Item 7. Management’s Discussion and Analysis
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements located in Item 8. Financial Statements and Supplementary Data of this Annual Report. Any reference to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Item 8. Financial Statements and Supplementary Data of this Annual Report. The results of operations reported and summarized below are not necessarily indicative of future operating results. This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under Item 1A. Risk Factors and located earlier in this Annual Report.
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EXECUTIVE SUMMARY
Our Business
We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. The services we offer to the oil and gas market cover the lifecycle of an offshore oil or gas field, and the services we offer to the renewable energy market are currently focused on offshore wind farm projects, including trenching and cable burial and seabed clearance operations. Our well intervention fleet includes seven purpose-built well intervention vessels and 10 intervention systems. Our robotics equipment includes 43 work-class ROVs and four trenchers. We charter robotics support vessels on both long-term and spot bases to facilitate our ROV and trenching operations. Our well intervention and robotics operations are geographically dispersed throughout the world. Our Production Facilities segment includes the HP I , the HFRS and our ownership of oil and gas properties.
Economic Outlook and Industry Influences
Demand for our services is primarily influenced by the condition of the oil and gas and the renewable energy markets, in particular, the willingness of offshore energy companies to spend on operational activities and capital projects. The performance of our business is largely affected by the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, global health, and several other factors, including:
● 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 capital for capital projects and production operations;
● the environmental and social 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;
● 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, including restrictions on oil and gas leases, and their interpretation and enforcement;
● environmental and other governmental regulations; and
● 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.
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Historically, drilling rigs have been the asset class used for offshore well intervention work, and rig day rates are a pricing indicator for our services. Our customers have used drilling rigs on existing long-term contracts (rig overhang) to perform well intervention work instead of new drilling activities. Lower volumes of work and lower day rates quoted by drilling rig contractors, combined with rig overhang, affects the utilization and/or rates we can achieve for our assets and services. Furthermore, additional volatile and uncertain macroeconomic conditions in some regions and countries around the world as well as ESG initiatives may impact our existing contracts and contracting opportunities and may introduce further volatility into our operations and/or financial results.
The ongoing COVID-19 pandemic has resulted in new market dynamics and challenges to us, including increased costs related to our supply chain, logistics and human capital resources. We have sought to minimize the direct impact of COVID-19 on our offshore workforce with crew changes that comport with travel restrictions and quarantine measures. While the full impact of the COVID-19 pandemic, including the duration of its negative impact on economic activity, remains unknown, we expect such impact to continue to be felt by our industry into the foreseeable future. The uncertainty and other conditions of the current environment have resulted in challenges to renew or secure long-term contracts for our vessels and systems, as operators have been less willing to commit to future spending. These developments have also impacted, and are expected to continue to impact, many other aspects of our industry and the global economy, including limiting access to and use of capital across various sources and markets, disrupting supply chains and increasing costs, and negatively affecting human capital resources including complicating offshore crew changes due to health and travel restrictions as well as the overall health of the global workforce.
Over the near-term, as oil and gas companies evaluate their budgetary spend allocations, we expect they may be weighted towards short-cycle production enhancement of existing wells rather than new long-cycle exploration projects, as historically enhancement is less expensive per incremental barrel of oil than exploration. Over the longer term, we expect oil and gas companies to increasingly focus on optimizing production of their existing subsea wells. Moreover, as the subsea tree base expands and ages, the demand for P&A services should persist. Our well intervention and robotics operations service the lifecycle of an oil and gas field and provide P&A services at the end of the life of a field as required by governmental regulations, and we believe that we have a competitive advantage in performing these services efficiently.
We expect the fundamentals for our business will remain favorable over the longer term as the need to prolong well life in oil and gas production and safely decommission end of life wells are primary drivers of demand for our services. This expectation is based on multiple factors, including (1) maintaining the optimal production of a well through enhancement is fundamental to maximizing the overall economics of well production; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling; and (3) extending the production of offshore wells not only maximizes a well’s production economics but also enables the financial benefit of delaying P&A costs, which can be substantial.
Demand for our services in the renewable energy market is affected by various factors, including the pace of consumer shift towards renewable energy sources, global electricity demand, technological advancements that increase the production and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water, and government subsidies for renewable energy projects.
We are subject to the effects of changing prices. Inflation rates have been relatively low and stable over the previous three decades; however, in 2021 due in part to supply chain disruptions and the effects of the COVID-19 pandemic, inflation rates began to rise significantly. Although we are able to reduce some of our exposure to price increases through the rates we charge, we bear the costs of operating and maintaining our assets, including labor and material costs as well as recertification and dry dock costs. While the cost outlook is not certain, we believe that we can manage these inflationary pressures by introducing appropriate sales price adjustments and by actively pursuing internal cost reduction efforts. However, competitive market pressures may affect our ability to recoup these price increases through the rates we charge, which may result in reductions in our operating margins and cash flows in the future.
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Business Activity Summary
In recent years, we have maintained a relatively strong balance sheet and enhanced our financial position through various means including securities offerings (the last of which occurred in August 2020) and executing a new five-year credit facility during 2021, which have allowed us to focus on our operations.
We re-activated the Q7000 in January 2021 and the Seawell in June 2021 after warm-stacking the vessels during part of 2020 due in part to the COVID-19 pandemic. The Q7000 performed well intervention work offshore Nigeria for most of 2021. The Seawell performed various work scopes in the North Sea during the second and third quarters of 2021.
In March 2021, we entered into a new agreement to provide various operators with access to the HFRS for well control purposes in the Gulf of Mexico through at least March 31, 2023.
We completed our five-year contract with BP for the Q5000 in April 2021. We also completed our four-year contracts with Petrobras for the Siem Helix 1 in August 2021 and the Siem Helix 2 in December 2021. Both the Q5000 and the Siem Helix 1 are currently working in the spot market. The Petrobras contract for the Siem Helix 2 was extended at reduced rates for one year until December 2022.
During 2021, we continued to improve our health and safety protocols in order to navigate through the COVID-19 pandemic, including significant measures to protect both onshore and offshore personnel.
We have continued to expand our services and offerings into the offshore renewable energy sector. During 2021, we performed site clearance and/or ROV support work on multiple renewable energy projects in the Asia Pacific and North Sea regions.
Backlog
Backlog is defined as firm commitments represented by signed contracts. As of December 31, 2021, our consolidated backlog totaled $348 million, of which $246 million is expected to be performed in 2022. As of December 31, 2021, our contract with Petrobras to provide well intervention services offshore Brazil with the Siem Helix 2 chartered vessel and our fixed fee agreement for the HP I represented approximately 37% of our total backlog. As of December 31, 2020, the total backlog associated with our operations was $407 million. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as services are often added but may sometimes be subtracted; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in backlog.
RESULTS OF OPERATIONS
Non-GAAP Financial Measures
A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under U.S. generally accepted accounting principles (“GAAP”). Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.
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We measure our operating performance based on EBITDA, Adjusted EBITDA and free cash flow. EBITDA, Adjusted EBITDA and free cash flow are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use EBITDA, Adjusted EBITDA and free cash flow to monitor and facilitate internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of EBITDA, Adjusted EBITDA and free cash flow provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand and compare our results to other companies that have different financing, capital and tax structures. Other companies may calculate their measures of EBITDA, Adjusted EBITDA and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA and free cash flow should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other income or cash flow data prepared in accordance with GAAP.
We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets and non-cash gains and losses on equity investments are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets and the general provision (release) for current expected credit losses, if any. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments, which are excluded from EBITDA as a component of net other income or expense. We define free cash flow as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. In the following reconciliation, we provide amounts as reflected in the condensed consolidated financial statements unless otherwise noted.
The reconciliation of our net income (loss) to EBITDA and Adjusted EBITDA is as follows (in thousands):
Year Ended December 31,
2021
2020
2019
Net income (loss)
$
(61,684)
$
20,084
$
57,697
Adjustments:
Income tax provision (benefit)
(8,958)
(18,701)
7,859
Net interest expense
23,201
28,531
8,333
(Gain) loss on extinguishment of long-term debt
136
(9,239)
18
Other (income) expense, net
1,490
(4,724)
(1,165)
Depreciation and amortization
141,514
133,709
112,720
Goodwill impairment
—
6,689
—
Gain on equity investment
—
(264)
(1,613)
EBITDA
95,699
156,085
183,849
Adjustments:
(Gain) loss on disposition of assets, net
631
(889)
—
General provision (release) for current expected credit losses
(54)
746
—
Realized losses from foreign exchange contracts not designated as hedging instruments
—
(682)
(3,761)
Adjusted EBITDA
$
96,276
$
155,260
$
180,088
The reconciliation of our cash flows from operating activities to free cash flow is as follows (in thousands):
Year Ended December 31,
2021
2020
2019
Cash flows from operating activities
$
140,117
$
98,800
$
169,669
Less: Capital expenditures, net of proceeds from sale of assets
(8,271)
(19,281)
(138,304)
Free cash flow
$
131,846
$
79,519
$
31,365
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Comparison of Years Ended December 31, 2021 and 2020
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. The following table details various financial and operational highlights for the periods presented (dollars in thousands):
Year Ended December 31,
Increase/(Decrease)
2021
2020
Amount
Percent
Net revenues —
Well Intervention
$
516,564
$
539,249
$
(22,685)
(4)
%
Robotics
137,295
178,018
(40,723)
(23)
%
Production Facilities
69,348
58,303
11,045
19
%
Intercompany eliminations
(48,479)
(42,015)
(6,464)
$
674,728
$
733,555
$
(58,827)
(8)
%
Gross profit (loss) —
Well Intervention
$
(21,262)
$
41,037
$
(62,299)
(152)
%
Robotics
13,441
22,716
(9,275)
(41)
%
Production Facilities
25,024
17,883
7,141
40
%
Corporate, eliminations and other
(1,810)
(1,727)
(83)
$
15,393
$
79,909
$
(64,516)
(81)
%
Gross margin —
Well Intervention
(4)
%
8
%
Robotics
10
%
13
%
Production Facilities
36
%
31
%
Total company
2
%
11
%
Number of vessels or robotics assets (1) / Utilization (2)
Well intervention vessels
7 / 67
%
7 / 67
%
Robotics assets (3)
47 / 36
%
49 / 34
%
Chartered robotics vessels
3 / 97
%
2 / 94
%
(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. Utilization rates of chartered robotics vessels in 2021 and 2020 included 477 and 1,057 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. Intercompany segment revenues are as follows (in thousands):
Year Ended December 31,
Increase/
2021
2020
(Decrease)
Well Intervention
$
21,521
$
15,039
$
6,482
Robotics
26,958
26,976
(18)
$
48,479
$
42,015
$
6,464
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.
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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.
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).
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).
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.
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.
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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.
Comparison of Years Ended December 31, 2020 and 2019
Various financial and operational highlights for the years ended December 31, 2020 and 2019 were previously presented in our 2020 Annual Report on Form 10-K.
LIQUIDITY AND CAPITAL RESOURCES
Financial Condition and Liquidity
The following table presents certain information useful in the analysis of our financial condition and liquidity (in thousands):
December 31,
2021
2020
Net working capital
$
251,255
$
246,338
Long-term debt (1)
262,137
258,912
Liquidity
304,660
451,532
(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. 2020-06.
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
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. We believe that our cash on hand, internally generated cash flows and availability under the ABL Facility will be sufficient to fund our operations and service our debt over at least the next 12 months.
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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. 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.
Cash Flows
The following table provides summary data from our consolidated statements of cash flows (in thousands):
Year Ended December 31,
2021
2020
2019
Cash provided by (used in):
Operating activities
$
140,117
$
98,800
$
169,669
Investing activities
(8,271)
(19,281)
(142,385)
Financing activities
(95,997)
(52,578)
(45,818)
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.
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.
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).
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.
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Long-term debt and other contractual commitments
The following table summarizes the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for property and equipment and operating lease obligations, as of December 31, 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. 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 8).
Total
Short-Term
Long-Term
MARAD debt
$
48,850
$
7,937
$
40,913
2022 Notes
35,000
35,000
—
2023 Notes
30,000
—
30,000
2026 Notes
200,000
—
200,000
Interest related to debt
66,875
17,832
49,043
Property and equipment
4,943
4,863
80
Operating leases (1)
179,305
102,030
77,275
Total cash obligations
$
564,973
$
167,662
$
397,311
(1) Operating leases include vessel charters and facility and equipment leases. At December 31, 2021, our commitment related to long-term vessel charters totaled approximately $156.2 million, of which $63.6 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, 2021 .
Other material cash requirements
Other material cash requirements include the following:
Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 16). 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.
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.
CRITICAL ACCOUNTING ESTIMATES
Our discussion and analysis of our financial condition and results of operations, as reflected in the consolidated financial statements and related footnotes included in Item 8 . Financial Statements and Supplementary Data of this Annual Report, are prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that have had or are reasonably likely to have a material impact on our financial condition or results of operations. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates involve a significant level of estimation uncertainty and may change over time as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We believe that the most critical accounting estimates are described below. See Note 2 to our consolidated financial statements for a detailed discussion on the application of our accounting policies.
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Table of Contents
Property and Equipment
We review our property and equipment for impairment indicators at least quarterly or whenever changes in facts and circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. We evaluate impairment indicators considering the nature of the asset or asset group, the future economic benefits of the asset or asset group, historical and estimated future profitability measures, and other external market conditions or factors that may be present. We often estimate future earnings and cash flows of our assets to corroborate our determination of whether impairment indicators exist. If impairment indicators suggest that the carrying amount of an asset may not be recoverable, we determine whether an impairment has occurred by estimating undiscounted cash flows of the asset and comparing those cash flows to the asset’s carrying value. If the undiscounted cash flows are less than the asset’s carrying value (i.e., the asset is unrecoverable), impairment, if any, is recognized for the difference between the asset’s carrying value and its estimated fair value. The expected future cash flows used for the assessment of recoverability are based on judgmental assessments of operating costs, project margins and capital project spending, considering information available at the date of review. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible.
The determination of the appropriate asset groups at which to evaluate impairment, the review of property and equipment for impairment indicators, the projection of future cash flows of property and equipment, and the estimated fair value of any property and equipment that may be deemed unrecoverable involve significant judgment and estimation by our management. Changes to those judgments and estimations could require us to recognize impairment charges in the future.