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Item 7. Management’s Discussion and Analysis

2023-02-24 compared with 2022-02-24 · 168 added, 127 removed, 156 unchanged (65% of the section changed)

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EXECUTIVE SUMMARY

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.

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 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.

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, 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:

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.

● worldwide economic activity and general economic and business conditions, including access to capital and capital markets;

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● the availability and discovery rate of new oil and natural gas reserves in offshore areas;

● the exploration and production of onshore shale oil and natural gas;

● the cost of offshore exploration for and production and transportation of oil and natural gas;

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● the environmental and social sustainability of the oil and gas sector and the perception thereof, including within the investing community;

● the transition towards renewable energy and carbon neutrality and away from fossil fuels;

● national energy sovereignty and energy security;

● the sale and expiration dates of offshore leases globally;

● technological advances affecting energy exploration, production, transportation and consumption;

● the exploration and production of onshore shale oil and natural gas;

● potential acceleration of the development of alternative fuels;

● shifts in end-customer preferences toward fuel efficiency and the use of natural gas or renewable energy alternatives;

● weather conditions, natural disasters, and epidemic and pandemic diseases, including the ongoing COVID-19 pandemic;

● weather conditions, natural disasters, and epidemic and pandemic diseases, including the COVID-19 pandemic;

● laws, regulations and policies directly related to the industries in which we provide services, including restrictions on oil and gas leases, and their interpretation and enforcement;

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● domestic and international tax laws, regulations and policies.

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.

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.

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.

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;

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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.

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, 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, 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.

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

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.

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.

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 is defined as firm commitments represented by signed contracts.

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.

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.

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, 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.

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;

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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 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 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 and the general provision (release) for current expected credit losses, if any.

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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(Gain) loss on disposition of assets, net

Acquisition and integration costs

Change in fair value of contingent consideration

General provision (release) for current expected credit losses

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Free Cash Flow

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

Long-term debt including current maturities

Cash and cash equivalents and restricted cash

Comparison of Years Ended December 31, 2022 and 2021

We have three reportable business segments:

Well Intervention, Robotics and Production Facilities.

All material intercompany transactions between the segments have been eliminated in our consolidated financial statements, including our consolidated results of operations.

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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Well Intervention

Shallow Water Abandonment

Production Facilities

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Well Intervention

Shallow Water Abandonment

Production Facilities

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Well Intervention

Shallow Water Abandonment

Production Facilities

Total company

Number of vessels or robotics assets (1) / Utilization (2)

Number of vessels, Robotics assets or Shallow Water Abandonment systems (1) / Utilization (2)

Well Intervention vessels

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Chartered Robotics vessels

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

(2) Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of calendar days in the applicable period.

Shallow Water Abandonment vessels (4)

Shallow Water Abandonment systems (5)

(1) Represents the number of vessels, Robotics assets or marketable Shallow Water Abandonment systems as of the end of the period, including spot vessels and those under term charters, and excluding acquired vessels prior to their in-service dates, vessels managed on behalf of third parties and vessels or assets disposed of and/or taken out of service.

(2) Represents the average utilization rate, which is calculated by dividing the total number of days the vessels, Robotics assets or marketable Shallow Water Abandonment systems generated revenues by the total number of calendar days in the applicable period.

Utilization rates of chartered Robotics vessels in 2022 and 2021 included 420 and 477 spot vessel days, respectively, at near full utilization.

(3) Consists of ROVs and trenchers.

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

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

(5) Consists of marketable P&A and coiled tubing systems.

Intercompany segment amounts are derived primarily from equipment and services provided to other business segments.

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Net Revenues.

Our consolidated net revenues decreased by 8% in 2021 as compared to 2020, reflecting lower revenues from our Well Intervention and Robotics segments and higher intercompany eliminations, offset in part by higher revenues in our Production Facilities segment.

Our Well Intervention revenues decreased by 4% in 2021 as compared to 2020, primarily reflecting lower utilization on the Siem Helix 1 in Brazil, lower rates on the Q5000 and lower rates and utilization on the Q4000 in the Gulf of Mexico.

These revenue decreases were offset in part by higher utilization on the Q7000 in West Africa, which was warm-stacked for most of 2020.

Our Robotics revenues decreased by 23% in 2021 as compared to 2020, primarily reflecting reduced seabed clearance days using spot vessels, as well as a reduction in trenching activities.

Our results included 1,178 vessel days and 336 trenching days in 2021 as compared to 1,690 vessel days and 407 trenching days (including 161 days on third-party vessels) in 2020.

Our Production Facilities revenues increased by 19% in 2021 as compared to 2020, primarily reflecting higher oil and gas prices and higher production volumes from our wells as well as higher HFRS revenues.

The increase in intercompany eliminations was primarily attributable to higher eliminations related to revenues that our Well Intervention segment earned in 2021 associated with capital spending in our Production Facilities segment to perform recompletion work on our Droshky oil and gas properties.

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.

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 2021 gross profit decreased by $64.5 million as compared to 2020, primarily reflecting lower gross profit in our Well Intervention and Robotics segments, offset in part by higher gross profit in our Production Facilities segment.

Our Well Intervention segment had a gross loss of $21.3 million in 2021 as compared to a gross profit of $41.0 million in 2020, primarily reflecting lower segment revenues as well as higher costs associated with our resumed activity in West Africa during 2021.

The gross profit related to our Robotics segment decreased by $9.3 million in 2021 as compared to 2020, primarily reflecting lower revenues, offset in party by lower costs due to fewer spot vessel days on site clearance projects.

The gross profit related to our Production Facilities segment increased by $7.1 million in 2021 as compared to 2020, primarily reflecting higher revenues during 2021.

Goodwill Impairment.

The $6.7 million charge in 2020 reflected the impairment of the entire goodwill balance, which related to our acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”) (Note 7).

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 $63.4 million in 2021 as compared to $61.1 million in 2020.

The increase primarily reflects higher employee incentive compensation costs, offset in part by cost reduction measures and lower credit loss reserves.

Our selling, general and administrative expenses in 2020 included a $2.7 million provision for current expected credit losses (Note 19).

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 $23.2 million in 2021 as compared to $28.5 million in 2020, primarily reflecting a reduction in our overall debt levels and the elimination of accretion of debt discounts associated with our Convertible Senior Notes Due 2022 (the “2022 Notes”), Convertible Senior Notes Due 2023 (the “2023 Notes”) and Convertible Senior Notes Due 2026 (the “2026 Notes”) as a result of the adoption of Accounting Standards Update (“ASU”) No.

2020-06 beginning January 1, 2021, offset in part by higher yields on the 2026 Notes, which were issued during the third quarter 2020, and the cessation of interest capitalization with the completion of the Q7000 in 2020.

Net interest expense in 2020 excluded $1.2 million in capitalized interest associated with the Q7000 (Note 8).

Gain (Loss) on Extinguishment of Long-term Debt.

The $0.1 million loss on extinguishment of long-term debt in 2021 was associated with the full repayment of the term loan under our former credit agreement (the “Term Loan”), which was terminated in September 2021 concurrent with our entering into the ABL Facility (Note 8).

The $9.2 million gain on extinguishment of long-term debt in 2020 was associated with the repurchase of $90.0 million in aggregate principal amount of the 2022 Notes and $95.0 million in aggregate principal amount of the 2023 Notes.

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).

Other Income (Expense), Net.

Net other expense was $1.5 million in 2021 primarily due to foreign currency transaction losses reflecting the weakening of the British pound.

Net other income was $4.7 million in 2020 primarily due to foreign currency transaction gains reflecting the strengthening of the British pound.

Income Tax Benefit.

Income tax benefit was $9.0 million for 2021 as compared to $18.7 million for 2020.

The change in income tax benefit was primarily attributable to certain discrete adjustments, offset in part by the jurisdictional mix of earnings.

In 2021 we recognized a $5.0 million benefit related to a reduction in our valuation allowance.

In 2020 we recognized a $7.6 million benefit related to the U.S.

Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and an $8.3 million benefit related to a foreign subsidiary restructuring (Note 9).

Absent these discrete events, income tax benefit would be $4.0 million and $2.8 million for 2021 and 2020, respectively.

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

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Long-term debt

(1) Current maturities of our long-term debt of $42.9 million and $90.7 million, respectively, are excluded from long-term debt.

Long-term debt as of December 31, 2021 is net of unamortized debt issuance costs.

Long-term debt as of December 31, 2020 is net of unamortized debt discounts and debt issuance costs.

See Note 8 for information relating to our long-term debt, including the impact of our adoption of ASU No.

Net Working Capital

Net working capital is equal to current assets minus current liabilities.

It measures short-term liquidity and operational efficiency and is important for predicting cash flow and debt requirements.

Our net working capital includes current maturities of our long-term debt.

Liquidity, as defined by us, is equal to cash and cash equivalents, excluding restricted cash, plus available capacity under our credit facility.

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 (Note 8) and excluded $73.6 million of restricted cash primarily related to a short-term project related letter of credit, the restriction from which is expected to be released upon completion of the project.

Our liquidity at December 31, 2020 included $291.3 million of cash and cash equivalents and $160.2 million of available borrowing capacity under the Revolving Credit Facility.

The ongoing COVID-19 pandemic has impacted our operations and our revenues, and we expect the pandemic to continue to impact our operations and our operating results into the foreseeable future, whether by contributing to oil price volatility, which in turn affects customer spending and demand for our services, or by disruptions to our operations, including supply chain and crew change disruptions and contributing to prince increases.

Nonetheless, we remain focused on maintaining a strong balance sheet and adequate liquidity.

We have reduced, deferred or cancelled certain planned capital expenditures and reduced operating costs as appropriate through various measures including warm stacking our vessels when idle.

Deferred capital spending and reduced operating costs should return with increases in activity.

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.

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.

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.

The ongoing COVID-19 pandemic and its impact on the energy and financial markets have contributed to rising yields on our existing debt as well as volatility in our stock price, both of which increase our cost of capital.

The yield on the 2026 Notes is significantly higher than that of the 2022 Notes and 2023 Notes.

The COVID-19 pandemic has also contributed to more limited access to certain capital markets.

An ongoing period of weak, or continued decreases in, industry activity may make it difficult to comply with our covenants and the other restrictions in our debt agreements.

Our failure to comply with these covenants and other restrictions could lead to an event of default.

Current global and market conditions have increased the potential for that difficulty and are expected to negatively impact the terms on which we are able to secure financing.

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.

At December 31, 2021, our available borrowing capacity under the ABL Facility was $51.1 million, net of $1.9 million of letters of credit issued under that 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.

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

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Operating Activities

Net cash flows provided by operating activities were $140.1 million in 2021 as compared to $98.8 million in 2020.

The increase in operating cash flows primarily reflects improvements in working capital, lower recertification and dry dock costs, and the receipt in 2021 of $18.9 million in income tax refunds related to the CARES Act, offset in part by lower earnings.

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

Capital expenditures represent cash paid principally for the acquisition, construction, completion, upgrade, modification and refurbishment of long-lived property and equipment.

Capital expenditures also include interest on property and equipment under development.

Our capital expenditures during 2020 primarily included payments associated with the construction and completion of the Q7000 , which commenced operations in January 2020.

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

Cash flows from financing activities consist primarily of proceeds from debt and equity transactions and repayments related to our long-term debt.

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 (Note 8).

Net cash outflows from financing activities of $52.6 million in 2020 primarily reflect the repayment of $46.4 million related to our indebtedness as well as our repurchase of $90 million of the 2022 Notes and $95 million of the 2023 Notes and entry into the capped call transactions associated with the 2026 Notes with proceeds from the issuance of the 2026 Notes in August 2020 (Note 8).

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).

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.

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.

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, 2021 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 certain property and equipment and related services but do not include expected capital spending that is not contractually committed as of December 31, 2021.

The 2022 Notes, 2023 Notes and 2026 Notes have certain early redemption and conversion features that could affect the timing and amount of any cash requirements.

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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Operating leases (1)

Earn-out consideration (2)

Total cash obligations

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At December 31, 2022, our commitment related to long-term vessel charters totaled approximately $378.8 million, of which $157.3 million was related to the non-lease (services) components that are not included in operating lease liabilities in the consolidated balance sheet as of December 31, 2022 .

(2) As part of the Alliance acquisition, we are required to make the earn-out payment to the seller in the Alliance transaction in 2024 in the event the Helix Alliance business achieves certain financial metrics in 2022 and 2023 (Note 3).

Amount reflects the estimated fair value of the earn-out as of December 31, 2022 although the final earn-out payable is not capped.

Other material cash requirements

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We have decommissioning obligations associated with our oil and gas properties (Note 15).

Those obligations approximate $31.0 million (undiscounted) as of December 31, 2021 and are all expected to be paid during the next 12 months.

We are entitled to receive certain amounts from Marathon Oil as these decommissioning obligations are fulfilled.

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 vessels and intervention systems are subject to certain regulatory certification requirements that must be satisfied in order for the vessels and intervention systems to operate.

Certification may require dry dock and other compliance costs on a periodic basis, usually every 30 months.

These costs can vary and generally range between $3.0 million to $15.0 million per vessel and $0.5 million to $5.0 million per intervention system, and the timing of those costs can vary.

We expect the sources of funds to satisfy our material cash requirements to primarily come from our ongoing operations but can also come from existing cash, availability under the ABL Facility, and access to capital markets.

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.

CRITICAL ACCOUNTING ESTIMATES

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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

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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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis