-19 pandemic, including the duration of its impact on economic activity, remains unknown, we expect such impact could escalate in the future, including affecting our customers’ willingness to commit to future spending, limiting access to and use of capital, disrupting supply chains and increasing costs, and negatively affecting human capital resources.

Business Activity Summary

As the oil and gas market has improved due to the post-COVID-19 recovery and the impact of sovereign energy security and independence, and as the energy market continues its migration of energy transition towards renewables, we executed a number of transactions during 2022 that demonstrate our commitment to our strategy and outlook for the markets we serve.

In February 2022, we entered into a two-year P&A contract with Trident for the Siem Helix 1, which commenced in December 2022. In September 2022, our contract with Petrobras for the Siem Helix 2 was extended for two years until December 2024. In October 2022, we entered into an intervention and decommissioning contract with Shell Brasil Petroleo LTDA for the Q7000, which is scheduled to commence in 2024. In November 2022, we extended the agreement for the HP 1 for one year until at least June 1, 2024.

In January 2022, we executed a time charter agreement for the Horizon Enabler in the North Sea with minimum firm periods in 2022 and 2023. In February 2022, we executed a time charter agreement for the Shelia Bordelon in the Gulf of Mexico until June 2024. In February 2022, the charter agreements for the Siem Helix 1 and the Siem Helix 2 were extended to February 2025 and February 2027, respectively. In August 2022, the time charter agreements for the Grand Canyon II and Grand Canyon III vessels were extended to December 2027 and May 2028, respectively.

In July 2022, we completed the acquisition of Alliance, expanding our services to the shallow waters predominantly in the Gulf of Mexico shelf.

In August 2022, we acquired from MP GOM a 62.5% interest in the Thunder Hawk Field, which is comprised of mature wells located in the Gulf of Mexico.

In December 2022, we acquired a 50% interest in two deepwater IRSs that can be used on our vessels, serve as backups, or be deployed on a stand-alone basis to our customers around the world.

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We have continued to expand our services and offerings into the offshore renewable energy sector. During 2022, we performed site clearance and/or ROV support work on multiple renewable energy projects in the Asia Pacific and North Sea regions and offshore U.S. East Coast. In November 2022, we acquired two jet trenchers and one plough trencher, which will enable us to expand our renewables trenching services into new markets.

Backlog

We define backlog as firm commitments represented by signed contracts. As of December 31, 2022, our consolidated backlog totaled $847 million, of which $533 million is expected to be performed in 2023. As of December 31, 2022, our contracts with Shell in the Gulf of Mexico, U.K. and Brazil, our contracts with Trident and Petrobras in Brazil and our agreement for the HP I in the Gulf of Mexico represented approximately 69% of our total backlog. As of December 31, 2021, our consolidated backlog totaled $348 million. 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.

RESULTS OF OPERATIONS

Non-GAAP Financial Measures

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

We measure our operating performance 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 income or cash flow data prepared in accordance with GAAP.

We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets and non-cash gains and losses on equity investments are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets, acquisition and integration costs, the change in fair value of contingent consideration and the general provision (release) for current expected credit losses, if any. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments, which are excluded from EBITDA as a component of net other income or expense. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. Net Debt is calculated as long-term debt including current maturities of long-term debt less cash and cash equivalents and restricted cash. In the following reconciliation, we provide amounts as reflected in the condensed consolidated financial statements unless otherwise noted.

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The reconciliation of our net income (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 Years Ended December 31, 2022 and 2021

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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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 increased by 29% in 2022 as compared to 2021, reflecting the addition of Shallow Water Abandonment segment in the third quarter 2022 and higher revenues from all of our segments.

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Our Well Intervention revenues increased by 1% in 2022 as compared to 2021, primarily reflecting higher vessel utilization and rates in the Gulf of Mexico and the North Sea as well as higher utilization on the Siem Helix 1 during 2022, offset in part by lower utilization on the Q7000 due to its scheduled maintenance during 2022, lower rates on the Siem Helix 1 and the Siem Helix 2 as they transitioned from their legacy contracts with Petrobras, and a weaker British pound during 2022 as compared to 2021. Overall Well Intervention vessel utilization increased to 80% in 2022 as compared to 67% in 2021.

Our Robotics revenues increased by 40% in 2022 as compared to 2021, primarily reflecting higher vessel, trenching and ROV activities. Chartered vessel days increased to 1,401 days, which included 420 spot vessel days, in 2022 as compared to 1,178 days, which included 477 spot vessel days, in 2021. Trenching days increased to 483 days during 2022 as compared to 336 days during 2021. Overall ROV and trencher utilization increased to 53% during 2022 from 36% during 2021.

Our Shallow Water Abandonment revenues in 2022 reflected revenues generated by Helix Alliance since the acquisition on July 1, 2022 (Note 3). The Epic Hedron heavy lift barge was 21% utilized, utilization of other Helix Alliance vessels was 76%, and utilization across marketable P&A and coiled tubing systems was 2,324 days, or 62%.

Our Production Facilities revenues increased by 19% in 2022 as compared to 2021, primarily reflecting higher oil and gas prices and improved rates related to the HFRS, offset in part by lower oil and gas production volumes in 2022. Revenues also benefitted from retroactive rate adjustment on our production contract with the HP I.

Gross Profit (Loss). Our consolidated 2022 gross profit increased by $35.2 million as compared to 2021, primarily reflecting increased profitability in our Robotics and Production Facilities segments and the addition of Shallow Water Abandonment segment in the third quarter 2022, offset in part by decreased profitability in our Well Intervention segment.

Our Well Intervention segment had a gross loss of $40.1 million in 2022 as compared to a gross loss of $21.3 million in 2021, primarily reflecting our mix of contracting year over year, with our lower rates in Brazil generating higher losses, offset in part by increased Gulf of Mexico and North Sea revenues generating lower incremental margins driven by an increase in integrated projects and reimbursable revenues during 2022.

Our Robotics gross profit increased by $24.1 million in 2022 as compared to 2021, primarily reflecting higher revenues due to increased trenching and ROV activities and a higher number of vessel days.

Our Shallow Water Abandonment gross profit in 2022 reflected results from Helix Alliance since the acquisition on July 1, 2022.

Our Production Facilities gross profit increased by $5.6 million in 2022 as compared to 2021, primarily reflecting increases in revenues, offset in part by higher costs during 2022.

Acquisition and Integration Costs. Our acquisition and integration costs of $2.7 million reflected Alliance acquisition related costs incurred during 2022 (Note 3).

Change in Fair Value of Contingent Consideration. The $16.1 million change in fair value of contingent consideration reflected an increase in the estimated earn-out payable in 2024 to the seller in the Alliance transaction as Helix Alliance’s 2022 results following the acquisition date and its expected 2023 results have both improved as compared to forecasts and information available at the time of acquisition (Notes 3 and 19).

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $76.8 million in 2022 as compared to $63.4 million in 2021, primarily reflecting higher employee incentive and share-based compensation costs as well as increased general and administrative expenses related to Helix Alliance.

Equity in Earnings of Investment. Equity in earnings of investment of $8.3 million primarily reflected the cash distribution as a result of the sale of the “Independence Hub” platform in 2022 (Note 2).

Net Interest Expense. Our net interest expense totaled $19.0 million in 2022 as compared to $23.2 million in 2021, primarily reflecting lower funded debt, which decreased by $42.9 million during 2022, and lower fees associated with our credit facility as compared to 2021 (Note 7).

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Other Income (Expense), Net. Net other expense was $23.3 million in 2022 as compared to $1.5 million in 2021, primarily reflecting higher foreign currency losses due to weakening of the British pound in 2022.

Income Tax Provision (Benefit). Income tax provision was $12.6 million for 2022 as compared to income tax benefit of $9.0 million for 2021. The effective tax rates for 2022 and 2021 were (16.8)% and 12.7%, respectively. These variances were primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions as well as losses in certain jurisdictions for which no financial statement benefits have been recognized (Note 8).

Comparison of Years Ended December 31, 2021 and 2020

Various financial and operational highlights for the years ended December 31, 2021 and 2020 were previously presented in our 2021 Annual Report on Form 10-K.

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 current maturities of long-term debt. Net working capital measures short-term liquidity and is important for predicting cash flow and debt servicing capacity.

Long-Term Debt

Long-term debt in the table above is net of unamortized debt issuance costs and excludes current maturities of $38.2 million and $42.9 million, respectively, at December 31, 2022 and 2021. See Note 7 for information relating to our long-term debt.

Liquidity

We define liquidity as cash and cash equivalents, excluding restricted cash, plus available capacity under our credit facility. Our liquidity at December 31, 2022 included $186.6 million of cash and cash equivalents and $98.1 million of available borrowing capacity under the ABL Facility (Note 7) and excluded $2.5 million of restricted cash. Our liquidity at December 31, 2021 included $253.5 million of cash and cash equivalents and $51.1 million of available borrowing capacity under the ABL Facility and excluded $73.6 million of short-term project related restricted cash. The reduction in cash and cash equivalents was primarily attributable to our acquisition of Alliance on July 1, 2022 (Note 3). The increase in available borrowing capacity under the ABL Facility resulted from debt repayments during 2022. As of December 31, 2022, we had approximately $28.9 million in Nigerian Naira, which is subject to currency exchange controls established by the Central Bank of Nigeria. Those exchange controls have to date restricted our ability to convert our Nigerian Naira into U.S. dollars.

During 2022, we saw an improvement in the markets we serve as evidenced by increases in our revenues and gross profit. We expect continued improvements in our operating performance, increases in our cash position and high availability on the ABL Facility. We believe that our cash on hand, internally generated cash flows and availability under the ABL Facility will be sufficient to fund our operations and service our debt over at least the next 12 months.

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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 ABL Facility. We currently do not anticipate borrowing under the ABL Facility other than for the issuance of letters of credit.

On February 20, 2023, we announced that our Board authorized a new share repurchase program under which we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. The repurchase program has no set expiration date. Repurchases under the program would be made through open market purchases in compliance with Rule 10b-18 under the Exchange Act, 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 based on an evaluation of market conditions, stock price, liquidity and other factors. The 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. The purchase of shares by us under the program is at our discretion and subject to prevailing financial and market conditions. Any repurchased shares are expected to be cancelled. No repurchases have been made pursuant to this program at the time of this filing.

Cash Flows

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

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Operating Activities

The decrease in our operating cash flows for 2022 as compared to 2021 primarily reflects higher regulatory recertification costs for our vessels and systems and negative changes in net working capital. Regulatory recertification spend on our vessels and systems amounted to $35.1 million and $9.6 million, respectively, during the comparable year over year periods. Operating cash flows for 2022 and 2021 included the receipt of $1.1 million and $18.9 million, respectively, in income tax refunds related to the U.S. Coronavirus Aid, Relief, and Economic Security Act.

Investing Activities

Cash flows used in investing activities for 2022 as compared to 2021 primarily reflect $112.6 million in net cash paid to acquire Alliance (Note 3), offset in part by $7.8 million in net cash distribution from Independence Hub in May 2022 (Note 2) and the deferral or reduction of our planned capital expenditures as our response to the adverse impact to our operations as a result of the COVID-19 pandemic.

Financing Activities

Net cash outflows from financing activities in 2022 primarily reflect the repayment of $7.9 million related to the MARAD Debt and $35 million related to the 2022 Notes (Note 7). Net cash outflows from financing activities of $96.0 million in 2021 primarily reflect the repayment of $90.9 million related to our indebtedness, including the final maturity of $53.6 million of the Nordea Q5000 Loan in January 2021 and $28.0 million in full repayment of the Term Loan in September 2021.

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, including the payment of the Alliance earn-out consideration to the seller in the Alliance transaction.

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Long-term debt and other contractual commitments

The following table summarizes 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 December 31, 2022 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 (in thousands). 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 December 31, 2022. Our 2023 Notes and 2026 Notes have certain early redemption and conversion features that could affect the timing and amount of any cash requirements. Although upon conversion these notes are able to be settled in either cash or shares, we intend to settle their principal amounts in cash (Note 7).

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Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 15). Those obligations, which are presented on a discounted basis on the consolidated balance sheets, approximate $78.6 million (undiscounted) as of December 31, 2022, none of which is expected to be paid during the next 12 months. We are entitled to receive certain amounts from Marathon Oil as certain decommissioning obligations are fulfilled.

Regulatory certification and dry dock. Our Well Intervention 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, they generally range between $3.0 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.

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CRITICAL ACCOUNTING ESTIMATES

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

Business Acquisition

We account for business acquisitions under the acquisition method of accounting. We determine the purchase price to be the cash and other assets transferred to the seller and the value of any liabilities, such as contingent consideration or other seller financing incurred. The estimate of any contingent consideration and its fair value on the acquisition date and subsequent reporting periods is a significant estimate.

We allocate the purchase price of businesses we acquire to identifiable assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill. The allocation of the purchase price requires management to make significant estimates in determining the fair values of assets acquired and liabilities assumed. These estimates and assumptions may include, but are not limited to, the cash flows that an asset is expected to generate in the future, the appropriate weighted average cost of capital, and the estimated useful lives. Changes in these assumptions could affect the carrying value of these assets, the amount of future depreciation or amortization and any possible impairment charges.

We use available and relevant information to estimate fair values (including quoted market prices when available) and the nominal value of acquired assets and assumed liabilities as well as deploy various valuation techniques such as discounted cash flows. We may engage third party specialists to assist in the fair value determination of acquired assets and liabilities, including identifiable long-lived assets and identifiable intangible assets, as well as any contingent earn-out consideration to be paid to the seller if certain future conditions are met. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, the estimated fair value of contingent earn-out considerations, as well as the remaining useful lives of these assets, could materially impact our financial condition or results of operations. See Note 3 to our consolidated financial statements for further discussion on our acquisition of Alliance during 2022.

Property and Equipment

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

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

New Accounting Standards

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

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

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

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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 and robotics operations. The services we offer to the oil and gas market cover the lifecycle of an offshore oil or gas field, and the services we offer to the renewable energy market are currently focused on offshore wind farm projects, including trenching and cable burial and seabed clearance operations. Our well intervention fleet includes seven purpose-built well intervention vessels and 10 intervention systems. Our robotics equipment includes 43 work-class ROVs and four trenchers. We charter robotics support vessels on both long-term and spot bases to facilitate our ROV and trenching operations. Our well intervention and robotics operations are geographically dispersed throughout the world. Our Production Facilities segment includes the HP I, the HFRS and our ownership of oil and gas properties.

Economic Outlook and Industry Influences

Demand for our services is primarily influenced by the condition of the oil and gas and the renewable energy markets, 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 several other factors, including:

Crude oil prices historically have been volatile, which volatility has been exacerbated by the ongoing COVID-19 pandemic. Prices declined significantly in 2020 but have since recovered their losses and are at their highest levels since 2014, but their stability remains uncertain. The decline in oil prices in 2020 and the overall volatility and uncertainty in prices, in addition to the shift in resource allocation to renewable energy, caused oil and gas companies to drastically reduce spending (on both operational activities and capital projects). These factors have led to a decrease in the demand and rates for services provided by offshore oil and gas services providers, but the increases in oil prices in 2021, as well as the outlook for higher sustained oil prices beyond 2021, could lead to higher customer spending for the industry.

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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. Lower volumes of work and lower day rates quoted by drilling rig contractors, combined with rig overhang, affects the utilization and/or rates we can achieve for our assets and services. Furthermore, additional volatile and uncertain macroeconomic conditions in some regions and countries around the world as well as ESG initiatives may impact our existing contracts and contracting opportunities and may introduce further volatility into our operations and/or financial results.

The ongoing COVID-19 pandemic has resulted in new market dynamics and challenges to us, including increased costs related to our supply chain, logistics and human capital resources. We have sought to minimize the direct impact of COVID-19 on our offshore workforce with crew changes that comport with travel restrictions and quarantine measures. While the full impact of the COVID-19 pandemic, including the duration of its negative impact on economic activity, remains unknown, we expect such impact to continue to be felt by our industry into the foreseeable future. The uncertainty and other conditions of the current environment have resulted in challenges to renew or secure long-term contracts for our vessels and systems, as operators have been less willing to commit to future spending. These developments have also impacted, and are expected to continue to impact, many other aspects of our industry and the global economy, including limiting access to and use of capital across various sources and markets, disrupting supply chains and increasing costs, and negatively affecting human capital resources including complicating offshore crew changes due to health and travel restrictions as well as the overall health of the global workforce.

Over the near-term, as oil and gas companies evaluate their budgetary spend allocations, we expect they may be weighted towards short-cycle production enhancement of existing wells rather than new long-cycle exploration projects, as historically enhancement is less expensive per incremental barrel of oil than exploration. Over the longer term, we expect oil and gas companies to increasingly focus on optimizing production of their existing subsea wells. Moreover, as the subsea tree base expands and ages, the demand for P&A services should persist. Our well intervention and robotics operations service the lifecycle of an oil and gas field and provide P&A services at the end of the life of a field as required by governmental regulations, and we believe that we have a competitive advantage in performing these services efficiently.

We expect the fundamentals for our business will remain favorable over the longer term as the need to prolong well life in oil and gas production and safely decommission end of life wells are primary drivers of demand for our services. This expectation is based on multiple factors, including (1) maintaining the optimal production of a well through enhancement is fundamental to maximizing the overall economics of well production; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling; and (3) extending the production of offshore wells not only maximizes a well’s production economics but also enables the financial benefit of delaying P&A costs, which can be substantial.

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 production and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water, and government subsidies for renewable energy projects.

We are subject to the effects of changing prices. Inflation rates have been relatively low and stable over the previous three decades; however, in 2021 due in part to supply chain disruptions and the effects of the COVID-19 pandemic, inflation rates began to rise significantly. Although we are able to reduce some of our exposure to price increases through the rates we charge, we bear the costs of operating and maintaining our assets, including labor and material costs as well as recertification and dry dock costs. While the cost outlook is not certain, we believe that we can manage these inflationary pressures by introducing appropriate sales price adjustments and by actively pursuing internal cost reduction efforts. However, competitive market pressures may affect our ability to recoup these price increases through the rates we charge, which may result in reductions in our operating margins and cash flows in the future.

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Business Activity Summary

In recent years, we have maintained a relatively strong balance sheet and enhanced our financial position through various means including securities offerings (the last of which occurred in August 2020) and executing a new five-year credit facility during 2021, which have allowed us to focus on our operations.

We re-activated the Q7000 in January 2021 and the Seawell in June 2021 after warm-stacking the vessels during part of 2020 due in part to the COVID-19 pandemic. The Q7000 performed well intervention work offshore Nigeria for most of 2021. The Seawell performed various work scopes in the North Sea during the second and third quarters of 2021.

In March 2021, we entered into a new agreement to provide various operators with access to the HFRS for well control purposes in the Gulf of Mexico through at least March 31, 2023.

We completed our five-year contract with BP for the Q5000 in April 2021. We also completed our four-year contracts with Petrobras for the Siem Helix 1 in August 2021 and the Siem Helix 2 in December 2021. Both the Q5000 and the Siem Helix 1 are currently working in the spot market. The Petrobras contract for the Siem Helix 2 was extended at reduced rates for one year until December 2022.

During 2021, we continued to improve our health and safety protocols in order to navigate through the COVID-19 pandemic, including significant measures to protect both onshore and offshore personnel.

We have continued to expand our services and offerings into the offshore renewable energy sector. During 2021, we performed site clearance and/or ROV support work on multiple renewable energy projects in the Asia Pacific and North Sea regions.

Backlog

Backlog is defined as firm commitments represented by signed contracts. As of December 31, 2021, our consolidated backlog totaled $348 million, of which $246 million is expected to be performed in 2022. As of December 31, 2021, our contract with Petrobras to provide well intervention services offshore Brazil with the Siem Helix 2 chartered vessel and our fixed fee agreement for the HP I represented approximately 37% of our total backlog. As of December 31, 2020, the total backlog associated with our operations was $407 million. 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.

RESULTS OF OPERATIONS

Non-GAAP Financial Measures

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

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We measure our operating performance based on EBITDA, Adjusted EBITDA and free cash flow. EBITDA, Adjusted EBITDA and free cash flow are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use EBITDA, Adjusted EBITDA and free cash flow 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 and free cash flow 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 and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA and free cash flow 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 income or cash flow data prepared in accordance with GAAP.

We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets and non-cash gains and losses on equity investments are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets and the general provision (release) for current expected credit losses, if any. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments, which are excluded from EBITDA as a component of net other income or expense. We define free cash flow as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. In the following reconciliation, we provide amounts as reflected in the condensed consolidated financial statements unless otherwise noted.

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

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