We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our report dated February 11, 2020, expressed an unqualified opinion on those consolidated financial statements.
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
The accompanying notes are an integral part of the consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General Information
Diamond Offshore Drilling, Inc. provides contract drilling services to the energy industry around the globe with a fleet of 15 offshore drilling rigs, consisting of four drillships and 11 semisubmersible rigs, including two rigs that are currently cold stacked. Our current fleet excludes the Ocean Confidence, which we expect to complete the sale of in the first quarter of 2020. See Note 8.
Unless the context otherwise requires, references in these Notes to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.
As of February 7, 2020, Loews Corporation, or Loews, owned approximately 53% of the outstanding shares of our common stock.
Principles of Consolidation
Our consolidated financial statements include the accounts of Diamond Offshore Drilling, Inc. and our wholly-owned subsidiaries after elimination of intercompany transactions and balances.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally accepted in the United States, or U.S., or GAAP, requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.
Changes in Accounting Principles
Leases. In February 2016, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2016-02, Leases (Topic 842), or ASU 2016-02, which (i) requires lessees to recognize a right of use asset and a lease liability on the balance sheet for most leases, (ii) updates previous accounting standards for lessors to align certain requirements with the updates to lessee accounting standards and the revenue recognition accounting standards and (iii) requires enhanced disclosure of qualitative and quantitative information about an entity's leasing arrangements.
We adopted ASU 2016-02 effective January 1, 2019 using an optional transition method requiring leases existing at, or entered into after, January 1, 2019 to be recognized and measured under the new accounting standard. Prior period amounts have not been adjusted and continue to be reflected in accordance with our historical accounting for leases. In our adoption of ASU 2016-02, we also utilized a transition practical expedient package whereby we did not reassess (i) whether any of our expired or existing contracts contain a lease, (ii) the classification for any expired or existing leases and (iii) initial direct costs for any existing leases. The adoption of this standard resulted in the recording of operating lease assets and offsetting operating lease liabilities of $146.8 million as of January 1, 2019, with no related impact on our annual Consolidated Statement of Stockholders’ Equity. See Note 11.
Upon adoption of ASU 2016-02, we concluded that our drilling contracts contain a lease component for the use of our drilling rigs based on the updated definition of a lease. However, ASU 2016-02 provides for a practical expedient for lessors whereby, under certain circumstances, the lessor may combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the
49
predominant component. We have determined that our current drilling contracts qualify for this practical expedient and have combined the lease and service components of our standard drilling contracts. We continue to account for the combined component under ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and its related amendments.
Revenue Recognition. In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09, which superseded the revenue recognition requirements in ASU Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services.
We adopted ASU 2014-09 and its related amendments, or collectively Topic 606, effective January 1, 2018 using the modified retrospective implementation method. Accordingly, we have applied the five-step method outlined in Topic 606 for determining when and how revenue is recognized to all contracts that were not completed as of the date of adoption. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. For contracts that were modified before the effective date, we have considered the modification guidance within the new standard and determined that the revenue recognized and contract balances recorded prior to adoption for such contracts were not impacted. While Topic 606 requires additional disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact on the measurement or recognition of our revenues.
Our adoption of ASU 2014-09 represents a change in accounting principle and therefore, we have recorded the cumulative effect of adopting Topic 606 as an increase to opening retained earnings on January 1, 2018. This adjustment represents an accrual for the earned portion of demobilization revenue expected to be received for contracts not completed as of December 31, 2017, which was not recordable under previous revenue recognition guidance until completion of the demobilization activities. See Note 2.
Income Taxes. In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory, or ASU 2016-16. ASU 2016-16 amended the guidance in Topic 740 with respect to the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. We have evaluated our historical intra-group transactions for impact under the provisions of ASU 2016-16 and adopted the guidance thereof effective January 1, 2018 using the modified retrospective approach. We recorded the $17.4 million cumulative effect of applying the new standard as a decrease to opening retained earnings with an offset to deferred income tax liability. See Note 14.
Stock-Based Compensation. In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718), or ASU 2016-09, which required (i) recognition of excess tax benefits and tax deficiencies as discrete tax items in the condensed consolidated statement of operations when share-based awards vest or are settled, (ii) exclusion of excess tax benefits from the computation of assumed proceeds under the treasury stock method when calculating earnings per share, and (iii) presentation of excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity. The guidance also provides for a policy election to either estimate the number of awards expected to vest or account for forfeitures when they occur.
We adopted ASU 2016-09 on January 1, 2017 using a modified retrospective approach and have elected to account for forfeitures of share-based awards in the period in which such forfeitures occur. The adoption resulted in a $0.6 million reduction in opening retained earnings and an offsetting increase in additional paid-in capital.
Recent Accounting Pronouncements Not Yet Adopted
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU 2016-13. ASU 2016-13 requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance is effective for interim and annual
50
periods beginning after December 15, 2019. We adopted ASU 2016-13 effective January 1, 2020 by applying a modified retrospective method and the impact was not material to our consolidated financial statements.
Cash and Cash Equivalents
We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.
The effect of exchange rate changes on cash balances held in foreign currencies was not material for the years ended December 31, 2019, 2018 and 2017.
Provision for Bad Debts
Prior to the adoption of ASU 2016-13, we have historically recorded a provision for bad debts on a case-by-case basis when facts and circumstances indicated that a customer receivable may not be collectible. In establishing these reserves, we considered historical and other factors that predicted collectability of such customer receivables, including write-offs, recoveries and the monitoring of credit quality. Such provision was reported as a component of “Operating expense” in our Consolidated Statements of Operations. See Note 4.
Drilling and Other Property 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 ended December 31, 2019 and 2018, we capitalized $343.8 million and $243.6 million, respectively, in replacements and betterments of our drilling fleet.
Costs incurred for major rig upgrades and/or the construction of rigs are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade or newbuild is completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are reported in our Consolidated Statements of Operations as “Loss (gain) on disposition of assets.” Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from 3 to 30 years.
Capitalized Interest
We capitalize interest cost for rig construction and other qualifying projects. A reconciliation of our total interest cost to “Interest expense, net of amounts capitalized” as reported in our Consolidated Statements of Operations is as follows (in thousands):
|
|
For the Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Total interest cost including amortization of debt
issuance costs
|
|
$
|
122,832
|
|
|
$
|
123,816
|
|
|
$
|
113,618
|
|
Capitalized interest
|
|
|
—
|
|
|
|
(576
|
)
|
|
|
(90
|
)
|
Total interest expense as reported
|
|
$
|
122,832
|
|
|
$
|
123,240
|
|
|
$
|
113,528
|
|
51
Impairment of Long-Lived Assets
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 term, 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 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:
|
•
|
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 have assigned 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.
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. See Note 3.
Fair Value of Financial Instruments
We believe that the carrying amount of our current financial instruments approximates fair value because of the short maturity of these instruments. See Note 7.
52
Debt Issuance Costs
Deferred costs associated with our credit facilities are presented in “Other assets” in our Consolidated Balance Sheets at December 31, 2019 and 2018 and amortized as interest expense over the respective terms of the credit facilities. During 2018, we paid $5.7 million in debt issuance and arrangement fees in connection with our credit facilities. Deferred costs associated with our senior notes are presented in our Consolidated Balance Sheets at December 31, 2019 and 2018 as a reduction to the related long-term debt and are amortized over the respective terms of the related debt. See Note 9.
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. Deferred tax assets and liabilities are classified as noncurrent in a classified statement of financial position. 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 utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.
We record both interest and penalties related to accrued uncertain tax positions in “Income tax benefit” in our Consolidated Statements of Operations. Liabilities for uncertain tax positions, including any interest and penalties, are denominated in the currency of the related tax jurisdiction and are revalued for changes in currency exchange rates. The revaluation of such liabilities for uncertain tax positions is reported in “Income tax benefit” in our Consolidated Statements of Operations. See Note 14.
Comprehensive (Loss) Income
Comprehensive (loss) income is the change in equity of a business enterprise during a period from transactions and other events and circumstances except those transactions resulting from investments by owners and distributions to owners. Comprehensive (loss) income for the three years ended December 31, 2019, 2018 and 2017 includes net (loss) income and unrealized holding gains and losses on marketable securities and financial derivatives designated as cash flow accounting hedges.
Foreign Currency
Our functional currency is the U.S. dollar. Transactions incurred in currencies other than the U.S. dollar are subject to gains or losses due to fluctuations in those currencies. We report foreign currency transaction gains and losses as “Foreign currency transaction (loss) gain” in our Consolidated Statements of Operations. The revaluation of assets and liabilities related to foreign income taxes, including deferred tax assets and liabilities and uncertain tax positions, including any interest and/or penalties, is reported in “Income tax benefit” in our Consolidated Statements of Operations.
53
2. Revenue from Contracts with Customers
The activities that primarily drive the revenue earned from our contract drilling services includes (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services provided within our drilling contracts as a single performance obligation satisfied over time and comprised of a series of distinct time increments in which we provide drilling services.
Consideration for activities that are not distinct within the context of our contracts and do not correspond to a distinct time increment within the contract term are allocated across the single performance obligation and recognized ratably over the initial term of the contract (which is the period we estimate to be benefited from the corresponding activities and generally ranges from two to 60 months). Consideration for activities that correspond to a distinct time increment within the contract term is recognized in the period when the services are performed. The total transaction price is determined for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. See below for further discussion regarding the allocation of the transaction price to the remaining performance obligations.
The amount estimated for variable consideration may be constrained (reduced) and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, management considers whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are re-assessed each reporting period as required.
Dayrate Drilling Revenue. Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.
Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.
In some contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, contractual provisions may require that a rig demobilize a certain distance before the demobilization revenue is payable or the amount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the wellsite. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on our past experience and knowledge of market conditions.
Contract Preparation Revenue. Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (on either a fixed lump-sum or variable dayrate basis). These activities are not considered to be distinct within the context of the contract. We record a contract liability for contract preparation fees received, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contract.
54
Capital Modification Revenue. From time to time, we may receive fees from our customers for capital improvements or upgrades to our rigs to meet contractual requirements (on either a fixed lump-sum or variable dayrate basis). The activities related to these capital modifications are not considered to be distinct within the context of our contracts. We record a contract liability for such fees and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.
Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations. Such amounts are recognized ratably over the period within the contract term during which the corresponding goods and services are to be consumed.
Contract Balances
Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Contract asset balances consist primarily of demobilization revenue that we expect to receive and is recognized ratably throughout the contract term, but invoiced upon completion of the demobilization activities. Once the demobilization revenue is invoiced, the corresponding contract asset is transferred to accounts receivable. Contract assets may also include amounts recognized in advance of amounts invoiced due to the blending of rates when a contract has operating dayrates that increase over the initial contract term. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract. Contract liabilities may also include amounts invoiced in advance of amounts recognized due to the blending of rates when a contract has operating dayrates that decrease over the initial contract term.
Contract balances are netted at a contract level, such that deferred revenue for mobilization, contract preparation and capital modifications (contract liabilities) is netted with any accrued demobilization revenue (contract asset) for each applicable contract.
The following table provides information about receivables, contract assets and contract liabilities from our contracts with customers (in thousands):
|
|
December 31,
2019
|
|
|
December 31,
2018
|
|
Trade receivables
|
|
$
|
199,572
|
|
|
$
|
160,478
|
|
Current contract assets (1)
|
|
|
6,314
|
|
|
|
6,832
|
|
Noncurrent contract assets (1)
|
|
|
—
|
|
|
|
2,107
|
|
Current contract liabilities (deferred revenue) (1)
|
|
|
(9,573
|
)
|
|
|
(2,803
|
)
|
Noncurrent contract liabilities (deferred revenue) (1)
|
|
|
(38,531
|
)
|
|
|
(17,723
|
)
|
(1)
|
Contract assets and contract liabilities may reflect balances that have been netted together on a contract basis. Net current contract asset and liability balances are included in “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, and net noncurrent contract asset and liability balances are included in “Other assets” and “Other liabilities,” respectively, in our Consolidated Balance Sheets as of December 31, 2019 and 2018.
|
55
Significant changes in the contract assets and the contract liabilities balances during the period are as follows (in thousands):
|
|
Net Contract Balances
|
|
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Contract assets, beginning of period
|
|
$
|
8,939
|
|
|
$
|
2,718
|
|
Contract liabilities, beginning of period
|
|
|
(20,526
|
)
|
|
|
(20,343
|
)
|
Net balance at beginning of period
|
|
|
(11,587
|
)
|
|
|
(17,625
|
)
|
Decrease due to amortization of revenue that was
included in the beginning contract liability
balance
|
|
|
6,952
|
|
|
|
19,026
|
|
Increase due to cash received, excluding amounts
recognized as revenue during the period
|
|
|
(34,529
|
)
|
|
|
(19,353
|
)
|
Increase due to revenue recognized during the
period but contingent on future performance
|
|
|
3,537
|
|
|
|
7,114
|
|
Decrease due to transfer to receivables during the
period
|
|
|
(5,119
|
)
|
|
|
(893
|
)
|
Adjustments
|
|
|
(1,044
|
)
|
|
|
144
|
|
Net balance at end of period
|
|
$
|
(41,790
|
)
|
|
$
|
(11,587
|
)
|
Contract assets at end of period
|
|
$
|
6,314
|
|
|
$
|
8,939
|
|
Contract liabilities at end of period
|
|
|
(48,104
|
)
|
|
|
(20,526
|
)
|
Deferred Contract Costs
Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Such deferred contract costs in the amount of $20.0 million and $4.0 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our Consolidated Balance Sheets at December 31, 2019. Deferred contract costs in the amount of $70.0 million and $13.1 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our Consolidated Balance Sheets at December 31, 2018. During the years ended December 31, 2019 and 2018, the amount of amortization of such costs was $96.0 million and $67.7 million, respectively. There was no impairment loss in relation to capitalized costs.
Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement.
Transaction Price Allocated to Remaining Performance Obligations
The following table reflects revenue expected to be recognized in the future related to unsatisfied performance obligations as of December 31, 2019 (in thousands):
|
|
|
|
|
|
For the Years Ending December 31,
|
|
|
|
2020
|
|
|
2021
|
|
|
2022
|
|
|
Total
|
|
Mobilization and contract
preparation revenue
|
|
$
|
2,268
|
|
|
$
|
630
|
|
|
$
|
124
|
|
|
$
|
3,022
|
|
Capital modification
revenue
|
|
|
9,028
|
|
|
|
1,777
|
|
|
|
—
|
|
|
|
10,805
|
|
Blended rate revenue
|
|
|
27,848
|
|
|
|
9,114
|
|
|
|
—
|
|
|
|
36,962
|
|
Total
|
|
$
|
39,144
|
|
|
$
|
11,521
|
|
|
$
|
124
|
|
|
$
|
50,789
|
|
56
The revenue included above consists of expected fixed mobilization and upgrade revenue for both wholly and partially unsatisfied performance obligations as well as expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. Revenue expected to be recognized in the future related to the blending of rates when a contract has operating dayrates that decrease over the initial contract term is also included. The amounts are derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at December 31, 2019. The actual timing of recognition of such amounts may vary due to factors outside of our control. We have applied the disclosure practical expedient in Topic 606 and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue.
3. Asset Impairments
2019 Impairment Evaluation. At December 31, 2019, we evaluated three drilling rigs with indicators of impairment. Based on our assumptions and analysis at that time, we determined that the undiscounted probability-weighted cash flow of each of these rigs was in excess of its carrying value. As a result, we concluded that no impairment of these rigs had occurred at December 31, 2019.
2018 Impairment. During 2018, we recorded an impairment loss of $27.2 million to recognize a reduction in fair value of the Ocean Scepter. We estimated the fair value of the impaired rig using a market approach based on a signed agreement to sell the rig, less estimated costs to sell. We considered this valuation approach to be a Level 3 fair value measurement due to the level of estimation involved as the sale had not yet been completed at the time of our analysis.
2017 Impairments. During 2017, we evaluated ten of our drilling rigs with indicators of impairment and determined that the carrying values of three rigs were impaired (we collectively refer to these three rigs as the 2017 Impaired Rigs).
We estimated the fair value of two of the 2017 Impaired Rigs using an income approach, whereby the fair value of each rig was estimated based on a calculation of the rig’s future net cash flows. These calculations utilized significant unobservable inputs, including estimated proceeds that may be received on ultimate disposition of each rig. The fair value of the remaining 2017 Impaired Rig was estimated using a market approach, which required us to estimate the value that would be received for the rig in the principal or most advantageous market for that rig in an orderly transaction between market participants. This estimate was primarily based on an indicative bid to purchase the rig at that time, as well as our evaluation of other market data points. Our fair value estimates were representative of Level 3 fair value measurements due to the significant level of estimation involved and the lack of transparency as to the inputs used.
We recorded aggregate impairment losses of $99.3 million for the year ended December 31, 2017 related to our 2017 Impaired Rigs.
See Note 1.
57
4. Supplemental Financial Information
Consolidated Balance Sheets Information
Accounts receivable, net of allowance for bad debts, consists of the following (in thousands):
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Trade receivables
|
|
$
|
199,572
|
|
|
$
|
160,478
|
|
Federal income tax receivable
|
|
|
38,574
|
|
|
|
—
|
|
Value added tax receivables
|
|
|
17,716
|
|
|
|
13,237
|
|
Related party receivables
|
|
|
166
|
|
|
|
174
|
|
Other
|
|
|
287
|
|
|
|
190
|
|
|
|
|
256,315
|
|
|
|
174,079
|
|
Allowance for bad debts
|
|
|
(5,459
|
)
|
|
|
(5,459
|
)
|
Total
|
|
$
|
250,856
|
|
|
$
|
168,620
|
|
There was no change in our provision for bad debts for each of the years ended December 31, 2019, 2018 and 2017. See Note 7 for a discussion of our policy regarding uncollectible accounts.
Prepaid expenses and other current assets consist of the following (in thousands):
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Deferred contract costs
|
|
$
|
20,019
|
|
|
$
|
70,021
|
|
Rig spare parts and supplies
|
|
|
18,250
|
|
|
|
20,256
|
|
Prepaid taxes
|
|
|
12,475
|
|
|
|
54,412
|
|
Current contract assets
|
|
|
6,314
|
|
|
|
6,832
|
|
Prepaid rig costs
|
|
|
2,990
|
|
|
|
5,247
|
|
Prepaid insurance
|
|
|
2,892
|
|
|
|
2,742
|
|
Prepaid software costs
|
|
|
2,319
|
|
|
|
1,531
|
|
Other
|
|
|
3,399
|
|
|
|
2,355
|
|
Total
|
|
$
|
68,658
|
|
|
$
|
163,396
|
|
Accrued liabilities consist of the following (in thousands):
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Accrued capital project/upgrade costs
|
|
$
|
56,603
|
|
|
$
|
37,379
|
|
Payroll and benefits
|
|
|
42,494
|
|
|
|
47,564
|
|
Rig operating expenses
|
|
|
37,969
|
|
|
|
42,323
|
|
Interest payable
|
|
|
28,234
|
|
|
|
28,234
|
|
Current operating lease liability (1)
|
|
|
20,030
|
|
|
|
—
|
|
Deferred revenue
|
|
|
9,573
|
|
|
|
2,803
|
|
Personal injury and other claims
|
|
|
7,074
|
|
|
|
5,544
|
|
Shorebase and administrative costs
|
|
|
5,275
|
|
|
|
6,217
|
|
Other
|
|
|
3,528
|
|
|
|
2,164
|
|
Total
|
|
$
|
210,780
|
|
|
$
|
172,228
|
|
|
(1)
|
We adopted ASU 2016-02 effective January 1, 2019, which required us to recognize a right of use asset and a lease liability on the balance sheet for most leases. See Note 11.
|
58
Consolidated Statements of Cash Flows Information
Noncash investing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information is as follows (in thousands):
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Accrued but unpaid capital expenditures at period
end
|
|
$
|
56,603
|
|
|
$
|
37,234
|
|
|
$
|
3,698
|
|
Common stock withheld for payroll tax
obligations (1)
|
|
|
1,398
|
|
|
|
1,301
|
|
|
|
483
|
|
Cash interest payments
|
|
|
113,063
|
|
|
|
113,063
|
|
|
|
97,096
|
|
Cash income taxes paid (refunded), net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign
|
|
|
17,821
|
|
|
|
9,286
|
|
|
|
43,999
|
|
U.S. federal
|
|
|
1,001
|
|
|
|
(7,389
|
)
|
|
|
—
|
|
State
|
|
|
(15
|
)
|
|
|
2
|
|
|
|
94
|
|
(1)
|
Represents the cost of 132,547, 87,799 and 29,416 shares of common stock withheld to satisfy the payroll tax obligation incurred as a result of the vesting of restricted stock units in 2019, 2018 and 2017, respectively. These costs are presented as a deduction from stockholders’ equity in “Treasury stock” in our Consolidated Balance Sheets at December 31, 2019, 2018 and 2017, respectively.
|
5. Stock-Based Compensation
We have an Equity Incentive Compensation Plan, or Equity Plan, for our officers, independent contractors, employees and non-employee directors, which is designed to encourage stock ownership by such persons. Under the Equity Plan, we may grant both time-vesting and performance-vesting awards, which are earned on the achievement of certain performance criteria. The following types of awards may be granted under the Equity Plan:
|
•
|
Stock options (including incentive stock options and nonqualified stock options);
|
|
•
|
Stock appreciation rights, or SARs;
|
|
•
|
Restricted stock units, or RSUs;
|
|
•
|
Performance shares or units; and
|
|
•
|
Other stock-based awards (including dividend equivalents).
|
A maximum of 7,500,000 shares of our common stock is available for the grant or settlement of awards under the Equity Plan, subject to adjustment for certain business transactions and changes in capital structure. Vesting conditions and other terms and conditions of awards under the Equity Plan are determined by our Board of Directors or the compensation committee of our Board of Directors, subject to the terms of the Equity Plan. RSUs may be issued with performance-vesting or time-vesting features. Except for RSUs issued to our Chief Executive Officer, RSUs are not participating securities, and the holders of such awards have no right to receive regular dividends if or when declared. However, we have not paid a dividend to stockholders since 2015.
Total compensation cost recognized for all awards under the Equity Plan (or its predecessor) for the years ended December 31, 2019, 2018 and 2017 was $6.2 million, $6.8 million and $8.7 million, respectively. Tax benefits recognized for the years ended December 31, 2019, 2018 and 2017 related thereto were $0.5 million, $0.8 million and $2.6 million, respectively. As of December 31, 2019 there was $6.6 million of total unrecognized compensation cost related to non-vested awards under the Equity Plan, which we expect to recognize over a weighted average period of two years.
59
Time-Vesting Awards
SARs. Currently, SARs awarded under the Equity Plan generally vest immediately and expire in ten years. The exercise price per share of SARs awarded under the Equity Plan may not be less than the fair market value of our common stock on the date of grant.
The fair value of SARs granted under the Equity Plan (or its predecessor) during each of the years ended December 31, 2019, 2018 and 2017 was estimated using the Black Scholes pricing model with the following weighted average assumptions:
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Expected life of SARs (in years)
|
|
|
7
|
|
|
|
7
|
|
|
|
7
|
|
Expected volatility
|
|
|
39.35
|
%
|
|
|
32.10
|
%
|
|
|
31.70
|
%
|
Risk free interest rate
|
|
|
2.11
|
%
|
|
|
2.56
|
%
|
|
|
2.09
|
%
|
The expected life of SARs is based on historical data as is the expected volatility. Risk free interest rates are determined using the U.S. Treasury yield curve at time of grant with a term equal to the expected life of the SARs.
A summary of SARs activity under the Equity Plan as of December 31, 2019 and changes during the year then ended is as follows:
|
|
Number of
Awards
|
|
|
Weighted-
Average
Exercise
Price
|
|
|
Weighted-
Average
Remaining
Contractual
Term
(Years)
|
|
|
Aggregate
Intrinsic
Value
(In
Thousands)
|
|
Awards outstanding at January 1, 2019
|
|
|
1,029,082
|
|
|
$
|
54.08
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
28,000
|
|
|
$
|
8.57
|
|
|
|
|
|
|
|
|
|
Expired
|
|
|
(134,852
|
)
|
|
$
|
71.46
|
|
|
|
|
|
|
|
|
|
Awards outstanding at December 31, 2019
|
|
|
922,230
|
|
|
$
|
50.19
|
|
|
|
3.6
|
|
|
$
|
—
|
|
Awards exercisable at December 31, 2019
|
|
|
922,230
|
|
|
$
|
50.19
|
|
|
|
3.6
|
|
|
$
|
—
|
|
The weighted-average grant date fair values per share of awards granted during the years ended December 31, 2019, 2018 and 2017 were $3.75, $7.11 and $5.61, respectively. The total intrinsic value of awards exercised during the years ended December 31, 2019, 2018 and 2017 was $0, $0.1 million and $0, respectively. The total fair value of awards vested during the years ended December 31, 2019, 2018 and 2017 was $0.1 million, $0.7 million and $1.2 million, respectively.
Restricted Stock Units. RSUs are contractual rights to receive shares of our common stock in the future if the applicable vesting conditions are met. In 2019, 2018 and 2017, we granted an aggregate of 310,700, 135,759 and 276,085 time-vesting RSUs, respectively. One-half of each annual grant of time-vesting RSUs will vest two years from the date of grant and the remaining 50% will vest three years from the date of grant, conditioned upon continued employment through the applicable vesting date. The fair value of time-vesting RSUs granted under the Equity Plan was estimated based on the fair market value of our common stock on the date of grant.
60
A summary of activity for time-vesting RSUs under the Equity Plan as of December 31, 2019 and changes during the year then ended is as follows:
|
|
Number
of Awards
|
|
|
Weighted
-Average
Grant Date
Fair Value
Per Share
|
|
Nonvested awards at January 1, 2019
|
|
|
422,059
|
|
|
$
|
16.57
|
|
Granted
|
|
|
310,700
|
|
|
$
|
10.47
|
|
Vested
|
|
|
(174,774
|
)
|
|
$
|
18.20
|
|
Forfeited
|
|
|
(24,382
|
)
|
|
$
|
13.42
|
|
Nonvested awards at December 31, 2019
|
|
|
533,603
|
|
|
$
|
12.58
|
|
The total fair value of time-vesting RSUs vested during the years ended December 31, 2019, 2018 and 2017 was $1.9 million, $1.9 million and $1.1 million, respectively.
Performance-Vesting Awards
Restricted Stock Units. In 2019, 2018 and 2017, we granted an aggregate of 190,634, 194,563 and 370,616 performance-vesting RSUs, respectively, which will vest upon achievement of certain performance goals as set forth in the individual award agreements over the three-year performance period beginning on January 1 in the year of grant. The shares of our common stock to be received upon the vesting of the performance-vesting RSUs will be delivered no later than March 15 of the year following completion of the three-year performance period. The fair value of performance-vesting RSUs granted under the Equity Plan to employees was estimated based on the fair market value of our common stock on the date of grant.
A summary of activity for performance-vesting RSUs under the Equity Plan as of December 31, 2019 and changes during the year then ended is as follows:
|
|
Number
of Awards
|
|
|
Weighted
-Average
Grant Date
Fair Value
Per Share
|
|
Nonvested awards at January 1, 2019
|
|
|
741,973
|
|
|
$
|
17.53
|
|
Granted
|
|
|
190,634
|
|
|
$
|
10.49
|
|
Vested
|
|
|
(223,330
|
)
|
|
$
|
21.44
|
|
Nonvested awards at December 31, 2019
|
|
|
709,277
|
|
|
$
|
14.41
|
|
The total grant date fair value of the performance-vesting RSUs that vested during the years ended December 31, 2019, 2018 and 2017 was $2.3 million, $2.5 million and $0.3 million, respectively.
6. (Loss) Earnings Per Share
We present basic and diluted (loss) earnings per share on our Consolidated Statements of Operations. Basic (loss) earnings per share excludes dilution and is computed by dividing net (loss) income by the weighted-average number of common shares outstanding for the period. Diluted (loss) earnings per share reflects the potential dilution that could occur if securities or other contracts to issue common stock (common share equivalents) were exercised or converted into common stock, unless the effect would be antidilutive. For all periods in which we experience a net loss, all shares of common stock issuable upon exercise of outstanding stock appreciation rights and vesting of outstanding restricted stock units have been excluded from the calculation of weighted-average shares because their inclusion would be antidilutive.
61
The following table sets forth the share effects of stock-based awards excluded from the computation of diluted (loss) earnings per share (in thousands).
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Employee and director:
|
|
|
|
|
|
|
|
|
|
|
|
|
SARs
|
|
|
982
|
|
|
|
1,133
|
|
|
|
1,315
|
|
RSUs
|
|
|
1,205
|
|
|
|
1,153
|
|
|
|
757
|
|
7. Financial Instruments and Fair Value Disclosures
Concentrations of Credit and Market Risk
Financial instruments that potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities. We generally place our excess cash investments in U.S. Treasury Bills and U.S. government-backed short-term money market instruments through several financial institutions. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.
Concentrations of credit risk with respect to our trade accounts receivable are limited, primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies, as well as government-owned oil companies. We believe that we have potentially significant concentrations of credit risk on the basis of the limited number of our rigs currently contracted and the smaller population of customers, as several customers have contracted for multiple rigs.
In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. Historically, we have recorded a provision for bad debts on a case-by-case basis when facts and circumstances indicated that a customer receivable may not be collectible. Losses on our trade receivables have been infrequent occurrences.
Fair Values
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value:
Level 1
|
Quoted prices for identical instruments in active markets.
|
Level 2
|
Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.
|
Level 3
|
Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.
|
62
Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. In addition, certain assets and liabilities may be recorded at fair value on a nonrecurring basis. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. We recorded an impairment charge related to one of our drilling rigs, which was measured at fair value on a nonrecurring basis in 2018, and have presented the aggregate loss in “Impairment of assets” in our Consolidated Statements of Operations for the year ended December 31, 2018.
Assets measured at fair value are summarized below (in thousands).
|
|
December 31, 2019
|
|
|
|
|
|
Fair Value Measurements Using
|
|
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Assets at
Fair Value
|
|
|
|
Recurring fair value measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Money market funds
|
|
$
|
135,300
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
135,300
|
|
|
|
Total short-term investments
|
|
$
|
135,300
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
135,300
|
|
|
|
|
|
December 31, 2018
|
|
|
|
Fair Value Measurements Using
|
|
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Assets at
Fair Value
|
|
|
Total
Losses
for Year
Ended (1)
|
|
Recurring fair value measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. Treasury bills
|
|
$
|
299,900
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
299,900
|
|
|
|
|
|
Money market funds
|
|
|
135,800
|
|
|
|
—
|
|
|
|
—
|
|
|
|
135,800
|
|
|
|
|
|
Short-term investments
|
|
$
|
435,700
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
435,700
|
|
|
|
|
|
Nonrecurring fair value measurements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Impaired assets
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
27,225
|
|
(1)
|
Represents impairment loss of $27.2 million recognized during 2018 related to a drilling rig whose carrying value was impaired and was subsequently sold. See Note 3.
|
We believe that the carrying amounts of our other financial assets and liabilities (excluding long-term debt), which are not measured at fair value in our Consolidated Balance Sheets, approximate fair value based on the following assumptions:
|
•
|
Cash and cash equivalents -- The carrying amounts approximate fair value because of the short maturity of these instruments.
|
|
•
|
Accounts receivable and accounts payable -- The carrying amounts approximate fair value based on the nature of the instruments.
|
63
Our senior notes are not measured at fair value; however, under the GAAP fair value hierarchy, our long-term debt would be considered Level 2 liabilities. The fair value of our senior notes was derived using a third-party pricing service at December 31, 2019 and 2018. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market for these instruments occurring generally within a 10-day period of the report date. Fair values and related carrying values of our senior notes (see Note 9) are shown below (in millions).
|
|
December 31, 2019
|
|
|
December 31, 2018
|
|
|
|
Fair
Value
|
|
|
Carrying
Value
|
|
|
Fair
Value
|
|
|
Carrying
Value
|
|
3.45% Senior Notes due 2023
|
|
$
|
212.5
|
|
|
$
|
249.6
|
|
|
$
|
185.0
|
|
|
$
|
249.5
|
|
7.875% Senior Notes due 2025
|
|
|
435.0
|
|
|
|
497.1
|
|
|
|
415.0
|
|
|
|
496.8
|
|
5.70% Senior Notes due 2039
|
|
|
292.5
|
|
|
|
497.3
|
|
|
|
305.0
|
|
|
|
497.2
|
|
4.875% Senior Notes due 2043
|
|
|
408.8
|
|
|
|
749.0
|
|
|
|
416.3
|
|
|
|
748.9
|
|
We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange.
8. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows (in thousands):
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Drilling rigs and equipment
|
|
$
|
8,004,489
|
|
|
$
|
8,210,824
|
|
Land and buildings
|
|
|
64,267
|
|
|
|
63,757
|
|
Office equipment and other
|
|
|
92,289
|
|
|
|
91,819
|
|
Cost
|
|
|
8,161,045
|
|
|
|
8,366,400
|
|
Less: accumulated depreciation
|
|
|
(3,008,217
|
)
|
|
|
(3,182,178
|
)
|
Drilling and other property and equipment, net
|
|
$
|
5,152,828
|
|
|
$
|
5,184,222
|
|
During 2019, we recognized an aggregate pre-tax loss of $1.1 million on the disposal of assets, which included a pre-tax gain on the sale of the Ocean Guardian of $14.3 million offset by an aggregate pre-tax loss of $15.4 million on the disposal of certain other property and equipment. In 2019, we also transferred the $1.0 million net book value of the Ocean Confidence, a previously impaired semisubmersible rig, to “Asset held for sale” in our Consolidated Balance Sheets at December 31, 2019. We expect to complete the sale of the rig in the first quarter of 2020 for a net gain of $3.5 million.
9. Credit Agreements and Senior Notes
Credit Agreements
In September 2012, we entered into a syndicated 5-year revolving credit agreement, which, as amended as of August 18, 2016, provided for a $1.5 billion senior unsecured revolving credit facility for general corporate purposes. On October 2, 2018, we entered into Amendment No. 6 and Consent to Credit Agreement and Successor Agency Agreement, or the Amendment, which amended our 5-year revolving credit agreement, dated as of September 28, 2012, as amended (we refer to such credit agreement as the Amended Credit Facility). Among other things, the Amendment reduced the aggregate principal amount of commitments under the credit facility to $325.0 million, of which $100.0 million of the commitments matured in 2019. The remaining $225.0 million of commitments mature on October 22, 2020 and are available, subject to the terms of the Amended Credit Facility, for revolving loans.
On October 2, 2018, Diamond Offshore Drilling, Inc., or DODI, as the U.S. borrower, and our subsidiary Diamond Foreign Asset Company, or DFAC, as the foreign borrower, entered into a senior 5-year revolving credit
64
agreement with a syndicate of lenders and Wells Fargo Bank, National Association, as administrative agent (we refer to such credit agreement as the $950 Million Credit Facility). The maximum amount of borrowings available under the $950 Million Credit Facility is $950.0 million and may be used for general corporate purposes, including investments, acquisitions and capital expenditures. The $950 Million Credit Facility, which matures on October 2, 2023, provides for a swingline subfacility of $100.0 million and a letter of credit subfacility of $250.0 million.
The entire amount of borrowings available under the $950 Million Credit Facility is available for loans to DFAC, and a portion of such amount is available for loans to DODI, based on a ratio as specified in the $950 Million Credit Facility. The obligations of DODI and DFAC under the $950 Million Credit Facility are each guaranteed by certain subsidiaries of DODI and DFAC, respectively, and 65% of the equity interest in DFAC is pledged as collateral for the obligations under the $950 Million Credit Facility.
The $950 Million Credit Facility includes restrictions on borrowing if, after giving effect to any such borrowings and the application of the proceeds thereof, the aggregate amount of available cash, as defined in the $950 Million Credit Facility, would exceed $500.0 million. In addition, the ability to borrow revolving loans under the $950 Million Credit Facility is conditioned on there being no unused commitments to advance loans under the Amended Credit Facility.
We refer to the Amended Credit Facility and $950 Million Credit Facility collectively as the Credit Agreements. At December 31, 2019, we had no borrowings outstanding under the Credit Agreements, however, in January 2020, a $6.0 million financial letter of credit was issued under the $950 Million Credit Facility in support of a previously issued surety bond. As of February 7, 2020, there was approximately $1.2 billion available under the Credit Agreements in the aggregate, subject to their respective terms.
Covenants
The Amended Credit Facility contains customary covenants, including, but not limited to, maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Amended Credit Facility, of not more than 60% at the end of each fiscal quarter, as well as limitations on liens; mergers, consolidations, liquidation and dissolution; changes in lines of business; swap agreements; transactions with affiliates; and subsidiary indebtedness.
The $950 Million Credit Facility contains certain financial covenants, including (i) maintenance of a ratio of consolidated indebtedness to total capitalization not to exceed 60% at the end of each fiscal quarter, (ii) maintenance of a ratio of not less than 80% at the end of each fiscal quarter of (A) the aggregate value of certain rigs directly wholly owned by the borrowers and subsidiary guarantors to (B) the aggregate value of substantially all rigs owned by us and (iii) maintenance of a ratio of not less than 3:00 to 1:00 at the end of each fiscal quarter of (A) the sum of the aggregate value of all marketed rigs, as defined in the $950 Million Credit Facility, wholly owned directly by DFAC and certain foreign guarantors, as specified in the $950 Million Credit Facility, plus the value of the Ocean Valiant at any time when it is a marketed rig owned by a guarantor to (B) the sum of commitments under the $950 Million Credit Facility, the outstanding loans and letter of credit exposures under the Amended Credit Facility plus certain other indebtedness of DFAC and certain foreign guarantors, as specified in the $950 Million Credit Facility.
The $950 Million Credit Facility also contains additional covenants generally applicable to DODI and its subsidiaries that we consider usual and customary for an agreement of this type, including a limit on the payment of dividends if certain minimum cash balances are not maintained.
The Credit Agreements provide for customary events of default including, among others, a cross-default provision with respect to DODI’s and its subsidiaries’ other indebtedness in excess of $100.0 million. At December 31, 2019, we were in compliance with all covenant requirements under the Credit Agreements.
Interest Rates and Fees
Revolving loans under the Credit Agreements bear interest, at our option, at a rate per annum based on either an alternate base rate, or ABR, or a Eurodollar Rate, as defined in the applicable Credit Agreement, plus the applicable interest margin for an ABR loan or a Eurodollar loan (determined based on our credit ratings). Swingline loans under the $950 Million Credit Facility bear interest, at our option, at a rate per annum equal to (i) the ABR plus the applicable
65
interest margin for ABR loans or (ii) the daily one-month Eurodollar Rate plus the applicable interest margin for Eurodollar loans.
Under the Credit Agreements, we also pay, based on our current long-term credit ratings, and as applicable, other customary fees including, but not limited to, a commitment fee on the unused commitments under each of the Credit Agreements and a fronting fee to the issuing bank for each letter of credit. Participation fees for letters of credit are dependent upon the type of letter of credit issued.
The following summarizes the interest rate margins and fees payable under the Credit Agreements, based on our current long-term credit ratings:
|
|
Amended Credit Facility
|
|
$950 Million Credit Facility
|
Revolving Loans:
|
|
|
|
|
ABR
|
|
0.25% over the greater of (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the daily one-month Eurodollar Rate plus 1.00%
|
|
3.25% over the greater of (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the daily one-month Eurodollar Rate plus 1.00%
|
Eurodollar
|
|
1.25% over specified LIBOR
|
|
4.25% over specified LIBOR
|
Swingline Loans
|
|
N/A
|
|
At our option, at a rate per annum equal to (i) the ABR plus the applicable interest margin for ABR loans or (ii) the daily one-month Eurodollar Rate plus the applicable interest margin for Eurodollar loans
|
Letter of credit participation fees:
|
|
|
|
|
Performance letters of credit
|
|
N/A
|
|
2.125% per annum
|
All other letters of credit
|
|
N/A
|
|
4.25% per annum
|
Commitment fee on unused
commitments under credit
agreement
|
|
0.20% per annum
|
|
0.70% per annum
|
Favorable changes in our current credit ratings could lower the interest rate margins and fees that we pay under the Credit Agreements; however, current interest rates and fees under the Credit Agreements will apply should there be any further downgrade in our credit ratings.
Senior Notes
At December 31, 2019, our senior notes were comprised of the following debt issues (dollars in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Semiannual
|
|
|
Principal
|
|
|
|
|
Interest Rate
|
|
|
Interest Payment
|
Debt Issue
|
|
Amount
|
|
|
Maturity Date
|
|
Coupon
|
|
|
Effective
|
|
|
Dates
|
3.45% Senior Notes due 2023
|
|
$
|
250.0
|
|
|
November 1, 2023
|
|
|
3.45
|
%
|
|
|
3.50
|
%
|
|
May 1 and November 1
|
7.875% Senior Notes due 2025
|
|
$
|
500.0
|
|
|
August 15, 2025
|
|
|
7.875
|
%
|
|
|
8.00
|
%
|
|
February 15 and August 15
|
5.70% Senior Notes due 2039
|
|
$
|
500.0
|
|
|
October 15, 2039
|
|
|
5.70
|
%
|
|
|
5.75
|
%
|
|
April 15 and October 15
|
4.875% Senior Notes due 2043
|
|
$
|
750.0
|
|
|
November 1, 2043
|
|
|
4.875
|
%
|
|
|
4.89
|
%
|
|
May 1 and November 1
|
66
At December 31, 2019 and 2018, the carrying value of our senior notes, net of unamortized discount and debt issuance costs, was as follows (in thousands):
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
3.45% Senior Notes due 2023
|
|
$
|
248,759
|
|
|
$
|
248,455
|
|
7.875% Senior Notes due 2025
|
|
|
491,655
|
|
|
|
490,491
|
|
5.70% Senior Notes due 2039
|
|
|
493,316
|
|
|
|
493,139
|
|
4.875% Senior Notes due 2043
|
|
|
742,011
|
|
|
|
741,837
|
|
Total senior notes, net
|
|
$
|
1,975,741
|
|
|
$
|
1,973,922
|
|
As of December 31, 2019, the aggregate annual maturity of our senior notes, excluding net unamortized discounts and debt issuance costs of $7.0 million and $17.3 million, respectively, was as follows (in thousands):
|
|
Aggregate
Principal
Amount
|
|
Year Ending December 31,
|
|
|
|
|
2020
|
|
$
|
—
|
|
2021
|
|
|
—
|
|
2022
|
|
|
—
|
|
2023
|
|
|
250,000
|
|
2024
|
|
|
—
|
|
Thereafter
|
|
|
1,750,000
|
|
Total maturities of senior notes
|
|
$
|
2,000,000
|
|
Notes Redemption. In August 2017, we redeemed all of our outstanding 5.875% senior notes due 2019, or 2019 Notes, for a redemption price of $543.0 million in the aggregate, including accrued and unpaid interest to the date of redemption. We accounted for the redemption as an extinguishment of debt and reported a corresponding loss of $35.4 million in our Consolidated Statements of Operations.
Senior Notes Due 2025. In August 2017, we issued $500.0 million aggregate principal amount of unsecured 7.875% senior notes due 2025, or 2025 Notes, and received net proceeds of $489.1 million after deduction of underwriter discounts, commissions and expenses. We used the net proceeds from the 2025 Notes, together with cash on hand, to fund the redemption of our previously outstanding 2019 Notes. The 2025 Notes are unsecured obligations of DODI, and rank equally in right of payment to all of its existing and future senior indebtedness, and are structurally subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem some or all of the 2025 Notes at any time or from time to time, on at least 15 days but not more than 60 days prior written notice, at the applicable redemption price specified in the governing indenture, plus accrued and unpaid interest to, but excluding, the date of redemption.
Senior Notes Due 2023 and 2043. Our 3.45% Senior Notes due 2023 and 4.875% Senior Notes due 2043 are unsecured and unsubordinated obligations of DODI, and rank equally in right of payment to all of its existing and future unsecured and unsubordinated indebtedness, and are effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of these notes for cash at any time or from time to time, on at least 15 days but not more than 60 days prior written notice, at a make-whole redemption price specified in the governing indenture (if applicable) plus accrued and unpaid interest to, but excluding, the date of redemption.
Senior Notes Due 2039. Our 5.70% Senior Notes due 2039 are unsecured and unsubordinated obligations of DODI, and rank equally in right of payment to all of its existing and future unsecured and unsubordinated indebtedness, and are effectively subordinated to all existing and future obligations of our subsidiaries. We have the right to redeem all or a portion of these notes for cash at any time or from time to time, on at least 15 days but not more than 60 days prior written notice, at the redemption price specified in the governing indenture plus accrued and unpaid interest to the date of redemption.
67
The 2025 Notes, 3.45% Senior Notes due 2023, 4.875% Senior Notes due 2043 and 5.70% Senior Notes due 2039 contain customary covenants including limitations on liens, mergers, consolidations and certain sales of assets and on entering into sale and lease-back transactions covering a drilling rig or drillship, as specified in each governing indenture. As of December 31, 2019, we were in compliance with all of these covenants.
10. Commitments and Contingencies
Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a liability for the amount of the estimated loss at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims.
Asbestos Litigation. We are one of several unrelated defendants in lawsuits filed in Louisiana state courts alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. The manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted in the lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our financial condition, results of operations and cash flows, including negative cash flows.
Non-Income Tax and Related Claims. We have received assessments related to, or otherwise have exposure to, non-income tax items such as sales-and-use tax, value-added tax, ad valorem tax, custom duties, and other similar taxes in various taxing jurisdictions. We have determined that we have a probable loss for these taxes and the related penalties and interest and, accordingly, have recorded a $16.1 million and $12.3 million liability at December 31, 2019 and 2018, respectively. We intend to defend these matters vigorously; however, the ultimate outcome of these assessments and exposures could result in additional taxes, interest and penalties for which the fully assessed amounts would have a material adverse effect on our financial statements
Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business, including a claim by one of our customers in Brazil, Petróleo Brasileiro S.A., or Petrobras, that it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities for our applicable portion of withholding taxes related to Petrobras’ charter agreements with its contractors. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of any claim, lawsuit or action cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of any litigation matter. Any claims against us, whether meritorious or not, could cause us to incur significant costs and expenses and require significant amounts of management and operational time and resources. In the opinion of our management, no such pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Personal Injury Claims. Under our current insurance policies, our deductibles for marine liability insurance coverage with respect to personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, which primarily result from Jones Act liability 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. Our deductibles for personal injury claims 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 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.
68
The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At December 31, 2019, our estimated liability for personal injury claims was $17.4 million, of which $6.4 million and $11.0 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2018, our estimated liability for personal injury claims was $27.9 million, of which $5.2 million and $22.7 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:
|
•
|
the severity of personal injuries claimed;
|
|
•
|
significant changes in the volume of personal injury claims;
|
|
•
|
the unpredictability of legal jurisdictions where the claims will ultimately be litigated;
|
|
•
|
inconsistent court decisions; and
|
|
•
|
the risks and lack of predictability inherent in personal injury litigation.
|
Purchase Obligations. At December 31, 2019, we had no purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.
Services Agreement. In February 2016, we entered into a ten-year agreement with a subsidiary of Baker Hughes Company (formerly named Baker Hughes, a GE company), or Baker Hughes, to provide services with respect to certain blowout preventer and related well control equipment, or Well Control Equipment, on our drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. Future commitments under the contractual services agreements are estimated to be approximately $39 million per year or an estimated $250 million in the aggregate over the remaining term of the agreements.
In addition, we lease Well Control Equipment for our drillships under ten-year operating leases. See Note 11.
Letters of Credit and Other. We were contingently liable as of December 31, 2019 in the amount of $37.1 million under certain tax, performance, supersedeas, VAT and customs bonds and letters of credit. Agreements relating to approximately $28.5 million of customs, tax, VAT and supersedeas bonds can require collateral at any time, while the remaining agreements, aggregating $8.6 million, cannot require collateral except in events of default. As of December 31, 2019, we had not been required to make any collateral deposits with respect to these agreements. However, in January 2020, we were required to issue a $6.0 million financial letter of credit as collateral in support of our outstanding surety bonds.
11. Leases and Lease Commitments
Our leasing activities primarily consist of operating leases for shorebase offices, office and information technology equipment, employee housing, vehicles, onshore storage yards and certain rig equipment and tools. Our leases have terms ranging from one month to ten years, some of which include options to extend the lease for up to five years and/or to terminate the lease within one year.
Additionally, we are participants in four sale and leaseback arrangements with a subsidiary of Baker Hughes pursuant to the 2016 sale of Well Control Equipment on our drillships and corresponding agreements to lease back that equipment under ten-year operating leases for approximately $26 million per year in the aggregate with renewal options for two successive five-year periods. At the time of the transactions with Baker Hughes, the carrying value of the Well Control Equipment exceeded the aggregate proceeds received from the sale, resulting in the recognition of prepaid rent, which was being amortized over the respective terms of the leases. On January 1, 2019, as a result of the adoption of ASU 2016-02, the aggregate remaining prepaid rent balances of $3.9 million and $10.6 million, previously recorded as “Prepaid expenses and other current assets” and “Other assets,” respectively, were
69
reclassified to a right-of-use lease asset within “Other assets” in our Consolidated Balance Sheets and continue to be amortized over the remaining terms of the leases.
In applying ASU 2016-02, we utilized an exemption for short-term leases whereby we did not record leases with terms of one year or less on the balance sheet. We have also made an accounting policy election not to separate lease components from non-lease components for each of our classes of underlying assets, except for subsea equipment, which includes the Well Control Equipment discussed above. At inception, the consideration for the overall Well Control Equipment arrangement was allocated between the lease and service components based on an estimation of stand-alone selling price of each component, which maximized observable inputs. The costs associated with the service portion of the agreement are accounted for separately from the cost attributable to the equipment leases based on that allocation and thus, are not included in our right-of-use lease asset or lease liability balances. The non-lease components for each of our other classes of assets generally relate to maintenance, monitoring and security services and are not separated from their respective lease components. See Note 10.
The lease term used for calculating our right-of-use assets and lease liabilities is determined by considering the noncancelable lease term, as well as any extension options that we are reasonably certain to exercise. The determination to include option periods is generally made by considering the activity in the region or for the rig corresponding to the respective lease, among other contract-based and market-based factors. We have used our incremental borrowing rate to discount future lease payments as the rate implicit in our leases is not readily determinable. To arrive at our incremental borrowing rate, we consider our unsecured borrowings and then adjust those rates to assume full collateralization and to factor in the individual lease term and payment structure.
Total operating lease expense for the year ended December 31, 2019 was $39.7 million of which $3.4 million related to short-term leases. Total operating lease expense for the years ended December 31, 2018 and 2017 was $30.1 million and $30.6 million, respectively.
Supplemental information related to leases is as follows (in thousands, except weighted-average data):
|
|
Year Ended
December 31,
2019
|
|
Operating cash flows used for operating leases
|
|
$
|
39,561
|
|
Right-of-use assets obtained in exchange for lease
liabilities
|
|
|
26,248
|
|
Weighted-average remaining lease term
|
|
6.7 years
|
|
Weighted-average discount rate
|
|
|
8.68
|
%
|
Future minimum rental payments under noncancelable operating leases as of December 31, 2018 were as follows (in thousands):
2019
|
|
$
|
28,373
|
|
2020
|
|
|
27,144
|
|
2021
|
|
|
26,565
|
|
2022
|
|
|
26,281
|
|
2023
|
|
|
26,280
|
|
Thereafter
|
|
|
64,062
|
|
Total lease payments
|
|
$
|
198,705
|
|
70
Maturities of lease liabilities as of December 31, 2019 are as follows (in thousands):
2020
|
|
$
|
32,888
|
|
2021
|
|
|
30,548
|
|
2022
|
|
|
29,973
|
|
2023
|
|
|
29,499
|
|
2024
|
|
|
29,580
|
|
Thereafter
|
|
|
51,784
|
|
Total lease payments
|
|
|
204,272
|
|
Less: interest
|
|
|
(50,348
|
)
|
Total lease liability
|
|
$
|
153,924
|
|
Amounts recognized in Consolidated Balance Sheets:
|
|
|
|
|
Accrued liabilities
|
|
$
|
20,030
|
|
Other liabilities
|
|
|
133,894
|
|
Total operating lease liability
|
|
$
|
153,924
|
|
Operating lease assets, including prepaid rent balances related to the Baker Hughes transaction, totaling $169.2 million are included in “Other assets” in our Consolidated Balance Sheets as of December 31, 2019.
As of December 31, 2019, we had an additional operating lease for mooring equipment to be used on a rig that had not yet commenced. The agreement, which commenced in January 2020, provides for fixed lease payments of approximately $5 million in the aggregate to be paid over a lease term of 5 years.
12. Related-Party Transactions
Transactions with Loews. We are party to a services agreement with Loews, or the Services Agreement, pursuant to which Loews performs certain administrative and technical services on our behalf. Such services include internal auditing services and advice and assistance with respect to obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i) allocated personnel cost (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) all out-of-pocket expenses related to the provision of such services. The Services Agreement may be terminated at our option upon 30 days’ notice to Loews and at the option of Loews upon six months’ notice to us. In addition, we have agreed to indemnify Loews for all claims and damages arising from the provision of services under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. We were charged $0.7 million, $0.6 million and $1.0 million by Loews for these support functions during the years ended December 31, 2019, 2018 and 2017, respectively.
13. Restructuring and Separation Costs
In late 2017, in response to expectations at the time that a recovery of the offshore drilling market would not occur in the near term, combined with changes to the size and composition of our drilling fleet since 2015, we reviewed our global cost and organizational structure, including the way in which we market our services in certain countries. As a result, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities, as well as the negotiation of a termination of our agency agreement in Brazil. We incurred $14.1 million in restructuring and employee separation related costs during 2017, including $11.5 million related to the termination of our Brazilian agency agreement. During 2018, we incurred an additional $5.0 million in severance and related costs for redundant employees identified in 2018 in connection with the restructuring plan and paid $12.4 million in previously accrued costs. During 2019, all remaining obligations under the restructuring plan were settled.
14. Income Taxes
Several of our rigs are owned by Swiss branches of entities incorporated in the U.K. that have historically been taxed under a special tax regime pursuant to Swiss corporate income tax rules. On September 3, 2019, the Swiss federal government, along with the Canton of Zug, enacted tax legislation, which we refer to as Swiss Tax Reform, effective as of January 1, 2020. Swiss Tax Reform significantly changed Swiss corporate income tax rules by,
71
among other things, abolishing special tax regimes. The legislation also provides transition rules under which companies can maintain their current basis of taxation through January 1, 2022.
The abolition of special tax regimes will require us to determine our Swiss tax liability on a net income basis beginning on January 1, 2022, thus also requiring deferred taxes to be computed on the difference between the Swiss tax basis and U.S. GAAP basis of certain items, including property, plant and equipment. There are still many uncertainties in the application of Swiss Tax Reform, including the values to be used to measure depreciable property. Therefore, we have recorded a $74.2 million net deferred tax asset for the difference in basis of certain of our rigs between Swiss tax and U.S. GAAP, offset, where appropriate, by a reserve for an uncertain tax position. As further clarification is issued by the Swiss tax authorities, deferred tax balances and the reserve for uncertain tax positions may need to be adjusted. The potential changes could have a material effect on our consolidated financial statements.
In 2019, the Internal Revenue Service, or IRS, issued final regulations with respect to the calculation of the toll charge associated with the deemed repatriation of previously deferred earnings of our non-U.S. subsidiaries, or Transition Tax, in response to the Tax Cuts and Jobs Act enacted in 2017, commonly referred to as the Tax Reform Act. Based on the new regulations, we recorded a net tax benefit of $14.2 million in the second quarter of 2019, primarily to reverse a previously recorded uncertain tax position related to the Transition Tax. Consequently, our revised net tax benefit associated with the Tax Reform Act is $34.5 million, which now consists of (i) a $38.0 million charge relating to the one-time mandatory repatriation of previously deferred earnings of certain non-US subsidiaries that are owned either wholly or partially by our U.S. subsidiaries, inclusive of the utilization of certain tax attributes and (ii) a $72.5 million credit resulting from the determination and re-measurement of our net U.S. deferred tax liabilities at the lower corporate income tax rate.
Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, the mix of international tax jurisdictions in which we operate and recognition of valuation allowances for deferred tax assets for which the tax benefits are not likely to be realized. Certain of our rigs are owned and operated, directly or indirectly, by DFAC. Our management has determined that we will no longer permanently reinvest foreign earnings. As of December 31, 2019, we recorded $0.4 million for the withholding income tax impact associated with the potential distribution of DFAC’s earnings. 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. The potential unrecorded tax liability associated with the outside basis difference is approximately $95 million.
The components of income tax expense (benefit) are as follows (in thousands):
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Federal – current
|
|
$
|
(13,810
|
)
|
|
$
|
20,107
|
|
|
$
|
6,994
|
|
State – current
|
|
|
19
|
|
|
|
2
|
|
|
|
95
|
|
Foreign – current
|
|
|
25,899
|
|
|
|
9,531
|
|
|
|
25,252
|
|
Total current
|
|
|
12,108
|
|
|
|
29,640
|
|
|
|
32,341
|
|
Federal – deferred
|
|
|
(67,015
|
)
|
|
|
(75,279
|
)
|
|
|
(85,066
|
)
|
Foreign – deferred
|
|
|
10,107
|
|
|
|
(714
|
)
|
|
|
12,939
|
|
Total deferred
|
|
|
(56,908
|
)
|
|
|
(75,993
|
)
|
|
|
(72,127
|
)
|
Total
|
|
$
|
(44,800
|
)
|
|
$
|
(46,353
|
)
|
|
$
|
(39,786
|
)
|
72
The difference between actual income tax expense and the tax provision computed by applying the statutory federal income tax rate to income before taxes is attributable to the following (in thousands):
|
|
Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
(Loss) income before income tax expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S.
|
|
$
|
(339,072
|
)
|
|
$
|
(266,855
|
)
|
|
$
|
(241,178
|
)
|
Foreign
|
|
|
(62,942
|
)
|
|
|
40,230
|
|
|
|
219,738
|
|
|
|
$
|
(402,014
|
)
|
|
$
|
(226,625
|
)
|
|
$
|
(21,440
|
)
|
Expected income tax benefit at federal statutory rate
|
|
$
|
(84,423
|
)
|
|
$
|
(47,591
|
)
|
|
$
|
(7,504
|
)
|
Effect of tax rate changes
|
|
|
(74,168
|
)
|
|
|
1,763
|
|
|
|
(74,294
|
)
|
Mandatory repatriation of earnings pursuant to
Tax Reform Act
|
|
|
—
|
|
|
|
—
|
|
|
|
94,194
|
|
Effect of foreign operations
|
|
|
3,129
|
|
|
|
15
|
|
|
|
(42,102
|
)
|
Valuation allowance
|
|
|
11,650
|
|
|
|
11,929
|
|
|
|
(41,492
|
)
|
Uncertain tax positions, settlements and
adjustments relating to prior years
|
|
|
96,960
|
|
|
|
(15,777
|
)
|
|
|
31,726
|
|
Other
|
|
|
2,052
|
|
|
|
3,308
|
|
|
|
(314
|
)
|
Income tax benefit
|
|
$
|
(44,800
|
)
|
|
$
|
(46,353
|
)
|
|
$
|
(39,786
|
)
|
Deferred Income Taxes. Significant components of our deferred income tax assets and liabilities are as follows (in thousands):
|
|
December 31,
|
|
|
|
2019
|
|
|
2018
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Net operating loss carryforwards, or NOLs
|
|
$
|
253,973
|
|
|
$
|
209,679
|
|
Foreign tax credits
|
|
|
43,026
|
|
|
|
43,225
|
|
Disallowed interest deduction
|
|
|
40,777
|
|
|
|
16,248
|
|
Worker’s compensation and other current
accruals
|
|
|
6,250
|
|
|
|
8,375
|
|
Deferred deductions
|
|
|
12,345
|
|
|
|
10,481
|
|
Deferred revenue
|
|
|
7,209
|
|
|
|
—
|
|
Operating lease liability
|
|
|
5,461
|
|
|
|
—
|
|
Other
|
|
|
4,367
|
|
|
|
6,380
|
|
Total deferred tax assets
|
|
|
373,408
|
|
|
|
294,388
|
|
Valuation allowance
|
|
|
(186,620
|
)
|
|
|
(174,970
|
)
|
Net deferred tax assets
|
|
|
186,788
|
|
|
|
119,418
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
(225,643
|
)
|
|
|
(212,251
|
)
|
Mobilization
|
|
|
(2,245
|
)
|
|
|
(11,012
|
)
|
Right-of-use assets
|
|
|
(5,461
|
)
|
|
|
—
|
|
Other
|
|
|
(967
|
)
|
|
|
(535
|
)
|
Total deferred tax liabilities
|
|
|
(234,316
|
)
|
|
|
(223,798
|
)
|
Net deferred tax liability
|
|
$
|
(47,528
|
)
|
|
$
|
(104,380
|
)
|
Net Operating Loss Carryforwards. As of December 31, 2019, we recorded a deferred tax asset of $254.0 million for the benefit of NOL carryforwards, comprised of $149.4 million related to our U.S. losses and $104.6 million related to our international operations. Approximately $154.7 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $99.3 million relates to NOL carryforwards in several of our foreign subsidiaries, as well as in the U.S. Unless utilized, these NOL carryforwards will expire between 2021 and 2038.
73
Foreign Tax Credits. As of December 31, 2019, we recorded a deferred tax asset of $43.0 million for the benefit of foreign tax credits in the U.S., all of which will expire, unless utilized, between 2020 to 2030.
Valuation Allowances. We record a valuation allowance on a portion of our deferred tax assets not expected to be ultimately realized. During the years ended December 31, 2019, 2018 and 2017, we established valuation allowances related to net operating losses, foreign tax credits and other deferred tax assets of $30.7 million, $35.2 million and $37.9 million, respectively. During the years ended December 31, 2019, 2018 and 2017, we released valuation allowances in various jurisdictions of $19.0 million, $23.3 million and $79.4 million, respectively. The valuation allowance was also reduced by a $6.2 million adjustment to retained earnings at January 1, 2018 in connection with our adoption of ASU 2016-16. See Note 1 “General Information - Changes in Accounting Principles - Income Taxes.”
As of December 31, 2019, valuation allowances aggregating $186.6 million have been recorded for our net operating losses, foreign tax credits and other deferred tax assets for which the tax benefits are not likely to be realized.
Unrecognized Tax Benefits. Our income tax returns are subject to review and examination in the various jurisdictions in which we operate, and we are currently contesting various tax assessments. We accrue for income tax contingencies, or uncertain tax positions, that we believe are not likely to be realized. A rollforward of the beginning and ending amount of unrecognized tax benefits, excluding interest and penalties, is as follows (in thousands):
|
|
For the Year Ended December 31,
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Balance, beginning of period
|
|
$
|
(55,943
|
)
|
|
$
|
(81,864
|
)
|
|
$
|
(34,970
|
)
|
Additions for current year tax positions
|
|
|
(85,970
|
)
|
|
|
(2,906
|
)
|
|
|
(51,260
|
)
|
Additions for prior year tax positions
|
|
|
(2,113
|
)
|
|
|
(20,943
|
)
|
|
|
(2,938
|
)
|
Reductions for prior year tax positions
|
|
|
23,267
|
|
|
|
49,175
|
|
|
|
623
|
|
Reductions related to statute of limitation
expirations
|
|
|
1,875
|
|
|
|
595
|
|
|
|
6,681
|
|
Balance, end of period
|
|
$
|
(118,884
|
)
|
|
$
|
(55,943
|
)
|
|
$
|
(81,864
|
)
|
The addition for current year tax positions in 2019 is due to a recent change in Switzerland tax legislation. Due to the uncertainties regarding the application of Swiss Tax Reform, including the values to be used to measure depreciable property, a liability for an uncertain tax position was recorded in the amount of $ 86.2 million. The $23.3 million reduction for prior year tax positions is mainly due to reversal of an uncertain tax position recorded for the one-time mandatory repatriation provision of the Tax Reform Act, following final regulations issued by the IRS in June 2019.
The $20.9 million addition for prior year tax positions in 2018 and the $51.3 million addition for current year tax positions in 2017, as well as the $49.2 million reduction for prior year tax positions in 2018 are all primarily due to uncertainty associated with the enactment of the Tax Reform Act and subsequent clarification issued by the IRS related to the positions in question.
At December 31, 2019, $0.5 million, $91.1 million and $58.3 million of the net liability for uncertain tax positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2018, $1.2 million, $7.5 million and $75.3 million of the net liability for uncertain tax positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. Of the net unrecognized tax benefits at December 31, 2019, 2018 and 2017, $148.8 million, $81.6 million and $101.9 million, respectively, would affect the effective tax rates if recognized.
At December 31, 2019, the amount of accrued interest and penalties related to uncertain tax positions was $4.0 million and $16.5 million, respectively. At December 31, 2018, the amount of accrued interest and penalties related to uncertain tax positions was $3.2 million and $16.3 million, respectively.
74
Interest expense recognized during the years ended December 31, 2019, 2018 and 2017 related to uncertain tax positions was $1.0 million, $0.1 million and $0.5 million, respectively. Penalties recognized during the years ended December 31, 2019, 2018 and 2017 related to uncertain tax positions were $0.3 million, $0.6 million and $(1.7) million, respectively.
We expect the statute of limitations for the 2013 through 2015 tax years to expire in 2020 for various of our subsidiaries operating in Ireland, Malaysia and Mexico. We anticipate that the related unrecognized tax benefit will decrease by $5.1 million at that time.
Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions include the year 2000 and the years 2009 to 2018. We are currently under audit in Australia, Brazil, Egypt, Equatorial Guinea, Malaysia, Mexico, Nicaragua, Qatar and the United Kingdom, or U.K. We do not anticipate that any adjustments resulting from the tax audit of any of these years will have a material impact on our consolidated results of operations, financial condition or cash flows.
15. Employee Benefit Plans
Defined Contribution Plans
We maintain defined contribution retirement plans for our U.S., U.K., and third-country national, or TCN, employees. The plan for our U.S. employees, or the 401k Plan, is designed to qualify under Section 401(k) of the Code. Under the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of such earnings. A participating employee may also elect to make after-tax contributions to the 401k Plan. During 2019, 2018 and 2017, we matched 100% of the first 5% of each employee’s qualifying annual compensation contributed to the 401k Plan on a pre-tax or Roth elective deferral basis in each respective year. Participants are fully vested in the employer match immediately upon enrollment in the 401k Plan. For the years ended December 31, 2019, 2018 and 2017, our provision for contributions was $9.1 million, $8.0 million and $8.9 million, respectively.
The defined contribution retirement plan for our U.K. employees provides that we make annual contributions in an amount equal to the employee's contributions generally up to a maximum percentage of the employee's defined compensation per year. Our contribution during 2019, 2018 and 2017 for employees working in the U.K. sector of the North Sea was 6% of the employee’s defined compensation. Our provision for contributions was $2.1 million, $1.5 million and $1.4 million for the years ended December 31, 2019, 2018 and 2017, respectively.
The defined contribution retirement plan for our TCN employees, or International Savings Plan, is similar to the 401k Plan. During 2019, 2018 and 2017, we matched 5% of each employee’s compensation contributed to the International Savings Plan in each respective year, and our provision for contributions was $0.4 million in each of the years ended December 31, 2019, 2018 and 2017.
Deferred Compensation and Supplemental Executive Retirement Plan
Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly compensated employees to compensate such employees for any portion of the applicable percentage of the base salary contribution and/or matching contribution under the 401k Plan that could not be contributed to that plan because of limitations within the Code. Our provision for contributions to the Supplemental Plan for 2019, 2018 and 2017 was approximately $0.1 million in each respective year.
16. Segments and Geographic Area Analysis
Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics due to the nature of the revenue-earning process as it relates to the offshore drilling industry over the operating lives of our drilling rigs.
75
Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At December 31, 2019, our active drilling rigs were located offshore three countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.
The following tables provide information about disaggregated revenue by equipment-type and country (in thousands):
|
|
Year Ended December 31, 2019
|
|
|
|
Total
Contract
Drilling
Revenues (1)
|
|
|
Revenues
Related to
Reimbursable
Expenses
|
|
|
Total
|
|
United States
|
|
$
|
507,759
|
|
|
$
|
7,881
|
|
|
$
|
515,640
|
|
Brazil
|
|
|
191,519
|
|
|
|
83
|
|
|
|
191,602
|
|
United Kingdom
|
|
|
149,724
|
|
|
|
14,036
|
|
|
|
163,760
|
|
Australia
|
|
|
85,932
|
|
|
|
23,710
|
|
|
|
109,642
|
|
Total
|
|
$
|
934,934
|
|
|
$
|
45,710
|
|
|
$
|
980,644
|
|
(1)
|
Contract drilling revenue for 2019 was entirely attributable to our floater rigs (drillships and semisubmersibles).
|
|
|
Year Ended December 31, 2018
|
|
|
|
Floater Rigs
|
|
|
Jack-up
Rigs (1)
|
|
|
Total
Contract
Drilling
Revenues
|
|
|
Revenues
Related to
Reimbursable
Expenses
|
|
|
Total
|
|
United States
|
|
$
|
628,574
|
|
|
$
|
8,413
|
|
|
$
|
636,987
|
|
|
$
|
7,436
|
|
|
$
|
644,423
|
|
Brazil
|
|
|
170,839
|
|
|
|
—
|
|
|
|
170,839
|
|
|
|
(26
|
)
|
|
|
170,813
|
|
United Kingdom
|
|
|
84,749
|
|
|
|
—
|
|
|
|
84,749
|
|
|
|
7,738
|
|
|
|
92,487
|
|
Australia
|
|
|
53,170
|
|
|
|
—
|
|
|
|
53,170
|
|
|
|
7,612
|
|
|
|
60,782
|
|
Malaysia
|
|
|
114,228
|
|
|
|
—
|
|
|
|
114,228
|
|
|
|
(210
|
)
|
|
|
114,018
|
|
Other countries (2)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
692
|
|
|
|
692
|
|
Total
|
|
$
|
1,051,560
|
|
|
$
|
8,413
|
|
|
$
|
1,059,973
|
|
|
$
|
23,242
|
|
|
$
|
1,083,215
|
|
(1)
|
Loss-of-hire insurance proceeds related to early contract terminations for two jack-up rigs.
|
(2)
|
This represents countries that individually comprised less than 5% of total revenues.
|
|
|
Year Ended December 31, 2017
|
|
|
|
Floater Rigs
|
|
|
Jack-up
Rigs
|
|
|
Total
Contract
Drilling
Revenues
|
|
|
Revenues
Related to
Reimbursable
Expenses
|
|
|
Total
|
|
United States
|
|
$
|
619,655
|
|
|
$
|
—
|
|
|
$
|
619,655
|
|
|
$
|
10,940
|
|
|
$
|
630,595
|
|
Brazil
|
|
|
280,798
|
|
|
|
—
|
|
|
|
280,798
|
|
|
|
(311
|
)
|
|
|
280,487
|
|
United Kingdom
|
|
|
171,146
|
|
|
|
—
|
|
|
|
171,146
|
|
|
|
6,424
|
|
|
|
177,570
|
|
Australia
|
|
|
125,568
|
|
|
|
—
|
|
|
|
125,568
|
|
|
|
15,385
|
|
|
|
140,953
|
|
Malaysia
|
|
|
164,984
|
|
|
|
—
|
|
|
|
164,984
|
|
|
|
1,988
|
|
|
|
166,972
|
|
Trinidad
|
|
|
67,924
|
|
|
|
—
|
|
|
|
67,924
|
|
|
|
—
|
|
|
|
67,924
|
|
Other countries (1)
|
|
|
—
|
|
|
|
21,144
|
|
|
|
21,144
|
|
|
|
101
|
|
|
|
21,245
|
|
Total
|
|
$
|
1,430,075
|
|
|
$
|
21,144
|
|
|
$
|
1,451,219
|
|
|
$
|
34,527
|
|
|
$
|
1,485,746
|
|
(1)
|
This represents countries that individually comprised less than 5% of total revenues.
|
76
The following table presents our long-lived tangible assets by country as of December 31, 2019, 2018 and 2017. A substantial portion of our assets is comprised of rigs that are mobile, and therefore asset locations at the end of the period are not necessarily indicative of the geographic distribution of the earnings generated by such assets during the periods and may vary from period to period due to the relocation of rigs. In circumstances where our drilling rigs were in transit at the end of a calendar year, they have been presented in the tables below within the country in which they were expected to operate (in thousands).
|
|
December 31,
|
|
|
|
2019
|
|
|
2018 (1)
|
|
|
2017 (1)
|
|
Drilling and other property and equipment, net:
|
|
|
|
|
|
|
|
|
|
|
|
|
United States
|
|
$
|
2,227,934
|
|
|
$
|
2,245,989
|
|
|
$
|
2,300,956
|
|
International:
|
|
|
|
|
|
|
|
|
|
|
|
|
United Kingdom
|
|
|
1,061,585
|
|
|
|
1,083,540
|
|
|
|
133,525
|
|
Brazil
|
|
|
883,607
|
|
|
|
923,355
|
|
|
|
923,398
|
|
Australia
|
|
|
570,964
|
|
|
|
242,929
|
|
|
|
629,436
|
|
Singapore
|
|
|
404,420
|
|
|
|
366,798
|
|
|
|
17
|
|
Malaysia
|
|
|
2,037
|
|
|
|
318,191
|
|
|
|
1,084,793
|
|
Other countries (2)
|
|
|
2,281
|
|
|
|
3,420
|
|
|
|
189,516
|
|
|
|
|
2,924,894
|
|
|
|
2,938,233
|
|
|
|
2,960,685
|
|
Total
|
|
$
|
5,152,828
|
|
|
$
|
5,184,222
|
|
|
$
|
5,261,641
|
|
(1)
|
During 2018 and 2017, we recorded aggregate impairment losses of $27.2 million and $99.3 million, respectively, to write down certain of our drilling rigs and related equipment with indicators of impairment to their estimated recoverable amounts.
|
(2)
|
This represents countries with long-lived assets that individually comprised less than 5% of total drilling and other property and equipment, net of accumulated depreciation.
|
Major Customers
Our customer base includes major and independent oil and gas companies and government-owned oil companies. Revenues from our major customers for the years ended December 31, 2019, 2018 and 2017 that contributed more than 10% of our total revenues are as follows:
|
|
Year Ended December 31,
|
|
Customer
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Hess Corporation
|
|
|
28.9
|
%
|
|
|
25.0
|
%
|
|
|
16.0
|
%
|
Occidental (formerly Anadarko)
|
|
|
20.6
|
%
|
|
|
33.8
|
%
|
|
|
24.9
|
%
|
Petróleo Brasileiro S.A.
|
|
|
19.5
|
%
|
|
|
15.8
|
%
|
|
|
18.9
|
%
|
BP
|
|
|
3.1
|
%
|
|
|
10.5
|
%
|
|
|
15.8
|
%
|
77
17. Unaudited Quarterly Financial Data
Unaudited summarized financial data by quarter for the years ended December 31, 2019 and 2018 is shown below (in thousands).
|
|
First
|
|
|
Second
|
|
|
Third
|
|
|
Fourth
|
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
|
Quarter
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
233,542
|
|
|
$
|
216,706
|
|
|
$
|
254,020
|
|
|
$
|
276,376
|
|
Operating loss
|
|
|
(49,127
|
)
|
|
|
(111,500
|
)
|
|
|
(72,834
|
)
|
|
|
(48,869
|
)
|
Loss before income tax expense
|
|
|
(77,390
|
)
|
|
|
(141,342
|
)
|
|
|
(102,610
|
)
|
|
|
(80,672
|
)
|
Net loss
|
|
|
(73,328
|
)
|
|
|
(113,988
|
)
|
|
|
(95,128
|
)
|
|
|
(74,770
|
)
|
Net loss per share, basic and diluted
|
|
$
|
(0.53
|
)
|
|
$
|
(0.83
|
)
|
|
$
|
(0.69
|
)
|
|
$
|
(0.54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
295,510
|
|
|
$
|
268,861
|
|
|
$
|
286,322
|
|
|
$
|
232,522
|
|
Operating income (loss) (1)
|
|
|
512
|
|
|
|
(52,375
|
)
|
|
|
(23,043
|
)
|
|
|
(37,277
|
)
|
Loss before income tax expense
|
|
|
(25,142
|
)
|
|
|
(79,286
|
)
|
|
|
(55,894
|
)
|
|
|
(66,303
|
)
|
Net income (loss)
|
|
|
19,321
|
|
|
|
(69,274
|
)
|
|
|
(51,112
|
)
|
|
|
(79,207
|
)
|
Net income (loss) per share, basic and diluted
|
|
$
|
0.14
|
|
|
$
|
(0.50
|
)
|
|
$
|
(0.37
|
)
|
|
$
|
(0.58
|
)
|
(1) During the second quarter of 2018, we recognized an impairment loss of $27.2 million to write down the carrying value of the Ocean Scepter to its estimated recoverable amount. See Note 3.