What changed in this filing

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Item 2. Management’s Discussion and Analysis

2022-04-27 compared with 2021-10-22 · 129 added, 245 removed, 134 unchanged (74% of the section changed)

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Included in forward-looking statements are, among other things:

● statements regarding our business strategy and any other business plans, forecasts or objectives, any or all of which are subject to change;

● statements regarding our business strategy, corporate initiatives and any other business plans, forecasts or objectives, any or all of which are subject to change;

● statements regarding projections of revenues, gross margins, expenses, earnings or losses, working capital, debt and liquidity, capital expenditures or other financial items;

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● statements regarding our ability to enter into and/or perform commercial contracts, including the scope, timing and outcome of those contracts;

● statements regarding the spot market, the continuation of our current backlog, our spending and cost reduction plans and our ability to manage changes, and the ongoing COVID-19 pandemic and oil price volatility and their respective effects and results on the foregoing as well as our protocols and plans;

● statements regarding the spot market, the continuation of our current backlog, our spending and cost reduction plans and our ability to manage changes, and the COVID-19 pandemic and oil price volatility and their respective effects and results on the foregoing as well as our protocols and plans;

● statements regarding the acquisition, construction, completion, upgrades to or maintenance of vessels, systems or equipment and any anticipated costs or downtime related thereto;

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● statements regarding potential developments, industry trends, performance or industry ranking;

● statements regarding our Environmental, Social and Governance (“ESG”) initiatives and the successes thereon or regarding our environmental efforts, including greenhouse gas emissions targets;

● statements regarding global, market or investor sentiment with respect to fossil fuels;

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These factors include:

● the results and effects of the ongoing COVID-19 pandemic and actions by governments, customers, suppliers and partners with respect thereto;

● the impact of domestic and global economic conditions and the future impact of such conditions on the offshore energy industry and the demand for our services;

● the general impact of oil and gas price volatility and the cyclical nature of the oil and gas market;

● the potential effects of regional tensions that have escalated or may escalate, including into conflicts or wars, and their impact on the global economy, oil and gas market, our operations, international trade, or our ability to do business with certain parties or in certain regions, and any governmental sanctions resulting therefrom;

● the results and effects of the COVID-19 pandemic and actions by governments, customers, suppliers and partners with respect thereto;

● the results of corporate initiatives such as alliances, partnerships, joint ventures, mergers, acquisitions, divestitures and restructurings, or the determination not to pursue or effect such initiatives;

● the impact of any potential cancellation, deferral or modification of our work or contracts by our customers;

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● unexpected future capital expenditures, including the amount and nature thereof;

● the effectiveness and timing of completion of our vessel and/or system upgrades and major maintenance items;

● the effectiveness and timing of our vessel and/or system upgrades, regulatory recertification and inspection as well as major maintenance items;

● unexpected delays in the delivery, chartering or customer acceptance, and terms of acceptance, of our assets;

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● the availability of capital (including any financing) to fund our business strategy and/or operations;

● the effectiveness of our ESG initiatives and disclosures;

● the impact of current and future laws and governmental regulations and how they will be interpreted or enforced, including related to litigation and similar claims in which we may be involved;

● the future impact of international activity such as the U.K.’s exit from the European Union, known as Brexit, and trade agreements on our business, operations and financial condition;

● the future impact of international activity and trade agreements on our business, operations and financial condition;

● the effect of adverse weather conditions and/or other risks associated with marine operations;

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● the impact of general, market, industry or business conditions;

● the impact of inflation and our ability to recoup rising costs in the rates we charge to our customers.

Our actual results could also differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item 7.

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We caution you not to place undue reliance on forward-looking statements.

Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements, all of which are expressly qualified by the statements in this section, or provide reasons why actual results may differ.

Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise forward-looking statements, all of which are expressly qualified by the statements in this section, or provide reasons why actual results may differ.

All forward-looking statements, express or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement.

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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 and cable burial operations.

Our well intervention fleet includes seven purpose-built well intervention vessels, six IRSs, three SILs and the ROAM.

Our robotics equipment includes 42 work-class ROVs, four trenchers and one ROVDrill.

We charter ROV support vessels on both long-term and spot bases to facilitate our ROV and trenching operations.

Our well intervention fleet includes seven purpose-built well intervention vessels and 10 intervention systems.

Our robotics equipment includes 40 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.

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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 also 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:

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

● the global supply and demand for oil and natural gas;

● political and economic uncertainty and geopolitical unrest, including regional conflicts and economic and political conditions in oil-producing regions;

● actions taken by OPEC and/or OPEC+ ;

● 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;

● the level of excess production capacity;

● the ability of oil and gas companies to generate funds or otherwise obtain external capital for capital projects and production operations;

● the Environmental, Social and Governance (“ESG”) sustainability of the oil and gas sector and the perception thereof, including within the investing community;

● the sale and expiration dates of offshore leases globally;

● governmental restrictions on oil and gas leases;

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

● 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;

● laws, regulations and policies directly related to the industries in which we provide services, and their interpretation and enforcement;

● environmental and other governmental regulations;

● 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 as well as actions taken by OPEC+ nations.

Prices have recovered their losses from 2020 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, have caused oil and gas operators to drastically reduce spending (on both operational activities and capital projects), which has decreased the demand and rates for services provided by offshore oil and gas services providers.

Historically, drilling rigs have been the asset class used for offshore well intervention work, and our customers have used drilling rigs on existing long-term contracts to perform well intervention work instead of new drilling activities.

Rig day rates are also a pricing indicator for our services.

Rig overhang, combined with lower volumes of work and lower day rates quoted by drilling rig contractors, affects the utilization and/or rates we can achieve for our assets and services.

Furthermore, additional volatile and uncertain macroeconomic conditions as well as ESG initiatives in some regions and countries around the world may have a direct and/or indirect impact on 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 a new period of market weakness and challenges to us.

While the full impact of the COVID-19 pandemic, including the duration of its negative impact on economic activity, remains unknown, we expect that the impact of COVID-19 on our industry will continue to be felt through 2021 and possibly longer.

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.

The COVID-19 pandemic and its effects on our industry and the global economy have impacted our 2020 and 2021 operating results to date.

Most if not all of our oil and gas customers cut their spending, which has reduced the demand and rates for the services offered to our oil and gas customers.

The COVID-19 pandemic continues to pose challenges with, and increase costs related to, our supply chain, logistics and human capital resources, including minimizing the direct impact of COVID-19 on our offshore workforce and challenges with offshore crew changes due to travel restrictions and quarantine measures.

Despite this current period of market weakness and volatility, over the longer term we expect oil and gas companies to increasingly focus on optimizing production of their existing subsea wells.

As oil and gas companies evaluate their budgetary spend allocations, we expect that they may be weighted towards production enhancement of existing wells rather than new exploration projects as enhancement is less expensive per incremental barrel of oil than exploration.

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 well intervention services efficiently.

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.

Oil and gas prices experienced recent highs during the first quarter 2022 as global demand continued to recover from COVID-19 related restrictions and supply was disrupted by regional conflicts.

The increases in oil prices, as well as the outlook for higher sustained oil prices, should lead to higher customer spending for the industry.

However, despite the current strong commodity price environment, there are broad headwinds to commodity price stability.

The headwinds include those regional conflicts, high inflation, ongoing COVID-related uncertainties, various governmental and customer ESG initiatives and continued shifting of resource allocation to renewable energy.

We expect this will contribute to commodity price volatility and may temper customer spending for oil and gas projects.

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, 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.

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 full impact of the COVID-19 pandemic, including the duration of its impact on economic activity, remains unknown, we expect such impact may continue into the foreseeable 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.

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 continue to 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 and customers shift resources to renewable energy, the demand for P&A services should persist.

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.

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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 provide services and methodologies that we believe are critical to maximizing production economics.

Our services cover the lifecycle of an offshore oil or gas field.

In addition to serving the oil and gas market, our robotics assets are contracted for the development of offshore renewable energy projects (wind farms).

We provide services primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions.

As of September 30, 2021, our consolidated backlog that is supported by written agreements or contracts totaled approximately $231 million, of which $69 million is expected to be performed over the remainder of 2021.

Our agreements 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 represent approximately 43% of our total backlog as of September 30, 2021.

Backlog is not necessarily a reliable indicator of revenues derived from these contracts as services may be added or subtracted;

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 and remained high through the first quarter 2022.

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.

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.

We define backlog as firm commitments represented by signed contracts.

As of March 31, 2022, our consolidated backlog totaled $548 million, of which $263 million is expected to be performed over the remainder of 2022.

Our contract with Trident Energy Do Brasil LTDA.

to provide P&A services offshore Brazil with the Siem Helix 1 chartered vessel, our contract with Petróleo Brasileiro S.A.

(“Petrobras”) to provide well intervention services offshore Brazil with the Siem Helix 2 chartered vessel, our well intervention contract with Shell Offshore Inc.

for the Q5000 and our fixed fee agreement for the HP I represented approximately 58% of our total backlog as of March 31, 2022.

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;

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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 the rates we would have generated had we performed the contract.

If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in backlog.

RESULTS OF OPERATIONS

We have three reportable business segments:

Well Intervention, Robotics 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.

Non-GAAP Financial Measures

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Three Months Ended

Nine Months Ended

September 30,

Net income (loss)

Income tax provision (benefit)

Income tax provision

Net interest expense

(Gain) loss on extinguishment of long-term debt

Other (income) expense, net

Depreciation and amortization

Goodwill impairment

(Gain) loss on disposition of assets, net

General provision (release) for current expected credit losses

Realized losses from foreign exchange contracts not designated as hedging instruments

Adjusted EBITDA

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

Nine Months Ended

September 30,

Three Months Ended

Cash flows from operating activities

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Free Cash Flow

Comparison of Three Months Ended September 30, 2021 and 2020

Comparison of Three Months Ended March 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 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):

Three Months Ended

September 30,

Net revenues —

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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 available calendar days in the applicable period.

The average utilization rates of chartered robotics vessels during the three-month periods ended September 30, 2021 and 2020 included 176 and 291 spot vessel days, respectively, at near full utilization.

(3) Consists of ROVs, trenchers and ROVDrill.

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

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

Utilization rates of chartered robotics vessels during the three-month periods ended March 31, 2022 and 2021 included 136 and three spot vessel days, respectively, at near full utilization.

(3) Consists of ROVs and trenchers.

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

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Three Months Ended

September 30,

Well Intervention

Net Revenues.

Our consolidated net revenues for the three-month period ended September 30, 2021 decreased by 7% as compared to the same period in 2020, reflecting lower revenues from our Well Intervention and Robotics segments, offset in part by higher revenues from our Production Facilities segment.

Our Well Intervention revenues decreased by 7% for the three-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting lower rates and vessel utilization in the Gulf of Mexico and Brazil, offset in part by higher utilization in the North Sea and on the Q7000 in West Africa.

Our revenues in the Gulf of Mexico and Brazil were negatively impacted by the completion of our long-term contracts on the Q5000 during the second quarter 2021 and the Siem Helix 1 during the third quarter 2021.

Our revenues in the North Sea and West Africa benefitted from utilization on the Seawell and the Q7000 , both of which were stacked during the three-month period ended September 30, 2020.

Our Robotics revenues decreased by 14% for the three-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting fewer vessel days, including reduced seabed clearance days using spot vessels, as well as a reduction in trenching activities.

Our results included 358 vessel days and 90 trenching days during the three-month period ended September 30, 2021 as compared to 450 vessel days and 154 trenching days during the same period in 2020.

Our Production Facilities revenues increased by 31% for the three-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting higher oil and gas prices, higher production volumes from our wells and higher revenues from the HFRS agreement.

Our consolidated net revenues for the three-month period ended March 31, 2022 decreased by 8% as compared to the same period in 2021, reflecting lower revenues from our Well Intervention segment, offset in part by higher revenues from our Robotics and Production Facilities segments.

Our Well Intervention revenues decreased by 20% for the three-month period ended March 31, 2022 as compared to the same period in 2021, primarily reflecting lower rates and vessel utilization in Brazil and the North Sea, offset in part by higher utilization in West Africa.

Our Brazil operations were on legacy contract rates with Petrobras with near full utilization during the first quarter 2021.

However, during the first quarter 2022, the Siem Helix 2 operated at lower rates under the extended contract with Petrobras and incurred 23 days off contract during its five-year regulatory inspection, and the Siem Helix 1 was operating on a short-term accommodations project offshore Ghana at lower rates.

The Q7000 was fully utilized in West Africa during the first quarter 2022 as compared to 67% utilized during the first quarter 2021.

Gulf of Mexico revenues were nominally changed from the prior year, with the Q5000 ’s higher-margin work on the legacy BP contract during the first quarter 2021 replaced by higher cost integrated projects during the first quarter 2022.

Our Robotics revenues increased by 69% for the three-month period ended March 31, 2022 as compared to the same period in 2021, primarily reflecting higher vessel and ROV activities.

Chartered vessel days increased to 323 days during the first quarter 2022 as compared to 165 days during the first quarter 2021, although vessel utilization was flat at 90% during both periods.

Vessel days during the first quarter 2022 included 136 spot vessel days performing seabed clearance work in the North Sea as compared to three spot vessel days during the first quarter 2021.

ROV and trencher utilization increased to 35% in the first quarter 2022 from 24% during the first quarter 2021, although trenching days decreased to 66 days during the first quarter 2022 as compared to 72 days during the first quarter 2021.

Our Production Facilities revenues increased by 11% for the three-month period ended March 31, 2022 as compared to the same period in 2021, primarily reflecting higher oil and gas prices.

Gross Profit (Loss).

Our consolidated gross profit decreased by $31.6 million for the three-month period ended September 30, 2021 as compared to the same period in 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 $9.6 million for the three-month period ended September 30, 2021 as compared to a gross profit of $21.9 million for the same period in 2020, primarily reflecting lower segment revenues as well as higher costs associated with our activity in West Africa, which resumed in the first quarter 2021.

The gross profit related to our Robotics segment decreased by $1.6 million for the three-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting lower revenues due to fewer spot vessel days on site clearance projects.

The gross profit related to our Production Facilities segment increased by $0.8 million for the three-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting higher revenues during the current quarter.

Our consolidated gross loss was $18.6 million for the three-month period ended March 31, 2022 as compared consolidated gross profit of $14.6 million for the same period in 2021, primarily reflecting decreased profitability in our Well Intervention and Production Facilities segments, offset in part by increased profitability in our Robotics segment.

Our Well Intervention segment had a gross loss of $28.4 million for the three-month period ended March 31, 2022 as compared to a gross profit of $8.7 million for the same period in 2021, primarily reflecting lower segment revenues as well as lower margins in the Gulf of Mexico due to higher integrated project costs.

Our Robotics segment had a gross profit of $3.5 million for the three-month period ended March 31, 2022 as compared to a gross loss of $0.9 million for the same period in 2021, primarily reflecting higher revenues due to increased ROV activity and a higher number of vessel days.

Selling, General and Administrative Expenses.

Our selling, general and administrative expenses were $13.3 million for the three-month period ended September 30, 2021 as compared to $16.1 million for the same period in 2020, primarily reflecting lower employee compensation costs.

Net Interest Expense.

Our net interest expense totaled $5.9 million for the three-month period ended September 30, 2021 as compared to $7.6 million for the same period in 2020, primarily reflecting lower interest expense due to a reduction in our overall debt levels and the elimination of accretion of debt discounts associated with the 2022 Notes, 2023 Notes and 2026 Notes as a result of the adoption of ASU No.

2020-06 beginning January 1, 2021 (Note 5).

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

The $0.1 million loss on extinguishment of long-term debt for the three-month period ended September 30, 2021 was associated with the full repayment of the Term Loan in September 2021 concurrent with our entering into the ABL Facility (Note 5).

The $9.2 million gain on extinguishment of long-term debt for the three-month period ended September 30, 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 selling, general and administrative expenses were $14.4 million for the three-month period ended March 31, 2022 as compared to $15.2 million for the same period in 2021, primarily reflecting lower employee incentive compensation costs.

Other Income (Expense), Net.

Net other expense was $4.0 million for the three-month period ended September 30, 2021 primarily due to foreign currency transaction losses reflecting the weakening of the British pound.

Net other expense was $3.9 million for the three-month period ended March 31, 2022 primarily due to foreign currency transaction losses reflecting the weakening of the British pound.

Net other income was $1.6 million for the same period in 2021 primarily due to foreign currency transaction gains reflecting the strengthening of the British pound.

Income Tax Provision (Benefit).

Income tax benefit was $1.1 million for the three-month period ended September 30, 2021 as compared to a $5.2 million provision for the same period in 2020.

The effective tax rates for the three-month periods ended September 30, 2021 and 2020 were 5.3% and 17.6%, respectively, primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions and the impact of the CARES Act in 2020 (Note 6).

Comparison of Nine Months Ended September 30, 2021 and 2020

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

Nine Months Ended

September 30,

Net revenues —

Well Intervention

Production Facilities

Intercompany eliminations

Gross profit (loss) —

Well Intervention

Production Facilities

Corporate, eliminations and other

Gross margin —

Well Intervention

Production Facilities

Total company

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

Well intervention vessels

Robotics assets (3)

Chartered robotics vessels

The average utilization rates of chartered robotics vessels during the nine-month periods ended September 30, 2021 and 2020 included 240 and 905 spot vessel days, respectively, at near full utilization.

(3) Consists of ROVs, trenchers and ROVDrill.

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

Intercompany segment revenues are as follows (in thousands):

Nine Months Ended

September 30,

Well Intervention

Net Revenues.

Our consolidated net revenues for the nine-month period ended September 30, 2021 decreased by 12% as compared to the same period in 2020, reflecting lower revenues from our Well Intervention and Robotics segments and higher intercompany eliminations, offset in part by higher revenues from our Production Facilities segment.

Our Well Intervention revenues decreased by 7% for the nine-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting lower rates on the Q5000 and lower rates and utilization on the Q4000 in the Gulf of Mexico as well as lower rates and utilization on the Siem Helix 1 in Brazil.

These revenue decreases were offset in part by higher rates and utilization on the Seawell in the North Sea and on the Q7000 in West Africa, both of which were stacked for most of the first nine months in 2020.

Our Robotics revenues decreased by 29% for the nine-month period ended September 30, 2021 as compared to the same period in 2020, reflecting fewer vessel days, including reduced seabed clearance days using spot vessels, as well as a reduction in trenching activities.

Our results included 759 vessel days and 246 trenching days during the nine-month period ended September 30, 2021 as compared to 1,353 vessel days and 315 trenching days during the same period in 2020.

Our Production Facilities revenues increased by 14% for the nine-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting higher HFRS revenues, higher oil and gas prices and higher production volumes from our wells.

The increase in intercompany eliminations was primarily attributable to higher elimination of revenues that our Well Intervention segment earned associated with its P&A work on our Droshky oil and gas properties on behalf of our Production Facilities segment during the nine-month period ended September 30, 2021.

Gross Profit (Loss).

Our consolidated gross profit decreased by $45.5 million for the nine-month period ended September 30, 2021 as compared to the same period in 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 $3.4 million for the nine-month period ended September 30, 2021 as compared to a gross profit of $35.9 million for the same period in 2020, primarily reflecting lower segment revenues as well as higher costs associated with our resumed activity in West Africa during the current period.

The gross profit related to our Robotics segment decreased by $10.8 million for the nine-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting lower revenues due to fewer spot vessel days on site clearance projects.

The gross profit related to our Production Facilities segment increased by $5.2 million for the nine-month period ended September 30, 2021 as compared to the same period in 2020, primarily reflecting higher revenues during the current period.

Goodwill Impairment.

The $6.7 million charge in the nine-month period ended September 30, 2020 reflects the impairment of the entire goodwill balance, which related to our acquisition of a controlling interest in STL (Note 10).

Selling, General and Administrative Expenses.

Our selling, general and administrative expenses were $42.0 million for the nine-month period ended September 30, 2021 as compared to $48.3 million for the same period in 2020, primarily reflecting lower credit loss reserves and employee compensation costs.

Our selling, general and administrative expenses for the nine-month period ended September 30, 2020 included a $2.4 million provision for current expected credit losses (Note 14).

Net Interest Expense.

Our net interest expense totaled $17.9 million for the nine-month period ended September 30, 2021 as compared to $20.4 million for the same period in 2020, primarily reflecting lower interest expense due to a reduction in our overall debt levels and the elimination of accretion of debt discounts associated with the 2022 Notes, 2023 Notes and 2026 Notes as a result of the adoption of ASU No.

2020-06 beginning January 1, 2021 (Note 5), offset in part by the cessation of interest capitalization with the completion of the Q7000 in 2020.

Net interest expense for the nine-month period ended September 30, 2020 excluded $1.2 million in capitalized interest associated with the Q7000 (Note 5).

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

The $0.1 million loss on extinguishment of long-term debt for the nine-month period ended September 30, 2021 was associated with the full repayment of the Term Loan in September 2021 concurrent with our entering into the ABL Facility (Note 5).

The $9.2 million gain on extinguishment of long-term debt for the nine-month period ended September 30, 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.

Other Expense, Net.

Net other expense was $1.4 million for the nine-month period ended September 30, 2021 as compared to $3.7 million for the same period in 2020 primarily due to foreign currency transaction losses reflecting the weakening of the British pound in each of those periods.

Income Tax Benefit.

Income tax benefit was $2.9 million for the nine-month period ended September 30, 2021 as compared to $16.1 million for the same period in 2020.

The effective tax rates for the nine-month periods ended September 30, 2021 and 2020 were 7.5% and 9,777.0%, respectively, primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions and the impact of the CARES Act and the foreign subsidiary restructuring in 2020 (Note 6).

Income Tax Provision.

Income tax provision was $2.1 million for the three-month period ended March 31, 2022 as compared to $0.1 million for the same period in 2021.

The effective tax rates for the three-month periods ended March 31, 2022 and 2021 were (5.4)% and (4.0)%, respectively.

These variances were primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions as well as losses for which no financial statement benefits have been recognized (Note 6).

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):

September 30,

Net working capital

Long-term debt (1)

Liquidity (2)

(1) Current maturities of our long-term debt of $42.8 million and $90.7 million, respectively, are included in net working capital and excluded from long-term debt.

Long-term debt as of September 30, 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 5 for information relating to our long-term debt, including the impact of our adoption of ASU No.

(2) 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 September 30, 2021 included $237.5 million of cash and cash equivalents and $69.6 million of available borrowing capacity under the ABL Facility (Note 5).

Our liquidity at September 30, 2021 excluded $71.3 million of restricted cash securing 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 carrying amounts of our long-term debt are as follows (in thousands):

September 30,

Term Loan (repaid September 2021) (1)

Nordea Q5000 Loan (matured January 2021) (2)

MARAD Debt (matures February 2027)

2022 Notes (mature May 2022) (3)

2023 Notes (mature September 2023) (3)

2026 Notes (mature February 2026) (3)

Total debt (4)

Less current maturities

Long-term debt

(1) The Term Loan was fully repaid in September 2021 concurrent with our entering into the ABL Facility (Note 5).

(2) The Nordea Q5000 Loan was fully repaid upon maturity in January 2021 (Note 5).

(3) As a result of the adoption of ASU No.

2020-06 beginning January 1, 2021, there are no longer any debt discounts associated with the 2022 Notes, 2023 Notes or 2026 Notes (Note 1) .

(4) Amounts are net of any unamortized debt discounts and debt issuance costs .

(1) Long-term debt is net of unamortized debt issuance costs.

Current maturities of our long-term debt of $43.1 million and $42.9 million, respectively, are excluded from long-term debt.

See Note 5 for information relating to our long-term debt.

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.

We define liquidity as cash and cash equivalents, excluding restricted cash, plus available capacity under our credit facility.

Our liquidity at March 31, 2022 included $229.7 million of cash and cash equivalents and $41.2 million of available borrowing capacity under the ABL Facility (Note 5) and excluded $72.9 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, 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 COVID-19 pandemic impacted our operations and our revenues.

We responded by deferring or reducing planned capital expenditures and operating costs during the past two years.

This spending is expected to return with our outlook of increased activity.

Furthermore, we have convertible debt instruments and other term debt maturities during 2022 that we intend to settle in cash.

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.

An ongoing period of weak, or continued decreases in, 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 March 31, 2022, our available borrowing capacity under the ABL Facility was $41.2 million, net of $2.3 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.

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

Nine Months Ended

September 30,

Three Months Ended

Cash provided by (used in):

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Financing activities

Our current requirements for cash primarily reflect the need to fund our operations and capital spending for our current lines of business and to service our debt.

The ongoing COVID-19 pandemic, challenging market conditions and industry-wide spending cuts have impacted our revenues and we expect these events to continue to impact our results into the foreseeable future.

Our operating cash flows are impacted to the extent we cannot replace those revenues or reduce costs.

Despite these challenges, we remain focused on maintaining a strong balance sheet and adequate liquidity.

We have reduced, deferred or cancelled certain planned capital expenditures and reduced our overall cost structure commensurate with our level of activities.

In 2020, we extended our debt maturity profile with refinancing a portion of the 2022 Notes and 2023 Notes with the 2026 Notes.

We have at the same time continued to de-lever our balance sheet with the repayment of the Nordea Q5000 Loan in January 2021 and the Term Loan in September 2021.

We have reduced operating costs through various measures including warm stacking our vessels when idle.

These costs should return with increases in activity.

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 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 the agreements governing our debt, and 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.

Decreases in our borrowing base may limit our ability to fully access the ABL Facility.

At September 30, 2021, our available borrowing capacity under the ABL Facility was $69.6 million, net of $2.2 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.

Operating Cash Flows

Net cash flows provided by operating activities were $121.3 million for the nine-month period ended September 30, 2021 as compared to $58.6 million for the same period 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.

Operating Activities

The decrease in our operating cash flows for the three-month period ended March 31, 2022 as compared to the same period in 2021 primarily reflects lower earnings, higher regulatory recertification costs for our vessels and systems and negative changes in net working capital.

Operating cash flows for the three-month periods ended March 31, 2022 and 2021 included the receipt of $1.1 million and $6.6 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 such as dynamically positioned vessels, topside equipment and subsea systems.

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

Significant sources (uses) of cash associated with investing activities are as follows (in thousands):

Nine Months Ended

September 30,

Capital expenditures:

Well Intervention

Production Facilities

Proceeds from sale of assets

Net cash used in investing activities

Our capital expenditures during the nine-month period ended September 30, 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 the three-month periods ended March 31, 2022 and 2021 reflect 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 and repayments related to our long-term debt.

Net cash outflows from financing activities of $95.7 million for the nine-month period ended September 30, 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 and $28.0 million in full repayment of the Term Loan (Note 5).

Net cash outflows from financing activities of $42.0 million for the nine-month period ended September 30, 2020 primarily reflect the repayment of $36.6 million of our indebtedness and entry into the 2026 Capped Calls as well as the repurchase of a portion of the 2022 Notes and 2023 Notes with proceeds from the issuance of the 2026 Notes (Note 5).

Free Cash Flow

Free cash flow increased by $73.5 million for the nine-month period ended September 30, 2021 as compared to the same period in 2020.

The increase was attributable to the increase in operating cash flows and the decrease in capital expenditures.

Free cash flow is a non-GAAP financial measure.

See “RESULTS OF OPERATIONS” above for the definition and calculation of free cash flow.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of September 30, 2021 and the scheduled years in which the obligations are contractually due (in thousands):

2022 Notes (2)

2023 Notes (3)

2026 Notes (4)

Net cash outflows from financing activities for the three-month period ended March 31, 2022 primarily reflect the repayment of $3.9 million related to the MARAD Debt (Note 5).

Net cash outflows from financing activities for the three-month period ended March 31, 2021 primarily reflect the repayment of $58.2 million related to our indebtedness, including the final maturity of $53.6 million of the Nordea Q5000 Loan.

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 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 March 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 March 31, 2022.

Our 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.

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 5).

Interest related to debt

2 unchanged sentences

Total cash obligations

(1) Excludes unsecured letters of credit outstanding at September 30, 2021 totaling $2.2 million.

These letters of credit may be issued to support various obligations, such as contractual obligations, contract bidding and insurance activities.

(2) Notes mature in May 2022.

See Note 5 for additional information.

(3) Notes mature in September 2023.

See Note 5 for additional information.

(4) Notes mature in February 2026.

See Note 5 for additional information.

(5) Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at September 30, 2021 for variable rate debt.

(1) Operating leases include vessel charters and facility and equipment leases.

At September 30, 2021, our commitment related to long-term vessel charters totaled approximately $180.3 million, of which $73.4 million was related to the non-lease (services) components that are not included in operating lease liabilities in the condensed consolidated balance sheet as of September 30, 2021.

At March 31, 2022, our commitment related to long-term vessel charters totaled approximately $268.4 million, of which $111.8 million was related to the non-lease (services) components that are not included in operating lease liabilities in the condensed consolidated balance sheet as of March 31, 2022.

Other material cash requirements

Other material cash requirements include the following:

Decommissioning.

We have decommissioning obligations associated with our oil and gas properties (Note 11).

Those obligations approximate $31.0 million (undiscounted) as of March 31, 2022 and are all expected to be paid during the next 12 months.

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

Regulatory recertification and dry dock.

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

Recertification 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.

The timing of these costs can vary.

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 ABL Facility and access to capital markets.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our discussion and analysis of our financial condition and results of operations, as reflected in the condensed consolidated financial statements and related footnotes, are prepared in conformity with GAAP.

As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented.

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 may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

For information regarding our critical accounting estimates and policies, please read our “Critical Accounting Estimates and Policies” as disclosed in our 2020 Form 10-K.

These estimates involve a significant level of estimation uncertainty and may change over time as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

For information regarding our critical accounting estimates, see our “Critical Accounting Estimates” as disclosed in our 2021 Form 10-K.

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-Q

Item 2. Management’s Discussion and Analysis