DIAMOND OFFSHORE DRILLING, INC. The following discussion should be read in conjunction with Item 1A, "Risk Factors" and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
This section of this Form 10-K generally discusses 2020 and 2019 items and year-to-year comparisons between 2020 and 2019. For a discussion of our financial condition and results of operations for 2019 compared to 2018, please refer to Item 7 of Part II, "Management's Discussion and Analysis of Financial Condition and Results of Operations" in our Annual Report on Form 10-K/A for the year endedDecember 31, 2019 filed with theSEC onFebruary 18, 2020 . We provide contract drilling services to the energy industry around the globe with a fleet of 13 offshore drilling rigs, consisting of four drillships and nine semisubmersible rigs, including two semisubmersible rigs that are cold stacked as of the date of this report. Our current fleet excludes the Ocean America andOcean Rover , which we are actively marketing for sale. See "- Results of Operations - Impairment of Assets" and Note 4 "Asset Impairments" to our Consolidated Financial Statements in Item 8 of this report.
Recent Developments
Since the commencement of the Chapter 11 Cases, we have continued to operate our business as a "debtor-in-possession" under the jurisdiction of theBankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of theBankruptcy Court . Additionally, as a debtor-in-possession, certain of our activities are subject to review and approval by theBankruptcy Court , including, among other things, the incurrence of secured indebtedness, material asset dispositions, and other transactions outside the ordinary course of business. There can be no guarantee that the Chapter 11 Cases will be completed successfully or in the time frame contemplated by the PSA. The Consenting Stakeholders and we made certain customary commitments to each other, including the Consenting Stakeholders committing to vote to approve the Plan. Through the financial restructuring contemplated in the PSA and the Plan, we, the Debtors, expect to emerge from the Chapter 11 cases with a capital structure that we expect will position the Debtors for future success in the offshore drilling industry. The risks and uncertainties surrounding the Chapter 11 Cases, the defaults under our Debt Instruments, and the weak industry conditions impacting our business raise substantial doubt as to our ability to continue as a going concern. The accompanying Consolidated Financial Statements have been prepared in accordance withU.S. GAAP, which contemplate our continuation as a going concern. For additional information concerning our Chapter 11 Cases, see "- Liquidity and Capital Resources," "Risk Factors - Risks Related to Our Chapter 11 Cases -" in Item 1A of this report and Note 2 "Chapter 11 Proceedings" and Note 18 "Subsequent Event" to our Consolidated Financial Statements included in Item 8 of this report. Market Overview The offshore contract drilling market continues to be severely challenged by an oversupply of rigs and continued depressed commodity prices, leading to a continuation of the prolonged industry downturn, a reduction in the number of drilling projects being sanctioned and increased competition. The global COVID-19 outbreak and resulting measures to mitigate the spread of the virus, including government-imposed lockdowns, restrictions and travel bans, contributed to a dramatic fall in demand for oil during 2020. The modest success of COVID-19 restrictions and mitigation protocols in slowing the spread of the virus and the recent development and ongoing distribution of vaccines to combat COVID-19 have resulted in the easing of lockdowns and restrictions in some areas, as well as a gradual increase in demand for oil. However, the increase in demand has been tempered by struggling economies in parts of the globe remaining in various stages of lockdown due to a resurgence in COVID-19 cases. Commodity prices have risen modestly since the start of the second quarter of 2020, primarily due to an agreement reached by theOrganization of Petroleum Exporting Countries and other oil producing nations on oil 33 -------------------------------------------------------------------------------- production quotas. The production cuts agreed to inApril 2020 were subject to a tapering plan that increased oil production at points during the remainder of 2020 and into 2021. As of the date of this report, the price for Brent crude oil had risen to the$60 -per-barrel range, buoyed by optimism resulting from the rollout of COVID-19 vaccines and aJanuary 2021 agreement bySaudi Arabia to reduce oil production to partially offset an increase in Russian production. Despite the modest recovery in commodity price since the first quarter of 2020, some analysts expect downward pressure on oil prices to persist in 2021 due to continuing concerns related to COVID-19 and the uncertain longevity of oil production quotas. Some industry analysts also predict that oil demand recovery/growth will be slowed by increasing fuel efficiency standards and decarbonization efforts. As a result, depressed commodity prices could continue for the foreseeable future. As a result of low commodity prices and uncertain global demand, many exploration and production companies, including some of our customers, made significant reductions in their capital spending programs in 2020, resulting in the early release of some offshore rigs from drilling programs or termination of contracts. Other drilling programs were paused or put on hold in response to the need for COVID-19 containment. Some industry analysts predict that capital spending programs in 2021 will remain flat or perhaps decline compared to 2020. Given the continued uncertainty around COVID-19 and other macroeconomic factors, many customers have elected to defer previously sanctioned offshore drilling projects, which negatively impacts utilization. At the end of 2020, based on industry reports, global floater contracted utilization was approximately 60%, with 126 of 212 available rigs contracted. In addition, industry analysts report that 26 floater rigs remain on order, with no floater deliveries having occurred in 2020. Only two of the twelve rigs on order scheduled for delivery in 2021 have been contracted for future work. The remaining rigs on order, none of which are contracted for future work, are scheduled for delivery in 2022 and 2023. Industry analysts also estimate that available rig supply will increase in 2021 as more than 50 of the currently contracted floaters will complete their contracts during the year and be available, increasing competition. To manage supply and reduce expenses in an oversupplied and highly competitive market, drilling contractors retired 24 floaters during 2020 based on industry data. Additionally, during periods of rig oversupply, it is not uncommon for a drilling contractor to elect to forego upcoming special surveys of rigs rolling off contract with no future work, resulting in the cold stacking or ultimate retirement of a rig. Historically, the longer a drilling rig remains cold stacked, the cost of reactivation increases and the likelihood of reactivation decreases. During 2020, we recognized asset impairments aggregating$842.0 million to write down four semisubmersible rigs to their estimated fair values. If market fundamentals in the offshore oil and gas industry continue to deteriorate or a market recovery is further delayed, we may be required to recognize additional impairment charges in future periods. As of the date of this report, we have two cold-stacked semisubmersible rigs, one of which has not been previously impaired. See "- Results of Operations - Impairment of Assets" and Note 4 "Asset Impairments" to our Consolidated Financial Statements in Item 8 of this report. As a result of the continuing protracted industry downturn and these challenges, we are continuing to actively seek ways to drive efficiency, reduce non-productive time and provide technical innovation to our customers. We expect these innovations and efficiencies to result in faster and safer drilling and completion of wells, leading to lower overall well costs to the benefit of our customers.
See "- Contract Drilling Backlog" for future commitments of our rigs during 2021 through 2024.
Contract Drilling Backlog
Contract drilling backlog, as presented below, includes only firm commitments
(typically represented by signed contracts) and is calculated by multiplying the
contracted operating dayrate by the firm contract period. Our calculation also
assumes full utilization of our drilling equipment for the contract period
(excluding scheduled shipyard and survey days); however, the amount of actual
revenue to be earned and the actual periods during which revenues will be earned
will be different than the amounts and periods shown in the tables below due to
various factors. Utilization rates, which generally approach 92-98% during
contracted periods, can be adversely impacted by downtime due to various
operating factors including weather conditions and unscheduled downtime for
repairs and maintenance, as well as COVID-19 related delays. Contract drilling
backlog excludes revenues for mobilization, demobilization, contract preparation
and customer reimbursables. No revenue is generally earned during periods of
downtime for regulatory surveys. Changes in our contract drilling backlog
between periods are generally a function
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of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our contracts, which could adversely affect our reported backlog.
See "Risk Factors - Risks Related to Our Business and Operations - We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue ultimately will be realized" in Item 1A of this report.
The backlog information presented below does not, nor is it intended to, align with the disclosures related to revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 3 "Revenue from Contracts with Customers" to our Consolidated Financial Statements in Item 8 of this report. Contract drilling backlog includes only future dayrate revenue as described above, while the disclosure in Note 3 excludes dayrate revenue and only reflects expected future revenue for mobilization, demobilization and capital modifications to our rigs, which are related to non-distinct promises within our signed contracts. The following table reflects our contract drilling backlog attributable to future operations as ofJanuary 1, 2021 (based on information available at that time),October 1, 2020 (the date reported in our Quarterly Report on Form 10-Q for the quarter endedSeptember 30, 2020 ), andJanuary 1, 2020 (the date reported in our Annual Report on Form 10-K for the year endedDecember 31, 2019 ) (in millions). January 1, October 1, January 1, 2021(1) 2020(1) 2020(1) Contract Drilling Backlog$ 1,187 $ 1,169 $ 1,611
(1) Contract drilling backlog as of
1, 2020 excludes future commitment amounts totaling approximately
million,
customer in the form of a guarantee of gross margin to be earned on future
contracts or by direct payment, pursuant to terms of an existing contract.
The following table reflects the amount of our contract drilling backlog by year
as of
For the Years Ending December 31,
Total 2021 2022 2023 2024
Contract Drilling Backlog (1)
$ 3
(1) Contract drilling backlog as of
commitments totaling an aggregate of approximately
three-year period ending
contract, these amounts are payable by a customer in the form of a guarantee
of gross margin to be earned on future contracts or by direct payment at the
end of such period.
The following table reflects the percentage of rig days committed by year as ofJanuary 1, 2021 . The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs, including cold-stacked rigs, multiplied by the number of days in a particular year). For the Years Ending December 31, 2021 2022 2023 2024 Rig Days Committed (1) 73% 40% 10% 0%
(1) As of
currently known and scheduled for contract preparation, mobilization of rigs,
surveys and extended repair and maintenance projects for the years 2021 and
2022, respectively.
Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows
Operating Income. Our operating income is primarily a function of contract
drilling revenue earned less contract drilling expenses incurred or recognized.
The two most significant variables affecting our contract drilling revenue are
the dayrates earned and utilization rates achieved by our rigs, each of which is
a function of rig supply and
35
-------------------------------------------------------------------------------- demand in the marketplace. These factors are not entirely within our control and are difficult to predict. We generally recognize revenue from dayrate drilling contracts as services are performed. Consequently, when a rig is idle, no dayrate is earned and revenue will decrease as a result. Revenue is affected by the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard projects. In connection with certain drilling contracts, we may receive fees for the mobilization and demobilization of equipment. In addition, some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements for which we may or may not be compensated. We recognize these fees ratably as services are performed over the initial term of the related drilling contracts. We defer mobilization and contract preparation fees received (on either a lump-sum or dayrate basis), as well as direct and incremental costs associated with the mobilization of equipment and contract preparation activities, and amortize each, on a straight-line basis, over the term of the related drilling contracts. As noted above, demobilization revenue expected to be received upon contract completion is estimated and is also recognized ratably over the initial term of the contract. Operating income also fluctuates due to varying levels of contract drilling expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment, which generally are not affected by changes in dayrates and short-term reductions in utilization. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or warm-stacked state with a full crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of our customer when a rig is under contract. However, if a rig is expected to be idle for an extended period of time, we may reduce the size of a rig's crew and take steps to "cold stack" the rig, which lowers expenses and partially offsets the impact on operating income. The cost of cold stacking a rig can vary depending on the type of rig. The cost of cold stacking a drillship, for example, is typically substantially higher than the cost of cold stacking an older floater rig. The principal components of our operating expenses include direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate. In addition, the costs associated with training employees can be significant. Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is performing, as well as the age and condition of the equipment and the regions in which our rigs are working. See "- Contractual Cash Obligations - Pressure Control by the Hour®." Restructuring Costs. During 2020, we incurred$60.9 million in incremental professional fees for attorneys, financial advisors and other professionals related to the consideration of restructuring alternatives, including the preparation for filing of the Chapter 11 Cases and related matters, and in connection with the Chapter 11 Cases. We expect to incur incremental costs of approximately$70 million during 2021 for similar professionals and services. See "- Results of Operations - Restructuring and Separation Costs" and "- Results of Operations - Reorganization items, net." COVID-19 Pandemic. The most immediate impact and risks to our business as a result of the COVID-19 outbreak and efforts to mitigate the spread of the virus have been to the safety of our personnel, as well as travel restrictions that have challenged the ability to move personnel, equipment, supplies and service personnel to-and-from our drilling rigs. In some instances, we have asked our rig crews to quarantine in-country before offshore rotations, as well as to remain in country after their offshore rotation, resulting in incremental costs for salaries and other employee-related expenses such as meals and lodging. Our employee travel costs have also increased due to decreased passenger capacity on carriers, requiring additional trips to move personnel. In some cases, we incur freight surcharges to bring equipment and supplies to our rigs. We have also incurred additional costs to deep-clean facilities, for medical personnel and to purchase medical supplies and personal protective equipment. With respect to protecting our crews and, thus, our rig operations, we have adopted COVID-19 testing requirements based on the regions in which our rigs are operating that primarily require testing of all personnel prior to an offshore rotation or travel from theU.S. to an international location. Additionally, for most of our rigs we have implemented the following health protocols once personnel are on board a rig: 36
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• 14-day isolation of our crew prior to reporting for crew change;
• decreased crew change frequency to minimize the frequency of travel and
turnover of crew;
• twice daily temperature checks;
• eliminated large group meetings;
• reduced seating capacity in galley for social distancing;
• eliminated self-servicing of food;
• increased frequency of disinfectant cleaning in communal areas on the rig;
and
• reduced number of personnel in elevators to a maximum of four.
In addition, the Ocean Monarch was previously expected to commence drilling
operations in Myanmar in late March 2020 . As a result of the COVID-19 pandemic
and restrictions put in place by the Republic of the Union of Myanmar , the start
of the drilling contract was delayed until December 2020 . During the delay,
the Ocean Monarch was warm stacked in Johor Bahru, Malaysia where it earned a
standby rate intended to cover our daily operating costs while waiting to
commence its contract. The Ocean Monarch commenced drilling operations in
December 2020 and follows enhanced protocols intended to protect the health of
the rig crew and prevent a shutdown of rig operations.
During the year ended December 31, 2020 , we incurred incremental costs of
approximately $12.5 million related to the COVID-19 pandemic. We expect to incur
similar types of costs during 2021 but cannot predict the future financial
impact of our response to the pandemic nor its duration in this fluid
environment. As such, costs may be more than projected, perhaps by a material
amount.
Regulatory Surveys and Planned Downtime. Our operating income is negatively
impacted when we perform certain regulatory inspections, which we refer to as a
special survey, that are due every five years for most of our rigs. The
inspection interval for our North Sea rigs is two-and-one-half years. Operating
revenue decreases because these special surveys are generally performed during
scheduled downtime in a shipyard. Operating expenses increase as a result of
these special surveys due to the cost to mobilize the rigs to a shipyard,
inspection costs incurred and repair and maintenance costs, which are recognized
as incurred. Repair and maintenance activities may result from the special
survey or may have been previously planned to take place during this mandatory
downtime. The number of rigs undergoing a special survey will vary from year to
year, as well as from quarter to quarter.
During 2021, we expect to spend approximately 325 days of planned downtime,
including approximately an aggregate 155 days, 95 days and 55 days for
mobilization and contract preparation activities for the Ocean BlackRhino, Ocean
Courage and Ocean Onyx, respectively. We also expect to spend approximately 20
days for an intermediate survey for the Ocean Patriot in the first quarter of
2021. We can provide no assurance as to the exact timing and/or duration of
downtime associated with these or other projects. See " - Contract Drilling
Backlog."
Physical Damage and Marine Liability Insurance . We are self-insured for physical
damage to rigs and equipment caused by named windstorms in the U.S. Gulf of
Mexico . If a named windstorm in the U.S. Gulf of Mexico causes significant
damage to our rigs or equipment, it could have a material adverse effect on our
financial condition, results of operations and cash flows. Under our current
insurance policy, we carry physical damage insurance for certain losses other
than those caused by named windstorms in the U.S. Gulf of Mexico for which our
deductible for physical damage is $25.0 million per occurrence. We do not
typically retain loss-of-hire insurance policies to cover our rigs.
In addition, we carry marine liability insurance covering certain legal
liabilities, including coverage for certain personal injury claims, and
generally covering liabilities arising out of or relating to pollution and/or
environmental risk. We believe that the policy limit for our marine liability
insurance is within the range that is customary for companies of our size in the
offshore drilling industry and is appropriate for our business. Under these
policies our deductibles for marine liability coverage related to insurable
events arising due to named windstorms in the U.S. Gulf of Mexico are $25.0
million for the first occurrence and vary in amounts ranging between $25.0
million and, if
37
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aggregate claims exceed certain thresholds, up to $100.0 million for each
subsequent occurrence, depending on the nature, severity and frequency of claims
that might arise during the policy year. Our deductibles for other marine
liability coverage, including personal injury claims not related to named
windstorms in the U.S. Gulf of Mexico , are $5.0 million for the first occurrence
and vary in amounts ranging between $5.0 million and, if aggregate claims exceed
certain thresholds, up to $100.0 million for each subsequent occurrence,
depending on the nature, severity and frequency of claims that might arise
during the policy year.
Impact of Changes in Tax Laws or Their Interpretation. We operate through our
various subsidiaries in a number of jurisdictions throughout the world. As a
result, we are subject to highly complex tax laws, treaties and regulations in
the jurisdictions in which we operate, which may change and are subject to
interpretation. Changes in laws, treaties and regulations and the interpretation
of such laws, treaties and regulations may put us at risk for future tax
assessments and liabilities which could be substantial and could have a material
adverse effect on our financial condition, results of operations and cash flows.
Critical Accounting Estimates
Our significant accounting policies are included in Note 1 "General Information" to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows: Property, Plant and Equipment. We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income currently while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. During the years endedDecember 31, 2020 and 2019, we capitalized$137.4 million and$343.8 million , respectively, in replacements and betterments of our drilling fleet. We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the expectation of cold stacking a rig in the near future, contracted backlog of less than one year for a rig, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project, reactivation or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
• dayrate by rig;
• utilization rate by rig if active, warm-stacked or cold-stacked (expressed
as the actual percentage of time per year that the rig would be used at
certain dayrates);
• the per day operating cost for each rig if active, warm-stacked or
cold-stacked;
• the estimated annual cost for rig replacements and/or enhancement programs;
• the estimated maintenance, inspection or other reactivation costs
associated with a rig returning to work;
• salvage value for each rig; and
• estimated proceeds that may be received on disposition of each rig.
Based on these assumptions, we develop a matrix for each rig under evaluation
using multiple utilization/dayrate scenarios, to each of which we assign a
probability of occurrence. We arrive at a projected probability-weighted cash
flow for each rig based on the respective matrix and compare such amount to the
carrying value of the asset to assess recoverability.
38
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The underlying assumptions and assigned probabilities of occurrence for
utilization and dayrate scenarios are developed using a methodology that
examines historical data for each rig, which considers the rig's age, rated
water depth and other attributes and then assesses its future marketability in
light of the current and projected market environment at the time of assessment.
Other assumptions, such as operating, maintenance, inspection and reactivation
costs, are estimated using historical data adjusted for known developments, cost
projections for re-entry of rigs into the market and future events that are
anticipated by management at the time of the assessment.
Management's assumptions are necessarily subjective and are an inherent part of
our asset impairment evaluation, and the use of different assumptions could
produce results that differ from those reported. Our methodology generally
involves the use of significant unobservable inputs, representative of a Level 3
fair value measurement, which may include assumptions related to future dayrate
revenue, costs and rig utilization, quotes from rig brokers, the long-term
future performance of our rigs and future market conditions. Management's
assumptions involve uncertainties about future demand for our services,
dayrates, expenses and other future events, and management's expectations may
not be indicative of future outcomes. Significant unanticipated changes to these
assumptions could materially alter our analysis in testing an asset for
potential impairment. For example, changes in market conditions that exist at
the measurement date or that are projected by management could affect our key
assumptions. Other events or circumstances that could affect our assumptions may
include, but are not limited to, a further sustained decline in oil and gas
prices, cancelations of our drilling contracts or contracts of our competitors,
contract modifications, costs to comply with new governmental regulations,
capital expenditures required due to advances in offshore drilling technology,
growth in the global oversupply of oil and geopolitical events, such as lifting
sanctions on oil-producing nations. Should actual market conditions in the
future vary significantly from market conditions used in our projections, our
assessment of impairment would likely be different.
During 2020, we recorded an aggregate impairment charge of $842.0 million
relating to four drilling rigs. We did not incur an impairment loss in 2019. See
"- Results of Operations - Impairment of Assets" and Note 4 "Asset Impairments"
to our Consolidated Financial Statements in Item 8 of this report.
Income Taxes. We account for income taxes in accordance with accounting
standards that require the recognition of the amount of taxes payable or
refundable for the current year and an asset and liability approach in
recognizing the amount of deferred tax liabilities and assets for the future tax
consequences of events that have been currently recognized in our financial
statements or tax returns. In each of our tax jurisdictions we recognize a
current tax liability or asset for the estimated taxes payable or refundable on
tax returns for the current year and a deferred tax asset or liability for the
estimated future tax effects attributable to temporary differences and
carryforwards. Deferred tax assets are reduced by a valuation allowance, if
necessary, which is determined by the amount of any tax benefits that, based on
available evidence, are not expected to be realized under a "more likely than
not" approach. We make judgments regarding future events and related estimates
especially as they pertain to the forecasting of our effective tax rate, the
potential realization of deferred tax assets such as net operating loss
carryforwards, utilization of foreign tax credits, and exposure to the
disallowance of items deducted on tax returns upon audit.
In several of the international locations in which we operate, certain of our
wholly-owned subsidiaries enter into agreements with other of our wholly-owned
subsidiaries to provide specialized services and equipment in support of our
foreign operations. We apply a transfer pricing methodology to determine the
arm's length amount to be charged for providing the services and equipment and
utilize outside consultants to assist us in the development of such transfer
pricing methodologies. In most cases, there are alternative transfer pricing
methodologies that could be applied to these transactions and, if applied, could
result in different chargeable amounts.
39--------------------------------------------------------------------------------
Results of Operations
Our operating results for contract drilling services are dependent on three
primary metrics or key performance indicators: revenue-earning, or R-E, days,
rig utilization and average daily revenue. The following table presents these
three key performance indicators and other comparative data relating to our
revenues and operating expenses (in thousands, except days, daily amounts and
percentages).
Year Ended December 31,
2020 2019
REVENUE-EARNING DAYS (1) 2,936 3,317
UTILIZATION (2) 59 % 56 %
AVERAGE DAILY REVENUE (3) $ 227,000 $ 272,600
CONTRACT DRILLING REVENUE $ 692,753 $ 934,934 REVENUE RELATED TO REIMBURSABLE
EXPENSES 40,934 45,710 TOTAL REVENUES$ 733,687 $ 980,644 CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION$ 618,553 $ 793,412 REIMBURSABLE EXPENSES$ 38,900 $ 45,016 OPERATING LOSS Contract drilling services, net$ 74,200 $ 141,522 Reimbursable expenses, net 2,034 694 Depreciation (320,085 ) (355,596 ) General and administrative expense (56,925 ) (67,878 ) Impairment of assets (842,016 ) - Restructuring and separation costs (17,724 ) - Gain (loss) on disposition of assets 7,375 (1,072 ) Total Operating Loss$ (1,153,141 ) $ (282,330 ) Other income (expense): Interest income 484 6,382
Interest expense, net of amounts capitalized (42,585 ) (122,832 ) Foreign currency transaction loss
(4,498 ) (3,936 )
Reorganization items, net (76,910 ) -
Other, net 560 702
Loss before income tax benefit (1,276,090 ) (402,014 )
Income tax benefit 21,186 44,800
NET LOSS $ (1,254,904 ) $ (357,214 ) (1) An R-E day is defined as a 24-hour period during which a rig earns a dayrate
after commencement of operations and excludes mobilization, demobilization
and contract preparation days.
(2) Utilization is calculated as the ratio of total R-E days divided by the total
calendar days in the period for all specified rigs in our fleet (including
two cold-stacked floater rigs at both
(3) Average daily revenue is defined as total contract drilling revenue for all
of the specified rigs in our fleet per R-E day.
2020 Compared to 2019
Contract Drilling Revenue. Contract drilling revenue decreased$242.2 million in 2020 compared to 2019, primarily due to lower average daily revenue earned ($138.3 million ) and 381 fewer R-E days ($103.9 million ). The decrease in average daily revenue was primarily due to both the Ocean BlackHornet and OceanBlackLion starting new contracts in 2020 at significantly lower dayrates than the rigs' previous contracts and the Ocean Monarch earning a reduced standby rate during most of 2020 due to COVID-19 related delays. R-E days decreased, compared to 2019, primarily due to cold stacking the Ocean Valiant and Ocean GreatWhite (an aggregate 507 fewer R-E days) 40 -------------------------------------------------------------------------------- and incremental downtime attributable to the warm stacking of rigs between contracts (450 fewer R-E days), partially offset by incremental R-E days for the Ocean Endeavor (180 additional R-E days), which was reactivated for a new contract that commenced during the second quarter of 2019, less downtime for planned shipyard projects and mobilization of rigs (266 additional R-E days) and less unplanned downtime for rig repairs and maintenance (130 additional R-E days). The decline in revenues during 2020 was partially offset by revenue recognized during the first quarter of 2020 related to the reimbursement of withholding taxes related to one of our rigs inBrazil ($8.8 million ). Contract Drilling Expense, Excluding Depreciation. Contract drilling expense, excluding depreciation, decreased$174.9 million during 2020 compared to 2019, primarily due to lower amortization of previously deferred contract preparation and mobilization costs ($73.2 million ), primarily related to a 2019 contract in theU.K. for the Ocean GreatWhite and contract completions in 2020, combined with lower costs for repairs, maintenance and inspections ($45.6 million ), labor and personnel ($21.3 million ), equipment rentals ($6.6 million ), the absence of a contingent loss reserve for a non-income tax assessment in 2019 ($7.1 million ) and other decreased rig costs ($10.6 million ). The overall reduction in rig operating expense during 2020 also reflected a reduction in shorebase and overhead costs related to restructuring efforts ($27.0 million ) in 2020. These cost reductions were partially offset by an increase in other rig moving costs, including fuel ($16.5 million ).
Depreciation Expense. Depreciation expense for 2020 decreased
General and Administrative Expense. General and administrative expense decreased$11.0 million during 2020 compared to 2019, primarily due to reduced payroll costs associated with recent restructuring efforts ($3.5 million ), lower travel costs due to COVID-19 related restrictions ($1.7 million ) and a net decrease in other administrative costs ($5.8 million ), including reduced costs associated with our services agreement with Loews Corporation, which was terminated onApril 24, 2020 . Impairment of Assets. During the first quarter of 2020, we recognized an aggregate impairment charge of$774.0 million to write down four of our drilling rigs with indicators of impairment to their estimated fair values. We recognized an additional$68.0 million impairment charge during the fourth quarter of 2020, to further write down the carrying value of one rig previously impaired during the first quarter of 2020 based on additional information regarding future opportunities for the rig. See Note 4 "Asset Impairments" and Note 8 "Financial Instruments and Fair Value Disclosures" to our Consolidated Financial Statements in Item 8 of this report. Restructuring and Separation Costs. Prior to the Petition Date, we incurred$7.4 million in legal and other professional advisor fees in connection with the consideration of restructuring alternatives, including the preparation for filing of the Chapter 11 Cases and related matters. Also, during 2020, we initiated a plan to reduce the number of employees in our world-wide organization in an effort to restructure our business operations and reduce operating costs. As a result of this initiative, we incurred costs of$10.3 million during 2020, primarily for severance and related costs associated with a reduction in personnel in our corporate offices, warehouse facilities and certain of our international shorebase locations. See Note 14 "Restructuring and Separation Costs" to our Consolidated Financial Statements in Item 8 of this report. Interest Expense. Interest expense for 2020 decreased$80.2 million compared to 2019, primarily due to decreased interest recognized on our Senior Notes and Revolving Credit Facility in 2020 as compared to 2019. We ceased accruing interest expense on our senior unsecured debt and borrowings under the Revolving Credit Agreement upon filing the Chapter 11 Cases onApril 26, 2020 . As a result, we did not record$76.7 million and$21.3 million of contractual interest expense related to our Senior Notes and borrowings drawn in 2020 under our Revolving Credit Agreement, respectively, for 2020. See Note 2 "Chapter 11 Proceedings" to our Consolidated Financial Statements in Item 8 of this report. Reorganization Items, net. We recognized$76.9 million in expenses and other net losses directly related to the Chapter 11 Cases in 2020, primarily consisting of incremental professional fees ($53.5 million ) incurred and the write-off of debt issuance costs associated with our Senior Notes ($27.6 million ), partially offset by net gains related to vendor settlements and purchase order cancellations ($4.2 million ). See Note 2 "Chapter 11 Proceedings" to our Consolidated Financial Statements in Item 8 of this report. 41 -------------------------------------------------------------------------------- Income Tax Benefit. We recorded a net income tax benefit of$21.2 million (1.7% effective tax rate) for 2020, compared to an income tax benefit of$44.8 million (11.1% effective tax rate) for 2019. The tax benefit for 2020 included a net tax benefit of$9.7 million due to a partial release of a previously recognized valuation allowance and tax rate change, as a result of the Coronavirus Aid, Relief and Economic Security Act, or the CARES Act. The CARES Act was signed into law onMarch 27, 2020 and allowed a carryback of net operating losses generated in 2018, 2019 and 2020 to each of the five preceding taxable years. Income tax benefit for 2019 included a net$14.2 million income tax benefit associated with the reduction in our estimate of our transition tax liability pursuant to final regulations issued by the Internal Revenue Service inJune 2019 . Other than these discrete tax amounts, the reduction in the effective tax rate in 2020, compared to 2019, was in large part due to$842.0 million in impairment charges recognized in 2020, with no tax benefit, and incremental valuation allowances recorded in 2020 of$ 69.2 million , compared to$30.7 million in 2019.
Liquidity and Capital Resources
As ofJanuary 1, 2021 , our contractual backlog was$1.2 billion , of which$0.7 billion is expected to be realized in 2021. AtDecember 31, 2020 , we had cash available for current operations of$405.9 million .
The terms of the PSA entered into on
(a) a$300.0 million to$400.0 million aggregate principal amount first lien, first out exit revolving credit facility (or Exit Revolving Credit Facility), plus a commitment fee of approximately$3.5 million payable in kind in the form of additional drawn commitments under the Exit Revolving Credit Facility, which shall increase both the amount of drawn and total commitments thereunder, in exchange for providing such new money commitments.;
(b) a
(c) $110.0 million aggregate principal amount in first lien, last out exit notes (or Exit Notes) plus$9.9 million aggregate principal amount of additional Exit Notes issued on account of the Commitment Premium (as defined in the Backstop Agreement) payable in kind in the form of additional Exit Notes.. The PSA contemplates that (i) the Exit Revolving Credit Facility will be fully committed, with up to$100.0 million drawn as of the Effective Date, as defined in the Plan included in the PSA, and (ii)$75.0 million of the Exit Notes will be issued and outstanding as of the Effective Date, excluding$9.9 million aggregate principal amount of additional Exit Notes issued on account of the Commitment Premium, while$35.0 million of the Exit Notes will remain fully committed but undrawn as of the Effective Date and will be available through a delayed draw mechanism pursuant to the terms of the Exit Notes.
See Note 18 "Subsequent Event" to our Consolidated Financial Statements in Item 8 of this report.
Although we anticipate that the financial restructuring pursuant to our Chapter 11 Cases will help address our liquidity concerns, uncertainty remains over theBankruptcy Court's approval and our successful implementation of the Plan and therefore substantial doubt exists as to our ability to continue as a going concern at this time. Financial information in this report has been prepared on the basis that we will continue as a going concern, which presumes that we will be able to realize our assets and discharge our liabilities in the normal course of business as they come due. Financial information in this report does not reflect the adjustments to the carrying values of assets and liabilities and the reported expenses and balance sheet classifications that would be necessary if we were unable to realize our assets and settle our liabilities as a going concern in the normal course of operations. Such adjustments could be material. Our long-term liquidity requirements, the adequacy of capital resources and ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until the Plan, or another Chapter 11 plan of reorganization, has been approved by theBankruptcy Court . If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and could be unable to continue as a going concern and would likely be required to significantly reduce, delay or eliminate capital expenditures, implement further cost reductions, or seek other financing alternatives. 42 -------------------------------------------------------------------------------- Our worldwide cash balances are available to finance both our domestic and foreign activities. If and when circumstances require, we expect to record the withholding tax impact associated with the potential distribution of earnings of our foreign subsidiaries; however, we have not provided income tax on the outside basis difference of our international subsidiaries as management does not intend to dispose of these subsidiaries and structuring alternatives exist to mitigate any potential liability should a disposition take place. We have historically invested a significant portion of our cash flows in the enhancement of our drilling fleet and our ongoing rig equipment replacement and capital maintenance programs. The amount of cash required to meet our capital commitments is determined by evaluating the need to upgrade our rigs to meet specific customer requirements and our rig equipment enhancement, maintenance and replacement programs. We make periodic assessments of our capital spending programs based on current and expected industry conditions and our cash flow forecast. Sources and Uses of Cash Our operating activities provided net cash of$8.4 million in 2020. Our other sources of cash during the year were borrowings under the Revolving Credit Agreement ($436.0 million ) and proceeds from the sales of the Ocean Confidence ($4.6 million ), our corporate headquarters office building inHouston, Texas ($7.5 million ) andTrinidad bonds ($5.9 million ). See "- Credit Agreements" and Note 5 "Supplemental Financial Information" and Note 10 "Credit Agreements and Senior Notes" to our Consolidated Financial Statements in Item 8 of this report.
We used cash aggregating
Cash Flow from Operations. Cash flow from operations in 2020 decreased$0.7 million compared to 2019, primarily due to lower cash receipts for contract drilling services ($157.2 million ), combined with collateral deposits made in support of certain outstanding surety and other bonds and letters of credit ($18.3 million ). The reduction in operating cash inflows was partially offset by the favorable effects of lower net cash expenditures for contract drilling, shorebase support and general and administrative costs in 2020 compared to 2019 ($125.4 million ) and the receipt of cash income tax refunds, net of payments ($30.6 million ) in 2020 compared to net cash taxes paid ($18.8 million ) in 2019. Upgrades and Other Capital Expenditures. As of the date of this report, we expect cash capital expenditures in 2021 to be approximately$120 million to$150 million . Planned spending in 2021 associated with projects under our capital maintenance and replacement programs includes equipment upgrades for the Ocean BlackRhino, Ocean BlackLion andOcean Courage . Credit Agreements. EffectiveMarch 17, 2020 , we terminated our$225.0 million revolving credit agreement, which was scheduled to mature onOctober 22, 2020 . At the time of termination, there were no borrowings outstanding under the facility. We did not incur any early termination penalties in connection with the termination and wrote off$0.5 million in deferred arrangement fees associated with the facility. InMarch 2020 , we borrowed$436.0 million under our$950.0 million senior 5-year Revolving Credit Agreement, which we entered into onOctober 2, 2018 . The principal and interest under the Revolving Credit Agreement became immediately due and payable upon filing of the Chapter 11 Cases, which constituted an event of default under the Revolving Credit Agreement. However, any efforts to enforce such payment obligations are automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors' rights of enforcement in respect of the Revolving Credit Agreement are subject to the applicable provisions of the Bankruptcy Code. The outstanding borrowings and accrued interest have been presented as "Liabilities subject to compromise" in our Consolidated Balance Sheets atDecember 31, 2020 . Additionally, as a result of the filing of the Chapter 11 Cases, we received notification onApril 28, 2020 that the commitments under our Revolving Credit Agreement had been reduced from$950 million to approximately$442.0 million , representing the amount of borrowings outstanding plus the value of a$6.0 million financial letter of credit, which was issued inJanuary 2020 under the Revolving Credit Agreement in support of a previously issued surety bond. 43
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See Note 10 "Credit Agreements and Senior Notes" to our Consolidated Financial Statements in Item 8 of this report.
Senior Notes. As ofDecember 31, 2020 , we had an aggregate$2.0 billion in Senior Notes outstanding with stated maturities at various times beginning in 2023 through 2043. The filing of the Chapter 11 Cases constituted an event of default that accelerated the Company's obligations under our Senior Notes. As a result, the principal and accrued interest thereon are immediately due and payable and have been presented as "Liabilities subject to compromise" in our Consolidated Balance Sheets atDecember 31, 2020 . However, any efforts to enforce such payment obligations are automatically stayed as a result of the filing of the Chapter 11 Cases, and the creditors' rights of enforcement in respect of the Senior Notes are subject to the applicable provisions of the Bankruptcy Code.
See Note 10 "Credit Agreements and Senior Notes" to our Consolidated Financial Statements in Item 8 of this report.
Credit Ratings
Following the commencement of the Chapter 11 Cases, Moody's Investors Service, Inc. andS&P Global Ratings lowered our credit ratings to default status. They subsequently withdrew our issued credit ratings and outlook and have discontinued their rating coverage of the Company.
Contractual Cash Obligations
The following table sets forth our contractual cash obligations atDecember 31, 2020 (in thousands). Payments Due By Period Contractual Obligations (1) Total 2021 2022-2023 2024-2025 Thereafter Senior notes (principal and (3) interest) (2)$ 3,726,909 $ 234,784 $ 476,125 $ 708,875 $ 2,307,125 Credit facility borrowings (4) 466,365 466,365 - - - Well Control Equipment services agreement 211,162 39,113 78,227 78,334 15,488 Operating leases 181,080 33,320 65,176 60,949 21,635 Total obligations$ 4,585,516 $ 773,582 $ 619,528 $ 848,158 $ 2,344,248
(1) The above table excludes
related to uncertain tax positions that could result in a future cash payment
as of
timing of future cash outflows associated with the liabilities recognized in
these balances, we are unable to make reasonably reliable estimates of the
period of cash settlement with the respective taxing authorities.
(2) Contractual obligations related to our Senior Notes are presented in the
table above in accordance with their stated maturities. However, the filing
of the Chapter 11 Cases constituted an event of default that accelerated the
Company's obligations under our Senior Notes. As a result, the principal and
accrued interest thereon are immediately due and payable and have been
presented as "Liabilities subject to compromise" in our Consolidated Balance
Sheets at
(3) Includes unpaid interest on our Senior Notes through
which
Petition Date and
the period after the Petition Date, which has not been recorded in our
Consolidated Statements of Operations for the year ended
(4) Contractual obligations under our Revolving Credit Agreement include
outstanding borrowings in the aggregate amount of
interest accrued through
interest recognized prior to the Petition Date and
contractual interest expense relating to the period after the Petition Date,
which has not been recorded in our Consolidated Statements of Operations for
the year ended December 31, 2020 . However, the exact amount of interest
relating to the period after the Petition Date is subject to final
determination in accordance with the Plan.
44
-------------------------------------------------------------------------------- Pressure Control by the Hour®. In 2016, we entered into a ten-year agreement with a subsidiary of Baker Hughes Company (formerly known as Baker Hughes, aGE company), or Baker Hughes, to provide services with respect to certain blowout preventer and related well control equipment, or Well Control Equipment, on our four drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. In connection with the contractual services agreement, we sold the Well Control Equipment on our drillships to a Baker Hughes subsidiary and are leasing it back over separate ten-year operating leases for approximately$26 million per year in the aggregate. Collectively, we refer to the contractual services agreement and corresponding operating lease agreements with the Baker Hughes affiliate as the "PCbtH program." See Note 11 "Commitments and Contingencies," Note 12 "Leases and Lease Commitments" and Note 18 "Subsequent Event" to our Consolidated Financial Statements in Item 8 of this report. Except for our contractual requirements under the PCbtH program discussed above, we had no other purchase obligations for major rig upgrades or any other significant obligations atDecember 31, 2020 , except for those related to our direct rig operations, which arise during the normal course of business.
Other Commercial Commitments - Letters of Credit
We were contingently liable as ofDecember 31, 2020 in the amount of$32.5 million under certain tax, performance, supersedeas, VAT and customs bonds and letters of credit. Agreements relating to approximately$24.2 million of customs, tax, VAT and supersedeas bonds can require collateral at any time, while the remaining agreements, aggregating$8.3 million , cannot require collateral except in events of default. During the year endedDecember 31, 2020 , a$6.0 million financial letter of credit was issued on our behalf as collateral in support of our outstanding surety bonds. The financial letter of credit was drawn on by the beneficiary inJanuary 2021 and was converted to an adjusted base rate loan under our Revolving Credit Agreement. During 2020, we also made cash collateral deposits of$17.5 million with respect to other bonds and letters of credit, which are recorded in "Other assets" in our Consolidated Balance Sheets atDecember 31, 2020 . The table below provides a list of these obligations inU.S. dollar equivalents and their time to expiration (in thousands). For the Years Ending December 31, Total 2021 2022 Other Commercial Commitments Tax bonds$ 15,172 $ 2,512 $ 12,660 Performance bonds 7,100 7,100 - Collateral letter of credit 6,034 6,034 - Supersedeas bonds 2,600 2,600 - Customs bonds 1,512 1,512 - Other 97 - 97 Total obligations$ 32,515 $ 19,758 $ 12,757
Off-Balance Sheet Arrangements
At
Other
Operations Outside theU.S. Our operations outside theU.S. accounted for approximately 54%, 47% and 41% of our total consolidated revenues for the years endedDecember 31, 2020 , 2019 and 2018, respectively. See "Risk Factors - Regulatory and Legal Risks - Significant portions of our operations are conducted outside theU.S. and involve additional risks not associated withU.S. domestic operations" in Item 1A of this report. Currency Risk. Some of our subsidiaries conduct a portion of their operations in the local currency of the country where they conduct operations, resulting in foreign currency exposure. Currency environments in which we currently have or previously had significant business operations includeAustralia ,Brazil ,Egypt ,Malaysia ,Mexico ,Trinidad and Tobago and theU.K. , creating exposure to certain monetary assets and liabilities denominated in 45
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currencies other than the
To reduce our currency exchange risk, we may, if possible, arrange for a portion of our international contracts to be payable to us in local currency in amounts equal to our estimated operating costs payable in local currency, with the balance of the contract payable inU.S. dollars. The revaluation of liabilities denominated in currencies other than theU.S. dollar related to foreign income taxes, including deferred tax assets and liabilities and uncertain tax positions, is reported as a component of "Income tax benefit" in our Consolidated Statements of Operations. 46
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Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words "expect," "intend," "plan," "predict," "anticipate," "estimate," "believe," "should," "could," "may," "might," "will," "will be," "will continue," "will likely result," "project," "forecast," "budget" and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:
• our ability to continue as a going concern;
• any potential debt restructuring and refinancing and access to sources of
liquidity, including the PSA and the restructuring and new exit financing
facilities contemplated by the PSA;
• our ability to obtain
other requests made to the
including maintaining strategic control as debtors-in-possession and the
outcomes of
in general;
• delays in the Chapter 11 Cases;
• our ability to confirm and consummate the Plan or any other plan of
reorganization that restructures our debt obligations to address our
liquidity issues and allows emergence from the Chapter 11 Cases;
• the effects of the Chapter 11 Cases on our operations, including our
relationships with employees, regulatory authorities, customers,
suppliers, banks, insurance companies and other third parties, and
agreements;
• the effects of the Chapter 11 Cases on the Company and its subsidiaries
and on the interests of various constituents, including holders of our
common stock and debt instruments;
• the length of time that we will operate under Chapter 11 protection and
the continued availability of operating capital during the pendency of the
proceedings;
• the actions and decisions of creditors, regulators and other third parties
that have an interest in the Chapter 11 Cases;
• increased advisory costs to execute the Plan or any other plan ofreorganization and increased administrative and legal costs related to the
Chapter 11 Cases and other litigation and the inherent risks involved in a
bankruptcy process;
• restrictions imposed on us by the Bankruptcy Court ;
• the impact of the delisting of our common stock by the New York Stock
Exchange on the liquidity and market price of our common stock;
• market conditions and the effect of such conditions on our future results
of operations;
• sources and uses of and requirements for financial resources and sources
of liquidity;
• customer spending programs;
• business plans or financial condition of our customers, including with
respect to or as a result of the COVID-19 pandemic;
• contractual obligations and future contract negotiations;
• interest rate and foreign exchange risk;
• operations outside the United States ;
47
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• business strategy; • growth opportunities;
• competitive position including, without limitation, competitive rigs
entering the market;
• expected financial position;
• cash flows and contract backlog;
• future amounts payable by a customer in the form of a guarantee of gross
margin to be earned on future contracts or by direct payment, pursuant to
terms of an existing contract, including the timing and revenue associated
therewith;
• idling drilling rigs or reactivating stacked rigs;
• outcomes of litigation and legal proceedings;
• declaration and payment of dividends;
• financing plans;
• market outlook;
• commodity prices;
• tax planning and effects of the Tax Cuts and Jobs Act and the CARES Act;
• changes in tax laws and policies or adverse outcomes resulting from
examination of our tax returns;
• debt levels and the impact of changes in the credit markets and credit
ratings for us and our debt;
• budgets for capital and other expenditures;
• duration and impacts of the COVID-19 pandemic, lockdowns, re-openings and
any other related actions taken by businesses and governments that may
impact our business, operations, supply chain and personnel, financial
condition, results of operations, cash flows and liquidity;
• expectations regarding our plans and strategies, including plans, effects
and other matters relating to the COVID-19 pandemic;
• timing and duration of required regulatory inspections for our drilling
rigs and other planned downtime;
• process and timing for acquiring regulatory permits and approvals for our
drilling operations;
• timing and cost of completion of capital projects;
• delivery dates and drilling contracts related to capital projects;
• plans and objectives of management;
• scrapping retired rigs;
• asset impairments and impairment evaluations;
• assets held for sale;
• our internal controls and internal control over financial reporting;
• performance of contracts;
• compliance with applicable laws; and
• availability, limits and adequacy of insurance or indemnification.
48
-------------------------------------------------------------------------------- These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following: • those described under "Risk Factors" in Item 1A; • our ability to continue as a going concern;
• our ability to consummate the Plan and the restructuring and new exit
financing facilities contemplated by the PSA;
• risks that our assumptions and analyses in the Plan or any other plan of
reorganization are incorrect;
• risks associated with third-party motions or objections in the Chapter 11
Cases, which may interfere with our ability to confirm and consummate a
plan of reorganization and restructuring generally;
• the potential adverse effects of the Chapter 11 Cases on our liquidity,
results of operations, access to capital resources or business prospects;
• our ability to obtain the
Plan and other motions or requests made to the Bankruptcy Court in the
Chapter 11 Cases;
• the impact of the COVID-19 outbreak or future epidemics on our business,
including the potential for worker absenteeism, facility closures, work
slowdowns or stoppages, supply chain disruptions, additional costs and
liabilities, delays, our ability to recover costs under contracts,insurance challenges, and potential impacts on access to capital, markets
and the fair value of our assets;
• general economic and business conditions and trends, including recessions
and adverse changes in the level of international trade activity;
• the continuing protracted downturn in our industry and the expected
continuation thereof;
• worldwide supply and demand for oil and natural gas;
• changes in foreign and domestic oil and gas exploration, development and
production activity;
• oil and natural gas price fluctuations and related market expectations;
• the ability of OPEC+ to set and maintain production levels and pricing,
and the level of production in non-OPEC+ countries;
• policies of various governments regarding exploration and development of
oil and gas reserves;
• inability to obtain contracts for our rigs that do not have contracts;
• the inability to reactivate cold-stacked rigs;
• the cancellation or renegotiation of contracts included in our reported
contract backlog;
• advances in exploration and development technology;
• the worldwide political and military environment, including, for example,
in oil-producing regions and locations where our rigs are operating or are
in shipyards;
• casualty losses;
• operating hazards inherent in drilling for oil and gas offshore;
• the risk of physical damage to rigs and equipment caused by named
windstorms in the U.S. Gulf of Mexico ;
• industry fleet capacity;
• market conditions in the offshore contract drilling industry, including,
without limitation, dayrates and utilization levels;
• competition;
• changes in foreign, political, social and economic conditions;
49
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• risks of international operations, compliance with foreign laws and
taxation policies and seizure, expropriation, nationalization,
deprivation, malicious damage or other loss of possession or use of
equipment and assets;
• risks of potential contractual liabilities pursuant to our various
drilling contracts in effect from time to time;
• customer or supplier bankruptcy, liquidation or other financial difficulties;
• the ability of customers and suppliers to meet their obligations to us and
our subsidiaries;
• collection of receivables;
• foreign exchange and currency fluctuations and regulations, and the
inability to repatriate income or capital;
• risks of war, military operations, other armed hostilities, sabotage,
piracy, cyber-attack, terrorist acts and embargoes;
• changes in offshore drilling technology, which could require significant
capital expenditures in order to maintain competitiveness;
• reallocation of drilling budgets away from offshore drilling in favor of
other priorities such as shale or other land-based projects;
• regulatory initiatives and compliance with governmental regulations
including, without limitation, regulations pertaining to climate change,
greenhouse gases, carbon emissions or energy use;
• compliance with and liability under environmental laws and regulations;
• uncertainties surrounding deepwater permitting and exploration and
development activities;
• potential changes in accounting policies by the Financial Accounting
Standards Board ,SEC , or regulatory agencies for our industry which may cause us to revise our financial accounting and/or disclosures in the future, and which may change the way analysts measure our business or financial performance; • development and increasing adoption of alternative fuels; • customer preferences; • risks of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts; • cost, availability, limits and adequacy of insurance; • invalidity of assumptions used in the design of our controls and
procedures and the risk that material weaknesses may arise in the future;
• business opportunities that may be presented to and pursued or rejected by
us;
• the results of financing efforts;
• adequacy and availability of our sources of liquidity;
• risks resulting from our indebtedness;
• public health threats;
• negative publicity; and
• impairments of assets.
The risks and uncertainties included here are not exhaustive. Other sections of
this report and our other filings with the SEC include additional factors that
could adversely affect our business, results of operations and financial
performance. Given these risks and uncertainties, investors should not place
undue reliance on forward-looking statements. Forward-looking statements
included in this report speak only as of the date of this report. We expressly
disclaim any obligation or undertaking to release publicly any updates or
revisions to any forward-looking statement to reflect any change in our
expectations or beliefs with regard to the statement or any change in events,
conditions or circumstances on which any forward-looking statement is based. In
addition, in certain places in this report, we
50
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refer to reports of third parties that purport to describe trends or
developments in energy production or drilling and exploration activity. While we
believe that each of these reports is reliable, we have not independently
verified the information included in such reports. We specifically disclaim any
responsibility for the accuracy and completeness of such information and
undertake no obligation to update such information.
New Accounting Pronouncements
For a discussion of recent accounting pronouncements that have had or are expected to have an effect on our consolidated financial statements, see Note 1 "General Information - Changes in Accounting Principles" to our Consolidated Financial Statements in Item 8 of this report.
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